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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)

Registrant's telephone number, including area code: (703) 522-1315

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

        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 ý No o

        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. o

        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,

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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.

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        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.

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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.



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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.



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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.



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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.

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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.



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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.



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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.



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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.



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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.



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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.



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Successful and timely completion of pending and future acquisitions; conducting appropriate due diligence; assumptions regarding the performance of countries, markets, and models.



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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.



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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.

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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.



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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.



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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.



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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:

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Supplying energy to customers at the lowest cost possible, taking into account factors such as reliability and environmental performance;



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Constructing, acquiring and operating projects of a relatively large size in geographically dispersed markets;



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To the extent available, maximizing the amount of non-recourse financing;



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When available, entering into longer-term power sales contracts or other arrangements with electric utilities or other customers with significant credit strength;

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Where possible, participating in distribution markets that grant concessions with long-term pricing arrangements; and



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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.

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        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

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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

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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 São 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 São 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 São Paulo.

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        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.

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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.

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13

14

15

*

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

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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

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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.

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        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

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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.

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        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

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"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

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(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 BBB-/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.

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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

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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.

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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

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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

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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

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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")

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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

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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

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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.

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PART II

ITEM 5—MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER 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

(b) Holders.

        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.

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ITEM 6—SELECTED FINANCIAL DATA

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.

        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.

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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.

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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.

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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:

        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.

*

Includes Venezuela and Colombia.

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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.

        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.

*

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.

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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

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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

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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.