Item 1—Business

Overview

The AES Corporation (including all its subsidiaries and affiliates, and collectively referred to herein as "AES" or the "Company" or "we"), founded in 1981, is a leading global power company. The Company's goal is to help meet the world's need for electric power in ways that benefit all of our stakeholders. AES participates primarily in four lines of business: contract generation, competitive supply, large utilities and growth distribution.

Mission Statement

The Company's goal is to help meet the world's need for electric power in ways that benefit all of our stakeholders, to build long-term value for the Company's shareholders, and to assure sustained performance and viability of the Company for its owners, employees and other individuals and organizations who depend on the Company. To achieve this goal, the Company has taken steps to improve performance and achieve excellence in the operation and management of each and every AES business, including the implementation of a compensation system which is dependent, in part, on each individual within AES meeting performance goals and targets. The Company shall continue to be guided by the four shared values that helped shape the Company's culture: Integrity, Fairness, Fun and Social Responsibility.

Contract Generation

AES's contract generation line of business consists of multiple power generation facilities located around the world. Provided that the counterparty's credit remains viable, these facilities have contractually limited their exposure to commodity price risks and electricity price volatility by entering into long-term (five years or longer) power purchase agreements for 75% or more of their 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 must 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 counterparty directly provides the necessary fuel and markets the resulting power output generated. However, not all businesses within AES's contract generation line of business have the same degree of contractually limited exposure, and therefore, the degree of predictability may vary from business to business.

Competitive Supply

AES's competitive supply line of business consists of generating facilities that sell electricity directly to wholesale 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 are unpredictable and can be, and from time to time have been, volatile. The results of operations of AES's competitive supply business are also more sensitive to the impact of market fluctuations in the price of electricity, natural gas, coal and other raw materials, and these businesses also have higher needs for credit support of their operations.

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Large Utilities

AES's large utility business is comprised of three utilities located in three countries: the U.S. (IPALCO Enterprises, Inc. ("IPALCO")), Brazil (Eletropaulo Metropolitana Electricidade de Sao Paulo S.A. ("Eletropaulo")) and Venezuela (C.A. La Electricidad de Caracas ("EDC")). AES's equity interest in each of these utilities is over 70%. All of these utilities are significant in size, and all 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 regulated tariff or concession agreements and to a lesser extent from contractual agreements of varying lengths and provisions. The results of operations of AES's large utility businesses are sensitive to changes in economic growth, abnormal weather conditions affecting their market and regulatory changes.

Growth Distribution

AES's growth distribution line of business includes distribution facilities located in developing countries or regions where the demand for electricity is expected to grow at a higher rate than in more developed parts of the world. However, these businesses face particular challenges associated with their presence in developing countries such as outdated equipment, significant theft-related losses, cultural problems associated with safety and non-payment, emerging economies and 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 other business segments. Distribution facilities in this line of business may include integrated generation, transmission, distribution or related services companies. The results of operations of AES's growth distribution business are sensitive to changes in economic growth, abnormal weather conditions affecting their market and regulatory changes, as well as the success of the operational changes implemented.

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Strategic Initiatives

In 2002, the company changed certain senior management positions, including the Chief Executive Officer position. These changes were accompanied by a shift in management philosophy to a more centralized organizational structure in certain functional areas.

Refinancing

In December 2002, AES completed a $2.1 billion refinancing of certain bank loans and debt securities by entering into new $1.6 billion senior secured credit facilities and completing an exchange offer relating to $500 million of outstanding debt securities. The refinancing substantially eliminates all scheduled parent debt maturities until November 2004. The $1.6 billion senior secured credit facilities are comprised of a $350 million senior secured revolving credit facility, three tranches of term loan facilities totaling approximately $1.2 billion and a £52.25 million letter of credit. In the exchange offer the Company issued approximately $258 million aggregate principal amount of its 10% senior secured notes with certain mandatory redemption provisions. The senior secured credit facilities and the senior secured notes are scheduled to mature in the second half of 2005. On March 14, 2003, the Company launched a consent solicitation seeking to change the definition of "Material Subsidiary" and amend certain other provisions of its outstanding senior and senior subordinated notes to conform those provisions to the provisions in its 10% senior secured notes. We cannot assure you that the consent solicitation will be successful.

Asset Sales

AES has 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 and improve short-term liquidity. One of these initiatives involves the sale of all or part of certain of the Company's subsidiaries. During 2002, the Company announced agreements to sell AES NewEnergy, CILCORP, Inc. ("CILCORP"), AES Mt. Stuart, and AES Ecogen for net equity proceeds of approximately $819 million. The NewEnergy transaction closed in September 2002, CILCORP and AES Mt. Stuart closed in January 2003 and AES Ecogen closed in February 2003. Additionally, the Company has reached agreements to sell 100% of Songas Limited and AES Kelvin (Pty.) Ltd, two generation businesses in Africa, for net equity proceeds of approximately $116 million. These transactions are expected to close in early to mid-2003. In January 2003, the Company announced the sale of Mountainview for $30 million with another $20 million payment contingent on the achievement of project specific milestones. This transaction closed in March 2003. Additionally, the Company announced in March 2003, agreements to sell 100% of its ownership interest in two generation businesses in Bangladesh (AES Haripur Private Limited ("Haripur") and AES Meghnaghat Limited ("Meghnaghat")) and 32% of its ownership interest in AES Oasis Limited ("AES Oasis"), which includes two electric generation development projects and desalination plants in Oman and Qatar (AES Barka and AES Ras Laffan, respectively), and the oil-fired generating facilities, AES LalPir and AES PakGen in Pakistan. Proceeds from the sales of Haripur and Meghnaghat are expected to be approximately $127 million in cash plus assumption of debt, subject to certain closing adjustments. Cash proceeds from the sale of the minority interest in AES Oasis will be approximately $150 million. Completion of this sale is subject to certain conditions, including government and lender approvals. The Company continues to evaluate which additional businesses it may sell. However, there can be no guarantee that the proceeds from such sales transactions will cover the entire investment in such subsidiaries. Additionally, depending on which businesses are eventually sold, the entire or partial sale of any subsidiaries may change the current financial characteristics of the Company's portfolio and results of operations, and in the future may impact the amount of recurring earnings and cash flows the Company would expect to achieve.

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Cost Cutting

In early 2002, the Company initiated a corporate-wide effort to more closely focus on cost reduction and revenue enhancement opportunities, and also to better capture the benefits of scale in the procurement of services and supplies. The Company expects to realize cost cutting benefits in both earnings and cash flows; however, there can be no assurance that the Cost Cutting Office will be successful in achieving these savings. The inability of the Company to achieve cost reductions and revenue enhancements may result in less than expected earnings and cash flows in 2003 and beyond. In addition, the shift to a more centralized organizational structure has led, and will continue to lead, to an expansion in the number of people performing certain financial and control functions, and will likely result in an increase in the Company's selling, general and administrative expense.

Restructuring

In July 2002 the Company established a Restructuring Office formerly referred to as the Turnaround Office, to focus on improving the operating and financial performance of, selling or abandoning certain of its underperforming businesses. Businesses are considered to be underperforming if they do not meet the Company's internal rate of return criteria, among other factors. The Restructuring Office is actively managing AES Drax Power Limited ("Drax"), AES Barry Limited ("Barry"), AES Gener S.A. ("Gener"), the Company's businesses within the Dominican Republic and the Company's Argentine businesses, as well as evaluating AES Sul Distribuidora Gaucha de Energia S.A.l ("Sul"), AES Uruguaiana Empreedimentos Ltda. ("Uruguaiana"), JSC AES Telasi ("Telasi"), Eletropaulo, Compagnia Energetica de Minas Gerais ("CEMIG") and certain development projects. The Company is evaluating whether the profitability and cash flows of such businesses can be sufficiently improved to achieve acceptable returns on the Company's investment, or whether such businesses should be disposed of or sold. If the Company determines that certain businesses are to be sold or otherwise disposed of, there can be no guarantee that the proceeds from such transactions would cover the Company's entire investment in such subsidiaries or that such proceeds will be available to the Company. It is possible that the restructuring efforts will change the ownership structure or the manner in which a business operates, and these efforts may result in an impairment charge if the Company is not able to recover its investment in such business. In 2002 the Company took after-tax charges of approximately $465 million on investments in certain development projects, $301 million on businesses classified as discontinued operations, and $2.3 billion of asset impairment charges at Drax, Barry, Eletropaulo and CEMIG. The inability of the Company to successfully restructure the underperforming businesses may result in less earnings and cash flows in 2003 and beyond.

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 asset write-downs and impairments, and severance and employee benefits. Additionally, depending on which businesses are eventually sold, the entire or partial sale of any subsidiary may change the current financial characteristics of the Company's portfolio and results of operations, and may impact the future amount of recurring earnings and cash flows the Company would expect to achieve.

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 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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Successful and timely completion of pending and future asset sales.



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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 its distribution businesses; changes in 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.



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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 movements in an economical manner of 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 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; changes in state or federal regulatory provisions; inability to obtain redress from regulatory authorities; 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

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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 NewEnergy Trading Arrangements ("NETA") in England and Wales (see also the description under Foreign Regulatory Environment 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 U.S. Securities and Exchange Commission, the U.S. 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 in which the Company is conducting or is seeking to conduct business.



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The 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, (ii) capital improvements to existing facilities, and (iii) the favorable resolution of pending or potential disputes regarding the construction of the Company's projects.



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



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The effects of a fluctuating 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),

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environmental remediations 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.



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The failure of any significant manufacturer of parts for facilities of the Company's subsidiaries or any significant provider of construction services to the Company's subsidiaries to fulfill its contractual obligations presently or in the future, either because such manufacturer or service provider is financially unable to fulfill such obligations or otherwise refuses to do so.

Description of Business Segments

The Company operates in four business segments: contract generation, competitive supply, large utilities and growth distribution. See Note 19 to the Consolidated Financial Statements included in Item 8 herein for financial information about those segments as well as information about foreign and domestic operations.

Contract Generation

AES's contract generation line of business consists of multiple power generation facilities located around the world. Provided that the counterparty's credit remains viable, these facilities have contractually limited their exposure to commodity price risks, primarily electricity prices. These facilities generally 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 must 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 counterparty directly assumes the risks associated with providing the necessary fuel and markets the resulting power output generated. However, not all businesses within AES's contract generation line of business have the same degree of contractually limited exposure, and therefore, the degree of predictability may vary from business to business.

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 the power generated by a particular facility. 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 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 takes steps to maintain flexibility

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with its customers. In many instances, AES is able to avoid contract abrogation by creatively restructuring contracts without disadvantaging itself. In situations in which 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 mitigating a portion of the risks imposed by operating in less developed countries.

Certain of the Company's contract generation customers are regulated utilities that are regulated by state or local public utility commissions ("PUCs"). PUCs often restrict the amount of debt certain utilities are permitted to incur, as well as the types of business activities in which they participate. Two of these types of customers, at the Company's Warrior Run and Beaver Valley plants, are owned by Allegheny Energy, Inc., which has encountered financial difficulty due to its energy trading business. The Company does not believe the financial difficulties of Allegheny Energy, Inc. will have a material adverse effect on the performance of those customers; however, there can be no assurance that a further deterioration in Allegheny Energy, Inc.'s financial condition will not have a material adverse effect on the ability of those customers to perform their operations. Other customers are commercial entities that have no such restrictions, and therefore, may be of lesser credit quality, which increases the risk of payment default to AES. One commercial customer at three of the Company's subsidiaries, Williams Energy, has recently encountered financial difficulties related to its electricity trading operations and has been downgraded below investment grade by a number of ratings agencies. There can be no assurance that Williams Energy will continue to meet its contractual commitments.

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, 2002, capitalized costs for projects under development and in early stage construction were approximately $15 million and capitalized costs for projects under construction were approximately $3.2 billion. The Company believes that these costs are recoverable; however, no assurance can be given that individual projects will be completed and reach commercial operation.

Competitive Supply

AES's competitive supply line of business consists of generating facilities that sell electricity directly to wholesale 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.

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 but may choose to integrate businesses in certain 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 are unpredictable and can be, and from time to time have been, 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

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with regard to its counterparties; however, there can be no assurance that 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.

During the third quarter of 2002, AES completed the sale of 100% of its ownership interest in AES NewEnergy to Constellation Energy Group. AES NewEnergy was previously reported in the competitive supply segment.

Two AES Competitive Supply businesses, AES Wolf Hollow, L.P. and Granite Ridge have fuel supply agreements with El Paso Merchant Energy L.P., an affiliate of El Paso Corp., which has encountered financial difficulties. The Company does not believe the financial difficulties of El Paso Corp. will have a material adverse effect on El Paso Merchant Energy L.P.'s performance under the supply agreement; however, there can be no assurance that a further deterioration in El Paso Corp.'s financial condition will not have a material adverse effect on the ability of El Paso Merchant Energy L.P. to perform its obligations. While El Paso Corp.'s financial condition may not have a material adverse effect on El Paso Merchant Energy, L.P. at this time, it could lead to a default under AES Wolf Hollow, L.P.'s fuel supply agreement, in which case AES Wolf Hollow, L.P.'s lenders may seek to declare a default under its credit agreements. AES Wolf Hollow, L.P. is working in concert with its lenders to explore options to avoid such a default.

Large Utilities

AES's large utility business is comprised of three utilities located in the U.S. (IPALCO), Brazil (Eletropaulo) and Venezuela (EDC). AES's equity interest in each of these utilities is over 70%. In January 2003, AES sold 100% of its ownership interest in a fourth utility, CILCORP, a utility holding company whose largest subsidiary is Central Illinois Light Company ("CILCO"), to Ameren Corporation. The sale of CILCORP by AES was required under the U.S. Public Utility Holding Company Act (PUHCA) when AES purchased IPALCO, a regulated utility in Indianapolis, Indiana in March 2001. CILCORP was previously reported in the large utilities segment. In February 2002, AES also exchanged a minority interest in a fifth utility, Light Servicos de Eletricidade S.A. ("Light"), for an additional ownership interest in Eletropaulo. All of these utilities are of significant size and all 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. AES's large utilities, including IPALCO (3,431 MW) and EDC (2,616 MW), aggregate 6,047 gross MW of generation capacity and serve over 1.6 million customers with annual sales of nearly 27,000 gigawatt hours. 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 ("IPL"). IPL is engaged 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. 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 winter capability is 3,342 MW and net summer capability is 3,224 MW.

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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 National Electric Energy Agency ("ANEEL"), the government agency responsible for regulating the Brazilian electric industry, 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 5.0 million customers or about 44% of the population in the State of São Paulo, Brazil. On February 6, 2002, AES exchanged its interest in Light for an additional 31% equity interest in Eletropaulo.

EDC was founded in 1895 and is the largest private-sector electric utility in Venezuela serving approximately 1.2 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 2,616 MW.

In April 2002, AES reached an agreement to sell 100 percent of its ownership interest in CILCORP, a utility holding company whose largest subsidiary is Central Illinois Light Company ("CILCO"), to Ameren Corporation in a transaction valued at $1.4 billion including the assumption of debt and preferred stock at the closing (which was approximately $900 million at December 31, 2002). The sale of CILCORP closed on January 31, 2003. The transaction also included an agreement to sell AES Medina Valley Cogen ("Medina Valley"), a gas-fired cogeneration facility located in CILCO's service territory, which closed on February 4, 2003. The sales of CILCORP and Medina Valley generated net proceeds (after expenses) of approximately $500 million, which are subject to certain adjustments. The sale of CILCORP by AES was required under PUHCA when AES purchased IPALCO in March 2001. CILCORP was previously reported in the large utilities segment.

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 required 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 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. However, these businesses face particular challenges associated with their presence in developing countries such as outdated equipment, significant theft-related losses, cultural problems associated with safety and non-payment, emerging economies, and 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 other business segments. Distribution facilities included in this line of business may include generation, transmission, distribution or related services companies. The results of operations of AES's growth distribution business are sensitive to changes in economic growth, abnormal weather conditions affecting their market and regulatory changes, as well as the success of the operational changes implemented.

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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 approximately 850 Gross MW of generation and serve over 4.8 million customers with sales exceeding 28,000 gigawatt hours in Argentina, Brazil, Cameroon, Dominican Republic, El Salvador, Georgia and Ukraine.

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(1)

At December 31, 2002, the Company had entered into agreements to sell these businesses. The CILCORP and Mt. Stuart transactions closed in January 2003. Ecogen and Medina Valley closed in February 2003.

(2)

At December 31, 2002, the Company had entered into agreements to sell these businesses. These transactions are expected to close in the first half of 2003.

(3)

In March 2003, the Company announced that it had entered into agreements to sell all or a portion of its interest in these businesses.

(4)

In January 2003, the Company entered into an agreement to sell this business. This transaction closed in March 2003.

Note: Some of the Company's generation businesses may change between the competitive supply and contract generation segments due to changes in the amount of output contracted.

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United States Regulatory Environment

General

Over the past decade the United States implemented a series of regulatory policies that encourage competition in wholesale and retail electricity markets. Such policies have been implemented both at the federal level and in many states, 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.

Beginning in the fall of 2001 and continuing through 2002, however, primarily as a result of events in California (the electricity shortage and price rise during the period from May 2000 through June 2001) and the bankruptcy of Enron, previously the largest U.S. electricity trading company, 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 toward 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, over the last several years the state of California abandoned the framework for deregulation that had been adopted in 1996, while the Federal Energy Regulatory Commission ("FERC") has not indicated any inclination to roll back its efforts to enhance "open access" electric transmission and enhance competition in 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 California electric market restructuring legislation. ( See below, "California Businesses," for more information). While the confluence of events 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 while wholesale prices are set by the market, the problems experienced in California could be repeated elsewhere.

The events in California generally have 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 Energy Information Administration shows 18 states (including the District of Columbia)

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are actively pursuing restructuring, 6 states have delayed or suspended such restructuring, and 27 states have no active restructuring plans. 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 at the retail level. Because AES has sold its primary retail electric business in the United States, the impact of these differing retail policies on it is expected to be small in the near term.

The federal government, through regulations promulgated by the FERC, has primary jurisdiction over wholesale electricity markets. Since 1990, FERC has approved market-based rates for many providers of wholesale generation, and the mix of market players has shifted dramatically toward non-utility entities, referred to as independent power producers or wholesale generators whose rates are based on competitive conditions rather than on costs. The Electric Power Supply Association reports that non-utility generators now account for approximately 30 percent of U.S. wholesale generation. FERC has proposed new regulations to implement a "standard market design" for wholesale electric markets and may publish a final rule in 2003. This rule generally is intended to further promote non-discriminatory, open access wholesale transmission and workably competitive wholesale generation markets. Some states and members of Congress have expressed concerns, however, and it is uncertain whether and in what form FERC will issue a final rule. Congress may seek to pass legislation affecting U.S. electric markets, including possible repeal of significant portions of the Public Utility Holding Company Act of 1935 and the Public Utility Regulatory Policies Act of 1978.

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. In December 2001, the largest of such marketers/traders, Enron, filed for bankruptcy. Several other companies subsequently have reduced or eliminated their marketing and trading activities. These activities have resulted in a less liquid wholesale market, in which AES participates primarily as a generator. Due to the Enron bankruptcy and difficulties of other marketing/trading companies, stricter trading and credit requirements have been implemented, which has made 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 of 2001, 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 existing at the beginning of 2002 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 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, 2002 the Company had receivables of $4 million relating to this period from various California entities, and is actively pursuing recovery of these amounts. In addition, the State of

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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. See "Legal Proceedings."

Foregin Regulatory Environment

Argentina

In 2002, Argentina continued to experience 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 were adopted by the Argentine government, including abandonment of the country's fixed 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 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. Presidential elections are scheduled to occur in Argentina in 2003, and the new government may enact changes to the regulations governing the electricity industry. 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.

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 an 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.

Brazil

The Brazilian electricity industry is regulated by 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) overseeing 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 MAE. The MAE was originally a self-regulated body, responsible for settling and clearing short-term power purchases according to the rules established by the market participants (generators and distributors) under a

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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, sometimes referred to herein as the MAE settlement, 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:

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Initial Contracts will be amended to eliminate Annex V provisions;



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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 for 65 months from the date of the agreement, which the Company believes is sufficient to bill and collect all amounts recorded;



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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;



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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;



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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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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 for 65 months from the date of the agreement, which the Company believes is sufficient to bill and collect all amounts recorded. The agreement also establishes that BNDES 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. In addition, the agreement provided a resolution to a long-standing regulatory issue related to 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, in 2001, 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.

Under the agreement, Sul was permitted to record additional revenue and a corresponding receivable from the spot market in the fourth quarter of 2001. However, ANEEL promulgated Order 288 during May 2002 which retroactively changed certain previously communicated methodologies, and resulted in a change in the calculation methods for electricity pricing in the Wholesale Energy Market. The Company recorded a pretax provision of approximately $160 million, including the amounts for Sul against revenues during May 2002 to reflect the negative impacts of this retroactive regulatory decision.

Sul filed a motion for an administrative appeal with ANEEL challenging the legality of Order 288 and requested a preliminary injunction in the Brazilian federal courts to suspend the effect of Order 288 pending the determination of the administrative appeal. Both were denied. In August 2002, Sul appealed and in October 2002 the court confirmed the preliminary injunction's validity. Its effect, however, was subsequently suspended pending an appeal by ANEEL and an appeal by Sul.

In December 2002, prior to any settlement of the Brazilian Wholesale Electricity Market ("MAE"), Sul filed an incidental claim requesting, by way of a preliminary injunction, the suspension of the Company's debts registered in the MAE. A Brazilian federal judge granted the injunction and ordered that an amount equal to one-half of the amount claimed by Sul from inter-market trading of energy purchased from Itaipu in 2001 be set aside by the MAE in an escrow account. The injunction was subsequently overturned. Sul has appealed that decision and requested the judge to reinstate the injunction and the escrow account. A decision is expected shortly.

The MAE partially settled its registered transactions between late December 2002 and early 2003. If the final settlement occurs with the effect of Order 288 in place, Sul will owe approximately $21 million, based upon the December 31, 2002 exchange rate. Sul does not believe it will have sufficient funds to make this payment. However, if the MAE settlement occurs absent the effect of Order 288, Sul will receive approximately $106 million, based upon the December 31, 2002 exchange rate. If Sul is unable to pay any amount that may be due to MAE, penalties and fines could be imposed up to and including the termination of the concession contract by ANEEL.

The Company does not believe that the terms of the industry-wide rationing agreement as currently being implemented restored the economic equilibrium of all of the concession contracts because the agreement covered only the rationing period, the consumption never returned to the previous levels and previously communicated methodologies for implementing the terms of the rationing agreement were retroactively changed.

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On September 3, 2002, ANEEL issued an order providing that the formula for adjusting the tariffs applicable to distribution companies, which are scheduled to be reset in 2003, should be based on a replacement cost method. The Company, together with other electric distribution companies, disagrees with the proposed method and filed a lawsuit advocating that a minimum bid price methodology be used to set the rate base. The companies have not obtained an injunction to date, but the lawsuit is ongoing. Taken alone, the method proposed in the ANEEL order would lead to a significantly lower adjustment in the tariff than would methodologies proposed by the distribution companies. Because a number of other factors that affect the formula have yet to be determined, we are unable to predict the ultimate impact, if any, of this order. These other factors include an "X" factor. The X factor is intended to permit the regulator to adjust tariffs so that consumers may share in the distribution company's realization of increased operating efficiencies. The revision, however, is entirely within the regulator's discretion. Currently, ten companies are under the tariff reset public hearing process, including Sul. These results are likely to influence Eletropaulo's tariff reset.

Under the industry-wide agreement reached in December 2001, Eletropaulo can receive Brazilian Real-denominated loans from BNDES, for revenues to be received through future tariff increases. Repayment will be made in 12 consecutive monthly installments beginning March 15, 2002. Eletropaulo is required to deposit a portion of its revenues in a restricted bank account as collateral for the loan. Future BNDES disbursements under the rationing agreement will have a repayment term of approximately 5 years.

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 expensive unit required by the system at the time. The spot price among 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 the marginal cost of production. Chile has four electricity systems; the major two interconnected electricity systems are the SIC and the SING, which cover almost 97% of the population of the country.

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 among 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 ruled 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 expected average marginal cost of

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capacity or energy. In order to ensure price stability, however, the regulatory authorities in Chile establish prices, known as "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 24 to 48 months in the case of the SIC and 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 customers (over 2MW) and other generation companies purchasing on a contractual basis are unregulated and are often 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 24 to 48 months, in the case of the SIC, or 24 to 48 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 at some hours.

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.

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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. On November 20, 2002 the MEM extended the date for the restructuring of integrated utilities to January 2004. 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 has been considering introducing 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.

United States Environmental and Land Use Regulations

The Company's businesses 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 emissions into the air, discharge of effluents into the water and the use of water, as well as 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 11 of the consolidated financial statements for more detail. AES has at times been in non-compliance with environmental 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 laws and 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

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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 may be required to make significant capital or other expenditures in connection with such changes in environmental laws or regulations. 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 including sulfur dioxide ("SO ₂ ") and nitrogen oxides ("NOx"). Among other things, the 1990 Amendments require reductions in acid rain precursor emissions (SO ₂ and NOx) from existing sources, particularly large, older power plants that were exempted from certain requirements of 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 ("PM"). In October 1999, a federal appeals court overturned the new standards. In February 2001, the U.S. Supreme Court reversed and remanded the case to the appeals court for further review of the standards but held that EPA's policy for implementing the new ozone standard was unlawful. In March 2002, the federal appeals court upheld the new standards. However, as directed by the U.S. Supreme Court, EPA must develop a new implementation policy for the ozone standard in 2003. Although we cannot predict what EPA's final policy for implementing the new ozone and PM standards will be, 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.

Also, EPA intends to propose a rule in December 2003 which would control certain SO ₂ emissions which form fine PM that is transported to downwind states. The rule will likely require an approximately 70% reduction in SO ₂ emissions by 2010 through market-based emissions trading.

NOx SIP Call

In October 1998, 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 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. 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.

Section 126 Petitions

In December 1999, EPA 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

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Section 126 of the Clean Air Act, the EPA made a finding that certain large electric generating units in upwind states significantly contribute to non-attainment of the NAAQS for ozone in the northeastern downwind states. The compliance date for affected emission sources, including electric generating plants, is May 31, 2004. As a result of EPA's ruling, 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, 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") regulations which require companies to obtain permits prior to making major modifications to their facilities. In December 2002, EPA promulgated revised NSR regulations. However, EPA has stated that the revised regulations will not affect existing enforcement cases. 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 establishes planning and emission reduction timelines for states to use to improve visibility in national parks throughout the United States. 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. 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 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 rule is 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"). 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. See "Recent Legislative and Regulatory Proposals" below for a description of other proposed mercury restrictions.

Global Warming

Global warming continues to be a concern and remains a policy issue that is regularly considered for possible government regulation. 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 which include carbon dioxide (CO ₂ ). Although the United States agreed to the Kyoto Protocol, the treaty has not been sent to the

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Senate for ratification. Several U.S. states, including Massachusetts, California and New Hampshire, have taken action to reduce greenhouse gas emissions. Also, several European countries have some regulations concerning greenhouse gases. U.S. federal legislation requiring reductions in greenhouse gases could substantially affect both the costs and the operating characteristics of AES's fossil-fuel (coal, oil, gas) fired businesses. See "Recent Legislative and Regulatory 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, various bills sponsored by members of Congress would require significant reductions for CO ₂ , NOx, SO ₂ and mercury. In addition, President Bush's "Clear Skies" legislation, which would cap emissions of three pollutants (NOx, SO ₂ and mercury), with voluntary reductions of CO ₂ , was introduced in Congress in July 2002 and reintroduced by Senator Inhofe in February 2003.

In February 2002, the New York Department of Environmental Conservation ("DEC") issued proposed regulations requiring electric generators to reduce SO ₂ emissions by 50% below current Clean Air Act standards. The state environmental authorities are scheduled to vote on this regulation on March 26, 2003. If adopted, the SO ₂ 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 the summertime ozone season. 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.

In early 2002, the EPA, pursuant to Section 316 of the United States Federal Water Pollution Control Act, proposed a regulation establishing location, design, construction and 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 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

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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 subject to EU directives and national legislation implementing those directives. 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. Also, in December 2002, Canada ratified the Kyoto Protocol, and the Russian Federation has declared its intention to ratify the Protocol in the spring of 2003. If ratified by the Russian Federation, the Protocol will enter into force for all countries that have ratified it. If the governments of the United Kingdom and The Netherlands, in particular, ratify and adopt regulations implementing the Kyoto Protocol, our facilities in those countries will be required to incur significant costs to reduce CO ₂ emissions, and their operating characteristics may be affected. These costs would 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. 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 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

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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, and 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 2002 net sales.

Employees

As of December 31, 2002, AES employed approximately 36,000 people.

Executive Officers and Significant Employees of the Registrant

The following is information concerning the present executive officers and significant employees of the Registrant set out in alphabetical order.

Joseph C. Brandt, 38 years old, was appointed Chief Restructuring Officer and Vice President in February 2003. From January 2002 to February 2003, Mr. Brandt was Group Manager for AES Andes, a business group responsible for AES's business interests in Argentina. From 1999 to 2002, Mr. Brandt held various corporate and development positions with the Company. From 1998 to 1999, Mr. Brandt worked as an investment advisor. Mr. Brandt received a JD from Georgetown University Law Center, an MA from the University of Virginia and an AB from George Mason University and was a Fulbright Scholar at the University of Helsinki, Finland.

Mark Fitzpatrick, 52 years old, was appointed Executive Vice President of the Company in February 2000. His responsibilities included overseeing the AES businesses in the Latin American Region. Mr. Fitzpatrick was Senior Vice President until February 2000, and was appointed Vice President of the Company in 1987. Mr. Fitzpatrick became Managing Director of Applied Energy Services Electric Limited for the United Kingdom and Western Europe operations in 1990. From 1984 to 1987, he served as a project director of the AES Beaver Valley and AES Thames projects.

Paul T. Hanrahan, 45 years old, was appointed President and Chief Executive Officer in June 2002. He was one of the four Chief Operating Officers appointed in February 2002. He was appointed Executive Vice President in February 2000, Senior Vice President since in 1997, and was appointed Vice President of the Company 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 Company, from 1990 to 1993.

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William R. Luraschi, 39 years old, was appointed Senior Vice President in February 2002 and has been Vice President of the Company since January 1998, and General Counsel of the Company since January 1994. He also was Secretary from February 1996 until June 2002. Prior to that, Mr. Luraschi was an attorney with the law firm of Chadbourne & Parke L.L.P.

Dr. Roger F. Naill, 56 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 from Dartmouth College and a MSM Degree from the A.P. Sloan School of Business (MIT).

John Ruggirello, 52 years old, was appointed Chief Operating Officer for Generation in February 2003. 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 led the AES Enterprise group, with responsibility for project development, construction and plant operations in the United States. Prior to joining the Company in 1987, Mr. Ruggirello was Operations Manager for a division of the Diamond Shamrock Corporation.

Barry J. Sharp, 43 years old, holds the position of Chief Financial Officer. His responsibilities include overseeing the finance function. 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 Company 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, 59 years old, has been Senior Vice President of the Company 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.

How to Contact AES and Sources of Other Information

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.aes.com. The Company's annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and any amendments to such reports filed pursuant to section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 are posted on the Company's website at http://www.aes.com as soon as practical after they are filed with the Securities and Exchange Commission and are available free of charge. Material contained on the Company's website is not incorporated by reference in this report on Form 10-K.