UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 COMMISSION FILE NUMBER 0-19281 The AES Corporation (Exact name of registrant as specified in its charter) Delaware (State of other jurisdiction of incorporation or organization) 1001 North 19th Street Arlington, Virginia (Address of principal executive offices) 54 1163725 (I.R.S. Employer Identification No.) 22209 (Zip Code) Registrant’s telephone number, including area code: (703) 522-1315 Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Common Stock, par value $0.01 per share Name of Each Exchange on Which Registered New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Title of Each Class Name of Each Exchange on Which Registered Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ( No 9 Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 9 The aggregate market value of Registrant’s voting stock held by non-affiliates of Registrant, at March 2, 2002, was $2,661,751,402. The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, at March 2, 2002, was 534,019,090. DOCUMENTS INCORPORATED BY REFERENCE The Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 25, 2002 is hereby incorporated by reference. Certain information therein is incorporated by reference into Part III hereof. PART I ITEM 1—BUSINESS (a) General Development of Business. Overview The AES Corporation (including all its subsidiaries and affiliates, and collectively referred to herein as ‘‘AES’’ or the ‘‘Company’’ or ‘‘we’’) is a global power company committed to serving the world’s needs for electricity in a socially responsible way. AES’s total megawatts (‘‘MW’’) in the 179 power plants in operation or under construction is approximately 62,852MW and net equity ownership (total MW adjusted for the Company’s ownership percentage) represents approximately 50,764MW. AES participates primarily in four lines of business: contract generation, competitive supply, large utilities and growth distribution. Contract Generation. AES’s contract generation line of business is made up of multiple power generation facilities located around the world that have contractually limited their exposure to commodity price risks, primarily electricity prices. These facilities limit their exposure to electricity price volatility by entering into long-term (five years or longer) power purchase agreements for 75% or more of their output capacity. Because they have contracted for a majority of their anticipated output, they are able to project their fuel supply requirements and also, generally, enter into long-term agreements for most of their fuel (coal, natural gas or fuel oil or other similar fuel) supply requirements, thereby also limiting their exposure to fuel price volatility. Through these contractual agreements, the businesses generally increase the predictability of their cash flows and earnings. In order to meet AES’s definition of its contract generation segment, long-term power purchase agreements have minimum initial durations of five years or longer and are typically entered into with one major customer, but may also be with a series of unrelated customers. In addition, AES may enter into tolling or ‘‘pass through’’ arrangements whereby the counter party directly assumes the risks associated with providing the necessary fuel and marketing the resulting power output generated. AES currently has 60 contract generation facilities in operation totaling 21,590 Gross MW and seven facilities under construction for an additional 3,388MW located in six different countries. The operating facilities have an average of 13 years remaining on their power purchase agreements and are located in 19 different countries, including 27% (5,843MW) in North America, 26% (5,704MW) in South America, 25% (5,349MW) in Asia, 16% (3,413MW) in Europe/Africa, and 6% (1,281MW) in the Caribbean. Customer types include private utilities, governments and commercial electric trading companies. AES’s contract generation business represented approximately 30% of pre-tax segment income and 27% of total revenues in 2001 compared to 31% and 23%, respectively in 2000. Competitive Supply. AES’s competitive supply line of business is oriented around the customer perspective and consists of generating facilities and retail supply businesses that sell electricity directly to wholesale and retail customers in competitive markets. Additionally, as compared to the contract generation segment discussed above, these generating facilities generally sell less than 75% of their output pursuant to long-term contracts with pre-determined pricing provisions and/or sell into power pools, under shorter-term contracts or into daily spot markets. The prices paid for electricity under short-term contracts and in the spot markets can be, and from time to time have been, unpredictable and volatile. The results of operations of AES’s competitive supply business is also more sensitive to the impact of market fluctuations in the price of electricity, natural gas, coal and other raw materials. This line of business includes generating facilities located around the world and the New Energy group of companies, which market electricity to commercial and industrial customers in those states in the U.S. that have introduced a competitive market for the sale of electricity to end users and in the U.K. The generating facilities included in this line of business represent 19,713 Gross MW in 8 different countries, including 42% (8,414MW) in Asia, 28% (5,476MW) in Europe/Africa, 14% (2,730MW) in South America, 9% (1,721MW) in North America and 7% (1,372MW) in the Caribbean. In addition, 2 AES is also currently in the process of adding approximately 4,121MW to its competitive operating supply portfolio. This line of business represented approximately 9% of pre-tax segment income and 29% of total revenues in 2001 compared to 21% and 32%, respectively in 2000. Large Utilities. AES’s large utility business is comprised of five integrated utilities located in the U.S. (IPALCO and CILCORP), Brazil (Eletropaulo Metropolitana (‘‘Eletropaulo’’) and Companhia Energetica de Minas Gerias (‘‘CEMIG’’)) and Venezuela (C.A. La Electricidad de Caracas (‘‘EDC’’)). AES’s equity interest in each of these utilities is over 70% other than CEMIG in which AES’s equity interest is approximately 21%. As of December 31, 2001, AES also owned a minority interest in a sixth utility, Light-Servicos de Electricidade S.A. (‘‘Light’’), which was exchanged in February 2002 for an additional ownership interest in Eletropaulo. All of these utilities are of significant size, and all but CILCORP maintain a monopoly franchise within a defined service area. In most cases large utilities combine generation, transmission and distribution capabilities. Large utilities are subject to extensive local, state and national regulation relating to ownership, marketing, delivery and pricing of electricity and gas with a focus on protecting customers. Large utility revenues result primarily from electricity sales to customers under tariff or concession agreements and to a lesser extent from contractual agreements of varying lengths and provisions. AES’s large utilities, including IPALCO (3,036MW), CILCORP (1,157MW), Light (793MW), EDC (2,265MW) and CEMIG (5,668MW), aggregate 12,919 Gross MW of generation capacity and serve over thirteen million customers with annual sales of nearly 120,000 gigawatt hours. AES’s large utility business represented approximately 51% of pre-tax segment income and 26% of total revenues in 2001 compared to 46% and 28%, respectively in 2000. Growth Distribution. AES’s growth distribution line of business includes distribution facilities that offer significant potential for growth because they are located in developing countries or regions where the demand for electricity is expected to grow at a higher rate than in more developed areas. However, these businesses face particular challenges relating to operational difficulties such as outdated equipment, significant non-technical or theft related losses, cultural problems associated with safety and non-payment, emerging economies as well as potentially less stable governments or regulatory regimes. Often however, the conditions of the business environment in a developing nation also provide for significant opportunities to implement operating improvements that may stimulate growth in earnings and cash flow performance at rates greater than those typically achievable in AES’s large utility segment. Distribution facilities included in this line of business may include integrated generation, transmission, distribution or related services companies. AES’s growth distribution business represented approximately 10% of pre-tax segment income and 18% of total revenues in 2001 compared to 2% and 17%, respectively in 2000. The facilities currently in this line of business represent 800 Gross MW of integrated generation and serve approximately 5.4 million customers with sales exceeding 30,844 gigawatt hours in Argentina, Brazil, Cameroon, Dominican Republic, El Salvador, Georgia, Kazakhstan and Ukraine. Reorganization. The Company has recently completed a reorganization to enhance operating performance, including further reductions of operating costs and revenue enhancements. This reorganization has included the creation of four Chief Operating Officer positions who, together with the CEO, constitute the Executive Office. Each COO is directly responsible for managing a portion of the Company’s geographically dispersed businesses as well as coordinating Company wide efforts associated with one of the Company’s business segments. In addition, two special offices, the Cost Cutting Office and the Turnaround Office, have been created to bring improved focus and coordination to the management of expenses across the Company and to improve or dispose of businesses that AES believes to be under-performing businesses from a return on capital perspective, respectively. Each of these offices reports to the Executive Office. Several additional efforts are being undertaken to respond to the current condition of the electricity and capital markets and their impacts on AES businesses, however, there can be no assurance that the initiatives described above or any others that are being, or may be, taken will have the anticipated positive effect. 3 The Company, a corporation organized under the laws of Delaware, was formed in 1981. AES has its principal offices located at 1001 North 19th Street, Suite 2000, Arlington, Virginia 22209. Its telephone number is (703) 522-1315, and its web address is http://www.aesc.com. The Company currently employs approximately 38,000 people worldwide. Cautionary Statements and Risk Factors The Company wishes to caution readers that the following important factors, among others, indicate areas affecting the Company, which involve risk and uncertainty. These factors should be considered when reviewing the Company’s business, and are relied upon by AES in issuing any forward-looking statements. Such factors could affect AES’s actual results and cause such results to differ materially from those expressed in any forward looking statements made by, or on behalf of, AES. Some or all of these factors may apply to the Company’s businesses as currently maintained or to be maintained. • The inability to raise capital on favorable terms, to refinance existing short-term corporate or subsidiary indebtedness or to fund operations, future acquisitions, construction of new plants (known as ‘‘greenfield development’’) and other capital commitments, particularly during times of uncertainty in the capital markets and in those areas of the world where the capital and bank markets are underdeveloped. • Changes in operation and availability of the Company’s generating plants (including wholly and partially owned facilities) compared to the Company’s historical performance; changes in the Company’s historical operating cost structure, including but not limited to those costs associated with fuel, operations, supplies, raw materials, maintenance and repair, people, environmental compliance, including the costs of required emission offsets, purchase and transmission of electricity and insurance; changes in the availability of fuel, supplies, raw materials, emission offsets, transmission access and insurance; changes or increases in planned or unplanned capital expenditures or other maintenance activities, including but not limited to expenditures relating to environmental emission equipment, changes in law or regulation, sudden mechanical failure, or acts of God. • Failure by the Company to achieve significant operating improvements and cost reductions in many of its distribution businesses; changes in the historical or expected cost structure of its distribution businesses, including unexpected increases in planned or unplanned capital expenditures or other maintenance activities; inability to predict, influence or respond appropriately to changes in law or regulatory schemes; inability to obtain redress from regulatory authorities. • Inability to obtain expected or contracted changes in electricity tariff rates or tariff adjustments for increased expenses, changes in the underlying foreign currency exchange rates or unexpected changes in those rates or adjustments; the ability or inability of AES to obtain, or hedge against, in an economical manner, foreign currency; foreign currency exchange rates and fluctuations in those rates; local inflation and monetary fluctuations; import and other charges or taxes; conditions or restrictions impairing repatriation of earnings or other cash flow; the economic, political and military conditions affecting property damage, interruption of business and expropriation risks; changes in trade, monetary and fiscal policies, laws and regulations; unwillingness of governments to honor contracts or other activities of governments, agencies, government-owned entities and similar organizations; development progress and other social and economic conditions; inability to obtain access to fair and equitable political, regulatory, administrative and legal systems, enforcement of judgments or a just result; nationalizations and unstable governments and legal systems, and intergovernmental disputes; inability to protect the Company’s rights and assets due to dysfunctional, corrupt or ineffective administrative or legal systems. 4 • In certain jurisdictions where the Company’s electricity tariffs are subject to regulatory review or approval, changes in the application or interpretation of regulatory provisions including, but not limited to, changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs, changes arising from changes in the underlying foreign currency exchange rates, changes in the definition or determination of controllable or non-controllable costs, changes in the definition of events which may or may not qualify as changes in economic equilibrium, changes in the timing of tariff increases or other changes in the regulatory determinations under the relevant concessions, state or federal regulatory provisions; unwillingness of regulatory bodies to take required actions, retrenchment or delay in taking action. • Changes in the amount of, and rate of growth in, AES’s selling, general and administrative expenses; the impact of AES’s ongoing evaluation of its development costs, business strategies and asset valuations, including, but not limited to, the effect of a failure to successfully complete certain acquisition, construction or development projects. • Legislation intended to promote competition in U.S. and non-U.S. electricity markets, including the effects of such legislation upon existing contracts, such as: (i) The New Energy Trading Arrangements (‘‘NETA’’) in the United Kingdom (see also the description of the AES Drax facility under Regulatory Outlook for related matters); (ii) legislation currently receiving serious consideration in the United States Congress to repeal (a) the Public Utility Regulatory Policies Act of 1978, as amended, or at least to repeal the obligation of utilities to purchase electricity from qualifying facilities, and (b) the Public Utility Holding Company Act of 1935, as amended; (iii) changes in regulatory rule-making by the Securities and Exchange Commission, the Federal Energy Regulatory Commission or other regulatory bodies; (iv) changes in energy taxes; (v) new legislative or regulatory initiatives in U.S. and non-U.S. countries; and (vi) changes in national, state or local energy, environmental, safety, tax and other laws and regulations applicable to the Company or its operations. • A reversal or continued slowdown of the trend toward electricity industry deregulation in the various markets that the Company is conducting or is seeking to conduct business. • The prolonged failure by any significant customer of the Company or any of its subsidiaries to fulfill its contractual payment obligations presently or in the future, either because such customer is financially unable to fulfill such contractual obligation or otherwise refuses to do so. • Successful and timely completion of (i) the respective construction of each of the Company’s electric generating projects now under construction and those projects yet-to-begin construction or (ii) capital improvements to existing facilities. • Successful and timely completion of pending and future acquisitions; conducting appropriate due diligence; assumptions regarding the performance of countries, markets, and models. • The effects of a strengthening dollar against foreign currencies; the lack of portability of products and services produced by the company’s power plants and distribution companies beyond the local markets where such products or services are produced; failure by the Company to include dollar indexation and other protective provisions in contracts or through third party hedging mechanisms, or the refusal of contracting parties to abide by such provisions when included. • The effects of a worldwide depression, recession or economic downturn; prolonged economic crisis in countries, states or regions where the Company conducts, or is seeking to conduct, its business; political, economic and market instability related to or resulting from economic crisis and the related collateral effects, including, but not limited to, riots, looting, destruction of property, terrorism and civil war. 5 • Changes and volatility in inflation, fuel, electricity and other commodity prices in U.S. and non-U.S. markets; conditions in financial markets, including fluctuations in interest rates and the availability of capital; temporary or prolonged over/under supply in key markets and changes in the economic and electricity consumption growth rates in the United States and non-U.S. countries. • Adverse weather conditions and the specific needs of each plant to perform unanticipated facility maintenance or repairs or outages (including annual or multi-year), or to install pollution control equipment or other environmental emission equipment. • The costs and other effects of legal and administrative cases, arbitrations or proceedings, settlements and investigations, claims (including insurance claims for losses suffered), and changes in those items, developments or assertions by or against AES; the effect of new, or changes in, accounting policies and practices and the application of such policies and practices. • Changes or increases in taxes on property, plant, equipment, emissions, gross receipts, income or other aspects of the Company’s business or operations; investigation or reversal of the Company’s tax positions by the IRS. (b) Financial Information About Industry Segments And Geographic Areas The Company operates in four business segments: contract generation, competitive supply, large utilities and growth distribution. See Note 16 to the Consolidated Financial Statements included in Item 8 herein for financial information about those segments. (c) Narrative Description of Business. AES is a global power company committed to serving the world’s needs for electricity in a socially responsible way. AES is comprised of four lines of business: contract generation, competitive supply, large utilities, and growth distribution. The contract generation segment includes generating plants that have entered into contracts with initial durations of 5 years or greater accounting for at least 75% of their estimated revenue stream. The competitive supply segment includes both wholesale (through generation facilities with shorter-term market-priced contracts) and retail sales of electricity directly to end users such as commercial, industrial, governmental and residential customers. The large utility segment is characterized by distribution businesses of significant size that often combine generation, transmission and distribution capabilities and are subject to extensive local, state and national regulation. The growth distribution segment includes distribution facilities facing particular challenges relating to operational difficulties that are located in emerging markets and offer significant potential for improved financial and operational performance. Through each of its four business lines, the Company attempts to participate in both regulated and competitive power markets through either greenfield development or by acquiring and operating existing facilities or companies. Elements of the Company’s strategy include: • Supplying energy to customers at the lowest cost possible, taking into account factors such as reliability and environmental performance; • Constructing, acquiring and operating projects of a relatively large size in geographically dispersed markets; • To the extent available, maximizing the amount of non-recourse financing; • When available, entering into longer-term power sales contracts or other arrangements with electric utilities or other customers with significant credit strength; 6 • Where possible, participating in distribution markets that grant concessions with long-term pricing arrangements; and • When available, entering into hedging, indexing or other arrangements to protect against fluctuations in currency, fuel costs and electricity prices. The Company also strives for operating excellence as a key element of its strategy, which it believes it accomplishes by minimizing organizational layers and maximizing company-wide participation in decision making. AES has attempted to create an operating environment that results in safe, clean and reliable electricity generation, distribution and supply. Because of this emphasis, the Company prefers to operate all facilities and businesses which it develops or acquires; however, there can be no assurance that the Company will have operating control of all of its facilities. The Company attempts to finance each domestic and foreign project primarily under loan agreements and related documents which, except as noted below, require the loans to be repaid solely from the project’s revenues and provide that the repayment of the loans (and interest thereon) is secured solely by the capital stock, physical assets, contracts and cash flow of that project subsidiary or affiliate. This type of financing is usually referred to as non-recourse debt or ‘‘project financing.’’ The lenders under these project financing structures generally do not have recourse to AES, the parent company, or its other projects for repayment, unless such entity explicitly agrees to undertake liability. AES has explicitly agreed to undertake certain limited obligations and contingent liabilities, most of which by their terms will only be effective or will be terminated upon the occurrence of future events. These obligations and liabilities take the form of guarantees, indemnities, letter of credit reimbursement agreements, and agreements to pay, in certain circumstances, to project lenders or other parties. To the extent AES becomes liable under guarantees and letter of credit reimbursement agreements, distributions received by AES from other projects are subject to the possibility of being utilized by AES to satisfy these obligations. To the extent of these obligations, the lenders to a project effectively have recourse to AES and to the distributions to AES from other projects. The aggregate contractual liability of AES is, in each case, usually a small portion of the aggregate project debt, and thus the project financing structures are generally described herein as being ‘‘substantially non-recourse’’ to AES and its other projects. AES has also hedged a substantial portion of its projects against the risk of fluctuations in interest rates. In each project with fixed capacity payments, AES has attempted to hedge all or a significant portion of its risk of interest rate fluctuations by arranging for fixed-rate financing or variable-rate financing with interest rate swaps or other hedging mechanisms. Contract Generation. AES’s contract generation line of business is made up of multiple power generation facilities located around the world that have contractually limited their exposure to commodity price risks, primarily electricity prices. These facilities limit their exposure to electricity price volatility by entering into long-term (five years or longer) power purchase agreements for 75% or more of their output capacity. Because they have contracted for a majority of their anticipated output, they are able to project their fuel supply requirements and also generally enter into long-term agreements for most of their fuel (coal, natural gas, fuel oil or other similar fuel) supply requirements, thereby limiting their exposure to fuel price volatility. Through these contractual agreements, the businesses generally increase the predictability of their cash flows and earnings. In order to meet AES’s definition of its contract generation segment, long-term power purchase agreements have a minimum duration of five years or longer and are typically entered into with one major customer, but may also be with a series of unrelated customers. In addition, AES may enter into tolling or ‘‘pass-through’’ arrangements whereby the counter-party assumes the risks associated with providing the necessary fuel and marketing the resulting power output generated. AES’s contract generation business represented approximately 30% of pre-tax segment income and 27% of total revenues in 2001 compared to 31% and 23%, respectively in 2000. 7 AES currently has 60 contract generation facilities in operation totaling 21,590 Gross MW. The operating facilities have an average of 13 years remaining on their sales contracts and are located in 19 different countries, including 27% (5,843MW) in North America, 26% (5,704MW) in South America, 25% (5,349MW) in Asia, 16% (3,413MW) in Europe/Africa, and 6% (1,281MW) in the Caribbean. Customer types include private utilities, governments and commercial electric trading companies. AES is also currently in the process of adding approximately 3,388MW in six different countries to its contract generation operating portfolio through its greenfield development. These include a 832MW natural gas-fired plant in the United States, a 454MW coal-fired plant in Puerto Rico, a 310MW natural gas-fired plant in the Dominican Republic, a 450MW natural gas-fired plant in Bangladesh, a 427MW natural gas-fired plant in Oman, a 750MW natural gas-fired plant in Qatar and a 165MW natural gas-fired plant in Sri Lanka. Typically, AES enters into long-term power purchase agreements or tolling agreements with electric utilities, power marketing firms and state-owned power companies. Although the specific terms of individual sales contracts may vary significantly, power purchase agreements or other similar arrangements for the sale of electricity (including tolling agreements or financially settled hedging agreements) generally contain pricing provisions that reflect the two principal products, capacity and energy, produced by electric generating facilities. Energy refers to the sale of the actual electricity produced by the generation facility and capacity refers to the amount of generation reserved for a particular customer, irrespective of the amount of energy actually purchased. To the extent possible, the Company attempts to structure its power generation facilities’ fuel supply contracts so that fuel costs are indexed in a manner similar to the energy payments a project receives under its power purchase agreement. In this way, project revenues are partially or completely hedged against fluctuations in fuel costs. However, there can be no guarantee that such arrangements will be available or, if available, will be an effective hedge. A significant portion of AES’s contract generating business is comprised of agreements whereby a single customer contracts for the majority, if not all, of a given power generation facility’s revenues. The prolonged failure of any significant customer to fulfill its contractual payment obligations in the future could have a substantial negative impact on AES’s results of operations and financial condition. AES has sought to reduce this risk, where possible, by contracting with customers who have their debt or preferred securities rated ‘‘investment grade,’’ or by obtaining sovereign government guarantees of the customer’s obligations. However, AES does not limit its business solely to the most developed countries or economies, nor even to those countries with investment grade sovereign credit ratings. In certain locations, particularly in developing countries or countries that are in a transition from centrally planned to market oriented economies, the electricity purchasers, both wholesale and retail, may be unable or unwilling to honor all of their contractual payment obligations. Moreover, collection of receivables may be hindered in some countries due to ineffective systems for adjudicating contract disputes. In order to minimize the risk of contract abrogation, AES maintains flexibility with its customers. In many instances, AES is able to avoid abrogation by creatively restructuring contracts without disadvantaging itself. Where this is not possible, AES diligently pursues resolution through litigation or contractually prescribed arbitration. AES believes that locating its plants in different geographic areas helps to mitigate the effects of regional economic downturns, thereby in part mitigating a portion of the risks imposed by operating in less developed countries. Because the stability of revenues for each power generation facility is dependent upon the predictability and containment of costs of operation, utilization of low-cost technology, selection of favorable sites and availability of quality fuel and permits contributes to the success of the contract generation business. AES seeks to enter into ‘‘turnkey’’ engineering contracts for each power generation facility it develops. Turnkey contracts allow AES to more reliably establish the total cost of construction and development and to delegate the majority of the construction responsibilities thereby 8 eliminating a significant portion of the cost uncertainties otherwise inherent in new power plant development. Competitive Supply. AES’s competitive supply line of business is oriented around the customer perspective and consists of generating facilities and retail supply businesses that sell electricity directly to wholesale and retail customers in competitive markets. Additionally, as compared to the contract generation segment discussed above, these generating facilities generally sell less than 75% of their output pursuant to long-term contracts with pre-determined pricing provisions and/or sell into power pools, under shorter-term contracts or into daily spot markets. The generating facilities included in this line of business represent 19,713 Gross MW in 8 different countries, including 42% (8,414MW) in Asia, 28% (5,476MW) in Europe/Africa, 14% (2,730MW) in South America, 9% (1,721MW) in North America and 7% (1,372MW) in the Caribbean. In addition, AES is also currently in the process of adding approximately 4,121MW to its competitive supply operating portfolio through its construction of new plants. These include a 210 MW natural gas-fired plant, a 450 MW natural gas-fired plant, two 720 MW natural gas-fired plants, a 500 MW natural gas-fired plant and a 1,056 MW natural gas-fired plant in the United States, a 123 MW hydroelectric facility in Argentina, two hydroelectric facilities totaling 230MW in Panama, and a 112 MW natural gas-fired plant in Tanzania. In the case of several generating facilities, including Drax, only a portion of the output is subject to the provisions of long term price hedging instruments. This line of business represented approximately 9% of pre-tax segment income and 29% of total revenues in 2001 compared to 21% and 32%, respectively for 2000. The retail portion of AES’s competitive supply business focuses on providing electricity and energy related products and services to commercial and industrial end users through the New Energy group of companies in the U.K. and in those states in the U.S. that have introduced a competitive market for the sale of electricity to end users, including California, Delaware, Illinois, Maine, Maryland, Massachusetts, New Hampshire, New York, Ohio, Pennsylvania, Rhode Island and Texas. The New Energy group of companies has approximately 2,700 customers. In these markets, AES typically enters into single or multi-year electricity supply contracts with its customers. These contracts may be structured as shared savings arrangements, fixed savings arrangements or fixed price supply contracts. AES also engages in wholesale purchases and sales of electricity to support its retail electricity sales to consumers. The wholesale purchases or sale of electricity often require substantial additional credit support, and this credit support currently is provided to New Energy through (i) Letters of Credit backed by AES, (ii) third parties such as surety companies or (iii) guarantees by AES. AES is currently evaluating whether continuing to provide such credit support for New Energy’s business is an appropriate use of its capital resources, and is exploring alternative credit arrangements for New Energy. Such arrangements may include finding a third party credit provider for all of New Energy’s credit needs, or a sale of part or all of AES’s interest in New Energy. In managing supply and price risk, all options for supply are actively considered, including (i) utilizing the output from AES owned generating assets, (ii) building or acquiring additional generating assets and (iii) buying electricity from other generators or marketers. AES permits its wholesale and retail businesses to operate independently without forcing integration, while allowing integration to occur in those instances where it is economically advantageous to AES to do so. The prices paid for electricity under short-term contracts and in the spot markets can be, and from time to time have been, unpredictable and volatile. This volatility is influenced by peak demand requirements, weather conditions, competition, market regulation, interest rate and foreign exchange rate fluctuations, electricity transmission and environmental emission constraints, the availability or prices of emission credits and fuel prices, as well as plant availability and other relevant factors. In addition to exposure to the risks associated with market movement, the competitive supply business is also exposed to credit risk either because such business may be required to establish sufficient credit to support its operations, or because of the potential nonperformance of contractual obligations by a counterparty. AES maintains credit policies with regard to its counterparties, however, there can be no assurance that 9 these parties will ultimately be able to pay when called to do so. The absence of long-term contracts can also result in uncertainty relating to future production volumes, which in turn causes uncertainty with respect to the volume of fuel to be consumed to support such production. As a result, the competitive supply business may also be exposed to volume risk in connection with its purchase of natural gas, coal and other raw materials. In the U.S., AES hedges certain aspects of its ‘‘net open’’ positions. AES has used a hedging strategy, where appropriate, to hedge its financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy involves the use of commodity forward contracts, futures, swaps and options. Large Utilities. AES’s large utility business is comprised of five integrated utilities located in the U.S. (IPALCO and CILCORP), Brazil (Eletropaulo and CEMIG) and Venezuela (EDC). AES’s equity interest in each of these utilities is over 70% other than CEMIG in which AES’s equity interest is only 21%. As of December 31, 2001, AES also owned a minority interest in a sixth utility, Light, which was exchanged in February 2002 for an additional ownership interest in Eletropaulo. All of these utilities are of significant size, and all but CILCORP maintain a monopoly franchise within a defined service area. In most cases large utilities combine generation, transmission and distribution capabilities. Large utilities are subject to extensive local and national regulation relating to ownership, marketing, delivery and pricing of electricity and gas with a focus on protecting customers. Large utility revenues result primarily from customer tariffs and to a lesser extent from contractual agreements of varying lengths and provisions. AES’s large utilities, including IPALCO (3,036MW), CILCORP (1,157MW), Light (793MW), EDC (2,265MW) and CEMIG (5,668MW), aggregate 12,919 Gross MW of generation capacity and serve over thirteen million customers with annual sales of nearly 120,000 gigawatt hours. AES’s large utility business represented approximately 51% of pre-tax segment income and 26% of total revenues in 2001 compared to 46% and 28%, respectively in 2000. Large utility revenues result primarily from electricity sales to customers under regulated tariff or concession agreements and to a lesser extent from contractual agreements of varying lengths and provisions. IPALCO is a holding company and its principal subsidiary is Indianapolis Power & Light Company, or IPL. IPL is engaged primarily in generating, transmitting, distributing and selling electric energy in the City of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, primarily in and around Indianapolis. IPL owns and operates two primarily coal-fired generating plants and a separately-sited combustion turbine that are used for electric generation. IPL also operates one coal and gas-fired plant. For electric generation, the total demonstrated net capability is 3,118MW, net winter capability is 3,129MW and net summer capability is 3,036MW. CILCORP is a holding company whose principal business subsidiary is Central Illinois Light Company (CILCO). CILCO is engaged in the generation, transmission, distribution and sale of electric energy in an area of approximately 3,700 square miles in central and east-central Illinois, and the purchase, distribution, transportation and sale of natural gas in an area of approximately 4,500 square miles in central and east-central Illinois, where the electricity industry has undergone deregulation. As part of its regulatory approval to acquire IPALCO, AES is required to divest CILCORP, which divestiture process is currently underway. Eletropaulo has served the S˜ao Paulo area for over 100 years and is the largest electricity distribution company in Latin America in terms of revenues. Eletropaulo’s concession contract with the Brazilian regulatory agency ANEEL entitles Eletropaulo to distribute electricity in its service area for 30 years. Eletropaulo’s service territory consists of 24 municipalities in the greater S˜ao Paulo metropolitan area and adjacent regions and accounts for about 15% of Brazil’s GDP, covering 4.7 million customers or about 41% of the population in the State of S˜ao Paulo. 10 CEMIG is engaged in electricity generation, transmission and distribution in Minas Gerais State, Brazil. CEMIG operates a distribution network that extends over 270,000 kilometers, the largest in Latin-America, and supplies over 4.5 million customers throughout Minas Gerais State, Brazil. EDC was founded in 1895 and is the largest private-sector electric utility in Venezuela serving approximately 1.1 million customers (approximately 20% of the Venezuelan population). EDC generates, transmits and distributes electricity primarily to metropolitan Caracas and its surrounding area. EDC’s distribution area covers 5,176 square kilometers. EDC has an installed generating capacity of 2,265MW. AES seeks to acquire large utilities that it believes it can successfully restructure by focusing on improving efficiencies to achieve cost savings while providing high quality services to its customers. Each utility employs business personnel with direct contact with its customers. AES believes it is important to manage the regulatory frameworks of its large utilities, which are becoming increasingly competitive. As regulated entities, each large utility is subject to extensive local, state and national regulation relating to ownership, marketing, delivery and pricing of electricity and gas with a focus on protecting customers. Regulatory approval must generally be sought for the purchase, acquisition, sale or disposal of these businesses. In some instances, the approval process can broadly affect all of AES’s public utility holdings. For example, as mentioned above, the provisions of the regulatory approval for AES’s acquisition of IPALCO require AES to relinquish control or dispose of a portion of its regulated assets or businesses in the United States, in particular certain transmission and distribution assets owned by CILCO, a subsidiary of CILCORP, within two years. Growth Distribution. AES’s growth distribution line of business includes distribution facilities that offer significant potential for growth because they are located in developing countries where the demand for electricity is expected to grow at a higher rate than in more developed parts of the world. Additionally, because these facilities face challenges relating to operational difficulties such as outdated equipment, significant non-technical losses, cultural problems, emerging economies, unstable governments, underdeveloped regulatory regimes or location in a developing nation they allow for operating improvements and financial performance improvements greater than that typically seen in the large utility segment. Distribution facilities included in this line of business may include generation, transmission, distribution or related services companies. AES’s growth distribution business represented approximately 10% of pre-tax segment income and 18% of total revenues in 2001 compared to 2% and 17%, respectively in 2000. Growth distribution revenues are derived from the distribution and sale of electricity made pursuant to the provisions of long-term electricity sale concessions granted by the appropriate governmental authorities, or in some locations, under existing regulatory laws and provisions. One of our distribution facilities (‘‘SONEL’’) is ‘‘integrated’’, in that it also owns electric power plants for the purpose of generating a portion of the electricity it sells. The facilities currently in this line of business represent 800 Gross MW of generation and serve over 5.4 million customers with sales exceeding 30,844 gigawatt hours in Argentina, Brazil, Cameroon, Dominican Republic, El Salvador, Georgia and Ukraine. AES believes it can leverage its operating expertise, decentralized approach and considerable experience in developing nations to improve the performance of these facilities. There is currently little competition in the growth distribution business. As deregulation and privatization efforts mature and more developing nations seek competitive power providers, the potential size of this market continues to grow and, depending on the rate of progress, may evolve into either a contract generation or competitive supply business or a large utility. 11 Principles, Values and Practices A core part of AES’s corporate culture is a commitment to ‘‘shared principles or values.’’ These principles describe how AES people endeavor to commit themselves to the Company’s mission of serving the world by providing safe, clean, reliable and low-cost electricity. The principles are: Integrity—AES strives to act with integrity, or ‘‘wholeness.’’ AES people seek to keep the same moral code at work as at home. Fairness—AES wants to treat fairly its people, its customers, its suppliers, its stockholders, governments and the communities in which it operates. Fun—AES desires that people employed by the Company and those people with whom the Company interacts have fun in their work. The Company believes that making decisions and being accountable is fun and has structured its organization to maximize the opportunity for fun for as many people as possible. Social Responsibility—Primarily, the Company believes that doing a good job at fulfilling its mission is socially responsible. But the Company also believes that it has a responsibility to be involved in projects that provide other social benefits, and consequently has instituted programs such as corporate matching of individual charitable gifts in addition to various local programs conducted by AES businesses. AES recognizes that most companies have standards and ethics by which they operate and that business decisions are based, at least in part, on such principles. The Company believes that an explicit commitment to a particular set of standards is a useful way to encourage ownership of those values among its people. While the people at AES acknowledge that they won’t always live up to these standards, they believe that being held accountable to these shared values will help them behave more consistently with such principles. AES makes an effort to support these principles in ways that acknowledge a strong corporate commitment and encourage people to act accordingly. For example, AES conducts annual surveys, both company-wide and at each business location, designed to measure how well its people are doing in supporting these principles through interactions within the Company and with people outside the Company. These surveys are perhaps most useful in revealing failures, and helping to deal with those failures. AES’s principles are relevant because they help explain how AES people approach the Company’s business. The Company seeks to adhere to these principles, not as a means to achieve economic success but because adherence is a worthwhile goal in and of itself. AES Facilities The following tables set forth information regarding the Company’s facilities that are in operation or under construction at December 31, 2001. For a description of risk factors and additional factors that may apply to the Company’s facilities, see also the information contained under the caption ‘‘Cautionary Statements and Risk Factors’’ in Item 1 above, and Item 7, ‘‘Discussion and Analysis of Financial Condition and Results of Operations’’ herein. 12 Generation Facilities Dominant Fuel Year of Acquisition or Commencement of Commercial Operations Geographic Location AES Equity Interest Gross MW (percent) Contract Generation North America Kingston Beaver Valley Thames Shady Point Hawaii Southland-Alamitos Southland-Huntington Beach Southland-Redondo Beach Warrior Run Hemphill Mendota Medina Valley Ironwood Red Oak South America Central Dique Gener-Termoandes Uruguaiana Uruguaiana Tiete (10 plants) GENER-Norgener GENER-Centrogener (9 plants) GENER-Electrica de Santiago GENER-Energia Verde GENER-Guacolda Europe and Africa Bohemia Elsta Ebute Kelvin Kilroot Medway Tisza II Asia Khrami I Khrami II Mktvari Yangchun XiangCi-Cili Wuhu Chengdu Hefei Jiaozuo Aixi-Chongqing Nanchuan Yangcheng (3 plants) OPGC Lal Pir PakGen Meghnaghat Barka Ras Laffan Kelanitissa Mt. Stuart Gas Coal Coal Coal Coal Gas Gas Gas Coal Various Various Gas Gas Gas Gas Gas Gas Gas Hydro Oil Hydro Gas Gas Coal Coal Gas Gas Coal Coal Gas Gas Hydro Hydro Gas Oil Hydro Coal Gas Oil Coal Coal Coal Coal Oil Oil Gas Gas Gas Gas Oil 1997 1987 1990 1991 1992 1998 1998 1998 2000 2001 2001 2001 2001 2002 2000 2000 2000 2000 1999 2000 2000 2000 2000 2000 2001 1998 2001 2001 1992 1996 1996 2000 2000 2000 1996 1996 1996 1997 1997 1997 1998 2001 1998 1997 1998 2002 2003 2004 2002 1999 13 Canada USA USA USA USA USA USA USA USA USA USA USA USA USA Argentina Argentina Brazil Brazil Brazil Chile Chile Chile Chile Chile Czech Republic Netherlands Nigeria South Africa UK UK Hungary Georgia Georgia Georgia China China China China China China China China India Pakistan Pakistan Bangladesh Oman Qatar Sri Lanka Australia 110 125 181 320 180 2,083 563 1,310 180 14 25 47 705 832 68 633 450 150 2,650 277 756 379 37 304 50 405 290 600 520 688 860 113 110 600 15 26 250 48 115 250 50 1,050 420 351 344 450 427 750 165 288 50 100 100 100 100 100 100 100 100 70 100 100 100 100 51 99 100 100 53 99 99 89 99 49 83 50 95 100 92 25 100 0 0 100 25 51 25 35 70 70 70 25 49 90 90 100 85 55 100 100 Generation Facilities Dominant Fuel Contract Generation (continued) Year of Acquisition or Commencement of Commercial Operations Geographic Location AES Equity Interest Gross MW (percent) Ecogen-Jeeralang Ecogen-Yarra Haripur Caribbean Merida III Puerto Rico Itabo Los Mina Andres Competitive Supply North America Deepwater Placerita NY-Cayuga NY-Greenidge NY-Somerset NY-Westover Delano Mountainview Existing Whitefield Huntington Beach 3&4 Granite Ridge Greystone Wolf Hollow Lake Worth Mountainview Development South America San Nicol´as-CTSN Rio Juramento-Cabra Corall Rio Juramento-El Tunal San Juan-Sarmiento San Juan-Ullum Quebrada de Ullum Alicura Parana Caracoles Europe/Africa Borsod Tiszapalkonya Ottana Belfast West Indian Queens Barry Drax Fifoots Songo Songo Asia Ekibastuz Gres Altai-Leninogorsk CHP Altai-Semipalatinsk CHP Altai-Shulbinsk Hydro Altai-Sogrinsk CHP Altai-Ust Kamenogorsk Heat Nets Gas Gas Gas Gas Coal Gas Oil Gas Coal Gas Coal Coal Coal Coal Various Gas Various Gas Gas Gas Gas Gas Gas Coal Hydro Hydro Gas Hydro Hydro Hydro Gas Hydro Coal Coal Oil Coal Gas Gas Coal Coal Gas Coal Coal Coal Hydro Coal Coal 1999 1999 2001 2000 2002 2000 1996 2003 1986 1989 1999 1999 1999 1999 2001 2001 2001 2002 2002 2002 2002 2003 2003 1993 1995 1995 1996 1996 1998 2000 2001 2004 1996 1996 2001 1992 1996 1998 1999 2000 2003 1996 1997 1997 1997 1997 1997 14 Australia Australia Bangledesh Mexico USA Dominican Republic Dominican Republic Dominican Republic USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA Argentina Argentina Argentina Argentina Argentina Argentina Argentina Argentina Argentina Hungary Hungary Italy UK UK UK UK UK Tanzania Kazakhstan Kazakhstan Kazakhstan Kazakhstan Kazakhstan Kazakhstan 449 510 360 484 454 587 210 310 143 120 306 161 675 126 50 126 14 450 720 500 720 210 1,056 650 102 10 33 45 45 1,000 845 123 171 250 140 120 140 230 4,065 360 112 4,000 418 840 702 349 310 100 100 100 55 100 24 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 88 98 98 98 98 100 100 100 100 100 100 100 98 100 100 100 100 49 100 100 100 100 100 0 Generation Facilities Dominant Fuel Year of Acquisition or Commencement of Commercial Operations Geographic Location AES Equity Interest Gross MW (percent) Competitive Supply (continued) Altai-Ust-Kamenogorsk CHP Altai-Ust-Kamenogorsk Hydro Caribbean Bayano Chiriqui-La Estrella Chiriqui-Los Valles Panama Bayano Esti Chivor Colombia I Large Utilities North America CILCORP-Duck Creek CILCORP-Edwards CILCORP-Indian Trails IPALCO- Georgetown IPALCO-Eagle Valley IPALCO-Petersburg IPALCO-Stout South America Light-Fontes Nova* Light-Ilha dos Pombos* Light-Nilo Pecanha* Light-Pereira Passos* CEMIG (35 plants) CEMIG-Miranda CEMIG-Igarapava Caribbean EDC-generation (4 plants) Growth Distribution Europe/ Africa SONEL Distribution Facilities Competitive Supply Eastern Kazakhstan REC Semipalatensk REC Large Utilities North America IPALCO Cilicorp-Electricity South America Light* CEMIG Eletropaulo* Caribbean EDC-distribution Coal Hydro Hydro Hydro Hydro Oil Hydro Hydro Hydro Gas Coal Coal Gas Oil Coal Coal Coal Hydro Hydro Hydro Hydro Hydro Hydro Hydro Gas 1997 1997 1999 1999 1999 1999 2003 2003 2000 2000 1999 1999 1999 2001 2001 2001 2001 1996 1996 1996 1996 1997 1997 1998 2000 Kazakhstan Kazakhstan Panama Panama Panama Panama Panama Panama Colombia Colombia USA USA USA USA USA USA USA Brazil Brazil Brazil Brazil Brazil Brazil Brazil 1,464 331 150 42 48 42 110 120 1,000 90 366 772 19 79 341 1,672 944 144 169 380 100 5,068 390 210 Venezuela 2,265 100 100 49 49 49 49 49 49 96 62 100 100 100 100 100 100 100 24 24 24 24 21 21 21 87 Hydro 2001 Cameroon 800 51 Year of acquisition Geographic Location Approximate Number of Customers served Approximate Gigawatt Hours AES Equity Interest (percent) 1999 1999 Kazakhstan Kazakhstan 291,000 178,513 1,455 1,117 2000 1999 1996 1997 1998 USA USA Brazil Brazil Brazil 433,010 193,000 2,800,000 4,680,000 4,657,306 16,256 6,743 19,981 32,179 34,789 2000 Venezuela 1,131,552 9,724 0 0 100 100 24 21 50 87 15 Distribution Facilities Growth Distribution South America Sul Eden Edes Edelap Europe and Africa SONEL Asia Telasi Kievoblenergo Rivnooblenergo Cesco Caribbean CLESA EDE Este CAESS DEUSEM EEO Year of acquisition Geographic Location Approximate Number of Customers served Approximate Gigawatt Hours AES Equity Interest (percent) 1997 1997 1997 1998 Brazil Argentina Argentina Argentina 935,125 278,854 141,281 279,568 7,390 1,886 834 2,102 2001 Cameroon 452,000 3,020 1998 2001 2001 1999 1998 1999 2000 2000 2000 Georgia Ukraine Ukraine India El Salvador Dominican Republic El Salvador El Salvador El Salvador 370,000 763,000 383,000 600,000 226,000 350,000 443,430 43,362 162,496 2,200 3,840 1,700 2,102 669 2,990 1,697 75 339 96 90 90 90 51 75 75 75 48 64 51 70 69 83 * On February 6, 2002, AES exchanged its interest in Light for an additional 31% equity interest in Eletropaulo. Over the past decade, regulations and laws affecting U.S. and world electricity generation and distribution businesses have moved toward more competition and less government control. The timing of this transition and the nature of the new regulatory rules vary greatly among states and countries. Regulatory Outlook Over the past decade the United States and other countries, mostly advanced industrial economies, implemented a series of regulatory policies that encourage competition in wholesale and retail electricity markets. In the United States, such policies have been implemented both at the federal and state level, reflecting the federal structure of the U.S. system. Wholesale power markets and transmission facilities are regulated by the federal government while retail electricity markets and distribution are regulated by each of the fifty states. Recently, however, primarily as a result of events in California (the electricity shortage and price rise in the summer of 2000) and the bankruptcy of Enron, previously the largest U.S. electricity trading company, in the fall of 2001, regulatory officials both in the United States and abroad have begun to reexamine the nature and pace of deregulation of electricity markets. This reexamination, however, just as the movement towards deregulation before it, has not occurred in a uniform manner but rather differs from state to state and between the federal government and the states themselves. Thus, while in 2001 the state of California abandoned the framework for deregulation that had been adopted in 1996, the Federal Energy Regulatory Commission (‘‘FERC’’) has not indicated any inclination to revisit ‘‘Order 888’’, the administrative cornerstone for the opening of the bulk power markets. Volatility in the wholesale power markets in California coupled with structural flaws inherent in the state’s deregulation law that shifted the risk of wholesale deregulation to the states’ investor owned utilities led the state government to impose emergency measures that effectively repealed Assembly Bill 1890, the act which restructured California’s electricity system in 1996. Under this legislation, a complex competitive wholesale market was established, the utilities agreed to sell a major portion of their generation assets and retail prices were fixed at a level that was believed to give utilities a fair return, assuming the market behaved as expected over the next few years. Unfortunately, due to a shortage of 16 rainfall and other factors the California market did not behave as expected, and electricity shortages statewide resulted. (See below ‘‘California Businesses’’ for more information). The new market structure did not adequately address undersupply issues which caused extremely volatile wholesale electricity prices. This, coupled with fixed retail prices, caused the utilities in California to face severe economic distress. While the confluence of environmental and market conditions that occurred in California may not be repeated in other states pursuing restructuring programs, to the extent these other states adopt, or have adopted, policies similar to California’s, particularly the use of ‘‘default’’ or regulated retail prices, the problems experienced in California could be repeated elsewhere. The events in California have generally caused state lawmakers and politicians to postpone restructuring legislation or even to propose a return to more traditional regulated markets. A recent survey by the Electric Power Supply Association shows 18 States have passed restructuring legislation, 6 States have delayed or suspended such legislation, and 26 States have no restructuring plans for 2002. The Company believes the most likely outlook over the next decade is for the United States to continue to resemble a ‘‘patchwork quilt’’ of differing regulatory policies. The federal government, through regulations promulgated by the FERC, has primary jurisdiction over wholesale electricity markets. These markets have been essentially deregulated since 1990 and the mix of market players has shifted dramatically toward unregulated, non-utility entities, referred to as independent power producers or wholesale generators. The Electric Power Supply Association reports that non-utility generators now account for over 40 percent of U.S. wholesale generation. One major result of creating competitive wholesale electricity markets has been the advent of marketing and trading companies. These entities buy and sell electricity, creating an interface between generators and retail customers. By far the largest such marketer/trader was Enron, accounting for over 80% percent by volume of the wholesale market in 2001. In December 2001, Enron filed for bankruptcy. While the Enron bankruptcy has had minimal effect on AES directly, the bankruptcy could result in a less liquid wholesale market, in which AES participates as both a generator and a retailer, going forward. Due to the size and credit rating of Enron prior to the bankruptcy, stricter trading and credit requirements are likely to be implemented, which could make future wholesale transactions more expensive for AES and its competitors. California Businesses During the first half of 2001, the wholesale electricity and natural gas markets in California continued to exhibit the high price volatility that began in May 2000. The volatility and unpredictable market dynamics were the result of a confluence of factors, including, among other things, growing demand, a supply/demand imbalance on natural gas pipelines importing gas to California, regional electrical supply shortages due to weather conditions, limited additions of new generating capacity over the previous decade, and the cost and availability of NOx emissions credits. The situation was further exacerbated by credit concerns among market participants brought on by the bankruptcies and near bankruptcies of the major investor owned utilities and the California Power Exchange. The freezing of retail prices avoided the natural reduction in overall demand that would have been the result of higher prices caused by undersupply, which left the state’s electricity system out of balance. In response to persistent high prices, the Federal Energy Regulatory Commission issued a number of orders, most notably on April 26 and June 19, adopting a price mitigation plan that included price caps, obligations on generators to offer all available capacity into the market, and tighter requirements on generators to coordinate their outage schedules with the California Independent System Operator. Many commercial and regulatory issues remain to be settled, the ultimate resolution of which may result in significant market or regulatory changes that cannot currently be determined or predicted. The outcome of any such changes will affect market conditions for all participants, including AES. Among the outstanding 17 commercial issues are the status of certain payables owed to generators and marketers for power delivered during 2000 and 2001. Although AES’s overall exposure to this risk is largely mitigated as a result of its tolling agreement related to the Southland plants, (see description below), at December 31, 2001 the Company had receivables of $13 million relating to this period from various California entities, and is actively pursuing recovery of these amounts. In addition, the State of California is seeking refunds from certain entities that supplied power within the state during 2000 and 2001, including AES. Because the pricing of the majority of power sold by the Company during that period was determined under the tolling agreement, the Company does not anticipate that its exposure to such refunds will be material. Nonetheless, it has been named in a number of proceedings and lawsuits related to refunds and cannot be certain of their outcome. In May, 2001, the U.S. Department of Justice initiated an investigation under the Sherman Act to determine whether a particular section of the Tolling Agreement relating to the addition of new capacity in southern California is anti-competitive. (See ‘‘Legal Proceedings’’ for more information). AES owns and operates approximately 4,450 megawatts of operational generating capacity in California, another 1,500 MW under construction and refurbishment, and also sells electricity to commercial and industrial end users through AES NewEnergy. Approximately 3,956 megawatts of the operating generation (Alamitos, Huntington Beach and Redondo Beach) are subject to a long-term tolling agreement. Under this agreement, AES’s subsidiaries receive predetermined capacity, operating and maintenance payments in return for operating the plant for the benefit of the third party. As a result, the revenues of these subsidiaries do not materially reflect the electricity price volatility experienced in California during 2001. The Company also owns 120 MW of combined cycle gas-fired capacity at its Placerita facility, as well as a total of 355 MW at four plants that it acquired in 2001 through its purchase of all common shares of Thermo Ecotek, including two gas-fired plants— Mountainview (126 MW) and Riverside Canal (154 MW)—and two wood-fired plants—Delano (50 MW) and Mendota (25 MW). Argentina Argentina is experiencing a significant political, social and economic crisis that has resulted in important changes in general economic policies and regulations as well as specific changes in the energy sector. During January and February 2002, many new economic measures have been adopted by the Argentine government, including abandoning the country’s fixed U.S. dollar-to-peso exchange rate, converting U.S. dollar denominated loans into pesos and placing restrictions on the convertibility of the Argentine peso. The government has also adopted new regulations in the energy sector that have the effect of repealing U.S. dollar denominated pricing under electricity tariffs as prescribed in existing electricity distribution concessions in Argentina by fixing all prices to consumers in pesos until June 30, 2002. In combination these circumstances create significant uncertainty surrounding the performance, cash flow and potential for profitability of the electricity industry in Argentina, including the Argentine subsidiaries of AES. The new regulations in the energy sector effectively overturn the U.S. dollar based nature of the electricity sector. Formerly, both the wholesale generation market and the distribution sector received payments that were linked to the U.S. dollar, not only because of the Convertibility Law that pegged the peso at a 1:1 exchange rate with the U.S. dollar but also because the price paid for wholesale generation reflected the U.S. dollar linked nature of the fuels used by the country’s generating facilities. 18 In the wholesale power market, electricity generators declared on a semi-annual basis their costs of generation which reflected the costs of their fuel. For thermal generators these fuel costs reflected the U.S. dollar costs of these commodities. Under the current regulations both the declaration of costs and the prices received as capacity and energy payments are denominated in pesos but are not permitted to reflect the devaluation of the peso against the U.S. dollar. As a result, the fuel costs for thermal generators no longer reflect the true costs of producing or delivering that fuel. At the same time generation prices now reflect the artificially low price of fuels and as a result the real price received for wholesale generation has been reduced by nearly 50% from the previous year. Under the previous regulations, distribution companies were granted long-term concessions (up to 99 years) which provided, directly or indirectly, tariffs based upon U.S. dollars and adjusted by the U.S. consumer price index and producer price index. Under the new regulations, tariffs have been delinked from the U.S. dollar and U.S. inflation indices. The tariffs of all distribution companies have been converted to pesos and frozen at the peso notional rate as of December 31, 2001. This new regime is to be in place at least until June 30, 2002. During the period until June 30, the government and the distribution companies are to negotiate a new regulatory framework applicable to the electricity distribution sector. AES has several subsidiaries in Argentina operating in both the competitive supply and growth distribution segments of the electricity business. Eden, Edes and Edelap are distribution companies that operate in the province of Buenos Aires. Generating businesses include Alicura, Parana, CTSN, Rio Juramento and several other smaller hydro facilities. These businesses are experiencing cash flow shortfalls arising from the economic and regulatory changes described earlier, and some of the businesses are in default on their project financing arrangements. AES is not generally required to support the potential cash flow or debt service obligations of these businesses. The effects of the crisis are not expected to have a significant negative impact on AES’s parent cash flows, due primarily to the non-recourse financing structure in place at most of AES’s Argentine businesses. The effects of the current circumstances on net income beginning in 2002 are much more uncertain and difficult to predict. AES’s total contributed cash investment and retained earnings in the competitive supply business in Argentina is approximately $575 million and the total similar investment in the growth distribution business is approximately $465 million. Depending on the ultimate resolution of these uncertainties, AES may be required in 2002 to record a material impairment loss or write-off associated with the recorded carrying values of its investments, including goodwill, although no such loss has been recorded to date. Additionally, under current conditions, the Argentine businesses may also incur operating losses during 2002. AES is currently investigating and pursuing several potential alternatives to minimize ongoing impacts on net income. It is possible, as AES pursues these alternatives, that future Argentine business results may be reported as discontinued operations. Brazil The Brazilian electricity industry is regulated by the National Electric Power Agency (ANEEL). Its responsibilities include, among others, (i) granting and supervising concessions for electricity generation, transmission and distribution, (ii) establishing regulations for the electricity sector, including the approval of electricity tariffs, (iii) oversight and auditing the activities of electric power concessionaires, and (iv) implementing and regulating the use of electricity, in the form of both thermal and hydroelectric power. In order to establish competition and to ensure short-term power supply to the market in Brazil upon deregulation of the power industry, the Federal Government created the Wholesale Energy Market (MAE). The MAE was originally a self-regulated body, responsible for settling and clearing 19 short-term power purchases according to the rules established by the market participants (generators and distributors) under a collective agreement, the Market Agreement, and to regulations issued by governing authorities, primarily ANEEL. The electricity industry in Brazil reached a critical point in 2001, as the result of a series of regulatory, meteorological and market driven problems. The MAE had a poor performance record due to an inability to resolve commercial disputes. In addition, the combined effects of growth in demand, decreased rainfall on the country’s heavily hydro-electric dependent generating capacity, and delays by the Brazilian energy regulatory authorities in developing an attractive regulatory structure (necessary to encourage new generation in the country) have led to shortages of electricity to meet expected demand in certain regions of Brazil. As a result, the Brazilian government, effective as of June 2001, implemented a program for the rationing of electricity consumption. Under these conditions, another issue arose, which is referred to as Annex V. It is an appendix included in all the regulated contracts established prior to the privatization of the generation companies in Brazil, which are known as the Initial Contracts. Under the Initial Contracts, ANEEL defined both prices and volumes, which were then entered into between all generators (both privatized and state- owned) and distribution companies. Annex V contains a mathematical formula that was designed to reduce the impact on generators during times when reservoir levels are low (such as those during rationing periods) and spot electricity prices are high. In these situations, Annex V decreases the generators’ contractual fixed volume obligations. However, that contractual reduction is generally not sufficient to cover the full extent of the actual reductions in energy available resulting from the water shortage conditions. As such, the generators are required to fulfill the remaining portion of their reduced contractual obligations to the distributors with a calculated and financially settled payment under the terms of Annex V. Such calculated payment effectively provides compensation to distributors for the shortfall in actual electricity delivered by generators and serves to partially offset the reductions in operating income experienced by the distributors resulting from the implications of lower electricity demand under imposed rationing conditions. In order to restore the economic equilibrium contained in all of the concession contracts, an industry-wide agreement that applies to both AES’s generation and distribution businesses in Brazil was reached. This agreement applies to the rationing-related loss of income incurred by both generation and distribution businesses as a result of the imposition of rationing in June 2001 and replaces the former Annex V contractual provisions, as follows: • Initial Contracts will be amended to eliminate Annex V provisions • Distribution companies will be entitled to recover rationing-related loss recovery through a tariff increase which has been in effect since December 26, 2001 and will remain in effect until such losses are recovered (expected to be three to four years) • Non-contracted (thermal) power plants, dispatched in order to fulfill the contractual requirements of the hydroelectric power plants, are to be paid at the spot price by the hydroelectric power plant generators (up to a price cap); with the consumers of electricity paying the difference between the spot price and the allowed price cap • Distribution companies will use their tariff increase to pay approximately 97% of the amounts originally payable under the Initial Contracts in order to provide the generation companies with recovery of their contractually allowed revenue amount • A loan funded by the National Development Bank of Brasil (BNDES), will provide liquidity prior to recovery through the allowed tariff increases. The loan will amortize in line with the recovery of costs through future tariff increases and will cover approximately 90% of the rationing-related losses for the distribution companies and the non-contracted energy payment of the generators. 20 In addition, the agreement provided a resolution to a long standing regulatory issue related to a portion of the distribution tariffs known as Parcel A. Parcel A is the portion of a tariff calculation formula which provides for the recovery of certain costs that are not within the control of the distribution company. A tracking-account was established in order to compensate for monthly variances in these non-manageable costs, which occur between tariff adjustment dates. These cost variances will also have retroactive interest rate compensation starting from January 1, 2001. The following non-manageable costs are included in the tracking-account: power purchases from the Itaipu hydro- electric facility (including exchange rate variations between the U.S. Dollar and the Brazilian Real), fuel costs, system charges, and financial compensation for hydro resources and transmission charges. The agreement, which includes all of the provisions discussed above, is contained in Provisional Measure #14, dated December 21, 2001. The Provisional Measure has the status of law but needs to be approved by the Congress within 120 days of its publication. In addition, every three years the tariffs applicable to distribution companies are adjusted based on a formula, which contains an ‘‘X’’ factor. The X factor is intended to permit the regulator to adjust the tariffs so that consumers may share in the distribution company’s realization of increased operating efficiencies. The revision, however, is entirely within the regulators discretion. The next adjustment is scheduled for 2003. Chile In Chile, the regulation of production schedules for electricity generation facilities is based on the marginal cost of production, which is the cost of the most inefficient unit required by the system at the time. The regulation of prices charged by generation companies for both electrical capacity (the amount of electricity available at any point in time) and electrical energy (the amount of electricity produced or consumed over a period of time) is also based on the marginal cost of production. Chile has two interconnected electricity systems, the SIC and the SING. In order to meet demand for electricity at any point in time, the lowest marginal cost generating plant in an interconnected system is used before the next lowest marginal cost plant is dispatched. As a result, at any specific level of demand, the appropriate supply will be provided at the lowest possible marginal cost of production available in the system. Generation companies are free to enter into sales contracts with distribution companies and other customers for the sale of capacity and energy. However, the electricity necessary to fulfill these contracts is provided by the contracting generation company only if the generation company’s marginal cost of production is low enough for its generating capacity to be dispatched to meet demand. Otherwise, the generation company will purchase electricity from other generation companies at the marginal cost of production in the system, if the contracting generation company’s marginal cost is above that of the last generator required to meet demand at the time. According to existing law, during periods when production cannot meet system demands, regardless of whether the government has enacted a rationing decree, the price of energy exchanges between generation companies is valued at the ‘‘unserved energy cost’’ or ‘‘shortage cost’’ which is the cost to consumers for not having energy available. This law remained untested until November 1998 when generators in the SIC were unable to agree on the implementation of the shortage cost during the supply deficit and associated mandated rationing periods. The matter was referred to the Ministry of Economy, which in March 1999 required the application of the shortage cost. Based on this decision, generators with energy deficits at the time were required to pay companies with energy surpluses the shortage cost or corresponding spot price equal to the cost of unserved energy for energy purchases during that period. The prices paid to generation companies by distribution companies for capacity and energy to be resold to their retail customers are based on the marginal cost of capacity or energy. In order to ensure price stability, however, the regulatory authorities in Chile establish prices, known as 21 ‘‘node prices,’’ every six months to be paid by distribution companies for the energy and capacity requirements of regulated consumers. Node prices for energy are calculated on the basis of the projections of the expected marginal costs within the system over the next 48 months in the case of the SIC and over the next 24 months in the case of the SING. The formula takes into account, among other things, assumptions regarding available supply and demand in the future. Node prices for capacity are based on the marginal investment required to meet peak demand, based on the cost of a diesel- fired turbine. Prices for capacity and energy sold to large industrial customers and other generation companies purchasing on a contractual basis are unregulated and are generally set with reference to node prices, alternative fuel prices, exchange rates and other factors. If average prices for capacity and energy sold to non-regulated customers differ from node prices by more than 10%, node prices are adjusted upward or downward, as the case may be, so that the difference between such prices equals 10%. In contrast, the spot price paid by one generation company to another for energy is referred to as the ‘‘system marginal cost,’’ which is based on the actual marginal cost of the highest cost generator producing electricity in the system during the relevant period, as determined on an hourly basis. Since the system marginal cost for energy is set weekly (but may in certain circumstances be changed on a daily basis) based on variables that can change on an instantaneous basis, and the node price for energy is set every six months based on projections of these variables over the next 48 months, in the case of the SIC, or 24 months, in the case of the SING, the system marginal cost for energy of a system tends to be more volatile than the node price for energy of that system. In periods of low water conditions that require greater generation of energy by more costly thermoelectric plants, the system marginal cost typically exceeds the node price. In periods of high water conditions when lower cost hydroelectric facilities can meet the majority of demand, the system marginal cost is typically below the node price and may in fact decline to zero. United Kingdom The New Electricity Trading Arrangements (‘‘NETA’’) became effective on March 27, 2001. The NETA system is structured around bilateral trading between generators, suppliers, traders and customers. The system operates like a standard commodity market, but makes special provision for the electricity system to be kept in physical balance. NETA includes forward and futures markets, allowing contracts for future delivery of electricity to be entered into up to several years in advance. The balancing mechanism enables the system operator, The National Grid Company, to change levels of generation and demand in near real-time. If an imbalance between a party’s net physical and net contractual positions occurs, the system provides a mechanism for settlement which creates an incentive for generators to accurately forecast their availability. A number of power exchanges have now emerged to facilitate medium- and short-term trading of standard products. It is anticipated that more sophisticated trading tools and financial instruments will develop as the market matures. Since the introduction of NETA, there has been a marked decline in the price paid for wholesale electricity. Day ahead and one-year forward prices have declined approximately 30% and appear to result from a combination of factors, some of which are specific to the new structure of the market and others which relate to fundamental market conditions (specifically warmer weather during the Winter 2001-2002). Specifically with reference to NETA, it appears that the new trading rules have increased competitiveness in the market. As a result of the significant price declines over this past year, virtually all generation facilities which do not have long-term contracts to sell their power have come under severe financial pressure and several have been taken off-line or shut-down as prices have fallen below their variable costs. In February 2002, the Company announced that it would take its Fifoots plant off-line as it had become no longer possible to sell power above its marginal cost of generation. Subsequently in March 2002, the Fifoots plant was placed into administrative receivership. In anticipation of the implementation of NETA and the changes to the wholesale electricity trading arrangements in England and Wales, AES Drax and TXU Europe Energy Trading Limited 22 (TXU), the successor entity to Eastern Power and Energy Trading Limited, agreed to amend the 15-year hedging contract to preserve the original commercial intent of the parties. The principal modification involved the conversion of the arrangement from financial to physical settlement. The amendment of the TXU contract required the consent of a majority of the lenders under the AES Drax bank facility and senior bonds. AES Drax obtained required approval on May 23, 2001. Due to lower long-term projections of electricity prices in the U.K market, and resulting lower debt service coverage ratios on AES Drax’s Senior Secured Bonds and Senior Secured Bank Debt, as well as a recent increase in the property damage and business interruption insurance deductible, AES Drax’s Senior Secured Bonds and Senior Secured Bank Facility were downgraded by Fitch and Moody’s from BBBw/Baa3 to BB+/Ba1 on November 30, 2001 and December 7, 2001, respectively. AES Drax’s Senior Notes (subordinated debt) were also downgraded from BB/Ba2 to B+/B1 by Fitch and Moody’s, respectively. Subsequent to year end, AES Drax had an event of default under its Senior Secured Bonds and Senior Secured Bank Debt as a result of its inability to obtain specified minimum amounts of insurance coverage. This is more fully discussed in the ‘‘Discussion and Analysis of Financial Condition and Results of Operations’’ section. AES Drax has maintained its ratings with Standard & Poors although they have placed both the senior debt and subordinated debt on negative watch. The direct effect of the downgrades has been increased borrowing costs and increased the credit support required for certain of the bilateral contracts entered into by AES Drax since the introduction of NETA. AES Drax has taken steps designed to address the concerns expressed by the rating agencies, but there can be no assurance that these steps will be sufficient. In the event Standard & Poors were to downgrade the rating on AES Drax’s senior secured debt, which is AES Drax’s sole remaining investment grade rating, it is likely AES Drax would experience significantly increased demands for credit support and even greater borrowing costs. Venezuela In September 1999 the Electric Service Law (LSE), which provides a framework for the deregulation of the electric utility industry in Venezuela, was enacted. On December 14, 2000 the Ministry of Energy and Mines enacted the Electric Law Regulations pursuant to the LSE. The LSE, as amended in December 2001, requires the restructuring of integrated electric companies by January 2003. The restructuring involves legally dividing generation, transmission, distribution and commercialization businesses into new independent legal entities that are financially, operationally and administratively autonomous. Under the LSE, generation and commercialization will be deregulated and will be opened up to competition whereas distribution and transmission will remain regulated businesses. The Ministry of Energy and Mines in consultation with the electric utility companies in Venezuela is currently developing a framework for the implementation of the LSE requirements. In addition, in January 1999 a joint resolution of the Ministry of Energy and Mines and the Ministry of Industry and Commerce (the ‘‘Joint Resolution’’) established the basic tariff rates applicable during the Four-Years Tariff Regime (1999-2002). The tariffs were established by the Ministry of Energy and Mines using a cost-plus methodology in that tariffs are calculated based on a return on investment methodology. Each company provides information about their business (assets and costs), and the tariffs are calculated by the regulator based on the expected return for a model company. Tariffs are adjusted: (i) semi-annually to reflect fluctuations in inflation and the currency exchange rate; and (ii) monthly to reflect fluctuations in fuel prices. In light of the potential for energy shortages facing Venezuela due primarily to a long dry season, the government is currently considering amending the tariff Joint Resolution for the year 2002 in order to introduce incentives to reduce the consumption of energy. Under the current plan there would be an increased tariff for energy consumption over certain thresholds. The increased tariff will apply to all commercial, industrial and residential sectors. 23 United States Environmental and Land Use Regulations The construction and operation of power projects are subject to extensive environmental and land use laws and regulations. In the United States the laws and regulations applicable to AES primarily involve the discharge of effluents into the water, emissions into the air and the use of water, but can also include wetlands preservation, endangered species, waste disposal and noise regulation. These laws and regulations often require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies. If AES violates or fails to comply with such laws, regulations, licenses, permits or approvals, AES could be fined or otherwise sanctioned by regulators. In addition, under certain environmental laws, AES could be responsible for costs relating to contamination at its facilities or at third party waste disposal sites. AES has accrued liabilities for projected environmental remediation costs. See Note 8 of the consolidated financial statements for more detail. AES is committed to operating its businesses cleanly, safely and reliably and strives to comply with all environmental laws, regulations, permits and licenses. Despite such efforts, the Company has at times been in non-compliance with such laws, regulations, licenses, permits and approvals, although no such instance has resulted in revocation of any material permit or license. AES has incurred and will continue to incur significant capital and other expenditures to comply with environmental laws and regulations, in particular, with respect to the NOx SIP call, the Section 126 petitions and other air emissions regulations described below. Although AES is not aware of any costs of complying with environmental laws and regulations which would reasonably be expected to result in a material adverse effect on its business, consolidated financial position or results of operations except as described below, there can be no assurance that AES will not be required to incur material compliance costs in the future. Environmental laws and regulations affecting power generation and distribution are complex, change frequently and have tended to become more stringent over time. If such laws and regulations are changed and any of AES’s facilities are not ‘‘grandfathered’’ (that is, made exempt by the fact that the facility pre-existed the law) or are not otherwise excluded, extensive modifications to a facility’s technologies and operations could be required. Should environmental laws or regulations change in the future, there can be no assurance that AES would be able to recover all or any increased costs from its customers or that its consolidated financial position or results of operations would not be materially and adversely affected. In addition, the Company will likely be required to make significant capital or other expenditures in connection with such changes in environmental laws or regulations, although AES’s businesses generally take into account capital expenditures for future environmental compliance. The Company is not aware of any currently planned changes in law, however, that would reasonably be expected to have a material adverse effect on its business, consolidated financial position or results of operations, except as described below. Clean Air Act. The Clean Air Act of 1970 (the ‘‘Clean Air Act’’), as amended in 1990 (the ‘‘1990 Amendments’’), sets guidelines for emissions standards for major pollutants (in particular, sulfur dioxides (‘‘SO2’’) and nitrogen oxides (‘‘NOx’’)) from newly built sources. Among other things, the 1990 Amendments attempt to reduce acid rain precursor emissions (SO2 and NOx) from existing sources, particularly large, older power plants that were exempted from certain regulations under the Clean Air Act. Other provisions of the Clean Air Act relate to the reduction of ozone precursor emissions (volatile organic compounds (‘‘VOC’’) and NOx) and have resulted in the imposition by various U.S. states of ‘‘reasonably available control technology’’ requirements to reduce such emissions. National Ambient Air Quality Standards. In 1997, the U.S. Environmental Protection Agency (‘‘EPA’’) published new standards that tighten national ambient air quality standards (‘‘NAAQS’’) for ozone and fine particulate matter. In May 1999, the EPA issued its final guidelines for the revised ground level ozone and particulate matter, which further delineate the so-called ‘‘non attainment regions’’ and other non-attainment classifications. In October 1999, a federal appeals court overturned the new standards. In February 2001, the U.S. Supreme Court upheld the new standards, but held that 24 the EPA’s policy of implementing these standards in non-attainment regions was unlawful and remanded the case to a federal appeals court for review. In December 2001, the federal appeals court heard oral arguments regarding EPA’s implementation of these standards in non-attainment regions. The federal appeals court’s ruling is expected in the Spring of 2002. If the EPA develops a reasonable interpretation of these standards as they may be applied in non-attainment regions, consistent with the court decisions, AES’s plants will likely be faced with further emission reduction requirements that could necessitate both the installation of additional control technology and a related increase in capital expenditures. NOx SIP Call. In October 1998, the EPA issued a final rule addressing the regional transport of ground-level ozone across state boundaries to the eastern United States. The rule (‘‘NOx SIP Call’’) as amended in June and August of 2000, requires twenty-two states and the District of Columbia, including Illinois, Indiana, New York and Pennsylvania, states in which AES’s plants are located, to reduce NOx emissions (a precursor to ozone formation) that cross state boundaries, including emissions from electric generating units. The District of Columbia and these states were required to submit revised state implementation plans (‘‘SIPs’’) by October 2000, with a compliance date for affected emissions sources, including electric generating plants, of May 31, 2004. In March 2000, a federal appeals court upheld the NOx SIP Call, but remanded minor aspects of the rule to the EPA for further rulemaking action. In February 2002, the EPA issued its proposed rule. The EPA final rule is expected by April 2003. As a result of the NOx SIP Call, AES will likely be required to make further reductions in NOx emissions at some of its facilities and incur estimated capital expenditures of approximately $380-540 million in connection therewith. Section 126 Petitions. In a related action, the EPA in December 1999 granted petitions filed by four northeastern states seeking to reduce ozone damage from certain sources in midwestern upwind states. In granting the petitions, submitted under Section 126 of the Clean Air Act, the EPA made a finding that certain large electric generating units significantly contribute to non-attainment of the NAAQS for ozone in the northeastern downwind states. Although the original deadline for compliance under the Section 126 Rule is May 1, 2003, in a memorandum dated January 18, 2002, the EPA stated its intention to establish a May 31, 2004 compliance date for all affected sources, subject to the completion of its response to a related court decision. The EPA’s intention, if implemented, would align the compliance dates for the Section 126 Rule and the NOx SIP Call described above. As a result of the Section 126 Rule, certain AES plants may be required to make further reductions in NOx emissions, in addition to those needed to comply with the ozone NAAQs and the NOx SIP Call described above. New Source Review. In the 1990s, the EPA commenced an industry-wide investigation of coal-fired electric generators to determine compliance with environmental requirements under the Clean Air Act associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. The EPA’s focus is on whether the changes were subject to new source review (‘‘NSR’’) permitting requirements. In May 2001, the Bush Administration directed the EPA to review the NSR permitting requirements and the U.S. Department of Justice to review its existing NSR enforcement actions, with the goal of ensuring the NSR requirements and enforcement thereof are consistent with the Clean Air Act and its regulations. In January 2002, the U.S. Department of Justice concluded that EPA’s pending enforcement actions are a reasonable interpretation of the Clean Air Act. The EPA’s report, which was originally due in August 2001, has not been issued to date. See Item 3—Legal Proceedings for a description of certain related litigation affecting AES. Regional Haze. The EPA published the final regional haze rule on July 1, 1999. This rule established planning and emission reduction timelines for states to use to improve visibility in national parks throughout the U.S. On June 22, 2001, the EPA signed a proposed rule to guide states in implementing the 1999 rule and in controlling power plant emissions that cause regional haze problems. 25 The proposed rule set guidelines for states in determining best available retrofit technology, or BART, at older power plants. Under the rule, states are required to submit to the EPA their regional haze SIPs by sometime during 2004 through 2008, depending on whether and when the EPA determines that state is in ‘‘attainment’’ or ‘‘non-attainment.’’ The ultimate effect of the new regional haze rule could be requirements for (i) newer and cleaner technologies and additional controls on conventional particulates, and (ii) reductions in SO2, NOx and particulate matter emissions from utility sources. If the proposed rules are finalized and implemented, and utility emissions reductions are required, compliance costs to AES could be significant. Hazardous Air Pollutants. The 1990 Amendments also regulate certain hazardous air pollutants (‘‘HAPs’’). Although the HAP provisions of the 1990 Amendments presently do not apply to electric and steam generating facilities such as AES’s U.S. plants, the 1990 Amendments directed the EPA to prepare a study on HAP emissions from power plants. In February 1998, the EPA released a final report on HAP emissions from power plants that, among other things, concluded that the risk of contracting cancer from exposure to HAPs (other than mercury) from most plants is low (less than one in one million) and that further research on mercury emissions was necessary. In December 2000, the EPA announced it would adopt rules to regulate mercury emissions from coal- and oil-fired power plants. The EPA expects to propose these regulations by December 2003 and issue final regulations by December 2004 with reductions required in 2007-2008. Once these final regulations have been issued, the use of ‘‘maximum available control technology’’ may be required to control these emissions. Global Warming. Global warming continues to be a concern. The Kyoto Protocol to the United Nations Framework Convention on Climate Change, if ratified by the requisite number of signatory countries, would require the signatory countries to make substantial reductions in ‘‘greenhouse gas’’ emissions. While it seems unlikely the Kyoto Protocol will be ratified by the requisite number of signatory countries any time soon, global warming remains a policy issue that is regularly considered for possible government regulation. Indeed, several European countries (including the U.K.) have some regulations concerning greenhouse gases. Although AES believes that U.S. government legislation requiring reductions in greenhouse gases (other than voluntary reductions) is unlikely, such legislation could substantially affect both the costs and the operating characteristics of AES’s fossil-fuel (coal, oil, gas) fired businesses. See ‘‘Recent Legislative Proposals’’ below. Recent Legislative and Regulatory Proposals. New legislation has been introduced in Congress which, if passed into law, would require reduction in power plant air emissions beyond the requirements described above. In particular, the ‘‘Clean Power Act’’ sponsored by Senator Jeffords of the State of Vermont and Senator Lieberman of the State of Connecticut would require significant reductions in emissions of four major power plant pollutants—CO2, NOx, SO2 and mercury. In addition, in February 2002, President Bush announced a climate change and multi-emissions control strategy which is likely to result in legislation similar to the Clean Power Act, but would require reductions in only three pollutants (NOx, SO2 and mercury), with voluntary reductions of CO2. Finally, in February 2002, the New York Department of Environmental Conservation (‘‘DEC’’) issued proposed regulations requiring electric generators to reduce SO2 emissions by 50% below current Clean Air Act standards. The SO2 regulation would be phased in beginning on January 1, 2005 with implementation completed by January 1, 2008. DEC’s proposed regulations would also require electric generators to meet stringent NOx reduction requirements year-round, rather than just during summertime ozone season: May through the end of September of each year. These new NOx regulations, if adopted, would take effect on October 1, 2004. If any of these and/or other similar rules or legislation are passed into law, AES’s generation facilities would likely be required to incur additional significant costs to install additional environmental pollution control technology. On February 28, 2002, the EPA, pursuant to Section 316 of the United States Federal Water Pollution Control Act,, approved a proposed regulation establishing location, design, construction and 26 capacity standards for cooling water intake structures at existing power plants, including many of AES’s U.S. facilities. The proposed regulation, which is designed to protect aquatic life affected by these intake structures, would require subject facilities to demonstrate their cooling water intake systems meet best technology available (‘‘BTA’’). While the proposed regulation is subject to public comment and potential revision prior to being finalized, the EPA is required to publish a final rule by August 28, 2003. If the proposed regulation is adopted, AES will be required, for each subject facility, (i) to demonstrate the facility already meets the proposed performance requirements; (ii) to select, design and construct new technologies, operational measures and/or restorative measures that meet the proposed requirements or (iii) to request a facility-specific determination of BTA if the costs of compliance are significantly greater than those estimated by EPA or if the costs of compliance would be significantly greater than the benefits of complying with the requirements. These requirements could result in significant capital expenditures and operating costs for each subject facility. Foreign Environmental Regulations AES has ownership interests in power plants and projects in many countries outside the United States. Each of these countries (and the localities therein) have separate laws and regulations governing the siting, construction, permitting, ownership, operation, decommissioning and remediation of, and power sales from, such power plants. These countries also have laws governing waste disposal, the discharge of pollutants into the air, water or ground and noise pollution. These laws and regulations are often different from those in effect in the United States. In addition to such foreign laws and regulations, projects funded by the World Bank are subject to World Bank environmental standards. These standards may be more stringent than local country standards but are typically not as strict as corresponding standards in the United States. AES has incurred and will continue to incur capital and other expenditures to comply with these laws and regulations, in particular, laws governing air emissions. Whenever feasible, AES attempts to use advanced environmental technologies (such as CFB coal technology or advanced gas turbines) in its non-U.S. businesses in order to minimize environmental impacts. Our operations in the European Union (the ‘‘EU’’), are also subject to other laws and regulations including EU directives and national legislation implementing those directives. In particular, the EU Directive on Integrated Pollution Prevention and Control could impose onerous permitting, air emissions reduction and other environmental requirements on AES’s EU facilities during this decade. Many of AES’s non-U.S. facilities are also subject to international conventions and protocols, including, without limitation, the Kyoto Protocol described in ‘‘United States Environmental and Land Use Regulation’’ above. On March 4, 2002, the fifteen Member Nations of the EU agreed to ratify the Kyoto Protocol. If the governments of each of those Member Nations, in particular, the United Kingdom, Germany and The Netherlands, ratify the Kyoto Protocol, costs and the operating characteristics of AES’s plants in the EU may be affected. These costs could be in addition to costs to comply with any other foreign regulations governing greenhouse gas emissions, including those already in effect in Europe. Based on current trends, AES expects that environmental and land use regulations affecting its plants located outside the United States will likely become more stringent over time. This may be due in part to a greater participation by local citizenry in the monitoring and enforcement of environmental laws, better enforcement of applicable environmental laws by the regulatory agencies, and the adoption of more sophisticated environmental requirements and more stringent environmental and land use laws and regulations. If foreign environmental and land use regulations were to change in the future, the Company may be required to make significant capital or other expenditures. There can be no assurance that AES would be able to recover from its customers all or any increased costs to comply with current or future environmental or land use regulations or that its business, financial condition or results of 27 operations would not be materially and adversely affected by such foreign environmental and land use regulations. Competition Contract generation. In the contract generation line of businesses, AES faces most of its competition during the development phase of its projects. Its competitors in this business include other independent power producers as well as various utilities and their affiliates. Traditionally, competition in this segment is limited due to the long-term nature of the generation contracts. However, due to the introduction of competitive power markets, and the addition of new market participants, there may be increased competition in attracting new customers and maintaining our current customers as their existing contracts expire. Competitive supply. AES competes in the competitive supply segment with numerous other independent power producers, energy marketers and traders, energy merchants, transmission and distribution providers and retail energy suppliers. Competitive factors include price, contract terms, including credit requirements and quality of service. Large Utilities. Historically, energy utilities operated within specific service territories where they were essentially the sole suppliers of electricity services, and therefore competition was limited to alternative means of energy such as gas and fuel. However, in certain locations, the large utilities business is facing significant challenges and increased competition as a result of changes in laws and regulations allowing wholesale and retail services to be provided on a competitive basis. There can be no assurance that the deregulation will not adversely affect the future operations, cash flows and financial condition of our large utilities. Growth distribution. In the growth distribution line of business there may be competition to acquire facilities. However, there is currently little competition in growth distribution business due to the significant barriers to entry present in these markets. AES competes against a number of other participants, some of which have greater financial resources and have been engaged in growth distribution related businesses for periods longer than AES and have accumulated more significant portfolios. Relevant competitive factors include financial resources, governmental assistance, access to non-recourse financing and regulatory factors. Customers The Company sells to a wide variety of customers. No individual customer accounted for more than 10% of the Company’s 2001 net sales. Employees As of December 31, 2001, AES and its subsidiaries employed approximately 38,000 people. Executive Officers and Significant Employees of the Registrant The following is certain information concerning the present executive officers and significant employees of the Registrant set out in alphabetical order. Dennis W. Bakke, 56 years old, co-founded the Registrant with Roger Sant in 1981 and has been a director of the Registrant since 1986. He has been President of the Registrant since 1987 and Chief Executive Officer since January 1994. From 1987 to 1993, he served as Chief Operating Officer of the Registrant; from 1982 to 1986, he served as Executive Vice President of the Registrant; and from 1985 to 1986 he also served as Treasurer of the Registrant. He served with Mr. Sant as Deputy Assistant Administrator of the Federal Energy Agency (‘‘FEA’’) from 1974 to 1976 and as Deputy Director of the 28 Energy Productivity Center, an energy research organization affiliated with The Mellon Institute at Carnegie Mellon University, from 1978 to 1981. He is a trustee of Rivendell School and a member of the Board of Directors of MacroSonix Corporation. Paul T. Hanrahan, 43 years old, was appointed one of four Chief Operating Officers in February 2002. His responsibilities include overseeing the growth distribution business segment. He was appointed Executive Vice President in February 2000, has been a Senior Vice President since 1997, and was appointed Vice President of the Registrant effective January 1994. From May 1, 2000 to February 2002, Mr. Hanrahan was Managing Director of AES Americas, a business group responsible for Bolivia, Colombia, Ecuador, Peru, Venezuela and Southern Brazil. From May 1, 1998 until becoming director of AES Americas, Mr. Hanrahan was Managing Director of AES Americas South, a business group within AES responsible for all of AES’s activities in Argentina, Paraguay, and Chile. From February 1995 until becoming Managing Director of AES Americas South he was President and Chief Executive Officer of AES Chigen, where he served as Executive Vice President, Chief Operating Officer and Secretary from December 1993 until February 1995. He was General Manager of AES Transpower, Inc., a subsidiary of the Registrant, from 1990 to 1993. William R. Luraschi, 38 years old, was appointed Senior Vice President in February 2002 and has been Vice President of the Registrant since January 1998, Secretary since February 1996 and General Counsel of the Registrant since January 1994. Prior to that, Mr. Luraschi was an attorney with the law firm of Chadbourne & Parke L.L.P. Dr. Roger F. Naill, 55 years old, was appointed Senior Vice President in February 2001 and has been Vice President for Planning at AES since 1981. Dr. Naill is responsible for AES’s financial forecasts and other corporate issues. Prior to joining the Registrant, Dr. Naill was Director of the Office of Analytical Services at the Department of Energy. Dr. Naill received a Ph.D in Engineering form Dartmouth College and a MSM Degree from the A.P. Sloan School of Business (MIT). John Ruggirello, 51 years old, was appointed one of four Chief Operating Officers in February 2002. His responsibilities include overseeing the contract generation business segment. He was appointed Executive Vice President of the Registrant in February 2000, was Senior Vice President until February 2000 and was appointed Vice President in January 1997. Mr. Ruggirello lead the AES Enterprise group, with responsibility for project development, construction and plant operations in the Mid-Atlantic region of the United States. He served as President of AES Beaver Valley from 1990 to 1996. J. Stuart Ryan, 43 years old, was appointed one of four Chief Operating Officers in February 2002. His responsibilities include overseeing the competitive supply business segment. He was appointed Executive Vice President of the Registrant in February 2000, was Senior Vice President until February 2000 and was President of the AES Pacific group, which is responsible for the Company’s business in Western North America. Between 1994 and 1998, Mr. Ryan lead the AES Transpower group responsible for AES’s activities in Asia (excluding China). From 1994 through 1997, he served as Vice President of the Registrant. Prior to 1994, Mr. Ryan served as general manager of a group within AES. Mr. Ryan also serves on Lehigh University’s Global Advancement Council and The Alumni Association Board of Directors. He is also on the Board of Directors of C.A. La Electricidad de Caracas. Roger W. Sant, 70 years old, co-founded the Company with Dennis Bakke in 1981. He has been Chairman of the Board and a director of the Registrant since its inception, and he held the office of Chief Executive Officer through December 31, 1993. He currently is Chairman of the Board of Directors of The Summit Foundation, is a Regent of the Smithsonian Institution, and serves on the Boards of Directors of The World Wildlife Fund US and Marriot International, Inc. He was Assistant Administrator for Energy Conservation and the Environment of the Federal Energy Agency (‘‘FEA’’) 29 from 1974 to 1976 and the Director of the Energy Productivity Center, an energy research organization affiliated with The Mellon Institute at Carnegie-Mellon University, from 1977 to 1981. Barry J. Sharp, 42 years old, was appointed one of four Chief Operating Officers in February 2002 and continues to hold the position of Chief Financial Officer. His responsibilities include overseeing the finance function as well as the large utilities business segment. He was appointed Executive Vice President in February 2001. Mr. Sharp was appointed Senior Vice President in January 1998 and had been Vice President and Chief Financial Officer since 1987. He also served as Secretary of the Registrant until February 1996. From 1986 to 1987, he served as the Company’s Director of Finance and Administration. Mr. Sharp is a certified public accountant. Kenneth R. Woodcock, 58 years old, has been Senior Vice President of the Registrant since 1987. Mr. Woodcock is responsible for coordinating AES’s relationships with the investment community, and he provides support for AES business development activities worldwide. From 1984 to 1987, he served as a Vice President for Business Development. Prior to the founding of AES he served in the United States federal government in energy and environment departments. (d) Financial Information About Foreign and Domestic Operations and Export Sales. See the information contained under the caption ‘‘Segments’’ in Note 16 to the Consolidated Financial Statements included in Item 8 herein. ITEM 2—PROPERTIES Offices are maintained by the Registrant in many places around the world, which are generally occupied pursuant to the provisions of long- and short-term leases, none of which are material to the Company. With a few exceptions, the Registrant’s facilities, which are described in Item 1 hereof, are subject to mortgages or other liens or encumbrances as part of the project’s related finance facility. The land interest held by the majority of the facilities is that of a lessee or, in the case of the facilities located in the People’s Republic of China, a land use right that is leased or owned by the related joint venture that owns the project. However, in a few instances, there exists no accompanying project financing for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned by the subsidiary or affiliate owning the facility outright. ITEM 3—LEGAL PROCEEDINGS In September 1999, an appellate judge in the Minas Gerais, Brazil state court system granted a temporary injunction that suspends the effectiveness of a shareholders’ agreement for CEMIG. This appellate ruling suspends the shareholders’ agreement while the action to determine the validity of the shareholders’ agreement is litigated in the lower court. In early November 1999, the same appellate court judge reversed this decision and reinstated the effectiveness of the shareholders’ agreement, but did not restore the super majority voting rights that benefited the Company. In March 2000, a state court in Minas Gerais again ruled that the shareholders’ agreement was invalid. In April 2000, the appellate court denied the appeal of that second state court decision. In August 2001, the appellate court denied another appeal, confirming the decision that the shareholders’ agreement was null and void. In November 2001, a special procedure was initiated whereby CEMIG requested that the case be transferred from state court to superior federal court in Brasilia. The Company intends to vigorously pursue its legal rights in this matter and to restore all of its rights regarding CEMIG. Failure to prevail in this matter would limit the Company’s influence on the daily operations of CEMIG. However, the Company would still own approximately 21.6% of the voting common stock of CEMIG. In December 2000, several class action lawsuits were filed in California against multiple wholesale power generators and marketers in California, including one class action that named AES. The complaint naming AES alleges violations of the state anti-competitive behavior act as well as antitrust 30 violations, and seeks compensatory and punitive damages. AES has been participating in a joint defense arrangement with the other named defendants. The AES lawsuit has been consolidated with five other lawsuits before a single judge in San Diego. In March 2002, the plaintiffs filed a new master complaint in the consolidated action, which asserted the claims asserted in the earlier action and names the Company, AES Redondo Beach, L.L.C., AES Alamitos, L.L.C., and AES Huntington Beach, L.L.C. as defendants. The Company believes it has meritorious defenses to this action and will defend itself vigorously against the allegations. The crisis in the California wholesale power market has directly or indirectly resulted in several administrative and legal actions involving the Company’s businesses in California. Each of the Company’s businesses in California (AES Southland, AES Placerita and AES New Energy) are subject to overlapping state investigations by the California Attorney General’s Office, the Market Oversight and Monitoring Committee of the California Independent System Operator (‘‘ISO’’), the California Public Utility Commission and a subcommittee of the California Senate. The businesses have responded to multiple requests for the production of documents and data surrounding the operation of the plants. In addition, in August 2000, the Federal Energy Regulatory Commission (‘‘FERC’’) announced an investigation into the national wholesale power markets, with particular emphasis upon the California wholesale electricity market, in order to determine whether there has been anti-competitive activity by wholesale generators and marketers of electricity. The FERC has requested documents from each of the AES Southland plants. In connection with this investigation, the FERC also commenced a formal administrative investigation into the maintenance and outage practices and schedules at the AES Alamitos and AES Huntington Beach plants in 2000 and 2001. The formal investigation also focuses on the activities of the AES plants contractual partner, Williams Energy Services Company in marketing power acquired from the plants. The AES plants have supplied documents and other information to the FERC in connection with its investigation. In May 2001, the Antitrust Division of the United States Department of Justice initiated an investigation to determine whether a provision in the AES Southland plants’ Tolling Agreement with Williams Energy has restricted the addition of new capacity in the Los Angeles area in contravention of the antitrust laws. The AES Southland businesses have provided documents and other information to the Department of Justice, and depositions of AES and Williams personnel are ongoing. In July 2001, a petition was filed against CESCO by the Grid Corporation of Orissa, India (‘‘Gridco’’), with the Orissa Electricity Regulatory Commission (‘‘OERC’’), alleging that CESCO had defaulted on its obligations as a government licensed distribution company and that CESCO management abandoned the management of CESCO and asking for interim measures of protection, including the appointment of a government regulator to manage CESCO. Gridco, a state owned entity, is the sole energy wholesaler to CESCO. In August 2001, the management of CESCO was handed over by the OERC to a government administrator that was appointed by the OERC. Gridco also has asserted that a Letter of Comfort issued by the Company in connection with the Company’s investment in CESCO obligates the Company to provide additional financial support to cover CESCO’s financial obligations. In December 2001, a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 was served on the Company by Gridco pursuant to the terms of the CESCO Shareholder’s Agreement (‘‘SHA’’), between Gridco, the Company, AES ODPL, and Jyoti Structures. The notice to arbitrate failed to detail the disputes under the SHA for which the Arbitration had been initiated. The Company believes that it has meritorious defenses to any actions asserted against it and expects that it will defend itself vigorously against the allegations. In May 2000, the New York State Department of Environmental Conservation (‘‘DEC’’) issued a Notice of Violation (‘‘NOV’’) to the New York State Electric & Gas Corporation (‘‘NYSEG’’) for violations of the Federal Clean Air Act and the New York Environmental Conservation Law at the 31 Greenidge and Westover plants related to NYSEG’s alleged failure to undergo an air permitting review prior to making repairs and improvements at those plants during the 1980s and 1990s. Pursuant to the agreement relating to the acquisition of the plants from NYSEG, AES Eastern Energy agreed with NYSEG that AES Eastern Energy will assume responsibility for the NOV, subject to a reservation of AES Eastern Energy’s right to assert any applicable exception to its contractual undertaking to assume pre-existing environmental liabilities. The financial and operational effect of this NOV is still being discussed with the DEC. On January 24, 2002, DEC informed AES Eastern Energy that it would be included as a responsible party under the NOV. The EPA also indicated the NOV could include alleged violations of similar rules at the Hickling and Jennison plants. The NOV is expected to be issued in early 2002. In addition to the NOV, the DEC alleged, after our acquisition of the Cayuga, Westover, Greenidge, Hickling and Jennison plants from NYSEG in May 1999, air permit violations at each of those plants. Specifically, DEC has alleged exceedences of the opacity emissions limitations at these plants. With respect to pre-May 1999 and post-May 1999 violations, respectively, DEC has notified NYSEG, on the one hand, and AES, on the other, of their respective liability for such alleged violations. To remediate these alleged violations, DEC has proposed that each of AES and NYSEG pay fines and penalties in excess of $100,000. Resolution of this matter could also require AES to install additional pollution control technology at these plants. The fines proposed against NYSEG could be significant. NYSEG has asserted a claim against AES for indemnification against all penalties and other related costs arising out of DEC’s allegations. AES believes it has meritorious defenses to NYSEG’s claims, and intends to vigorously defend itself against them. The NOV and DEC’s allegations of opacity exceedences and any additional enforcement actions that might be brought by the New York State Attorney General, the DEC or the EPA, against any of AES’s New York plants, may ultimately result in the imposition of penalties and may require further emission reductions at those plants. The EPA has commenced an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Federal Clean Air Act associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. The EPA’s focus is on whether the changes were subject to new source review or new performance standards, and whether best available control technology was or should have been used. On August 4, 1999, the EPA issued a NOV to the Company’s Beaver Valley plant, generally alleging that the facility failed to obtain the necessary permits in connection with certain changes made to the facility in the mid-to-late 1980s. AES Beaver Valley and the EPA continue to discuss potential remedies and settlement of the EPA’s allegations. A settlement, if reached, could include the addition of pollution control technology and the payment of potential fines and penalties. The Company believes it has meritorious defenses against EPA’s allegations and intends to vigorously defend itself against them. The Company is involved in certain other legal proceedings in the normal course of business. It is the opinion of the Company that none of the pending litigation will have a material adverse effect on its financial position or cash flows. ITEM 4—SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the fourth quarter of 2001. 32 ITEM 5—MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER PART II MATTERS (a) Market Information. The common stock of the Company is currently traded on the New York Stock Exchange (NYSE) under the symbol ‘‘AES’’. The following tables set forth the high and low sale prices for the common stock as reported by the NYSE for the periods indicated. Price Range of Common Stock 2001 High Low 2000 High Low First Quarter . . . . . . . Second Quarter . . . . . Third Quarter . . . . . . Fourth Quarter . . . . . $60.15 52.25 44.50 17.80 $41.30 39.95 12.00 11.60 (b) Holders. First Quarter . . . . . . . Second Quarter . . . . . Third Quarter . . . . . . Fourth Quarter . . . . . $44.72 49.63 70.25 72.81 $34.25 35.56 45.13 45.00 As of March 2, 2002, there were 9,967 record holders of the Company’s Common Stock, par value $0.01 per share. (c) Dividends. Under the terms of the Company’s corporate revolving loan and letters of credit facility of $850 million entered into with a commercial bank syndicate and other bank agreements, the Company is currently limited in the amount of cash dividends it is allowed to pay. In addition, the Company is precluded from paying cash dividends on its Common Stock under the terms of a guaranty to the utility customer in connection with the AES Thames project in the event certain net worth and liquidity tests of the Company are not met. The Company has met these tests at all times since making the guaranty. The ability of the Company’s project subsidiaries to declare and pay cash dividends to the Company is subject to certain limitations in the project loans, governmental provisions and other agreements entered into by such project subsidiaries. Such limitations permit the payment of cash dividends out of current cash flow for quarterly, semiannual or annual periods only at the end of such periods and only after payment of principal and interest on project loans due at the end of such periods, and in certain cases after providing for debt service reserves. 33 ITEM 6—SELECTED FINANCIAL DATA Year Ended December 31, 2001 2000 1999 1998 1997 (in millions, except per share data) Statement of Operations Data: Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,327 $ 7,534 $ 4,117 $ 3,257 $ 2,227 284 Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . — Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3) Extraordinary items, net of applicable income taxes . . . . . . . . . . . . . 18 Cumulative effect of change in accounting principle . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 299 Basic earnings per share: From continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.88 $ Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extraordinary items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cumulative effect of change in accounting principle . . . . . . . . . . . . . 1.72 $ (0.04) — (0.02) — — 0.89 $ (0.01) (0.04) — 1.10 $ — 0.01 — 467 (194) — — 273 0.75 — (0.01) 0.05 827 (21) (11) — 795 377 (3) (17) — 357 437 — 4 — 441 (0.36) Basic earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.52 $ 1.66 $ 0.84 $ 1.11 $ 0.79 Diluted earnings per share: From continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.87 $ Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extraordinary items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cumulative effect of change in accounting principle . . . . . . . . . . . . . 1.65 $ (0.04) — (0.02) — — (0.36) 0.87 $ (0.01) (0.04) — 1.06 $ — 0.01 — 0.75 — (0.01) 0.05 Diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.51 $ 1.59 $ 0.82 $ 1.07 $ 0.79 December 31, 2001 2000 1999 1998 1997 (in millions) Balance Sheet Data: Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $36,736 $33,038 $23,222 $12,900 $11,065 4,522 Non-recourse debt (long-term) . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,096 Recourse debt (long-term) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mandatorily redeemable preferred stock of subsidiary . . . . . . . . . . . . — Company obligated convertible mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of AES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,696 3,458 22 14,673 4,913 22 4,505 1,644 — 9,521 2,167 22 1,228 5,542 1,318 3,315 550 2,006 978 5,539 550 2,368 ITEM 7—DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Recent Strategic Initiatives AES has recently announced a number of strategic initiatives designed to decrease its dependence on access to the capital markets, strengthen its balance sheet, reduce the financial leverage at the parent Company, enhance its profitability, reduce its earnings volatility and improve short-term liquidity. Strategic Repositioning After evaluating changes in the electricity industry, the capital markets generally and circumstances applicable to certain of the Company’s businesses, the Company has decided that additional financial strength and flexibility at the parent level will enhance the Company’s competitive advantage in the 34 future. To accomplish this goal, the Company will seek to reduce leverage, particularly at the parent level, through some combination of dividends from operating subsidiaries, equity issuances and the strategic sale of certain businesses. These initiatives, particularly asset dispositions, will be conducted after extensive evaluation and are likely to take several years to complete. In addition, in an effort to reduce earnings and cash flow volatility, the Company may seek to reduce its concentration of businesses in certain geographic markets like Latin America as well as its exposure to fluctuations in wholesale electricity prices, particularly in its merchant generation businesses. Decreasing Dependence on Capital Markets In response to recent declines in the trading prices for AES’s equity and debt securities which have created significant uncertainty regarding AES’s ability to access the capital markets on acceptable terms, AES has undertaken a number of steps designed to minimize the need for the parent company to access the capital markets during 2002 by increasing its near term liquidity. These steps include: • Reducing planned capital expenditures for 2002, primarily for new facilities under construction, to approximately $710 million from $1.2 billion • Significantly reducing planned business development spending • Proceeding with selective near term assets sales, including the sale of all of CILCORP, a wholly owned subsidiary, and the sale of Itabo, an equity method investment, and certain project financings and refinancings. AES is continuing to evaluate the impacts of further reducing planned capital expenditures. In addition, in some instances the Company may sell development projects. There can be no guarantee that the proceeds from such transactions would cover the entire investment in such projects. Also, the Company may incur additional expenses related to the reduction of planned capital expenditures. Cost Cutting Office In early 2002, the Company created the Cost Cutting Office (which assumed many of the responsibilities of the cost cutting task force which was created in late 2001). The Cost Cutting Office’s mission is to: • Better capture the benefits of scale in the procurement of services and supplies • Take advantage of cross business opportunities • Systematically audit progress Although there can be no assurance that such efforts will be successful, AES’s goal is to achieve aggregate cost savings of approximately $50 million in 2002. Turnaround Office In early 2002, AES established a Turnaround Office (which assumed many of the responsibilities of the task force on under-performing businesses which was created in late 2001). The Turnaround Office’s mission is to: • Identify underperforming businesses and • Fix, sell or abandon these underperforming businesses. The Turnaround Office identified six businesses that were underperforming: Drax, Sul, Uruguaiana, Chivor, TermoAndes and Telasi. All of these businesses are either merchant generating plants or are located in Latin America, except for Telasi which is in growth distribution in Asia. AES is in the 35 process of identifying whether the profitability of such businesses can be sufficiently improved to remain part of AES’s portfolio, or whether such businesses should be sold or abandoned. New Reporting Segments In late 2001, the Company completed a strategic review of its operations that resulted in a reorganization of the Company into four business units. • Contract generation • Competitive supply • Large utilities • Growth distribution The table set forth below shows the percentage of revenues, gross margin and total assets represented by each of these units for the year ended December 31, 2001. % of Revenues % of Gross Margin % of Total Assets Contract generation . . . . . . . . . . . . . . . . . . . . . . . . . Competitive supply . . . . . . . . . . . . . . . . . . . . . . . . . . Large utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth distribution . . . . . . . . . . . . . . . . . . . . . . . . . . 27% 29% 26% 18% 36% 19% 32% 13% 35% 28% 25% 12% Statement of Financial Accounting Standards (‘‘SFAS’’) No. 131 requires companies to disclose certain information about their operating segments where operating segments are defined as ‘‘components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance’’. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments. The Company has determined that its four business units constitute reportable ‘‘segments’’ for purposes of SFAS No. 131 and accordingly, has presented the required financial information in Note 16 to the consolidated financial statements. Additional Developments Charges related to dispositions Most of the strategic initiatives described above involve potential sales or other dispositions of businesses by AES. Some of these sales or dispositions may result in AES recognizing losses related to severance and employee benefits, asset write-downs and impairments and otherwise. The Company is currently assessing the impact such dispositions will have on the pooling-of-interests accounting used for the IPALCO acquisition. Such dispositions may require the acquisition to be restated as a purchase. Argentina Argentina is experiencing a political, social and economic crisis that has resulted in significant changes in general economic policies and regulations as well as specific changes in the energy sector. In January and February 2002, many new economic measures have been adopted by the Argentine government, including abandoning the country’s fixed dollar-to-peso exchange rate, converting dollar denominated loans into pesos and placing restrictions on the convertibility of the Argentine peso. The government has also adopted new regulations in the energy sector that have the effect of repealing U.S. dollar denominated pricing under electricity tariffs as prescribed in existing electricity distribution concessions in Argentina by fixing all prices to consumers in pesos until June 30, 2002. In combination, these circumstances create significant uncertainty surrounding the performance, cash flow and potential 36 for profitability of the electricity industry in Argentina, including the Argentine subsidiaries of AES. AES has several subsidiaries in Argentina operating in both the competitive supply and growth distribution segments of the electricity business. Eden, Edes and Edelap are distribution companies that operate in the province of Buenos Aires. Generating businesses include Alicura, Parana, CTSN, Rio Juramento and several other smaller hydro facilities. These businesses are experiencing cash flow shortfalls arising from the economic and regulatory changes described earlier, and some of the businesses are in default on their project financing arrangements. AES is not generally required to support the potential cash flow or debt service obligations of these businesses. The effects of the crisis are not expected to have a significant negative impact on AES’s parent cash flow, due primarily to the non-recourse financing structure in place at most of AES’s Argentine businesses. The effects of the current circumstances on future earnings are much more uncertain and difficult to predict. At December 31, 2001, AES’s total contributed cash investment and retained earnings in the competitive supply business in Argentina is approximately $575 million and the total investment in the growth distribution business is approximately $465 million. Depending on the ultimate resolution of these uncertainties, AES may be required in 2002 to record a material impairment loss or write-off associated with the recorded carrying values of its investments, including goodwill, although no such loss has been recorded to date. Additionally, under current conditions, the Argentine businesses may also incur operating losses during 2002. AES is currently investigating and pursuing several potential alternatives to minimize the impacts on future earnings. It is possible, as AES pursues these alternatives, that future Argentine business results may be reported as discontinued operations. Brazil During 2001, the Brazilian Real experienced a significant devaluation relative to the U.S. Dollar, declining from 1.96 Reais to the Dollar at December 31, 2000 to 2.41 Reais at December 31, 2001. Also, during 1999, the Brazilian Real experienced a significant devaluation relative to the U.S. Dollar declining from 1.21 Reais to the U.S. Dollar at December 31, 1998 to 1.81 Reais to the U.S. Dollar at December 31, 1999. This continued devaluation resulted in significant foreign currency translation and transaction losses particularly during 2001 and 1999. The Company recorded $210 million, $64 million and $203 million before income taxes of non-cash foreign currency transaction losses on the U.S. dollar denominated debt at its investments in Brazilian equity-method affiliates during 2001, 2000 and 1999, respectively. These amounts are recorded in equity in pre-tax earnings of affiliates in the accompanying consolidated income statements. Further devaluation of the Brazilian Real will continue to have a negative impact on the Company’s results of operations. In December 2001, the Company’s Brazilian subsidiaries and equity affiliates reached an agreement (the ‘‘agreement’’) with the Brazilian government that provided resolution to all rationing related issues as well as to certain other issues. There were three parts to the agreement. First, Annex V, a provision in the initial contracts between the generators and the distributors that was designed to protect the distribution companies from reduced sales volumes and to limit the financial burden of generation companies during periods of rationing, was replaced with a tariff increase that would compensate both generators and distributors for rationing related losses. The net ownership-adjusted impact to AES from the elimination of Annex V and the resulting tariff increase represented additional income before taxes of $60 million. However, the amount recorded under the new methodology at December 31, 2001 was substantially the same as the contractual receivable previously recorded under Annex V. Accordingly, the only impact was the balance sheet reclassification of the receivable to a regulatory asset. The tariff increase will remain in effect until all recoverable amounts are collected which the Company estimates to be approximately three years. The agreement also establishes that BNDES, the National Development Bank of Brazil, will fund 90% of the amounts recoverable under the tariff increase up front through loans prior to their recovery through tariffs. The loans are repayable over the tariff increase collection period. 37 The second part of the agreement relates to the Parcel A costs which are certain costs that each distribution company is permitted to defer and pass through to its customers via a future tariff adjustment. Parcel A costs are limited by the concession contracts to the cost of purchased power and certain other costs and taxes. The Brazilian regulator had granted tariff increases to recover a portion of previously deferred Parcel A costs. However, due to uncertainty surrounding the Brazilian economy, the regulator had delayed approval of some Parcel A tariff increases. As part of the agreement, a tracking account that was previously established was officially defined. Parcel A costs incurred previous to January 1, 2001 were not allowed under the definition of the tracking account. As a result, the Company wrote-off approximately $160 million ($101 million representing the Company’s portion from equity affiliates), of Parcel A costs incurred prior to 2001 that will not be recovered. The third part of the agreement relates to the sales price that Sul, the Company’s distribution subsidiary in Porto Alegre, would receive for its sales of excess energy. As a result of the agreement, Sul recorded approximately $100 million of additional revenue and a corresponding receivable from the spot market in the fourth quarter. Sul had elected early in 2001, as permitted under its concession contract, to expose itself to gains or losses based on the difference between the market price of energy in the South where they normally sell electricity and the Southeast where they take delivery. Drought conditions in the Southeast, even with rationing, created a large imbalance between prices in the Southeast and the South resulting in the substantial gain. Sul had not recorded the revenue prior to the fourth quarter because rationing had made the spot market illiquid and the negotiations on-going with the government, distributors and generators created an environment where collection of the receivable was not assured. The BNDES pre-funding of the tariff increase through loans to the distributors and generators added the needed liquidity to the spot market to assure collection. Eletropaulo. AES has owned an interest in Eletropaulo Metropolitana Electricidade de Sao Paulo S.A. (‘‘Eletropaulo’’) since May 1999 and has gradually increased its ownership interest in Eletropaulo through a series of transactions since then. Historically, AES has accounted for this investment using the equity-method of accounting. On February 6, 2002, AES acquired a controlling interest in Eletropaulo and consequently will begin consolidating the subsidiary in 2002. As of December 31, 2001, Eletropaulo had $1.6 billion of outstanding indebtedness, approximately $868 million of which is scheduled to mature during 2002 and the remaining maturing thereafter. AES’s total investment including retained earnings associated with Eletropaulo as of December 31, 2001, was approximately $1.3 billion. In addition, AES financed certain of its purchases in Eletropaulo through deferred purchase price financing arrangements provided by BNDES to subsidiaries of the Company, which aggregates approximately $1.2 billion. The payment schedule varies from April 2002 through January 2004. BNDES maintains as collateral shares that represent substantially all of the Company’s ownership interest in Eletropaulo. As a result of the volatility of the Brazilian Real and the difficult economic conditions in Brazil, the Company is evaluating whether to contribute equity sufficient to allow such subsidiaries to make the payments. If AES does not contribute sufficient equity or other consideration, or if there is not a successful renegotiation of the debt with BNDES, there can be no assurance that such subsidiaries will be able to pay such amounts, or refinance or extend the maturities of any or all of the payment amounts. In such event, BNDES may choose to seize the shares held as collateral, and this may result in a loss and resulting write-off of a portion or all of the Company’s investment. Venezuela Due to the slowing economy, falling oil revenues, capital flight and a decline in foreign reserves, the Venezuelan government began floating its currency on February 12, 2002. For the past five years, the Venezuelan currency had been traded within a fixed band, which only allowed it to trade at 7.5% above or below a central point, a daily rate set by the Banco Central de Venezuela. As a result of the change the U.S. Dollar to Venezuelan exchange rate had floated as high as 1,110.60 before declining to 895.01 at March 21, 2002 as compared to 757.50 at December 31, 2001. Our tariffs at EDC in 38 Venezuela are adjusted semi-annually to reflect fluctuations in inflation and the currency exchange rate. However, a failure to receive such adjustment to reflect changes in the exchange rate and inflation could adversely affect the Company’s results of operations. Accounting for Derivatives On January 1, 2001, the Company adopted SFAS No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ which, as amended, established new accounting and reporting standards for derivative instruments and hedging activities. SFAS No. 133 requires that all derivatives (including derivatives embedded in other contracts) be recorded as either assets or liabilities at fair value on the balance sheet. Changes in the derivative’s fair value are to be recognized in earnings in the period of change, unless hedge accounting criteria are met. Hedge accounting allows the derivative’s gains or losses in fair value to offset the related results of the hedged item. The Company utilizes derivative financial instruments to manage interest rate risk, foreign exchange risk and commodity price risk. Although the majority of the Company’s derivative instruments qualify for hedge accounting, the adoption of SFAS No. 133 will result in more variation, positive or negative, to the Company’s results of operations from changes in interest rates, foreign exchange rates and commodity prices. For the year ended December 31, 2001, the Company recognized $36 million of losses pursuant to SFAS No. 133 related to derivatives which did not qualify for hedge accounting. See Note 7 to the consolidated financial statements which provides a more complete discussion of the accounting for derivatives under SFAS No. 133. Development costs Certain subsidiaries and affiliates of the Company (domestic and non-U.S.) are in various stages of developing and constructing greenfield power plants, some but not all of which have signed long-term contracts or made similar arrangements for the sale of electricity. Successful completion depends upon overcoming substantial risks, including, but not limited to, risks relating to failures of siting, financing, construction, permitting, governmental approvals or the potential for termination of the power sales contract as a result of a failure to meet certain milestones. As of December 31, 2001, capitalized costs for projects under development and in early stage construction were approximately $68 million. The Company believes that these costs are recoverable; however, no assurance can be given that individual projects will be completed and reach commercial operation. Enron Enron Corporation and several of its affiliates filed Chapter 11 bankruptcy petitions on December 2, 2001, in the U.S. Bankruptcy Court for the Southern District of New York. At that time, several of the Company’s subsidiaries had outstanding long-term contracts for gas and electricity purchases and sales with Enron and its subsidiaries. Other Enron subsidiaries were also under contract to provide engineering, procurement and construction (‘‘EPC’’) services on three of the Company’s greenfield development projects, including AES Wolf Hollow in Texas, AES Lake Worth Generation in Florida, and the AES Ebute Barge project in Nigeria. To avoid delay, each respective AES subsidiary has put into place transition arrangements that allow the subcontractors to continue working on the project, while alternative arrangements for completing the projects are investigated. With respect to AES Wolf Hollow, AES has contracted with Stone & Webster, Inc. for EPC services. Such alternative arrangements could include, but are not limited to, procuring a partner for the current EPC contractor, replacing the current EPC contractor entirely or assigning the contract to the largest subcontractor. Although disruption or delay in the progress of construction has not occurred to date, there can be no assurance that such disruption or delay will not occur in the future. The Company does not believe any such disruption or delay will have a material adverse effect on the results of operations or financial position of the Company. 39 Energy Trading Activities The Company does not engage in significant energy trading activities associated with its retail and wholesale supply businesses. For the years ended December 31, 1999, 2000 and 2001, the Company recorded net gains from energy trading activities of $3 million, $21 million and $5 million, respectively. Off Balance Sheet Arrangements In May 1999, a subsidiary of the Company acquired six electric generating stations from New York State Electric and Gas. Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. This transaction has been accounted for as a sale/leaseback transaction with operating lease treatment. See Note 8 to the consolidated financial statements for a more complete discussion of this transaction. The Company has investments in several equity method affiliates, and does not consolidate the financial information of equity method affiliates. Therefore, none of the assets or liabilities of our equity method affiliates are included on our consolidated balance sheets. See Note 4 to the consolidated financial statements for summarized financial information from our equity method affiliates. Related Party Transactions The Company did not enter into any material related party transactions during the years ended December 31, 1999, 2000 and 2001. Significant Accounting Policies General AES prepares its consolidated financial statements in accordance with accounting principles generally accepted in the U.S. As such, it is required to make certain estimates, judgments and assumptions that it believes are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. The significant accounting policies which AES believes are most critical to understanding and evaluating its reported financial results include the following: Property, Plant and Equipment; Long-Lived Assets; Functional Currency Determination; Regulatory Assets and Contingencies. Property, Plant and Equipment Property, plant and equipment is recorded at cost and is depreciated over its estimated useful life. The estimated useful lives of AES’s generation and distribution facilities range from 10 to 50 years. A significant decrease in the estimated useful life of a material amount of property, plant or equipment could have a material adverse impact on our operating results in the period in which the estimate is revised and subsequent periods. Long-Lived Assets AES evaluates the impairment of its long-lived assets based on the projection of undiscounted cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. Estimates of future cash flows used to test the recoverability of specific long- lived assets are based on expected cash flows from the use and eventual disposition of the assets. A significant reduction in actual cash flows and estimated cash flows may have a material adverse impact on AES’s operating results and financial condition. 40 Functional Currency Determination A business’s functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. AES’s consolidated financial results are reported in U.S. Dollars and include the effects of translating the financial statements from our international businesses with a functional currency different from the U.S. Dollar to the U.S. Dollar. Assets and liabilities are translated at the exchange rate in effect at the end of the period. Revenues and expenses are translated at the average exchange rate for the period. Translation adjustments that result from translating financial statements into the U.S. Dollar are not included in determining net income and are reported in other comprehensive income in the equity section of the consolidated balance sheet. Some of AES’s businesses have foreign currency transactions which are transactions denominated in a currency other than the business’s functional currency. A change in exchange rates between the functional currency and the currency in which the transaction is denominated results in a foreign currency transaction gain or loss that is included in the determination of net income. If facts and circumstances require a change in the functional currency of a significant subsidiary, the change in functional currency could have a material impact on AES’s operating results and financial condition. Regulatory Assets AES capitalizes incurred costs as deferred regulatory assets when there is a probable expectation that future revenue equal to the costs incurred will be billed and collected as a direct result of the inclusion of the costs in an increased tariff set by the regulator. The assets are recovered when AES collects the related costs through billings to customers. AES has recorded deferred regulatory assets of $390 million and $401 million at December 31, 2001, and 2000, respectively, that it expects to pass through to its customers in accordance with and subject to regulatory provisions. The regulatory assets include $134 million and $110 million at December 31, 2001, and 2000, respectively, which are AES’s share of regulatory assets recorded by AES’s equity method affiliates in Brazil, which are included in the investments and advances to affiliates balance on the accompanying consolidated balance sheets. The deferred regulatory assets at entities, which are controlled and consolidated by AES are recorded in other assets on the consolidated balance sheets. If the regulator disallows a material amount of capitalized costs to be included in future tariffs, the write-off of the regulatory assets may have a material adverse impact on AES’s operating results. Contingencies AES accrues for loss contingencies when the amount of the loss is probable and estimable. AES is subject to various environmental regulations, and is involved in certain legal proceedings. If AES’s actual environmental and/or legal obligations are materially different from its estimates, the recognition of the actual amounts may have a material impact on AES’s operating results and financial condition. New Accounting Pronouncements In June 2001, the FASB issued SFAS No. 142, ‘‘Goodwill and Other Intangible Assets.’’ The provisions of this statement are required to be applied starting with fiscal years beginning after December 15, 2001. This statement is required to be applied at the beginning of an entity’s fiscal year and to be applied to all goodwill and other intangible assets recognized in its financial statements at that date. SFAS No. 142 addresses how intangible assets (but not those acquired in a business combination) should be accounted for in financial statements upon their acquisition. This statement also addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. The statement requires that goodwill and certain other intangibles would have to be assessed each year to determine whether an impairment loss has occurred. Any impairments recognized upon adoption would be recorded as a change in accounting principle. 41 Future impairments would be recorded in income from continuing operations. The statement provides specific guidance for testing goodwill for impairment. The Company had $3.2 billion of goodwill at December 31, 2001. Goodwill amortization was $62 million for the year ended December 31, 2001. The Company is currently assessing the impact of SFAS No. 142 on its financial position and results of operations. In June 2001, the FASB issued SFAS No. 143, ‘‘Accounting for Asset Retirement Obligations,’’ which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. The statement requires recognition of legal obligations associated with the retirement of a long-lived asset, except for certain obligations of lessees. The Company is currently assessing the impact of SFAS No. 143 on its financial position and results of operations. In December 2001, the FASB revised its earlier conclusion, Derivatives Implementation Group (‘‘DIG’’) Issue C-15, related to contracts involving the purchase or sale of electricity. Contracts for the purchase or sale of electricity, both forward and option contracts, including capacity contracts, may qualify for the normal purchases and sales exemption and are not required to be accounted for as derivatives under SFAS No. 133. In order for contracts to qualify for this exemption, they must meet certain criteria, which include the requirement for physical delivery of the electricity to be purchased or sold under the contract only in the normal course of business. Additionally, contracts that have a price based on an underlying that is not clearly and closely related to the electricity being sold or purchased or that are denominated in a currency that is foreign to the buyer or seller are not considered normal purchases and normal sales and are required to be accounted for as derivatives under SFAS No. 133. This revised conclusion is effective beginning April 1, 2002. The Company is currently assessing the impact of revised DIG Issue C-15 on its financial condition and results of operations. 2001 COMPARED TO 2000 Revenues Revenues increased $1.8 billion, or 24% to $9.3 billion in 2001 from $7.5 billion in 2000. The increase in revenues is due to the acquisition of new businesses, new operations from greenfield projects and positive improvements from existing operations. Excluding businesses acquired or that commenced commercial operations in 2001 or 2000, revenues increased 5% to $7.1 billion in 2001. The following table shows the revenue of each segment: 2001 2000 % Change Contract generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Competitive supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Large utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2.5 billion $2.7 billion $2.4 billion $1.7 billion $1.7 billion $2.4 billion $2.1 billion $1.3 billion 47% 13% 14% 31% Contract generation revenues increased $800 million, or 47% to $2.5 billion in 2001 from $1.7 billion in 2000, principally resulting from the addition of revenues attributable to businesses acquired during 2001 or 2000. Excluding businesses acquired or that commenced commercial operations in 2001 or 2000, contract generation revenues increased 2% to $1.7 billion in 2001. The increase in contract generation segment revenues was due primarily to increases in South America, Europe/Africa and Asia. In South America, contract generation segment revenues increased $472 million due mainly to the acquisition of Gener and the full year of operations at Uruguaiana offset by reduced revenues at Tiete from the electricity rationing in Brazil. In Europe/Africa, contract generation segment revenues increased $88 million, and the acquisition of a controlling interest in Kilroot during 2000 was the largest contributor to the increase. In Asia, contract generation segment revenues increased $96 million, and increased operations from our Ecogen peaking plant was the most significant contributor to the 42 increase. In North America, contract generation segment revenues increased $46 million. In the Caribbean (which includes Venezuela and Colombia), contract generation segment revenues increased $11 million, and this was due to a full year of operations at Merida III offset by a lower capacity factor at Los Mina. Competitive supply revenues increased $300 million or 13% to $2.7 billion in 2001 from $2.4 billion in 2000. Excluding businesses acquired or that commenced commercial operations in 2001 or 2000, competitive supply revenues increased 3% to $2.4 billion in 2001. The most significant increases occurred within North America and the Caribbean. Slight increases were recorded within South America and Asia. Europe/Africa reported a slight decrease due to lower pool prices in the U.K. offset by the start of commercial operations at Fifoots and the acquisition of Ottana. In North America, competitive supply segment revenues increased $184 million due primarily to an expanded customer base at New Energy as well as increased operations at Placerita. These increases in North America were offset by lower market prices at our New York businesses. In the Caribbean, competitive supply segment revenues increased $123 million due primarily to the acquisition of Chivor. Large utility revenues increased $300 million, or 14% to $2.4 billion in 2001 from $2.1 billion in 2000, principally resulting from the addition of revenues attributable to businesses acquired during 2001 or 2000. Excluding businesses acquired in 2001 and 2000, large utility revenues increased 1% to $1.6 billion in 2001. The majority of the increase occurred within the Caribbean, and there was a slight increase in North America. In the Caribbean, revenues increased $312 million due to a full year of revenues from EDC, which was acquired in June 2000. Growth distribution revenues increased $400 million, or 31% to $1.7 billion in 2001 from $1.3 billion in 2000. Excluding businesses acquired in 2001 or 2000, growth distribution revenues increased 20% to $1.3 billion in 2001. Revenues increased most significantly in the Caribbean and to a lesser extent in South America and Europe/Africa. Revenues decreased slightly in Asia. In the Caribbean, growth distribution segment revenues increased $296 million due primarily to a full year of operations at CAESS, which was acquired in 2000 and improved operations at EDE Este. In South America, growth distribution segment revenues increased $89 million due to the significant revenues at Sul from our settlement with the Brazilian government offset by declines in revenues at our Argentine distribution businesses. The settlement with the Brazilian government confirmed the sales price that Sul would receive from its sales into the southeast market (where rationing occurred) under its Itaipu contract. In Europe/Africa, growth distribution segment revenues increased $59 million from the acquisition of SONEL. In Asia, growth distribution segment revenues decreased $33 million mainly due to the change in the way in which we are accounting for our investment in CESCO. CESCO was previously consolidated but was changed to equity method during 2001 when the Company was removed from management and the Board of Directors. This decline was partially offset by the increase in revenues from the distribution businesses that we acquired in the Ukraine. AES is a global power company which operates in 29 countries around the world. The breakdown of AES’s revenues for the years ended December 31, 2001 and 2000, based on the geographic region in which they were earned, is set forth below. A more detailed breakdown by country can be found in Note 16 of the consolidated financial statements. North America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . South America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Caribbean* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Europe/Africa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3.6 billion $ 1.7 billion $ 1.9 billion $ 1.4 billion $693 million $ 3.4 billion $ 1.1 billion $ 1.1 billion $ 1.3 billion $615 million 6% 55% 73% 8% 13% 2001 2000 % change * Includes Venezuela and Colombia. 43 Gross margin Gross margin increased $307 million, or 15%, to $2.3 billion in 2001 from $2.0 billion in 2000. Gross margin as a percentage of revenues decreased to 25% in 2000 from 26% in 2001. The increase in gross margin is due to acquisition of new businesses and new operations from greenfield projects offset by lower market prices in the United Kingdom. The decrease in gross margin as a percentage of revenues is due to a decline in the competitive supply and contract generation gross margin percentages offset slightly by increased gross margin percentages from large utilities and growth distribution. Excluding businesses acquired or that commenced commercial operations in 2001 or 2000, gross margin decreased 2% to $1.8 billion in 2001. 2001 2000 % Change Contract generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Competitive supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Large utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $827 million $440 million $739 million $296 million $767 million $559 million $538 million $131 million 8% (21%) 37% 126% Contract generation gross margin increased $60 million, or 8%, to $827 million in 2001 from $767 million in 2000. Excluding businesses acquired or that commenced commercial operations during 2001 and 2000, contract generation gross margin decreased 6% to $710 million in 2001. Contract generation gross margin increased in all geographic regions except for Asia. The contract generation gross margin as a percentage of revenues decreased to 33% in 2001 from 44% in 2000. In South America, contract generation gross margin increased $17 million and was 27% of revenues. The increase is due to the acquisition of Gener offset by a decline at Tiete from the rationing of electricity in Brazil. In North America, contract generation gross margin increased $8 million and was 50% of revenues. The increase is due to improvements at Southland and Beaver Valley partially offset by a decrease at Thames from the contract buydown (see footnote 13 to the Company’s consolidated financial statements). In Europe/ Africa, contract generation gross margin increased $44 million and was 30% of revenues. The increase is due primarily to our additional ownership interest in Kilroot and the acquisition of Ebute in Nigeria. In Asia, contract generation gross margin decreased $22 million and was 29% of revenues. The decrease is due mainly to additional bad debt provisions at Jiaozuo, Hefei and Aixi in China that were partially offset by the start of commercial operations at Haripur. The decrease in contract generation gross margin as a percentage of revenue is due to the acquisition of generation businesses with overall gross margin percentages, which are lower than the overall portfolio of generation businesses. As a percentage of sales, contract generation gross margin declined in South America and Asia, was relatively flat in North America and increased in Europe/Africa and the Caribbean. The competitive supply gross margin decreased $119 million, or 21%, to $440 million in 2001 from $559 million in 2000. Excluding businesses acquired or that commenced commercial operations during 2001 and 2000, competitive supply gross margin decreased 26% to $408 million in 2001. The overall decrease is due to declines in Europe/Africa and South America that were partially offset by slight increases in North America, the Caribbean and Asia. The competitive supply gross margin as a percentage of revenues decreased to 16% in 2001 from 23% in 2000. In South America, competitive supply segment gross margin decreased $61 million and was 1% of revenues due to declines at our businesses in Argentina. In Europe/Africa, competitive supply segment gross margin decreased $95 million and was 22% of revenues. The decrease is due primarily to declines at Drax, Barry and Fifoots from the lower market prices in the U.K. In North America, competitive supply segment gross margin increased $14 million and was 11% of revenues. The increase was due to an expanded customer base at New Energy and was partially offset by decreases at Somerset in New York and Deepwater in Texas. In the Caribbean (which includes Colombia), the competitive supply gross margin increased $15 million and was 29% of revenues. The increase is due primarily to the acquisition of Chivor. As a percentage 44 of sales, competitive supply gross margin declined in South America, Europe/Africa and the Caribbean and remained relatively flat in North America and Asia. Large utilities gross margin increased $201 million, or 37%, to $739 million in 2001 from $538 million in 2000. Excluding businesses acquired or that commenced commercial operations during 2001 and 2000, large utilities gross margin increased 10% to $396 million in 2001. Large utilities gross margin as a percentage of revenues increased to 30% in 2001 from 25% in 2000. In the Caribbean (which includes Venezuela), large utility gross margin increased $166 million and was due to a full year of contribution from EDC which was acquired in June 2000. Also, in North America, the gross margin contributions from both IPALCO and CILCORP increased. Growth distribution gross margin increased $165 million, or 126% to $296 million in 2001 from $131 million in 2000. Excluding businesses acquired during 2001 and 2000, growth distribution gross margin increased 93% to $268 million in 2001. Growth distribution gross margin as a percentage of revenue increased to 18% in 2001 from 10% in 2000. Growth distribution business gross margin, as well as gross margin as a percentage of sales, increased in South America and the Caribbean, but decreased in Europe/Africa and Asia. In South America, growth distribution margin increased $157 million and was 38% of revenues. The increase is due primarily to Sul’s sales of excess energy into the southeast market where rationing was taking place. In the Caribbean, growth distribution margin increased $39 million and was 5% of revenues. The increase is due mainly to lower losses at Ede Este and an increase in contribution from CAESS. In Europe/Africa, growth distribution margin decreased $10 million and was negative due to losses at SONEL. In Asia, growth distribution margin decreased $18 million and was negative due primarily to an increase in losses at Telasi. The breakdown of AES’s gross margin for the years ended December 31, 2001 and 2000, based on the geographic region in which they were earned, is set forth below. 2001 % of Revenue 2000 % of Revenue % change North America . . . . . . . . . . . . . . . . South America . . . . . . . . . . . . . . . . Caribbean* . . . . . . . . . . . . . . . . . . Europe/Africa . . . . . . . . . . . . . . . . Asia . . . . . . . . . . . . . . . . . . . . . . . $912 million $522 million $457 million $310 million $101 million 25% 30% 25% 22% 15% $844 million $416 million $226 million $371 million $138 million 25% 36% 21% 29% 22% 8% 25% 102% (16%) (27%) * Includes Venezuela and Colombia. Selling, general and administrative expenses Selling, general and administrative expenses increased $38 million, or 46%, to $120 million in 2001 from $82 million in 2000. Selling, general and administrative expenses as a percentage of revenues remained constant at 1% in 2001 and 2000. The overall increase in selling, general and administrative expenses is due to increased development activities. Interest expense, net Net interest expense increased $327 million, or 29%, to $1.5 billion in 2001 from $1.1 billion in 2000. Net interest expense as a percentage of revenues increased to 16% in 2001 from 15% in 2000. Net interest expense increased overall primarily due to interest expense at new businesses, additional corporate interest expense arising from senior debt issued during 2001 to finance new investments and mark-to-market losses on interest rate related derivative instruments. 45 Other income, net Other income decreased $8 million, or 26%, to $23 million in 2001 from $31 million in 2000. Other income includes foreign currency transaction gains and losses at consolidated subsidiaries and mark-to-market adjustments on certain derivative financial instruments and other non-operating income. Gain on sale of assets During 2000, IPALCO sold certain assets (‘‘Thermal Assets’’) for approximately $162 million. The transaction resulted in a gain to the company of approximately $31 million. Of the net proceeds, $88 million was used to retire debt specifically assignable to the Thermal Assets. Gain on available for sale securities During 2001, a subsidiary of the Company sold approximately 14 million shares of Compania Anonima Nacional Telefonos de Venezuela resulting in a realized gain of approximately $18 million. During 2000, a subsidiary of the Company sold approximately one million shares of Internet Capital Group, Inc. resulting in a realized gain of approximately $112 million. Environmental fine The Company recorded a $17 million environmental fine in 2000 related to excess nitrogen oxide air emissions at certain of its generating facilities in California. Equity in pre-tax earnings of affiliates Equity in pre-tax earnings of affiliates decreased $300 million, to $175 million in 2001 from $475 million in 2000. The overall decrease in equity in earnings is due primarily to declines in equity in earnings of Brazilian large utility affiliates which resulted from the devaluation of the Brazilian Real, as well as the rationing of electricity in Brazil. Equity in earnings of competitive supply affiliates decreased to ($5) million in 2001 from $0 million in 2000. The decrease is due to losses incurred at Infovias, a Brazilian company. Equity in earnings of contract generation affiliates increased to $54 million in 2001 from $49 million in 2000. The increase is due primarily to contributions from equity affiliates of Gener and the contribution from Itabo offset by a decrease in Kilroot related to the Company’s purchase of an additional interest thereby making it a consolidated subsidiary. Equity in earnings of large utilities decreased $286 million to $140 million in 2001 from $426 million in 2000. The decrease is primarily due to the devaluation of the Brazilian Real, as well as the impact of electricity rationing in Brazil. Equity in earnings of large utilities included non-cash Brazilian foreign currency transaction losses on a pretax basis of $210 million and $64 million in 2001 and 2000, respectively. Our distribution concession contracts in Brazil provide for annual tariff adjustments based upon changes in the local inflation rates and generally significant devaluations are followed by increased local currency inflation. However, because of the lack of adjustment to the current exchange rate, the in arrears nature of the respective adjustment to the tariff or the potential delays or magnitude of the resulting local currency inflation of the tariff, the future results of operations of the company’s distribution companies in Brazil could be adversely affected by the continued devaluation of the Brazilian Real. Equity in earnings of growth distribution affiliates decreased to ($13) million in 2001 from $0 million in 2000. The decrease is primarily due to the change in the way in which we account for our 46 investment in CESCO. CESCO was previously consolidated but was changed to equity method during 2001 when the Company was removed from management and the Board of Directors. Income taxes Income taxes (including income taxes on equity in earnings and minority interests) decreased $147 million to $230 million in 2001 from $377 million in 2000. The Company’s effective tax rate increased to 33% in 2001 from 31% in 2000, due to increased dividends from foreign businesses. Severance and transaction costs During the first quarter of 2001, the Company incurred approximately $94 million of transaction and contractual severance costs related to the acquisition of IPALCO. During the third quarter of 2001, the Company recorded an additional $37 million in contractual severance costs related to the IPALCO transaction. Minority interest Minority interest (before income taxes) decreased $19 million, or 15%, to $105 million in 2001 from $124 million in 2000. The decreases in contract generation, competitive supply and growth distribution minority interest were offset slightly by an increase in the large utilities minority interest. Contract generation minority interest decreased $15 million to $22 million in 2001 from $36 million in 2000. The decrease in contract generation minority interest is due primarily to lower contributions from Tiete. Competitive supply minority interest decreased $26 million to $11 million in 2001 from $37 million in 2000. The decrease in competitive supply minority interest is due primarily to lower contributions from Panama and CTSN. Large utilities minority interest increased $3 million to $88 million in 2001 from $85 million in 2000. Increased contributions from EDC were almost entirely offset by declines at CEMIG. Growth distribution minority interest increased $19 million to ($16) million in 2001 from ($31) million in 2000. The increases were due to the acquisition of CAESS and increased contributions from EDE Este. Discontinued operations During 2001, the Company discontinued certain of its operations, including Power Direct, Ib Valley, Power Northern, Geoutilities, TermoCandelaria and several telecommunications businesses in the United States and Brazil. As a result, the Company recorded $194 million and $21 million in 2001 and 2000, respectively, net of tax, of net losses from these businesses. All of the operations for these businesses and the related write-offs from disposition are reported in this line item. Results of operations in 2001 were a loss of approximately $47 million and the write-off from dispositions was a loss of approximately $147 million, net of tax. All amounts in 2000 represent results from operations. Extraordinary item On March 31, 2000, the Company replaced its corporate revolving bank loan with a new facility that incorporated the letter of credit facility. As a result, the Company wrote-off the unamortized deferred financing costs related to the refinanced revolver resulting in an extraordinary item for the early extinguishment of debt of $7 million, net in tax. In November 2000, a subsidiary of the Company sold its Thermal Assets to Citizen Gas & Coke Utility. A portion of the proceeds was used to retire debt specifically assignable to the assets. In connection with the retirement of the debt, the subsidiary 47 wrote-off debt issuance costs of $4 million, which resulted in an extraordinary loss for the early retirement of debt. Net income Net income decreased $522 million to $273 million in 2001 from $795 million in 2000. The overall decrease in net income is due to decreased net income from competitive supply and large utility businesses offset slightly by increases in the contract generation and growth distribution businesses. The decreases are primarily due to lower market prices in the United Kingdom and the decline in the Brazilian Real during 2001 resulting in foreign currency transaction losses of approximately $210 million. Additionally the Company recorded severance and transaction costs related to the IPALCO pooling-of-interest transaction and a loss from discontinued operations of $194 million. Our 10 largest contributors to net income in 2001 were as follows: Lal Pir/Pak Gen, Shady Point and Thames from contract generation; Somerset from competitive supply; EDC, Eletropaulo, IPALCO, CILCORP and CEMIG from large utilities; and Sul from growth distribution. 2000 COMPARED TO 1999 Revenues Revenues increased $3.4 billion, or 83%, to $7.5 billion in 2000 from $4.1 billion in 1999. The increase in revenues is due primarily to the acquisition of new businesses. Excluding businesses acquired or that commenced commercial operations during 2000 or 1999, revenues increased 6% to $3.6 billion. 2000 1999 % Change Contract generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Competitive supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Large utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1.7 billion $2.4 billion $2.1 billion $1.3 billion $ 1.3 billion $873 million $992 million $948 million 31% 175% 112% 37% Contract generation revenues increased $400 million, or 31%, to $1.7 billion in 2000 from $1.3 billion in 1999. Excluding businesses acquired or that commenced commercial operations in 2000 or 1999, contract generation revenues increased 4% to $1.3 billion in 2000. The increase in contract generation segment revenues was due primarily to increases in South America, North America, Caribbean and Asia, offset by a slight decline in Europe/Africa. In South America, contract generation segment revenue increased $245 million, and this is due mainly to the acquisition of Tiete. In North America, contract generation segment revenues increased $76 million due primarily to the start of commercial operations at Warrior Run in January 2000. In the Caribbean, contract generation segment revenues increased $92 million due primarily to the start of commercial operations at Merida III in June 2000 and increased revenues from Los Mina. In Asia, contract generation segment revenue increased $41 million due primarily to increased operations at the Ecogen peaking plant and Lal Pir and Pak Gen in Pakistan. In Europe/Africa, contract generation segment revenues remained fairly constant with decreases at Tisza II in Hungary being offset by the acquisition of a controlling interest at Kilroot. Competitive supply revenues increased $1.5 billion, or 175%, to $2.4 billion in 2000 from $873 million in 1999. Excluding businesses acquired or that commenced commercial operations in 2000 or 1999, competitive supply revenues increased 25% to $477 million in 2000. The most significant increases occurred within North America and Europe/Africa. Slight increases occurred in South America and the Caribbean. Asia reported a slight decrease. In North America, competitive supply segment revenues increased $610 million due primarily to the New York plants and New Energy 48 contributing a full year of revenues in 2000. In Europe/Asia, competitive supply segment revenues increased $875 million due primarily to Drax contributing a full year of revenues during 2000. Large utilities revenues increased $1.1 billion, or 112%, to $2.1 billion in 2000 from $992 million in 1999. Excluding businesses acquired in 2000 or 1999, large utilities revenues increased 2% to $892 million in 2000. The increase in large utility segment revenues occurred in North America and the Caribbean. North America large utility segment revenues increased $628 million due to CILCORP contributing a full year of revenues in 2000. The acquisition of EDC in Venezuela contributed entirely to the $494 million increase in Caribbean revenues. Growth distribution revenues increased $352 million, or 37%, to $1.3 billion in 2000 from $948 million in 1999. Excluding businesses acquired in 2000 or 1999, growth distribution revenues increased 5% to $889 million in 2000. The increase in growth distribution segment revenues occurred within South America, the Caribbean and Asia. In South America, growth distribution revenues increased $51 million due primarily to increased revenues from Sul caused by improved economic conditions in Brazil. In the Caribbean, growth distribution revenues increased $189 million due primarily to the acquisition of EDE Este and CESCO in 1999 and CAESS in 2000. The breakdown of AES’s revenues for the years ended December 31, 2000 and 1999, based on the geographic region in which they were earned, is set forth below. North America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . South America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Caribbean* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Europe/Africa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3.4 billion $ 1.1 billion $ 1.1 billion $ 1.3 billion $615 million $ 2.1 billion $827 million $312 million $421 million $499 million 62% 33% 253% 209% 23% 2000 1999 % change * Includes Venezuela and Colombia. Gross margin Gross margin, which represents total revenues reduced by cost of sales, increased $700 million, or 54%, to $2.0 billion in 2000 from $1.3 billion in 1999. Gross margin as a percentage of revenues decreased to 26% in 2000 from 31% in 1999. The decrease in gross margin as a percentage of revenues is primarily due to the decrease in the competitive supply and growth distribution gross margin. Excluding businesses acquired or that commenced commercial operations in 2000 or 1999, gross margin decreased 2% to $1.1 billion in 2000. 2000 1999 % Change Contract generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Competitive supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Large utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $767 million $559 million $538 million $131 million $552 million $244 million $282 million $185 million 39% 129% 91% (29%) The contract generation gross margin increased $215 million, or 39%, to $767 million in 2000 from $552 million in 1999. Excluding businesses acquired or that commenced commercial operations in 2000 or 1999, contract generation gross margin decreased 3% to $509 million in 2000. The increase in contract generation gross margin was primarily due to increases in South America and North America. Slight increases in the Caribbean and Asia were offset by slight decreases in Europe/Africa. The contract generation gross margin as a percentage of revenues increased to 44% in 2000 from 42% in 1999. In South America, contract generation gross margin increased $168 million and was 66% of revenues. The increase is primarily due to the acquisition of Tiete. In North America, contract 49 generation increased $47 million and was 52% of revenues. The increase is due primarily to the start of commercial operations at Warrior Run. The overall increase in gross margin as a percentage of revenues is due primarily to slightly better gross margin percentages from businesses acquired than the core portfolio of businesses. As a percentage of revenues, contract generation gross margin increased in South America, remained relatively flat in North America and Europe/Africa and decreased slightly in Asia. The competitive supply gross margin increased $315 million, or 129%, to $559 million in 2000 from $244 million in 1999. Excluding businesses acquired or that commenced commercial operations in 2000 or 1999, competitive supply gross margin increased 14% to $177 million in 2000. The increase in competitive supply gross margin was due primarily to increases in North America and Europe/Africa. Slight increases in South America and the Caribbean were offset by slight declines in Asia. The competitive supply gross margin as a percentage of revenues decreased to 23% in 2000 from 28% in 1999. In North America, competitive supply gross margin increased $71 million and was 12% of revenues. The increase is due to a full year of contribution by the New York plants. In Europe/Africa, competitive supply gross margin increased $243 million and was 30% of revenues. The increase was due primarily to the contribution of a full year by Drax. The overall increase in gross margin is due primarily to businesses acquired during 1999, which contributed a full year of operations in 2000. The overall decline in gross margin as a percentage of revenues is due to lower gross margins experienced at Drax, Panama, Ekibastuz and Altai. As a percentage of revenues, competitive supply gross margin increased in South America, remained flat in North America and decreased in Europe/Africa, the Caribbean and Asia. Large utilities gross margin increased $256 million, or 91%, to $538 million in 2000 from $282 million in 1999. Excluding businesses acquired in 2000 or 1999, large utilities gross margin decreased 2% to $262 million in 2000. The increase in large utilities gross margin was due to increases in North America and the Caribbean. The large utilities gross margin as a percentage of revenues decreased to 25% in 2000 from 28% in 1999. In North America, large utilities gross margin increased $78 million and was 22% of revenues. The increase is due to a full year of contribution from CILCORP. As a percentage of revenues, large utilities gross margin decreased in North America. The acquisition of EDC in the Caribbean contributed entirely to the $177 million increase, which was 36% of revenues. Growth distribution gross margin decreased $54 million, or 29%, to $131 million in 2000 from $185 million in 1999. Excluding businesses acquired in 2000 or 1999, growth distribution gross margin decreased 10% to $172 million in 2000. The decrease in growth distribution gross margin was due to decreases in South America, the Caribbean and Asia. The growth distribution gross margin as a percentage of revenues decreased to 10% in 2000 from 20% in 1999. In South America, growth distribution gross margin decreased $10 million and was 22% of revenues. Increases from Sul were offset by declines from Eden/Edes and Edelap in Argentina. In the Caribbean, growth distribution gross margin decreased $31 million and was (2%) of revenues. The decrease was due to the inclusion of a full year of losses from EDE Este. As a percentage of revenues, growth distribution gross margin decreased in South America and the Caribbean and remained flat in Asia. 50 The breakdown of AES’s gross margin for the years ended December 31, 2000 and 1999, based on the geographic region in which they were earned, is set forth below. 2000 % of Revenue 1999 % of Revenue % change North America . . . . . . . . . . . . . . . . South America . . . . . . . . . . . . . . . . Caribbean* . . . . . . . . . . . . . . . . . . Europe/Africa . . . . . . . . . . . . . . . . Asia . . . . . . . . . . . . . . . . . . . . . . . $844 million $416 million $226 million $371 million $138 million 25% 36% 21% 29% 22% $649 million $232 million $75 million $124 million $183 million 32% 28% 24% 29% 37% 30% 79% 201% 199% (26%) * Includes Venezuela and Colombia. Selling, general and administrative expenses Selling, general and administrative expenses increased $11 million, or 15%, to $82 million in 2000 from $71 million in 1999. Selling, general and administrative expenses as a percentage of revenues remained constant at 1% in both 2000 and 1999. The increase is due to an increase in business development activities. Interest expense, net Net interest expense increased $506 million, or 80%, to $1.1 billion in 2000 from $632 million in 1999. Interest expense as a percentage of revenues remained constant at 15% in both 2000 and 1999. Interest expense increased primarily due to the interest at new businesses, including Drax, Tiete, CILCORP and EDC, as well as additional corporate interest costs resulting from the senior debt and convertible securities issued within the past two years. Other income, net Other income increased $16 million, or 107%, to $31 million in 2000 from $15 million in 1999. Other income includes foreign currency transaction gains and losses as well as other non-operating income. The increase in other income is due primarily to a favorable legal judgment and the sale of development projects. Severance and transaction costs During the fourth quarter of 2000, the Company incurred approximately $79 million of transaction and contractual severance costs related to the acquisition of IPALCO. Gain on sale of assets During 2000, IPALCO sold certain assets (‘‘Thermal Assets’’) for approximately $162 million. The transaction resulted in a gain to the Company of approximately $31 million. Of the net proceeds, $88 million was used to retire debt specifically assignable to the Thermal Assets. During 1999, the Company recorded a $29 million gain (before extraordinary loss) from the buyout of its long-term power sales agreement at Placerita. The Company received gross proceeds of $110 million which were offset by transaction related costs of $19 million and an impairment loss of $62 million to reduce the carrying value of the electric generation assets to their estimated fair value after termination of the contract. The estimated fair value was determined by an independent appraisal. Concurrent with the buyout of the power sales agreement, the Company repaid the related non-recourse debt prior to its scheduled maturity and recorded an extraordinary loss of $11 million, net of income taxes. 51 Gain on available-for-sale securities During 2000, a subsidiary of the Company sold approximately one million shares of Internet Capital Group, Inc. resulting in a realized gain of approximately $112 million. There were no similar transactions during 1999. Environmental fine The Company recorded a $17 million environmental fine in 2000 related to excess nitrogen oxide in air emissions at certain of its generating facilities in California. As a result of the shortage of electricity in California in 2000, our generating facilities in California operated at higher than expected capacity factors. The Company does not intend to operate its facilities in California unless it has sufficient nitrogen oxide air emission credits or allocations. Equity in pre-tax earnings of affiliates Equity in pre-tax earnings of affiliates (before income taxes) increased $446 million to $475 million in 2000 from $29 million in 1999. Equity in earnings of affiliates includes foreign currency transaction losses of $64 million and $203 million in 2000 and 1999, respectively. The increase in equity in earnings of affiliates resulted from the increase in equity in earnings of large utility investments offset by a slight decrease in equity in earnings of competitive generation investments. The Company did not have any equity in earnings from competitive supply or growth distribution investments during 2000 or 1999. Equity in earnings of contract generation affiliates decreased $11 million, or 18%, to $49 million in 2000 from $60 million in 1999. The decrease in equity in earnings is due to the acquisition of a controlling interest in Kilroot during 2000 thereby causing it to become consolidated during the year and declining its equity in earnings contribution. Equity in earnings of large utilities increased $457 million to $426 million in 2000 from ($31) million in 1999. The significant increase in equity in earnings is due to an additional ownership interest in Eletropaulo, as well as improved economic conditions in Brazil, which resulted in much greater contribution from Eletropaulo and CEMIG. Foreign currency transaction losses decreased $139 million to $64 million in 2000 at our large utility affiliates in Brazil. Income taxes Income taxes (including income taxes on equity in earnings and minority interest) increased $186 million to $377 million in 2000 from $191 million in 1999. The Company’s effective tax rate decreased to 31% in 2000 from 34% in 1999 due to an increase in earnings of certain foreign businesses which are taxed at a lower rate than the U.S. income tax rate. Minority interest Minority interest (before income taxes) increased $59 million, or 92%, to $124 million in 2000 from $64 million in 1999. The increase in minority interest is due to increases in all segments except growth distribution, which had a decline from 1999. Contract generation minority interest increased $20 million, or 125%, to $36 million in 2000 from $16 million in 1999. The increase in minority interest is due to increased contributions from Tiete. Competitive supply minority interest increased $11 million, or 42%, to $37 million in 2000 from $26 million in 1999. The increase in minority interest is due to increased contributions from generation businesses in South America. 52 Large utilities minority interest increased $88 million to $85 million in 2000 from a loss of $3 million in 1999. The overall increase is due to increased contributions from EDC and CEMIG. Growth distribution minority interest decreased $60 million to a loss of $31 million in 2000 from $25 million in 1999. The overall decrease is due to lower contributions from EDE Este and CESCO. Discontinued operations During 2001, the Company discontinued certain of its operations, including Power Direct, Power Northern, Geoutilities and several telecommunications businesses in the United States and Brazil. Therefore, the results of operations from these businesses have been reclassified to discontinued operations. The Company recorded $21 million and $3 million in 2000 and 1999, respectively, net of tax, of net losses from these businesses. Extraordinary item On March 31, 2000, the Company replaced its corporate revolving bank loan with a new facility that would incorporate the letter of credit facility. As a result, the Company wrote-off the unamortized deferred financing costs related to the refinanced revolver resulting in an extraordinary item for the early extinguishment of debt of $7 million net in tax. In November 2000, a subsidiary of the Company sold its Thermal Assets to Citizen Gas & Coke Utility. A portion of the proceeds was used to retire debt specifically assignable to the assets. In connection with the retirement of the debt, the subsidiary wrote-off debt issuance costs of $4 million, which resulted in an extraordinary loss for the early retirement of debt. In 1999, the Company recorded a $17 million loss, net of income taxes from the early extinguishment of recourse debt and non-recourse debt at Placerita. Net income Net income increased $438 million, or 123%, to $795 million in 2000 from $357 million in 1999. The increase in net income is due to increases in all segments except growth distribution. The businesses contributing the most include the New York plants, Drax, Tiete, EDC, Eletropaulo and CEMIG. Net income was also positively impacted by non-recurring gains from the sale of assets and investments of $143 million offset by expenses from severance and transaction costs of $79 million from the IPALCO pooling-of-interests transaction and an environmental fine of $17 million. CAPITAL RESOURCES AND LIQUIDITY Non-recourse project financing General AES is a holding company that conducts all of its operations through subsidiaries. AES has, to the extent practicable, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire its electric power plants, distribution companies and related assets. Non-recourse borrowings are substantially non-recourse to other subsidiaries and affiliates and to AES as the parent company, and are generally secured by the capital stock, physical assets, contracts and cash flow of the related subsidiary or affiliate. At December 31, 2001, AES had $5.4 billion of recourse debt and $16.9 billion of non-recourse debt outstanding. For more information on AES’s long term debt see Note 6 of the consolidated financial statements. The Company intends to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that the Company or its affiliates may develop, construct or acquire. However, depending on market conditions and the unique characteristics of individual businesses, non-recourse debt financing may not be available or available on economically attractive terms. 53 In addition to the non-recourse debt, if available, AES as the parent company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition. These investments have generally taken the form of equity investments or loans, which are subordinated to the project’s non-recourse loans. The funds for these investments have been provided by cash flows from operations and by the proceeds from issuances of debt, common stock and other securities issued by the Company. Similarly, in certain of its businesses, the Company may provide financial guarantees or other credit support for the benefit of counter parties who have entered into contracts for the purchase or sale of electricity with the Company’s subsidiaries. In such circumstances, were a subsidiary to default on a payment or supply obligation, the Company would be responsible for its subsidiary’s obligations up to the amount provided for in the relevant guarantee or other credit support. As a result of recent declines in the trading prices of AES’s equity and debt securities, counter parties may no longer be as willing to accept general unsecured commitments by AES to provide credit support. Accordingly, with respect to both new and existing commitments, AES may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace any AES credit support. For example, AES has provided an aggregate of approximately $260 million of guarantees to entities that supply power to AES New Energy. AES cannot provide assurance that it will be able to provide adequate assurances to such counter parties. In addition, to the extent AES is required and able to provide letters of credit or other collateral to such counter parties, it will limit the amount of credit available to AES to meet its other liquidity needs. At December 31, 2001, AES had provided outstanding financial and performance related guarantees or other credit support commitments to or for the benefit of its subsidiaries, which were limited by the terms of the agreements, to an aggregate of approximately $775 million (excluding those collateralized by letter-of-credit obligations discussed below). The Company is also obligated under other commitments, which are limited to amounts, or percentages of amounts, received by AES as distributions from its project subsidiaries. These amounts aggregated $50 million as of December 31, 2001. In addition, the Company has commitments to fund its equity in projects currently under development or in construction. At December 31, 2001, such commitments to invest amounted to approximately $207 million (excluding those collateralized by letter-of-credit obligations). At December 31, 2001, the Company had $453 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations. The Company pays a letter-of-credit fee ranging from 0.50% to 2.0% per annum on the outstanding amounts. In addition, the Company had $76 million and a subsidiary of the Company had $271 million in surety bonds outstanding at December 31, 2001. Project level defaults While the lenders under AES’s non-recourse project financings do not have direct recourse to the parent, defaults thereunder can still have important consequences for AES’s results of operations and liquidity, including, without limitation: • Reducing AES’s cash flows since the project subsidiary will typically be prohibited from distributing cash to AES during the pendancy of any default • Triggering AES’s obligation to make payments under any financial guarantee, letter of credit or other credit support AES has provided to or on behalf of such subsidiary • Causing AES to record a loss in the event the lender forecloses on the assets • Triggering defaults in the parent’s outstanding debt and trust preferred instruments. For example, the parent’s revolving credit agreement and outstanding senior notes, senior subordinated notes, junior subordinated notes and trust preferred securities include events of 54 default for certain bankruptcy related events involving material subsidiaries. In addition, the parent’s revolving credit agreement and senior subordinated notes include events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries. At December 31, 2001, a number of the Company’s subsidiaries were in default under their outstanding project indebtedness as of December 31, 2001, including Chivor in Colombia and Edelap, Eden/Edes and Parana in Argentina. Because none of these businesses are material subsidiaries, none of these defaults are expected to have a material adverse effect on the Company’s results of operations or financial condition. All of the related loans have been recorded in current non-recourse debt in the accompanying consolidated balance sheets. Because of the current political, social and economic crisis in Argentina, the Company’s Argentine businesses are experiencing significant cash flow shortfalls. AES may be required to record a material impairment or loss or write-off associated with the recorded carrying values of its Argentine businesses in 2002. In addition, subsequent to year end, AES Drax had an event of default under its 1.3 billion pound sterling bank facility as a result of its inability to obtain specified minimum amounts of insurance coverage. While the lenders under this facility have not exercised their right to accelerate the maturity of the loans thereunder, they have refused to waive the prohibition on the payment of any dividends by AES Drax and its subsidiaries during the pendancy of the default. Accordingly, AES Drax has had to use its debt service reserve accounts to service a portion of its outstanding subordinated public debt at the holding company and has been unable, and will for at least the next six months be unable, to pay dividends to AES. On March 21, 2002, Fifoots was placed in administrative receivership by its lenders. Fifoots defaulted on its debt after electricity prices in the U.K. fell below its marginal costs. AES expects to write-off its investment of approximately $36 million in Fifoots during the first quarter of 2002. Parent company liquidity Because of the non-recourse nature of most of AES’s indebtedness, AES believes that unconsolidated parent company liquidity is more important than the liquidity position of AES and its consolidated subsidiaries as presented on a consolidated basis. The parent company’s principal sources of liquidity are: • Dividends and other distributions from its subsidiaries, including refinancing proceeds • Proceeds from debt and equity financings at the parent company level, including borrowings under its revolving credit facility, and • Proceeds from asset sales. The parent Company’s cash requirements through the end of 2002 are primarily to fund: • Construction commitments • Other equity commitments • Interest and preferred dividends • Principal repayments of long-term debt • Taxes, and • Parent company overhead. While AES believes that its sources of liquidity will be adequate to meet its needs through the end of 2002, this belief is based on a number of material assumptions, including, without limitation, assumptions about exchange rates, power market pool prices, the ability of its subsidiaries to pay 55 dividends and the timing and amount of asset sale proceeds. In addition, there can be no assurance that these sources will be available when needed or that its actual cash requirements will not be greater than anticipated. The parent company’s non-contingent contractual obligations are set forth below: Non-contingent contractual obligation Less than 1 year 1 to 3 years Over 3 years Total Payment due by period Indebtedness (excluding interest) . . . . . . . . . . . . . Trust preferred securities (excluding dividends) . . . Construction commitments . . . . . . . . . . . . . . . . . Other equity commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total $488 million — $156 million $ .5 million $645 million $845 million $ 4.1 billion — $978 million $ 7 million $ 1.5 million $ 5.1 billion $ 41 million $ 1 million $887 million $ 5.4 billion $978 million $204 million $ 3 million $ 6.6 billion The parent company’s contingent contractual obligations are set forth below (in millions, except for number of agreements): Contingent contractual obligations Number of Amount Agreements Exposure Range for Each Agreement Guarantees . . . . . . . . . . . . . . . . . . . . . . . . . . . . $775 Letters of credit – under the Revolver . . . . . . . . $285 Letters of credit – outside the Revolver . . . . . . . $168 Surety bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 76 68 24 12 15 <$1–$100 <$1–$104 <$1–$107 <$1–$42 On Balance Off Balance Sheet $249 $155 $107 — Sheet $526 $130 $ 61 $ 76 The Company has a varied portfolio of performance related contingent contractual obligations. Amounts related to the balance sheet items represent credit enhancements made by AES the parent company and other third parties for the benefit of the lenders associated with the non-recourse debt recorded as liabilities in the accompanying consolidated balance sheets. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, supplier support and liquidated damages under power purchase agreements for projects in development, under construction and operating. While AES does not expect to be required to fund any material amounts under these contingent contractual obligations during 2002, many of the events which would give rise to such an obligation are beyond AES’s control. There can be no assurance that it would have adequate sources of liquidity to fund its obligations under these contingent contractual obligations if it were required to make substantial payments thereunder. Interim needs for shorter-term and working capital financing at the parent company have been met with borrowings under AES’s revolving credit facility (the ‘‘Revolver’’). The Company currently maintains an $850 million credit line under the Revolver. The Revolver and other borrowings contain certain restrictive covenants. The covenants provide for, among other items, maintenance of certain reserves, and require that minimum levels of working capital, net worth, and certain financial ratio tests are met. The most restrictive of these covenants include limitations on incurring additional debt and on the payment of dividends to stockholders. At December 31, 2001, cash borrowings and letters of credit outstanding under the Revolver amounted to $70 million and $285 million, respectively. Letters of credit outstanding outside the Revolver amounted to $168 million. The Company may also seek, from time to time, to meet some of its short-term and interim funding needs with additional commitments from banks and other financial institutions at the parent or subsidiary level. The Company has secured equity-linked loans (‘‘SELLS’’) of $350 million due in 2003 and $300 million due in 2004. The Company is required to maintain as collateral 2.25 times the amount of the SELLS in the form of unregistered shares. Registration of the shares can only occur in the event of 56 nonpayment or failure to maintain adequate collateral levels. As of December 31, 2001 and 2000, approximately 111 million and 81 million shares of the Company’s common stock, respectively, had been issued to the consolidated subsidiaries. These shares are not considered outstanding and therefore have been excluded from the calculation of earnings per share. FINANCIAL POSITION AND CASH FLOWS Consolidated cash flows At December 31, 2001, AES had a consolidated net working capital deficit of ($388) million as compared to positive working capital of $745 million at the end of 2000. Cash and short-term investments were $1.4 billion at December 31, 2001. Included in the net working capital is approximately $2.7 billion from the current portion of long-term debt. The Company intends to repay approximately $1.0 billion of the current debt during 2002, which includes $488 million of recourse debt, and the remainder is expected to be refinanced. There can be no guarantee that these refinancings will have terms as favorable as those currently in existence. There are some subsidiaries that issue short-term debt and commercial paper in the normal course of business and continually refinance these obligations. The decrease in net working capital was due primarily to an increase in the current portion of debt and a decline in short-term investments. Short-term investments decreased due to the payment in 2001 of $848 million for the Gener acquisition that was classified as short-term investments at December 31, 2000. Property, plant and equipment, net of accumulated depreciation, accounts for 64% of the Company’s total assets and was $23.4 billion at December 31, 2001. Net property, plant and equipment increased $4.2 billion, or 22%, during 2001. The increase was due primarily to construction activities at the Company’s greenfield projects. Acquisitions of new businesses contributed to a lesser extent. In total, the Company’s consolidated debt increased $3.6 billion, or 20%, to $22.3 billion at December 31, 2001. The increase is due primarily to borrowings used to fund the construction of the Company’s greenfield projects and borrowings used to refinance the redeemable preferred trust, commonly called RHINOS. Borrowings used to fund acquisitions contributed to a lesser extent. At December 31, 2001, the Company had $922 million of cash and cash equivalents. Cash and cash equivalents decreased $28 million. The $1.7 billion provided by operating activities and the $1.6 billion of cash raised by financing activities was used to fund the $3.3 billion of investing activities. Cash flows provided by operating activities totaled $1.7 billion during 2001. The increase in cash provided by operating activities during 2001 is due to the collection of the Thames contract prepayment and enhanced collections of accounts receivable at Los Mina, Ekibastuz, Altai and Telasi. Net cash used in investing activities totaled $3.3 billion during 2001. The cash used in investing activities includes $1.4 billion for acquisitions and $3.2 billion for property additions, primarily new greenfield construction efforts. Net cash provided by financing activities was $1.6 billion during 2001. The cash provided by financing activities includes $1.7 billion provided by net borrowings. Parent operating cash flow The following discussion of ‘‘parent operating cash flow’’, formerly described by AES as ‘‘parent EBITDA’’, has been included because AES believes it is a useful measure of the cash flow available to the parent company to meet its liquidity needs. Parent operating cash flow is not a measure under generally accepted accounting principles (‘‘GAAP’’) and should not be construed as an alternative to net income or cash flows from operating activities, which are determined in accordance with GAAP, as an indicator of operating performance or as a measure of liquidity. Parent operating cash flow may differ from that, or similarly titled measures, used by other companies. 57 Parent operating cash flow includes the following amounts received in cash by the parent and qualifying holding companies from operating subsidiaries and affiliates less parent operating expenses: • Dividends • Consulting and management fees • Tax sharing payments • Interest and other distributions paid during the period with respect to cash and other temporary cash investments less parent operating expenses. Parent operating cash flow does not include the following additional cash payments made to the parent company by its subsidiaries and affiliates: • Returns of invested capital • Repayments of debt principal • Payments released from debt service reserve accounts upon the issuance of letters of credit for the benefit of subsidiaries or affiliates. Parent interest charges include all interest payments incurred by the parent, whether or not they are expensed or capitalized. Such charges exclude the distributions on convertible trust preferred securities. Parent operating cash flows for 2001 amounted to approximately $1.2 billion. This compares to $871 million for 2000. Cash payments for parent interest charges, as defined, rose to $391 million in 2001 from $216 million in 2000. Resultant parent interest coverage ratios for the same periods were 2.97x and 4.03x, respectively. The 2001 increase of approximately $292 million in parent operating cash flows was a 33% increase from 2000. The increase was driven primarily by the contributions from new businesses added through both acquisitions and newly operational greenfield projects. This included increased contributions from IPALCO; Eastern Energy, our coal-fired base load plants in New York; and Gener, purchased at the beginning of 2001. These increases were offset in part by reduced cash flows from some of our existing businesses, primarily decreases in contributions from Brazil, caused by rationing. Approximately 72% of 2001 parent operating cash flows were from investment grade countries compared with approximately 56% in 2000 and 80% in 1999. The reconciliation between parent operating cash flow and the net cash provided by operating activities on the unconsolidated cash flows included in Schedule I is presented below (in millions). Parent operating cash flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: $1,163 Cash held at qualifying holding companies . . . . . . . . . . . . . . . . . . . . . . . (125) Net cash provided by operating cash flows . . . . . . . . . . . . . . . . . . . . . . . $1,038 The cash held at qualifying holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries had no contractual restrictions on their ability to send cash to AES, the parent company. Cash at those subsidiaries was used for investment and related activities outside of the U.S. These investments included equity investments and loans to other foreign subsidiaries as well as development and general costs and expenses incurred outside the U.S. 58 At year end we had approximately $70 million of cash, $496 million of availability under our $850 million revolver, and approximately $900 million of additional debt capacity at the parent company under the revolver loan covenants. ITEM 7a— QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market Risks AES is exposed to market risks associated with interest rates, foreign exchange rates and commodity prices. AES often utilizes financial instruments and other contracts to hedge against such fluctuations. AES also utilizes financial and commodity derivatives for the purpose of hedging exposures to market risk. AES generally does not enter into derivative instruments for trading or speculative purposes. Interest Rate Risk. AES is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt, fixed-rate debt and trust preferred securities, as well as interest rate swap and option agreements. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, AES partially hedges against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, AES executes interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Foreign Exchange Rate Risk. AES is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of our foreign subsidiaries and affiliates utilize currencies other than AES’s consolidated reporting currency, the U.S. Dollar. Additionally, certain of AES’s foreign subsidiaries and affiliates have entered into monetary obligations in U.S. Dollars or currencies other than their own functional currencies. Primarily, AES is exposed to changes in the U.S. Dollar/United Kingdom Pound Sterling exchange rate, the U.S. Dollar/Brazilian Real exchange rate, the U.S. Dollar/Venezuelan Bolivar exchange rate and the U.S. Dollar/Argentine Peso exchange rate. Whenever possible, these subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. AES also uses foreign currency forward and swap agreements, where possible, to manage our risk related to certain foreign currency fluctuations. Commodity Price Risk. AES is exposed to the impact of market fluctuations in the price of electricity, natural gas and coal. Although AES primarily consists of businesses with long-term contracts or retail sales concessions, a portion of AES’s current and expected future revenues are derived from businesses without significant long-term revenue or supply contracts. These competitive supply businesses subject our results of operations to the volatility of electricity and natural gas prices in competitive markets. AES’s businesses hedge certain aspects of their ‘‘net open’’ positions in the U.S. We have used a hedging strategy, where appropriate, to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy involves the use of commodity forward contracts, futures, swaps and options as well as long-term supply contracts for the supply of fuel and electricity. Value at Risk. In 2000, AES adopted a value at risk (‘‘VaR’’) approach to assess and manage risk across the Company and its subsidiaries. VaR measures the potential loss in a portfolio’s value due to market volatility, over a specified time horizon, stated with a specific degree of probability. The quantification of market risk using VaR provides a consistent measure of risk across diverse markets and instruments. The VaR approach was adopted because the Company feels that statistical models of risk measurement, such as VaR, provide an objective, independent assessment of risk exposure to the Company. The use of VaR requires a number of key assumptions, including the selection of a confidence level for expected losses, the holding period for liquidation and the treatment of risks 59 outside the VaR methodology, including liquidity risk and event risk. VaR, therefore, is not necessarily indicative of actual results that may occur. The use of VaR allows AES to aggregate risks across all AES businesses, compare risk on a consistent basis and identify the drivers of risk. Because of the inherent limitations of VaR, including those specific to the variance/covariance approach, specifically the assumption that values or returns are normally distributed, AES relies on VaR as only one component in its risk assessment process. In addition to using VaR measures, AES performs stress and scenario analyses to estimate the economic impact of market changes on the value of our portfolios. These results are used to supplement the VaR methodology. AES has performed a company-wide VaR analysis of all of its material financial assets, liabilities and derivative instruments. The VaR calculation incorporates numerous variables that could impact the fair value of AES’s instruments, including interest rates, foreign exchange rates and commodity prices, as well as correlation within and across these variables. AES performs its VaR calculation using a model based on J.P. Morgan’s RiskMetrics approach, which utilizes the variance/covariance method. We express VaR as a dollar amount of the potential loss in the fair value of our portfolio based on a 95% confidence level and a one-day holding period. During the year ended December 31, 2001, our average daily VaR for interest rate-sensitive instruments was $73.1 million. The daily VaR for interest rate-sensitive instruments was highest at year- end, and equaled $97.5 million. The daily VaR for interest rate-sensitive instruments was lowest at the end of the first quarter, and equaled $59.8 million. The daily VaR for interest rate-sensitive instruments as of December 31, 2000 was $40.3 million. These amounts include the financial instruments that serve as hedges and the underlying hedged items. VaR for interest rate-sensitive instruments increased in 2001 as compared with 2000 due to higher interest rate volatilities, caused by decreases in interest rates and uncertainty surrounding the U.S. economy, and an increase in our fixed-rate debt portfolio due to the addition of new businesses. During the year ended December 31, 2001, our average daily VaR for foreign exchange rate-sensitive instruments was $3.4 million. The daily VaR for foreign exchange rate- sensitive instruments was highest at the end of the third quarter, and equaled $6.0 million. The daily VaR for foreign exchange rate-sensitive instruments was lowest at the end of the first quarter, and equaled $0.7 million. The daily VaR for foreign exchange rate-sensitive instruments as of December 31, 2000 was $4.9 million. These amounts include the financial instruments that serve as hedges and the underlying hedged items. During the year ended December 31, 2001, our average daily VaR for commodity price-sensitive instruments was $6.2 million. The daily VaR for commodity price-sensitive instruments was highest at the end of the second quarter, and equaled $7.1 million. The daily VaR for commodity price-sensitive instruments was lowest at year-end, and equaled $5.5 million. The daily VaR for commodity price-sensitive instruments as of December 31, 2000 was $5.5 million. These amounts include the financial instruments that serve as hedges and do not include the underlying physical assets. 60 ITEM 8—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. INDEPENDENT AUDITORS’ REPORT To the Stockholders of The AES Corporation: We have audited the accompanying consolidated balance sheets of The AES Corporation and subsidiaries (the Company) as of December 31, 2001 and 2000, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included the financial statement schedules listed in the index on page S-1. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits. The consolidated financial statements and financial statement schedules give retroactive effect to the merger of The AES Corporation and IPALCO Enterprises, Inc., which has been accounted for as a pooling of interests as described in Note 2 to the consolidated financial statements. We did not audit the financial statements of C.A. La Electricidad de Caracas and Corporation EDC, C.A. and their subsidiaries (‘‘EDC’’), a majority-owned subsidiary, which statements reflect total assets constituting 9% and 10% of consolidated total assets as of December 31, 2001 and 2000, total revenues constituting 9% and 7% of consolidated total revenues and total income from continuing operations constituting 47% and 14% of consolidated income from continuing operations for 2001 and 2000. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for EDC, is based solely on the report of such other auditors. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits, and the report of the other auditors, provide a reasonable basis for our opinion. In our opinion, based on our audits and the report of the other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of The AES Corporation and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, based on our audits and the report of other auditors, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. As discussed in Note 3 to the financial statements, the Company changed its method of accounting for the impairment or disposal of long-lived assets effective January 1, 2001 to conform with Statement of Financial Accounting Standards No. 144. Also, as discussed in Note 7 to the financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001 to conform with Statement of Financial Accounting Standards No. 133. Deloitte & Touche LLP McLean, VA February 5, 2002 (February 6, 2002 as to paragraph 9 of Note 4, and March 21, 2002 as to paragraph 7 of Note 6) 61 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and the Board of Directors of C.A. La Electricidad de Caracas and Corporaci´on EDC, C.A.: We have audited the accompanying combined balance sheets of C.A. La Electricidad de Caracas and Corporaci´on EDC, C.A. and their Subsidiaries (Venezuelan corporations), translated into U.S. dollars, as of December 31, 2001 and 2000, and the related translated combined statements of income, stockholders’ investment and cash flows for the year ended December 31, 2001 and for the period from June 1 through December 31, 2000. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. These translated combined financial statements have been prepared for use in the preparation of the consolidated financial statements of AES Corporation and, accordingly, they translate the assets, liabilities, stockholders’ investment, revenues and expenses of C.A. La Electricidad de Caracas and Corporaci´on EDC, C.A. and their Subsidiaries for that purpose. The translated combined financial statements have not been prepared for use by other parties and may not be appropriate for such use. In our opinion, the translated financial statements referred to above present fairly, in all material respects and for the purpose described in the preceding paragraph, the financial position of C.A. La Electricidad de Caracas and Corporaci´on EDC, C.A. and their Subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the year ended December 31, 2001 and for the period from June 1 through December 31, 2000, in conformity with accounting principles generally accepted in the United States. Porta, Cachafeiro, Lar´ıa Y Asociados A Member Firm of Andersen Hector L. Gutierrez D. Public Accountant CPC NL 24,321 Caracas, Venezuela January 18, 2002 (except with respect to the matter discussed in Note 18, as to which the dates are February 20, 2002) 62 THE AES CORPORATION CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2001 AND 2000 2001 2000 (Amounts in Millions, Except Shares and Par Value) ASSETS Current Assets: Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Short-term investments-including restricted cash of $357-2001; $1,189-2000 . . . . . . . . . . . . . . . . Accounts receivable – net of reserves of $251-2001; $203 -2000 . . . . . . . . . . . . . . . . . . . . . . . . Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Receivable from affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current assets of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, Plant and Equipment: Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Electric generation and distribution assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Construction in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant, and equipment – net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Assets: Deferred financing costs – net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Project development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Investments in and advances to affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Debt service reserves and other deposits Goodwill – net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term assets of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets Total other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 922 588 1,588 626 10 260 607 52 4,653 599 21,406 (3,314) 4,743 23,434 482 68 3,100 474 3,208 249 1,068 8,649 $ 950 1,297 1,539 569 27 167 1,193 42 5,784 656 18,357 (2,632) 2,861 19,242 381 67 3,122 509 2,181 457 1,295 8,012 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $36,736 $33,038 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities: Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued and other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current liabilities of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Recourse debt – current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-recourse debt – current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-Term Liabilities: Non-recourse debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Recourse debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term liabilities of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Minority Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Commitments and Contingencies (Note 8) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Company-Obligated Convertible Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of AES . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stockholders’ Equity: Preferred stock, no par value – 50 million shares authorized; none issued . . . . . . . . . . . . . . . . . Common stock, $.01 par value – 1, 200 million shares authorized for 2001 and 2000, 645 million issued and 533 million outstanding in 2001, 603 million issued and 522 million outstanding in 2000 Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Treasury Stock, at cost: 2000 -13 million shares Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 819 283 1,185 82 488 2,184 5,041 14,673 4,913 1,904 154 2,004 23,648 1,530 — 978 — 5 5,225 2,809 (2,500) — 5,539 $ 743 409 1,293 132 — 2,462 5,039 12,696 3,458 1,863 184 1,586 19,787 1,442 — 1,228 — 5 5,172 2,551 (1,679) (507) 5,542 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $36,736 $33,038 See notes to consolidated financial statements. 63 THE AES CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, General and Administrative Expenses . . . . . . Severance and Transaction Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest Expense, net Other Income, net . . . . . . . . . . . . . . . . . . . . . . . . . Gain on Sale of Assets . . . . . . . . . . . . . . . . . . . . . . Gain on Sale of Available for Sale Securities . . . . . . Impairment Loss . . . . . . . . . . . . . . . . . . . . . . . . . . Environmental Fine . . . . . . . . . . . . . . . . . . . . . . . . Equity in Pre-tax Earnings of Affiliates . . . . . . . . . . INCOME BEFORE INCOME TAXES AND MINORITY INTEREST . . . . . . . . . . . . . . . . . . . Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Minority Interest INCOME FROM CONTINUING OPERATIONS . . Loss from operations of discontinued businesses (net of income taxes of $35, $11 and $1, respectively) . . INCOME BEFORE EXTRAORDINARY ITEMS . . Extraordinary Items – early extinguishment of debt – net of applicable income tax . . . . . . . . . . . . . . . . . 2001 2000 1999 (Amounts in Millions, Except Shares and Par Value) $ 4,117 $ 7,534 $ 9,327 (2,854) (5,539) (7,025) (71) (82) (120) — (79) (131) (632) (1,138) (1,465) 15 31 23 91 31 — — 112 18 (62) — — — (17) — 29 475 175 802 230 105 467 (194) 273 — 1,328 377 124 827 (21) 806 (11) 633 191 65 377 (3) 374 (17) NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 273 $ 795 $ 357 BASIC EARNINGS PER SHARE: Income from continuing operations . . . . . . . . . . . . . Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extraordinary items BASIC EARNINGS PER SHARE . . . . . . . . . . . . . DILUTED EARNINGS PER SHARE: Income from continuing operations . . . . . . . . . . . . . Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extraordinary items DILUTED EARNINGS PER SHARE . . . . . . . . . . $ 0.88 (0.36) — $ 0.52 $ 0.87 (0.36) — $ 0.51 $ 1.72 (0.04) (0.02) $ 1.66 $ 1.65 (0.04) (0.02) $ 1.59 $ 0.89 (0.01) (0.04) $ 0.84 $ 0.87 (0.01) (0.04) $ 0.82 See notes to consolidated financial statements. 64 THE AES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 OPERATING ACTIVITIES: Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjustments to net income: Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gain from sale of available-for-sale securities Gain from sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Impairment loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Provision for deferred taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Minority interest earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Undistributed earnings of affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Changes in operating assets and liabilities: Decrease (increase) in accounts and contract receivables . . . . . . . . . . . . . . . . . . . . Increase in inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Increase in other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Decrease (increase) in other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Decrease) increase in accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Decrease) increase in accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Decrease in accrued and other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Increase (decrease) in other liabilities 859 (18) — — 229 47 105 (140) (69) 712 (10) (34) 295 (125) (148) (368) 83 Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,691 INVESTING ACTIVITIES: Property additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisitions-net of cash acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from the sales of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sale of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Purchase of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Affiliate advances and equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Decrease (increase) in restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Project development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Debt service reserves and other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FINANCING ACTIVITIES: (Repayments) borrowings under the revolver, net . . . . . . . . . . . . . . . . . . . . . . . . . . Issuance of non-recourse debt and other coupon bearing securities . . . . . . . . . . . . . . . Repayments of non-recourse debt and other coupon bearing securities . . . . . . . . . . . . Payments for deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Distributions to) contributions by minority interests, net . . . . . . . . . . . . . . . . . . . . . Issuance of common stock, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Common stock dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of exchange rate changes on cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS . . . . . . . . . . . . . . CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR . . . . . . . . . . . . . . . . . . (3,173) (1,365) 564 670 (649) (133) 832 (105) 45 (3,314) (70) 5,935 (4,015) (153) (70) 14 (15) 1,626 (31) (28) 950 2001 2000 1999 (Amounts in Millions) $ 273 $ 795 $ 357 697 (112) (31) — 32 (2) 124 (320) (61) (270) (56) (156) (132) 257 126 (225) (160) 506 (2,226) (1,818) 234 195 (96) (515) (1,110) (96) (101) (5,533) (195) 7,081 (2,831) (136) (54) 1,508 (55) 5,318 (34) 257 693 950 388 — (91) 62 4 12 64 30 72 (154) (45) (87) (31) (61) 85 (184) (41) 380 (938) (5,713) 650 49 (98) (193) (80) (84) (94) (6,501) 102 6,427 (1,289) (119) 32 1,226 (51) 6,328 (15) 192 501 693 608 112 $ $ CASH AND CASH EQUIVALENTS, END OF YEAR . . . . . . . . . . . . . . . . . . . . . . $ 922 $ SUPPLEMENTAL DISCLOSURES: Cash payments for interest-net of amounts capitalized . . . . . . . . . . . . . . . . . . . . . . . Cash payments for income taxes-net of refunds . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,846 254 $ 1,191 216 SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES: Common stock issued for acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities assumed in purchase transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conversion of AES Trust I and AES Trust II (see Note 9) . . . . . . . . . . . . . . . . . . . . 511 1,362 — 67 2,098 550 48 3,570 — See notes to consolidated financial statements. 65 THE AES CORPORATION CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 Common Stock Shares Amount Additional Paid-In Capital Accumulated Other Retained Comprehensive Treasury Comprehensive Income (Loss) Earnings Stock Loss $ 357 (759) 107 $(295) $ 795 (575) (107) (2) $ 111 Balance at January 1, 1999 . . . . . . . . . 402.0 $4 $1,671 (Amounts in Millions) $ (343) $1,505 $(469) Net income . . . . . . . . . . . . . . . . . . . Foreign currency translation adjustment Unrealized gains on marketable — — — — securities . . . . . . . . . . . . . . . . . . . — — Comprehensive loss . . . . . . . . . . . . . . Dividends declared . . . . . . . . . . . . . . Issuance of common stock through — — — — — — public offerings . . . . . . . . . . . . . . . 48.0 — 1,280 Issuance of common stock pursuant to acquisitions . . . . . . . . . . . . . . . . . . Purchase of treasury stock . . . . . . . . . Issuance of common stock under benefit plans and exercise of stock options and warrants . . . . . . . . . . . Tax benefit associated with the exercise of options . . . . . . . . . . . . . . . . . . . 1.8 — (1.6) — 3.2 — — — 48 — 30 23 357 — — (51) — — — — — Balance at December 31, 1999 . . . . . . 453.4 4 3,052 1,811 Net income . . . . . . . . . . . . . . . . . . . Foreign currency translation adjustment Realized gains on marketable securities Minimum pension liability adjustment . Comprehensive income . . . . . . . . . . . Dividends declared . . . . . . . . . . . . . . Issuance of common stock through public offerings and Tecon conversions . . . . . . . . . . . . . . . . . . Issuance of common stock pursuant to — — — — — — — — — — — — — — 59.2 1 1,946 acquisitions . . . . . . . . . . . . . . . . . . 1.3 — Issuance of common stock under benefit plans and exercise of stock options and warrants . . . . . . . . . . . Tax benefit associated with the exercise of options . . . . . . . . . . . . . . . . . . . 7.8 — — — 67 50 57 795 — — — (55) — — — — — (759) 107 — — — — — — (995) — (575) (107) (2) — — — — — — — — — — — (88) — — (557) — — — — — — — 50 — Balance at December 31, 2000 . . . . . . 521.7 $5 $5,172 $2,551 $(1,679) $(507) See notes to consolidated financial statements. 66 CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 Common Stock Shares Amount Additional Paid-In Capital Accumulated Other Retained Comprehensive Treasury Comprehensive Income (Loss) Earnings Stock Loss Balance at December 31, 2000 . . . . 521.7 Cumulative effect of adopting SFAS $5 $5,172 (Amounts in Millions) $(1,679) $2,551 $(507) No. 133 on January 1, 2001 . . . . — — Net income . . . . . . . . . . . . . . . . . . — — Foreign currency translation adjustment . . . . . . . . . . . . . . . . . — — Unrealized losses on marketable securities . . . . . . . . . . . . . . . . . . — — Minimum pension liability adjustment . . . . . . . . . . . . . . . . . — — Change in derivative fair value . . . . — — Comprehensive loss . . . . . . . . . . . . Dividends declared . . . . . . . . . . . . — — Issuance of common stock pursuant to acquisitions . . . . . . . . . . . . . . 9.4 — Retirement of treasury stock . . . . . — — Issuance of common stock under benefit plans and exercise of stock options and warrants . . . . . 2.1 — Tax benefit associated with the exercise of options . . . . . . . . . . . — $ (93) 273 (636) (48) (16) (28) $(548) — — — — — — — 511 (507) 34 15 — 273 — — — — (15) — — — — (93) — (636) (48) (16) (28) — — — — — — — — — — — — 507 — — Balance at December 31, 2001 . . . . 533.2 $5 $5,225 $2,809 $(2,500) $ — See notes to consolidated financial statements. 67 THE AES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2001, 2000 AND 1999 1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The AES Corporation and its subsidiaries and affiliates, (collectively ‘‘AES’’ or ‘‘the Company’’) is a global power company primarily engaged in owning and operating electric power generation and distribution businesses in many countries around the world. The consolidated financial statements have been prepared to give retroactive effect to the merger with IPALCO Enterprises, Inc. (‘‘IPALCO’’), which has been accounted for as a pooling of interests as more fully discussed in Note 2. PRINCIPLES OF CONSOLIDATION—The consolidated financial statements of the Company include the accounts of The AES Corporation, its subsidiaries, and controlled affiliates. Investments, in which the Company has the ability to exercise significant influence but not control, are accounted for using the equity method. Intercompany transactions and balances have been eliminated. A loss in value of an equity method investment which is other than a temporary decline is recognized in earnings as an impairment. CASH AND CASH EQUIVALENTS—The Company considers unrestricted cash on hand, deposits in banks, certificates of deposit, and short-term marketable securities with an original maturity of three months or less to be cash and cash equivalents. INVESTMENTS—Securities that the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at historical cost. Other investments that the Company does not intend to hold to maturity are classified as available-for-sale or trading. Unrealized gains or losses on available-for-sale investments are recorded as a separate component of stockholders’ equity. Investments classified as trading are marked to market on a periodic basis through the statement of operations. Interest and dividends on investments are reported in interest income. Gains and losses on sales of investments are recorded using the specific identification method. Short-term investments consist of investments with original maturities in excess of three months but less than one year. Short-term investments also includes restricted cash. Debt service reserves and other deposits, which might otherwise be considered cash and cash equivalents, are treated as non-current assets (see Note 5). INVENTORY—Inventory, valued at the lower of cost or market (first in, first out method) consists of the following (in millions): December 31, 2001 2000 Coal, fuel oil, and other raw materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Spare parts and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $334 292 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $626 $298 271 $569 PROPERTY, PLANT, AND EQUIPMENT—Property, plant, and equipment is stated at cost. The cost of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. Depreciation, after consideration of salvage value, is computed using the straight-line method over the estimated composite useful lives of the assets. Depreciation expense stated as a percentage of average cost of depreciable property, plant and equipment was, on a composite basis, 3.57%, 3.68% and 3.73% for the years ended December 31, 2001, 2000 and 1999, respectively. 68 The components of our electric generation and distribution assets and the related rates of depreciation are as follows: Composite Rate Useful Life Generation and Distribution Facilities . . . . . . . . . . . . . . . . . . . . . . . . . Other Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Leasehold Improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Furniture and Fixtures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0% – 10.0% 10 – 50 yrs. 2.5% – 5.0% 20 – 40 yrs. 3.3% – 10.0% 10 – 30 yrs. 2 – 7 yrs. 14.3% – 50.0% Maintenance and repairs are charged to expense as incurred. Emergency and rotable spare parts inventories are included in electric generation and distribution assets and are depreciated over the useful life of the related components. CONSTRUCTION IN PROGRESS—Construction progress payments, engineering costs, insurance costs, salaries, interest, and other costs relating to construction in progress are capitalized during the construction period. Construction in progress balances are transferred to electric generation and distribution assets when each asset is ready for its intended use. Interest capitalized during development and construction totaled $295 million, $225 million, and $105 million in 2001, 2000, and 1999, respectively. GOODWILL—Goodwill is amortized on a straight-line basis over the estimated benefit period, which ranges from 10 to 40 years. Goodwill at December 31, 2001 and 2000 is shown net of accumulated amortization of $190 million and $128 million, respectively. The Company evaluates the impairment of goodwill whenever events or changes in circumstances indicate that the carrying amount may not be recoverable using the projection of undiscounted cash flows. In the event such cash flows are not expected to be sufficient to recover the recorded value of goodwill, the goodwill will be written down to the estimated fair value based on discounted cash flow analysis. LONG-LIVED ASSETS—In accordance with Statement of Financial Accounting Standards (‘‘SFAS’’) No. 144, ‘‘Accounting for the Impairment or Disposal of Long-lived Assets,’’ the Company evaluates the impairment of long-lived assets based on the projection of undiscounted cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values (see Note 3) based on discounted cash flow analysis. DEFERRED FINANCING COSTS—Financing costs are deferred and amortized over the related financing period using the effective interest method or the straight-line method when it does not differ materially from the effective interest method. Deferred financing costs are shown net of accumulated amortization of $154 million and $105 million as of December 31, 2001 and 2000, respectively. PROJECT DEVELOPMENT COSTS—The Company capitalizes the costs of developing new construction projects after achieving certain project-related milestones that indicate that the project is probable of completion. These costs represent amounts incurred for professional services, permits, options, capitalized interest, and other costs directly related to construction. These costs are transferred to construction in progress when significant construction activity commences, or expensed at the time the Company determines that development of a particular project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, siting, financing, construction, permitting, and contract compliance. INCOME TAXES—The Company follows SFAS No. 109, ‘‘Accounting for Income Taxes.’’ Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. 69 FOREIGN CURRENCY TRANSLATION—A business’s functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is other than the U.S. Dollar translate their assets and liabilities into U.S. Dollars at the current exchange rates in effect at the end of the fiscal period. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. Dollars at the average exchange rates that prevailed during the period. The gains or losses that result from this process, and gains and losses on intercompany foreign currency transactions which are long-term in nature, and which the Company does not intend to settle in the foreseeable future, are shown in accumulated other comprehensive loss in the stockholders’ equity section of the balance sheet. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency are included in determining net income. For subsidiaries operating in highly inflationary economies, the U.S. Dollar is considered to be the functional currency, and transaction gains and losses are included in determining net income. During 2001, the Brazilian Real experienced a significant devaluation relative to the U.S. Dollar, declining from 1.96 Reais to the U.S. Dollar at December 31, 2000 to 2.41 Reais at December 31, 2001. Also, during 1999, the Brazilian Real experienced a significant devaluation relative to the U.S. Dollar declining from 1.21 Reais to the U.S. Dollar at December 31, 1998 to 1.81 Reais to the Dollar at December 31, 1999. This continued devaluation resulted in significant foreign currency translation and transaction losses particularly during 2001 and 1999. The Company recorded $210 million, $64 million and $203 million before income taxes of non-cash foreign currency transaction losses on U.S. dollar denominated debt from its investments in Brazilian equity-method affiliates during 2001, 2000 and 1999, respectively. These amounts are recorded in equity in pre-tax earnings of affiliates in the accompanying consolidated statements of operations. The cash flow impacts of these losses will be realized when the principal balance of the related debt is paid or subsequent refinancings of such principal are paid. During 2001, Argentina began experiencing a significant political, social and economic crisis that has resulted in significant changes in general economic policies and regulations as well as specific changes in the energy sector. In January and February 2002, many new economic measures have been adopted by the Argentine government, including abandoning the country’s fixed dollar-to-peso exchange rate, converting dollar denominated loans into pesos and placing restrictions on the convertibility of the Argentine peso. The government has also adopted new regulations in the energy sector that have the effect of repealing U.S. dollar denominated pricing under electricity tariffs as prescribed in existing electricity distribution concessions in Argentina by fixing all prices to consumers in pesos until June 30, 2002. In response to the changes, the Company recorded foreign currency transaction losses in 2001 of approximately $31 million using an exchange rate of 1.65 Argentine Pesos to U.S. Dollar based on the exchange rate upon reopening of the local currency markets in mid-January 2002. These losses are recorded in other income, net in the accompanying consolidated statements of operations. In combination these circumstances create significant uncertainty surrounding the performance, cash flow and potential for profitability of the electricity industry in Argentina, including the Argentine subsidiaries of AES. REVENUE RECOGNITION AND CONCENTRATION—Revenues from the sale of electricity and steam generation are recorded based upon output delivered and capacity provided at rates as specified under contract terms or prevailing market rates. Electricity distribution revenues are recognized when power is provided. Revenues from power sales contracts entered into after 1991 with decreasing scheduled rates are recognized based on the output delivered at the lower of the amount billed or the average rate over the contract term. Several of the Company’s power plants rely primarily on one power sales contract with a single customer for the majority of revenues (see Note 8). No single customer accounted for 10% or more of revenues in 2001, 2000 or 1999. The prolonged failure of any 70 of the Company’s customers to fulfill contractual obligations or make required payments could have a substantial negative impact on AES’s revenues and profits. REGULATION—The Company has investments in growth distribution and large utilities businesses located in the United States and certain foreign countries that are subject to regulation by the applicable regulatory authority. Our distribution businesses generally operate in markets that are subject to electricity price regulation as compared with regulation based solely on the cost of the electricity or the allowed rate of return on a specific distribution company’s assets or net assets. For the regulated portion of these businesses, the Company capitalizes incurred costs as deferred regulatory assets when there is a probable expectation that future revenue equal to the costs incurred will be billed and collected as a direct result of the inclusion of the costs in an increased tariff set by the regulator or as permitted under the electricity sales concession for that business. The deferred regulatory asset is eliminated when the Company collects the related costs through billings to customers. Regulators in the respective jurisdictions typically perform a tariff review for the distribution companies on an annual basis. If a regulator excludes all or part of a cost from recovery, that portion of the deferred regulatory asset is impaired and is accordingly reduced to the extent of the excluded cost. The Company has recorded deferred regulatory assets of $390 million and $401 million at December 31, 2001, and 2000, respectively, that it expects to pass through to its customers in accordance with and subject to regulatory provisions. The regulatory assets include $134 million and $110 million at December 31, 2001, and 2000, respectively, which are AES’s share of regulatory assets recorded by the Company’s equity method affiliates in Brazil, which are included in the investments and advances to affiliates balance on the accompanying consolidated balance sheets. The deferred regulatory assets at entities, which are controlled and consolidated by the Company, are recorded in other assets on the consolidated balance sheets. During 2001, the electricity markets in significant portions of Brazil experienced rationing, or reduced availability of electricity to customers, due to low rainfall, reduced reservoir levels and that country’s significant dependence on electricity generated from hydrological resources. These factors resulted in higher costs and lower sales for AES’s Brazilian subsidiaries and equity affiliates. In December 2001, the Company’s Brazilian subsidiaries and equity affiliates reached an industry-wide agreement (the ‘‘agreement’’) with the Brazilian government that provided resolution to all rationing related issues as well as to certain other electricity tariff related issues. There were three parts to the agreement. First, Annex V, a provision in the initial contracts between the generators and the distributors that was designed to protect the distribution companies from reduced sales volumes and to limit the financial burden of generation companies during periods of rationing, was replaced with a tariff increase for end-use consumers that would compensate both generators and distributors for rationing related losses. The net ownership-adjusted impact to AES from the elimination of Annex V and the resulting tariff increase represented additional income before income taxes of $60 million. However, the amount recorded under the new methodology at December 31, 2001 was substantially the same as the contractual receivable previously recorded under the provisions of Annex V. Accordingly, the only impact of this portion of the agreement was the balance sheet reclassification of the receivable to a regulatory asset. The tariff increase will remain in effect until all recoverable amounts are collected which the Company estimates will take approximately three years. The agreement also establishes that BNDES, the National Development Bank of Brazil, will fund 90% of the amounts recoverable under the tariff increase up front through loans prior to their recovery through tariffs. The loans are repayable over the tariff increase collection period. The second part of the agreement relates to the Parcel A costs which are certain costs that each distribution company is permitted to defer and pass through to its customers via a future tariff adjustment. Parcel A costs are limited by the concession contracts to the cost of purchased power and certain other costs and taxes. The Brazilian regulator had granted tariff increases to recover a portion of previously deferred Parcel A costs. However, due to uncertainty surrounding the Brazilian economy, 71 the regulator had delayed approval of some Parcel A tariff increases. As part of the agreement, a tracking account that was previously established was officially defined. Parcel A costs incurred previous to January 1, 2001 were not allowed under the definition of the tracking account. As a result, the Company wrote-off approximately $160 million ($101 million representing the Company’s portion from equity affiliates), of Parcel A costs incurred prior to 2001 that will not be recovered. The third part of the agreement relates to the sales price that Sul, the Company’s distribution subsidiary in Porto Alegre, would receive for its sales of excess energy. As a result of the agreement, Sul, recorded approximately $100 million of additional revenue and a corresponding receivable from the spot market in the fourth quarter. Sul had elected early in 2001, as permitted under its concession contract, to expose itself to gains or losses based on the difference between the market price of energy in the South where they normally sell electricity and the Southeast where they take delivery. Drought conditions in the Southeast, even with rationing, created a large imbalance between prices in the Southeast and the South resulting in a substantial gain. Sul had not recorded the revenue prior to the fourth quarter because rationing had made the Brazilian spot market illiquid and the negotiations on- going with the government, distributors and generators created an environment where collection of the receivable was not assured. The BNDES pre-funding of the tariff increase through loans to the distributors and generators added the needed liquidity to the spot market to assure collection. DERIVATIVES—The Company enters into various derivative transactions in order to hedge its exposure to certain market risks. The Company does not enter into derivative transactions for trading purposes. All derivative transactions are accounted for under SFAS No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended and interpreted. SFAS No. 133 requires that an entity recognize all derivatives (including derivatives embedded in other contracts), as defined, as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the derivative’s fair value are to be recognized currently in earnings, unless specific hedge accounting criteria are met. Hedge accounting allows a derivative’s gains or losses in fair value to offset related results of the hedged item in the statement of operations and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Prior to the adoption of SFAS No. 133 on January 1, 2001, derivatives classified as other than trading were accounted for using settlement accounting (i.e. gains and losses were accrued based on the current period cash settlement due under the contract.) SFAS No. 133 allows hedge accounting for fair value and cash flow hedges. SFAS No. 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair value hedge as well as the offsetting gain or loss on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge be reported as a component of accumulated other comprehensive income in stockholders’ equity and be reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The remaining gain or loss on the derivative, if any, must be recognized currently in earnings. If a cash flow hedge is terminated because it is probable that the hedged transaction or forecasted transaction will not occur, the related balance in other comprehensive income as of such date is immediately recognized. If a cash flow hedge is terminated early for other reasons, the related balance in other comprehensive income as of the termination date is recognized concurrently with the related hedged transaction. The Company currently has outstanding interest rate swap, cap, and floor agreements that hedge against interest rate exposure on floating rate non-recourse debt. These transactions, which are classified as other than trading, are accounted for at fair value. The majority of these transactions are accounted for as cash flow hedges. The Company enters into currency swaps and forwards to hedge against foreign currency risk on certain non-functional currency-denominated liabilities. These transactions are accounted for at fair 72 value. The majority of these transactions are accounted for as either fair value hedges or cash flow hedges. The Company enters into electric and gas derivative instruments, including swaps, options, forwards and futures contracts to manage its risks related to electric and gas sales and purchases. These transactions are accounted for at fair value. The majority of these transactions are accounted for as cash flow hedges, and as such, gains and losses arising from derivative financial instrument transactions that hedge the impact of fluctuations in energy prices are recognized in income concurrent with the related purchases and sales of the commodity. If a derivative financial instrument is entered into for trading purposes, it is marked-to-market with net gains reported within revenues or net losses reported within cost of sales. Derivative fair values are reflected at quoted or estimated market value. The values are adjusted to reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions. In the absence of quoted market prices, other valuation techniques to estimate fair value are utilized. The use of these techniques requires the Company to make estimations of future prices and other variables, including market volatility, price correlation, and market liquidity. In December 2001, the FASB revised its earlier conclusion, Derivatives Implementation Group (‘‘DIG’’) Issue C-15, related to contracts involving the purchase or sale of electricity. Contracts for the purchase or sale of electricity, both forward and option contracts, including capacity contracts, may qualify for the normal purchases and sales exemption and are not required to be accounted for as derivatives under SFAS No. 133. In order for contracts to qualify for this exemption, they must meet certain criteria, which include the requirement for physical delivery of the electricity to be purchased or sold under the contract only in the normal course of business. Additionally, contracts that have a price based on an underlying that is not clearly and closely related to the electricity being sold or purchased or that are denominated in a currency that is foreign to the buyer or seller are not considered normal purchases and normal sales and are required to be accounted for as derivatives under SFAS No. 133. This revised conclusion is effective beginning April 1, 2002. The Company is currently assessing the impact of revised DIG Issue C-15 on its financial condition and results of operations. EARNINGS PER SHARE—Basic and diluted earnings per share are based on the weighted average number of shares of common stock and potential common stock outstanding during the period, after giving effect to stock splits (see Note 12). Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive stock options, warrants, deferred compensation arrangements, and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable. USE OF ESTIMATES—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant items subject to such estimates and assumptions include the carrying value and estimated useful lives of goodwill and long-lived assets; valuation allowances for receivables and deferred tax assets, the recoverability of deferred regulatory assets and the valuation of certain financial instruments, environmental liabilities and potential litigation claims and settlements (see Note 8). RECLASSIFICATIONS—Certain reclassifications have been made to prior-period amounts to conform to the 2001 presentation. 73 2. BUSINESS COMBINATIONS On March 27, 2001, AES completed its merger with IPALCO through a share exchange transaction in accordance with the Agreement and Plan of Share Exchange dated July 15, 2000, between AES and IPALCO, and IPALCO became a wholly owned subsidiary of AES. The Company accounted for the combination as a pooling of interests. Each of the outstanding shares of IPALCO common stock was converted into the right to receive 0.463 shares of AES common stock. The Company issued approximately 41.5 million shares of AES common stock. The consideration consisted of newly issued shares of AES common stock. IPALCO is an Indianapolis-based utility with 3,000 MW of generation and 433,000 customers in and around Indianapolis. The Company issued approximately 346,000 options for the purchase of AES common stock in exchange for IPALCO outstanding options using the exchange ratio. All unvested IPALCO options became vested pursuant to the existing stock option plan upon the change in control. In connection with the merger with IPALCO, the Company incurred contractual liabilities associated with existing termination benefit agreements and other merger related costs for investment banking, legal and other fees. These costs, which were $131 million and $79 million in 2001 and 2000, respectively, are shown separately in the accompanying consolidated statements of operations. All of the amounts for the plan were expensed as incurred. As a result of the plan, the workforce was reduced by 480 people. The tables below sets forth revenues, extraordinary items, net income and comprehensive income for AES and IPALCO for the years ended December 31, 2001, 2000 and 1999. Years Ended December 31, 2001 2000 1999 (in Millions) Revenues: AES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IPALCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $8,491 836 $6,643 891 $3,246 871 $9,327 $7,534 $4,117 Extraordinary items: AES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IPALCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — (7) $ (17) — (4) $ — $ (11) $ (17) Net Income: AES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IPALCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 204 69 $ 640 155 $ 228 129 $ 273 $ 795 $ 357 74 AES IPALCO Combined Comprehensive Income: Year ended December 31, 1999 Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign currency translation adjustment . . . . . . . . . . . . . . . . . . . . . . . . . . Unrealized gains on marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . $ 228 (759) — Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(531) $129 — 107 $236 Year ended December 31, 2000 Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign currency translation adjustment . . . . . . . . . . . . . . . . . . . . . . . . . . $ 640 (575) $155 — Realized gains on marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Minimum pension liability adjustment — (107) (2) — $ 357 (759) 107 $(295) $ 795 (575) (107) (2) Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 65 $ 46 $ 111 Year ended December 31, 2001 Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign currency translation adjustment . . . . . . . . . . . . . . . . . . . . . . . . . . $ 204 (636) $ 69 — $ 273 (636) Unrealized losses on marketable securities . . . . . . . . . . . . . . . . . . . . . . . . Change in derivative fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Minimum pension liability adjustment Cumulative effect of adopting SFAS No. 133 on January 1, 2001 . . . . . . . . (48) (28) (9) (93) — — (7) (48) (28) (16) (93) Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(610) $ 62 $(548) There have been no changes to the significant accounting policies of AES or IPALCO due to the merger. Both AES and IPALCO have the same fiscal years. There were no intercompany transactions between the two companies. The Company has accounted for the following transactions, completed in 2001, using the purchase method of accounting. Accordingly, the purchase price of each transaction has been allocated based upon the estimated fair value of the assets and the liabilities acquired as of the acquisition date, with the excess, if any, reflected as goodwill. The results of operations of the acquired companies have been included in the consolidated results of operations since the date of each acquisition. In January 2001, following the expiration on December 28, 2000 of a Chilean tender offer, Inversiones Cachagua Limitada, a Chilean subsidiary of AES, paid cash for 3,466,600,000 shares of common stock of Gener S.A (‘‘Gener’’). Also in January 2001, following the expiration on December 29, 2000, of the simultaneous United States offer to exchange all American Depositary Shares (‘‘ADS’’) of Gener for AES common stock, AES issued 9.1 million shares of common stock with a value of approximately $511 million in exchange for Gener ADSs tendered pursuant to the United States offer, which, together with the shares acquired in the Chilean offer, resulted in AES’s acquisition of approximately 96.5% of the capital stock of Gener. Subsequently, the Company’s total ownership reached approximately 99% due to a stock buyback program initiated by Gener in February 2001. The purchase price for the acquisition of Gener is approximately $1.4 billion before asset sales of $318 million, plus the assumption of approximately $700 million of non-recourse debt. Approximately $865 million of goodwill was recorded as part of the purchase and is being amortized over 40 years. At December 31, 2000, $848 million of cash had been raised by AES through the issuance of debt and equity for the purchase of Gener. This amount is recorded as restricted cash in short-term investments in the accompanying consolidated balance sheets. In conjunction with its tender offer, the Company agreed to sell two of Gener’s generating assets (Central Puerto and Hidronequen) to TotalFinaElf. In March 2001, Gener and TotalFinaElf executed a purchase and sale agreement which granted to 75 TotalFinaElf the option to purchase three of Gener’s generating assets in Argentina: Central Puerto, Hidronequen and TermoAndes. Pursuant to this agreement, in August, 2001, AES sold Gener’s interest in Central Puerto to a TotalFinaElf subsidiary for $255 million. In addition, in September TotalFinaElf purchased Gener’s interest in Hidronequen for $72.5 million as well as subordinated debt related to Hidronequen held by Gener for approximately $50 million. The option to purchase TermoAndes expired unexercised. Upon completion of the purchase, Gener implemented an employee severance plan. As of December 31, 2001, the severance plan was completed and the workforce was reduced by 187 people. All of the approximately $9 million cost related to the plan was recorded in 2001 and all cash payments were made in 2001. In April 2001, the Company acquired a 75% controlling interest in Kievoblenergo, a distribution company that serves the region that surrounds Kiev, the capital city of Ukraine, for approximately $46 million in cash. The remaining 25% interest is either publicly owned or owned by the employees of the distribution company. In May 2001, the Company acquired a 75% controlling interest in Rivnooblenergo, a distribution company that serves the Rivno region in Ukraine, for approximately $23 million in cash. The remaining 25% interest is either publicly owned or owned by the employees of the distribution company. In July 2001, a subsidiary of the Company completed the final phase of its acquisition of the energy assets of Thermo Ecotek Corporation, a wholly owned subsidiary of Thermo Electron Corporation of Waltham, Massachusetts. The transaction was consummated in two phases. The initial phase of the transaction, which occurred on June 29, 2001, was closed at a price of $242 million in cash. The purchase price for the second and final phase was $18 million in cash. This resulted in a total purchase price for the two phases of the Thermo Ecotek acquisition of $260 million. No material long- term liabilities were assumed at acquisition date. The portfolio of assets acquired by the Company included approximately 500 MW of gas-fired, biomass-fired (agricultural and wood waste) and coal- fired operating power assets in the United States, the Czech Republic, and Germany, a natural gas storage project in the United States, and over 1,250 MW of advanced development power projects in the United States. In July 2001, a subsidiary of the Company acquired a 56% interest in SONEL, an integrated electricity utility in Cameroon, with a 20-year concession on generation, transmission and distribution country-wide. The purchase price was approximately $70 million in cash, plus the assumption of approximately $260 million of long-term liabilities. The other 44% will remain with the government. SONEL is one of the largest African electricity utilities with 800 MW of installed capacity, and 427,000 customers. The purchase price allocations for Thermo Ecotek, SONEL, Kievoblenergo and Rivnooblenergo have been completed on a preliminary basis, subject to adjustments resulting from engineering, environmental, legal and other analyses during the respective allocation periods. In June 2000, pursuant to its tender offer for ADSs, a subsidiary of the Company purchased for cash approximately 35 million ADSs, each representing 50 shares, of C.A. La Electricidad de Caracas and Corporacion EDC, C.A. (together, ‘‘EDC’’) at $28.50 per ADS. Also in June, 2000, pursuant to its tender offer for all outstanding shares of EDC, a subsidiary of the Company purchased approximately 1.1 billion shares of EDC at $0.57 per share. The purchases brought the Company’s ownership interest in EDC to approximately 81%. Subsequently, the Company’s total ownership reached approximately 87% due to a stock buyback program initiated by EDC in July 2000. The total purchase price was $1.7 billion of cash. EDC is the largest private integrated utility in Venezuela, covering the capital region of Caracas. It has interests in distribution businesses in Venezuela, as well as El Salvador-together serving 76 over 1 million customers. EDC also provides 2,265 MW of installed capacity through its generation facilities in Venezuela. The purchase price allocation was as follows (in millions): Purchase price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Stockholders’ equity of EDC Capital stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid-in surplus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjustment of assets and liabilities to fair value: Property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Employee severance plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Investment in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Elimination of intangible asset – goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other net assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,700 (508) (245) (1,353) 323 (1,578) 231 157 36 7 (51) Goodwill – negative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(1,281) Property and equipment was reduced by the negative goodwill. The cost of the acquisition was allocated on the basis of estimated fair value of the assets acquired and liabilities assumed, primarily based upon an independent appraisal. As of December 31, 2000, the severance plan was completed and the workforce was reduced by approximately 2,500 people. All of the costs associated with the plan were recorded during 2000, and all of the cash payments were made in 2000. In August 2000, a subsidiary of the Company completed the acquisition of a 59% equity interest in a Hidroelectrica Alicura S.A. (‘‘Alicura’’) in Argentina from Southern Energy, Inc. and its partners. Alicura operates a 1,000 MW peaking hydro facility located in the province of Neuquen, Argentina. The purchase price of approximately $205 million includes the assumption of existing non-recourse debt. In December 2000 a subsidiary of the Company acquired an additional 39% ownership interest in Alicura, 19.5% ownership interests each from the Federal Government of Argentina and the Province of Neuquen, for approximately $9 million. At December 31, 2000, the Company’s ownership interest was 98%. The employees of Alicura own the remaining 2%. All of the purchase price was allocated to property, plant and equipment and is being depreciated over the useful life. In October 2000, a subsidiary of the Company completed the acquisition of Reliant Energy International’s 50% interest in El Salvador Energy Holdings, S.A. (‘‘ESEH’’) that owns three distribution companies in El Salvador. The purchase price for this interest in ESEH was approximately $173 million. The three distribution companies, Compania de Alumbrado Electrico de San Salvador, S.A. de C.V., Empresa Electrica de Oriente, S.A. de C.V. and Distribuidora Electrica de Usulutan, S.A. De C.V. serve 3.5 million people, approximately 60% of the population of El Salvador, including the capital city of San Salvador. A subsidiary of the Company had previously acquired a 50% interest in ESEH through its acquisition of EDC. Through the purchase of Reliant Energy International’s ownership interest, the Company owns a controlling interest in the three distribution companies. The total purchase price for 100% of the interest in ESEH approximated $325 million, of which approximately $176 million was allocated to goodwill and is being amortized over 40 years. In December 2000, the Company acquired all of the outstanding shares of KMR Power Corporation (‘‘KMR’’), including the buyout of a minority partner in one of KMR’s subsidiaries, for approximately $64 million and assumed long-term liabilities of approximately $245 million. The acquisition was financed through the issuance of approximately 699,000 shares of AES common stock and cash. KMR owns a controlling interest in two gas-fired power plants located in Cartagena, Colombia: a 100% interest in the 314 MW TermoCandelaria power plant and a 66% interest in the 100 77 MW Mamonal plant. Approximately $77 million of the purchase price was allocated to goodwill and is being amortized over 32 years. The TermoCandelaria power plant has been included in discontinued operations in the accompanying consolidated financial statements. The table below presents supplemental unaudited pro forma operating results as if all of the acquisitions had occurred at the beginning of the periods shown (in millions, except per share amounts). No pro forma operating results are provided for 2001, because the impact would not have been material. The pro forma amounts include certain adjustments, primarily for depreciation and amortization based on the allocated purchase price and additional interest expense: Year Ended December 31, 2000 Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income before extraordinary items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Basic earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $8,137 833 822 $1.67 $1.61 The pro forma results are based upon assumptions and estimates that the Company believes are reasonable. The pro forma results do not purport to be indicative of the results that actually would have been obtained had the acquisitions occurred at the beginning of the periods shown, nor are they intended to be a projection of future results. 3. DISCONTINUED OPERATIONS Effective January 1, 2001, the Company adopted SFAS No. 144. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 requires a component of an entity that either has been disposed of or is classified as held for sale to be reported as discontinued operations if certain conditions are met. During the year, the Company decided to exit certain of its businesses. These businesses included Power Direct, Geoutilities, TermoCandelaria, Ib Valley and several telecommunications businesses in Brazil and the U.S. The businesses were either disposed of or abandoned during the year or were classified as held for sale at December 31, 2001. For those businesses disposed of or abandoned, the Company determined that significant adverse changes in legal factors and/or the business climate, such as unfavorable market conditions and low tariffs, negatively affected the value of these assets. The Company has certain businesses that are held for sale, including TermoCandelaria. The Company has approved and committed to a plan to sell these assets, they are available for immediate sale, and a plan has been established to locate a buyer at a reasonable fair market value price. The Company believes it will sell these assets within one year and it is unlikely that significant changes will be made to the plan to sell. At December 31, 2001, the assets and liabilities associated with the discontinued operations are segregated on the consolidated balance sheets. A majority of the long-lived assets related to discontinued operations are for the TermoCandelaria competitive supply business located in Colombia. The revenues associated with the discontinued operations were $287 million, $74 million and $7 million for the years ended December 31, 2001, 2000 and 1999, respectively. The pretax losses associated with the discontinued operations were $58 million, $31 million and $4 million for each of the years ended December 31, 2001, 2000 and 1999, respectively. The loss on disposal and impairment write-downs for those businesses held for sale, net of tax associated with the discontinued operations, was $145 million for the year ended December 31, 2001. 78 4. INVESTMENTS IN AND ADVANCES TO AFFILIATES The Company is a party to joint venture/consortium agreements through which the Company has equity investments in Companhia Energetica de Minas Gerais (‘‘CEMIG’’), Light-Servicos de Eletricidade S.A. (‘‘Light’’) and Eletropaulo Metropolitana Electricidade de Sao Paulo S.A. (‘‘Eletropaulo’’). The joint venture/consortium parties generally share operational control of the investee. The agreements prescribe ownership and voting percentages as well as other matters. The Company records its share of earnings from its equity investees on a pre-tax basis. The Company’s share of the investee’s income taxes is recorded in income tax expense. Effective May 1, 2000, the Company disposed of its investment in Northern/AES Energy. The disposition of the investment did not have a material effect on the Company’s financial condition or results of operations. In May 2000, the Company completed the acquisition of 100% of Tractebel Power Ltd (‘‘TPL’’) for approximately $67 million and assumed liabilities of approximately $200 million. TPL owned 46% of Nigen. The Company also acquired an additional 6% interest in Nigen from minority stockholders during the year ended December 31, 2000 through the issuance of approximately 99,000 common shares of AES stock valued at approximately $4.9 million. With the completion of these transactions, the Company owns approximately 98% of Nigen’s common stock and began consolidating its financial results beginning May 12, 2000. Approximately $100 million of the purchase price was allocated to excess of costs over net assets acquired and is being amortized over 23 years. In August 2000, a subsidiary of the Company acquired a 49% interest in Songas Limited for approximately $40 million. Songas Limited owns the Songo Songo Gas-to-Electricity Project in Tanzania. Under the terms of a project management agreement, the Company has assumed overall project management responsibility. The project consists of the refurbishment and operation of five natural gas wells in coastal Tanzania, the construction and operation of a 65 mmscf/day gas processing plant and related facilities, the construction of a 230 km marine and land pipeline from the gas plant to Dar es Salaam and the conversion and upgrading of an existing 112 MW power station in Dar es Salaam to burn natural gas, with an optional additional unit to be constructed at the plant. Since the project is currently under construction, no revenues or expenses have been incurred, and therefore no results are shown in the following table. In May 1999, a subsidiary of the Company acquired subscription rights from the Brazilian state- controlled Eletrobras, which allowed it to purchase preferred, non-voting shares in Light and Eletropaulo. The aggregate purchase price of the subscription rights and the underlying shares in Light and Eletropaulo was approximately $53 million and $77 million, respectively, and represented 3.7% and 4.4% economic ownership interest in their capital stock, respectively. In May 2000, a subsidiary of the Company acquired an additional 5% of the preferred, non-voting shares of Eletropaulo for approximately $90 million. In January 2000, 59% of the preferred non-voting shares were acquired for approximately $1 billion at auction from BNDES, the National Development Bank of Brazil. The price established at auction was approximately $72.18 per 1,000 shares, to be paid in four annual installments. As of December 31, 2001, 44.4% of the total purchase price had been paid. Installments of 1%, 28.5% and 26.1% are due in 2002, 2003 and 2004, respectively. At December 31, 2000, the Company had a total economic interest of 49.6% and a voting interest of 17.35% in Eletropaulo. The Company accounts for this investment using the equity-method based on the related consortium agreement. The consortium agreement provides the Company with the ability to exercise significant influence but not control. In December 2000, a subsidiary of the Company with EDF International S.A. (‘‘EDF’’) completed the acquisition of an additional 3.5% interest in Light from two subsidiaries of Reliant Energy for approximately $136 million. Pursuant to the acquisition, the Company acquired 30% of the shares while 79 EDF acquired the remainder. With the completion of this transaction, the Company owns approximately 21.14% of Light. In December 2000, a subsidiary of the Company entered into an agreement with EDF International S.A. (‘‘EDF’’) to jointly acquire an additional 9.2% interest in Light, which is held by a subsidiary of Companhia Siderurgica Nacional (‘‘CSN’’). In January 2001, pursuant to this transaction, the Company acquired an additional 2.75% interest in Light and a corresponding 0.83% in Eletropaulo for $114.6 million. At December 31, 2001, the Company owns approximately 23.89% of Light and 50.43% of Electropaulo. The additional ownership increased the Company’s economic ownership in Eletropaulo but did not give the Company the ability to control the business. Control of the business did not occur until the exchange described below occurred. On February 6, 2002, a subsidiary of the Company has exchanged with EDF, their shares representing a 23.89% interest in Light for 88% of the shares of AES Elpa S.A. (formerly Lightgas Lida). AES Elpa owns 77% of the voting capital (31% of total capital) of Eletropaulo and 100% of Light Telecom. Additionally, AES Elpa assumed debt of $527 million in the transaction of which $245 million is due in April 2002 and $111 million is due in October 2002. As a result of this transaction, AES has acquired a controlling interest in Eletropaulo and will begin consolidating the subsidiary in 2002. During 2001, the Company was removed from the management and the Board of Directors of CESCO, a subsidiary of the Company, by GRIDCO. GRIDCO is a 100% owned entity of the Government of the State of Orissa, India, and the minority shareholder of CESCO, a distribution company also in Orissa. An administrator appointed by the state regulator has been making the significant decisions that are expected to be made in the ordinary course of business. Due to these actions the Company has removed all of its people from the business. Because the Company has lost operational control of CESCO, it has changed its accounting for this business from consolidation to equity-method accounting. The investment in the business has been written-down to zero. The Company does not believe it has any further ongoing obligation related to this business. The following table presents summarized financial information (in millions) for the Company’s investments in affiliates over which it has the ability to exercise significant influence but does not control, which are accounted for using the equity method: As of and for the Years Ended December 31, 2001 2000 1999 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Noncurrent Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Noncurrent Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stockholder’s Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,147 1,717 650 3,700 14,943 3,510 8,297 6,836 $ 6,241 1,989 859 2,423 13,080 3,370 5,927 6,206 $ 5,960 1,839 62 2,259 15,359 3,637 7,536 6,445 80 Relevant equity ownership percentages for these investments are presented below: Affiliate Country 2001 December 31, 2000 1999 CEMIG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CESCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Chigen affiliates . . . . . . . . . . . . . . . . . . . . . . . . . EDC affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . Eletropaulo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Elsta . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gener affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . Infovias . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kingston . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Light . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Medway Power, Ltd. . . . . . . . . . . . . . . . . . . . . . . United Kingdom Nigen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . United Kingdom Northern/AES Energy . . . . . . . . . . . . . . . . . . . . . OPGC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Songas Limited . . . . . . . . . . . . . . . . . . . . . . . . . . Brazil India China Venezuela Brazil Netherlands Chile Brazil Canada Brazil United States India Tanzania 21.62% 21.62% 48.45 30.00 45.00 50.43 50.00 37.50 50.00 50.00 23.89 25.00 — — 49.00 49.00 48.45 30.00 45.00 49.60 50.00 n/a 50.00 50.00 21.14 25.00 — — 49.00 49.00 21.62% 48.45 30.00 n/a 9.90 50.00 n/a 50.00 50.00 17.68 25.00 46.17 50.00 49.00 n/a The results of operations and the financial position of the Brazilian affiliates, Light, Eletropaulo and CEMIG, were negatively impacted by the devaluation of the Brazilian Real. The Brazilian Real experienced a significant devaluation relative to the U.S. Dollar, declining from 1.96 Reais to the U.S. Dollar at December 31, 2000 to 2.41 Reais at December 31, 2001. Additionally, during 1999, the Brazilian Real experienced a significant devaluation relative to the U.S. Dollar declining from 1.21 Reais to the U.S. Dollar at December 31, 1998 to1.81 Reais to the U.S. Dollar at December 31, 1999. This continued devaluation resulted in significant foreign currency translation and transaction losses particularly during 2001 and 1999. The Company recorded $210 million, $64 million and $203 million before income taxes of non-cash foreign currency transaction losses on its investments in Brazilian equity-method affiliates during 2001, 2000 and 1999, respectively. The Company’s cumulative after-tax share of undistributed earnings of affiliates included in consolidated retained earnings was $462 million, $370 million, and $96 million at December 31, 2001, 2000, and 1999, respectively. The Company charged and recognized construction revenues, management fees and interest on advances to its affiliates, which aggregated $12 million, $11 million, $21 million for each of the years ended December 31, 2001, 2000 and 1999, respectively. 81 5. INVESTMENTS The short-term investments and debt service reserves and other deposits were invested as follows (in millions): December 31, 2001 2000 RESTRICTED CASH AND CASH EQUIVALENTS (1) . . . . . . . . . . . . . . . . . . . . . $ 831 $1,710 HELD-TO-MATURITY: Certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Commercial paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Debt securities issued by foreign governments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AVAILABLE-FOR-SALE: Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TRADING: Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106 — 2 3 111 103 — 103 17 86 7 — — 93 — 1 1 2 TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,062 $1,806 (1) Amounts required to be maintained in cash or cash equivalents in accordance with certain covenants of various project financing agreements and lease contracts. Restricted cash at December 31, 2000, also includes certain cash deposited in escrow. The Company’s investments are classified as held-to-maturity, available-for-sale or trading. The amortized cost and estimated fair value of the held-to-maturity and available-for-sale investments (other than the equity securities discussed below) were approximately the same. The trading investments are recorded at fair value. All of the Company’s investments were short-term at December 31, 2001 and 2000. Also included in short-term investments at December 31, 2001 and 2000 was restricted cash of approximately $357 million and $1.2 billion, respectively. In 2001, a subsidiary of the Company sold approximately 14 million shares of Compania Anonima Nacional Telefonos de Venezuela resulting in a realized gain of approximately $18 million. In 2000, a subsidiary of the Company sold approximately one million shares of Internet Capital Group, Inc. resulting in a realized gain of approximately $112 million. The after-tax proceeds from this sale were applied primarily to the reduction of the Company’s outstanding unsecured debt. During the fourth quarter of 2001, the Company had recorded unrealized losses of approximately $48 million related to available-for-sale equity securities which are included in accumulated other comprehensive loss in the accompanying consolidated balance sheets. 82 6. LONG-TERM DEBT NON-RECOURSE DEBT—Non-recourse debt at December 31, 2001 and 2000 consisted of the following (in millions): VARIABLE RATE: Bank loans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Commercial paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes and Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Debt to (or guaranteed by) multilateral or export credit agencies Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIXED RATE: Bank loans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Commercial Paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes and bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Debt to (or guaranteed by) multilateral or export credit agencies Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SUBTOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest Rate (1) Final Maturity December 31, 2001 2000 7.05% 2023 6.40% 2008 7.75% 2030 5.65% 2018 12.38% 2022 6.19% 2018 13.50% 2002 8.72% 2029 7.90% 2023 3.43% 2010 $ 5,760 501 889 945 602 $ 6,861 637 — 649 837 1,892 63 5,922 165 118 2,003 — 3,994 164 13 16,857 (2,184) 15,158 (2,462) $14,673 $12,696 (1) Weighted average interest rate at December 31, 2001. Non-recourse debt borrowings are primarily collateralized by the capital stock of the relevant subsidiary and in certain cases the physical assets of, and all significant agreements associated with, such business. Such debt is not a direct obligation of the AES, the parent corporation. These non- recourse financings include structured project financings, acquisition financings, working capital facilities and all other consolidated debt of the subsidiaries. The Company has issued shares of common stock to consolidated subsidiaries as collateral under various borrowing arrangements (see Note 11). The Company has interest rate swap and forward interest rate swap agreements in an aggregate notional principal amount of $3.2 billion at December 31, 2001. The interest rate swaps are accounted for at fair value (see Note 7). The swap agreements effectively change the variable interest rates on the portion of the debt covered by the notional amounts to weighted average fixed rates ranging from approximately 4.19% to 9.90%. The agreements expire at various dates from 2002 through 2017. In the event of nonperformance by the counter parties, the Company may be exposed to increased interest rates; however, the Company does not anticipate nonperformance by the counter parties, which are multinational financial institutions. Certain commercial paper borrowings of subsidiaries are supported by letters of credit or lines of credit issued by various financial institutions. In the event of nonperformance or credit deterioration of these financial institutions, the Company may be exposed to the risk of higher effective interest rates. The Company does not believe that such nonperformance or credit deterioration is likely. At December 31, 2001, a number of the Company’s subsidiaries were in default under their outstanding project indebtedness as of December 31, 2001, including Chivor, Edelap, Eden/Edes and Parana. Because none of these businesses are material subsidiaries, none of these defaults is expected to have a material adverse effect on the Company’s results of operations or financial condition. All of 83 the related loans have been recorded in current non-recourse debt in the accompanying consolidated balance sheets. In addition, subsequent to year end, AES Drax had an event of default under its 1.3 billion pound sterling bank facility as a result of its inability to obtain specified minimum amounts of insurance coverage. While the lenders under this facility have not exercised their right to accelerate the maturity of the loans thereunder, they have refused to waive the prohibition on the payment of any dividends by AES Drax and its subsidiaries during the pendancy of the default. Accordingly, AES Drax has had to use its debt service reserve accounts to service a portion of its outstanding subordinated public debt at the holding company and has been unable, and will for at least the next six months be unable, to pay dividends to AES. On March 21, 2002, Fifoots was placed in administrative receivership by its lenders. Fifoots defaulted on its debt after electricity prices in the U.K. fell below its marginal costs. AES expects to write-off its investment of approximately $36 million in Fifoots during the first quarter of 2002. RECOURSE DEBT—Recourse debt obligations are direct borrowings of the AES parent corporation and at December 31, 2001 and 2000, consisted of the following (in millions): Corporate revolving bank loan . . . . . . . . . . . . . . . . . . . . . . Term loan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Term loan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Remarketable or Redeemable Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior subordinated notes . . . . . . . . . . . . . . . . . . . . . . . . . Senior subordinated notes Senior subordinated notes . . . . . . . . . . . . . . . . . . . . . . . . . Senior subordinated debentures . . . . . . . . . . . . . . . . . . . . . Convertible junior subordinated debentures . . . . . . . . . . . . . Unamortized discounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . SUBTOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1) Interest rate at December 31, 2001. Interest First Call Final Rate (1) Maturity Date (2) 2001 2000 4.09% 2003 4.49% 2003 4.50% 2002 8.75% 2002 8.00% 2008 9.50% 2009 9.38% 2010 8.88% 2011 8.38% 2011 8.75% 2008 7.38% 2013 10.25% 2006 8.38% 2007 8.50% 2007 8.88% 2027 4.50% 2005 2000 — — — 2000 — — — — — 2003 2001 2002 2002 2004 2001 $ 70 $ 140 — — 300 200 750 850 — — — — 250 325 375 125 150 (7) 425 188 300 200 750 850 600 196 400 200 250 325 375 125 150 (3) 5,401 3,458 (488) — $4,913 $3,458 (2) Except for the Remarketable or Redeemable Securities, which are discussed below, the first call date represents the date that the Company, at its option, can call the related debt. The term loan with a final maturity in 2003 has an interest rate equal to LIBOR plus 2.38%. LIBOR has been fixed at 2.11% through June 2002. The term loan with a final maturity in 2002 has an interest rate equal to LIBOR plus 2.5%. LIBOR has been fixed at 2.00% through February 2002 and 1.92% through May 2002. 84 In March 2000, the Company entered into an $850 million revolving credit agreement with a syndicate of banks, which provides for a combination of either loans or letters of credit up to the maximum borrowing capacity. Loans under the facility bear interest at either Prime plus a spread of 0.50% or LIBOR plus a spread of 2%. Such spreads are subject to adjustment based on the Company’s credit ratings and the term remaining to maturity. This facility replaced the Company’s then existing separate $600 million revolving credit facility and $250 million letter of credit facilities. As of December 31, 2001, $496 million was available. Commitment fees on the facility at December 31, 2001 were .50% per annum. The Company’s recourse debt borrowings are unsecured obligations of the Company. In May 2001, the Company issued $200 million of Remarketable or Redeemable Securities (‘‘ROARS’’). The ROARS are scheduled to mature on June 15, 2013, but such maturity date may be adjusted to a date, which shall be no later than June 15, 2014. On the First Remarketing Date (June 15, 2003) or subsequent Remarketing dates thereafter, the remarketing agent, or the Company, may elect to redeem the ROARS at 100% of the aggregate principal amount and unpaid interest, plus a premium in certain circumstances. The Company at its option, may also redeem the ROARS subsequent to the First Remarketing Date at any time. Interest on the ROARS accrues at 7.375% until the First Remarketing Date, and thereafter is set annually based on market rate bids, with a floor of 5.5%. The ROARS are senior notes. The Junior Subordinate Debentures are convertible into common stock of the Company at the option of the holder at any time at or before maturity, unless previously redeemed, at a conversion price of $27.00 per share. FUTURE MATURITIES OF DEBT—Scheduled maturities of total debt at December 31, 2001, are (in millions): 2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,672 2,323 1,255 1,819 1,383 12,806 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $22,258 COVENANTS—The terms of the Company’s recourse debt, including the revolving bank loan, senior and subordinated notes contain certain restrictive financial and non-financial covenants. The financial covenants provide for, among other items, maintenance of a minimum consolidated net worth, minimum consolidated cash flow coverage ratio and minimum ratio of recourse debt to recourse capital. The non-financial covenants include limitations on incurrence of additional debt and payments of dividends to stockholders. In addition, the Company’s revolver contains provisions regarding events of default that could be caused by events of default in other debt of AES and certain of its significant subsidiaries, as defined in the agreement. The terms of the Company’s non-recourse debt, which is debt held at subsidiaries, include certain financial and non-financial covenants. These covenants are limited to subsidiary activity and vary among the subsidiaries. These covenants may include but are not limited to maintenance of certain reserves, minimum levels of working capital and limitations on incurring additional indebtedness. As of December 31, 2001, approximately $442 million of restricted cash was maintained in accordance with certain covenants of the debt agreements, and these amounts were included within debt service reserves and other deposits in the consolidated balance sheets. Various lender and governmental provisions restrict the ability of the Company’s subsidiaries to transfer retained earnings to the parent company. Such restricted retained earnings of subsidiaries amounted to approximately $6.5 billion at December 31, 2001. 85 7. DERIVATIVE INSTRUMENTS Effective January 1, 2001, AES adopted SFAS No. 133, ‘‘Accounting For Derivative Instruments And Hedging Activities,’’ which, as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. The adoption of SFAS No. 133 on January 1, 2001, resulted in a cumulative reduction to income of less than $1 million, net of deferred income tax effects, and a cumulative reduction of accumulated other comprehensive income in stockholders’ equity of $93 million, net of deferred income tax effects. For the year ended December 31, 2001, the impact of changes in derivative fair value primarily related to derivatives that do not qualify for hedge accounting treatment was a charge of $36 million, after income taxes. This amount includes a charge of $6 million, after income taxes, related to the ineffective portion of derivatives qualifying as cash flow and fair value hedges for the year ended December 31, 2001. There was no net effect on results of operations for the year ended December 31, 2001, of derivative and non-derivative instruments that have been designated and qualified as hedging net investments in foreign operations. Approximately $35 million of other comprehensive loss related to derivative instruments as of December 31, 2001 is expected to be recognized as a reduction to earnings over the next twelve months. A portion of this amount is expected to be offset by the effects of hedge accounting. The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for hedges of interest rate risk, as foreign currency transaction and translation gains and losses are recognized for hedges of foreign currency exposure and as electric and gas sales and purchases are recognized for hedges of forecasted electric and gas transactions. Amounts recorded in accumulated other comprehensive income, net of tax, during the year-ended December 31, 2001, were as follows (in millions): Transition adjustment on January 1, 2001 . . . . . . . . . . . . . . . . . . . . . . . . . . Reclassification to earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change in fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (93) (32) 4 Balance, December 31, 2001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(121) AES utilizes derivative financial instruments to hedge interest rate risk, foreign exchange risk and commodity price risk. The Company utilizes interest rate swap, cap and floor agreements to hedge interest rate risk on floating rate debt. The majority of AES’s interest rate derivatives are designated and qualify as cash flow hedges. Currency forward and swap agreements are utilized to hedge foreign exchange risk which is a result of AES or one of its subsidiaries entering into monetary obligations in currencies other than its own functional currency. The majority of AES’s foreign currency derivatives are designated and qualify as either fair value hedges or cash flow hedges. Certain derivative instruments and other non-derivative instruments are designated and qualify as hedges of the foreign currency exposure of a net investment in a foreign operation. The Company utilizes electric and gas derivative instruments, including swaps, options, forwards and futures, to hedge the risk related to electricity and gas sales and purchases. The majority of AES’s electric and gas derivatives are designated and qualify as cash flow hedges. The maximum length of time over which AES is hedging its exposure to variability in future cash flows for forecasted transactions, excluding forecasted transactions related to the payment of variable interest, is three years. For the year ended December 31, 2001, a charge of $4 million, after income taxes, was recorded for two cash flow hedges that were discontinued because it is probable that the hedged forecasted transaction will not occur. A portion of this charge has been classified as discontinued operations. For the year ended December 31, 2001, no fair value hedges were de-recognized or discontinued. 86 8. COMMITMENTS, CONTINGENCIES AND RISKS OPERATING LEASES—As of December 31, 2001, the Company was obligated under long-term non-cancelable operating leases, primarily for office rental and site leases. Rental expense for operating leases, excluding amounts related to the sale/leaseback discussed below, was $32 million, $13 million, and $7 million in the years ended December 31, 2001, 2000 and 1999, respectively. The future minimum lease commitments under these leases are $44 million for 2002, $41 million for 2003, $37 million for 2004, $37 million for 2005, $38 million for 2006, and a total of $405 million for the years thereafter. SALE/LEASEBACK—In May 1999, a subsidiary of the Company acquired six electric generating stations from New York State Electric and Gas (‘‘NYSEG’’). Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. This transaction has been accounted for as a sale/leaseback with operating lease treatment. Rental expense was $58 million, $54 million and $26 million in 2001, 2000 and 1999, respectively. Future minimum lease commitments are $63 million for 2002, $58 million for 2003, $63 million for 2004, $59 million for 2005, $62 million for 2006 and a total of $1.3 billion for the years thereafter. In connection with the lease of the two power plants, the subsidiary is required to maintain a rent reserve account equal to the maximum semi-annual payment with respect to the sum of the basic rent and fixed charges expected to become due in the immediately succeeding three-year period. At December 31, 2001 and 2000, the amount deposited in the rent reserve account approximated $32 million and $31 million, respectively. This amount is included in restricted cash and can only be utilized to satisfy lease obligations. The agreements governing the leases restrict the subsidiary’s ability to incur additional indebtedness, sell its assets or merge with another entity. The ability of the subsidiary to make distributions is restricted unless certain covenants, including the maintenance of certain coverage ratios, are met. The subsidiary is also required to maintain an additional liquidity account initially equal to $65 million less the balance of the rent reserve account. A letter of credit from a bank for $36 million has been obtained to satisfy this requirement. CONTRACTS—Operating subsidiaries of the Company have entered into ‘‘take-or-pay’’ contracts for the purchase of electricity from third parties. Purchases in 2001 were approximately $368 million. The future commitments under these contracts are $409 million for 2002, $378 million for 2003, $341 million for 2004, $332 million for 2005, $318 million for 2006 and a total of $4.3 billion for the years thereafter. Operating subsidiaries of the Company have entered into various long-term contracts for the purchase of fuel subject to termination only in certain limited circumstances. Purchases in 2001 were approximately $617 million. The future commitments under contracts are $546 million for 2002, $519 million for 2003, $492 million for 2004, $397 million for 2005, $248 million for 2006, and $1.9 billion thereafter. In connection with an electricity sales agreement, a subsidiary of the Company assumed contingent liabilities related to plant performance. If plant availability and contract performance specifications are not met, then a subsidiary of the Company may be required to make payments of up to $127 million to a third party under the terms of a power sales agreement. Several of the Company’s power plants rely on power sales contracts with one or a limited number of entities for the majority of, and in some case all of, the relevant plant’s output over the term of the power sales contract. The remaining term of power sales contracts related to the Company’s power plants range from 5 to 29 years. However, the operations of such plants are dependent on the continued performance by customers and suppliers of their obligations under the relevant power sales 87 contract, and, in particular, on the credit quality of the purchasers. If a substantial portion of the Company’s long-term power sales contracts were modified or terminated, the Company would be adversely affected to the extent that it was unable to find other customers at the same level of contract profitability. Some of the Company’s long-term power sales agreements are for prices above current spot market prices. The loss of one or more significant power sales contracts or the failure by any of the parties to a power sales contract to fulfill its obligations thereunder could have a material adverse impact on the Company’s business, results of operations and financial condition. During 2000, the wholesale electricity market in California experienced a significant imbalance in the supply of, and demand for electricity, which resulted in significant electricity price increases and volatility. California’s two largest utilities were required to purchase wholesale power at higher market prices and to sell it at fixed prices to retail end users. Because the cost of wholesale power exceeded the price the utilities charged their retail customers, these utilities are facing severe financial difficulties. There can be no assurances that such utilities can, or will choose to, honor their financial commitments. In the event that such utilities become insolvent or otherwise choose not to honor their commitments, creditors (including certain of the Company’s subsidiaries) may seek to exercise whatever remedies may be available, including, among other things, placing the utilities into involuntary bankruptcy. There can be no assurances that amounts owing directly or indirectly from such utilities will be recovered. In addition, the California Independent System Operator has sought a Temporary Restraining Order over some of the generators, including AES subsidiaries, arguing that, in times of declared emergencies, generators are required to continue to provide electricity to the market even if there is no credit-worthy purchaser for the electricity. The bulk of the Company’s revenues in California are not subject to this credit risk, because they are generated under a tolling agreement entered into by AES Southland. But the Company’s other subsidiaries have some exposure to this risk. At December 31, 2001 and 2000, the Company had receivables of approximately $13 million and $27 million, respectively, that are subject to this credit risk. In addition, because these utilities have defaulted on amounts due in the state sanctioned markets, the markets have sought to recover those amounts pro rata from other market participants, including certain of the Company’s subsidiaries. Enron Corporation and several of its affiliates filed Chapter 11 bankruptcy petitions on December 2, 2001, in the U.S. Bankruptcy Court for the Southern District of New York. At that time, several of the Company’s subsidiaries had outstanding long-term contracts for gas and electricity purchases and sales with Enron and its subsidiaries. The Company does not believe its exposure under these contracts is material and has not recorded any liability associated with these contracts. Other Enron subsidiaries were also under contract to provide engineering, procurement and construction (‘‘EPC’’) services on three of the Company’s greenfield construction projects, including AES Wolf Hollow in Texas, AES Lake Worth Generation in Florida, and the AES Ebute Barge project in Nigeria. To avoid delay, each respective AES subsidiary has put into place transition arrangements that allow the subcontractors to continue working on the project, while alternative arrangements for completing the projects are investigated. Such alternative arrangements could include, but are not limited to, procuring a partner for the current EPC contractor, replacing the current EPC contractor entirely or assigning the contract to the largest subcontractor. Although disruption or delay in the progress of construction has not occurred to date, there can be no assurance that such disruption or delay will not occur in the future. The Company does not believe any such disruption or delay will have a material adverse effect on the results of operations or financial position of the Company. ENVIRONMENTAL—As of December 31, 2001, the Company has recorded cumulative liabilities associated with acquired generation plants of approximately $33 million for projected environmental remediation costs. During 2000, the Company incurred a $17 million environmental fine and was required to incur capital expenditures related to excess nitrogen oxide air emissions at certain of its generating facilities in California. 88 In May 2000, the New York State Department of Environmental Conservation (‘‘DEC’’) issued a Notice of Violation (‘‘NOV’’) to NYSEG for violations of the Federal Clean Air Act and the New York Environmental Conservation Law at the Greenidge and Westover plants related to NYSEG’s alleged failure to undergo an air permitting review prior to making repairs and improvements during the 1980s and 1990s. Pursuant to the agreement relating to the acquisition of the plants from NYSEG, AES Eastern Energy agreed with NYSEG that AES Eastern Energy will assume responsibility for the NOV, subject to a reservation of AES Eastern Energy’s right to assert any applicable exception to its contractual undertaking to assume pre-existing environmental liabilities. The Company believes it has meritorious defenses to any actions asserted against it and expects to vigorously defend itself against the allegations; however, the NOV issued by the DEC, and any additional enforcement actions that might be brought by the New York State Attorney General, the DEC or the U.S. Environmental Protection Agency (‘‘EPA’’), against the Somerset, Cayuga, Greenidge or Westover plants, might result in the imposition of penalties and might require further emission reductions at those plants. The EPA has commenced an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Federal Clean Air Act associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. The EPA’s focus is on whether the changes were subject to new source review or new performance standards, and whether best available control technology was or should have been used. On August 4, 1999, the EPA issued a NOV to the Company’s Beaver Valley plant, generally alleging that the facility failed to obtain the necessary permits in connection with certain changes made to the facility in the mid-to-late 1980s. The Company believes it has meritorious defenses to any actions asserted against it and expects to vigorously defend itself against the allegations. The Company’s generating plants are subject to emission regulations. The regulations may result in increased operating costs or the purchase of additional pollution control equipment if emission levels are exceeded. The Company reviews its obligations as it relates to compliance with environmental laws, including site restoration and remediation. Because of the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Based on currently available information, the Company does not believe that any costs incurred in excess of those currently accrued will have a material effect on the financial condition and results of operations of the Company. DERIVATIVES—Certain subsidiaries and an affiliate of the Company entered into interest rate, foreign currency, electricity and gas derivative contracts with various counter parties, and as a result, the Company is exposed to the risk of nonperformance by its counter parties. The Company does not anticipate nonperformance by the counter parties. The Company is exposed to market risks on derivative contracts and on other unmatched commitments to purchase and sell energy on a price and quantity basis. Such market risks are monitored to limit the Company’s exposure. GUARANTEES—In connection with certain of its project financing, acquisition, and power purchase agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments, excluding those collateralized by letter-of-credit obligations discussed below, were limited as of December 31, 2001, by the terms of the agreements, to an aggregate of approximately $775 million representing 68 agreements with individual exposures ranging from less than $1 million up to $100 million. Of this amount, $249 million represents credit enhancements for non- recourse debt that is recorded in the accompanying consolidated balance sheets. The Company is also obligated under other commitments, which are limited to amounts, or percentages of amounts, received by AES as distributions from its subsidiaries. These amounts aggregated $50 million as of December 89 31, 2001. In addition, the Company has commitments to fund its equity in projects currently under development or in construction. At December 31, 2001, such commitments to invest amounted to approximately $207 million. LETTERS OF CREDIT—At December 31, 2001, the Company had $453 million in letters of credit outstanding representing 36 agreements with individual exposures ranging from less than $1 million up to $107 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. Of this amount, $262 million represent credit enhancements for non-recourse debt that is recorded in the accompanying consolidated balance sheets. The Company pays a letter-of-credit fee ranging from 0.50% to 2.0% per annum on the outstanding amounts. In addition, the Company had $76 million and a subsidiary of the Company had $271 million in surety bonds outstanding at December 31, 2001. LITIGATION—In September 1999, an appellate judge in the Minas Gerais, Brazil state court system granted a temporary injunction that suspends the effectiveness of a shareholders’ agreement for Cia. Energetica De Minas Gerais (‘‘CEMIG’’). This appellate ruling suspends the shareholders’ agreement while the action to determine the validity of the shareholders’ agreement is litigated in the lower court. In early November 1999, the same appellate court judge reversed this decision and reinstated the effectiveness of the shareholders’ agreement, but did not restore the super majority voting rights that benefited the Company. In March 2000, a state court in Minas Gerais again ruled that the shareholders’ agreement was invalid. In April 2000, the appellate court denied the appeal of that second state court decision. In August 2001, the appellate court denied another appeal, confirming the decision that the shareholder’s agreement was null and void. AES was required to exhaust all state- level appeals before the matter is heard before the Brazilian federal court. In November 2001, a special procedure was initiated whereby CEMIG requested that the case be transferred from state court to superior court in Brasilia. The Company intends to vigorously pursue its legal rights in this matter and to restore all of its rights regarding CEMIG. Failure to prevail in this matter would limit the Company’s influence on the daily operations of CEMIG. However, the Company would still own approximately 21.6% of the voting common stock of CEMIG and be able to exercise significant influence over the operations of the business. In November 2000, the Company was named in a purported class action suit along with six other defendants alleging unlawful manipulation of the California wholesale electricity market, resulting in inflated wholesale electricity prices throughout California. Alleged causes of action include violation of the Cartwright Act, the California Unfair Trade Practices Act and the California Consumers Legal Remedies Act. In December 2000, the case was removed from the San Diego County Superior Court to the U.S. District Court for the Southern District of California. The case has been consolidated with five other lawsuits alleging similar claims against other defendants. In March 2002, the plaintiffs filed a new master complaint in the consolidated action, which asserted the claims asserted in the earlier action and names the Company, AES Redondo Beach, L.L.C., AES Alamitos, L.L.C., and AES Huntington Beach, L.L.C. as defendants. The Company believes it has meritorious defenses to any actions asserted against it and expects that it will defend itself vigorously against the allegations. In addition, the crisis in the California wholesale power markets has directly or indirectly resulted in several administrative and legal actions involving the Company’s businesses in California. Each of the Company’s businesses in California (AES Southland, AES Placerita and AES New Energy) are subject to overlapping state investigations by the California Attorney General’s Office, the Market Oversight and Monitoring Committee of the California Independent System Operator (‘‘ISO’’), the California Public Utility Commission and a subcommittee of the California Senate. Each of these investigations are currently in the document gathering stage, and the businesses have responded to multiple requests for the production of documents and data surrounding the operation and bidding behavior of the plants. 90 In August 2000, the Federal Energy Regulatory Commission (‘‘FERC’’) announced an investigation into the national wholesale power markets, with particular emphasis upon the California wholesale electricity market, in order to determine whether there has been anti-competitive activity by wholesale generators and marketers of electricity. The FERC has requested documents from each of the AES Southland plants. Similar to the state investigation, the FERC investigation has focused their attention to date upon the forced and planned maintenance outages taken by the plants in 2000. This FERC investigation also has focused on the activities surrounding the marketing of the power from the plants. In May 2001, the Antitrust Division of the United States Department of Justice initiated an investigation to determine whether a provision in the AES Southland plants’ Tolling Agreement with Williams Energy Services Company has restricted the addition of new capacity in the Los Angeles area in contravention of the antitrust laws. The AES Southland businesses have provided documents and other information to the Department of Justice. In July of 2001, a petition was filed against CESCO, an affiliate of the Company by the Grid Corporation of Orissa, India (‘‘Gridco’’), with the Orissa Electricity Regulatory Commission (‘‘OERC’’), alleging that CESCO has defaulted on its obligations as a government licensed distribution company; that CESCO management abandoned the management of CESCO; and asking for interim measures of protection, including the appointment of a government regulator to manage CESCO. Gridco, a state owned entity, is the sole energy wholesaler to CESCO. In August 2001, the management of CESCO was handed over by the OERC to a government administrator that was appointed by the OERC. Gridco also has asserted that a Letter of Comfort issued by the Company in connection with the Company’s investment in CESCO obligates the Company to provide additional financial support to cover CESCO’s financial obligations. In December 2001, a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 was served on the Company by Gridco pursuant to the terms of the CESCO Shareholder’s Agreement (‘‘SHA’’), between Gridco, the Company, AES ODPL, and Jyoti Structures. The notice to arbitrate failed to detail the disputes under the SHA for which the Arbitration had been initiated. The Company believes that it has meritorious defenses to any actions asserted against it and expects that it will defend itself vigorously against the allegations. RISKS RELATED TO REGULATED AND FOREIGN OPERATIONS—AES operates businesses in many regulated and foreign environments. There are certain economic, political, technological and regulatory risks associated with operating in these environments. Investments in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. During 2001 and 1999, the Company’s financial position and results of operations were adversely affected by a significant devaluation of the Brazilian Real relative to the U.S. Dollar. The distribution businesses, which the Company owns or has investments in, are subject to regulatory review or approval which could limit electricity tariff rates charged to customers or require the return of amounts previously collected. These regulatory environments are also subject to change, which could impact the results of operations. In certain locations, particularly developing countries or countries that are in a transition from centrally planned to market-oriented economies, the electricity purchasers, both wholesale and retail, may be unable or unwilling to honor their payment obligations. Collection of receivables may be hindered in these countries due to ineffective systems for adjudicating contract disputes. In June 1999, a subsidiary of the Company assumed long-term managerial control of two regional electric distribution companies (‘‘RECs’’) in Kazakhstan as part of a settlement of receivables outstanding from the government of Kazakhstan. The Company’s claim against the government was for electricity previously provided. The contractual rights to control the operations of the RECs received in this transaction were valued at approximately $26 million, based on the net present value of incremental cash flows expected to be received as a result of operating the RECs. The value of the contract rights was recorded in the statement of operations in 1999. The two distribution businesses 91 serve approximately 1.8 million people. The Company expects that the government of Kazakhstan will abide by the terms and periods agreed to in the original memorandum of understanding that currently governs the Company’s operating control of the RECs. However, the contract is subject to economic, political and regulatory risks associated with operating in Kazakhstan. The Company does not consolidate the RECs because it operates them under a management agreement and does not have a controlling ownership interest in them. Argentina is experiencing a significant political, social and economic crisis that has resulted in significant changes in general economic policies and regulations as well as specific changes in the energy sector. During January and February 2002, many new economic measures have been adopted by the Argentine government, including abandoning the country’s fixed dollar-to-peso exchange rate, converting dollar denominated loans into pesos and placing restrictions on the convertibility of the Argentine peso. The government has also adopted new regulations in the energy sector that have the effect of repealing U.S. Dollar denominated pricing under electricity tariffs as prescribed in existing electricity distribution concessions in Argentina by fixing all prices to consumers in pesos until June 30, 2002. In combination these circumstances create significant uncertainty surrounding the performance, cash flow and potential for profitability of the electricity industry in Argentina, including the Argentine subsidiaries of AES. AES has several subsidiaries in Argentina operating in both the competitive supply and growth distribution segments of the business. Eden, Edes and Edelap are distribution companies that operate in the province of Buenos Aires. Generating businesses include Alicura, Parana, CTSN, Rio Juramento and several other smaller hydro facilities. These businesses are experiencing significant cash flow shortfalls arising from the economic and regulatory changes described earlier, and some of the businesses are in default on their project financing arrangements beginning in 2002. AES (the parent company) is not generally required to support the potential cash flow or debt service obligations of these businesses. The effects of the crisis are not expected to have a significant negative impact on AES’s overall liquidity, due primarily to the non-recourse financing structure in place at most of AES’s Argentine businesses. The effects of the current circumstances on future earnings are much more uncertain and difficult to predict. At December 31, 2001, AES’s total contributed cash investment and the retained earnings in the competitive supply business in Argentina are approximately $575 million and the total similar investment in the growth distribution business is approximately $465 million. Depending on the ultimate resolution of these uncertainties, AES may be required in 2002 to record a material impairment loss or write-off associated with the recorded carrying values of its investments, including goodwill, although no such loss has been recorded to date. Additionally, under current conditions, the Argentine businesses may also incur operating losses during 2002. AES is currently investigating and pursuing several potential alternatives to minimize the impacts on earnings. It is possible, as AES pursues these alternatives, that future Argentine business results may be reported as discontinued operations. AES financed certain of its purchases in Eletropaulo through deferred purchase price financing arrangements provided by BNDES to subsidiaries of the Company, which aggregates approximately $1.2 billion. The payment schedule varies from April 2002 through January 2004. BNDES maintains as collateral shares that represent substantially all of the Company’s ownership interest in Eletropaulo. As a result of the volatility of the Brazilian Real and the difficult economic conditions in Brazil, the Company is evaluating whether to contribute equity sufficient to allow such subsidiaries to make the payments. If AES does not contribute sufficient equity or other consideration, or if there is not a successful renegotiation of the debt with BNDES, there can be no assurance that such subsidiaries will be able to pay such amounts, or refinance or extend the maturities of any or all of the payment amounts. In such event, BNDES may choose to seize the shares held as collateral, and this may result in a loss and resulting write-off of a portion or all of the Company’s investment. 92 LEVERAGED LEASE INVESTMENTS—CILCORP has investments in leveraged leases totaling $136 million. Related deferred tax liabilities total $106 million. The investment includes estimated residual values totaling $86 million. Leveraged lease residual value assumptions are adjusted on a periodic basis, based on independent appraisals. SALE OF ACCOUNTS RECEIVABLE—IPALCO has sold, on a revolving basis, an undivided interest in $50 million of its accounts receivable. The subsidiary is required to maintain eligible accounts receivable of $50 million in order for the agreement to remain valid. The accounts receivable were sold on a non-recourse basis. OTHER—IPALCO has an agreement with a regulatory body that establishes certain performance measures for their system and call center reliability. If these standards are not maintained, penalties of up to $7 million per violation can be assessed. The agreement is in effect until 2004. No penalties have been incurred under the agreement in 2001. LIQUIDITY—AES believes that its sources of liquidity will be adequate to meet its needs through the end of 2002. This belief is based on a number of assumptions, including, without limitation, assumptions about exchange rates, pool prices, the ability of its subsidiaries to pay dividends and the timing and amount of asset sale proceeds. In addition, as discussed in this Note 8, AES has numerous material contingent commitments. While AES does not expect to be required to fund any material amounts under these contingent contractual obligations during 2002, many of the events which would give rise to such an obligation are beyond AES’s control. 9. COMPANY-OBLIGATED CONVERTIBLE MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS During 1997, two wholly owned special purpose business trusts (AES Trust I and AES Trust II) issued Term Convertible Preferred Securities (‘‘Tecons’’). On March 31, 1997, AES Trust I issued 5 million of $2.6875 Tecons (liquidation value $50) for total proceeds of $250 million and concurrently purchased $250 million of 5.375% junior subordinated convertible debentures due 2027 of AES (individually the 5.375% Debentures). On October 29, 1997, AES Trust II issued 6 million of $2.75 Tecons (liquidation value $50) for total proceeds of $300 million and concurrently purchased $300 million of 5.5% junior subordinated convertible debentures due 2012 of AES (individually the 5.5% Debentures). During 2000, the Company called for redemption of AES Trust I and AES Trust II. Substantially all of AES Trust I Tecons were converted into approximately 14 million shares of AES common stock and substantially all of AES Trust II Tecons were converted into approximately 11 million shares of AES common stock. During 1999, AES Trust III, a wholly owned special purpose business trust, issued 9 million of $3.375 Tecons (liquidation value $50) for total proceeds of approximately $518 million and concurrently purchased approximately $518 million of 6.75% junior subordinated convertible debentures due 2029 (individually, the 6.75% Debentures). During 2000, AES Trust VII, a wholly owned special purpose business trust, issued 9.2 million of $3.00 Tecons (liquidation value $50) for total proceeds of approximately $460 million and concurrently purchased approximately $460 million of 6% junior subordinated convertible debentures due 2008 (individually, the 6% Debentures and collectively with the 6.75% Debentures, the Junior Subordinated Debentures). The sole assets of AES Trust III and VII (collectively, the Tecon Trusts) are the Junior Subordinated Debentures. AES, at its option, can redeem the 6.75% Debentures after October 17, 2002, which would result in the required redemption of the Tecons issued by AES Trust III, for $52.10 per Tecon, reduced annually by $0.422 to a minimum of $50 per Tecon, and can redeem the 6% Debentures after May 18, 2003, which would result in the required redemption of the Tecons issued by AES Trust VII, for $51.88 93 per Tecons, reduced annually by $0.375 to a minimum of $50 per Tecon. The Tecons must be redeemed upon maturity of the Junior Subordinated Debentures. The Tecons are convertible into the common stock of AES at each holder’s option prior to October 15, 2029 for AES Trust III and May 14, 2008 for AES Trust VII at the rate of 1.4216 and 1.0811, respectively, representing a conversion price of $35.171 and $46.25 per share, respectively. Dividends on the Tecons are payable quarterly at an annual rate of 6.75% by AES Trust III and 6% by AES Trust VII. The Trusts are each permitted to defer payment of dividends for up to 20 consecutive quarters, provided that the Company has exercised its right to defer interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the Tecons would accumulate quarterly and accrue interest and the Company may not declare or pay dividends on its common stock. On November 30, 1999, three wholly owned special purpose business trusts (individually, AES RHINOS Trust I, II, and III, collectively, the Rhinos Trusts and with the Tecon Trusts, collectively the Trusts) issued trust preferred securities (‘‘Rhinos’’). The aggregate amount of Rhinos issued was approximately $250 million. Concurrent with the issuance of the Rhinos, the Rhinos Trusts purchased approximately $258 million of junior subordinated convertible notes due 2007. In October 2001, the Rhino Trusts were converted to an amortizing loan. Interest expense for each of the years ended December 31, 2001, 2000 and 1999, includes approximately $63 million, $71 million and $38 million for 2001, 2000 and 1999, respectively, related to the Tecon Trusts and approximately, $17 million, $21 million and $2 million for 2001, 2000 and 1999, respectively, related to the Rhinos Trusts. 10. MINORITY INTEREST Minority interest includes $100 million of cumulative preferred stock of subsidiaries at December 31, 2001 and 2000. In 2000, a subsidiary of the Company retired $25 million of its cumulative preferred stock at par value. The total annual dividend requirement was approximately $2 million at December 31, 2001. $22 million of the preferred stock is subject to mandatory redemption requirements over the period 2003-2008. Except for the series of preferred stock subject to mandatory redemption discussed above, each series of preferred stock is redeemable solely at the option of the issuer at prices between $101 and $118 per share. 11. STOCKHOLDERS’ EQUITY SALE OF STOCK—In May 2000, the Company sold 24.725 million shares of common stock at $37.00 per share. Net proceeds from the offering were $886 million. In November 2000, the Company sold 10 million shares of common stock at $52.50 per share. Net proceeds from the offering were $520 million. STOCK SPLIT AND STOCK DIVIDEND—On April 17, 2000, the Board of Directors authorized a two-for-one stock split, effected in the form of a stock dividend, payable to stockholders of record on May 1, 2000. Accordingly, all outstanding shares, per share and stock option data in all periods presented have been restated to reflect the stock split. SHARES ISSUED FOR ACQUISITIONS—In January 2001, the Company issued approximately 9.1 million shares valued at approximately $511 million to fund a portion of the acquisition of Gener. During March 2001, the Company issued approximately 41.5 million shares in the IPALCO pooling-of- interests transaction. During December 2000, the Company issued approximately 699,000 shares, valued at $51 million to fund the acquisition of KMR. Also, during 2000, the Company issued approximately 343,000 shares, valued at $16 million in various other acquisitions. 94 RESTRICTED STOCK—The Company issued restricted stock under various incentive stock option plans. Generally, under each plan, shares of restricted common stock with value equal to a stated percentage of participants’ base salary are initially awarded at the beginning of a three-year performance period, subject to adjustment to reflect the participants’ actual base salary. The shares remain restricted and nontransferable throughout each three-year performance period, vesting in one- third increments in each of the three years following the end of the performance period. At the end of a performance period, awards are subject to adjustment to reflect the Company’s performance compared to peer companies. Final awards under the plans can range from zero up to 400% of the initial awards. Vested shares are no longer restricted and may be held or sold by the participant. Compensation expense of $6 million, $8 million and $1 million for 2001, 2000 and 1999, respectively, as measured by the market value of the common stock at the balance sheet date, has been recognized. In January 2001, the final performance evaluation was completed for one of the restricted stocks plans resulting in final awards of an additional 199,000 shares with approximately 101,000 shares becoming fully vested. All shares of restricted stock became fully vested on the date of merger with IPALCO. Under the terms of the restricted stock plan, no additional shares will be awarded. STOCK OPTIONS—The Company has granted options to purchase shares of common stock under its stock option plans. Under the terms of the plans, the Company may issue options to purchase shares of the Company’s common stock at a price equal to 100% of the market price at the date the option is granted. The options become eligible for exercise under various schedules. At December 31, 2001, there were approximately 8.3 million shares reserved for future grants under the plans. A summary of the option activity follows (in thousands of shares): Years Ended December 31, 2001 2000 1999 Weighted Average Exercise Price Shares Weighted Average Exercise Price Shares Weighted- Average Exercise Price Shares Outstanding—beginning of year . . . . . . . . . . . . . . . . . 15,575 $16.32 16,698 $10.72 17,065 8.95 (5,069) 14.11 (2,817) Exercised during the year . . . . . . . . . . . . . . . . . . . . . (1,507) (129) 30.85 Forfeited during the year . . . . . . . . . . . . . . . . . . . . . (1,743) 42.21 36.98 4,075 17.78 Granted during the year . . . . . . . . . . . . . . . . . . . . . . 21,164 $8.83 7.45 (14) 21.83 20.16 2,464 Outstanding—end of year . . . . . . . . . . . . . . . . . . . . . 33,489 16.55 15,575 16.32 16,698 10.72 Eligible for exercise—end of year . . . . . . . . . . . . . . . 11,845 $13.38 11,449 $10.51 14,086 $9.44 The following table summarizes information about stock options outstanding at December 31, 2001 (in thousands of shares): Options Outstanding Options Exercisable Range of Exercise Prices $ 0.78 – $ 3.24 . . . . . . . . . . . . . . . . . . . . . . . $ 3.25 – $ 9.88 . . . . . . . . . . . . . . . . . . . . . . . $ 9.89 – $14.40 . . . . . . . . . . . . . . . . . . . . . . . $14.41 – $22.85 . . . . . . . . . . . . . . . . . . . . . . . $22.86 – $58.00 . . . . . . . . . . . . . . . . . . . . . . . $58.01 – $80.00 . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted- Average Remaining Life (In Years) Weighted- Average Exercise Price Total Outstanding 0.0 3.1 9.4 6.6 8.4 8.7 7.9 $ 1.60 5.20 13.03 17.93 44.06 61.42 $16.55 4 5,548 20,307 2,887 4,733 10 33,489 95 Total Exercisable 4 5,548 1,823 2,869 1,597 4 11,845 Weighted- Average Exercise Price $ 1.60 5.20 11.43 17.94 35.75 61.66 $13.38 The Company accounts for its stock-based compensation plans under Accounting Principles Board Opinion (‘‘APB’’) No. 25, ‘‘Accounting for Stock Issued to Employees,’’ and has adopted SFAS No. 123, ‘‘Accounting for Stock-based Compensation,’’ for disclosure purposes. No compensation expense has been recognized in connection with the options, as all options have been granted only to AES people, including Directors, with an exercise price equal to the market price of the Company’s common stock on the date of grant. For SFAS No. 123 disclosure purposes, the weighted average fair value of each option grant has been estimated as of the date of grant primarily using the Black-Scholes option-pricing model with the following weighted average assumptions: Interest rate (risk-free) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Years Ended December 31, 2001 4.84% 86% — 2000 5.4% 41% 1% 1999 6.5% 46% — Using these assumptions, and an expected option life of approximately 8 years, the weighted average fair value of each stock option granted was $14.87, $18.99 and $22.43, for the years ended December 31, 2001, 2000 and 1999, respectively. Had compensation expense been determined under the provisions of SFAS No. 123, utilizing the assumptions detailed in the preceding paragraph, the Company’s net income and earnings per share for the years ended December 31, 2001, 2000 and 1999 would have been reduced to the following pro forma amounts (in millions except per share amounts): NET INCOME: As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . BASIC EARNINGS PER SHARE: As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . DILUTED EARNINGS PER SHARE: As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Years Ended December 31, 2001 2000 1999 $ 273 229 $0.52 0.43 $0.51 0.43 $ 795 752 $1.66 1.56 $1.59 1.50 $ 357 341 $0.84 0.81 $0.82 0.79 The disclosures of such amounts and assumptions are not intended to forecast any possible future appreciation of the Company’s stock or change in dividend policy. As of December 31, 1999, the Company had warrants outstanding to purchase up to 2.6 million shares of common stock at $7.36 a share. These warrants expired in July 2000. Substantially all of the warrants were exercised prior to expiration. COMMON STOCK HELD BY SUBSIDIARIES—The Company has secured equity-linked loans (‘‘SELLS’’) of $350 million due in 2003 and $300 million due in 2004. The loans were issued by consolidated subsidiaries and have been classified as non-recourse debt in the accompanying consolidated balance sheets. The Company is required to maintain as collateral 2.25 times the amount of the SELLS in the form of unregistered AES common shares. Registration of the shares can only occur in the event of nonpayment or failure to maintain adequate collateral levels. An event of default under the Company’s revolver would cause a cross default in the SELLS agreements. As of December 31, 2001 and 2000, approximately 111 million and 81 million shares of the Company’s common stock, respectively, had been issued to the consolidated subsidiaries. These shares are not considered outstanding and therefore have been excluded from the calculation of earnings per share. 96 12. EARNINGS PER SHARE The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for income from continuing operations. In the table below, Income represents the numerator (in millions) and Shares represent the denominator (in millions): December 31, 2001 December 31, 2000 December 31, 1999 $ per Income Shares Share Income Shares Share Income Shares Share $ per $ per BASIC EPS Income from continuing operations . . . . . . . . . . . . . . $467 532.2 $ 0.88 $827 482.1 $ 1.72 $377 422.8 $ 0.89 EFFECT OF DILUTIVE SECURITIES: Stock options and warrants . . . . . . . . . . . . . . . . . . . . Stock units allocated to deferred compensation plans . . . Tecons and other convertible debt, net of tax . . . . . . . . — — 5 5.3 .4 5.6 (0.01) — — 22 — — 9.8 0.5 21.1 (0.04) — — (0.03) — — 9.4 0.5 — (0.02) — — DILUTED EARNINGS SHARE . . . . . . . . . . . . . . . . $472 543.5 $ 0.87 $849 513.5 $ 1.65 $377 432.7 $ 0.87 There were approximately 4,048,470 and 173,000 options outstanding in 2001 and 2000 that were omitted from the earnings per share calculation because they were antidilutive. There were no antidilutive options in 1999. 13. SALE OF ASSETS In October 1999, AES Placerita Inc. (‘‘Placerita’’), a wholly owned subsidiary of the Company, received proceeds of approximately $110 million to complete the buyout of its long-term power sales agreement. In connection with the buyout, the Company incurred transaction related costs of approximately $19 million and recorded a gain on contract buyout of $91 million. The buyout of the power sales agreement resulted in the loss of a significant customer and required the Company to assess the recoverability of the carrying amount of Placerita’s electric generation assets. The Company recorded an impairment loss of approximately $62 million to reduce the carrying value of the electric generation assets to their estimated fair value after termination of the contract. The estimated fair value was determined by an independent appraisal. Concurrent with the buyout of the power sales contract, the Company extinguished certain liabilities under the related project financing debt prior to their scheduled maturity. As a result, the Company has recorded an extraordinary loss of approximately $11 million, net of income tax of approximately $5 million. In September 1999, AES Thames Inc. (‘‘Thames’’), a wholly owned subsidiary of the Company, amended its power sales agreement with Connecticut Light and Power (‘‘CL&P’’), its sole customer. The amendment, which was subject to regulatory approval, includes a partial prepayment for certain electricity to be delivered by Thames to CL&P in the years 2001-2014. According to the terms of the amendment, the Company will receive $532 million plus accrued interest in return for a reduction in future electricity rates. Interest accrues on the prepayment at a rate of 8.3% per annum from the date of regulatory approval. In March 2000, the Connecticut Department of Public Utility Control (‘‘DPUC’’) approved the amendment to the power sales agreement. In July 2000, CL&P requested and subsequently received approval from the DPUC to issue bonds to fund the prepayment. The contractual receivable was recorded in other current assets with a corresponding amount of deferred revenue in other liabilities in the accompanying December 31, 2000 consolidated balance sheet. The deferred revenue is being amortized into income on a ratable basis over the contract term based on kilowatt hours provided. Amortization of $32 million was recorded for the year ended December 31, 2001. The contractual receivable was paid during 2001. On November 20, 2000, IPALCO sold certain assets (‘‘the Thermal Assets’’) for approximately $162 million. The transaction resulted in a gain to the Company of approximately $31 million ($19 97 million after tax). Of the net proceeds, $88 million was used to retire debt specifically assignable to the Thermal Assets. The related notes were retired in November 2000. In connection with the retirement of the debt, the Company incurred make-whole payments and wrote off debt issuance costs of approximately $4 million, which was recorded as an extraordinary loss in 2000. 14. INCOME TAXES INCOME TAX PROVISION—The provision for income taxes consists of the following (in millions): Years Ended December 31, 2001 2000 1999 Federal: Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2 10 $151 (29) $ 70 46 State: Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign: Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 11 181 26 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $230 20 (2) 11 14 208 29 $377 98 (48) $191 The Company records its share of earnings of its equity investees on a pre-tax basis. The Company’s share of the investees’ income taxes is recorded in income tax expense. EFFECTIVE AND STATUTORY RATE RECONCILIATION—A reconciliation of the U.S. statutory Federal income tax rate to the Company’s effective tax rate as a percentage of income before taxes (after minority interest) is as follows: Years Ended December 31, 2001 2000 1999 Statutory Federal tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State taxes, net of Federal tax benefit Taxes on foreign earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other-net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35% 35% 35% 1 2 (3) (5) (2) 1 4 (4) (1) Effective tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33% 31% 34% DEFERRED INCOME TAXES—Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, and (b) operating loss and tax credit carry forwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered. As of December 31, 2001, the Company had Federal net operating loss carry forwards for tax purposes of approximately $412 million expiring from 2008 through 2021, Federal general business tax credit carry forwards for tax purposes of approximately $49 million expiring in years 2005 through 2021, and Federal alternative minimum tax credits of approximately $53 million that carry forward without expiration. As of December 31, 2001, the Company had foreign net operating loss carry forwards of approximately $1.1 billion that expire at various times beginning in 2002, and some of which carry forward without expiration, and foreign investment and assets tax credits of approximately $33 million 98 that expire at various times beginning in 2002 through 2006. The Company had state net operating loss carry forwards as of December 31, 2001, of approximately $540 million expiring in years 2001 through 2021, and state tax credit carry forwards of approximately $5 million expiring in years 2002 through 2010. The valuation allowance decreased by $2 million during 2001 to $117 million at December 31, 2001. This decrease was primarily the result of the utilization of certain foreign net operating loss carry forwards for which a valuation allowance had previously been established. The Company believes that it is more likely than not that the remaining deferred tax assets as shown below will be realized. Deferred tax assets and liabilities are as follows (in millions): December 31, 2001 2000 Differences between book and tax basis of property and total deferred tax liability . . . $2,671 $2,562 Operating loss carry forwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bad debt and other book provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Retirement costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tax credit carry forwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other deductible temporary differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (482) (107) (79) (139) (337) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total gross deferred tax asset Less: Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,144) 117 (328) (104) (75) (162) (316) (985) 119 Total net deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,027) (866) Net deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,644 $1,696 Undistributed earnings of certain foreign subsidiaries and affiliates aggregated approximately $1.2 billion and $777 million at December 31, 2001 and 2000, respectively. The Company considers these earnings to be indefinitely reinvested outside of the United States and, accordingly, no U.S. deferred taxes have been recorded with respect to such earnings. Should the earnings be remitted as dividends, the Company may be subject to additional U.S. taxes, net of allowable foreign tax credits. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings. A deferred tax asset of $192 million has been recorded as of December 31, 2001 for the cumulative effects of certain foreign currency translation losses. Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The reduced tax rates for these operations will be in effect for the life of the related businesses, at the end of which ownership transfers back to the local government. The income tax benefits related to the tax status of these operations are estimated to be $33 million, $29 million and $27 million for the years ended December 31, 2001, 2000 and 1999, respectively. Income from continuing operations before income taxes consisted of the following: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . U.S. Non U.S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Years Ended December 31, 2001 $336 361 $697 2000 $ 631 573 $1,204 1999 376 192 $568 99 15. BENEFIT PLANS PROFIT SHARING AND STOCK OWNERSHIP PLANS—The Company sponsors two defined contribution plans, qualified under section 401 of the Internal Revenue Code, which are available to eligible AES people. The plans provide for Company matching contributions, other Company contributions at the discretion of the Compensation Committee of the Board of Directors, and discretionary tax deferred contributions from the participants. Participants are fully vested in their own contributions and the Company’s matching contributions. Participants vest in other Company contributions ratably over a five-year period ending on the 5th anniversary of their hire date. Company contributions to the plans were approximately $13 million, $11 million and $7 million for the years ended December 31, 2001, 2000 and 1999, respectively. DEFERRED COMPENSATION PLANS—The Company sponsors a deferred compensation plan under which directors of the Company may elect to have a portion, or all, of their compensation deferred. The amounts allocated to each participant’s compensation account may be converted into common stock units. Upon termination or death of a participant, the Company is required to distribute, under various methods, cash or the number of shares of common stock accumulated within the participant’s deferred compensation account. Distribution of stock is to be made from common stock held in treasury or from authorized but previously unissued shares. The plan terminates and full distribution is required to be made to all participants upon any change of control of the Company (as defined in the plan document). No stock associated with distributions was issued during 2001 under such plan. In addition, the Company sponsors an executive officers’ deferred compensation plan. At the election of an executive officer, the Company will establish an unfunded, nonqualified compensation arrangement for each officer who chooses to terminate participation in the Company’s profit sharing and employee stock ownership plans. The participant may elect to forego payment of any portion of his or her compensation and have an equal amount allocated to a contribution account. In addition, the Company will credit the participant’s account with an amount equal to the Company’s contributions (both matching and profit sharing) that would have been made on such officer’s behalf if he or she had been a participant in the profit sharing plan. The participant may elect to have all or a portion of the Company’s contributions converted into stock units. Dividends paid on common stock are allocated to the participant’s account in the form of stock units. The participant’s account balances are distributable upon termination of employment or death. The Company also sponsors a supplemental retirement plan covering certain highly compensated AES people. The plan provides incremental profit sharing and matching contributions to participants that would have been paid to their accounts in the Company’s profit sharing plan if it were not for limitations imposed by income tax regulations. All contributions to the plan are vested in the manner provided in the Company’s profit sharing plan, and once vested are nonforfeitable. The participant’s account balances are distributable upon termination of employment or death. DEFINED BENEFIT PLANS—Certain of the Company’s subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Pension benefits are based on years of credited service, age of the participant and average earnings. Of the twelve defined benefit plans, six are at U.S. subsidiaries and the remaining are at foreign subsidiaries. 100 Significant weighted average assumptions used in the calculation of pension benefits expense and obligation are as follows: Pension Benefits Years Ended December 31, 2001 2000 1999 Discount rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rates of compensation increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected long-term rate of return on plan assets . . . . . . . . . . . . . . . . . . . 7% 3% 9% 8% 3% 9% 8% 4% 9% A subsidiary of the Company has a defined benefit plan, which has a benefit obligation of $383 million and $320 million at December 31, 2001 and 2000, respectively, and uses salary bands to determine future benefit costs rather than rate of compensation increases. As such, rates of compensation increase in the table above do not include amounts relating to this specific defined benefit plan. Total pension cost for the years ended December 31, 2001, 2000 and 1999 includes the following components (in millions): Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost on projected benefit obligation . . . . . . . . . . . . . . . . . . . . . . Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amount of curtailment loss recognized . . . . . . . . . . . . . . . . . . . . . . . . . . VERP benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total pension cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pension Costs Years Ended December 31, 2001 $ 9 57 (54) 6 19 2 $ 39 2000 $ 14 55 (63) 6 57 (3) $ 66 1999 $ 13 29 (16) — — (3) $ 23 The changes in the benefit obligation of the plans combined for the years ended December 31, 2001 and 2000 are as follows (in millions): CHANGE IN BENEFIT OBLIGATION: Benefit obligation at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of foreign currency exchange rate change on beginning balance . . . . . . . . . . . . . Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Assumed in acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VERP benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2001 2000 $ 810 (22) 9 57 4 19 (58) 61 (11) $ 650 (10) 14 55 71 57 (48) 19 2 Benefit obligation as of December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 869 $ 810 101 The changes in the plan assets of the plans combined for the years ended December 31, 2001 and 2000 are as follows (in millions): CHANGE IN PLAN ASSETS: Fair value of plan assets at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of foreign currency exchange rate change on beginning balance . . . . . . . . . . . . . Actual return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2001 2000 $ 685 (6) (32) (58) 15 $ 714 (6) 12 (48) 13 Fair value of plan assets as of December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 604 $ 685 The funded status of the plans combined for the years ended as of December 31, 2001 and 2000 are as follows (in millions): Funded status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unrecognized net actuarial gain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(265) $(125) (84) 3 53 2 Accrued benefit cost as of December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(210) $(206) 2001 2000 All of the Company’s pension plans have been aggregated in the table above. All of the Company’s plans at December 31, 2001, had benefit obligations exceeding the fair value of the related plan’s assets. As of December 31, 2000, the Company had plans with benefit obligations exceeding the fair values of plan assets by approximately $165 million. In November 2000, a subsidiary of the Company implemented a Voluntary Early Retirement Program (‘‘VERP’’). This program offers enhanced retirement benefits upon early retirement to eligible employees. The VERP was available to all employees, except officers, whose combined age and years of service will total at least 75 on June 30, 2001. Participation was limited to, and subsequently accepted by 400 qualified employees. Participants elected actual retirement dates in 2001. Additionally, the post-retirement benefits will be provided to VERP retirees until age 55 at which time they will be eligible to receive benefits from the independent Voluntary Employee Benefit Association trustee. The subsidiary recognized the $19 million and $57 million pre-tax non-cash pension benefit costs of the VERP in 2001 and 2000, respectively. During 2000, a subsidiary of the Company curtailed one of its defined benefit plans. In connection with the curtailment, the subsidiary paid approximately $8 million and transferred approximately $145 million of plan assets to an independent trustee. 16. SEGMENTS The Company operates in four business segments: contract generation, competitive supply, large utilities and growth distribution businesses. Contract generation businesses are businesses that supply wholesale electricity under long-term contracts for more than 75% of their output, and these businesses generally have little exposure to commodity price risk. Competitive supply businesses are businesses that supply electricity, both wholesale and retail, pursuant to short-term contracts or into spot electricity markets. Competitive supply businesses are generally exposed to commodity price risk. Large utility businesses are utilities of significant size that maintain a monopoly franchise within a defined service area, and these businesses are generally subjected to extensive regulation in their respective jurisdiction. Growth distribution businesses are distribution businesses that offer significant potential for growth because they face particular challenges related to operational difficulties such as outdated 102 equipment, significant non-technical losses, cultural problems, emerging economics, unstable governments or location in a developing nation that allow for operating improvements that would result in financial performance improvement that are typically greater that those seen in the large utility business. Although the nature of the product is the same, the segments are differentiated by the nature of the customers, operational differences and risk exposure. All balance sheet information for businesses that were discontinued during the year are broken out and shown separately in the chart below. All income statement related information is shown in the line ‘‘Discontinued operations’’ in the accompanying consolidated statements of operations. The accounting policies of the four business segments are the same as those described in Note 1-General and Summary of Significant Accounting Policies. The Company uses gross margin to evaluate the performance of its business segments. Depreciation and amortization at the business segments are included in the calculation of gross margin. Corporate depreciation and amortization is reported within selling, general and administrative expenses in the consolidated statements of operations. Pre-tax equity in earnings is used to evaluate the performance of businesses that are significantly influenced by the Company. Sales between the segments are accounted for at fair value as if the sales were to third parties. All intersegment activity has been eliminated with respect to revenue and gross margin. The Company previously reported two business segments. All prior year amounts have been restated to reflect four business segments. Information about the Company’s operations and assets by segment is as follows (in millions): Total Revenues(1) Amortization Margin Earnings Assets Depreciation and Pre-Tax Gross Equity in Investment in and Advances to Property Additions Affiliates Year Ended December 31, 2001 Contract Generation . . . . . . . . . . . . . . Competitive Supply . . . . . . . . . . . . . . . Large Utilities . . . . . . . . . . . . . . . . . . Growth Distribution . . . . . . . . . . . . . . Discontinued Businesses . . . . . . . . . . . . Corporate . . . . . . . . . . . . . . . . . . . . . $2,466 2,729 2,444 1,688 — — Total . . . . . . . . . . . . . . . . . . . . $9,327 $260 196 289 111 — 3 $859 $ 827 440 739 296 — — $ 54 (6) 140 (13) — — $12,306 10,335 9,351 4,300 17 427 $ 729 46 2,292 12 — 21 $2,302 $175 $36,736 $3,100 $ 977 1,684 420 89 — 3 $3,173 Total Revenues(1) Amortization Margin Earnings Assets Depreciation and Pre-Tax Gross Equity in Investment in and Advances to Property Additions Affiliates Year Ended December 31, 2000 Contract Generation . . . . . . . . . . . . . . Competitive Supply . . . . . . . . . . . . . . . Large Utilities . . . . . . . . . . . . . . . . . . Growth Distribution . . . . . . . . . . . . . . Discontinued Businesses . . . . . . . . . . . . Corporate . . . . . . . . . . . . . . . . . . . . . $1,750 2,395 2,113 1,276 — — Total . . . . . . . . . . . . . . . . . . . . $7,534 $166 171 278 84 — 1 $700 $ 767 559 538 131 — — $1,995 $ 49 — 426 — — — $475 $10,310 8,566 9,826 3,886 160 290 $ 517 67 2,485 23 — 30 $33,038 $3,122 $1,244 700 114 147 21 — $2,226 103 Total Revenues(1) Amortization Margin Earnings Assets Depreciation and Pre-Tax Gross Equity in Investment in and Advances to Property Additions Affiliates Year Ended December 31, 1999 Contract Generation . . . . . . . . . . . . . . Competitive Supply . . . . . . . . . . . . . . . Large Utilities . . . . . . . . . . . . . . . . . . Growth Distribution . . . . . . . . . . . . . . Corporate . . . . . . . . . . . . . . . . . . . . . $1,304 873 992 948 — Total . . . . . . . . . . . . . . . . . . . . $4,117 $119 61 140 79 1 $400 $ 551 245 282 185 — $ 60 — (31) — — $ 6,736 7,744 5,415 3,158 145 $ 531 1 1,042 1 — $1,263 $ 29 $23,198 $1,575 $ 534 199 103 102 — $ 938 (1) Intersegment revenues for the years ended December 31, 2001, 2000, and 1999 were $134 million, $81 million and $76 million, respectively. Revenues are recorded in the country in which they are earned and assets are recorded in the country in which they are located. Information about the Company’s consolidated operations and long- lived assets by country are as follows (in millions): Revenues Property, Plant and Equipment, net 2001 2000 1999 2001 2000 1999 United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,522 $3,353 $2,056 $ 8,169 $ 6,727 $ 5,636 4,518 United Kingdom . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,283 Brazil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,031 Argentina . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Chile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Venezuela . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 210 Dominican Republic . . . . . . . . . . . . . . . . . . . . . . . . . 73 El Salvador . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 369 Pakistan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Colombia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120 Hungary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,026 Other Non-U.S.(1) . . . . . . . . . . . . . . . . . . . . . . . . . . 4,162 207 1,958 376 452 1,724 — 1,023 — 2,369 424 250 301 481 97 2,476 4,447 2,076 1,551 — 2,218 225 153 319 41 91 1,394 1,110 695 482 — 494 333 139 232 — 177 519 1,130 895 483 446 806 391 341 231 124 175 783 170 80 206 — 212 358 Total Non-U.S. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,805 4,181 2,061 15,265 12,515 9,630 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $9,327 $7,534 $4,117 $23,434 $19,242 $15,266 (1) AES has operations in 18 countries, which are included in this category. 17. FAIR VALUE OF FINANCIAL INSTRUMENTS The fair value of current financial assets, current financial liabilities, and debt service reserves and other deposits, are estimated to be equal to their reported carrying amounts. The fair value of non- recourse debt, excluding capital leases, is estimated differently based upon the type of loan. For variable rate loans, carrying value approximates fair value. For fixed rate loans and preferred stock with mandatory redemption, other than securities registered and publicly traded, the fair value is estimated using discounted cash flow analyses based on the Company’s current incremental borrowing rates. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards and swaps, and energy derivatives is the estimated net amount that the Company would receive or pay to terminate the agreements as of the balance sheet date. The estimated fair values for certain of the notes and bonds included in non-recourse debt, and certain of the recourse debt and Tecons, which are registered and publicly traded, are based on quoted market prices. 104 The estimated fair values of the Company’s assets and liabilities have been determined using available market information. The estimates are not necessarily indicative of the amounts the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. The estimated fair values of the Company’s debt and derivative financial instruments as of December 31, 2001 and 2000 are as follows (in millions): December 31, 2001 December 31, 2000 Carrying Amount Fair Value Carrying Amount Fair Value Assets: Foreign currency forwards and swaps, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Energy derivatives, net $ $ 14 7 $ 14 7 $ 10 25 14 (2) Liabilities: Non-recourse debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $16,857 $17,064 $15,158 $15,384 Recourse debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tecons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest rate caps and floors, net . . . . . . . . . . . . . . . . . . . . . . Preferred stock with mandatory redemption . . . . . . . . . . . . . . 5,401 978 166 72 22 4,730 626 166 72 22 3,458 1,228 2 2 22 3,343 1,624 141 7 20 The fair value estimates presented herein are based on pertinent information as of December 31, 2001 and 2000. The Company is not aware of any factors that would significantly affect the estimated fair value amounts since December 31, 2001. 18. NEW ACCOUNTING PRONOUNCEMENTS In June 2001, the FASB issued SFAS No. 142, ‘‘Goodwill and Other Intangible Assets.’’ The provisions of this statement are required to be applied starting with fiscal years beginning after December 15, 2001. This statement is required to be applied at the beginning of an entity’s fiscal year and to be applied to all goodwill and other intangible assets recognized in its financial statements at that date. SFAS No. 142 addresses how intangible assets (but not those acquired in a business combination) should be accounted for in financial statements upon their acquisition. This statement also addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. The statement requires that goodwill and certain other intangibles with an indefinite life, as defined in the standard, no longer be amortized. However, goodwill and intangibles would have to be assessed each year to determine whether an impairment loss has occurred. Any impairments recognized upon adoption would be recorded as a change in accounting principle. Future impairments would be recorded in income from continuing operations. The statement provides specific guidance for testing goodwill for impairment. The Company had $3.2 billion of goodwill at December 31, 2001. Goodwill amortization was $62 million for the year ended December 31, 2001. The Company is currently assessing the impact of SFAS No. 142 on its financial position and results of operations. In June 2001, the FASB issued SFAS No. 143, ‘‘Accounting for Asset Retirement Obligations,’’ which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. The statement requires recognition of legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) the normal operation of a long-lived asset, except for certain obligations of lessees. The Company is currently assessing the impact of SFAS No. 143 on its financial position and results of operations. ***************** 105 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) The following table summarizes the unaudited quarterly statements of operations for the Company for 2001 and 2000, giving effect to the acquisition of IPALCO as if it had occurred at the beginning of the earliest period presented (in millions, except per share amounts). Additionally, the amounts have been adjusted for the early implementation of SFAS No. 144. Quarter Ended 2001 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extraordinary items, net of tax benefit . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Basic earnings per share: Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mar 31 Jun 30 Sep 30 Dec 31 $2,495 637 120 (9) — 111 $2,184 469 144 (29) — 115 $2,261 514 13 (10) — 3 $2,387 682 190 (146) — 44 $ 0.23 (0.02) $ 0.27 (0.05) $ 0.02 (0.02) $ 0.36 (0.27) Basic earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.21 $ 0.22 $ 0.00 $ 0.09 Diluted earnings per share: (1) Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.22 (0.02) $ 0.27 (0.05) $ 0.02 (0.02) $ 0.35 (0.27) Diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.20 $ 0.22 $ 0.00 $ 0.08 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extraordinary items, net of tax benefit . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Basic earnings per share: Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extraordinary items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quarter Ended 2000 Mar 31 Jun 30 Sep 30 Dec 31 $1,692 478 275 (1) (7) 267 $1,744 400 144 (4) — 140 $1,981 532 171 (7) — 164 $2,117 585 237 (9) (4) 224 $ 0.61 (0.00) (0.01) $ 0.30 (0.01) — $ 0.34 (0.01) $ 0.47 (0.02) — (0.01) Basic earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.60 $ 0.29 $ 0.33 $ 0.44 Diluted earnings per share: Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extraordinary items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.57 (0.00) (0.01) $ 0.29 (0.01) — $ 0.33 (0.01) $ 0.46 (0.02) — (0.01) Diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.56 $ 0.28 $ 0.32 $ 0.43 (1) The sum of these amounts does not equal the annual amount due to rounding or because the quarterly calculations are based on varying numbers of shares outstanding. ITEM 9—CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. 106 PART III ITEM 10—DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. See the information with respect to the ages of the Registrant’s directors in the table and the information contained under the caption ‘‘Election of Directors’’ on pages 1 through 5, inclusive, of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 25, 2002, which information is incorporated herein by reference. See also the information with respect to executive officers of the Registrant under the caption entitled ‘‘Executive Officers and Significant Employees of the Registrant’’ in Item 1 of Part I hereof, which information is incorporated herein by reference. ITEM 11—EXECUTIVE COMPENSATION. See the information contained under the captions ‘‘Compensation of Executive Officers’’ and ‘‘Compensation of Directors’’ of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 25, 2002, which is incorporated herein by reference. ITEM 12—SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. (a) Security Ownership of Certain Beneficial Owners. See the information contained under the caption ‘‘Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers’’ of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 25, 2002, which information is incorporated herein by reference. (b) Security Ownership of Directors and Executive Officers. See the information contained under the caption ‘‘Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers’’ of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 25, 2002, which information is incorporated herein by reference. (c) Changes in Control. None. ITEM 13—CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. See the information contained under the caption ‘‘Related Party Transactions’’ of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 25, 2002, which information is incorporated herein by reference. 107 ITEM 14—EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K. (a) 1. Financial Statements. The following Consolidated Financial Statements of The AES Corporation are filed under ‘‘Item 8. Financial Statements and Supplementary Data.’’ PART IV Consolidated Balance Sheets as of December 31, 2001 and 2000 Consolidated Statements of Operations for the years ended December 31, 2001, 2000 and 1999 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999 Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2001, 2000 and 1999 Notes to Consolidated Financial Statements 2. Financial Statement Schedules. See Index to Financial Statement Schedules of the Registrant and subsidiaries at page S-1 hereof, which index is incorporated herein by reference. (b) Exhibits. 3.1 3.2 4.1 10.1 10.2 10.5 10.6 10.7 Sixth Amended and Restated Certificate of Incorporation of The AES Corporation is incorporated herein by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q of the Registrant for the quarterly period ended June 30, 1998 filed August 14, 1998. By-Laws of The AES Corporation, as amended. There are numerous instruments defining the rights of holders of long-term indebtedness of the Registrant and its consolidated subsidiaries, none of which exceeds ten percent of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any of such agreements to the Commission upon request. Amended Power Sales Agreement, dated as of December 10, 1985, between Oklahoma Gas and Electric Company and AES Shady Point, Inc. is incorporated herein by reference to Exhibit 10.5 to the Registration Statement on Form S-1 (Registration No. 33-40483). First Amendment to the Amended Power Sales Agreement, dated as of December 19, 1985, between Oklahoma Gas and Electric Company and AES Shady Point, Inc. is incorporated herein by reference to Exhibit 10.45 to the Registration Statement on Form S-1 (Registration No. 33-46011). The AES Corporation Profit Sharing and Stock Ownership Plan is incorporated herein by reference to Exhibit 4(c)(1) to the Registration Statement on Form S-8 (Registration No. 33-49262). The AES Corporation Incentive Stock Option Plan of 1991, as amended, is incorporated herein by reference to Exhibit 10.30 to the Annual Report on Form 10-K of the Registrant for the fiscal year ended December 31, 1995. Applied Energy Services, Inc. Incentive Stock Option Plan of 1982 is incorporated herein by reference to Exhibit 10.31 to the Registration Statement on Form S-1 (Registration No. 33-40483). 108 10.8 10.9 Deferred Compensation Plan for Executive Officers, as amended, is incorporated herein by reference to Exhibit 10.32 to Amendment No. 1 to the Registration Statement on Form S-1 (Registration No. 33-40483). Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q of the Registrant for the quarter ended March 31, 1998, filed May 15, 1998. 10.10 The AES Corporation Stock Option Plan for Outside Directors is incorporated herein by reference to Exhibit 10.43 to the Annual Report on Form 10-K of Registrant for the Fiscal Year ended December 31, 1991. 10.11 The AES Corporation Supplemental Retirement Plan is incorporated herein by reference to Exhibit 10.64 to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 1994. 10.12 The AES Corporation 2001 Stock Option Plan is incorporated herein by reference to Exhibit 10.12 to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2000. 10.13 Second Amended and Restated Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.13 to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2000. 12 21.1 23.1 23.2 24 Statement of computation of ratio of earnings to fixed charges. Significant subsidiaries of The AES Corporation. Consent of Independent Auditors, Deloitte & Touche LLP. Consent of Independent Auditors, Arthur Andersen. Power of Attorney. (c) Reports on Form 8-K. Registrant filed a Current Report on Form 8-K dated October 26, 2001 related to the Company’s results of operations for the quarter ended September 30, 2001. 109 Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, as amended, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES THE AES CORPORATION (Company) Date: March 25, 2002 By: /s/ WILLIAM R. LURASCHI Name: William R. Luraschi Title: Senior Vice President, Secretary and General Counsel Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated. Name * (Roger W. Sant) * (Dennis W. Bakke) * (Hazel R. O’Leary) * (Dr. Alice F. Emerson) * (Robert F. Hemphill, Jr.) * (Frank Jungers) * (John H. McArthur) Title Date Chairman of the Board March 25, 2002 President, Chief Executive Officer (principal executive officer) and Director March 25, 2002 Director March 25, 2002 Director March 25, 2002 Director March 25, 2002 Director March 25, 2002 Director March 25, 2002 110 Name * (Thomas I. Unterberg) * (Robert H. Waterman, Jr.) /s/ BARRY S. SHARP (Barry J. Sharp) Title Date Director March 25, 2002 Director March 25, 2002 Executive Vice President, Chief Operating Officer and Chief Financial Officer (principal financial and accounting officer) March 25, 2002 *By: /s/ WILLIAM R. LURASCHI March 25, 2002 Attorney-in-fact 111 THE AES CORPORATION AND SUBSIDIARIES INDEX TO CONSOLIDATED FINANCIAL STATEMENT SCHEDULES . . . . . . . . . . . . . . Schedule I—Condensed Financial Information of Registrant Schedule II—Valuation and Qualifying Accounts . . . . . . . . . . . . . . . . . . . . . . . S-2 S-7 Schedules other than those listed above are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof. S-1 THE AES CORPORATION SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF UNCONSOLIDATED BALANCE SHEETS (IN MILLIONS) ASSETS Current Assets: Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts and notes receivable from subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Investment in and advances to subsidiaries and affiliates . . . . . . . . . . . . . . . . . . . . Office Equipment: Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Office equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Assets: Deferred financing costs (less accumulated amortization: 2001, $39 2000, $22) . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2001 2000 $ 45 3,093 12 22 3,172 8,697 $ 73 2,372 2 5 2,452 7,726 9 (2) 7 105 60 165 6 (2) 4 99 28 127 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12,041 $10,309 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities: Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued and other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Term bank loan – current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior notes payable – current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ 123 188 300 Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term Liabilities: Revolving Bank Loan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Term loan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior notes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior subordinated notes and debentures payable . . . . . . . . . . . . . . . . . . . . . . . . Junior subordinated notes and debentures payable . . . . . . . . . . . . . . . . . . . . . . . . Redeemable or remarketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stockholders’ Equity: Preferred stock Common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Additional paid-in capital Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,539 5,542 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12,041 $10,309 See notes to Schedule I S-2 2 71 — — 73 140 — 2,099 1,069 1,386 — 4,694 611 70 425 2,996 1,072 1,128 200 5,891 5 5,225 2,809 — (2,500) 5 5,172 2,551 (507) (1,679) THE AES CORPORATION SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF UNCONSOLIDATED OPERATIONS (IN MILLIONS) For the Years Ended December 31, 2001 2000 1999 Revenues from subsidiaries and affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity in earnings of subsidiaries and affiliates . . . . . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative expenses . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 164 340 127 (34) (367) $ 116 884 122 (21) (255) $ 85 395 89 (44) (172) Income before income taxes and extraordinary item . . . . . . . . . . . . . . . . . . . . Income tax (benefit) expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income before extraordinary item . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extraordinary item-loss on extinguishment of debt net of applicable 230 (43) 273 846 44 802 353 (4) 357 income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (7) — Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 273 $ 795 $ 357 See notes to Schedule I S-3 THE AES CORPORATION SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF UNCONSOLIDATED CASH FLOWS (IN MILLIONS) Net cash provided by (used in) operating activities . . . . . . . . . . . . . . . . Investing Activities Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Project development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Investment in and advances to subsidiaries . . . . . . . . . . . . . . . . . . . . . . Escrow deposits and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Additions to property, plant and equipment For the Years Ended December 31, 2001 2000 1999 $ 1,038 $ (37) $ (252) (1,448) — (1,283) — (3) (2,584) (7) (127) 3 2 (2,024) (26) (622) (3) — Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,734) (2,713) (2,675) Financing Activities (Repayments) borrowings under the revolver, net . . . . . . . . . . . . . . . . . Issuance of notes payable and other coupon bearing securities, net . . . . . Proceeds from issuance of common stock, net . . . . . . . . . . . . . . . . . . . . Payments for deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . (Decrease) increase in cash and cash equivalents . . . . . . . . . . . . . . . . . . Cash and cash equivalents, beginning of year . . . . . . . . . . . . . . . . . . . . (70) 1,754 14 (30) 1,668 (28) 73 (195) 1,610 1,449 (50) 2,814 64 9 102 1,524 1,305 (39) 2,892 (35) 44 Cash and cash equivalents, ending of year . . . . . . . . . . . . . . . . . . . . . . . $ 45 $ 73 $ 9 See notes to Schedule I S-4 THE AES CORPORATION SCHEDULE I NOTES TO SCHEDULE I 1. Application of Significant Accounting Principles Accounting for Subsidiaries and Affiliates—The AES Corporation (‘‘the Company’’) has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated condensed financial information. Revenues—Construction management fees earned by the parent from its consolidated subsidiaries are eliminated. Income Taxes—The unconsolidated income tax expense or benefit computed for the Company in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, reflects the tax assets and liabilities of the Company on a stand-alone basis and the effect of filing a consolidated U.S. income tax return with certain other affiliated companies. Accounts and Notes Receivable from Subsidiaries—Such amounts have been shown in current or long-term assets based on terms in agreements with subsidiaries, but payment is dependent upon meeting conditions precedent in the subsidiary loan agreements. Reclassifications—Certain reclassifications have been made to conform with the 2001 presentation. S-5 2. Notes Payable Revolving Bank Loan: First Call Date(1) December 31 2001 2000 Variable rate revolving bank loan due 2003 . . . . . . . . . . . . . . . . . . . . . . 2000 $ 70 $ 140 Term Loans: Term loan due 2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Term loan due 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior Notes Payable: 8.75% Senior notes due 2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.00% Senior notes due 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.75% Senior notes due 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.50% Senior notes due 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.38% Senior notes due 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.88% Senior notes due 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.38% Senior notes due 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Remarketable or Redeemable Securities due 2013 . . . . . . . . . . . . . . . . . Unamortized discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2002 2000 — — — — — 2003 188 425 613 300 200 400 750 850 600 196 200 — — — — 300 200 — 750 850 — — — (1) Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,496 2,099 Senior Subordinated Notes and Debentures Payable: 10.25% Senior subordinated notes due 2006 . . . . . . . . . . . . . . . . . . . . . 8.38% Senior subordinated notes due 2007 . . . . . . . . . . . . . . . . . . . . . . 8.50% Senior subordinated notes due 2007 . . . . . . . . . . . . . . . . . . . . . . 8.88% Senior subordinated debentures due 2027 . . . . . . . . . . . . . . . . . . Unamortized discounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2001 2002 2002 2004 250 325 375 125 (3) 250 325 375 125 (6) Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,072 1,069 Junior Subordinated Notes and Debentures Payable: 4.50% Convertible junior subordinated notes due 2005 . . . . . . . . . . . . . 6.00% Convertible junior subordinated debentures due 2008 . . . . . . . . . 6.75% Convertible junior subordinated debentures due 2029 . . . . . . . . . Variable rate convertible junior subordinated debentures due 2007 . . . . . 2001 2003 2002 1999 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150 460 518 — 150 460 518 258 1,128 6,379 1,386 4,694 (488) — $5,891 $4,694 (1) Except for the Remarketable or Redeemable Securities, which are discussed below, the first call date represents the date that the Company, at its option, can call the related debt. In May 2001, the Company issued $200 million of Remarketable or Redeemable Securities (‘‘ROARS’’). The ROARS are scheduled to mature on June 15, 2013, but such maturity date may be adjusted to a date, which shall be no later than June 15, 2014. On the First Remarketing Date (June 15, 2003) or subsequent Remarketing dates thereafter, the remarketing agent, or the Company, may elect to redeem the ROARS at 100% of the aggregate principal amount and unpaid interest, plus S-6 a premium in certain circumstances. The Company at its option, may also redeem the ROARS subsequent to the First Remarketing Date at any time. Interest on the ROARS accrues at 7.375% until the First Remarketing Date, and thereafter is set annually based on market rate bids, with a floor of 5.5%. The ROARS are senior notes. Future maturities of debt—Scheduled maturities of total debt at December 31, 2001 are (in millions): 2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 488 495 — 150 250 4,996 TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $6,379 3. Dividends from Subsidiaries and Affiliates Cash dividends received from consolidated subsidiaries and from affiliates accounted for by the equity method were as follows (in millions): Subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,038 21 $428 100 $180 51 2001 2000 1999 THE AES CORPORATION SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS (IN MILLIONS) Additions Deductions Balance at Charged to Beginning of Costs and Acquisitions/ Expenses Sale of Business Adjustment Translation Written Allowance for accounts receivables: Year ended December 31, 1999 . . . . . . . . . . Year ended December 31, 2000 . . . . . . . . . . Year ended December 31, 2001 . . . . . . . . . . Period $59 104 201 Amounts Balance at Off $(10) (21) (32) End of Period $104 201 251 $ 8 72 137 $68 47 (50) $(21) (1) (5) S-7