EX-99 11 x991.txt (1) UPDATED ITEM 1 EXHIBIT 99.1 PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS ITEM 1 DOES NOT REFLECT EVENTS OCCURRING AFTER THE DATE OF THE FILING OF THE ANNUAL REPORT ON FORM 10-K OF THE REGISTRANTS OTHER THAN AEP OR THE ANNUAL REPORT ON FORM 10-K/A IN THE CASE OF AEP. NO ATTEMPT HAS BEEN MADE IN THIS REPORT TO MODIFY OR UPDATE OTHER DISCLOSURES EXCEPT AS REQUIRED TO REFLECT THE EFFECTS OF THE NEW REPORTABLE SEGMENTS.
GLOSSARY OF TERMS The following abbreviations or acronyms used in Item 1 are defined below: Abbreviation or Acronym Definition ----------------------- ---------- AEGCo......................................AEP Generating Company, an electric utility subsidiary of AEP AEP........................................American Electric Power Company, Inc. AEPES......................................AEP Energy Services, Inc., a subsidiary of AEP AEP Power Pool.............................APCo, CSPCo, I&M, KPCo and OPCo, as parties to the Interconnection Agreement AEPR.......................................AEP Resources, Inc., a subsidiary of AEP AEPSC or Service Corporation...............American Electric Power Service Corporation, a service subsidiary of AEP AEP System or the System...................The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries AEP Utilities..............................AEP Utilities, Inc., subsidiary of AEP, formerly, Central and South West Corporation AFUDC......................................Allowance for funds used during construction. Defined in regulatory systems of accounts as the net cost of borrowed funds used for construction and a reasonable rate of return on other funds when so used. APCo.......................................Appalachian Power Company, an electric utility subsidiary of AEP Btu........................................British thermal unit Buckeye....................................Buckeye Power, Inc., an unaffiliated corporation CAA........................................Clean Air Act CAAA.......................................Clean Air Act Amendments of 1990 Cardinal Station...........................Generating facility co-owned by Buckeye and OPCo Centrica...................................Centrica U.S. Holdings, Inc., and its affiliates collectively, unaffiliated companies CERCLA.....................................Comprehensive Environmental Response, Compensation and Liability Act of 1980 CG&E.......................................The Cincinnati Gas & Electric Company, an unaffiliated utility company Cook Plant.................................The Donald C. Cook Nuclear Plant, owned by I&M, located near Bridgman, Michigan CSPCo......................................Columbus Southern Power Company, a public utility subsidiary of AEP CSW Operating Agreement....................Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing generating capacity allocation DOE........................................United States Department of Energy DP&L.......................................The Dayton Power and Light Company, an unaffiliated utility company East Zone Companies of AEP.................APCo, CSPCo, I&M, KPCo and OPCo ECOM.......................................Excess cost over market EMF........................................Electric and Magnetic Fields EPA........................................United States Environmental Protection Agency ERCOT......................................Electric Reliability Council of Texas EWG........................................Exempt wholesale generator, as defined under PUHCA FERC.......................................Federal Energy Regulatory Commission Fitch......................................Fitch Ratings, Inc. FPA........................................Federal Power Act FUCO.......................................Foreign utility company as defined under PUHCA I&M........................................Indiana Michigan Power Company, a public utility subsidiary of AEP I&M Power Agreement........................Unit Power Agreement Between AEGCo and I&M, dated March 31, 1982 Interconnection Agreement..................Agreement, dated July 6, 1951, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants IURC.......................................Indiana Utility Regulatory Commission KPCo.......................................Kentucky Power Company, a public utility subsidiary of AEP LLWPA......................................Low-Level Waste Policy Act of 1980 LPSC.......................................Louisiana Public Service Commission MECPL......................................Mutual Energy CPL, L.P., a Texas REP and former AEP affiliate MEWTU......................................Mutual Energy WTU, L.P., a Texas REP and former AEP affiliate MISO.......................................Midwest Independent Transmission System Operator Moody's....................................Moody's Investors Service, Inc. MTM........................................Marked-to-market MW.........................................Megawatt NOx........................................Nitrogen oxide NPC........................................National Power Cooperatives, Inc., an unaffiliated corporation NRC........................................Nuclear Regulatory Commission OASIS......................................Open Access Same-time Information System OATT.......................................Open Access Transmission Tariff, filed with FERC OCC........................................Corporation Commission of the State of Oklahoma Ohio Act...................................Ohio electric restructuring legislation OPCo.......................................Ohio Power Company, a public utility subsidiary of AEP OVEC.......................................Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo together own a 44.2% equity interest PJM........................................PJM Interconnection, L.L.C. Pro Serv...................................AEP Pro Serv, Inc., a subsidiary of AEP PSO........................................Public Service Company of Oklahoma, a public utility subsidiary of AEP PTB........................................Price to beat, as defined by the Texas Act PUCO.......................................The Public Utilities Commission of Ohio PUCT.......................................Public Utility Commission of Texas PUHCA......................................Public Utility Holding Company Act of 1935, as amended QF.........................................Qualifying facility, as defined under the Public Utility Regulatory Policies Act of 1978 RCRA.......................................Resource Conservation and Recovery Act of 1976, as amended REP........................................Retail electricity provider Rockport Plant.............................A generating plant, consisting of two 1,300,000-kilowatt coal-fired generating units, near Rockport, Indiana RTO........................................Regional Transmission Organization SEC........................................Securities and Exchange Commission S&P........................................Standard & Poor's Ratings Service SO2........................................Sulfur dioxide SO2 Allowance..............................An allowance to emit one ton of sulfur dioxide granted under the Clean Air Act Amendments of 1990 SPP........................................Southwest Power Pool STPNOC.....................................STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners, including TCC SWEPCo.....................................Southwestern Electric Power Company, a public utility subsidiary of AEP TCA........................................Transmission Coordination Agreement dated January 1, 1997 by and among, PSO, SWEPCo, TCC, TNC and AEPSC, which allocates costs and benefits in connection with the operation of the transmission assets of the four public utility subsidiaries TCC........................................AEP Texas Central Company, formerly Central Power and Light Company, a public utility subsidiary of AEP TEA........................................Transmission Equalization Agreement dated April 1, 1984 by and among APCo, CSPCo, I&M, KPCo and OPCo, which allocates costs and benefits in connection with the operation of transmission assets Texas Act..................................Texas electric restructuring legislation TNC........................................AEP Texas North Company, formerly West Texas Utilities Company, a public utility subsidiary of AEP TVA........................................Tennessee Valley Authority UCOS.......................................Unbundled cost of service Virginia Act...............................Virginia electric restructuring legislation VSCC...................................... Virginia State Corporation Commission WVPSC......................................West Virginia Public Service Commission West Zone Companies of AEP.................PSO, SWEPCo, TCC and TNC
FORWARD-LOOKING INFORMATION This report made by AEP and certain of its subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: o Electric load and customer growth. o Abnormal weather conditions o Available sources and costs of fuels. o Availability of generating capacity. o The speed and degree to which competition is introduced to AEP's power generation business. o The ability to recover stranded costs in connection with possible/ proposed deregulation of generation. o New legislation and government regulation o Oversight and/or investigation of the energy sector or its participants. o The ability of AEP to successfully control its costs. o The success of acquiring new business ventures and disposing of existing investments that no longer match AEP's corporate profile. o International and country-specific developments affecting AEP's foreign investments, including the disposition of any current foreign investments and potential additional foreign investments. o The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns. o Inflationary trends. o Electricity and gas market prices. o Interest rates. o Liquidity in the banking, capital and wholesale power markets. o Actions of rating agencies. o Changes in technology, including the increased use of distributed generation within AEP's transmission and distribution service territory. o Other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events. Item 1. Business General Overview and Description of Subsidiaries AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a registered public utility holding company under PUHCA that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries. The service areas of AEP's public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. The generating and transmission facilities of AEP's public utility subsidiaries are interconnected, and their operations are coordinated, as a single integrated electric utility system. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP, which do business as "American Electric Power," have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring legislation in Michigan, Ohio, Texas and Virginia has caused or will cause AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers. The AEP System is an integrated electric utility system and, as a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The member companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC. At December 31, 2002, the subsidiaries of AEP had a total of 22,083 employees. AEP, because it is a holding company rather than an operating company, has no employees. The public utility subsidiaries of AEP are: APCo (organized in Virginia in 1926) is engaged in the generation, transmission and distribution of electric power to approximately 925,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2002, APCo and its wholly owned subsidiaries had 2,520 employees. Among the principal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. In addition to its AEP System interconnections, APCo also is interconnected with the following unaffiliated utility companies: Carolina Power & Light Company, Duke Energy Corporation and Virginia Electric and Power Company. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems. CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, transmission and distribution of electric power to approximately 689,000 retail customers in Ohio, and in supplying and marketing electric power at wholesale to other electric utilities, municipalities and other market participants. At December 31, 2002, CSPCo had 1,171 employees. CSPCo's service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Among the principal industries served are food processing, chemicals, primary metals, electronic machinery and paper products. In addition to its AEP System interconnections, CSPCo also is interconnected with the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company. I&M (organized in Indiana in 1925) is engaged in the generation, transmission and distribution of electric power to approximately 571,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants. At December 31, 2002, I&M had 2,667 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana. In addition to its AEP System interconnections, I&M also is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, CG&E, Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power & Light Company. KPCo (organized in Kentucky in 1919) is engaged in the generation, transmission and distribution of electric power to approximately 174,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2002, KPCo had 412 employees. In addition to its AEP System interconnections, KPCo also is interconnected with the following unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KPCo is also interconnected with TVA. Kingsport Power Company (organized in Virginia in 1917) provides electric service to approximately 46,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport Power Company does not own any generating facilities. It purchases electric power from APCo for distribution to its customers. At December 31, 2002, Kingsport Power Company had 57 employees. OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, transmission and distribution of electric power to approximately 702,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2002, OPCo had 1,988 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, petroleum refining and chemicals. In addition to its AEP System interconnections, OPCo also is interconnected with the following unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company. PSO (organized in Oklahoma in 1913) is engaged in the generation, transmission and distribution of electric power to approximately 505,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2002, PSO had 998 employees. Among the principal industries served by PSO are natural gas and oil production, oil refining, steel processing, aircraft maintenance, paper manufacturing and timber products, glass, chemicals, cement, plastics, aerospace manufacturing, telecommunications, and rubber goods. In addition to its AEP System interconnections, PSO also is interconnected with Ameren Corporation, Empire District Electric Co., Oklahoma Gas & Electric Co., Southwestern Public Service Co. and Westar Energy Inc. SWEPCo (organized in Delaware in 1912) is engaged in the generation, transmission and distribution of electric power to approximately 437,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2002, SWEPCo had 1,372 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum refining, manufacturing of pulp and paper, chemicals, food processing, and metal refining. The territory served by SWEPCo also includes several military installations, colleges, and universities. In addition to its AEP System interconnections, SWEPCo is also interconnected with CLECO Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas & Electric Co. TCC (organized in Texas in 1945) is engaged in the generation, transmission and sale of power to affiliated and non-affiliated entities and the distribution of electric power to approximately 689,000 retail customers through REPs in southern Texas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2002, TCC had 1,248 employees. Among the principal industries served by TCC are oil and gas extraction, food processing, apparel, metal refining, chemical and petroleum refining, plastics, and machinery equipment. In addition to its AEP System interconnections, TCC is a member of ERCOT. TNC (organized in Texas in 1927) is engaged in the generation, transmission and sale of power to affiliated and non-affiliated entities and the distribution of electric power to approximately 189,000 retail customers through REPs in west and central Texas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2002, TNC had 595 employees. The principal industry served by TNC is agriculture. The territory served by TNC also includes several military installations and correctional facilities. In addition to its AEP System interconnections, TNC is a member of ERCOT. Wheeling Power Company (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 41,000 retail customers in northern West Virginia. Wheeling Power Company does not own any generating facilities. It purchases electric power from OPCo for distribution to its customers. At December 31, 2002, Wheeling Power Company had 59 employees. AEGCo (organized in Ohio in 1982) is an electric generating company. AEGCo sells power at wholesale to I&M and KPCo. AEGCo has no employees. Service Company Subsidiary AEP also owns a service company subsidiary, AEPSC. AEPSC provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP System companies. The executive officers of AEP and its public utility subsidiaries are all employees of AEPSC. At December 31, 2002, AEPSC had 6,548 employees. Classes of Service The principal classes of service from which the public utility subsidiaries of AEP derive revenues and the amount of such revenues during the year ended December 31, 2002 are as follows:
AEP System(a) APCo CSPCo I&M KPCo (in thousands) Utility Operations: Electric Generation Residential........................... $ 3,701,000 $ 616,509 $ 533,061 $ 371,329 $ 118,654 Commercial............................ 2,126,000 276,238 442,847 224,843 50,075 Industrial............................ 1,903,000 353,841 138,174 330,428 96,716 Other Retail Customers................ 385,000 80,429 38,018 61,450 16,911 Electric T&D.......................... (3,643,000) (594,089) (492,278) (321,721) (132,054) -------------- ------------- ------------- ------------- ------------ Total Retail....................... 4,472,000 732,928 659,822 666,329 150,302 Marketing and Trading-Electricity..... 1,846,000 204,878 134,836 279,705 50,056 Unrealized MTM Income................. 270,000 18,089 13,388 0 0 Other................................. 202,000 264,486 99,836 259,009 46,271 -------------- ------------- ------------- ------------- ------------ Total Electric Generation.......... 6,790,000 1,220,381 907,882 1,205,043 246,629 -------------- ------------- ------------- ------------- ------------ Electric Transmission and Distribution Transmission.......................... 922,000 186,960 107,673 118,812 50,381 Distribution.......................... 2,721,000 407,129 384,605 202,909 81,673 -------------- ------------- ------------- ------------- ------------ Total Electric T&D................. 3,643,000 594,089 492,278 321,721 132,054 -------------- ------------- ------------- ------------- ------------ Total Utility Operations........... 10,433,000 1,814,470 1,400,160 1,526,764 378,683 --------------- -------------- -------------- -------------- ------------ Investments- Gas Operations: Marketing and Trading-Gas............. 3,444,000 0 0 0 0 Unrealized MTM Income................. (399,000) 0 0 0 0 -------------- Total Investments- Gas Operations.. 3,045,000 0 0 0 0 Investments- UK Operations................ 264,000 0 0 0 0 Investments- Other........................ 794,000 0 0 0 0 Total Revenues..................... $ 14,536,000 $ 1,814,470 $ 1,400,160 $ 1,526,764 $ 378,683 ============== ============= ============= ============= ============
OPCo PSO SWEPCo TCC TNC (in thousands) Utility Operations: Electric Generation Residential........................... $ 475,210 $ 315,711 $ 313,023 $ 49,210 $ 8,651 Commercial............................ 244,943 218,718 212,626 32,518 4,098 Industrial............................ 531,085 162,386 214,622 12,395 2,134 Other Retail Customers................ 71,737 38,998 33,104 3,594 1,638 Electric T&D.......................... (589,673) (275,547) (348,236) (554,547) (73,353) ------------- ------------ ------------- ------------- ----------- Total Retail....................... 733,302 460,266 425,139 (456,830) (56,832) Marketing and Trading-Electricity..... 219,488 17,394 157,159 811,800 283,883 Unrealized MTM Income....................... 25,574 0 (3,686) (8,490) (1,473) Other......................................... 545,088 40,440 157,872 789,466 151,809 ------------- ------------ ------------- ------------- ----------- Total Electric Generation.................. 1,523,452 518,100 736,484 1,135,946 377,387 ------------- ------------ ------------- ------------- ----------- Electric Transmission and Distribution Transmission.......................... 162,660 63,178 92,076 68,003 25,273 Distribution.......................... 427,013 212,369 256,160 486,544 48,080 ------------- ------------ ------------- ------------- ----------- Total Electric T&D................. 589,673 275,547 348,236 554,547 73,353 ------------- ------------ ------------- ------------- ----------- Total Utility Operations................. 2,113,125 793,647 1,084,720 1,690,493 450,740 -------------- ------------ ------------- -------------- ------------ Investments- Gas Operations: Marketing and Trading-Gas............. 0 0 0 0 0 Unrealized MTM Income................. 0 0 0 0 0 Total Investments- Gas Operations.. 0 0 0 0 0 Investments- UK Operations................ 0 0 0 0 0 Investments- Other........................ 0 0 0 0 0 Total Revenues........................... $ 2,113,125 $ 793,647 $ 1,084,720 $ 1,690,493 $ 450,740 ============= ============ ============= ============= ===========
---------- (a) Includes revenues of other subsidiaries not shown. Intercompany transactions have been eliminated, including AEGCo's total revenues of $213,281,000 for the year ended December 31, 2002, all of which resulted from its wholesale business, including its marketing and trading of power. Holding Company Regulation The provisions of PUHCA, administered by the SEC, regulate many aspects of a registered holding company system, such as the AEP System. PUHCA limits the operations of a registered holding company system to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of assets and intra-system transactions. PUHCA and the rules and orders of the SEC currently require that transactions between associated companies in a registered holding company system be performed at cost with limited exceptions. Over the years, the AEP System has developed numerous affiliated service, sales and construction relationships and, in some cases, invested significant capital and developed significant operations in reliance upon the ability to recover its full costs under these provisions. The Division of Investment Management of the SEC has recommended the conditional repeal of PUHCA. Under its recommendation, certain oversight authority would be transferred to the FERC. Legislation has since been introduced in numerous sessions of Congress that would repeal PUHCA, but such legislation has not passed. AEP-CSW Merger On June 15, 2000, CSW (now known as AEP Utilities, Inc.) merged with and into a wholly-owned merger subsidiary of AEP. As a result, CSW became a wholly owned subsidiary of AEP. The four wholly owned public utility subsidiaries of CSW--PSO, SWEPCo, TCC and TNC--became indirect wholly owned public utility subsidiaries of AEP as a result of the merger. The merger was approved by the FERC and the SEC (with respect to PUHCA). On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to properly explain how the merger met the requirements of PUHCA and remanded the case to the SEC for further review. The court held that the SEC had not adequately explained its conclusions that the merger met PUHCA requirements that the merging entities be "physically interconnected" and that the combined entity was confined to a "single area or region." Management believes that the merger meets the requirements of PUHCA and expects the matter to be resolved favorably. Financing General AEP's goal is to use cash from operations to fund capital expenditures, dividends and working capital. Short-term debt is used as an interim bridge for timing differences in the need for cash or to fund debt maturities until permanent financing is arranged. It has been the practice of AEP's operating subsidiaries to finance current construction expenditures in excess of available cash from operations by initially incurring short-term debt, up to levels authorized by regulatory agencies, and then to reduce the short-term debt with the proceeds of subsequent sales by such subsidiaries of long-term debt securities and cash capital contributions by AEP. In the past, short-term debt has come from AEP's commercial paper program and revolving credit facilities. Proceeds were loaned to the subsidiaries through intercompany notes under the AEP money pool. The recent downgrade of AEP's commercial paper rating by Moody's, described below, may limit AEP's access to commercial paper on terms as favorable as those of recent years. Therefore, AEP may establish commercial paper programs for certain of its public utility subsidiaries and AEP Utilities. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity. AEP's revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for this type of facility, including a maximum debt/capital test and a $50 million cross-acceleration provision. At December 31, 2002, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreements. A voluntary bankruptcy or insolvency would be considered an immediate termination event. AEP's subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as leasing arrangements, including the leasing of utility assets and coal mining and transportation equipment and facilities. Credit Ratings The rating agencies have been conducting credit reviews of AEP and its registrant subsidiaries. The agencies are also reviewing many companies in the energy sector due to issues that impact the entire industry. In February 2003 Moody's completed its review of AEP and its rated subsidiaries. The results of that review were downgrades of the following ratings for unsecured debt: AEP from Baa2 to Baa3, APCo from Baa1 to Baa2, TCC from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1. TNC, which had no senior unsecured notes outstanding at the time of the ratings action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial paper was also concurrently downgraded from P-2 to P-3. The completion of this review was a culmination of earlier ratings action in 2002 that had included a downgrade of AEP from Baa1 to Baa2. With the completion of the reviews, Moody's has placed AEP and its rated subsidiaries on stable outlook. In March 2003 S&P completed its review of AEP and its rated subsidiaries. The results of that review were downgrades of the ratings for unsecured debt for AEP and its rated subsidiaries from BBB+ to BBB. AEP's commercial paper rating was affirmed at A-2. With the completion of the reviews, S&P has placed AEP and its rated subsidiaries on stable outlook. In March 2003 Fitch completed its review of AEP. The result of that review was a downgrade of AEP's unsecured debt rating from BBB+ to BBB. AEP's commercial paper rating was affirmed at F-2. With the completion of the reviews, Fitch has placed AEP and its rated subsidiaries on stable outlook. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, included in the updated 2002 Annual Reports, under the heading entitled Financial Condition for additional information with respect to AEP's credit ratings, liquidity and specific financing activities. Environmental and Other Matters General AEP's subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. The environmental issues that are potentially material to the AEP system include: o The CAA and CAAA and state laws and regulations (including State Implementation Plans) that require compliance, obtaining permits and reporting as to air emissions. o Litigation with the federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating plants required additional permitting or pollution control technology. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters under the heading entitled Federal EPA Complaint and Notice of Violation and Note 9 to the consolidated financial statements entitled Commitments and Contingencies, included in the updated 2002 Annual Reports, for further information. o Rules issued by the EPA and certain states that require substantial reductions in NOx emissions. The compliance dates for these rules range from 2003 to 2005. AEP is installing (or has installed) emission control technology and is taking other measures to comply with required reductions. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 9 to the consolidated financial statements entitled Commitments and Contingencies, included in the updated 2002 Annual Reports, under the heading entitled NOx Reductions for further information. o CERCLA, which imposes upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites, costs for environmental remediation. AEP does not, however, anticipate that any of its currently identified CERCLA-related issues will result in material costs or penalties to the AEP System. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, included in the updated 2002 Annual Reports, under the heading entitled Superfund for further information. o The Federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits. There are, however, no matters material to the AEP System currently pending under the Clean Water Act. o Solid and hazardous waste laws and regulations, which govern the management and disposal of certain wastes. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion byproducts, which the EPA has determined are not hazardous waste governed subject to RCRA. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. AEP's subsidiaries will confront several new environmental policies and regulations over the next decade with the potential for substantial control costs and premature retirement of some generating plants. These could include (i) new or additional controls on sulfur dioxide, NOx and mercury emissions from future laws or regulations, or the possibility of an adverse decision in the new source review litigation; (ii) a new Clean Water Act rule to reduce fish and other aquatic organisms killed at once-through cooled power plants; (iii) finalization and implementation of more stringent water quality-based permit limits; and (iv) a possible future requirement to reduce carbon dioxide emissions. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, included in the updated 2002 Annual Reports, under the heading entitled Environmental Concerns and Issues for information on current environmental issues. AEP expects costs related to environmental controls to eventually be reflected in some jurisdictions in the rates of AEP's public utility subsidiaries. In Michigan, Ohio, Texas and Virginia, those costs may not be recoverable if future market prices for electricity generated by plants in those jurisdictions are insufficient to permit AEP to recover such costs. Moreover, legislation adopted by certain states and proposed at the state and federal level governing restructuring of the electric utility industry may also affect the recovery of certain of these costs. There can be no assurance that these costs will be recovered. AEP's international operations are subject to environmental regulation by various authorities within the host countries. Under certain circumstances, these authorities may require modifications to these facilities and operations or impose fines and other costs for violations of applicable statutes and regulations. From time to time, these operations are named as parties to various legal claims, actions, complaints or other proceedings related to environmental matters. AEP's UK generation facilities will be subject to additional environmental constraints in 2008 (which become more stringent after 2015) because they are subject to regulation governing large combustion plants. In the fourth quarter of 2002, AEP decided not to install certain emission control technology on its Fiddler's Ferry and Ferrybridge generation facilities in 2008. This decision and its legal and regulatory consequences will result in a significant reduction in the estimated economic life of those facilities. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System. See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 9 to the consolidated financial statements entitled Commitments and Contingencies, included in the updated 2002 Annual Reports, for further information with respect to environmental matters. Environmental Expenditures Expenditures related to generation facility compliance with air and water quality standards during 2001 and 2002 and the current estimate for 2003 are shown below. Substantial expenditures in addition to the amounts set forth below may be required by the System in future years in connection with the modification and addition of facilities at generating plants for environmental quality controls in order to comply with air and water quality standards which have been or may be adopted. Future expenditures could be significantly greater if litigation regarding whether AEP properly installed emission control equipment on its plants is resolved against AEP. See Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, included in the updated 2002 Annual Reports, for more information regarding this litigation and environmental expenditures in general. 2001 2002 2003 Actual Actual Estimate (in thousands) AEGCo............................. $ 3,500 $ 1,200 $ 11,200 APCo.............................. 99,200 108,400 65,700 CSPCo............................. 22,500 25,400 39,300 I&M............................... 700 1,200 18,500 KPCo.............................. 11,200 110,600 39,900 OPCo.............................. 125,300 110,300 53,100 PSO............................... 400 1,200 100 SWEPCo............................ 9,200 3,400 9,000 TCC............................... 2,500 600 0 TNC............................... 800 1,900 0 ----------- ----------- ----------- AEP System........................ $ 275,300 $ 364,200 $ 236,800 =========== =========== =========== Electric and Magnetic Fields EMF are found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF is created by electricity flowing in transmission and distribution lines, electrical equipment, household wiring, and appliances. A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, none has produced any conclusive evidence that EMF does or does not cause adverse health effects. Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from customers. Energy Market Investigations During 2002, several governmental entities launched investigations of participants in energy trading markets, including AEP. A number of those investigations resulted in data requests of AEP. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, included in the updated 2002 Annual Reports, under the heading Energy Market Investigations. Utility Operations General Utility operations constitute the majority of AEP's business operations. Utility operations include the generation, transmission and distribution of electric power to retail customers and the supplying and marketing of electric power at wholesale (through the electric generation function) to other electric utility companies, municipalities and other market participants Electric Generation Facilities AEP's public utility subsidiaries own approximately 38,000 MW of domestic generation. See Deactivation and Planned Disposition of Generating Facilities for a discussion of planned reductions in AEP's generating fleet. The AEP public utility subsidiaries operate their generating plants as a single interconnected and coordinated electric utility system. See Item 2 -- Properties of the Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2002, filed on March 20, 2003, for more information regarding generation facilities. AEP Power Pool and CSW Operating Agreement APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company's "member-load-ratio." The member-load ratio is calculated monthly by dividing such company's highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies. As of December 31, 2002, the member-load ratios were as follows: Peak Demand Member-Load (kw) Ratio (%) APCo....................... 6,010 28.2 CSPCo...................... 4,040 19.0 I&M........................ 4,323 20.3 KPCo....................... 1,551 7.3 OPCo....................... 5,360 25.2 Although the FERC has approved the right of withdrawal of CSPCo and OPCo from the AEP Power Pool as part of its order approving the settlement agreements and AEP's FERC restructuring application, CSPCo and OPCo have remained a party to the AEP Power Pool. If CSPCo and OPCo continue to remain in the AEP Power Pool, notification to or approval by the FERC may be required. See Management's Discussion and Analysis of Results of Operations and Financial Condition, under the headings entitled Industry Restructuring and Corporate Separation, included in the updated 2002 Annual Reports, for a discussion of AEP's corporate separation plan filed with the FERC and related settlement agreements with state commissions and other intervenors. The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement and AEP System Interim Allowance Agreement during the years ended December 31, 2000, 2001 and 2002: 2000 2001 2002 ------------- ------------- --------- (in thousands) APCo....................... $ (274,000) $ (256,700) $ (127,000) CSPCo...................... (250,400) (251,200) (267,000) I&M........................ 93,900 166,200 113,600 KPCo....................... (21,500) (27,600) (46,500) OPCo....................... 452,000 369,300 326,900 PSO, SWEPCo, TCC and TNC, and AEPSC are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement). The CSW Operating Agreement requires the west zone public utility subsidiaries to maintain specified annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other AEP west zone subsidiaries as capacity commitments. The CSW Operating Agreement also delegates to AEP Service Corporation the authority to coordinate the acquisition, disposition, planning, design and construction of generating units and to supervise the operation and maintenance of a central control center. The following table shows the net credits or (charges) allocated among the parties under the CSW Operating Agreement during the years ended December 31, 2000, 2001 and 2002: 2000 2001 2002 ------------ ------------ -------- (in thousands) PSO.......................... $ (9,000) $ (6,500) $ (53,700) SWEPCo....................... 55,400 62,300 67,800 TCC.......................... 3,600 (13,500) 15,400 TNC.......................... (50,000) (42,300) (29,500) Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any public utility subsidiary is often sold to customers (or in the case of the ERCOT area of Texas, REPs) by such public utility subsidiary at rates approved (other than in the ERCOT area of Texas) by the public utility commission in the jurisdiction of sale. In Ohio, Virginia and the ERCOT area of Texas, such rates are based on a statutory formula as those jurisdictions transition to the use of market rates for generation. See Regulation -- Rates. Under the Interconnection Agreement, power allocated to a public utility subsidiary that is not required to serve its native load is sold at wholesale on behalf of such subsidiary. Under the CSW Operating Agreement, power generated that is not needed to serve the native load of any public utility subsidiary is sold at wholesale by the generating subsidiary. See Marketing and Trading- Electricity for a discussion of the trading and marketing of such power. AEP's System Integration Agreement provides for the integration and coordination of AEP's east and west zone operating subsidiaries, joint dispatch of generation within the AEP System, and the 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 Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits within each zone. Marketing and Trading- Electricity AEP enters into transactions for the purchase and sale of power as part of its utility operations. Power transactions are executed with counterparties or through brokers. Brokers and counterparties may require cash or cash related instruments to be deposited on these transactions as margin against open positions. AEP trades power with numerous counterparties. Since AEP's open power trading contracts are valued based on changes in market power prices, our exposures change daily. In October 2002, AEP announced its plans to reduce its exposure to energy trading markets and to downsize the trading and wholesale marketing operations. It is expected that in the future power trading and marketing operations will be smaller in scope, will generally be limited to risk management around AEP assets and, accordingly, focused in regions in which AEP owns assets. Fuel Supply The following table shows the sources of power generated by the AEP System: 2000 2001 2002 -------------------- Coal........................................ 78% 74% 78% Natural Gas................................. 13% 12% 8% Nuclear..................................... 5% 11% 11% Hydroelectric and other..................... 4% 3% 3% Variations in the generation of nuclear power are primarily related to refueling outages and, in a portion of 2000, the shutdown of the Cook Plant to respond to issues raised by the NRC. Variations in the generation of natural gas power are primarily related to the availability of cheaper alternatives to fulfill certain power requirements and to deactivate certain of its gas-fired plants. Coal and Lignite: AEP System generating companies procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations, short-term, and spot agreements with various producers and coal trading firms. AEP believes, but cannot provide assurances that, it will be able to secure coal and lignite of adequate quality and in adequate quantities to operate its coal and lignite-fired units. The following table shows the amount of coal delivered to the AEP System during the past three years and the average delivered price of spot coal purchased by System companies: 2000 2001 2002 ---------- ---------- ------- Total coal delivered to AEP operated plants (thousands of tons)....................... 73,259 73,889 76,442 Average price per ton of spot-purchased coal.. $ 24.03 $ 27.30 $ 27.06 The coal supplies at AEP System plants vary from time to time depending on various factors, including customers' usage of electric power, space limitations, the rate of consumption at particular plants, labor unrest and weather conditions which may interrupt deliveries. At December 31, 2002, the System's coal inventory was roughly 56 days of normal usage. This estimate assumes that the total supply would be utilized through the operation of plants that use coal most efficiently. In cases of emergency or shortage, system companies have developed programs to conserve coal supplies at their plants. Such programs have been filed and reviewed with officials of federal and state agencies and, in some cases, the state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agencies. The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to ratemaking principles by which such electric utilities would be compensated. In addition, the federal government is authorized, under prescribed conditions, to allocate coal and to require the transportation thereof, for the use of power plants or major fuel-burning installations. Natural Gas: AEP, through its public utility subsidiaries, consumed over 163 billion cubic feet of natural gas during 2002 for generating power. A majority of the gas fired power generation plants are connected to at least two natural gas pipelines, which provides greater access to competitive supplies and improves reliability. A portfolio of long-term and short-term purchase and transportation agreements (that are acquired on a competitive basis and based on market prices) supplies natural gas requirements for each plant. Nuclear: I&M and STPNOC have made commitments to meet certain of the nuclear fuel requirements of the Cook Plant and STP, respectively. Steps currently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel. I&M has made and will make purchases of uranium in various forms in the spot, short-term, and mid-term markets until it decides that deliveries under long-term supply contracts are warranted. TCC and the other STP participants have entered into contracts with suppliers for (i) 100% of the uranium concentrate sufficient for the operation of both STP units through spring 2006 and (ii) 50% of the uranium concentrate needed for STP through spring 2007. For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool. AEP anticipates that the Cook Plant has storage capacity to permit normal operations through 2012. STP has on-site storage facilities with the capability to store the spent nuclear fuel generated by the STP units over their licensed lives. Nuclear Waste and Decommissioning I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a significant future financial commitment to safely dispose of SNF and decommission and decontaminate the plants. The ultimate cost of retiring the Cook Plant and STP may be materially different from estimates and funding targets as a result of the: o Type of decommissioning plan selected; o Escalation of various cost elements (including, but not limited to, general inflation); o Further development of regulatory requirements governing decommissioning; o Limited availability to date of significant experience in decommissioning such facilities; o Technology available at the time of decommissioning differing significantly from that assumed in these studies; and o Availability of nuclear waste disposal facilities. Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant and STP will not be significantly different than current projections. See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, included in the updated 2002 Annual Reports, for information with respect to nuclear waste and decommissioning and related litigation. Low-Level Radioactive Waste: The LLWPA mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. Michigan and Texas do not currently have disposal sites for such waste available. AEP cannot predict when such sites may be available, but South Carolina and Utah operate low-level radioactive waste disposal sites and accept low-level radioactive waste from Michigan and Texas. AEP's access to the South Carolina facility is currently allowed through the end of fiscal year 2008. Deactivation and Planned Disposition of Generation Facilities In September 2002, AEP indicated to ERCOT its intent to deactivate 16 gas-fired power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently conducted reliability studies that determined that seven plants (4 TCC plants and 3 TNC plants) would be required to ensure reliability of the electricity grid. As a result of these studies, ERCOT and AEP agreed to enter into reliability must run agreements (which expired in December 2002, but have been renewed for all but two units of these plants) to continue operation of these plants. With ERCOT's approval, AEP proceeded with its planned deactivation of the remaining nine plants. TCC has also filed a plan of divestiture with the PUCT proposing to sell all of its power generation assets in an effort to determine its level of stranded costs in accordance with the Texas Act. The PUCT has dismissed its proceeding relating to TCC's plan of divestiture in anticipation of promulgating rules of general application regarding stranded cost determination for nuclear facilities. See Texas Regulatory Assets and Stranded Cost Recovery and Post-Restructuring Wires Charges. The assets to be sold have a generating capacity of 4,497 MW and include eight gas-fired generating plants, one coal-fired plant, TCC's interest in another coal-fired plant, a hydroelectric facility and TCC's interest in STP. See Note 8 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, included in the updated 2002 Annual Reports, for more information on the planned disposition of TCC generation facilities. Structured Arrangements Involving Capacity, Energy, and Ancillary Services In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement relating to the construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC. From the commercial operation date (which occurred in 2002) until the end of 2005, OPCo will be entitled to 100% of the power generated by the facility, and responsible for the fuel and other costs of the facility. After 2005, NPC and OPCo will be entitled to 80% and 20%, respectively, of the power of the facility, and both parties will generally be responsible for the fuel and other costs of the facility. OPCo will also provide certain back-up power to NPC. Certain Power Agreements AEGCo: Since its formation in 1982, AEGCo's business has consisted of the ownership and financing of its 50% interest in Unit 1 of the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M and KPCo pursuant to unit power agreements. The I&M Power Agreement provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M). Such amounts, when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances. Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo unit power agreement expires on December 31, 2004. The agreement will be extended until December 31, 2009 for Unit 1 and December 31, 2022 for Unit 2 if AEP's restructuring settlement agreement filed with the FERC becomes effective. AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities; (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant; (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements); and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The capital funds agreement will terminate after all AEGCo Obligations have been paid in full. OVEC: AEP, CSPCo and several unaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. Until September 1, 2001, OVEC supplied the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The sponsoring companies are now entitled to receive and pay for all OVEC capacity (approximately 2,200 MW) in proportion to their power participation ratios. The aggregate power participation ratio of APCo, CSPCo, I&M and OPCo is 42.1%. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. The Inter-Company Power Agreement, which defines the rights of the owners and sets the power participation ratio of each, will expire by its terms on March 12, 2006. Buckeye: Contractual arrangements among OPCo, Buckeye and other investor-owned electric utility companies in Ohio provide for the transmission and delivery, over facilities of OPCo and of other investor-owned utility companies, of power generated by the two units at the Cardinal Station owned by Buckeye and back-up power to which Buckeye is entitled from OPCo under such contractual arrangements, to facilities owned by 25 of the rural electric cooperatives which operate in the State of Ohio at 342 delivery points. Buckeye is entitled under such arrangements to receive, and is obligated to pay for, the excess of its maximum one-hour coincident peak demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of the generating units which Buckeye currently owns in the Cardinal Station. Such demand, which occurred on August 1, 2002, was recorded at 1,398,559 kilowatts. Electric Transmission and Distribution General AEP's public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2--Properties of the Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2002, filed on March 20, 2003, for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold, in combination with electric power, to retail customers of AEP's public utility subsidiaries in their service territories. These sales are made at rates established by the state utility commissions of the states in which they operate, and in some instances, the FERC as well. See Regulation-- Rates. The FERC regulates and approves the rates for wholesale transmission transactions. See Regulation-- FERC. As discussed below, some transmission services also are separately sold to non-affiliated companies. AEP's public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. For a discussion of competition in the sale of power, see Competition. AEP Transmission Pool Transmission Equalization Agreement: APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single interconnected and coordinated system and are parties to the Transmission Equalization Agreement, dated April 1, 1984, as amended (TEA), defining how they share the costs and benefits associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 KV and above) and certain facilities operated at lower voltages (138 KV and above). This sharing is based upon each company's "member-load ratio." The member-load ratio is calculated monthly by dividing such company's highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies. As of December 31, 2002, the member-load ratios were as follows: Peak Demand Member-Load (kw) Ratio (%) APCo........................................ 6,010 28.2 CSPCo....................................... 4,040 19.0 I&M......................................... 4,323 20.3 KPCo........................................ 1,551 7.3 OPCo........................................ 5,360 25.2 The following table shows the net credits or (charges) allocated among the parties to the TEA during the years ended December 31, 2000, 2001 and 2002: 2000 2001 2002 ------------ ------------ -------- (in thousands) APCo................................ $ 3,400 $ 3,100 $ 13,400 CSPCo............................... (38,300) (40,200) (42,200) I&M................................. 43,800 41,300 36,100 KPCo................................ 6,000 4,600 5,400 OPCo................................ (14,900) (8,800) (12,700) Transmission Coordination Agreement: PSO, SWEPCo, TCC, TNC and AEPSC are parties to a Transmission Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA establishes a coordinating committee, which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of the west zone public utility subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff. Under the TCA, the west zone public utility subsidiaries have delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the AEP OATT on their behalf. The TCA also provides for the allocation among the west zone public utility subsidiaries of revenues collected for transmission and ancillary services provided under the AEP OATT. The following table shows the net credits or (charges) allocated among the parties to the TCA during the years ended December 31, 2000, 2001 and 2002: 2000 2001 2002 ---------- ---------- ------- (in thousands) PSO................................... $ 3,300 $ 4,000 $ 4,200 SWEPCo................................ 5,900 5,400 5,000 TCC................................... (3,400) (3,900) (3,600) TNC................................... (5,800) (5,500) (5,600) Transmission Services for Non-Affiliates: In addition to providing transmission services in connection with their own power sales, AEP's public utility subsidiaries and other System companies also provide transmission services for non-affiliated companies. See Regional Transmission Organizations. AEP's public utility subsidiaries are subject to regulation by the FERC under the FPA in respect of transmission of electric power. Coordination of East and West Zone Transmission: AEP's System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP's east and west zone public utility subsidiaries. The System Transmission Integration Agreement functions as an umbrella agreement in addition to the TEA and the TCA. The System Transmission Integration Agreement contains two service schedules that govern: o The allocation of transmission costs and revenues and o The allocation of third-party transmission costs and revenues and System dispatch costs. The System Transmission Integration Agreement contemplates that additional service schedules may be added as circumstances warrant. Regional Transmission Organizations On April 24, 1996, the FERC issued orders 888 and 889. These orders require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff that reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an Open Access Same-time Information System (OASIS), which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct that prohibit utilities' system operators from providing non-public transmission information to the utility's merchant employees. The orders also allow a utility to seek recovery of certain prudently incurred stranded costs that result from unbundled transmission service. In December 1999, FERC issued Order 2000, which provides for the voluntary formation of RTOs, entities created to operate, plan and control utility transmission assets. Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals. AEP is required, as a condition of FERC's approval in 2000 of AEP's merger with CSW, to transfer functional control of its transmission facilities to one or more RTOs. In May 2002, AEP announced an agreement with PJM to pursue terms for its east zone public utility subsidiaries to participate in PJM, a FERC approved RTO. In July 2002, the FERC tentatively approved AEP subsidiaries' decision to join PJM, subject to certain conditions being met. The satisfaction of these conditions is only partially within AEP's control. AEP's public utility subsidiaries have filed applications with the state utility commissions of Indiana, Kentucky, Ohio and Virginia requesting approval of the transfer of functional control of transmission assets in those states to PJM. Those applications are pending. In February 2003, the Virginia legislature enacted legislation that would prohibit the transfer of functional control of transmission assets to an RTO until at least July 2004. In July 2002, FERC conditionally accepted filings related to a proposed consolidation of MISO and the SPP. In that order the FERC required AEP's west zone subsidiaries in SPP to file reasons why those subsidiaries should not be required to join MISO. SWEPCo has filed an application with the LPSC requesting approval of the transfer of functional control of its Louisiana transmission assets to MISO and intends to make a similar filing in Arkansas with respect to its Arkansas transmission assets. AEP presently plans to transfer functional control of its transmission facilities in SPP to MISO or the merged MISO/SPP. Regulation General Except for retail generation sales in Ohio, Virginia and the ERCOT area of Texas, AEP's public utility subsidiaries' retail rates and certain other matters are subject to traditional regulation by the state utility commissions. Retail sales in Michigan, while still regulated, are now made at unbundled rates. Other states in AEP's service territory have also passed restructuring legislation that has not been implemented or has been repealed. See Electric Restructuring and Customer Choice Legislation and Rates. AEP's subsidiaries are also subject to regulation by the FERC under the FPA. I&M and TCC are subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant and STP, respectively. AEP and its subsidiaries are also subject to the broad regulatory provisions of PUHCA administered by the SEC. Rates Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility's cost of service is generally comprised of its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of (i) a utility's revenues and expenses during a defined test period and (ii) such utility's level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time as part of a transition to customer choice of generation suppliers, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time. The rates of AEP's public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). In Ohio, Virginia and the ERCOT area of Texas, rates are transitioning from bundled cost-based rates for electric service to unbundled cost-based rates for transmission and distribution service on the one hand, and market pricing for and/or customer choice of generation on the other. Historically, the state regulatory frameworks in the service area of the AEP System reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility's rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes. While the historical framework remains in a portion of AEP's service territory, recovery of increased fuel costs (i) is no longer provided for in Ohio and (ii) may be limited in Indiana and Michigan, which have capped rates. Fuel recovery is also limited in the ERCOT area of Texas, but because AEP sold MECPL and MEWTU, there is little impact on AEP of fuel recovery procedures related to service in ERCOT. The following state-by-state analysis summarizes the regulatory environment of each jurisdiction in which AEP operates. Several public utility subsidiaries operate in more than one jurisdiction. Indiana: I&M provides retail electric service in Indiana at a bundled rate approved by the IURC. While rates are set on a cost-of-service basis, utilities may also generally seek to adjust fuel clause rates quarterly. I&M's base rate is capped through December 31, 2004 and its fuel recovery rate is capped through February 29, 2004. Ohio: CSPCo and OPCo operate as functionally separated utilities and provide "default" retail electric service to customers at unbundled rates established by the Ohio Act through December 31, 2005. Thereafter, CSPCo and OPCo will continue to provide distribution services to retail customers at rates approved by the PUCO. These rates will be frozen from December 31, 2005 to (i) December 31, 2008 for CSPCo and (ii) December 31, 2007 for OPCo. Transmission services will continue to be provided at rates established by the FERC. Default retail generation service rates will be based on market prices pursuant to rules currently under consideration by the PUCO. Oklahoma: PSO provides retail electric service in Oklahoma at a bundled rate approved by the OCC. PSO's rates are set on a cost-of-service basis. Fuel and purchased power costs above the amount included in base rates are recovered by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is adjusted quarterly and is based upon forecasted fuel and purchased power costs. Over or under collections of fuel costs for prior periods can be recovered when new quarterly factors are established. Texas: The Texas Act requires the legal separation of generation-related assets from transmission and distribution assets. TCC and TNC currently operate on a functionally separated basis. In January 2002, TCC and TNC transferred all their retail customers in the ERCOT area of Texas to MECPL, MEWTU and AEP Commercial and Industrial REP (an AEP affiliate). TNC's retail SPP customers were ultimately transferred to Mutual Energy SWEPCo L.P. (an AEP affiliate). TCC and TNC provide retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules. The implementation of the business separation plan for SWEPCo operations in the SPP area of Texas was delayed by the PUCT. As such, SWEPCo's Texas operations continue to operate and to be regulated as a traditional bundled utility with both base and fuel rates. Virginia: APCo provides unbundled retail electric service in Virginia. APCo's unbundled generation, transmission (which reflect FERC approved transmission rates) and distribution rates as well as its functional separation plan were approved by the VSCC in December 2001. The Virginia Act capped base rates at their mid-1999 levels until the end of the transition period (July 1, 2007), or sooner if the VSCC finds that a competitive market for generation exists in Virginia. The Virginia Act permits APCo to seek a one-time change to its capped non-generation rates after January 1, 2004. The Virginia Act allows adjustments to fuel rates during the transition period and continues to permit utilities to recover their actual fuel costs, the fuel component of their purchased power costs and certain capacity charges. APCo recovers its generation capacity charges through capped base rates. West Virginia: APCo and Wheeling Power Company provide retail electric service at bundled rates approved by the WVPSC. A plan to introduce customer choice was approved by the West Virginia Legislature in its 2000 legislative session. However, implementation of that plan was placed on hold pending necessary changes to the state's tax laws in a subsequent session. Those changes have not been made. While West Virginia generally allows recovery of fuel costs, the most recent proceeding resulted in the suspension of an active fuel clause for APCo and WPCo (though they continue to recover fuel costs through fixed bundled rates). APCo and Wheeling Power Company are currently unable to change the current level of fuel cost recovery, though this ability could be reinstated in a future proceeding. Other Jurisdictions: The public utility subsidiaries of AEP also provide service at regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled rates in Michigan. The table below illustrates the current rate regulation status of the states in which the public utility subsidiaries of AEP operate:
Percentage Fuel Clause Rates Of AEP System Sales System Status of Base Rates for Profits Shared Retail Jurisdiction Power Supply Energy Delivery Status Includes w/Ratepayers Revenues(1) -------------- -------------------- -------------------- --------------- --------------- --------------- ---------------- Ohio Frozen through 2005 Distribution frozen None Not applicable Not applicable 30% through 2007 for OPCo and 2008 for CSP; Transmission frozen through 2005 Texas (TCC, TNC) See footnote 2 Not capped or frozen Not applicable Not applicable Not applicable 17%(2) Texas (SWEPCo) Capped until Active Fuel and fuel Yes, above base 3% 6/15/03 portion of levels purchased power Indiana Capped until Capped until Fuel and fuel No 10% 1/1/05(3) 3/1/04(3) portion of purchased power Virginia Capped until as Capped until as late Active Fuel and fuel No 9% lateas 7/1/07(4) as 7/1/07(4) portion of purchased power West Virginia Fixed(5) Suspended(5) Fuel and fuel Yes, but 9% portion of suspended purchased power Oklahoma Cap expired 1/1/03 Active Fuel and fuel Yes 9% portion of purchased power Louisiana Capped until Active Fuel and fuel Yes, above base 5% 6/15/05 portion of levels purchased power Kentucky Frozen until Active Fuel and fuel Yes, above base 3% 6/15/03(6) portion of levels purchased power Arkansas Capped until Active Fuel and fuel Yes, above base 2% 6/15/03 portion of levels purchased power Michigan Capped until Capped until Capped until Fuel and fuel Yes, in some 2% 1/1/05(7) 1/1/05(7) 1/1/04(8) portion of areas, but purchased suspended power Tennessee Not capped or Active Fuel and fuel No 1% frozen portion of purchased power
(1) Represents the percentage of revenues from sales to retail customers from AEP utility companies operating in each state to the total AEP System revenues from sales to retail customers for the year ended December 31, 2002. (2) Retail electric service in the ERCOT area of Texas is provided to most customers through unaffiliated REPs which must offer PTB rates until January 1, 2007. The percentage of revenues shown includes revenues from power sales contracts between MECPL and TCC and MEWTU and TNC. (3) Capped base and fuel rates pursuant to a 1999 settlement with base rate freeze extended pursuant to merger stipulation. (4) Base rates are capped until the earlier of 7/1/07 or a finding by the VSCC that a competitive market for generation exists. One-time change in non-generation rates is allowed in Virginia after 1/1/04. (5) Rates fixed and expanded net energy clause suspended in West Virginia pursuant to a 1999 rate case stipulation, but subject to change in a future proceeding. (6) Utilities may request that an environmental surcharge be imposed to recover costs associated with the installation of emission control equipment. (7) Capped base and fuel rates pursuant to a 1999 settlement and base rates extended pursuant to merger stipulation. (8) Michigan fuel rates capped until 1/1/04 pursuant to a 1999 fuel settlement. FERC Under the FPA, FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. FERC regulations require AEP to provide open access transmission service at FERC-approved rates. The transmission service regulated by FERC is predominantly wholesale transmission service, which is service not associated with bundled electricity sales to retail customers. FERC also regulates unbundled transmission service to retail customers. Under the FPA, the FERC regulates the sale of power for resale in interstate commerce by (i) approving contracts for wholesale sales to municipal and cooperative utilities and (ii) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices. AEP has market-rate authority from FERC, under which most of its wholesale marketing activity takes place. In November 2001, the FERC issued an order in connection with its triennial review of AEP's market based pricing authority requiring (i) certain actions by AEP in connection with its sales and purchases within its control area and (ii) posting of information related to generation facility status on AEP's website. AEP has appealed this order, and the FERC has issued an order delaying the effective date of the order. See Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, included in the updated 2002 Annual Reports, for more information on the current status of this proceeding. Electric Restructuring and Customer Choice Legislation Certain states in AEP's service area have adopted restructuring or customer choice legislation. In general, this legislation provides for a transition from bundled cost-based rate regulated electric service to unbundled cost-based rates for transmission and distribution service and market pricing for the supply of electricity with customer choice of supplier. At a minimum, this legislation allows retail customers to select alternative generation suppliers. Electric restructuring and/or customer choice began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and the ERCOT area of Texas. Electric restructuring in the SPP area of Texas, also scheduled to begin on January 1, 2002, has been delayed by the PUCT. AEP's public utility subsidiaries operate in both the ERCOT and SPP areas of Texas. Implementation of legislation enacted in Oklahoma and West Virginia to allow retail customers to choose their electricity supplier is on hold. In 2001 Oklahoma delayed implementation of customer choice indefinitely. Before West Virginia's choice plan can be effective, tax legislation must be passed to preserve pre-legislation levels of funding for state and local governments. No further legislation has been passed related to restructuring in West Virginia. In February 2003, Arkansas repealed its restructuring legislation. See Note 7 to the consolidated financial statements, entitled Effects of Regulation, included in the updated 2002 Annual Reports, for a discussion of the effect of restructuring and customer choice legislation on accounting procedures. See Management's Discussion and Analysis of Results of Operations and Financial Condition, included in the updated 2002 Annual Reports, under the headings entitled Industry Restructuring and Corporate Separation for a discussion of AEP's corporate separation plan filed with the FERC and related settlement agreements with state commissions and other intervenors. Michigan Customer Choice Customer choice commenced for I&M's Michigan customers on January 1, 2002. Rates for retail electric service for I&M's Michigan customers were unbundled (though they continue to be regulated) to allow customers the ability to evaluate the cost of generation service for comparison with other suppliers. At December 31, 2002, none of I&M's Michigan customers had elected to change suppliers and no alternative electric suppliers are registered to compete in I&M's Michigan service territory. Ohio Restructuring The Ohio Act requires vertically integrated electric utility companies that offer competitive retail electric service in Ohio to separate their generating functions from their transmission and distribution functions. Following the market development period (which will terminate no later than December 31, 2005), retail customers will receive distribution and, where applicable, transmission service from the incumbent utility whose distribution rates will be approved by the PUCO and whose transmission rates will be approved by the FERC. See Regulation--FERC for a discussion of FERC regulation of transmission rates and Regulation--Rates--Ohio for a discussion of the impact of restructuring on distribution rates. CSPCo and OPCo are each presently operating as functionally separated electric utility companies and no longer charge bundled rates for retail electric service. Each has sought and, from certain regulatory authorities, obtained regulatory approval to legally separate its transmission and distribution assets from its generation assets. CSPCo and OPCo are, however, currently determining the regulatory feasibility of complying with restructuring legislation through continued functional separation. Assuming regulatory compliance, it is currently their intention to remain functionally separated. Texas Restructuring The Texas Act substantially amends the regulatory structure governing electric utilities in Texas in order to allow retail electric competition for all customers and requires each utility to separate into (i) a REP, (ii) a power generation company and (iii) a transmission and distribution utility. Upon separation, neither the REP nor the power generation company will be subject to traditional cost of service rate regulation. See Regulation--Rates--Texas for a discussion of the impact of restructuring on rates. SWEPCo, TCC and TNC initially filed a restructuring plan in January 2000 (which they subsequently updated) that the PUCT approved in February 2002. The updated restructuring plan provided for the legal separation of TCC's and TNC's assets in accordance with the Texas Act into (i) an affiliate power generation company, (ii) a transmission and distribution utility and (iii) various REPs, including those subsequently purchased by Centrica (see below). TCC and TNC continue to pursue legal separation as required by the Texas Act. The PUCT has delayed the implementation of the plan for SWEPCo operations within the SPP area of Texas. Under the Texas Act, a REP, which itself cannot own any generation assets, obtains its electricity from power generation companies, EWGs and other generating entities and provides services at generally unregulated rates, except that the prices that may be charged to residential and small commercial customers by REPs affiliated with a utility within the affiliated utility's service area are set by the PUCT until January 1, 2007. This set price is referred to as the "price to beat" rate (PTB). Affiliate REPs are required to offer the PTB rate to all residential and small commercial customers (with a peak usage of less than 1,000 KW) effective January 1, 2002. As described below, AEP sold its affiliate REPs that must provide PTB service. The PTB rate is still relevant to AEP, however, in determining (i) the contingent portion of the sales price of the affiliate REPs AEP sold and (ii) certain of AEP's obligations in the 2004 true-up proceedings. Prior to the start of retail competition in January 2002, AEP formed MECPL and MEWTU to act as affiliate REPs for TCC and TNC respectively. MECPL and MEWTU were sold in December 2002 to Centrica, which assumed all of the rights and obligations of an affiliated REP, including the provision of PTB service and the obligation to provide data necessary for TCC's and TNC's 2004 true-up proceeding. In connection with the sale, TCC and TNC have contracted to supply approximately 90% of MECPL's and MEWTU's respective power requirements relating to former TCC and TNC PTB customers for a two-year period. See Note 12 to the consolidated financial statements, entitled Acquisitions, Distributions and Discontinued Operations, included in the updated 2002 Annual Reports, for more information on the sale of these REPs and AEP's contractual rights and obligations in connection with the sale. The Texas Act also allows certain transmission and distribution utilities whose generation assets were unbundled to recover certain regulatory assets and stranded costs related to their generation assets. For a discussion of (i) regulatory assets and stranded costs subject to recovery by TCC and (ii) rate adjustments made after implementation of restructuring to allow recovery of certain costs by or with respect to TCC and TNC, see Texas Regulatory Asset and Stranded Cost Recovery and Post-Restructuring Wires Charges. Virginia Restructuring The Virginia Act was enacted in 1999 providing for retail choice of generation suppliers to be phased in over the January 1, 2002 to January 1, 2004 period. The Virginia Act required jurisdictional utilities to unbundle their power supply and energy delivery rates and to file functional separation plans by January 1, 2002. APCo filed its plan and, following VSCC approval of a settlement agreement, now operates in Virginia as a functionally separated electric utility charging unbundled rates for its retail sales of electricity. The settlement agreement addressed functional separation, leaving decisions related to legal separation for later VSCC consideration. Texas Regulatory Assets and Stranded Cost Recovery and Post-Restructuring Wires Charges Certain transmission and distribution utilities in Texas whose generation assets were unbundled pursuant to the Texas Act may recover generation-related regulatory assets and generation-related stranded costs. Regulatory assets consist of the Texas jurisdictional amount of generation-related regulatory assets and liabilities in the audited financial statements as of December 31, 1998. Stranded costs consist of the positive excess of the net regulated book value of generation assets over the market value of those assets, taking specified factors into account. The Texas Act allows alternative methods of valuation to determine the fair market value of generation assets, including outright sale, full and partial stock valuation and asset exchanges, and also, for nuclear generation assets, the ECOM model. The Texas Act further permits utilities to establish a special purpose entity to issue securitization bonds for the recovery of regulatory assets and, after the 2004 true-up proceeding, the amount of stranded costs and remaining regulatory assets not previously securitized. Securitization bonds allow for regulatory assets and stranded costs to be refinanced with recovery of the bond principal and financing costs ensured through a non-bypassable rate surcharge by the regulated transmission and distribution utility over the life of the securitization bonds. Any stranded costs not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competitive transition charge to transmission and distribution customers. Regulatory Assets In 1999, TCC filed an application with the PUCT to securitize approximately $1.27 billion of its retail generation-related regulatory assets and approximately $47 million in other qualified restructuring costs. On March 27, 2000, the PUCT issued an order authorizing issuance of up to $797 million of securitization bonds including $764 million for recovery of net generation-related regulatory assets and $33 million for other qualified refinancing costs. The securitization bonds were issued in February 2002. TCC has included a transition charge in its distribution rates to repay the bonds over a 14-year period. In addition, another $185 million of generation-related regulatory assets are being recovered through distribution rates beginning in January 2002. Remaining generation-related regulatory assets of approximately $214 million originally included by TCC in its 1999 securitization request along with certain other regulatory assets will be included in TCC's request to recover stranded costs in the 2004 true-up proceeding. Stranded Costs In a March 2000 filing with the PUCT to determine unbundled transmission and distribution charges and initial stranded cost recovery, TCC requested recovery of an additional $1.1 billion of stranded costs and regulatory assets that were not securitized. In October 2001, the PUCT issued an order in the UCOS proceeding determining an initial amount of TCC ECOM or stranded costs of approximately negative $615 million based upon the PUCT's ECOM model. The ruling indicated that TCC costs were below market after securitization of regulatory assets. TCC disagrees with the ruling and believes it has positive stranded costs in addition to the securitized regulatory assets. As a result of this stranded cost determination, the PUCT ordered TCC to refund $55 million of estimated excess earnings for the period 1999 through 2001 to customers through a credit applied to distribution rates over a five-year period. TCC appealed the PUCT's estimate of stranded costs and refund of excess earnings, among other issues, to the Travis County District Court. This estimate may be superseded by a final determination made as part of the 2004 true-up proceedings. The final amount of TCC's stranded costs including regulatory assets and ECOM will be established by the PUCT in the 2004 true-up proceeding. Pursuant to PUCT rules, if TCC's total stranded costs determined in the 2004 true-up proceeding are less than the amount of securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates. The Texas Third Circuit Court of Appeals ruled in February 2003 that the Texas Act does not contemplate the refunding to customers of negative stranded costs. In addition, the Court ruled that negative stranded costs cannot be offset against other true-up adjustments, including under-recovered fuel amounts. This ruling may be appealed to the Texas Supreme Court, which has discretion as to whether to accept and consider the appeal. 2004 True-Up Proceedings Beginning as early as January 2004, the PUCT will conduct true-up proceedings (with respect to the ERCOT area of Texas) for each investor-owned utility, its affiliated REP and affiliated power generation company. The purpose of the true-up proceeding is to (i) quantify and reconcile the amount of stranded costs and generation-related regulatory assets that have not yet been securitized, (ii) conduct a true-up of the PUCT ECOM model for 2002 and 2003 to reflect market prices determined in required capacity auctions, (iii) establish final fuel recovery balances and (iv) determine the price to beat clawback component. The true-up proceeding will generally result in either additional charges or credits to retail customers through transmission and distribution rates collected by their REPs and remitted to the utility. Stranded Cost and Generation-Related Regulatory Asset Determination: The Texas Act authorized the use of several valuation methodologies to quantify stranded costs and generation-related regulatory assets in the 2004 true-up proceeding, including by the sale of assets. TCC filed a plan of divestiture with the PUCT in December 2002 seeking approval to sell its generation assets to determine their market value. The PUCT has dismissed its proceeding relating to TCC's plan of divestiture in anticipation of promulgating rules of general application regarding stranded cost determination. If the PUCT determines the sale of assets methodology cannot be used to determine the market value of STP, TCC intends to pursue the use of one or more market valuation methods. Divestiture of TCC's interest in STP to a nonaffiliate will also require NRC approval. TNC does not have any recoverable stranded costs or generation-related regulatory assets that can be considered as part of the 2004 true-up. ECOM/Capacity Auction Component: The PUCT used a computer model or projection, called an ECOM model, to estimate stranded costs related to generation plant assets in the UCOS proceeding. In connection with using the ECOM model to calculate the stranded cost estimate, the PUCT estimated the market power prices that will be received in the competitive wholesale generation market. Any difference between the ECOM model market prices and actual market power prices as measured by generation capacity auctions required by the Texas Act during the period of January 1, 2002 through December 31, 2003 will be a component of the 2004 true-up proceeding, either increasing or decreasing the amount of recovery for TCC. Auctions to date have generally indicated that market prices have been lower than the PUCT's ECOM estimates. Unless this is reversed, TCC's recovery in the 2004 true-up proceeding would be increased. In the event TCC has transferred its generation assets to an affiliate, the Texas Act would require TCC to remit to its affiliate the recovery amount accruing after the transfer. See Note 8 to the consolidated financial statements, entitled Customer Choice and Industry Restructuring, included in the updated 2002 Annual Reports, for a discussion of the current calculation of the difference between the market price and ECOM estimate. Fuel Recovery Balance Determination: The amount TCC or TNC recovers in the 2004 true-up proceeding could be increased or reduced (or the amount TCC must refund could be increased) by any under or over-recovery of fuel. The fuel component will be determined by the amount of fuel costs and expenses the PUCT approves based on a final fuel reconciliation that TCC filed on December 2, 2002 and that TNC filed on June 3, 2002. TCC's fuel reconciliation covers its fuel costs from the period beginning July 1, 1998 and ending December 31, 2001. TCC's fuel reconciliation filing seeks approval for $1.6 billion in fuel expense collected from retail customers during that period. TCC's fuel reconciliation filing reflects a fuel over-recovery balance, as of December 31, 2001, of $63.5 million, including interest. A procedural schedule has been set with a hearing scheduled to begin May 7, 2003. TNC's fuel reconciliation requests approval of $292 million in fuel costs associated with serving both ERCOT and SPP retail customers from July 1, 2000 through December 31, 2001. It reflects a fuel under-recovery balance, as of December 31, 2001, of $26.9 million, including interest. The amounts in this paragraph may periodically be adjusted as filings are updated or adjusted. A final order from the PUCT is expected in the first half of 2003. Any under or over-recovery, plus interest thereon, will be recovered from or returned to customers as a component of the 2004 true-up proceeding. Price to Beat Clawback Component: The amount TCC or TNC recovers in the 2004 true-up proceeding could be reduced (or the amount TCC or TNC must refund could be increased) by the PTB clawback component. If MECPL and MEWTU (which are no longer affiliated with TCC or TNC) continue to serve 60% or more of TCC's and TNC's respective PTB load as of January 1, 2004 and the PTB (reduced by non-bypassable wires charges) exceeds the market price of electricity, any such excess must be credited to customers of TCC and TNC in the 2004 true-up proceeding, by up to $150 per customer, subject to certain adjustments. The Texas Act provides that MECPL and MEWTU effectively indemnify TCC and TNC, respectively, for any PTB clawback amounts assessed them. The MECPL and MEWTU sale agreements provide that Centrica (as purchaser of MECPL and MEWTU) and AEP Utilities (the parent of TCC and TNC, as seller of MECPL and MEWTU) will share responsibility for this indemnity. Further Securitization Bonds and Wires Charges: After final determination of its stranded costs and other true-up adjustments by the PUCT, TCC expects to issue securitization bonds in the amount of its non-securitized stranded costs and generation-related regulatory assets determined in the 2004 true-up proceeding. The bonds can have a maximum term of 15 years. If securitization bonds are not issued to finance all non-securitized stranded costs and generation-related regulatory assets, TCC will seek recovery of these amounts as well as its other true-up adjustments, through a non-bypassable competition transition charge in transmission and distribution rates. For a discussion of recovery of regulatory assets and stranded costs in Ohio and Virginia, see Note 8 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, included in the updated 2002 Annual Reports. Competition AEP's public utility subsidiaries have the right (which in some cases is exclusive) to sell electric power at retail within their respective service areas in the states of Arkansas, Indiana, Kentucky, Louisiana, Oklahoma, Tennessee, West Virginia and the SPP area of Texas. In Michigan, Ohio and Virginia, AEP's public utility subsidiaries continue to provide service to customers who have not been offered or have not selected alternate service from competing suppliers. In those states, service is currently being provided according to prescribed rules and rates. In the ERCOT area of Texas, TCC and TNC sell power to Centrica, which provides PTB service to certain former customers of TCC and TNC and must compete for customers. See Regulation -- Rates for a description of the setting of rates for power sold at bundled or unbundled state-regulated rates. The public utility subsidiaries of AEP, like many other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. Legislation has been enacted in Michigan, Ohio, Texas and Virginia that allows for customer choice of generation supplier. Although restructuring legislation has been passed in Oklahoma and West Virginia, it has been delayed indefinitely in Oklahoma and not implemented in West Virginia. In addition, restructuring legislation in Arkansas has been repealed. See Electric Restructuring Legislation. Customer choice legislation generally allows competition in the generation and sale of electric power, but not in its transmission and distribution. See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 8 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, included in the updated 2002 Annual Reports, for further information with respect to restructuring legislation affecting AEP subsidiaries. The public utility subsidiaries of AEP, like the electric industry generally, face increasing competition in the sale of available power on a wholesale basis, primarily to other public utilities and power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market by creating a generation market with fewer barriers to entry and mandating that all generators have equal access to transmission services. As a result, there are more generators able to participate in this market. The principal factors in competing for wholesale sales are price (including fuel costs), availability of capacity and power and reliability of service. AEP's public utility subsidiaries also compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they generally maintain a favorable competitive position. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy. Significant changes in the global economy in recent years have led to increased price competition for industrial customers in the United States, including those served by the AEP System. Some of these industrial customers have requested price reductions from their suppliers of electric power. In addition, industrial customers that are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, providing various off-peak or interruptible supply options pursuant to tariffs filed with the various state commissions. Occasionally, these rates are first negotiated, and then filed with the state commissions. The public utility subsidiaries believe that they are unlikely to be materially adversely affected by this competition. Seasonality Sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP's facilities and the terms of power sale contracts AEP enters into. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP's results of operations and may impact its financial condition. Investments- Gas Operations AEP, through certain subsidiaries, operates and owns an interest in a significant amount of gas-related assets, including: o 6,400 miles of natural gas pipelines between two systems; o 128 billion cubic feet of storage among two facilities; o Five natural gas processing plants; and o Certain gas marketing contracts. AEP enters into transactions for the purchase and sale of natural gas. Gas transactions are executed over-the-counter with counterparties or through brokers. Gas transactions are also executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission. Brokers and counterparties may require cash or cash related instruments to be deposited on these transactions as margin against open positions. AEP trades gas contracts with numerous counterparties. Since AEP's open gas trading contracts are valued based on changes in market gas prices, our exposures change daily. In October 2002, AEP announced its plans to reduce its exposure to energy trading markets and to downsize the trading and wholesale marketing operations. It is expected that in the future trading and marketing operations will be smaller in scope, will generally be limited to risk management around AEP assets and, accordingly, focused in regions in which AEP owns assets. Investments- UK Operations AEP, through certain subsidiaries, operates and owns 4,000 MW of power generation facilities in the UK and engages in the following activities: o Selling wholesale power in the UK. o Trading and marketing power in transactions predominantly limited to risk management around assets used or managed by AEP subsidiaries in the UK. AEP trades with numerous counterparties. Since AEP's open power trading contracts are valued based on changes in market power prices, our exposures change daily. In October 2002 AEP announced its plans to reduce the exposure to energy trading markets and to downsize the trading and wholesale marketing operations. It is expected that in the future power trading and marketing operations will be smaller in scope and size, will generally be limited to risk management around AEP's assets and, accordingly, focused in those regions in which AEP owns assets. Investments- Other AEP, through certain subsidiaries, conducts certain business operations other than those included in other segments in which it uses and manage the following assets: o 1,879 MW of domestic and 1,235 MW of international power generation facilities; o Coal mines and related facilities; and o Barge, rail and other fuel transportation related assets. These operations include the following activities: o Entering into long-term transactions to buy or sell capacity, energy, and ancillary services of electric generating facilities, either existing or to be constructed, at various locations in North America and Europe. o Through Pro Serv, providing engineering, construction, project management and other consulting services for energy-related projects. o Holding and/or operating various properties, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Louisiana, Ohio, Pennsylvania and West Virginia. o Through MEMCO Barge Line Inc., transporting coal and dry bulk commodities, primarily on the Ohio, Illinois, and Lower Mississippi rivers for AEP, as well as unaffiliated customers. AEP, through certain subsidiaries, owns or leases 7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity. AEP has entered into an agreement with The Dow Chemical Company to construct a 900 MW cogeneration facility at Dow's chemical facility in Plaquemine, Louisiana. Commercial operation is expected in November 2003. AEP is entitled to 100% of the facility's capacity and energy over The Dow Chemical Company's requirements and has contracted to sell the power from this facility to an unaffiliated party. AEP has made certain investments in telecommunications, international energy and other concerns. In 2002, AEP wrote down the value of certain of those investments. See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 13 to the consolidated financial statements entitled Asset Impairment and Investment Value Losses, included in the updated 2002 Annual Reports. AEP also sold the following foreign investments in 2002: o SEEBOARD, an electricity supply and distribution company in the United Kingdom serving 2,000,000 customers and covering 3,000 square miles of service territory. o CitiPower, a retail electricity and gas supply and distribution subsidiary in Australia serving 240,000 customers. See Note 12 to the consolidated financial statements entitled Acquisitions, Dispositions and Discontinued Operations, included in the updated 2002 Annual Reports.