AES CORPORATION - 10-K Annual Report

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ý No o

The aggregate market value of Registrant's voting stock held by non-affiliates of Registrant, on June 28, 2002 (based on the closing sale price of $5.42 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $2,421,114,000. The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, on March 3, 2003, was 564,542,183.

The Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on May 1, 2003 is hereby incorporated by reference. Certain information therein is incorporated by reference into Part III hereof.

		Page
Part I
Item 1—Business		1
Item 2—Properties		28
Item 3—Legal Proceedings		29
Item 4—Submission of Matters to a Vote of Security Holders		33
Part II
Item 5—Market for Registrant's Common Equity and Related Stockholder Matters		34
Item 6—Selected Financial Data		35
Item 7—Discussion and Analysis of Financial Condition and Results of Operations		36
Item 7a—Quantitative and Qualitative Disclosures About Market Risk		78
Item 8—Financial Statements and Supplementary Data		80
Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		153
Part III
Item 10—Directors and Executive Officers of the Registrant		153
Item 11—Executive Compensation		153
Item 12—Security Ownership of Certain Beneficial Owners and Management		153
Item 13—Certain Relationships and Related Transactions		153
Item 14—Disclosure Controls and Procedures		153
Part IV
Item 15—Exhibits, Financial Statement Schedules and Reports on Form 8-K		154
Signatures		158

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

The Company wishes to caution readers that the following important factors, among others, indicate areas affecting the Company, which involve risk and uncertainty. These factors should be considered when reviewing the Company's business, and are relied upon by AES in issuing any forward-looking statements. Such factors could affect AES's actual results and cause such results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, AES. Some or all of these factors may apply to the Company's businesses as currently maintained or to be maintained.

The 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.

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

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.

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

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.

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.

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.

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.

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.

The following tables set forth information regarding the Company's facilities that are in operation or under construction at December 31, 2002. For a description of risk factors and additional factors that may apply to the Company's facilities, see also the information contained under the caption "Cautionary Statements and Risk Factors" in Item 1 above, and Item 7, "Discussion and Analysis of Financial Condition and Results of Operations" herein.

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)

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.

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

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."

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.

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

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:

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.

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.

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

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.

The New Electricity Trading Arrangements ("NETA") became effective on March 27, 2001. The NETA system is structured around bilateral trading between generators, suppliers, traders and customers. The system operates like a standard commodity market, but makes special provision for the electricity system to be kept in physical balance. NETA includes forward and futures markets, allowing contracts for future delivery of electricity to be entered into up to several years in advance. The balancing mechanism enables the system operator, The National Grid Company, to change levels of generation and demand in near real-time. If an imbalance between a party's net physical and net contractual positions occurs, the system provides a mechanism for settlement which creates an incentive for generators to accurately forecast their availability. A number of power exchanges have now emerged to facilitate medium- and short-term trading of standard products. It is anticipated that more sophisticated trading tools and financial instruments will develop as the market matures.

Since the introduction of NETA, there has been a marked decline in the price paid for wholesale electricity. Day ahead and one-year forward prices have declined approximately 30% and appear to result from a combination of factors, some of which are specific to the new structure of the market and others which relate to fundamental market conditions (specifically warmer weather during the Winter 2001-2002). Specifically with reference to NETA, it appears that the new trading rules have increased competitiveness in the market. As a result of the significant price declines over this past year, virtually all generation facilities which do not have long-term contracts to sell their power have come under severe financial pressure and several have been taken off-line or shut-down as prices have fallen below their variable costs. In February 2002, the Company announced that it would take its Fifoots plant off-line as it had become no longer possible to sell power above its marginal cost of generation. Subsequently in March 2002, the Fifoots plant was placed into administrative receivership.

In 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.

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

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.

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 ("SO₂") and nitrogen oxides ("NOx"). Among other things, the 1990 Amendments require reductions in acid rain precursor emissions (SO₂ 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.

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 SO₂ emissions which form fine PM that is transported to downwind states. The rule will likely require an approximately 70% reduction in SO₂ emissions by 2010 through market-based emissions trading.

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.

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

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.

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.

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.

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 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 (CO₂). Although the United States agreed to the Kyoto Protocol, the treaty has not been sent to the

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.

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 CO₂, NOx, SO₂ and mercury. In addition, President Bush's "Clear Skies" legislation, which would cap emissions of three pollutants (NOx, SO₂ and mercury), with voluntary reductions of CO₂, 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 SO₂ 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 SO₂ regulation would be phased in beginning on January 1, 2005 with implementation completed by January 1, 2008. DEC's proposed regulations would also require electric generators to meet stringent NOx reduction requirements year-round, rather than just during 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.

AES has ownership interests in power plants and projects in many countries outside the United States. Each of these countries (and the localities therein) have separate laws and regulations governing the siting, construction, permitting, ownership, operation, decommissioning and remediation of, and power sales from, such power plants. These countries also have laws governing waste disposal, the discharge of pollutants into the air, water or ground and noise pollution. These laws and regulations are often different from those in effect in the United States. In addition to such foreign laws and regulations, projects funded by the World Bank are subject to World Bank environmental standards. These standards may be more stringent than local country standards but are typically not as strict as corresponding standards in the United States. AES has incurred and will continue to incur capital and other expenditures to comply with these laws and regulations, in particular, laws governing air

emissions. Whenever feasible, AES attempts to use advanced environmental technologies (such as CFB coal technology or advanced gas turbines) in its non-U.S. businesses in order to minimize environmental impacts.

Our operations in the European Union (the "EU") are 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 CO₂ 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.

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.

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.

Historically, energy utilities operated within specific service territories where they were essentially the sole suppliers of electricity services, and therefore competition was limited to alternative means of energy such as gas and fuel. However, in certain locations, the large utilities business is facing significant challenges and increased competition as a result of changes in laws and regulations allowing wholesale and retail services to be provided on a competitive basis. There can be no assurance that the

deregulation will not adversely affect the future operations, cash flows and financial condition of our large utilities.

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.

The Company sells to a wide variety of customers. No individual customer accounted for more than 10% of the Company's 2002 net sales.

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.

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.

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.

Offices are maintained by the Registrant in many places around the world, which are generally occupied pursuant to the provisions of long- and short-term leases, none of which are material to the Company. With a few exceptions, the Registrant's facilities, which are described in Item 1 hereof, are subject to mortgages or other liens or encumbrances as part of the project's related finance facility. The land interest held by the majority of the facilities is that of a lessee or, in the case of the facilities located in the People's Republic of China, a land use right that is leased or owned by the related joint venture that owns the project. However, in a few instances, there exists no accompanying project financing for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned by the subsidiary or affiliate owning the facility outright.

In September 1999, a judge in the Brazilian appellate state court of Minas Gerais granted a temporary injunction suspending the effectiveness of a shareholders' agreement between the Company's joint venture ("SEB") and the state of Minas Gerais concerning CEMIG which granted SEB certain rights and powers in respect of CEMIG (the "Special Rights"). The temporary injunction was granted pending determination by the lower state court of whether the shareholders' agreement could grant SEB the Special Rights. In November 1999, the full state appellate court upheld the temporary injunction. In March 2000, the lower state court in Minas Gerais ruled on the merits of the case, holding that the shareholders' agreement was invalid where it purported to grant SEB the Special Rights. In April 2001, the state appellate court denied an appeal of the merits decision, and extended the injunction. In October 2001, SEB filed two appeals against the decision on the merits of the state appellate court, one to the Federal Superior Court and the other to the Supreme Court of Justice. In August 2002, SEB filed two interlocutory appeals against the state appellate court's refusal to consider SEB's appeal on the merits, one directed to the Federal Superior Court and the other to the Supreme Court of Justice. The appeals continue to be pending. The Company, together with SEB, intends to vigorously pursue by all legal means a restoration of the value of its investment in CEMIG. However, there can be no assurances that the Company and SEB will be successful in their efforts. Failure to prevail in this matter may limit the SEB's influence on the daily operation of CEMIG.

In November 2000, the Company was named in a purported class action suit along with six other defendants alleging unlawful manipulation of the California wholesale electricity market, resulting in inflated wholesale electricity prices throughout California. Alleged causes of action include violation of the Cartwright Act, the California Unfair Trade Practices Act and the California Consumers Legal Remedies Act. In December 2000, the case was removed from the San Diego County Superior Court to the U.S. District Court for the Southern District of California. The case has been consolidated with five other lawsuits alleging similar claims against other defendants. In March 2002, the plaintiffs filed a new master complaint in the consolidated action, which asserted the claims asserted in the earlier action and names the Company, AES Redondo Beach, L.L.C., AES Alamitos, L.L.C., and AES Huntington Beach, L.L.C. as defendants. Defendants have filed a motion to dismiss the action in its entirety. The Company believes it has meritorious defenses to any actions asserted against it and expects that it will defend itself vigorously against the allegations.

In addition, the crisis in the California wholesale power markets has directly or indirectly resulted in several administrative and legal actions involving the Company's businesses in California. Each of the Company's businesses in California (AES Placerita and AES Southland, which is comprised of AES Redondo Beach, AES Alamitos, and AES Huntington Beach) are subject to overlapping state investigations by the California Attorney General's Office, the Market Oversight and Monitoring Committee of the California Independent System Operator ("ISO"), the California Public Utility Commission and a subcommittee of the California Senate. The businesses have cooperated with the investigation and responded to multiple requests for the production of documents and data surrounding the operation and bidding behavior of the plants.

In August 2000, the Federal Energy Regulatory Commission ("FERC") announced an investigation into the national wholesale power markets, with particular emphasis upon the California wholesale electricity market, in order to determine whether there has been anti-competitive activity by wholesale generators and marketers of electricity. The FERC has requested documents from each of the AES Southland plants and AES Placerita. AES Southland and AES Placerita have cooperated fully with the FERC investigation.

In May 2001, the Antitrust Division of the United States Department of Justice initiated an investigation to determine whether a provision in the AES Southland plants' Tolling Agreement with Williams Energy Services Company has restricted the addition of new capacity in the Los Angeles area

in contravention of the antitrust laws. The AES Southland businesses have provided documents and other information to the Department of Justice.

In July of 2001, a petition was filed against CESCO, an affiliate of the Company by the Grid Corporation of Orissa, India ("Gridco"), with the Orissa Electricity Regulatory Commission ("OERC"), alleging that CESCO has defaulted on its obligations as a government licensed distribution company; that CESCO management abandoned the management of CESCO; and asking for interim measures of protection, including the appointment of a government regulator to manage CESCO. Gridco, a state owned entity, is the sole energy wholesaler to CESCO. In August 2001, the management of CESCO was handed over by the OERC to a government administrator that was appointed by the OERC. Gridco also has asserted that a Letter of Comfort issued by the Company in connection with the Company's investment in CESCO obligates the Company to provide additional financial support to cover CESCO's financial obligations. In December 2001, a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 was served on the Company by Gridco pursuant to the terms of the CESCO Shareholder's Agreement ("SHA"), between Gridco, the Company, AES ODPL, and Jyoti Structures. The notice to arbitrate failed to detail the disputes under the SHA for which the Arbitration had been initiated. After both parties had appointed arbitrators, and those two arbitrators appointed the third neutral arbitrator, Gridco filed a motion with the India Supreme Court seeking the removal of AES' arbitrator and the neutral chairman arbitrator. In the fall of 2002, the Supreme Court rejected Gridco's motion to remove the arbitrators. Gridco has now asked the arbitrators themselves to rule on the same motion, which motion again requests their removal from the panel. Although that motion remains pending, the present panel has requested that the parties' statements of claim be filed by April 2003. The Company believes that it has meritorious defenses to any actions asserted against it and expects that it will defend itself vigorously against the allegations.

In November 2002, the Company was served with a grand jury subpoena issued on application of the United States Attorney for the Northern District of California. The subpoena seeks, inter alia, certain categories of documents related to the generation and sale of electricity in California from January 1998 to the present. The Company intends to comply fully with its legal obligations in responding to the subpoena.

In April 2002, IPALCO and certain former officers and directors of IPALCO were named as defendants in a purported class action lawsuit filed in the United States District Court for the Southern District of Indiana. On May 28, 2002, an amended complaint was filed in the lawsuit. The amended complaint asserts that former members of the pension committee for the thrift plan breached their fiduciary duties to the plaintiffs under the Employment Retirement Income Securities Act by investing assets of the thrift plan in the common stock of IPALCO prior to the acquisition of IPALCO by the Company. In February 2003, the Court denied the defendants motion to dismiss the lawsuit. Discovery continues in the lawsuit. The subsidiary believes it has meritorious defenses to the claims asserted against them and intends to defend these lawsuits vigorously.

In July 2002, the Company, Dennis W. Bakke, Roger W. Sant, and Barry J. Sharp were named as defendants in a purported class action filed in the United States District Court for the Southern District of Indiana. In September 2002, two virtually identical complaints were filed against the same defendants in the same court. All three lawsuits purport to be filed on behalf of a class of all persons who exchanged their shares of IPALCO common stock for shares of AES common stock pursuant to the Registration Statement dated and filed with the SEC on August 16, 2000. The complaint purports to allege violations of Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 based on statements in or omissions from the Registration Statement covering certain secured equity-linked loans by AES subsidiaries; the supposedly volatile nature of the price of AES stock, as well as AES's allegedly unhedged operations in the United Kingdom. In October 2002, the defendants moved to consolidate these three actions with the IPALCO securities lawsuit referred to immediately below. This consolidation motion is pending. On November 5, 2002, the Court appointed lead plaintiffs and lead

and local counsel. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend these lawsuits vigorously.

In September 2002, IPALCO and certain of its former officers and directors were named as defendants in a purported class action filed in the United States District Court for the Southern District of Indiana. The lawsuit purports to be filed on behalf of the class of all persons who exchanged shares of IPALCO common stock for shares of AES common stock pursuant to the Registration Statement dated and filed with the SEC on August 16, 2000. The complaint purports to allege violations of Sections 11 of the Securities Act of 1933 and Sections 10(a), 14(a) and 20(a) of the Securities Exchange Act of 1934, and Rules 10b-5 and 14a-9 promulgated thereunder based on statements in or omissions from the Registration Statement covering certain secured equity-linked loans by AES subsidiaries; the supposedly volatile nature of the price of AES stock; and AES's allegedly unhedged operations in the United Kingdom. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

In October 2002, the Company, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp were named as defendants in purported class actions filed in the United States District Court for the Eastern District of Virginia. Between October 29, 2002 and December 4, 2002, six virtually identical lawsuits were filed against the same defendants in the same court. The lawsuits purport to be filed on behalf of a class of all persons who purchased the Company's stock between April 26, 2001 and February 14, 2002. The complaints purport to allege that certain statements concerning the Company's operations in the United Kingdom violated Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder. On December 4, 2002, defendants moved to transfer the seven actions to the United States District Court for the Southern District of Indiana. By stipulation dated December 9, 2002, the parties agreed to consolidate these actions into one action. On December 12, 2002 the Court entered an order consolidating the cases under the caption In re AES Corporation Securities Litigation, Master File No. 02-CV-1485. On January 16, 2003, the Court granted defendants' motion to transfer the consolidation action to the United States District Court for the Southern District of Indiana. The Company and the individuals believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

Beginning in September 2002, El Salvador tax and commercial authorities initiated investigations involving four of the Company's subsidiaries in El Salvador, Compañia de Luz Electrica de Santa Ana S.A. de C.V. ("CLESA"), Compañía de Alumbrado Electrico de San Salvador, S.A. de C.V. ("CAESS"), Empresa Electrica del Oriente, S.A. de C.V. ("EEO"), and Distribuidora Electrica de Usultan S.A. de C.V. ("DEUSEM"), in relation to two financial transactions closed in June 2000 and December 2001, respectively. The authorities have issued document requests and the Company and its subsidiaries are cooperating fully in the investigations. As of March 18, 2003, certain of these investigations have been successfully concluded, with no fines or penalties imposed on the Company's subsidiaries. The tax authorities' and attorney general's investigations are pending conclusion.

In March 2002, the general contractor responsible for the refurbishment of two previously idle units at AES's Huntington Beach plant filed for bankruptcy in the United States bankruptcy court for the Central District of California. A number of the subcontractors hired by the general contractor, due to alleged non-payment by the general contractor, have asserted claims for non-payment against AES Huntington Beach. The general contractor has also filed claims seeking up to $57 million from AES Huntington Beach for additional costs it allegedly incurred as a result of changed conditions, delays, and work performed outside the scope of the original contract. The general contractor's claim includes its subcontractors' claims. All of these claims are adversary proceedings in the general contractor's bankruptcy case. In the event AES Huntington Beach were required to satisfy any of the subcontractor claims for payment, AES Huntington Beach may be unsuccessful in recovering such amounts from, or offsetting such amounts against claims by, the general contractor. The Company does not believe that

any additional amounts are owed by its subsidiary and such subsidiary intends to defend vigorously against such claims.

The U.S. Department of Justice is conducting an investigation into allegations that persons and/or entities involved with the Bujagali hydroelectric power project which the Company is developing in Uganda, have made or have agreed to make certain improper payments in violation of the Foreign Corrupt Practices Act. The Company is conducting its own internal investigation and is cooperating with the Department of Justice in this investigation.

In November 2002, a lawsuit was filed against AES Wolf Hollow L.L.P. and AES Frontier L.P., two subsidiaries of the Company, in Texas State Court by Stone and Webster, Inc. The complaint in the action alleges claims for declaratory judgment and breach of contract allegedly arising out of the denial of certain force majeure claims purportedly asserted by the plaintiff in connection with its construction of the Wolf Hollow project, a gas-fired combined cycle power plant being constructed in Hood County, Texas. Stone and Webster is the general contractor for the Wolf Hollow project. The subsidiary believes it has meritorious defenses to the claims asserted against it and intends to defend the lawsuit vigorously.

On August 24, 2002, Bechtel Power Corporation ("Bechtel") filed a lawsuit against the Company in California State court alleging three claims for breach of guaranty and one claim for fraud. Bechtel contends that AES owes Bechtel approximately $47 million based on AES's alleged guaranty of purported payment obligations of Mountainview to Bechtel under a certain construction contract. Bechtel also asserts that the Company fraudulently induced Bechtel to enter into such construction contract. In December 2002, the Company's motion seeking a stay of the lawsuit as issues asserted in the lawsuit are the subject of a mandatory arbitration currently pending between Bechtel and Mountainview (see "Bechtel Arbitration" referenced below) was granted by the Court. In January 2003, Bechtel and the Company agreed to a further stay of the litigation pending the parties' finalization of an agreement whereby the Mountainview project would be sold by the Company. In March 2003, in connection with the sale of Mountainview, the parties agreed to file a voluntary dismissal of the arbitration.

On September 25, 2002, Mountainview filed a demand for arbitration against Bechtel Power Corporation (the "Bechtel Arbitration"). The claims asserted in the Bechtel Arbitration relate to existing disputes between the parties regarding amounts that Bechtel asserts are owing by Mountainview due to purported services provided in connection with the construction of the Mountainview power project located in California. Mountainview seeks a determination in the arbitration that Mountainview has fully performed all obligations owing to Bechtel and Mountainview owes no further amounts to Bechtel. In December 2003, the members of the arbitration panel were appointed by the parties. In January 2003, Bechtel and the Company agreed to a further stay of the arbitration pending the parties' finalization of an agreement whereby the Mountainview project would be sold by the Company. In March 2003, in connection with the sale of Mountainview, the parties agreed to file a voluntary dismissal of the arbitration.

In March 2003, the office of the Federal Public Prosecutor for the State of Sao Paulo, Brazil notified Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgas and the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo and the quality of service provided by Eletropaulo to its customers and requested various documents from Eletropaulo relating to these matters. Also in March 2003, the Commission for Public Works and Services of the Sao Paulo Congress requested Eletropaulo to appear at a hearing relating to the default by AES Elpa and AES Transgas with BNDES and the quality of service rendered.

In December 2002, Enron filed a lawsuit in the Bankruptcy Court for the Southern District Court of New York against the Company, NewEnergy, and CILCO. Pursuant to the Complaint, Enron seeks to

recover approximately $13 million dollars from NewEnergy (and the Company as guarantor of the obligations of NewEnergy). Enron contends that NewEnergy and the Company are liable to Enron based upon certain accounts receivables purportedly owing from NewEnergy and an alleged payment arising from the purported termination by NewEnergy of a "Master Energy Purchase and Sale Agreement." In the Complaint, Enron seeks to recover from CILCO the approximate amount of $31.5 million dollars arising from the termination by CILCO of a "Master Energy Purchase and Sale Agreement" and certain accounts receivables that Enron claims are due and owing from CILCO to Enron. On February 13, 2003 the Company, NewEnergy and CILCO filed a motion to dismiss certain portions of the action and compel arbitration of the disputes with Enron. Also in February 2003, the Bankruptcy Court Ordered the parties to mediate the disputes. The Company believes it has meritorious defenses to the claims asserted against it and intends to defend the lawsuits vigorously.

In December 2002, plaintiff David Schoellermann filed a purported derivative lawsuit in Virginia State Court on behalf of the Company against the members of the Board of Directors and numerous officers of the Company (the "Schoellermann Lawsuit"). The lawsuit alleges that defendants breached their fiduciary duties to the Company by participating in or approving the Company's alleged manipulation of electricity prices in California. Certain of the defendants are also alleged to have engaged in improper sales of stock based on purported inside information that the Company was manipulating the California electricity prices. The complaint seeks unspecified damages and a constructive trust on the profits made from the alleged insider sales. On February 28, 2003, a motion to dismiss the action was filed based on the plaintiff's failure to make a demand on the Company to investigate the allegations. On February 21, 2003, a second Derivative lawsuit was filed by plaintiff Joe Pearce in Virginia State Court on behalf of the Company against the members of the Board of Directors and numerous officers of the Company (the "Pearce Lawsuit"). It is anticipated that a similar motion to dismiss, as filed in the Schoellerman Lawsuit, will be filed to dismiss the Pearce Lawsuit.

On February 26, 2003, the Company, Dennis W. Bakke, Roger W. Sant, and Barry J. Sharp were named as defendants in a purported class action lawsuit filed in the United States District Court for the Southern District of Indiana captioned Stanley L. Moskal and Barbara A. Moskal v. The AES Corporation, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp. 1:03-CV-0284 (Southern District of Indiana). The lawsuit purports to be filed on behalf of a class of all persons who engaged in "option transactions" concerning AES securities between July 27, 2002 and November 8, 2002. The complaint alleges that AES and the individual defendants failed to disclose information concerning purported manipulation of the California electricity market, the effect thereof on AES's reported revenues, and AES's purported contingent legal liabilities as a result thereof, in violation of Sections 10(b) and 20 (a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. The Company and the individual defendants have not yet responded to the complaint.

The Company is also involved in certain other legal proceedings in the normal course of business.

No matters were submitted to a vote of security holders during the fourth quarter of 2002.

Item 5—Market for Registrant's Common Equity and Related Stockholder Matters

The common stock of the Company is currently traded on the New York Stock Exchange (NYSE) under the symbol "AES." The following tables set forth the high and low sale prices for the common stock as reported by the NYSE for the periods indicated.

As of March 3, 2003, there were 9,663 record holders of the Company's Common Stock, par value $0.01 per share.

Under the terms of the Company's senior secured credit facilities entered into with a commercial bank syndicate, the Company is not allowed to pay cash dividends. In addition, the Company is precluded from paying cash dividends on its Common Stock under the terms of a guaranty to the utility customer in connection with the AES Thames project in the event certain net worth and liquidity tests of the Company are not met.

The ability of the Company's project subsidiaries to declare and pay cash dividends to the Company is subject to certain limitations in the project loans, governmental provisions and other agreements entered into by such project subsidiaries.

See the information contained under the caption "Securities Authorized for Issuance under Equity Compensation Plans" of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on May 1, 2003, which information is incorporated herein by reference.

Please note that acquisitions, disposals, reclassifications and changes in accounting principles affect the comparability of information included in the tables below. Please refer to the Notes to the consolidated financial statements for further explanation of the effect of such activities.

Item 7—Discussion and Analysis of Financial Condition and Results of Operations

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. Certain of the Company's obligations under the senior secured credit facilities are guaranteed by some of its domestic subsidiaries. The Company's obligations under the senior secured credit facilities are, subject to certain exceptions, secured, equally and ratably with its 10.0% senior secured notes due 2005, by: (i) all of the capital stock of domestic subsidiaries owned directly by us and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by AES and (ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements owed to AES by its subsidiaries. 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.

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, 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 or 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.

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 Drax, Barry, Gener, the Company's businesses within the Dominican Republic and the Company's Argentine businesses, as well as evaluating Sul, Uruguaiana, Telasi, Eletropaulo, 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 and construction 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.

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. Due to the changes, the Company changed the functional currency for its businesses in Argentina to the peso effective January 1, 2002. If the commercial arrangements or regulatory framework within which any of the businesses operate become indexed to a currency other than the peso, the functional currency of the respective business may change. The Argentine peso experienced a significant devaluation relative to the U.S. dollar during 2002. The Company recorded foreign currency transaction losses on the U.S. dollar denominated net liabilities of its Argentine subsidiaries during 2002 of approximately $143 million before income taxes representing a decline in the Argentine peso to the U.S. dollar from 1.65 used at December 31, 2001 to 3.32 at December 31, 2002.

AES has several subsidiaries in Argentina operating in both the competitive supply and growth distribution segments of the electricity business. Eden, Edes and Edelap are distribution companies that operate in the province of Buenos Aires. Generating businesses include Alicura, Parana, CTSN, Rio Juramento and several other smaller hydro facilities. These businesses are experiencing cash flow shortfalls arising from the economic and regulatory changes described earlier, and some of the businesses are in default on their project financing arrangements. AES is not generally required to support the potential cash flow or debt service obligations of these businesses.

The effects of the crisis are not expected to have a significant negative impact on AES's parent cash flow, due primarily to the non-recourse financing structure in place at most of AES's Argentine businesses. The effects of the current circumstances on future earnings are much more uncertain and difficult to predict. At December 31, 2002, AES total investment in the competitive supply business in Argentina was approximately $141 million and the total investment in the growth distribution business was approximately negative $61 million. These investment amounts are net of foreign currency translation losses.

During the first quarter of 2002, the Company recorded an after-tax impairment charge of $190 million which represented the write off of goodwill related to certain of our businesses in Argentina. This charge resulted from the adoption of SFAS No. 142 and is recorded as a cumulative effect of a change in accounting principle on the consolidated statement of operations.

Depending on the ultimate resolution of these uncertainties, AES may be required in 2003 to record a material impairment loss or write off associated with the recorded carrying values of its investments.

During 2002, the Brazilian Real experienced a significant devaluation relative to the U.S. dollar, declining from 2.41 Reais to the dollar at December 31, 2001 to 3.53 Reais at December 31, 2002. Also, during 2001, the Brazilian Real experienced a significant devaluation relative to the U.S. dollar

declining from 1.96 Reais to the U.S. dollar at December 31, 2000 to 2.41 Reais to the U.S. dollar at December 31, 2001. This continued devaluation resulted in significant foreign currency translation and transaction losses, particularly during 2002 and 2001. The Company recorded $357 million, $210 million, and $64 million before income taxes of non-cash foreign currency transaction losses on the U.S. dollar denominated net liabilities at its investments in Brazilian businesses during 2002, 2001 and 2000, respectively. The 2002 amount of $357 million is reported as $317 million of foreign currency transaction losses, $43 million of related minority interest (income) expense, and $83 million of equity in pre-tax (loss) earnings of affiliates on the consolidated statement of operations that primarily arises from Eletropaulo which was consolidated beginning in February 2002. The 2001 and 2000 amounts of $210 million and $64 million, respectively, are recorded in equity in pre-tax earnings of affiliates in the accompanying consolidated statements of operations since Eletropaulo was accounted for as an equity method investment during those years. Further devaluation of the Brazilian Real will continue to have a negative impact on the Company's results of operations.

Eletropaulo. AES has owned an interest in Eletropaulo since April 1998. The Company began consolidating Eletropaulo in February 2002 when AES Elpa acquired a controlling interest in the business. AES financed a significant portion of the acquisition of Eletropaulo, including both common and preferred shares, through loans and deferred purchase price financing arrangements provided by BNDES, the National Development Bank of Brazil and its wholly owned subsidiary BNDES Participacoes Ltda. ("BNDESPAR"), to AES Elpa and AES Transgas, respectively. As of December 31, 2002, AES Elpa and AES Transgas had approximately $542 million and $621 million of outstanding BNDES and BNDESPAR indebtedness, respectively. All of the common shares of Eletropaulo owned by AES Elpa are pledged to BNDES to secure the AES Elpa debt and all of the preferred shares of Eletropaulo owned by AES Transgas and AES Cemig Empreendimentos II, Ltd. (which owns approximately 7.4% of Eletropaulo's preferred shares, representing 4.4% economic ownership of Eletropaulo) are pledged to BNDESPAR to secure AES Transgas debt. AES has pledged its share of the proceeds in the event of the sale of certain of its businesses in Brazil, including Sul, Uruguaiana, Eletronet and AES Communications Rio, to secure the indebtedness of AES Elpa to BNDES for the repayment of the debt of AES Elpa. The interests underlying the Company's investments in Uruguaiana, AES Communications Rio and Eletronet have also been pledged as collateral to BNDES under the AES Elpa loan. As of December 31, 2002, Eletropaulo had $1.4 billion of outstanding indebtedness. The Company's total investment associated with Eletropaulo as of December 31, 2002, was approximately negative $1.0 billion, which is net of foreign currency translation losses and other comprehensive losses arising from minimum pension obligations.

During the fourth quarter of 2002, the Company recorded an after-tax impairment charge of approximately $706 million at Eletropaulo. This charge was taken to reflect the reduced carrying value of certain assets, including goodwill, primarily resulting from slower than anticipated recovery to pre-rationing electricity consumption levels and lower electricity prices due to devaluation of foreign exchange rates.

approximately $621 million of AES Transgas's outstanding debt with BNDESPAR. As a result of a cross default provision, BNDES also has the right to call due approximately $231 million loaned to Eletropaulo under the program in Brazil established to alleviate the effects of rationing on electricity companies. Due to BNDES' right of acceleration and existing financial covenant and other defaults under Eletropaulo loan agreements, Eletropaulo's commercial lenders have the right to call due approximately $836 million of indebtedness. In addition, Eletropaulo has indebtedness of approximately $514 million scheduled to mature in 2003. At December 31, 2002, Eletropaulo, AES Elpa and AES Transgas have a combined $1.9 billion of debt classified as current on the accompanying consolidated balance sheet.

Eletropaulo, AES Elpa and AES Transgas are in negotiations with debt holders, BNDES and BNDESPAR to seek resolution of these issues; however, there can be no assurance that these negotiations will be successful. If the negotiations are not successful, Eletropaulo would face an increased risk of loss of its concession and of bankruptcy, resulting in an increased risk of loss of AES's investment in Eletropaulo. Dividend restrictions applicable to Eletropaulo are expected to reduce substantially the ability of Eletropaulo to pay dividends. In addition, the refinancing agreement entered into with BNDES in June 2002 provides for Eletropaulo to pay directly to BNDES any dividends in respect of the shares held by AES Elpa, AES Transgas and Cemig Empreendimentos II Ltd. In light of the failure of AES Elpa and AES Transgas to make the BNDES and BNDESPAR payments when due, BNDES and BNDESPAR may choose to foreclose on the collateral, and this may result in a loss and a corresponding write-off of a portion or all of the Company's investment in Eletropaulo. In addition, the default on the BNDES loan could also result in a cross-default to a BNDES loan in connection with our investment in CEMIG.

Although neither AES Elpa nor AES Transgas currently constitute "material subsidiaries" for purposes of the cross-default, cross acceleration and bankruptcy related events of default contained in AES's parent company indebtedness, Eletropaulo does constitute a "material subsidiary" for purposes of certain of such bankruptcy related events of default. However, given that a bankruptcy proceeding would generally be an unattractive remedy for Eletropaulo's lenders, as it could result in an intervention by ANEEL or a termination of Eletropaulo's concession, and given that Eletropaulo is currently in negotiations to restructure such indebtedness, the Company believes such an outcome is unlikely. The Company cannot assure you, however, that such negotiations will be successful. As a result, AES may have to write-off some or all of the assets of Eletropaulo, AES Elpa or AES Transgas.

Sul. Sul and AES Cayman Guaiba, a subsidiary of the Company that owns the Company's interest in Sul, are facing near-term debt payment obligations that must be extended, restructured, refinanced or paid. Sul had outstanding debentures of $53 million, at the December 31, 2002 exchange rate, that were restructured on December 1, 2002. The restructured debentures have partial interest payments due in June 2003 and December 2003 and principal payments due in 12 equal monthly installments commencing on December 1, 2002. The banks under the $300 million AES Cayman Guaiba syndicated loan have granted a waiver in respect of $30 million of principal payments due under such loan until the earlier of April 24, 2003 and the execution of satisfactory final documentation in respect of the restructuring of such loan. The Company cannot assure you, however, that the restructuring will be completed.

In addition, during the second quarter of 2002, ANEEL promulgated an order ("Order 288") whose practical effect was to purport to invalidate gains recorded by Sul from inter-submarket trading of energy purchased from the Itaipu power station. The Company, in total, recorded a pre-tax provision as a reduction of revenues of approximately $160 million during the second quarter of 2002. 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.

Sul continues legal action against ANEEL to seek resolution of these issues. Sul and AES Cayman Guaiba will continue to face shorter-term debt maturities in 2004 but, given that a bankruptcy proceeding would generally be an unattractive remedy for each of its lenders, as it would result in an intervention by ANEEL or a termination of Sul's concession, and because Sul has completed negotiations for debt restructuring through 2003, we think such an outcome is unlikely. We cannot assure you, however, that future negotiations will be successful and AES may have to write off some or all of the assets of Sul or AES Cayman Guaiba. The Company's total investment associated with Sul as of December 31, 2002 was approximately $146 million, which is net of foreign currency translation losses.

During the first quarter of 2002, the Company recorded an after-tax impairment charge of $231 million related to the write off of goodwill at Sul. This charge resulted from the adoption of SFAS No. 142 and is recorded as a cumulative effect of a change in accounting principle on the consolidated statements of operations.

In the fourth quarter of 2002, a combination of events occurred related to the CEMIG investment. These events included consistent poor operating performance in part caused by continued depressed demand and poor asset management, the inability to adequately service or refinance operating company debt and acquisition debt, and a continued decline in the market price of CEMIG shares. Additionally, our partner in one of the holding companies in the CEMIG ownership structure sold its interest in this company to an unrelated third party in December 2002 for a nominal amount. Upon evaluating these events in conjunction with each other, the Company concluded that an other than temporary decline in value of the CEMIG investment had occurred. Therefore, in December 2002, AES recorded a charge related to the other than temporary impairment of the investment in CEMIG, and the shares in CEMIG were written-down to fair market value. Additionally, AES recorded a valuation allowance against a deferred tax asset related to the CEMIG investment. The total amount of these charges, net

of tax, was $587 million, of which $264 million relates to the other than temporary impairment of the investment and $323 million relates to the valuation allowance against the deferred tax asset. At December 31, 2002, the Company's total investment associated with CEMIG was negative.

Tiete. The MAE settlement for the period from September 2000 to September 2002 for Tiete totals an obligation of approximately $64 million, at the December 31, 2002 exchange rate. Fifty percent of the amount was due on December 26, 2002, and the rest is due after MAE's numbers are audited. According to the industry-wide agreement reached in December 2001, BNDES was supposed to provide Tiete with a credit facility in the amount of approximately $43 million at the December 31, 2002 exchange rate to pay off a part of the liability. This credit facility has not yet been provided. In the meantime, the Federal Court has granted Tiete an injunction suspending the payment of the obligation until BNDES makes this credit facility available. However, if the MAE settles absent the effect of ANEEL Order 288, which is currently being appealed by market participants, including Sul, Tiete's obligation to the MAE would be increased by $17 million at the December 31, 2002 exchange rate. The appealing market participants have received a favorable injunction against ANEEL's Order 288. However, this injunction was overturned in February 2003. The Company's total investment associated with Tiete as of December 31, 2002 was approximately $26 million, which is net of foreign currency translation losses.

Under Brazilian corporate law, Tiete may only pay to shareholders dividends or interest on net worth from net income less allocations to statutory reserves. In 2002, Tiete's dividends and interest on net worth paid to shareholders were insufficient to enable payment to be made of amounts due on debt obligations of AES IHB Cayman, Ltd., an affiliate of Tiete, guaranteed by Tiete's parent company, AES Tiete Holdings, Ltd., and direct shareholders, AES Tiete Empreendimentos Ltda ("TE") and Tiete Participaçoes Ltda. As a result, those payments were principally funded through Tiete capital reductions and intercompany loans from Tiete to TE. These debt obligations are also supported by a foreign exchange guaranty facility and related political risk insurance provided by the Overseas Private Investment Corporation ("OPIC"), an agency of the United States government. A payment of principal and interest on the debt obligations in the amount of approximately $21.5 million is due on June 15, 2003. Because Tiete recorded a net loss for 2002, no dividends or interest on net worth will be available to enable that payment to be made. As a result, Tiete Holdings intends to seek certain amendments to the debt obligations and the OPIC documentation designed to reduce the risk of defaults due to the limitation on dividend and interest on net worth payments, including amendments to allow debt payments to be made with the proceeds of loans from Tiete. Any loan by Tiete to its affiliates is subject to ANEEL approval. No assurance can be given, however, that these amendments will be adopted or that ANEEL will grant such approval.

Uruguaiana. The MAE settlement for the period from September 2000 to September 2002 for Uruguaiana totals an obligation of approximately $13 million at the December 31, 2002, exchange rate. Fifty percent of the outstanding liability was due on December 26, 2002. Uruguaiana disagreed with the liability for the period from December 2000 to March 2002, which represents approximately $11 million at the December 31, 2002, exchange rate, and on December 18, 2002, Uruguaiana obtained an injunction from the Federal Court suspending the payment of the liability under dispute. On February 25, 2003, ANEEL and MAE filed an appeal against the injunction. On March 12, 2003, the judge responsible for the case did not accept the appeal and maintained the injunction for Uruguaiana. Uruguaiana believes that under the terms of its ANEEL Independent Power Producer Operational Permit, power purchase and regulatory contracts, it is not liable for replacement power costs arising directly out of the electric system's instability. Furthermore, the civil action also discusses the power prices changed by ANEEL in August 2002 related to energy sold at the spot market in June 2001. Uruguaiana does not expect to have sufficient resources to pay the MAE settlement, and if the legal challenge of this obligation is not successful, penalties and fines could be imposed, up to and including the termination of the ANEEL Independent Power Producer Operational Permit. The Company's total investment associated with Uruguaiana as of December 31, 2002 was approximately $272 million, which is net of foreign currency translation losses.

Other Regulatory Matters. The electricity industry in Brazil reached a critical point in 2001 as a result of a series of regulatory, meteorological and market driven problems. The Brazilian government implemented a program for the rationing of electricity consumption effective as of June 2001. In December 2001, an industry-wide agreement was reached with the Brazilian government that applies to Eletropaulo, Tiete, CEMIG, Sul and Uruguaiana. There were three parts of the agreement that specifically affected AES. The terms of the agreement were implemented during 2002.

First, Annex V, a provision in the initial contracts between the generators and the distributors that was designed to protect the distribution companies from reduced sales volumes and to limit the financial burden of generation companies during periods of rationing, was replaced with a tariff increase that would compensate both generators and distributors for rationing related losses. The net ownership-adjusted impact to AES from the elimination of Annex V and the resulting tariff increase represented additional income before taxes of $60 million. However, the amount recorded under the new methodology at December 31, 2001 was substantially the same as the contractual receivable previously recorded under Annex V. Accordingly, the only impact was the balance sheet reclassification of the receivable to a regulatory asset. The tariff increase will remain in effect 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.

The second part of the agreement relates to the Parcel A costs which are certain costs that each distribution company is permitted to defer and pass through to its customers via a future tariff adjustment. Parcel A costs are limited by the concession contracts to the cost of purchased power and certain other costs and taxes. The Brazilian regulator had granted tariff increases to recover a portion of previously deferred Parcel A costs. However, due to uncertainty surrounding the Brazilian economy, the regulator had delayed approval of some Parcel A tariff increases. As part of the agreement, a tracking account that was previously established was officially defined. Parcel A costs incurred previous to January 1, 2001 were not allowed under the definition of the tracking account. As a result, 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 third part of the agreement, Sul was permitted to record additional revenue and a corresponding receivable from the spot market in the fourth quarter of 2001. However, the electricity regulator, ANEEL promulgated Order 288 which retroactively changed certain previously communicated methodologies during May 2002, 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 an injunction in October 2002, which was upheld in December 2002, forcing MAE to keep its original values. The injunction was reversed in the beginning of February 2003. Sul continues to pursue judicial options to address this situation.

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.

The politics and economy in Venezuela have been experiencing significant systemic crisis. The economy has suffered from falling oil revenues, capital flight and a decline in foreign reserves. The country is experiencing a negative growth of GDP, high unemployment, significant foreign currency fluctuations and political instability. Beginning December 2, 2002 Venezuela experienced a forty-five day nationwide general strike that affected a significant portion of the Venezuelan economy, including the city of Caracas and the oil industry. This general strike has affected the normal conduct of the business of EDC. In combination, these circumstances create significant uncertainty surrounding the performance, cash flow and potential for profitability of EDC. However, AES is not required to support the potential cash flow or debt service obligations of EDC. AES's total investment in EDC at December 31, 2002 was approximately $1.8 billion, which is net of foreign currency translation losses.

In February 2002, the Venezuelan Government decided not to continue support of the Venezuelan currency, which has caused significant devaluation. As a result of the change, the U.S. dollar to Venezuelan exchange rate had floated as high as 1,497 before declining to 1,403 at December 31, 2002 as compared to 758 at December 31, 2001. EDC uses the U.S. dollar as its functional currency. A portion of its debt is denominated in the Venezuelan Bolivar, and as of December 31, 2002, EDC has net Venezuelan Bolivar monetary liabilities thereby creating foreign currency gains when the Venezuelan Bolivar devalues. During 2002, the Company recorded pre-tax foreign currency transaction gains of approximately $39 million, as well as $40 million of pre-tax mark to market gains on a foreign currency forward contract due to a decline in the Venezuelan Bolivar to the U.S. dollar exchange rate. The tariffs at EDC are adjusted semi-annually to reflect fluctuations in inflation and the currency exchange rate. However, a failure to receive such adjustment to reflect changes in the exchange rate and inflation could adversely affect the Company's results of operations.

Effective January 21, 2003, the Venezuelan Government and the Central Bank of Venezuela (Central Bank) agreed to suspend the trading of foreign currencies in the country for five business days and to establish new standards for the foreign currency exchange regime. Then, effective February 5, 2003, the Venezuelan Government and the Central Bank entered into an exchange agreement that will govern the Foreign Currency Management Regime, and establish the applicable exchange rate. The exchange agreement established certain conditions including the centralization of the purchase and sale of currencies within the country by the Central Bank, and the incorporation of the Foreign Currency Management Commission (CADIVI) to administer the execution of the exchange agreement and establish certain procedures and restrictions. The acquisition of foreign currencies will be subject to the prior registration of the interested party and the issuance of an authorization to participate in the exchange regime. Furthermore, CADIVI will govern the provisions of the exchange agreement, define the procedures and requirements for the administration of foreign currencies for imports and exports, and authorize purchases of currencies in the country. The exchange rates set by such agreements are 1,596 Bolivars per U.S. dollar for purchases and 1,600 Bolivars per U.S. dollar for sales. These actions may impact the ability of EDC to distribute cash to the parent.

combination of cost-plus and return on investment methodologies. The regulation that establishes basic tariff rates is expected to change for 2003, and this change may have an impact on the amount and timing of the cash flows and earnings reported by EDC.

At December 31, 2002, EDC was not in compliance with two of its net worth covenants on $131 million and $9 million of non-recourse debt primarily due to the impact of the devaluation of the Venezuelan Bolivar. EDC requested and received from its lenders waivers for both covenants, which are effective through March 31, 2003. Of the related debt, approximately $102 million is classified as non-recourse debt—long term in the accompanying consolidated balance sheets. The remainder is classified as non-recourse debt—current.

Drax a subsidiary of AES, is the operator of the Drax Power Plant, Britain's largest power station. On November 14, 2002, TXU Europe Energy Trading Limited ("TXU EET") was required to make a £49 million payment to Drax for power purchased in October under the hedging contract ("Hedging Agreement") between Drax and TXU EET. TXU EET failed to make the payment, and attempts to negotiate a solution acceptable to both parties proved unsuccessful. On November 18, 2002, Drax terminated the Hedging Agreement, with immediate effect, on the grounds of TXU EET's failure to provide the credit support of approximately £270 million required under the terms of the Hedging Agreement. On November 19, 2002, TXU EET and certain other entities including the guarantor of the Hedging Agreement, TXU Europe Group plc ("TXU Group"), were placed into administration. Following termination of the Hedging Agreement, and the placing of TXU EET and TXU Group into administration, Drax has been working cooperatively with its lenders to address the liquidity needs of the project, including letters of credit required to support trading Drax's output in the open market. Drax has submitted a claim for capacity damages of approximately £266 million in accordance with the terms of the Hedging Agreement as well as a claim of approximately £85 million for unpaid electricity delivered in October and November. The Hedging Agreement accounted for approximately 60% of the revenues generated by Drax and payments under this agreement were significantly higher than Drax is currently receiving in the open market. As a result of the termination of the Hedging Agreement, the Company recorded an after-tax impairment loss of approximately $893 million in the fourth quarter of 2002. Drax is classified as held for sale in the accompanying consolidated balance sheets. On December 13, 2002, Drax signed a standstill agreement with its senior lenders to provide Drax time to restructure its business after the termination of the Hedging Agreement. The standstill agreement provides temporary and/or permanent waivers by the senior lenders of defaults that have occurred or could occur up to the expiry of the standstill period on May 31, 2003 including a permanent waiver resulting from termination of the Hedging Agreement.

Since certain of Drax's forward looking debt service cover ratios as of June 30, 2002 were below required levels, Drax, was not able to make any cash distributions to Drax Energy at that time. Drax expects that the ratios, if calculated as of December 31, 2002, would again be below the required levels at December 31, 2002 since any improvement in the ratios for the period ended December 31, 2002 would have required a favorable change in the forward curve for electricity prices during the period from June 30, 2002 to December 31, 2002 and such favorable change did not occur. As part of the standstill agreement signed by the Drax entities and its senior lenders, the debt service coverage ratios as of December 31, 2002 were not calculated by the bank group. As a consequence of the foregoing, Drax was not permitted to make any distributions to Drax Energy, the holding company high-yield note issuer. As a result, Drax Energy was unable to make the full amount of the interest payment of $11.5 million and £7.6 million due on its high-yield notes on February 28, 2003. Drax Energy's failure to make the full amount of the required interest payment constitutes an event of default under its high-yield notes, although pursuant to intercreditor agreements the holders of the high-yield notes have no enforcement rights until 90 days following the delivery of certain notices under the intercreditor arrangements. Drax is currently a material subsidiary for certain bankruptcy-related events of default

contained in AES's parent company indebtedness, and therefore certain bankruptcy events of Drax could result in a default under our corporate debt agreements.

On September 30, 2002, Barry entered into a tolling agreement with TXU EET and an associated guarantee agreement (subject to a cap) with TXU Group. On November 19, 2002, TXU EET and certain other entities including TXU Group were placed into administration, and Barry subsequently terminated the tolling agreement on November 26, 2002 on the grounds of insolvency of TXU EET and TXU Group. As a result of the termination of the tolling agreement, the Company recorded an after-tax impairment loss of approximately $120 million in the fourth quarter of 2002. On December 20, 2002, Barry signed a standstill agreement with its senior lenders to provide time for Barry to investigate the options available to restructure the business. The standstill agreement provides waivers by the senior lenders of certain defaults that have occurred or could occur up to the expiry of the standstill period on March 31, 2003.

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, 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. AES participates primarily in four lines of business: large utilities, growth distribution, contract generation and competitive supply.

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%. 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. 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 the Company's large utility businesses are sensitive to changes in economic growth, abnormal weather conditions affecting their markets, and regulatory changes.

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 large utility segment. Distribution facilities included in this line of business may include integrated generation, transmission, distribution or related services companies. The results of operations of the Company's growth distribution business are sensitive to changes in economic growth, abnormal weather conditions affecting their market and regulatory changes.

AES's contract generation line of business consists of multiple power generation facilities located around the world. Provided 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 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.

For instance, with Gener, the Company's contract generation business in Chile, the price for electricity received under its electricity sales contracts is impacted by decisions of the regulatory authorities in Chile that establish prices known as "node prices" every six months to be paid by distribution companies for the energy and capacity requirements of regulated customers. Node prices for energy are calculated on the basis of the projections of the expected marginal costs within the system. Node prices for capacity are calculated based on the marginal investment required to meet peak demand, based on the cost of a diesel-fired turbine. The prices for energy and capacity sold on a contractual basis in Chile are generally set with reference to those node prices. This administratively-determined pricing mechanism has more volatility than other contractual arrangements where the price for electricity is not subject to similar adjustment.

Certain of the Company's contract generation customers are regulated utilities that are regulated by PUCs. PUCs often restrict the amount of debt those utilities are permitted to incur, as well as the types of business activities in which they participate. This generally results in a stronger customer credit quality.

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. The Company's investment in these three subsidiaries is approximately $184 million at December 31, 2002. For the year ended December 31, 2002, the Company recorded $5.9 million of net income from the three subsidiaries.

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. In the United Kingdom, TXU Europe entered administration in November 2002 and is no longer performing under its contracts with Drax and Barry. As described in the footnotes and in other sections of the Discussion and Analysis of Financial Condition and Results of Operations, TXU Europe's failure to perform under its contracts has had a material adverse effect on the results of operations of these businesses.

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 the 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.

The revenues from our facilities that distribute electricity to end-use customers are generally subject to regulation. These businesses are generally required to obtain third party approval or confirmation of rate increases before they can be passed on to the customers through tariffs. These businesses comprise the large utilities and growth distribution segments of the Company. Revenues from contract generation and competitive supply are not regulated.

The distribution of revenues between the segments for the years ended December 31, 2002, 2001 and 2000 is as follows:

	2002		2001		2000
Large utilities	36	%	21	%	22	%
Growth distribution	14	%	21	%	21	%
Contract generation	29	%	32	%	27	%
Competitive supply	21	%	26	%	30	%

that these costs are recoverable; however, no assurance can be given that individual projects will be completed and reach commercial operation.

During 2002, the Company took an after-tax charge of approximately $465 million to write off its investments in certain development projects including AES Lake Worth ("Lake Worth"), AES Greystone, LLC ("Greystone") and Mountainview.

Lake Worth is a 210 megawatt gas-fired power plant currently under construction in Florida. In the fourth quarter of 2002, circumstances surrounding the Lake Worth project indicated that the carrying amount of the Company's investment in the Lake Worth project may not be recoverable. Therefore, in accordance with SFAS No. 144, a pre-tax impairment charge of $78 million ($51 million after-tax) was recorded to write-down the net assets of the project to their fair value. The timing of this charge was due to a decision by the Company not to provide any further funding for this project and to sell the project. Lake Worth is a competitive supply business.

In September 2002, Greystone and its subsidiary Haywood Power I, LLC, sold the Greystone gas-fired peaker assets then under construction in Tennessee to Tenaska Power Equipment for $36 million including cash and assumption of certain obligations. With this sale, AES and its subsidiaries have eliminated any future capital expenditures related to the facility, and also settled all major outstanding obligations with parties involved in this project. AES recorded a pre-tax loss of approximately $168 million ($110 million after-tax) associated with this sale. Greystone was previously recorded as a competitive supply business.

Mountainview consists of a completed 126 megawatt gas-fired power plant and a 1,056 megawatt gas-fired power plant under construction in California. In December 2002, AES classified its investments in Mountainview as held for sale. In the fourth quarter of 2002, the Company recorded a pre-tax impairment charge of $415 million ($270 million after-tax) to reduce the carrying value of Mountainview's assets to estimated realizable value in accordance with SFAS No. 144. The determination of the realizable value was based on available market information obtained through discussions with potential buyers. In January 2003, the Company entered into an agreement to sell Mountainview for $30 million with another $20 million payment contingent on the achievement of project specific milestones. The transaction closed in March 2003. Mountainview was previously reported in the competitive supply segment.

The Company utilizes derivative financial instruments to manage interest rate risk, foreign exchange risk and commodity price risk. Although the majority of the Company's derivative instruments qualify for hedge accounting, the adoption of SFAS No. 133 in 2001 has resulted in more variation to the Company's results of operations from changes in interest rates, foreign exchange rates and commodity prices. For the year ended December 31, 2002, the Company recognized $42 million of gains, net of income taxes, primarily related to derivatives which did not qualify for hedge accounting. See Note 10 to the consolidated financial statements which provides a more complete discussion of the Company's accounting for derivatives.

The Company does not engage in significant energy trading activities associated with its retail and wholesale supply businesses. For the years ended December 31, 2002, 2001 and 2000, the Company recorded net gains from energy trading activities of $0 million, $5 million and $21 million, respectively.

The Company did not enter into any related party transactions that were material for financial reporting purposes during the years ended December 31, 2002, 2001 and 2000.

Certain foreign and domestic subsidiaries of the Company maintain defined benefit pension plans (the "Pension Plans", or the "Plans") covering substantially all of their respective employees. Pension benefits are generally based on years of credited service, age of the participant and average earnings. Of the thirteen Pension Plans existing at December 31, 2002, three are at domestic subsidiaries and ten are at foreign subsidiaries. These exclude one domestic Plan and one foreign Plan maintained at businesses classified as held for sale or discontinued operations during 2002.

Two defined benefit pension plans constitute 85% of pension cost for the year ended December 31, 2002, 89% of the benefit obligation at December 31, 2002 and 86% of the fair value at December 31, 2002. One plan is a plan administered in the United States (the "US Plan") and the other plan is administered in Brazil (the "Brazilian Plan"). Of the remaining plans, no one plan represents a significant portion of the pension cost, benefit obligation or fair value at December 31, 2002.

Pension cost for the US Plan is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on plan assets of 9% in 2002 and 2001 and 8% in 2000. In developing our expected long-term rate of return assumption, we evaluated input from our actuaries, including their review of asset class return expectations by several respected consultants and economists, as well as long-term inflation assumptions. Projected returns by such consultants and economists are selected from within the "best estimate range", which is the smallest range which the actuary reasonably anticipates that the actual results, compounded over the measurement period, are more likely to fall than not. The best estimate of this range is based on asset class return expectations which reflect historical data as well as the opinion of several consultants and economists about the forecasted returns of each class. The best estimate range is a probability distribution of returns that spans the 25^th to 75^th percentiles of 20-year returns. It is anticipated that our investment managers will continue to generate long-term returns of at least 9%. Our expected long-term rate of return on plan assets is based on an asset allocation assumption of 45% U.S. equities, 10% non-U.S. equities, 40% fixed income and 5% real estate which is equal to our actual asset allocation. We continue to believe that 9% is a reasonable long-term rate of return on our plan assets. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually, and will adjust as necessary.

The US Plan bases its determination of pension expense or income on the fair value of assets on the measurement date. As of December 31, 2002, the US Plan has generated cumulative unrecognized net actuarial losses of approximately $91 million which remain to be recognized in pension cost. These unrecognized net actuarial losses result in decreases in future pension income depending on several factors, including whether such losses at each measurement date exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets in accordance with SFAS No. 87, "Employers Accounting for Pensions".

The discount rate used for determining future pension obligations for the US Plan is based upon the Aa rated annual yield as of the measurement date as published in the Moody's Daily Long-term Corporate Bond Yields based on bonds with maturities of 20 years and above. The discount rates determined using this basis were 6.75% in 2002, 7.25% in 2001, and 8.00% in 2000.

Lowering the expected long-term rate of return on the US Plan assets by 1.0% would have increased our 2002 pension cost by approximately $2.5 million. Lowering the discount rate by 100 basis points would increase our 2002 pension cost by approximately $2.8 million.

The fair value of the US Plan's assets has decreased to $224 million at December 31, 2002 from $257 million at December 31, 2001. The investment performance returns and benefits paid during 2002 has increased the underfunded position, net of benefit obligations, of the US Plan from $127 million at December 31, 2001 to $187 million at December 31, 2002.

The Brazilian Plan began to be reported on a consolidated basis when the acquisition of an additional ownership interest in Eletropaulo occurred in February 2002. Pension cost for the Brazilian Plan is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on plan assets of 15% in 2002. In developing our expected long-term rate of return assumption, we evaluated input from our actuaries, including their review of asset class return expectations which are based on studies of historical data series as well as the opinion of several respected consultants and economists about forecasts, long-term inflation assumptions, dollar spot assumptions and local interest rate assumptions. Each asset class return expectation is based upon historical returns for assets with similar maturities and risk. It is anticipated that our investment managers will continue to generate long-term returns of at least 15%. Over the past seven years, the Brazilian Plan has had actual returns of 18%. Our expected long-term rate of return on plan assets is based on an asset allocation assumption of 83% fixed income investments, 12% equities and 5% real estate. Our assumed asset allocation uses a lower exposure to equities to more closely match market conditions and near-term forecasts. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually, and will adjust as necessary.

The Brazilian Plan bases its determination of pension expense or income on the fair value of assets on the measurement date. As of December 31, 2002, the Brazilian Plan has generated cumulative unrecognized net actuarial losses of approximately $562 million which remain to be recognized in pension cost. These unrecognized net actuarial losses result in decreases in future pension income depending on several factors, including whether such losses at each measurement date exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets in accordance with SFAS No. 87, "Employers Accounting for Pensions".

The discount rate used for determining future pension obligations for the Brazilian Plan is based on long-term annuity contracts since there is no active corporate bond market in Brazil. The discount rate determined on this basis is 9% for 2002.

Lowering the expected long-term rate of return on our Plan assets by 1.0% would have increased our 2002 pension cost by approximately $6.5 million. Lowering the discount rate by 100 basis points would increase our 2002 pension cost by approximately $12 million.

The fair value of the Brazilian Plan assets is $642 million at December 31, 2002. The Brazilian Plan has an underfunded position, net of benefit obligations, of $969 million at December 31, 2002.

Annually, we review all Pension Plans to determine if the Plans' accumulated benefit obligations exceed the fair value of the Plans' assets. If the accumulated benefit obligations exceed the fair value of plan assets, an additional minimum pension liability is recorded on the balance sheet, with a corresponding charge to other comprehensive income. We may incur additional minimum pension liabilities in future periods and they could be material.

AES prepares its consolidated financial statements in accordance with accounting principles generally accepted in the U.S. As such, it is required to make certain estimates, judgments and assumptions that it believes are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. The significant accounting policies which AES believes are most critical to understanding and evaluating its reported financial results include those pertaining to the following: Property, Plant and Equipment; Long-Lived Assets; Functional Currency Determination; Regulatory Assets and Contingencies.

Property, plant and equipment is recorded at cost and is depreciated over its estimated useful life. The estimated useful lives of AES's generation and distribution facilities range from 10 to 50 years. A significant decrease in the estimated useful life of a material amount of property, plant and equipment could have a material adverse impact on our operating results in the period in which the estimate is revised and subsequent periods. The loss of a long-term contract and the inability to replace it at one of our contract generation businesses or a significant overabundance of supply and a sustained, significant decline in market prices in the regions served by our competitive supply businesses could cause us to decrease the estimated useful life of our impacted generation facilities. The loss of a long-term concession agreement and the inability to replace it at one of our growth distribution businesses or large utilities could cause us to decrease the estimated useful life of our impacted distribution facilities. Additionally, significant physical damage or a significant mechanical failure may cause us to decrease the estimated useful life of the affected property, plant and equipment. If the useful life of any of our property, plant and equipment is changed, the new life would be based on engineering studies and expected usage. The estimated average remaining useful life of our property, plant and equipment is approximately 23 years. If the estimated average remaining useful life of our property, plant and equipment decreased by 5 years, annual depreciation expense would increase by $220 million.

AES evaluates the impairment of its long-lived assets based on the projection of undiscounted cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. Estimates of future cash flows used to test the recoverability of specific long-lived assets are based on expected cash flows from the use and eventual disposition of the assets. AES has $8.5 billion of long-lived contract generation assets, and expected cash flows for businesses within the contract generation segment are based on the expected output of the generation facilities as well as the terms of our contractual agreements. AES has $3.2 billion of long-lived competitive supply assets, and expected cash flows for businesses within the competitive supply segment are based on the expected output of the generation facilities as well as expected future market prices as published on industry forward curves and other market price studies. AES has $6.2 billion of large utility long-lived assets and $1.8 billion of growth distribution long-lived assets. In determining expected cash flows for businesses within our large utilities and growth distribution segments, we consider historical experience as well as future expectations, and the expected future cash flows are based on expected future tariffs and expected future customer demand. A significant reduction in actual cash flows and estimated cash flows may have a material adverse impact on AES's operating results and financial condition.

A business's functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. AES's consolidated financial results are reported in U.S. dollars and include the effects of translating the financial statements from our international businesses with a functional currency different from the U.S. dollar to the U.S. dollar. Assets and liabilities are translated at the exchange rate in effect at the end of the period. Revenues and expenses are translated at the average exchange rate for the period. Translation adjustments that result from translating financial statements into the U.S. dollar are not included in determining net income and are reported in other comprehensive income in the equity section of the consolidated balance sheet. Some of AES's businesses have foreign currency transactions which are transactions denominated in a currency other than the business's functional currency. A change in exchange rates between the functional currency and the currency in which the transaction is denominated results in a foreign currency transaction gain or loss that is included in the determination of net income. If facts and circumstances require a change in the functional currency of a significant

subsidiary, the change in functional currency could have a material impact on AES's operating results and financial condition. A change in the commercial contracts of a business which resulted in indexation of revenues and expenses to a currency other than the local currency of the business would require us to evaluate the appropriate functional currency for that respective business. Additionally, a significant change in the denomination of the financing and the availability of cash flows for remittance to the parent would require us to evaluate the appropriate functional currency for that respective business.

AES capitalizes incurred costs as deferred regulatory assets when there is a probable expectation that future revenue equal to the costs incurred will be billed and collected as a direct result of the inclusion of the costs in an increased tariff set by the regulator. The Company's expectation that it will be able to recover the costs is based upon the regulation within the regions in which we operate as well as precedent. The assets are recovered when AES collects the related costs through billings to customers. AES has recorded deferred regulatory assets of $627 million and $390 million at December 31, 2002, and 2001, respectively, that it expects to pass through to its customers in accordance with and subject to regulatory provisions. These amounts include $11 million and $12 million of assets classified as discontinued operations at December 31, 2002 and 2001, respectively. The deferred regulatory assets at entities which are controlled and consolidated by AES are recorded in other assets on the consolidated balance sheets. If the regulator disallows a material amount of capitalized costs to be included in future tariffs, the write off of the regulatory assets may have a material adverse impact on AES's operating results.

AES accrues for loss contingencies when the amount of the loss is probable and estimable. Estimates of the probability and the amount of loss are often made in consultation with third-party experts and vary based on specific facts and circumstances. AES is subject to various environmental regulations, and is involved in certain legal proceedings. If the Company's actual environmental and/or legal obligations are materially different from its estimates, the recognition of the actual amounts may have a material impact on AES's operating results and financial condition.

Asset retirement obligations. In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143, which is effective January 1, 2003, requires entities to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. When a new liability is recorded beginning in 2003, the entity will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company will adopt SFAS No. 143 effective January 1, 2003.

The Company has completed a detailed assessment of the specific applicability and implications of SFAS No. 143. The scope of SFAS No. 143 includes primarily active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. As of December 31, 2002, the Company had a recorded liability of approximately $15 million related to asset retirement obligations. Upon adoption of SFAS No. 143, the Company will record an additional liability of approximately $13 million, a net asset of approximately $9 million, and a cumulative effect of a change in accounting principle of approximately $2 million, after income taxes. Proforma net (loss) income and (loss) earnings per share have not been presented for the years ended December 31, 2002, 2001 and 2000 because the proforma application of SFAS No. 143 to prior periods would result in proforma net (loss) income and (loss) earnings per share not materially different from the actual amounts reported for those periods in the accompanying consolidated statements of operations.

Early extinguishments of debt. During the second quarter of 2002, the Company adopted SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." Among other items, this Statement rescinds FASB Statement No. 4, "Reporting Gains and Losses from Extinguishments of Debt". As a result, early extinguishments of debt are no longer reported as extraordinary items but are included in income from continuing operations. For the year ended December 31, 2002, the Company extinguished debt with a face value of approximately $117 million for approximately 21.6 million shares of the Company's common stock. This resulted in a gain of approximately $44 million for the year ended December 31, 2002 which is recorded in other income in the accompanying consolidated statement of operations. There were no early extinguishments of debt during 2001. In 2000, the Company recognized losses of approximately $11 million related to the early extinguishment of debts.

Exit or disposal activities. In June 2002, the Financial Accounting Standards Board issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses financial accounting and reporting for costs associated with exit or disposal activities. This Statement requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Prior to issuance of SFAS No. 146, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002. We do not expect the adoption of this pronouncement to have a material impact on our financial statements.

Stock-based compensation. In December 2002, the Financial Accounting Standards Board issued SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure." SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company expects to use the prospective method to transition to the fair value based method of accounting for stock-based employee compensation. All employee awards granted, modified, or settled after January 1, 2003, will be recorded using the fair value based method of accounting. The expanded disclosures required by SFAS No. 148 will be included in our quarterly financial reports beginning in the first quarter of 2003.

Guarantor accounting. The Company adopted the disclosure provisions of FASB Interpretation No. ("FIN") 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others," in the fourth quarter of 2002. We will apply the initial recognition and measurement provisions on a prospective basis for all guarantees issued after December 31, 2002. Under FIN 45, at the inception of guarantees issued after December 31, 2002, we will record the fair value of the guarantee as a liability, with the offsetting entry being recorded based on the circumstances in which the guarantee was issued. We will account for any fundings under the guarantee as a reduction of the liability. After funding has ceased, we will recognize the remaining liability in the income statement on a straight-line basis over the remaining term of the guarantee. In general, we enter into various agreements providing financial performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. FIN 45 does not encompass guarantees issued either between parents and their subsidiaries or between corporations under common control, a parent's guarantee of its subsidiary's debt to a third party (whether the parent is a corporation or an individual), a subsidiary's guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent, nor guarantees of a Company's own future performance. Adoption of FIN 45 will have no impact to our historical financial statements as existing guarantees are not subject to the measurement provisions of FIN 45. The Company does not expect adoption of the liability recognition provisions of FIN 45 to have a material impact on our financial position or results of operations.

Variable interest entities. FIN 46, "Consolidation of Variable Interest Entities," is effective immediately for all enterprises with variable interests in variable interest entities created after January 31, 2003. FIN 46 provisions must be applied to variable interests in variable interest entities created before February 1, 2003 from the beginning of the third quarter of 2003. If an entity is determined to be a variable interest entity, it must be consolidated by the enterprise that absorbs the majority of the entity's expected losses if they occur and/or receives a majority of the entity's expected residual returns if they occur. If significant variable interests are held in a variable interest entity, the company must disclose the nature, purpose, size and activity of the variable interest entity and the company's maximum exposure to loss as a result of its involvement with the variable interest entity in all financial statements issued after January 31, 2003. We do not believe that the adoption of FIN 46 will result in our consolidation of any previously unconsolidated entities or material additional disclosure.

DIG Issue C11. In connection with the January 2003 FASB Emerging Issues Task Force (EITF) meeting, the FASB was requested to reconsider an interpretation of SFAS No. 133. The interpretation, which is contained in the Derivatives Implementation Group's C11 guidance, relates to the pricing of contracts that include broad market indices. In particular, that guidance discusses whether the pricing in a contract that contains broad market indices (e.g. CPI) could qualify as a normal purchase or sale. The Company is currently reevaluating which contracts, if any, that have previously been designated as normal purchases or sales would now not qualify for this exception. The Company is currently evaluating the effects that this guidance will have on its results of operations and financial position.

Revenues increased $1.0 billion, or 13%, to $8.6 billion in 2002 from $7.6 billion in 2001. The increase in revenues is due to the acquisition of new businesses, new operations from greenfield projects and positive improvements from existing operations. Excluding businesses acquired or that commenced commercial operations in 2002 or 2001, revenues decreased 17% to $6.1 billion in 2002. AES is a global power company which operates in 31 countries around the world. The breakdown of AES's revenues for the years ended December 31, 2002 and 2001, based on the business segment and geographic region in which they were earned, is set forth below.

Regulated revenues. Regulated revenues increased 33% or $1.1 billion to $4.3 billion in 2002 compared to $3.3 billion in 2001. The $1.5 billion increase in large utilities revenues was offset by a $433 million decline in growth distribution revenues. Weather generally impacts the demand for electricity, and therefore, extreme temperatures will impact the amount of revenues recorded. Excluding businesses acquired or that commenced operations in 2002 or 2001, regulated revenues decreased 27% to $2.3 billion during 2002.

Large utilities revenues increased 91% or $1.5 billion to $3.1 billion in 2002 compared to $1.6 billion in 2001. This change was primarily due to the consolidation of Eletropaulo in Brazil partially offset by an $18 million decrease in North America and a $172 million decrease in the Caribbean. The North America change was primarily due to lower revenues at IPALCO in Indiana resulting from low wholesale electricity prices. The Caribbean decline occurred at EDC in Venezuela and was primarily caused by the devaluation of the Venezuelan Bolivar. The Company began consolidating Eletropaulo in February 2002 when control of the business was obtained. Please see Note 2 to the Consolidated Financial Statements for a complete description of the Eletropaulo swap transaction. If Eletropaulo had been consolidated during the comparable period in 2001, revenues compared to the prior period would have been lower due to rationing in Brazil in early 2002. Although rationing ended in February 2002 customer demand has not returned to the level it was prior to rationing. As customer demand builds, Eletropaulo believes it will experience benefits through increased revenues.

Growth distribution revenues decreased 27% or $0.4 billion to $1.2 billion in 2002 compared to $1.6 billion in 2001. Growth distribution revenues decreased $518 million and $76 million in South America and the Caribbean, respectively. This was offset by a $161 million increase in Europe/Africa. South America revenues decreased due to the impact of the devaluation of the Argentine peso at Eden-Edes and Edelap, as well as due to the provision for the Brazilian regulatory decision at Sul. During the second quarter of 2002, ANEEL announced an order to retroactively change the calculation methods of the Wholesale Energy Markets ("MAE"). As a result the company recorded a provision for the Brazilian regulatory decision at Sul of approximately $146 million against revenues. The Caribbean decreased primarily due to lower revenues in El Salvador. Increases in Europe/Africa are due to the acquisitions of Sonel in Cameroon and Kievoblenergo and Rivnooblenergo in the Ukraine as well as improvements at Telasi in Georgia.

Non-regulated revenues. Non-regulated revenues decreased 2% or $75 million to $4.3 billion in 2002 compared to $4.4 billion in 2001 due to reductions in competitive supply revenues offset in part by an increase in contract generation revenues. Non-regulated revenues will continue to be impacted by weather and market prices for electricity in the United Kingdom and the Northeastern U.S. Excluding businesses acquired or that commenced operations in 2002 or 2001, non-regulated revenues decreased 10% to $3.8 billion in 2002.

Contract generation revenues increased 3% or $61 million to $2.5 billion in 2002 compared to $2.4 billion in 2001. Increases in contract generation revenues during 2002 in North America, Europe/Africa and Asia were offset by declines in South America and the Caribbean. North America revenues increased $88 million mainly due to the start of operations at Ironwood in Pennsylvania, Red Oak in New Jersey, increased revenues from Warrior Run in Maryland and the acquisition of Mendota in California and Hemphill in New Hampshire as part of the Thermoecotek acquisition, offset by declines at Southland in California. South America revenues decreased $69 million mainly due to declines at the Gener plants in Chile and Tiete and Uruguaiana in Brazil. Caribbean revenues decreased $24 million due to lower revenues from Los Mina in the Dominican Republic and Merida III in Mexico. Europe/Africa revenues increased $38 million due to the acquisition of Ebute in Nigeria and Bohemia in the Czech Republic, and improved operations at Tisza in Hungary offset by lower revenues from Kilroot in Northern Ireland, which experienced an outage in the second quarter of 2002. Asia revenues increased $28 million most significantly at Haripur in Bangladesh and Jiaozuo in China.

Competitive supply revenues decreased 7% or $136 million to $1.8 billion in 2002 compared to $2.0 billion in 2001 due to decreases in all geographic regions except for Asia. North America revenues declined $70 million primarily due to lower market prices in the Northeastern U.S. combined with a decline in demand in California due to mild weather. The decline in California was partially offset by additional revenue associated with the acquisition of Delano in California. South America revenues

decreased $58 million primarily due to the devaluation of the Argentine peso in February 2002 offset slightly by the start of operations at Parana in Argentina. Caribbean revenues declined slightly due to declines at Colombia I and Panama offset in part by an increase at Chivor in Colombia. Europe/Africa revenues declined $13 million due to a decline in merchant energy prices in the United Kingdom that was driven by mild weather conditions, increased competition and the significant over-capacity that exists in the United Kingdom generation market, and reduced revenues from the closure of Belfast West in Northern Ireland offset slightly by the acquisition of Ottana in Italy. Asia revenues increased $6 million primarily due to increases at our business in Kazakhstan.

Gross margin decreased $258 million, or 12%, to $1.9 billion in 2002 from $2.2 billion in 2001. Gross margin as a percentage of revenues decreased to 22% in 2002 from 28% in 2001. The decrease in gross margin is due to lower market prices in the U.S., the United Kingdom and elsewhere partially offset by the acquisition of new businesses and new operations from greenfield projects. Gross margin as a percentage of revenues declined for each segment except contract generation. Excluding businesses acquired or that commenced commercial operations in 2002 or 2001, gross margin decreased 27% to $1.6 billion in 2002. Gross margin in future periods will be negatively impacted by the expensing of stock options and other long-term incentive compensation.

Regulated gross margin. Regulated gross margin decreased 18% or $149 million to $690 million in 2002 compared to $839 million in 2001. The decrease is primarily due to weakening margins in our South American growth distribution businesses and our Caribbean large utility business offset by increases at our North and South American large utilities and Europe/Africa growth distribution businesses. Regulated gross margin as a percentage of revenues decreased to 16% in 2002 from 26% in 2001. Excluding businesses acquired or that commenced operations in 2002 or 2001, regulated gross margin decreased 42% to $499 million in 2002.

Large utilities gross margin increased 11% or $67 million to $685 million in 2002 compared to $618 million in 2001 primarily due to increases in North and South America offset in part by a decrease in the Caribbean. North America increased $12 million due to increased contributions from IPALCO. South America increased $177 million due to the consolidation of Eletropaulo. The decrease of $122 million in the Caribbean is due to the devaluation of the Venezuelan Bolivar and its impacts on EDC. EDC's tariff is adjusted semi-annually to reflect fluctuations in inflation and the currency exchange rate. However, a failure to receive such an adjustment to reflect changes in the exchange rate and inflation could adversely affect their results of operations in the future. The large utilities gross margin as a percentage of revenues decreased to 22% for 2002 from 38% in 2001. Eletropaulo's 2002 gross margin was negatively impacted by the write off approximately $80 million of other receivables. Excluding this adjustment, the large utilities gross margin as a percentage of revenues would have been 24% in 2002. Our distribution concession contracts in Brazil provide for annual tariff adjustments based upon changes in the local inflation rates and, generally, significant devaluations are followed by increased local currency inflation. However, because of the lack of adjustment to the current exchange rate, the in arrears nature of the respective tariff adjustment, or the potential delays or magnitude of the resulting local currency inflation of the tariff, the future results of operations of Eletropaulo could be adversely affected by the continued devaluation of the Brazilian Real.

Growth distribution gross margin decreased 98% or $216 million to $5 million in 2002 compared to $221 million in 2001. The decline of $310 million in South America gross margin was offset in part by increases of $72 million and $22 million in Europe/Africa and the Caribbean, respectively. South America gross margin declined primarily due to devaluation of the Argentine peso and the reduction in gross margin from Sul due to the $146 million provision for the Brazilian Regulatory decision. Europe/Africa gross margin increased due to operational improvements at Telasi in Georgia and the acquisitions of Kievoblenergo and Rivnooblenergo in the Ukraine. Caribbean gross margin increased due primarily to operational improvements at EDE Este in the Dominican Republic. The growth distribution gross margin as a percentage of revenues decreased to 0% in 2002 from 14% in 2001. However, excluding the $146 million nonrecurring provision for the Brazilian Regulatory decision at Sul, growth distribution gross margin as a percentage of revenues would have been 13% in 2002.

Non-regulated gross margin. Non-regulated gross margin decreased 8% or $109 million to $1.2 billion in 2002 compared to $1.3 billion in 2001. This decrease is primarily due to lower margins at our North American, South American, European and African competitive supply businesses partially offset by increased margins in all regions of our contract generation segment. Non-regulated gross margin as a percentage of revenues decreased to 28% in 2002 from 30% in 2001. Excluding businesses acquired or that commenced operations in 2002 or 2001, non-regulated gross margin decreased 16% to $1.1 billion in 2002.

Contract generation gross margin increased 23% or $196 million to $1.1 billion in 2002 compared to $0.9 billion in 2001 primarily due to improvements at existing businesses and operations from new businesses. The contract generation gross margin as a percentage of revenues increased to 42% in 2002 from 35% in 2001. Gross margin increased in all geographic regions. North America gross margin increased $58 million due to the start of commercial operations at Ironwood in Pennsylvania, Red Oak in New Jersey and improvements at Warrior Run in Maryland and Beaver Valley in Pennsylvania. South America gross margin increased $27 million due to increases at Gener, Tiete and Uruguaiana. Europe/Africa gross margin increased $51 million mainly due to the acquisition of Ebute in Nigeria and improvements at Kilroot in Northern Ireland and Tisza II in Hungary. Asia gross margin increased $55 million mainly due to increased contributions from Jiaozuo and Hefei in China.

Competitive supply gross margin decreased 63% or $305 million to $179 million in 2002 compared to $484 million in 2001. Decreases in North America, South America, Europe and Africa gross margins were offset slightly by increases from the Caribbean and Asia. North America gross margin decreased $44 million mainly due to the lower energy prices in New York and milder weather in California. South America gross margin decreased $22 million mainly due to the devaluation of the peso in Argentina. Europe/Africa gross margin decreased $253 million mainly due to lower energy prices in the United Kingdom Caribbean gross margin increased $10 million mainly due to increases from Panama and Chivor in Colombia. The competitive supply gross margin as a percentage of revenues decreased to 10% in 2002 from 25% in 2001. Gross margin at Drax in 2002 included the write off of approximately $215 million of trade receivables due to the bankruptcy of TXU Europe. Excluding this adjustment, the competitive supply gross margin as a percentage of revenues would have been 21% in 2002.

Selling, general and administrative expenses. SG&A decreased $8 million, or 7%, to $112 million in 2002 from $120 million in 2001. SG&A as a percentage of revenues decreased to 1% in 2002 from 2% in 2001. The overall decrease in SG&A is due to the Company's increased focus on cost cutting. However, the Company has undertaken several corporate initiatives that require additional personnel and infrastructure, and these may result in increased selling, general and administrative expenses in future periods. Additionally, the expensing of stock options and other long-term incentive compensation will increase selling, general and administrative expenses in future periods.

Severance and transaction costs. During 2001, the Company incurred approximately $131 million of transaction and contractual severance costs related to the acquisition of IPALCO.

Interest expense. Interest expense increased $456 million, or 29%, to $2.0 billion in 2002 from $1.6 billion in 2001. Interest expense as a percentage of revenues was 24% in 2002 and 21% in 2001. Overall interest expense increased primarily due to the consolidation of Eletropaulo in February 2002, issuance of senior secured notes at IPALCO, interest expense from new businesses, as well as additional corporate interest costs arising from a higher outstanding balance during 2002 on the Company's revolving loan. During December 2002, the Company refinanced a significant amount of

debt at terms less favorable than the original debt. As a result, the amount of interest expense recorded in future periods is expected to increase.

Interest income. Interest income increased $123 million, or 65%, to $312 million in 2002 from $189 million in 2001. Interest income as a percentage of revenues was 4% in 2002 and 2% in 2001. The increase in interest income during 2002 is due primarily to the consolidation of Eletropaulo partially offset by a decline in interest income from Thames due to the collection of its contract receivable.

Other income. Other income increased $103 million, or 89%, to $219 million in 2002 from $116 million in 2001. Approximately $169 million of the amount recorded in 2002 is attributable to gains on the extinguishment of liabilities and market-to-market gains on commodity derivatives. See Note 16 to the consolidated financial statements for an analysis of other income.

Other expense. Other expense increased $22 million, or 34%, to $87 million in 2002 from $65 million in 2001. Approximately $76 million of the amount recorded in 2002 is attributable to losses on the sale of assets or extinguishment of liabilities and other non-operating expenses. See Note 16 to the consolidated financial statements for an analysis of other expense.

Foreign currency transaction losses. Foreign currency transaction losses increased $426 million to $456 million in 2002 from $30 million in 2001. Foreign currency transaction losses increased primarily due to a 50% devaluation in the Argentine peso from 1.65 at December 31, 2001 to 3.32 at December 31, 2002, which resulted in $143 million of foreign currency transaction losses for the year ended December 31, 2002. Additionally, a 32% devaluation occurred in the Brazilian Real during 2002 from 2.41 at December 31, 2001 to 3.53 at December 31, 2002. Furthermore, the Company recorded more foreign currency losses due to the consolidation of Eletropaulo, and since there was less allocation to the minority partners because their investment has been reduced to zero. As a result, the Company recorded net Brazilian foreign currency losses of $357 million during 2002, of which approximately $83 million is included in equity in pre-tax (losses) earnings of affiliates. These decreases were offset by $39 million of foreign currency transaction gains recorded at EDC during 2002 due to a 46% devaluation of the Venezuelan Bolivar from 758 at December 31, 2001 to 1,403 at December 31, 2002. EDC uses the U.S. dollar as its functional currency but a portion of its debt is denominated in the Venezuelan Bolivar.

Equity in pre-tax (losses) earnings of affiliates. Equity in pre-tax (losses) earnings of affiliates declined by $379 million to a loss of $203 million in 2002 compared to income of $176 million in 2001. The overall decrease is due primarily to declines in equity in earnings of Brazilian large utility affiliates, including the impairment charge associated with the other than temporary decline in value of CEMIG.

Additionally, a share swap was completed during February 2002 which gave the Company control of Eletropaulo. In 2001, the Company recorded $134 million of equity in Eletropaulo's pre-tax earnings; however, this amount decreased to $18 million due to consolidation of Eletropaulo's results subsequent to the share swap and the ongoing devaluation of the Brazilian Real. Equity in pre-tax (losses) earnings of our large utilities included non-cash Brazilian foreign currency transaction losses of $83 million and $210 million during 2002 and 2001, respectively, due to the devaluation of the Brazilian Real during both periods.

Equity in (losses) earnings of growth distribution affiliates improved from a loss of $13 million in 2001 to $0 in 2002. The improvement is primarily due to a change in accounting for our investment in CESCO.

Equity in earnings of contract generation affiliates increased to $75 million in 2002 from $54 million in 2001. The increase is due primarily to contributions from several Chinese equity affiliates and from Elsta offset by a decrease from OPGC.

Equity in earnings of competitive supply affiliates improved from a loss of $9 million in 2001 to a loss of $3 million in 2002. The improvement is primarily due to the sale of Infovias, a Brazilian company, during the second quarter of 2002.

(Loss) gain on sale of assets and asset impairment expense. (Loss) gain on sale of assets and asset impairment expense changed from a gain of $18 million for 2001 to a loss of $1.6 billion in 2002 primarily resulting from impairment charges taken in 2002. Financial distress of certain TXU Europe companies during late 2002 resulted in the issuance of an administration order for TXU EET and TXU Group, and led to the termination of the long-term electricity sales hedging arrangement at Drax and a tolling agreement at Barry. As a result of these terminations, the Company recorded pre-tax asset impairment charges of $955 million at Drax and $172 million at Barry in the fourth quarter of 2002. Drax and Barry are competitive supply businesses located in the United Kingdom. Additionally, the Company recorded pre-tax charges totaling approximately $357 million related to the sale or impairment of development projects and approximately $116 million related to the sale or impairment of investments during 2002.

Drax is the operator of Drax Power Plant, Britain's largest power station. In November 2002, Drax terminated its Hedging Agreement with TXU EET. In November 2002, TXU Group, the guarantor under the power supply hedging agreement between Drax and TXU EET, filed for administration in the United Kingdom. As a result of the termination of the Hedging Agreement, which provided Drax above-market prices for the contracted output (equal to approximately 60 percent of the total output of the plant), Drax became fully exposed to power prices in the United Kingdom. The termination of the Hedging Agreement constituted a change in circumstance as defined by Statement of Financial Accounting Standard (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, that indicated that the carrying value of Drax's net assets may not be recoverable. Accordingly, in the fourth quarter of 2002, a pre-tax impairment charge of $955 million was taken to write-down the net assets to their fair value.

Barry had a tolling agreement with TXU EET which contracted all of the output of the Barry plant. The TXU EET administration order discussed above constituted a change in circumstance, as defined by SFAS No. 144, which indicated that the carrying amount of the Barry net assets may not be recoverable. Accordingly, in the fourth quarter of 2002, an impairment charge of $172 million was recorded to write-down the net assets to their fair value.

In the fourth quarter of 2002, the Company decided not to provide any further funding to Lake Worth and to sell the project. As a result, the carrying amount of AES's investment in the Lake Worth project is not expected to be recovered. Accordingly, in accordance with SFAS No. 144, an impairment charge of $78 million was recorded to write-down the net assets of Lake Worth to their fair market value.

In September 2002, AES Greystone, LLC and its subsidiary Haywood Power I, LLC, sold the Greystone gas-fired peaker assets then under construction in Tennessee to Tenaska Power Equipment for $36 million including cash and assumption of certain obligations. With this sale, AES and its subsidiaries have eliminated any future capital expenditures related to the facility, and also settled all major outstanding obligations with parties involved in this project. AES recorded a loss of approximately $168 million associated with this sale. Greystone was previously recorded as a competitive supply business.

Additionally, during 2002, the Company recorded $86 million of other losses which resulted from the sale of assets to third parties, and $141 million of other asset impairment charges taken to reflect the net realizable value of discontinued development projects and other non-recoverable assets.

Goodwill impairment expense. During 2002, the Company recorded a goodwill impairment charge of $612 million primarily related to all of the goodwill at Eletropaulo in Brazil. The Company recognizes as goodwill the excess of the cost of an acquired entity over the net amount assigned to assets acquired and liabilities assumed. The Company evaluates goodwill for impairment on an annual basis and

whenever events or changes in circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company's annual impairment testing date is October 1^st. Prior to January 1, 2002, goodwill was amortized on a straight-line basis over the estimated benefit period, which ranged from 10 to 40 years, and total accumulated amortization amounted to $190 million at December 31, 2001. As of January 1, 2002, goodwill is no longer amortized.

Income taxes. Income taxes (including income taxes on equity in earnings) on continuing operations changed to a benefit of $27 million in 2002 from expense of $206 million in 2001. The Company's tax position changed from tax expense at a 32% effective tax rate in 2001 to a tax benefit at a 1% effective tax rate in 2002. The 2002 effective tax rate resulted from a small tax benefit on the pre-tax book loss, which was primarily due to the book write off of non-deductible foreign goodwill, and the recording of valuation allowances against deferred tax assets from translation losses and various capital losses.

Minority interest (income) expense. Pre-tax minority interest changed $137 million, or 133%, to a benefit of $34 million in 2002 from an expense of $103 million in 2001. Increases in minority interest income in large utilities and competitive supply were somewhat offset by greater minority interest expense in growth distribution and contract generation.

Large utilities minority interest changed by $124 million to a benefit of $36 million for 2002 from expense of $88 million for 2001. Increases in minority interest income from EDC and CEMIG were slightly offset by increased expense from Eletropaulo. The change is mainly due to the sharing of losses that resulted from currency devaluations and impairment charges with the minority shareholders. The change in large utilities minority interest would have been somewhat greater; however, the minority interest in Eletropaulo was reduced to zero during the third quarter of 2002 and the Company began picking up all of the losses.

Growth distribution minority interest changed to an expense of $6 million for 2002 compared to a benefit of $16 million for 2001. The change in growth distribution minority interest is due to additional expense from Sonel, Kievoblenergo, and Ede Este partially offset by lower expense at Eden Edes, Edelap, and CAESS.

Contract generation minority interest expense increased $26 million to $48 million for 2002 compared to expense of $22 million for 2001. The change is due to the sharing of earnings by the minority partners of Tiete in Brazil and at several of our Chinese businesses.

Competitive supply minority interest changed by $60 million to a benefit of $51 million in 2002 compared to expense of $9 million in 2001. The change in competitive supply minority interest is primarily due to sharing of losses that resulted from the devaluation of the Argentine peso with the minority shareholders.

(Loss) income from continuing operations. (Loss) income from continuing operations decreased $3.0 billion to a loss of $2.6 billion for 2002 from income of $446 million for 2001. The loss recorded in 2002 resulted primarily from asset and goodwill impairments as well as foreign currency transaction losses.

Discontinued operations. Loss from operations of discontinued businesses, net of tax, were $573 million and $173 million, respectively, in 2002 and 2001. During 2002, the Company discontinued certain of its operations including Fifoots, CILCORP, NewEnergy, Eletronet, Mt. Stuart, Ecogen, two Altai businesses, Mountainview and Kelvin. The Company closed the sale of CILCORP in January 2003. Pursuant to SFAS No. 144, if any of these businesses are not sold or disposed of within one year of the date they were classified as discontinued operations they must be reclassified as continuing operations.

Accounting change. On April 1, 2002, the Company adopted Derivative Implementation Group ("DIG") Issue C-15 which established specific guidelines for certain contracts to be considered normal

purchases and normal sales contracts under SFAS No. 133. As a result of this adoption, the Company had two contracts which no longer qualified as normal purchases and normal sales contracts and were required to be treated as derivative instruments under SFAS No. 133. The adoption of DIG Issue C-15, effective April 1, 2002, resulted in a cumulative increase to income of $127 million, net of income tax effects.

Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets" which establishes accounting and reporting standards for goodwill and other intangible assets. The adoption of SFAS No. 142 resulted in a cumulative reduction to income of $473 million, net of income tax effects. SFAS No. 142 adopts a fair value model for evaluating impairment of goodwill in place of the recoverability model used previously. The Company wrote-off the goodwill associated with certain acquisitions where the current fair market value of such businesses is less than the current carrying value of the business, primarily as a result of reductions in fair value associated with lower than expected growth in electricity consumption compared to the original estimates made at the date of acquisition. The Company's annual impairment testing date is October 1^st.

Net (loss) income. Net (loss) income decreased $3.8 billion to a loss of $3.5 billion in 2002 from net income of $273 million in 2001. This effect was due to lower gross margin from the growth distribution and competitive supply segments, increased interest expense, increased foreign currency losses due to devaluation in Brazil and Argentina, impairment charges taken on goodwill and other assets, and losses from discontinued operations offset by greater interest income, higher gross margin from the large utilities and contract generation segments, and greater sharing of losses with minority partners.

Revenues increased $1.4 billion, or 23% to $7.6 billion in 2001 from $6.2 billion in 2000. The increase in revenues is due to the acquisition of new businesses, new operations from greenfield projects and positive improvements from existing operations. Excluding businesses acquired or that commenced commercial operations in 2001 or 2000, revenues increased 1% to $5.5 billion in 2001. AES is a global power company which operates in 31 countries around the world. The breakdown of AES's revenues for the years ended December 31, 2001 and 2000, based on the business segment and geographic region in which they were earned, is set forth below.

Regulated revenues. Regulated revenues increased $594 million, or 22%, to $3.3 billion in 2001 from $2.7 billion in 2000. Regulated revenues increased in both the large utilities and growth distribution segments due to the contributions of acquired businesses as well as improved operations. Weather generally impacts the demand for electricity, and therefore, extreme temperatures will impact the amount of revenues recorded. Excluding businesses acquired or that commenced operations in 2001 or 2000, regulated revenues increased 8% to $2.1 billion during 2001.

Large utilities revenues increased $257 million, or 19%, to $1.6 billion in 2001 from $1.4 billion in 2000 principally resulting from the addition of revenues attributable to businesses acquired during 2001 or 2000. The majority of the increase occurred within the Caribbean, offset by a decrease of $56 million in North America. In the Caribbean, revenues increased $313 million due to a full year of revenues from EDC, which was acquired in June 2000.

Growth distribution revenues increased $337 million, or 26%, to $1.6 billion in 2001 from $1.3 billion in 2000. Revenues increased most significantly in the Caribbean and to a lesser extent in South America and Europe/Africa. Revenues decreased in Asia. In the Caribbean, growth distribution segment revenues increased $297 million due primarily to a full year of operations at CAESS, which was acquired in 2000, and improved operations at EDE Este. In South America, growth distribution segment revenues increased $14 million due to the significant revenues at Sul from our settlement with the Brazilian government offset by declines in revenues at our Argentine distribution businesses. The settlement with the Brazilian government confirmed the sales price that Sul would receive from its sales into the southeast market (where rationing occurred) under its Itaipu contract. The Brazilian government reversed this decision retroactively in 2002. In Europe/Africa, growth distribution segment revenues increased $197 million primarily from the acquisition of SONEL. In Asia, growth distribution segment revenues decreased $171 million mainly due to the change in the way in which we are accounting for our investment in CESCO. CESCO was previously consolidated but was changed to equity method during 2001 when the Company was removed from management and the Board of Directors. This decline was partially offset by the increase in revenues from the distribution businesses that we acquired in Ukraine.

Non-regulated revenues. Non-regulated revenues increased $845 million, or 24%, to $4.4 billion in 2001 from $3.5 billion in 2000. Non-regulated revenues increased in both the contract generation and competitive supply segments due to the acquisition of new businesses as well as improved operations at existing businesses. Excluding businesses acquired or that commenced operations in 2001 or 2000, non-regulated revenues decreased 4% to $3.3 billion during 2001

Contract generation revenues increased $709 million, or 42% to $2.4 billion in 2001 from $1.7 billion in 2000, principally resulting from the addition of revenues attributable to businesses acquired during 2001 or 2000. Contract generation revenues increased in all geographic regions, but most significantly in South America. South America revenues grew $521 million due mainly to the acquisition of Gener and the full year of operations at Uruguaiana offset by reduced revenues at Tiete from the electricity rationing in Brazil. In Europe/Africa, contract generation segment revenues increased $118 million, and the acquisition of a controlling interest in Kilroot during 2000 was the largest contributor to the increase. North America and Asia contract generation revenues increased $46 million and $13 million, respectively. Caribbean contract generation revenues increased $11 million due to a full year of operations at Merida III offset by a lower capacity factor at Los Mina.

Competitive supply revenues increased $136 million or 7% to $2.0 billion in 2001 from $1.8 billion in 2000. The most significant increases occurred within the Caribbean where revenues increased $122 million due primarily to the acquisition of Chivor. Slight increases were recorded within North America, South America and Asia. Europe/Africa reported a $52 million decrease due to lower pool prices in the United Kingdom offset by the acquisition of Ottana. In North America, competitive supply segment revenues increased $7 million due primarily to increased operations at Placerita offset by lower market prices at our New York businesses.

Gross margin increased $274 million, or 14%, to $2.2 billion in 2001 from $1.9 billion in 2000. Gross margin as a percentage of revenues decreased to 28% in 2001 from 31% in 2000. The increase in gross margin is due to the acquisition of new businesses and new operations from greenfield projects offset by lower market prices in the United Kingdom. The decrease in gross margin as a percentage of revenues is due to a decline in the contract generation and competitive supply gross margin percentages offset slightly by increased gross margin percentages from large utilities and growth distribution. Excluding businesses acquired or that commenced commercial operations in 2001 or 2000, gross margin decreased 4% to $1.6 billion in 2001.

Regulated gross margin. Regulated gross margin increased $271 million, or 48%, to $839 million in 2001 from $568 million in 2000. Regulated gross margin increased in both the large utilities and growth distribution segments.

Regulated gross margin as a percentage of revenues increased to 26% during 2001 from 21% for 2000. Excluding businesses acquired or that commenced operations in 2001 or 2000, regulated gross margin increased 36% to $545 million during 2001.

Large utilities gross margin increased $181 million, or 41%, to $618 million in 2001 from $437 million in 2000. Large utilities gross margin as a percentage of revenues increased to 38% in 2001 from 32% in 2000. In the Caribbean, large utility gross margin increased $165 million and was due to a full year of contribution from EDC which was acquired in June 2000. Additionally, increased margins at IPALCO contributed to a $28 million improvement in North American gross margin.

Growth distribution gross margin increased $90 million, or 69%, to $221 million in 2001 from $131 million in 2000. Growth distribution gross margin as a percentage of revenue increased to 14% in 2001 from 10% in 2000. Growth distribution gross margin, as well as gross margin as a percentage of sales, increased in South America, the Caribbean, and Asia but decreased in Europe/Africa. In South America, growth distribution margin increased $80 million and was 32% of revenues. The increase is due primarily to Sul's sales of excess energy at prices determined under an initial decision made by ANEEL into the southeast market where rationing was taking place; however, the Brazilian government reversed this decision retroactively in 2002. In the Caribbean, growth distribution margin increased $39 million and was 5% of revenues mainly due to lower losses at Ede Este and an increase in contribution from CAESS. In Europe/Africa, growth distribution margin decreased $56 million and was negative due to losses at SONEL. In Asia, growth distribution margin improved $27 million but remained negative. The improvement was primarily due to the change in accounting for CESCO.

CESCO was previously consolidated but was changed to equity method accounting in the third quarter of 2001 when the Company was removed from management and lost operational control.

Non-regulated gross margin. Non-regulated gross margin remained relatively consistent at $1.3 billion in both 2001 and 2000. Non-regulated gross margin as a percentage of revenues decreased to 30% during 2001 from 38% in 2000 due to a decline in market prices in the United Kingdom and the U.S. which resulted in a decrease in competitive supply gross margin that was offset by an increase in contract generation gross margin. Excluding businesses acquired or that commenced operations in 2001 or 2000, non-regulated gross margin decreased 17% to $1.1 billion in 2001.

Contract generation gross margin increased $107 million, or 14%, to $854 million in 2001 from $747 million in 2000. Contract generation gross margin increased in all geographic regions except Asia. The contract generation gross margin as a percentage of revenues decreased to 35% in 2001 from 44% in 2000. In South America, contract generation gross margin increased $64 million and was 31% of revenues. The increase is due to the acquisition of Gener offset by a decline at Tiete from the rationing of electricity in Brazil. In North America, contract generation gross margin increased $8 million and was 50% of revenues. The increase is due to improvements at Shady Point and Beaver Valley partially offset by a decrease at Thames from the contract buydown. In Europe/Africa, contract generation gross margin increased $50 million and was 29% of revenues. The increase is due primarily to our additional ownership interest in Kilroot and the acquisition of Ebute in Nigeria. In Asia, contract generation gross margin decreased $26 million and was 33% of revenues. The decrease is due mainly to additional bad debt provisions at Jiaozuo, Hefei and Aixi in China that were partially offset by the start of commercial operations at Haripur. The decrease in contract generation gross margin as a percentage of revenue is due to the acquisition of generation businesses with overall gross margin percentages lower than the overall portfolio of generation businesses. As a percentage of sales, contract generation gross margin declined in North America, South America and Asia, and increased in Europe/Africa and the Caribbean.

The competitive supply gross margin decreased $104 million, or 18%, to $484 million in 2001 from $588 million in 2000. The overall decrease is due to declines in North America, Europe/Africa and South America that were partially offset by slight increases in the Caribbean and Asia. The competitive supply gross margin as a percentage of revenues decreased to 25% in 2001 from 32% in 2000. In South America, competitive supply segment gross margin decreased $26 million and was 24% of revenues due to declines at several of our businesses in Argentina. In Europe/Africa, competitive supply segment gross margin decreased $87 million and was 23% of revenues. The decrease is due primarily to declines at Drax and Barry from the lower market prices in the United Kingdom In North America, competitive supply segment gross margin decreased $8 million and was 27% of revenues. The decrease was due to decreases at Somerset in New York and Deepwater in Texas. In the Caribbean, the competitive supply gross margin increased $15 million and was 29% of revenues. The increase is due primarily to the acquisition of Chivor offset by lower margin at Panama. As a percentage of sales, competitive supply gross margin declined in all regions except Asia where it remained relatively flat.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $38 million, or 46%, to $120 million in 2001 from $82 million in 2000. Selling, general and administrative expenses as a percentage of revenues increased to 2% in 2001 from 1% in 2000. The overall increase in selling, general and administrative expenses was due to increased development activities.

Severance and transaction costs. During the first quarter of 2001, the Company incurred approximately $94 million of transaction and contractual severance costs related to the acquisition of IPALCO. During the third quarter of 2001, the Company recorded an additional $37 million in contractual severance costs related to the IPALCO transaction.

Interest expense. Interest expense increased $313 million, or 25%, to $1,575 million in 2001 from $1,262 million in 2000. Interest expense as a percentage of revenues increased to 21% in 2001 from 20% in 2000. Interest expense increased overall primarily due to interest expense at new businesses, additional corporate interest expense arising from senior debt issued during 2001 to finance new investments and mark-to-market losses on interest rate related derivative instruments. In December 2002, the Company refinanced $2.1 billion of bank debt and debt securities at terms less favorable than the original debt. As a result, the amount of interest expense recorded in future periods is expected to increase.

Interest income. Interest income decreased $12 million, or 6%, to $189 million in 2001 from $201 million in 2000. Much of the decrease occurred at Thames due to receiving payment of the contract receivable from Connecticut Light and Power, plus generally lower interest rates in 2001.

Other income. Other income increased $65 million, or 127%, to $116 million in 2001 from $51 million in 2000. See Note 16 to the consolidated financial statements for an analysis of other income.

Other expense. Other expense increased $13 million, or 25%, to $65 million in 2001 from $52 million in 2000. See Note 16 to the consolidated financial statements for an analysis of other expense.

Foreign currency transaction losses. Foreign currency transaction losses increased $26 million, or 650%, to $30 million in 2001 from $4 million in 2000. Foreign currency transaction losses increased primarily due to devaluations in Argentina and to a much lesser extent in the United Kingdom, offset by income received on foreign currency forward contracts.

Equity in pre-tax (losses) earnings of affiliates. Equity in pre-tax earnings of affiliates decreased $299 million, or 63%, to $176 million in 2001 from $475 million in 2000. The overall decrease in equity in earnings is due primarily to declines in equity in earnings of Brazilian large utility affiliates which

primarily resulted from the devaluation of the Brazilian Real, as well as the rationing of electricity in Brazil.

Equity in earnings of large utilities decreased $282 million to $144 million in 2001 from $426 million in 2000 and included non-cash Brazilian foreign currency transaction losses on a pretax basis of $210 million and $64 million in 2001 and 2000, respectively. Our distribution concession contracts in Brazil provide for annual tariff adjustments based upon changes in the local inflation rates and generally significant devaluations are followed by increased local currency inflation. However, because of the lack of adjustment to the current exchange rate, the in arrears nature of the respective adjustment to the tariff or the potential delays or magnitude of the resulting local currency inflation of the tariff, the future results of operations of the company's distribution companies in Brazil could be adversely affected by the continued devaluation of the Brazilian Real.

Equity in earnings of growth distribution affiliates decreased to an expense of $13 million in 2001 from $0 million in 2000. The decrease is primarily due to the change in the way in which we account for our investment in CESCO. CESCO was previously consolidated but was changed to equity method during 2001 when the Company was removed from management and the Board of Directors.

Equity in earnings of contract generation affiliates increased to $54 million in 2001 from $49 million in 2000. The increase is due primarily to contributions from equity affiliates of Gener and the contribution from Itabo offset by a decrease in Kilroot related to the Company's purchase of an additional interest thereby making it a consolidated subsidiary.

Equity in earnings of competitive supply affiliates decreased to expense of $9 million in 2001 from $0 million in 2000. The decrease is due to losses incurred at Infovias, a Brazilian company.

Income taxes. Income taxes (including income taxes on equity in earnings and minority interests) decreased $162 million to $206 million in 2001 from $368 million in 2000. The Company's effective tax rate was 32% in 2001 and 31% in 2000.

Minority interest (income) expense. Minority interest expense (before income taxes) decreased $17 million, or 14%, to $103 million in 2001 from $120 million in 2000. Minority interest expense decreased in contract generation and competitive supply. Minority interest income decreased in growth distribution, and large utilities minority interest expense increased.

Large utilities minority interest expense increased $3 million to $88 million in 2001 from $85 million in 2000. Increased expense at EDC was almost entirely offset by declines at CEMIG.

Growth distribution minority interest income decreased $15 million to $16 million in 2001 from $31 million in 2000. The decrease was mainly due to the deconsolidation of CESCO, and sharing the effect of a full year's results of CAESS with our minority partners.

Contract generation minority interest expense decreased $14 million to $22 million in 2001 from $36 million in 2000. The decrease in contract generation minority interest expense was due primarily to lower contributions from Tiete and Jiaozuo.

Competitive supply minority interest expense decreased $21 million to $9 million in 2001 from $30 million in 2000. The decrease in competitive supply minority interest expense is due primarily to lower contributions from Panama and CTSN.

Discontinued operations. During 2001, the Company discontinued certain of its operations, including Power Direct, Ib Valley, Power Northern, Geoutilities, TermoCandelaria and several telecommunications businesses in the United States and Brazil. During 2002, the Company discontinued certain of its operations, including Fifoots, CILCORP, NewEnergy, Eletronet, Mt. Stuart, Ecogen, two Altai businesses, Mountainview and Kelvin. All of the operations for these businesses and the related write offs from dispositions in 2001 are reported in this line item. Results of discontinued operations in 2001 were a loss of approximately $173 million and the write off from dispositions was a loss of approximately $145 million, net of tax. All amounts in 2000 represent results from operations.

Net income. Net income decreased $522 million to $273 million in 2001 from $795 million in 2000. The overall decrease in net income is due to decreased gross margin from competitive supply due to lower market prices in the United Kingdom and the decline in the Brazilian Real during 2001 resulting in foreign currency transaction losses of approximately $210 million. Additionally the Company recorded severance and transaction costs related to the IPALCO pooling-of-interest transaction and a loss from discontinued operations of $173 million. This decrease was partially offset by increased gross margins from large utilities, growth distribution and contract generation.

AES is a holding company that conducts all of its operations through subsidiaries. AES has, to the extent practicable, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire its electric power plants, distribution companies and related assets. Non-recourse borrowings are substantially non-recourse to other subsidiaries and affiliates and to AES as the parent company, and are generally secured by the capital stock, physical assets, contracts and cash flow of the related subsidiary or affiliate. At December 31, 2002, AES had $5.8 billion of recourse debt and $14.2 billion of non-recourse debt outstanding. For more information on AES's long term debt see Note 9 of the consolidated financial statements.

The Company intends to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that the Company or its affiliates may develop, construct or acquire. However, depending on market conditions and the unique characteristics of individual businesses, non-recourse debt financing may not be available or available on economically attractive terms. If the Company decides not to provide any additional funding or credit support, the inability of any of our subsidiaries that are under construction or that have near-term debt payment obligations to obtain non-recourse project financing may result in such subsidiary's insolvency and the loss of the Company's investment in such subsidiary. Additionally, the loss of a significant customer at any of our subsidiaries may result in the need to restructure the non-recourse project financing at that subsidiary, and the inability to successfully complete a restructuring of the non-recourse project financing may result in a loss of the Company's investment in such subsidiary.

In addition to the non-recourse debt, if available, AES as the parent company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition. These investments have generally taken the form of equity investments or loans, which are subordinated to the project's non-recourse loans. The funds for these investments have been provided by cash flows from operations and by the proceeds from issuances of debt, common stock and other securities issued by the Company. Similarly, in certain of its businesses, the Company may provide financial guarantees or other credit support for the benefit of counter parties who have entered into contracts for the purchase or sale of electricity with the Company's subsidiaries. In such circumstances, were a subsidiary to default on a payment or supply obligation, the Company would be responsible for its subsidiary's obligations up to the amount provided for in the relevant guarantee or other credit support.

As a result of recent declines in the trading prices of AES's equity and debt securities, counter parties may no longer be as willing to accept general unsecured commitments by AES to provide credit support. Accordingly, with respect to both new and existing commitments, AES may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace any AES credit support. AES may not be able to provide adequate assurances to such counter parties. In addition, to the extent AES is required and able to provide letters of credit or other collateral to such counter parties, it will limit the amount of credit available to AES to meet its other liquidity needs.

At December 31, 2002, AES had provided outstanding financial and performance related guarantees or other credit support commitments to or for the benefit of its subsidiaries, which were limited by the terms of the agreements, to an aggregate of approximately $657 million (excluding those collateralized by letters-of-credit and other obligations discussed below). The Company is also obligated under other commitments, which are limited to amounts, or percentages of amounts, received by AES as distributions from its project subsidiaries. These amounts aggregated $25 million as of December 31, 2002. In addition, the Company has commitments to fund its equity in projects currently under development or in construction. At December 31, 2002, such commitments to invest amounted to approximately $65 million (excluding those collateralized by letter-of-credit obligations).

At December 31, 2002, the Company had $213 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations. Of these letters of credit, $104 million were provided under the Company's revolver. The Company pays letter-of-credit fees ranging from 1.35% to 7.00% per annum on the outstanding amounts. In addition, the Company had $6 million in surety bonds outstanding at December 31, 2002.

While the lenders under AES's non-recourse project financings generally do not have direct recourse to the parent, defaults thereunder can still have important consequences for AES's results of operations and liquidity, including, without limitation:

At December 31, 2002, Eletropaulo in Brazil and Edelap, Eden/Edes, Parana and TermoAndes, all in Argentina were each in default under certain of their outstanding project indebtedness. The total debt classified as current in the accompanying consolidated balance sheets related to such defaults was $1.4 billion at December 31, 2002.

In May 1999, a subsidiary of the Company acquired six electric generating stations from New York State Electric and Gas. Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. This transaction has been accounted for as a sale/leaseback transaction with operating lease treatment. Accordingly, these assets are not recorded on the books of the Company, and periodic lease payments, which amounted to $54 million in 2002, are expensed as incurred. Combined revenues and operating income of the two plants were $281 million and $65 million, respectively, in 2002. The lease obligations bear an imputed interest rate of approximately 9% which approximates fair market value. The Company is not subject to any additional liabilities or contingencies if the arrangement were to terminate, and the Company believes there would be minimal effects on operating cash flows if the off balance sheet arrangement was dissolved. The terms of the lease include restrictive covenants such as

the maintenance of certain coverage ratios. As of December 31, 2002, the Company fulfilled a lease requirement on the subsidiary's behalf by funding an additional liquidity account, as defined in the lease agreement, in the form of a $36 million letter of credit. However, the subsidiary is required to replenish or replace this letter of credit in the event it is drawn upon or requires replacement. Historically, the plants have satisfied the restrictive covenants of the lease, and there are no known trends or uncertainties that would indicate early termination of the lease. See Note 11 to the consolidated financial statements for a more complete discussion of this transaction.

IPL, a subsidiary of the Company, formed IPL Funding Corporation ("IPL Funding") in 1996 to purchase, on a revolving basis, up to $50 million of the retail accounts receivable and related collections of IPL in exchange for a note payable. IPL Funding is not consolidated by IPL or IPALCO since it meets requirements set forth in SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" to be considered a qualified special-purpose entity. IPL Funding has entered into a purchase facility with unrelated parties ("the Purchasers") pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, up to $50 million of the receivables purchased from IPL. As of December 31, 2002, the aggregate amount of receivables purchased pursuant to this facility was $50.0 million. The net cash flows between IPL and IPL Funding are limited to cash payments made by IPL to IPL Funding for interest charges and processing fees. These payments totaled approximately $1.1 million, $2.3 million and $3.5 million for the years ended December 31, 2002, 2001 and 2000, respectively. IPL retains servicing responsibilities through its role as a collection agent for the amounts due on the purchased receivables, but may be replaced as servicing agent if IPL fails to meet certain financial covenants regarding interest coverage and debt-to-capital. The transfers of such retail accounts receivable from IPL to IPL Funding are recorded as sales; however, no gain or loss is recorded on the sale. See Note 11 to the consolidated financial statements for additional discussion about this arrangement.

The Company has investments in several equity method affiliates including CEMIG, and does not consolidate the financial information of equity method affiliates. Therefore, none of the assets or liabilities of our equity method affiliates are included on our consolidated balance sheets. See Note 7 to the consolidated financial statements for summarized financial information from our equity method affiliates.

As of December 31, 2002, the Company's known contractual obligations are as follows.

	Payment due by period (amounts in millions)
Contractual obligations	Total		Less than 1 year		1 to 3 years	3 to 5 years		Over 5 years
Indebtedness (excluding interest)	$	20,047		$	3,341	$	4,742		$	2,968	$	8,996
Trust preferred securities (excluding dividends)	$	978			—		—			—	$	978
Construction commitments	$	65		$	65		—			—		—
Operating lease obligations	$	1,726		$	88	$	157		$	145	$	1,336
Purchase obligations	$	14,991		$	1,654	$	2,512		$	1,433	$	9,392

Total	$	37,807		$	5,148	$	7,411		$	4,546	$	20,702

Please refer to Note 11 to the consolidated financial statements for additional disclosure regarding these obligations.

Because of the non-recourse nature of most of AES's indebtedness, AES believes that unconsolidated parent company liquidity is an important measure of liquidity.

The parent company's cash requirements through the end of 2003 are primarily to fund:

In addition, certain of the Company's regulatory subsidiaries are subject to rules and regulations that could possibly result in a restriction on their ability to pay dividends. For example, on February 12, 2003, the Indiana Utility Regulatory Commission (IURC) issued an Order in connection with a petition filed by IPL for approval of its financing program, including the issuance of additional long-term debt. The Order approved the requested financing but set forth a process whereby IPL must file a report with the IURC, prior to declaring or paying a dividend, that sets forth (1) the amount of any proposed dividend, (2) the amount of dividends distributed during the prior twelve months, (3) an income statement for the same twelve-month period, (4) the most recent balance sheet, and (5) IPL's capitalization as of the close of the preceding month, as well as a pro forma capitalization giving effect to the proposed dividend, with sufficient detail to indicate the amount of unappropriated retained earnings. If within twenty (20) calendar days the IURC does not initiate a proceeding to further explore the implications of the proposed dividend, the proposed dividend will be deemed approved. The Order stated that such process should continue in effect during the term of the financing authority, which expires December 31, 2006. On February 28, 2003, IPL filed a petition for reconsideration, or in the alternative, for rehearing with the IURC. This petition seeks clarification of certain provisions of the Order. In addition, the petition requests that the IURC establish objective criteria in connection with the reporting process related to IPL's long term debt capitalization ratio. Whether or not such petition is successful, the Company has no reason to believe the IURC will prevent IPL from paying future dividends in the ordinary course of prudent business operations.

In December 2002, the Company completed a $2.1 billion refinancing of its bank and short-term debt securities by entering into $1.6 billion in senior secured credit facilities and exchanging a portion of $500 million of outstanding debt securities. The refinancing substantially eliminates all scheduled parent company 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 additional letter of credit.

While the Company believes that its sources of liquidity will be adequate to meet its needs through the end of 2003, this belief is based on a number of material assumptions, including, without limitation, assumptions about exchange rates, power market pool prices, the ability of its subsidiaries to pay dividends and the timing and amount of asset sale proceeds. In addition, there can be no assurance

that these sources will be available when needed or that its actual cash requirements will not be greater than anticipated.

The parent company's non-contingent contractual obligations are set forth below:

	Payment due by period (amounts in millions)
Non-contingent contractual obligation	Less than 1 year		1 to 3 years		Over 3 years	Total
Indebtedness (excluding interest)	$	26		$	1,810	$	3,968	$	5,804
Trust preferred securities (excluding dividends)		—			—	$	978	$	978
Construction commitments	$	65			—		—	$	65

Total	$	91		$	1,810	$	4,946	$	6,847

The parent company's contingent contractual obligations are set forth below (in millions, except for number of agreements):

Contingent contractual obligations	Amount
Guarantees	$	652	52	<$1 – $100	$	273
Letters of credit—under the Revolver	$	104	14	<$1 – $36	$	51
Letters of credit—outside the Revolver	$	109	5	<$1 – $84	$	84
Surety bonds	$	6	6	<$1 – $3		—

Total	$	871	77		$	408

The Company has a varied portfolio of performance related contingent contractual obligations. Amounts related to the balance sheet items represent credit enhancements made by AES the parent company and other third parties for the benefit of the lenders associated with the non-recourse debt recorded as liabilities in the accompanying consolidated balance sheets. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, supplier support and liquidated damages under power purchase agreements for projects in development, under construction and operating. While AES does not expect to be required to fund any material amounts under these contingent contractual obligations during 2003 or beyond that are not recorded on the balance sheet, many of the events which would give rise to such an obligation are beyond AES's control. There can be no assurance that it would have adequate sources of liquidity to fund its obligations under these contingent contractual obligations if it were required to make substantial payments thereunder.

Interim needs for shorter-term and working capital financing at the parent company have been met with borrowings under the $350 million senior secured revolving credit facility (the "Revolver") which comprises part of the new $1.6 billion senior secured credit facilities. The senior secured credit facilities contain certain restrictive covenants. The covenants provide for, among other items:

At December 31, 2002, cash borrowings and letters of credit outstanding under the Revolver amounted to $228 million and $104 million, respectively. Letters of credit outstanding outside the Revolver amounted to $109 million.

The Company has a secured equity-linked loan ("SELL") of $225 million due in 2005 that is secured by a pledge of 218 million shares of the Company's common stock at December 31, 2002. As of December 31, 2001, 111 million shares of the Company's common stock had been issued to consolidated subsidiaries with respect to this SELL and another SELL, which was refinanced in December 2002. These shares are not considered outstanding and therefore have been excluded from the calculation of earnings per share.

The Company's senior secured notes due 2005 are subject to mandatory redemption provisions including provisions which require the Company, on November 25, 2004, to redeem 40% of the aggregate principal amount of the senior secured notes issued on December 13, 2003 and not previously redeemed (at the Company's option or pursuant to the other mandatory redemption provisions), at a price equal to 100% of the principal amount of the senior secured notes to be redeemed plus accrued and unpaid interest. As of December 31, 2002 approximately $258 million aggregate principal amount of senior secured notes were outstanding.

The Company's senior secured notes also contain covenants which limit the Company's ability to incur secured indebtedness and provide guarantees.

At December 31, 2002, AES had a consolidated net working capital deficit of $2.2 billion as compared to negative working capital of ($236) million at the end of 2001. The decrease in net working capital was due primarily to an increase in the current portion of debt, accounts payable, and accrued and other liabilities, partially offset by an increase in other current assets. Cash and short-term investments were $1.0 billion at December 31, 2002. Included in the net working capital deficit is approximately $3.3 billion from the current portion of long- term debt. The Company expects to refinance a significant amount of the current portion of long-term debt. There can be no guarantee that these refinancings will have terms as favorable as those currently in existence. There are some subsidiaries that issue short-term debt and commercial paper in the normal course of business and continually refinance these obligations.

Property, plant and equipment, net of accumulated depreciation, accounts for 56% of the Company's total assets and was $18.8 billion at December 31, 2002. Net property, plant and equipment increased $734 million, or 4%, during 2002. The increase was due primarily to construction activities at the Company's greenfield projects and the consolidation of Eletropaulo, offset by the reclassification of certain businesses to discontinued operations.

AES continuously monitors both actual and potential changes to environmental regulations and plans for the associated costs. As a result of such events, the Company expects to spend approximately $105 million in 2003 to comply with environmental laws and regulations and to raise our level of preparedness for future regulations that may be enacted. The Company expects to obtain third party financing for a portion of these capital expenditures. The planned 2003 capital expenditures include anticipated construction costs associated with new environmental standards imposed by the EPA relating to NOx emission reductions, as well as the installation of low NOx burners, additional monitoring equipment, and other environmental-related projects.

In total, the Company's consolidated debt increased $1.2 billion, or 6%, to $20.0 billion at December 31, 2002. The increase is due primarily to the addition of debt held on the books of Eletropaulo which was consolidated during 2002, and borrowings used to fund the construction of the

Company's greenfield projects. This increase was partially offset by the reclassification of certain businesses to discontinued operations.

At December 31, 2002, the Company had $780 million of cash and cash equivalents representing a decrease of $22 million from December 31, 2001. The $1.4 billion provided by operating activities and the $172 million of cash raised by financing activities was used to fund the $1.6 billion of investing activities.

Cash flows provided by operating activities totaled $1.4 billion during 2002. The decrease in cash provided by operating activities during 2002 is due to the one-time collection of a contract prepayment in 2001, partially offset by improved cash flows from operations at several North American businesses. Net cash used in investing activities totaled $1.6 billion during 2002. The cash used in investing activities includes $2.1 billion for property additions, primarily representing new greenfield construction efforts. Net cash provided by financing activities was $172 million during 2002, which primarily consists of net borrowings.

The net cash provided by operating activities of the parent was $1.0 billion for 2002 as shown on Schedule I on page S-4. Cash received by the parent from operating subsidiaries and affiliates includes:

This amount does not include $0.1 billion of cash sent by operating subsidiaries and affiliates to qualifying holding companies during 2002.

The cash held at qualifying holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries had no contractual restrictions on their ability to send cash to AES, the parent company. Cash at those subsidiaries was used for investment and related activities outside of the U.S. These investments included equity investments and loans to other foreign subsidiaries as well as development and general costs and expenses incurred outside the U.S.

Approximately 70% of cash sent by operating subsidiaries and affiliates in 2002 were from businesses located in investment grade countries compared with approximately 72% in 2001 and 56% in 2000.

At year end, the parent company and qualified holding companies had approximately $197 million of cash and $18 million of availability under our $350 million revolver.

AES is exposed to market risks associated with interest rates, foreign exchange rates and commodity prices. AES often utilizes financial instruments and other contracts to hedge against such fluctuations. AES also utilizes financial and commodity derivatives for the purpose of hedging exposures to market risk. AES generally does not enter into derivative instruments for trading or speculative purposes.

AES is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt, fixed-rate debt and trust preferred securities, as well as interest rate swap and option agreements. Depending on whether a plant's capacity payments or revenue stream is fixed or varies with inflation, AES partially hedges against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, AES executes interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing.

AES is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of our foreign subsidiaries and affiliates utilize currencies other than AES's consolidated reporting currency, the U.S. dollar. Additionally, certain of AES's foreign subsidiaries and affiliates have entered into monetary obligations in U.S. dollars or currencies other than their own functional currencies. Primarily, AES is exposed to changes in the U.S. dollar/United Kingdom Pound Sterling exchange rate, the U.S. dollar/Brazilian Real exchange rate, the U.S. dollar/Venezuelan Bolivar exchange rate and the U.S. dollar/Argentine peso exchange rate. Whenever possible, these subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. AES also uses foreign currency forward and swap agreements, where possible, to manage our risk related to certain foreign currency fluctuations.

AES is exposed to the impact of market fluctuations in the price of electricity, natural gas and coal. Although AES primarily consists of businesses with long-term contracts or retail sales concessions, a portion of AES's current and expected future revenues are derived from businesses without significant long-term revenue or supply contracts. These competitive supply businesses subject our results of operations to the volatility of electricity and natural gas prices in competitive markets. AES's businesses hedge certain aspects of their "net open" positions in the U.S. We have used a hedging strategy, where appropriate, to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy involves the use of commodity forward contracts, futures, swaps and options as well as long-term supply contracts for the supply of fuel and electricity.

In 2000, AES adopted a value at risk ("VaR") approach to assess and manage risk across the Company and its subsidiaries. VaR measures the potential loss in a portfolio's value due to market volatility, over a specified time horizon, stated with a specific degree of probability. The quantification of market risk using VaR provides a consistent measure of risk across diverse markets and instruments. The VaR approach was adopted because the Company feels that statistical models of risk measurement, such as VaR, provide an objective, independent assessment of risk exposure to the Company. The use of VaR requires a number of key assumptions, including the selection of a confidence level for expected losses, the holding period for liquidation and the treatment of risks outside the VaR methodology, including

liquidity risk and event risk. VaR, therefore, is not necessarily indicative of actual results that may occur.

The use of VaR allows AES to aggregate risks across all AES businesses compare risk on a consistent basis and identify the drivers of risk. Because of the inherent limitations of VaR, including those specific to the variance/covariance approach, specifically the assumption that values or returns are normally distributed, AES relies on VaR as only one component in its risk assessment process. In addition to using VaR measures, AES performs stress and scenario analyses to estimate the economic impact of market changes on the value of our portfolios. These results are used to supplement the VaR methodology.

AES has performed a company-wide VaR analysis of all of its material financial assets, liabilities and derivative instruments. The VaR calculation incorporates numerous variables that could impact the fair value of AES's instruments, including interest rates, foreign exchange rates and commodity prices, as well as correlation within and across these variables. AES performs its VaR calculation using a model based on J.P. Morgan's RiskMetrics approach, which utilizes the variance/covariance method. We express VaR as a dollar amount of the potential loss in the fair value of our portfolio based on a 95% confidence level and a one-day holding period.

During the year ended December 31, 2002, our average daily VaR for interest rate-sensitive instruments was $83.4 million. The daily VaR for interest rate-sensitive instruments was highest at the end of the third quarter, and equaled $95.2 million. The daily VaR for interest rate-sensitive instruments was lowest at the end of the second quarter, and equaled $76.3 million. Our average daily VaR for interest rate-sensitive instruments was $73.1 million during the year ended December 31, 2001. These amounts include the financial instruments that serve as hedges and the underlying hedged items. VaR for interest rate-sensitive instruments increased in 2002 as compared with 2001 due to higher interest rate volatilities, caused by decreases in interest rates and uncertainty surrounding the U.S. economy, and an increase in our fixed-rate debt portfolio due to the addition of new businesses. During the year ended December 31, 2002, our average daily VaR for foreign exchange rate-sensitive instruments was $46.5 million. The daily VaR for foreign exchange rate-sensitive instruments was highest at the end of the third quarter, and equaled $68.5 million. The daily VaR for foreign exchange rate-sensitive instruments was lowest at the end of the first quarter, and equaled $30.4 million. The average daily VaR for foreign exchange rate-sensitive instruments during the year ended December 31, 2001 was $3.4 million. These amounts include the financial instruments that serve as hedges and the underlying hedged items. VaR for foreign exchange rate-sensitive instruments increased in 2002 as compared to 2001 primarily due to the consolidation of Eletropaulo, which caused an increase in the Company's foreign currency denominated debt portfolio. During the year ended December 31, 2002, our average daily VaR for commodity price-sensitive instruments was $5.4 million. The daily VaR for commodity price-sensitive instruments was highest at the end of the first quarter, and equaled $6.7 million. The daily VaR for commodity price-sensitive instruments was lowest at the end of the third quarter, and equaled $4.8 million. The average daily VaR for commodity price-sensitive instruments during the year ended December 31, 2001 was $6.2 million. These amounts include the financial instruments that serve as hedges and do not include the underlying physical assets or contracts that are not permitted to be settled in cash.

We have audited the accompanying consolidated balance sheets of The AES Corporation and subsidiaries (the Company) as of December 31, 2002 and 2001, and the related consolidated statements of operations, changes in stockholders' equity (deficit), and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedules listed in the index on page S-1 of the Company's annual report on Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits. We did not audit the financial statements of C.A. La Electricidad de Caracas and Corporation EDC, C.A. and their subsidiaries ("EDC"), a majority-owned subsidiary, for the years ended December 31, 2001 and 2000, which statements reflect total assets constituting 9% of consolidated total assets as of December 31, 2001, total revenues constituting 11% and 8% of consolidated total revenues and total income from continuing operations constituting 50% and 14% of consolidated total income from continuing operations for 2001 and 2000, respectively. Those statements were audited by other auditors who have ceased operations and whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for EDC, is based solely on the report of such other auditors.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits, and the report of the other auditors, provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of the other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of The AES Corporation and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, based on our audits and the report of other auditors, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 10 to the financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001 to conform with Statement of Financial Accounting Standards No. 133. Also, as discussed in Note 10 to the financial statements, the Company changed its method of accounting for certain contracts for the purchase or sale of electricity effective April 1, 2002 to conform with Derivative Implementation Group Issue C-15. As discussed in Note 6 to the financial statements, the Company changed its method of accounting for goodwill and other intangible assets effective January 1, 2002 to conform with Statement of Financial Accounting Standards No. 142.

McLean, VA
February 12, 2003 (March 14, 2003 as to Note 4,
March 21, 2003 as to Notes 9 and 11, March 25, 2003 as to Note 22,
and March 21, 2003 as to Note 2 of Schedule I)

Due to the Company's inability to obtain an accountants' report from Porta, Cachafeiro, Laría Y Asociados (a Member Firm of Andersen), we have included this copy of their latest signed and dated accountants' report on the financial position and results of operations of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their subsidiaries as of December 31, 2001 and 2000, the results of their operations and their cash flows for the year ended December 31, 2001, and the results of their operations and cash flows for the period from June 1 through December 31, 2000. This report is a copy of the original and has not been reissued by Porta, Cachafeiro, Laría Y Asociados. Porta, Cachafeiro, Laría Y Asociados has not provided a consent to the inclusion of its report in this Form 10-K. See Exhibit 23.2 for additional information regarding our inability to obtain this consent and the limitations imposed on investors as a result.

To the Stockholders and the Board of Directors of
C.A. La Electricidad de Caracas and Corporación EDC, C.A.:

We have audited the accompanying combined balance sheets of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their Subsidiaries (Venezuelan corporations), translated into U.S. dollars, as of December 31, 2001 and 2000, and the related translated combined statements of income, stockholders' investment and cash flows for the year ended December 31, 2001 and for the period from June 1 through December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

These translated combined financial statements have been prepared for use in the preparation of the consolidated financial statements of AES Corporation and, accordingly, they translate the assets, liabilities, stockholders' investment, revenues and expenses of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their Subsidiaries for that purpose. The translated combined financial statements have not been prepared for use by other parties and may not be appropriate for such use.

In our opinion, the translated financial statements referred to above present fairly, in all material respects and for the purpose described in the preceding paragraph, the financial position of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their Subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the year ended December 31, 2001 and for the period from June 1 through December 31, 2000, in conformity with accounting principles generally accepted in the United States.

Caracas, Venezuela
January 18, 2002 (except with respect
to the matter discussed in Note 18, as
to which the dates are February 20, 2002)

THE AES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, 2001 AND 2000

The AES Corporation and its subsidiaries and affiliates, (collectively, "AES" or "the Company") is a global power company primarily engaged in owning and operating electric power generation and distribution businesses in many countries around the world. The revenues and cost of sales of our large utilities and growth distribution segments are reported as regulated, and the revenues and cost of sales of our contract generation and competitive supply segments are reported as non-regulated.

The consolidated financial statements have been prepared to give retroactive effect to the merger with IPALCO Enterprises, Inc. ("IPALCO"), which has been accounted for as a pooling of interests as more fully discussed in Note 3.

PRINCIPLES OF CONSOLIDATION—The consolidated financial statements of the Company include the accounts of The AES Corporation, its subsidiaries, and controlled affiliates. Investments, in which the Company has the ability to exercise significant influence but not control, are accounted for using the equity method. Intercompany transactions and balances have been eliminated. A loss in value of an equity method investment which is other than a temporary decline is recognized in earnings as an impairment.

CASH AND CASH EQUIVALENTS—The Company considers unrestricted cash on hand, deposits in banks, certificates of deposit, and short-term marketable securities with an original maturity of three months or less to be cash and cash equivalents.

INVESTMENTS—Securities that the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at historical cost. Other investments that the Company does not intend to hold to maturity are classified as available-for-sale or trading. Unrealized gains or losses on available-for-sale investments are recorded as a separate component of stockholders' equity. Investments classified as trading are marked to market on a periodic basis through the statement of operations. Interest and dividends on investments are reported in interest income. Gains and losses on sales of investments are recorded using the specific identification method. Short-term investments consist of investments with original maturities in excess of three months but less than one year. Debt service reserves and other deposits are treated as non-current assets (see Note 8).

INVENTORY—Inventory, valued at the lower of cost or market (first in, first out method) consists of the following (in millions):

	December 31,
	2002			2001
Coal, fuel oil, and other raw materials	$	281		$	334
Spare parts and supplies		217			292

Total		498			626
Less: Inventory of discontinued operations		(114	)		(158	)

	$	384		$	468

PROPERTY, PLANT, AND EQUIPMENT—Property, plant, and equipment is stated at cost. The cost of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. Depreciation, after consideration of salvage value, is computed using the straight-line method over the estimated composite useful lives of the assets. Depreciation expense stated as a

percentage of average cost of depreciable property, plant and equipment was, on a composite basis, 3.86%, 3.57% and 3.68% for the years ended December 31, 2002, 2001 and 2000, respectively.

The components of our electric generation and distribution assets and the related rates of depreciation are as follows:

	Composite Rate	Useful Life
Generation and Distribution Facilities	2.0% – 10.0%	10 – 50 yrs.
Other Buildings	2.5% – 5.0%	20 – 40 yrs.
Leasehold Improvements	3.3% – 10.0%	10 – 30 yrs.
Furniture and Fixtures	14.3% – 50.0%	2 – 7 yrs.

Maintenance and repairs are charged to expense as incurred. Emergency and rotable spare parts inventories are included in electric generation and distribution assets and are depreciated over the useful life of the related components.

CONSTRUCTION IN PROGRESS—Construction progress payments, engineering costs, insurance costs, salaries, interest, and other costs relating to construction in progress are capitalized during the construction period. Construction in progress balances are transferred to electric generation and distribution assets when each asset is ready for its intended use. Interest capitalized during development and construction totaled $302 million, $295 million, and $225 million in 2002, 2001, and 2000, respectively. Recoveries of liquidating damages from construction delays are recorded as a reduction in the related projects' construction costs.

GOODWILL—The Company recognizes as goodwill the excess of the cost of an acquired entity over the net amount assigned to assets acquired and liabilities assumed. The Company evaluates goodwill for impairment on an annual basis and whenever events or changes in circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company's annual impairment testing date is October 1^st. Prior to January 1, 2002, goodwill was amortized on a straight-line basis over the estimated benefit period, which ranged from 10 to 40 years, and total accumulated amortization amounted to $190 million at December 31, 2001. As of January 1, 2002, goodwill is no longer amortized.

LONG-LIVED ASSETS—In accordance with Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets," the Company evaluates the impairment of long-lived assets based on the projection of undiscounted cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values (see Note 5).

DEFERRED FINANCING COSTS—Financing costs are deferred and amortized over the related financing period using the effective interest method or the straight- line method when it does not differ materially from the effective interest method. Deferred financing costs are shown net of accumulated amortization of $178 million and $154 million as of December 31, 2002 and 2001, respectively.

PROJECT DEVELOPMENT COSTS—The Company capitalizes the costs of developing new construction projects after achieving certain project-related milestones which indicate that the project's completion is probable. These costs represent amounts incurred for professional services, permits, options, capitalized interest, and other costs directly related to construction. These costs are transferred to construction in progress when significant construction activity commences, or expensed at the time the Company determines that development of a particular project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, siting, financing, construction, permitting, and contract compliance.

INCOME TAXES—The Company follows SFAS No. 109, "Accounting for Income Taxes." Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases.

FOREIGN CURRENCY TRANSLATION—A business's functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is other than the U.S. dollar translate their assets and liabilities into U.S. dollars at the current exchange rates in effect at the end of the fiscal period. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. dollars at the average exchange rates that prevailed during the period. The translation differences that result from this process, and gains and losses on intercompany foreign currency transactions which are long-term in nature, and which the Company does not intend to settle in the foreseeable future, are shown in accumulated other comprehensive loss in the stockholders' equity section of the balance sheet. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency are included in determining net income. For subsidiaries operating in highly inflationary economies, the U.S. dollar is considered to be the functional currency, and transaction gains and losses are included in determining net income.

During 2002, the Brazilian Real experienced a significant devaluation relative to the U.S. dollar, declining from 2.41 Reais to the U.S. dollar at December 31, 2001 to 3.53 Reais at December 31, 2002. Also, during 2001, the Brazilian Real experienced a significant devaluation relative to the U.S. dollar declining from 1.96 Reais to the U.S. dollar at December 31, 2000 to 2.41 Reais to the dollar at December 31, 2001. This continued devaluation resulted in significant foreign currency translation and transaction losses. The Company recorded $357 million, $210 million, and $64 million before income taxes of non-cash foreign currency transaction losses on the U.S. dollar denominated debt at its investments in Brazilian businesses during 2002, 2001 and 2000, respectively. The 2002 amount of $357 million is reported as $317 million of foreign currency transaction losses, $43 million of related minority interest (income) expense, and $83 million of equity in pre-tax (loss) earnings of affiliates on the consolidated statement of operations that primarily arises from Eletropaulo which was consolidated beginning in February 2002. The 2001 and 2000 amounts of $210 million and $64 million, respectively, are recorded in equity in pre-tax (loss) earnings of affiliates in the accompanying consolidated statements of operations because Eletropaulo was accounted for as an equity method investment during those years. The cash flow impacts of these losses will be realized when the principal balance of the related debt is paid or subsequent refinancing of such principal are paid. In Brazil, the Company has total investments at December 31, 2002 in large utilities businesses of approximately negative $1.5 billion, in growth distribution businesses of approximately $146 million and in contract generation businesses of approximately $298 million, which are net of foreign currency translation losses and other comprehensive losses arising from minimum pension obligations.

changed the functional currency for its businesses in Argentina to the peso effective January 1, 2002. The Argentine peso experienced a significant devaluation relative to the U.S. dollar during 2002. The Company recorded pre-tax foreign currency transaction losses on the U.S. dollar denominated net liabilities of its Argentine subsidiaries during 2002 of approximately $143 million representing a decline in the Argentine peso to the U.S. dollar from 1.65 used at December 31, 2001 to 3.32 at December 31, 2002. In Argentina, the Company has total investments at December 31, 2002 in growth distribution businesses of approximately negative $61 million and in competitive supply businesses of approximately $141 million. These investment amounts are net of foreign currency translation losses. 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.

In February 2002, the Venezuelan government decided not to continue support of the Venezuelan currency. As a result, the Venezuelan Bolivar has experienced significant devaluation relative to the U.S. dollar during 2002. EDC, a subsidiary of the company, uses the U.S. dollar as its functional currency. A portion of its debt is denominated in the Venezuelan Bolivar, and as of December 31, 2002, EDC has net Venezuelan Bolivar monetary liabilities thereby creating the foreign currency gains when the Venezuelan Bolivar devalues. During 2002, the Company recorded pre-tax foreign currency transaction gains of approximately $39 million, as well as $40 million of pre-tax mark to market gains on a foreign currency forward contract due to a decline in the Venezuelan Bolivar to the U.S. dollar exchange rate from 758 at December 31, 2001 to 1,403 at December 31, 2002. At December 31, 2002, the Company's total investment in EDC, a large utility business, was approximately $1.8 billion, which is net of foreign currency translation losses.

REVENUE RECOGNITION AND CONCENTRATION—Electricity distribution revenues are reported as regulated. Revenues from the sale of energy are recognized in the period during which the sale occurs. The calculation of revenues earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the average price per customer class for that month. Revenues from the sale of electricity and steam generation are reported as non-regulated and are recorded based upon output delivered and capacity provided at rates as specified under contract terms or prevailing market rates. Revenues from power sales contracts entered into after 1991 with decreasing scheduled rates are recognized based on the output delivered at the lower of the amount billed or the average rate over the contract term. Several of the Company's power plants rely primarily on one power sales contract with a single customer for the majority of revenues (see Note 11). No single customer accounted for 10% or more of revenues in 2002, 2001 or 2000. The prolonged failure of any of the Company's customers to fulfill contractual obligations or make required payments could have a substantial negative impact on AES's revenues and profits.

Within our regulated businesses, sales of purchased power amounted to approximately $1.3 billion, $1.5 billion and $1.1 billion for the years ended December 31, 2002, 2001 and 2000, respectively. The related power purchased by the regulated businesses amounted to approximately $948 million, $970 million and $639 million for the years ended December 31, 2002, 2001 and 2000, respectively. Our non-regulated businesses consist primarily of generation businesses, and therefore, do not generally purchase power for resale.

REGULATION—The Company has investments in large utilities and growth distribution businesses located in the United States and certain foreign countries that are subject to regulation by the applicable regulatory authority. Our distribution businesses generally operate in markets that are subject to electricity price regulation as compared with regulation based solely on the cost of the electricity or the allowed rate of return on a specific distribution company's assets or net assets. For the regulated portion of these businesses, the Company capitalizes incurred costs as deferred regulatory assets when there is a probable expectation that future revenue equal to the costs incurred will be billed and collected as a direct result of the inclusion of the costs in an increased tariff set by the regulator or as permitted under the electricity sales concession for that business. The deferred

regulatory asset is eliminated when the Company collects the related costs through billings to customers, or when recovery is no longer probable. Regulators in the respective jurisdictions typically perform a tariff review for the distribution companies on an annual basis. If a regulator excludes all or part of a cost from recovery, that portion of the deferred regulatory asset is impaired and is accordingly reduced to the extent of the excluded cost. The Company has recorded deferred regulatory assets of $627 million and $390 million at December 31, 2002, and 2001, respectively, that it expects to pass through to its customers in accordance with and subject to regulatory provisions. These amounts include $11 million and $12 million of assets classified as discontinued operations at December 31, 2002 and 2001, respectively. The deferred regulatory assets at entities, which are controlled and consolidated by the Company, are recorded in other assets on the consolidated balance sheets.

The electricity industry in Brazil reached a critical point in 2001 as a result of a series of regulatory, meteorological and market driven problems. The Brazilian government implemented a program for the rationing of electricity consumption effective as of June 2001. In December 2001, an industry-wide agreement was reached with the Brazilian government that applies to Eletropaulo, Tiete, CEMIG, Sul and Uruguaiana. There were three parts of the agreement that specifically affected AES. The terms of the agreement were implemented during 2002.

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, the Company is 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.

DERIVATIVES—The Company enters into various derivative transactions in order to hedge its exposure to certain market risks. The Company does not enter into derivative transactions for trading purposes. All derivative transactions are accounted for under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended and interpreted. SFAS No. 133 requires that an entity recognize all derivatives (including derivatives embedded in other contracts), as defined, as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the derivative's fair value are to be recognized currently in earnings, unless specific hedge accounting criteria are met. Hedge accounting allows a derivative's gains or losses in fair value to offset related results of the hedged item in the statement of operations and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Prior to the adoption of SFAS No. 133 on January 1, 2001, derivatives were accounted for using settlement accounting (i.e. net settlements were accrued based on the current period cash settlement due under the contract).

SFAS No. 133 allows hedge accounting for fair value and cash flow hedges. SFAS No. 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair value hedge as well as the offsetting gain or loss on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge be reported as a component of accumulated other comprehensive income in stockholders' equity and be reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The remaining gain or loss on the derivative, if any, must be recognized currently in earnings. If a cash flow hedge is terminated because it is probable that the hedged transaction or forecasted transaction will not occur, the related balance in other comprehensive income as of such date is immediately recognized. If a cash flow hedge is terminated early for other reasons, the related balance in other comprehensive income as of the termination date is recognized concurrently with the related hedged transaction.

The Company currently has outstanding interest rate swap, cap, and floor agreements that hedge against interest rate exposure on floating rate non-recourse debt. These transactions, which are classified as other than trading, are accounted for at fair value. The majority of these transactions are accounted for as cash flow hedges.

The Company enters into currency swaps and forwards to hedge against foreign currency risk on certain non-functional currency-denominated liabilities. These transactions are accounted for at fair value. A portion of these transactions are accounted for as either fair value hedges or cash flow hedges.

The Company enters into electric and gas derivative instruments, including swaps, options, forwards and futures contracts to manage its risks related to electric and gas sales and purchases. These transactions are accounted for at fair value. The majority of these transactions are accounted for as cash flow hedges, and as such, gains and losses arising from derivative financial instrument transactions that hedge the impact of fluctuations in energy prices are recognized in income concurrent with the related purchases and sales of the commodity.

Derivative fair values are reflected at quoted or estimated market value. The values are adjusted to reflect the potential impact of liquidating the Company's position in an orderly manner over a reasonable period of time under present market conditions. In the absence of quoted market prices, other valuation techniques to estimate fair value are utilized. The use of these techniques requires the Company to make estimations of future prices and other variables, including market volatility, price correlation, and market liquidity.

In December 2001, the FASB revised its earlier conclusion, Derivatives Implementation Group ("DIG") Issue C-15, related to contracts involving the purchase or sale of electricity. Contracts for the purchase or sale of electricity, both forward and option contracts, including capacity contracts, may qualify for the normal purchases and sales exemption and are not required to be accounted for as derivatives under SFAS No. 133. In order for contracts to qualify for this exemption, they must meet certain criteria, which include the requirement for physical delivery of the electricity to be purchased or sold under the contract only in the normal course of business. Additionally, contracts that have a price based on an underlying index that is not clearly and closely related to the electricity being sold or purchased or that are denominated in a currency that is foreign to the buyer or seller are not considered normal purchases and normal sales and are required to be accounted for as derivatives under SFAS No. 133. This revised conclusion became effective beginning April 1, 2002 (see Note 10).

EARNINGS PER SHARE—Basic and diluted earnings per share are based on the weighted average number of shares of common stock and potential common stock outstanding during the period, after giving effect to stock splits (see Note 15). Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive stock options, warrants, deferred compensation arrangements, and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.

USE OF ESTIMATES—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant items subject to such estimates and assumptions include the carrying value and estimated useful lives of long-lived assets; impairment of goodwill and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of deferred regulatory assets and the valuation of certain financial instruments, pension liabilities, environmental liabilities and potential litigation claims and settlements (see Note 11).

STOCK OPTIONS—The Company accounts for its stock-based compensation plans under Accounting Principles Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees," and has adopted SFAS No. 123, "Accounting for Stock-based Compensation," for disclosure purposes. No compensation expense has been recognized in connection with the options, as all options have been granted only to AES people, including Directors, with an exercise price equal to the market price of the Company's common stock on the date of grant. For SFAS No. 123 disclosure purposes, the

weighted average fair value of each option grant has been estimated as of the date of grant primarily using the Black-Scholes option-pricing model with the following weighted average assumptions:

	Years Ended December 31,
	2002	2001	2000
Interest rate (risk-free)	3.83%	4.84%	5.4%
Volatility	68%	86%	41%
Dividend yield	—	—	1%

Using these assumptions, and an expected option life of approximately 9 years, the weighted average fair value of each stock option granted was $1.98, $14.87 and $18.99, for the years ended December 31, 2002, 2001 and 2000, respectively.

Had compensation expense been determined under the provisions of SFAS No. 123, utilizing the assumptions detailed in the preceding paragraph, the Company's net income and earnings per share for the years ended December 31, 2002, 2001 and 2000 would have been reduced to the following pro forma amounts (in millions except per share amounts):

	Years Ended December 31,
	2002			2001		2000
NET INCOME:
As reported	$	(3,509	)	$	273	$	795
Pro forma		(3,657	)		179		753
BASIC EARNINGS PER SHARE:
As reported	$	(6.51	)	$	0.52	$	1.66
Pro forma		(6.79	)		0.34		1.56
DILUTED EARNINGS PER SHARE:
As reported	$	(6.51	)	$	0.51	$	1.59
Pro forma		(6.79	)		0.33		1.50

The disclosures of such amounts and assumptions are not intended to forecast any possible future appreciation of the Company's stock or change in dividend policy.

Effective January 1, 2003, the Company has elected to adopt fair value accounting for its stock-based compensation as allowed under SFAS No. 123, as amended by SFAS No. 148. SFAS No. 123 allows for three alternative methods of accounting for stock-based compensation at fair value. The three methods are the prospective method, modified prospective method and the retroactive restatement method. The prospective method requires recognition of stock-based compensation expense at fair value for all awards granted in the year of adoption but not for previous awards. The modified prospective method requires recognition of stock-based compensation expense at fair value for the unvested portion of all stock options granted, modified or settled since 1994. The retroactive restatement method requires recognition of stock-based compensation expense at fair value for the unvested portion of all stock options granted, modified or settled since 1994 with all prior periods being restated. The Company has elected to use the prospective method for recognizing stock-based compensation expense.

The Company will continue to use an option-pricing model to determine the fair value of options issued. The expense for each award grant, including awards with graded vesting, will be recognized on a straight-line basis over the vesting period. Any forfeitures will be recognized when they occur. The above proforma disclosure has been calculated using these assumptions. Prior to the adoption of fair value accounting, the Company recognized compensation expense for stock options based on the intrinsic value of the option on the grant date, which was zero for all grants. Therefore, there has been no expense recorded for stock-based compensation for the year ended December 31, 2002 or any prior

periods. The Company's Board of Directors have approved the issuance of approximately 11 million options in the first quarter of 2003. Approximately 8 million of the options will be issued under existing plans. The remaining options will be granted under a new plan that is subject to shareholder approval. The Black Scholes fair value is $2.01 per option for those to be issued under the existing plans. The Company will recognize the expense related to these options based on their fair value over the vesting period which is 2 years.

RECLASSIFICATIONS—Certain reclassifications have been made to prior-period amounts to conform to the 2002 presentation.

On February 6, 2002, a subsidiary of the Company exchanged with EDF International S.A., its shares representing a 23.89% interest in Light Servicos de Eletricidade S.A. for 88% of the shares of AES Elpa S.A. (formerly Lightgas Ltda) (the "swap"). AES Elpa owns 77% of the voting capital (31% of the total capital) of Eletropaulo Metropolitana Eletricidade de Sao Paulo S.A. ("Eletropaulo") and 100% of AES Communications Rio. In connection with the swap, AES Elpa assumed debt of $527 million of which approximately $85 million was due in October 2002 and the remainder due in 2003.

The swap was accounted for at historical cost as a reorganization of entities under common control. Pre-existing goodwill of approximately $780 million was recorded in conjunction with the swap at the March 31, 2002 exchange rate. In conjunction with the Company's annual goodwill impairment review and as a result of the unfavorable economic and regulatory environment in Brazil, AES determined the entire goodwill amount was impaired and recorded a charge of $607 million, after income taxes, at the October 1, 2002 exchange rate (see Note 6).

As a result of the swap, the Company has a controlling interest through a 70.37% ownership interest in Eletropaulo and consolidates its activity. Previously the Company had accounted for its investment in Eletropaulo using the equity method. At December 31, 2002, Eletropaulo had total assets of approximately $3.6 billion and total liabilities of approximately $3.9 billion, including the debt of AES Elpa.

On March 27, 2001, AES completed its merger with IPALCO through a share exchange transaction in accordance with the Agreement and Plan of Share Exchange dated July 15, 2000, between AES and IPALCO, and IPALCO became a wholly owned subsidiary of AES. The Company accounted for the combination as a pooling of interests. Each of the outstanding shares of IPALCO common stock was converted into the right to receive 0.463 shares of AES common stock. The Company issued approximately 41.5 million shares of AES common stock. The consideration consisted of newly issued shares of AES common stock. IPALCO is an Indianapolis-based utility with approximately 3,400 MW of gross generation capacity and 450,000 customers in and around Indianapolis.

The Company issued approximately 346,000 options for the purchase of AES common stock in exchange for IPALCO outstanding options using the exchange ratio. All unvested IPALCO options became vested pursuant to the existing stock option plan upon the change in control.

In connection with the merger with IPALCO, the Company incurred contractual liabilities associated with existing termination benefit agreements and other merger related costs for investment banking, legal and other fees. These costs, which were $131 million in 2001 are shown separately in the accompanying consolidated statements of operations. All of the amounts for the plan were expensed as incurred. As a result of the plan, the workforce was reduced by 480 people.

The table below sets forth revenues, net income and comprehensive loss for AES and IPALCO for the period from January 1, 2001 through the date of the merger (amounts in millions).

Revenues:
	AES	$	1,820
	IPALCO		215

Consolidated Revenues		$	2,035

Net Income:
	AES	$	129
	IPALCO		(18	)

Consolidated Net Income		$	111

	AES			IPALCO			Combined
Comprehensive Loss:
Net Income (Loss)	$	129		$	(18	)	$	111
Foreign currency translation adjustment		(236	)		—			(236	)
Change in derivative fair value		(50	)		—			(50	)
Minimum pension liability		—			(2	)		(2	)
Cumulative effect of adopting SFAS No. 133 on Jan. 1, 2001		(93	)		—			(93	)

Comprehensive Loss	$	(250	)	$	(20	)	$	(270	)

There have been no changes to the significant accounting policies of AES or IPALCO due to the merger. Both AES and IPALCO have the same fiscal years. There were no intercompany transactions between the two companies prior to the merger date.

The tables below set forth revenues, net income and comprehensive income for AES and IPALCO for the year ended December 31, 2000.

		2000
Revenues:
	AES	$	5,315
	IPALCO		891

		$	6,206

Extraordinary items:
	AES	$	(7	)
	IPALCO		(4	)

		$	(11	)

Net Income:
	AES	$	640
	IPALCO		155

		$	795

	AES			IPALCO			Combined
Comprehensive Income:
Year ended December 31, 2000
Net Income	$	640			155		$	795
Foreign currency translation adjustment		(575	)		—			(575	)
Realized gains on marketable securities		—			(107	)		(107	)
Minimum pension liability adjustment		—			(2	)		(2	)

Comprehensive income	$	65		$	46		$	111

The Company has accounted for the following transactions, completed in 2001, using the purchase method of accounting. Accordingly, the purchase price of each transaction has been allocated based upon the estimated fair value of the assets and the liabilities acquired as of the acquisition date, with the excess, if any, reflected as goodwill. The results of operations of the acquired companies have been included in the consolidated results of operations since the date of each acquisition.

In January 2001, following the expiration on December 28, 2000 of a Chilean tender offer, Inversiones Cachagua Limitada, a Chilean subsidiary of AES, paid cash for 3,466,600,000 shares of common stock of Gener S.A ("Gener"). Also in January 2001, following the expiration on December 29, 2000 of the simultaneous United States offer to exchange all American Depositary Shares ("ADS") of Gener for AES common stock, AES issued 9.1 million shares of common stock with a value of approximately $511 million in exchange for Gener ADSs tendered pursuant to the United States offer, which, together with the shares acquired in the Chilean offer, resulted in AES's acquisition of approximately 96.5% of the capital stock of Gener. Subsequently, the Company's total ownership reached approximately 99% due to a stock buyback program initiated by Gener in February 2001. The purchase price for the acquisition of Gener was approximately $1.4 billion before asset sales of $318 million, plus the assumption of approximately $700 million of non-recourse debt. Approximately $865 million of goodwill was recorded as part of the purchase and was being amortized over 40 years until January 1, 2002 when the Company adopted SFAS No. 142. See Note 6 for further disclosure of the financial statement impact of this accounting pronouncement. In conjunction with its tender offer, the Company agreed to sell two of Gener's generating assets (Central Puerto and Hidronequen) to TotalFinaElf. In March 2001, Gener and TotalFinaElf executed a purchase and sale agreement which granted to

TotalFinaElf the option to purchase three of Gener's generating assets in Argentina: Central Puerto, Hidronequen and TermoAndes. Pursuant to this agreement, in August, 2001, AES sold Gener's interest in Central Puerto to a TotalFinaElf subsidiary for $255 million. In addition, in September TotalFinaElf purchased Gener's interest in Hidronequen for $72.5 million as well as subordinated debt related to Hidronequen held by Gener for approximately $50 million. The option to purchase TermoAndes expired unexercised. Upon completion of the purchase, Gener implemented an employee severance plan. As of December 31, 2001, the severance plan was completed and the workforce was reduced by 187 people. All of the approximately $9 million cost related to the plan was recorded in 2001 and all cash payments were made in 2001. The purchase price allocation for Gener was finalized during 2001.

In April 2001, the Company acquired a 75% controlling interest in Kievoblenergo, a distribution company that serves the region that surrounds Kiev, the capital city of Ukraine, for approximately $46 million in cash. The remaining 25% interest is either publicly owned or owned by the employees of the distribution company.

In May 2001, the Company acquired a 75% controlling interest in Rivnooblenergo, a distribution company that serves the Rivno region in Ukraine, for approximately $23 million in cash. The remaining 25% interest is either publicly owned or owned by the employees of the distribution company.

In July 2001, a subsidiary of the Company completed the final phase of its acquisition of the energy assets of Thermo Ecotek Corporation, a wholly owned subsidiary of Thermo Electron Corporation of Waltham, Massachusetts. The transaction was consummated in two phases. The initial phase of the transaction, which occurred on June 29, 2001, was closed at a price of $242 million in cash. The purchase price for the second and final phase was $18 million in cash. This resulted in a total purchase price for the two phases of the Thermo Ecotek acquisition of $260 million. No material long-term liabilities were assumed at the acquisition date. The portfolio of assets acquired by the Company included approximately 500 MW of gas-fired, biomass-fired (agricultural and wood waste) and coal-fired operating power assets in the United States, the Czech Republic, and Germany, a natural gas storage project in the United States, and over 1,250 MW of advanced development power projects in the United States.

In July 2001, a subsidiary of the Company acquired a 56% interest in SONEL, an integrated electricity utility in Cameroon, with a 20-year concession on generation, transmission and distribution country-wide. The purchase price was approximately $70 million in cash, plus the assumption of approximately $260 million of long-term liabilities. The other 44% will remain with the government. SONEL is one of the largest African electricity utilities with approximately 800 MW of installed capacity and 452,000 customers.

The purchase price allocations for Thermo Ecotek, SONEL, Kievoblenergo and Rivnooblenergo were finalized during 2002 with no material adjustments to the preliminary purchase accounting. Proforma disclosures for the 2002, 2001 and 2000 purchase business combinations have not been presented as the effects would be immaterial.

Effective January 1, 2001, AES adopted SFAS No. 144. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 requires a component of an entity that either has been disposed of or is classified as held for sale to be reported as discontinued operations if certain conditions are met.

As a result of a significant reduction in electricity prices in Great Britain during the first quarter of 2002, operating revenues at the Company's Fifoots Point subsidiary were insufficient to cover operating expenses and debt service costs. Accordingly, the subsidiary was placed in administrative receivership by

its project financing lenders and the Company's ownership of the subsidiary was terminated. This resulted in a write off of the Company's investment of $53 million, net of income taxes. The Company has no continuing involvement in the Fifoots Point subsidiary which was previously reported in the competitive supply segment.

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. During the year, a pre-tax goodwill impairment expense of approximately $104 million was recorded to reduce the carrying amount of the Company's investment to its estimated fair market value. The goodwill was considered impaired since the current fair market value of the business was less than its carrying value. The fair market value of AES's investment in CILCORP was estimated using as a basis the expected sale price under the related sales agreement. The transaction also includes an agreement to sell AES Medina Valley Cogen, a gas-fired cogeneration facility located in CILCO's service territory. The sale of CILCORP by AES was required under the Public Utility Holding Company Act (PUHCA) when AES merged with IPALCO, a regulated utility in Indianapolis, Indiana in March 2001. The transaction closed in January 2003, and generated approximately $500 million in cash proceeds, net of transaction expenses. CILCORP was previously reported in the large utilities segment.

During the second quarter of 2002, after exploring several strategic options related to Eletronet, a telecommunication business in Brazil, AES committed to a plan to sell its 51% ownership interest in this business. The estimated realizable value was less than the book value of AES's investment and as a result, the investment in Eletronet was written down to its estimated realizable value. The Eletronet sale will close in two parts, the first of which occurred on December 31, 2002. The total loss for Eletronet for 2002, including results of operations, write downs, and the effect of the first closing was $149 million, net of income taxes. Eletronet was previously reported in the competitive supply segment.

In September 2002, AES sold 100 percent of its ownership interest in AES NewEnergy to Constellation Energy Group for approximately $260 million, which resulted in a loss on sale of approximately $29 million. AES NewEnergy was previously reported in the competitive supply segment.

In December 2002, AES reached an agreement to sell 100 percent of its ownership interest in both AES Mt. Stuart and AES Ecogen, both generation businesses in Australia, to Origin Energy Limited and to a consortium of Babcock & Brown and Prime Infrastructure Group, respectively. The total sales price for both businesses is approximately $171 million, which equates to an equity purchase price of approximately $59 million, which represents a premium to AES's book investment. The sale of AES Mt. Stuart closed in January 2003. The sale of AES Ecogen closed in February 2003. AES Mt. Stuart and AES Ecogen were previously reported in the contract generation segment.

In December 2002, AES reached an agreement to sell 100 percent of its ownership interests in Songas Limited and AES Kelvin Power (Pty.) Ltd. to CDC Globeleq for approximately $329 million, which includes the assumption of debt. These two businesses were previously reported in the contract generation segment.

In December 2002, AES classified its investment in Mountainview as held for sale. In the fourth quarter of 2002, the Company recorded a pre-tax impairment charge of $415 million ($270 million after-tax) to reduce the carrying value of Mountainview's assets to estimated realizable value in accordance with SFAS No. 144. The determination of the realizable value was based on available market information obtained through discussions with potential buyers. In January 2003, the Company entered into an agreement to sell Mountainview for $30 million with another $20 million payment contingent on the achievement of project specific milestones. The transaction closed in March 2003. Mountainview was previously reported in the competitive supply segment.

During 2001, the Company decided to exit certain of its businesses. These businesses included Power Direct, Geoutilities, TermoCandelaria, Ib Valley and several telecommunications businesses in Brazil and the U.S. For those businesses disposed of or abandoned, the Company determined that significant adverse changes in legal factors and/or the business climate, such as unfavorable market conditions and low tariffs, negatively affected the value of these assets. The Company had certain businesses that were held for sale as of December 31, 2001, including TermoCandelaria. The sales of these assets were completed prior to December 31, 2002, and the resulting gains or losses on these sales were not material.

All of the business components discussed above are classified as discontinued operations in the accompanying consolidated statements of operations. Previously issued statements of operations have been restated to reflect discontinued operations reported subsequent to the original issuance date. The revenues associated with the discontinued operations were $1,714 million, $1,991 million and $1,400 million for the years ended December 31, 2002, 2001 and 2000, respectively. The pretax income associated with the discontinued operations were $121 million, $10 million and $11 million for each of the years ended December 31, 2002, 2001 and 2000, respectively. The loss on disposal and impairment write-downs for those businesses sold or held for sale, net of tax associated with the discontinued operations, was $633 million and $145 million for the years ended December 31, 2002 and 2001, respectively.

The assets and liabilities associated with the discontinued operations and assets held for sale are segregated on the consolidated balance sheets at December 31, 2002 and 2001. The carrying amount of major asset and liability classifications for businesses recorded as discontinued operations and held for sale are as follows:

Drax, is the operator of Drax Power Plant, Britain's largest power station. In November 2002, Drax terminated its Hedging Agreement with TXU Europe Energy Trading Limited ("TXU EET"). In November 2002, TXU Europe Group plc ("TXU Group"), the guarantor under the power supply hedging agreement between Drax Power and TXU EET, filed for administration in the United Kingdom. As a result of the termination of the Hedging Agreement, which provided Drax above-market prices for the contracted output (equal to approximately 60 percent of the total output of the plant), Drax became fully exposed to power prices in the United Kingdom. The termination of the Hedging Agreement constituted a change in circumstance as defined by Statement of Financial

Accounting Standard (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, that indicated that the carrying value of Drax's net assets may not be recoverable. Accordingly, in the fourth quarter of 2002, a pre-tax impairment charge of $1,170 million ($893 million after-tax) was recorded to write-down the net assets of Drax to their fair value. This charge includes a write off of $215 million of trade receivables and a $955 million write-down of the investment to net realizable value. The approximate fair value of net assets was determined by discounting future projected future cash flows of the business. Additionally, in the fourth quarter of 2002, the Company approved and committed to a plan to sell the business. The business is available for immediate sale, and a plan has been established to locate a buyer at a reasonable fair market price. The Company believes it will sell the business within one year and it is unlikely that significant changes will be made to the plan to sell. The Company expects to have a significant continuing involvement in the operations of the business after the sale transaction. Accordingly, Drax is classified as an asset held for sale in the accompanying consolidated balance sheets as of December 31, 2002 and 2001, and is classified as a competitive supply business.

Barry had a tolling agreement with TXU EET which contracted all of the output of the Barry plant. The TXU EET administration discussed above constituted a change in circumstance, as defined by SFAS No. 144, that indicated that the carrying amount of the Barry long-lived net assets may not be recoverable. Accordingly, in the fourth quarter of 2002, a pre-tax impairment charge of $172 million ($120 million after-tax) was recorded to write-down the long-lived net assets of Barry to their fair value. The approximate fair value of long-lived assets was determined by discounting the projected future cash flows of the business. Barry is a competitive supply business.

In the fourth quarter of 2002, circumstances surrounding the AES Lake Worth project indicated that the carrying amount of the Company's investment in the Lake Worth project may not be recoverable. Therefore, in accordance with SFAS No. 144, a pre-tax impairment charge of $78 million ($51 million after-tax) was recorded to write-down the net assets of the project to their fair market value. The fair value of the net assets was estimated by analyzing the discounted future cash flows of the business as well as indications from unrelated third parties regarding the value of the project. The timing of this charge was due to a decision by the Company not to provide any further funding for this project and to sell the project. Lake Worth is a competitive supply business.

In September 2002, AES Greystone, LLC and its subsidiary Haywood Power I, LLC, sold the Greystone gas-fired peaker assets then under construction in Tennessee to Tenaska Power Equipment for $36 million including cash and assumption of certain obligations. With this sale, AES and its subsidiaries have eliminated any future capital expenditures related to the facility, and also settled all major outstanding obligations with parties involved in this project. AES recorded a pre-tax loss of approximately $168 million ($110 million after-tax) associated with this sale. Greystone was previously recorded as a competitive supply business.

In March 2002, AES's 87 percent owned subsidiary, Corporacion EDC, C.A., sold its remaining shares in Compania Anonima Nacional Telefonos de Venezuela ("CANTV") for cash proceeds of approximately $92 million. The loss realized on this transaction, before the effect of minority interest, was approximately $57 million. EDC is a large utility business.

In December 2001, AES's 87 percent owned subsidiary, Corporacion EDC, C.A., sold a portion of its shares in CANTV as part of a share buyback program to CANTV for cash proceeds of approximately $59 million. The gain realized on this transaction, before the effect of minority interest, was approximately $18 million.

In 2000, a subsidiary of IPALCO sold approximately 1 million shares of its investment in an internet company which went public in 1999 for $114 million. This sale resulted in a gain to the Company of approximately $112 million before income taxes.

Also in 2000, IPALCO sold certain assets (the "Thermal Assets") for approximately $162 million. The transaction resulted in a gain to the Company of approximately $31 million before income taxes ($19 million after income taxes). Of the net proceeds, $88 million was used to retire debt specifically assignable to the Thermal Assets. The related notes were retired in November and December 2000 and January 2001. In connection with the retirement of the debt, the Company incurred make-whole payments and wrote-off debt issuance costs of approximately $4 million. IPALCO is a large utility business.

Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets" which establishes accounting and reporting standards for goodwill and other intangible assets. The standard eliminates goodwill amortization and requires an evaluation of goodwill for impairment upon adoption of the standard, as well as annual subsequent evaluations. The Company's annual impairment testing date is October 1st.

SFAS No. 142 requires that goodwill be evaluated for impairment at a level referred to as a reporting unit. A reporting unit is an operating segment as defined by SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information", or one level below an operating segment, referred to as a component. Each AES business constitutes a reporting unit.

Generally, reporting units have been acquired in separate transactions. In the event that more than one reporting unit is acquired in a single acquisition, the fair value of each reporting unit is determined, and that fair value is allocated to the assets and liabilities of that unit. If the determined fair value of the reporting unit exceeds the amount allocated to the net assets of the reporting unit, goodwill is assigned to that reporting unit.

The adoption of SFAS No. 142 resulted in a cumulative reduction to income of $473 million, net of income tax effects, which was recorded as a cumulative effect of accounting change in the first quarter of 2002. SFAS No. 142 adopts a fair value model for evaluating impairment of goodwill in place of the recoverability model used previously. The reduction resulted from the write off of goodwill related to certain of our businesses in Argentina, Brazil and Colombia. The Company wrote-off the goodwill associated with certain acquisitions where the current fair market value of such businesses is less than the current carrying value of the business, primarily as a result of reductions in fair value associated with lower than expected growth in electricity consumption and lower electricity prices due in part to the devaluation of foreign exchange rates compared to the original estimates made at the date of acquisition. The fair value of these businesses was estimated using the expected present value of future cash flows and comparable sales, when available.

As part of the annual testing, the Company wrote-off an additional $610 million, net of income tax effects, which is recorded in goodwill impairment expense in the accompanying consolidated statement of operations. The impairment expense primarily related to Eletropaulo in Brazil which was not included in the testing as part of the adoption of SFAS No. 142 since it was an equity method investment at that time. The goodwill was considered impaired since the current fair market value of the business is less than the carrying value of the business, primarily as a result of slower than anticipated recovery to pre-rationing electricity consumption levels and lower electricity prices due to devaluation of foreign exchange rates. The amount of the impairment charge represents the write off required to reduce the carrying amount of the asset to its estimated fair value based on discounted cash flows of the business.

Changes in the carrying amount of goodwill, by segment, for the year ended December 31, 2002 are as follows (in millions):

Reported net income and earnings per share adjusted to exclude goodwill amortization expense for 2002, 2001 and 2000 are as follows (in millions, except per share amounts):

Included in other assets in the accompanying consolidated balance sheets are concession agreements with a gross carrying amount of $184 million and accumulated amortization of $18 million. The agreements have a weighted average remaining amortization period of 17.3 years. For the year ended December 31, 2002 the amortization expense was $9.1 million. The estimated amortization expense for fiscal years 2003 through 2007 is $9.8 million each year.

The Company records its share of earnings from its equity investees on a pre-tax basis. The Company's share of the investee's income taxes is recorded in income tax expense.

CEMIG. The Company is a party to a joint venture/consortium agreement through which the Company has an equity investment in Companhia Energetica de Minas Gerais ("CEMIG"), an integrated utility in Minas Gerais, Brazil. The agreement prescribes ownership and voting percentages as well as other matters.

our partner in one of the holding companies in the CEMIG ownership structure sold its interest in this holding company to an unrelated third party in December 2002 for a nominal amount. Upon evaluating these events in conjunction with each other, the Company concluded that an other than temporary decline in value of the CEMIG investment had occurred. Therefore, in December 2002, AES recorded a charge related to the other than temporary impairment of the investment in CEMIG, and the shares in CEMIG were written-down to fair market value. Additionally, AES recorded a valuation allowance against a deferred tax asset related to the CEMIG investment. The total amount of these charges, net of tax, was $587 million, of which $264 million relates to the other than temporary impairment of the investment and $323 million relates to the valuation allowance against the deferred tax asset. As a result of these charges, the Company's investment in CEMIG, net of debt used to finance the CEMIG investment, is negative.

In the fourth quarter of 2002, AES lost management control of one of the holding companies in the CEMIG ownership structure. This holding company indirectly owns the shares related to the CEMIG investment and indirectly holds the project financing debt related to CEMIG. As a result of the loss of management control, AES deconsolidated this holding company at December 31, 2002, and will account for the investment in this holding company using the equity method in future periods.

Eletropaulo. In May 1999, a subsidiary of the Company acquired subscription rights from the Brazilian state-controlled Eletrobras, which allowed it to purchase preferred, non-voting shares in Light Servicos de Eletricidade S.A. ("Light") and Eletropaulo Metropolitana Electricidade de Sao Paulo S.A. ("Eletropaulo"). The aggregate purchase price of the subscription rights and the underlying shares in Light and Eletropaulo was approximately $53 million and $77 million, respectively, and represented 3.7% and 4.4% economic ownership interest in their capital stock, respectively.

In January 2000, 59% of the preferred non-voting shares of Eletropaulo were acquired for approximately $1 billion at auction from BNDES, the National Development Bank of Brazil. The price established at auction was approximately $72.18 per 1,000 shares, to be paid in four annual installments. In May 2000, a subsidiary of the company acquired an additional 5% of the preferred, non-voting shares of Eletropaulo for approximately $90 million. At December 31, 2000, the Company had a total economic interest of 49.6% and a voting interest of 17.35% in Eletropaulo; therefore, the Company accounted for this investment using the equity-method based on the related consortium agreement that allows the exercise of significant influence.

In December 2000, a subsidiary of the Company, along with EDF International S.A. ("EDF"), completed the acquisition of an additional 3.5% interest in Light from two subsidiaries of Reliant Energy for approximately $136 million. Pursuant to the acquisition, the Company acquired 30% of the shares while EDF acquired the remainder. With the completion of this transaction, the Company owned approximately 21.14% of Light.

In December 2000, a subsidiary of the Company entered into an agreement with EDF to jointly acquire an additional 9.2% interest in Light, which is held by a subsidiary of Companhia Siderurgica Nacional ("CSN"). In January 2001, pursuant to this transaction, the Company acquired an additional 2.75% interest in Light for $114.6 million. At December 31, 2001, the Company owned approximately 23.89% of Light.

On February 6, 2002, a subsidiary of the Company exchanged with EDF, their shares representing a 23.89% interest in Light for 88% of the shares of AES Elpa S.A. (formerly Lightgas Ltda). AES Elpa owns 77% of the voting capital (31% of total capital) of Eletropaulo and 100% of AES Communications Rio. As a result of this transaction, AES acquired a controlling interest in Eletropaulo and began consolidating the subsidiary.

Other. In the second quarter of 2002, the Company sold its investment in Empresa de Infovias S.A. ("Infovias"), a telecommunications company in Brazil, for proceeds of $31 million to CEMIG, an

affiliated company. The loss recorded on the sale was approximately $14 million and is recorded as a loss on sale of assets and asset impairment expenses in the accompanying consolidated statements of operations.

In the second quarter of 2002, the Company recorded an impairment charge of approximately $40 million, after income taxes, on an equity method investment in a telecommunications company in Latin America held by EDC. The impairment charge resulted from sustained poor operating performance coupled with recent funding problems at the invested company.

During 2001, the Company lost operational control of Central Electricity Supply Corporation ("CESCO"), a distribution company located in the state of Orissa, India. CESCO is accounted for as a cost method investment.

In May 2000, the Company completed the acquisition of 100% of Tractebel Power Ltd ("TPL") for approximately $67 million and assumed liabilities of approximately $200 million. TPL owned 46% of Nigen. The Company also acquired an additional 6% interest in Nigen from minority stockholders during the year ended December 31, 2000 through the issuance of approximately 99,000 common shares of AES stock valued at approximately $4.9 million. With the completion of these transactions, the Company owns approximately 98% of Nigen's common stock and began consolidating its financial results beginning May 12, 2000. Approximately $100 million of the purchase price was allocated to excess of costs over net assets acquired and was amortized through January 1, 2002 at which time the Company adopted SFAS No. 142 and ceased amortization of goodwill.

In August 2000, a subsidiary of the Company acquired a 49% interest in Songas Limited ("Songas") for approximately $40 million. The Company acquired an additional 16.79% of Songas for approximately $12.5 million, and the Company began consolidating this entity in 2002. Songas owns the Songo Songo Gas-to-Electricity Project in Tanzania. In December 2002, the Company signed a Sales Purchase Agreement to sell Songas. The sale is expected to close in early 2003. See Note 4 for further discussion of the transaction.

The following table presents summarized comparative financial information (in millions) for the Company's investments in 50% or less owned investments accounted for using the equity method.

AS OF AND FOR THE YEARS ENDED DECEMBER 31,	2002		2001		2000
Revenues	$	2,832	$	6,147	$	6,241
Operating Income		695		1,717		1,989
Net Income		229		650		859
Current Assets		1,097		3,700		2,423
Noncurrent Assets		6,751		14,942		13,080
Current Liabilities		1,418		3,510		3,370
Noncurrent Liabilities		3,349		8,297		5,927
Stockholder's Equity		3,081		6,835		6,206

In 2002, 2001 and 2000, the results of operations and the financial position of CEMIG were negatively impacted by the devaluation of the Brazilian Real and the impairment charge recorded in 2002. The Brazilian Real devalued 32%, 19% and 8% for the years ended December 31, 2002, 2001 and 2000, respectively.

The Company recorded $83 million, $210 million, and $64 million of pre-tax non-cash foreign currency transaction losses on its investments in Brazilian equity method affiliates during 2002, 2001 and 2000, respectively.

Affiliate	Country	2002		2001		2000
CEMIG	Brazil	21.62	%	21.62	%	21.62	%
Chigen affiliates	China	30.00		30.00		30.00
EDC affiliates	Venezuela	45.00		45.00		45.00
Eletropaulo	Brazil	—		50.43		49.60
Elsta	Netherlands	50.00		50.00		50.00
Gener affiliates	Chile	37.50		37.50		—
Infovias	Brazil	—		50.00		50.00
Itabo	Dominican Republic	25.00		25.00		25.00
Kingston Cogen Ltd	Canada	50.00		50.00		50.00
Light	Brazil	—		23.89		21.14
Medway Power, Ltd	United Kingdom	25.00		25.00		25.00
OPGC	India	49.00		49.00		49.00
Songas Limited	Tanzania	—		49.00		49.00

The Company's after-tax share of undistributed earnings of affiliates included in consolidated retained earnings was $189 million, $462 million, and $370 million at December 31, 2002, 2001 and 2000, respectively. The Company charged and recognized construction revenues, management fee and interest on advances to its affiliates, which aggregated $7 million, $12 million, and $11 million for each of the years ended December 31, 2002, 2001 and 2000, respectively.

	December 31,
	2002		2001
HELD-TO-MATURITY:
Certificates of deposit	$	168	$	106
Money market funds		40		1
Debt securities issued by foreign governments		—		2
Other		1		2

Subtotal		209		111

AVAILABLE-FOR-SALE:
Equity securities		—		103
Corporate Bonds		2		—

Subtotal		2		103

TRADING:
Equity securities		—		1

TOTAL	$	211	$	215

The Company's investments are classified as held-to-maturity, available-for-sale or trading. The amortized cost and estimated fair value of the held-to-maturity and available-for-sale investments (other than the equity securities discussed below) were approximately the same. The trading investments are recorded at fair value. As of December 31, 2002 and 2001, approximately $170 million and $100 million, respectively, of investments classified as held-to-maturity, were restricted or pledged as collateral.

During the fourth quarter of 2001, the Company recorded gross unrealized losses of approximately $48 million related to available-for-sale equity securities, which were included in accumulated other comprehensive loss in the accompanying consolidated balance sheets.

NON-RECOURSE DEBT—Non-recourse debt at December 31, 2002 and 2001 consisted of the following (in millions):

Non-recourse debt borrowings are primarily collateralized by the capital stock of the relevant subsidiary and in certain cases the physical assets of, and all significant agreements associated with, such business. Such debt is not a direct obligation of AES, the parent corporation. These non-recourse financings include structured project financings, acquisition financings, working capital facilities and all other consolidated debt of the subsidiaries. The Company has issued shares of common stock to consolidated subsidiaries as collateral under various borrowing arrangements (see Note 14).

The Company has interest rate swap and forward interest rate swap agreements for continuing operations, discontinued operations and businesses held for sale in an aggregate notional principal amount of approximately $4.4 billion at December 31, 2002. The interest rate swaps are accounted for at fair value (see Note 10). The swap agreements effectively change the variable interest rates on the portion of the debt covered by the notional amounts to fixed rates ranging from approximately 2.22% to 9.90%. The agreements expire at various dates from 2003 through 2023. In the event of nonperformance by the counter parties, the Company may be exposed to increased interest rates; however, the Company does not anticipate nonperformance by the counter parties, which are multinational financial institutions.

Certain commercial paper borrowings of subsidiaries are supported by letters of credit or lines of credit issued by various financial institutions. In the event of nonperformance or credit deterioration of these financial institutions, the Company may be exposed to the risk of higher effective interest rates. The Company does not believe that such nonperformance or credit deterioration is likely.

With the exception of Eletropaulo, none of the projects referred to above that are currently in default are owned by subsidiaries that currently meet the applicable definition of materiality in AES's corporate debt agreements in order for such defaults to trigger an event of default or permit an acceleration under such indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact the Company's financial position and results of operations, it is possible that one or more of these subsidiaries could fall within the definition of a "material subsidiary" and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the AES parent company's senior notes, senior subordinated notes and junior subordinated notes.

As of December 31, 2002, AES Elpa and AES Transgas had approximately $542 million and $621 million of outstanding BNDES and BNDESPAR indebtedness, respectively. All of the common shares of Eletropaulo owned by AES Elpa are pledged to BNDES to secure the AES Elpa debt and all of the preferred shares of Eletropaulo owned by AES Transgas and AES Cemig Empreendimentos II, Ltd. (which owns approximately 7.4% of Eletropaulo's preferred shares, representing 4.4% economic ownership of Eletropaulo) are pledged to BNDESPAR to secure AES Transgas debt. AES has pledged its share of the proceeds in the event of the sale of certain of its businesses in Brazil, including Sul, Uruguaiana, Eletronet and AES Communications Rio, to secure the indebtedness of AES Elpa to BNDES for the repayment of the debt of AES Elpa. The interests underlying the Company's investments in Uruguaiana, AES Communications Rio and Eletronet have also been pledged as collateral to BNDES under the AES Elpa loan. As of December 31, 2002, Eletropaulo had $1.4 billion of outstanding indebtedness.

Due, in part, to the effects of power rationing, the sharp decline of the value of the Brazilian Real in dollar terms and the lack of access to the international capital markets, Eletropaulo is facing significant near-term debt payment obligations that must be extended, restructured, refinanced or repaid. AES Elpa failed to make a payment of $85 million due to BNDES on January 30, 2003, and AES Transgas failed to make a payment of $330 million due to BNDESPAR on February 28, 2003 in connection with the purchase of the preferred shares of Eletropaulo. All other participating holders of preferred shares of Eletropaulo accepted an offer from AES Transgas to defer payment until April 15, 2003, of approximately $6.5 million due by AES Transgas in connection with the deferred purchase by AES Transgas of Eletropaulo preferred stock from such former holders. As a result of such failure to pay the amounts due under the financing arrangements, BNDES has the right to call due the approximately $542 million of AES Elpa's outstanding debt with BNDES and BNDESPAR has the right to call due approximately $621 million of AES Transgas's outstanding debt with BNDESPAR. As a result of a cross default provision, BNDES also has the right to call due approximately $231 million loaned to Eletropaulo under the program in Brazil established to alleviate the effects of rationing on electricity companies. Due to BNDES' right of acceleration and existing financial covenant and other defaults under Eletropaulo loan agreements, Eletropaulo's commercial lenders have the right to call due approximately $836 million of indebtedness. In addition, Eletropaulo has indebtedness of approximately $514 million scheduled to mature in 2003. At December 31, 2002, Eletropaulo, AES Elpa and AES Transgas have a combined $1.9 billion of debt classified as current on the accompanying consolidated balance sheet.

Although neither AES Elpa nor AES Transgas currently constitute "material subsidiaries" for purposes of the cross-default, cross acceleration and bankruptcy related events of default contained in AES's parent company indebtedness, Eletropaulo does constitute a "material subsidiary" for purposes of certain of such bankruptcy-related events of default. However, given that a bankruptcy proceeding would generally be an unattractive remedy for Eletropaulo's lenders, as it could result in an intervention by ANEEL or a termination of Eletropaulo's concession, and given that Eletropaulo is currently in negotiations to restructure such indebtedness, the Company believes such an outcome is unlikely. The Company cannot assure you, however, that such negotiations will be successful. As a result, AES may have to write-off some or all of the assets of Eletropaulo, AES Elpa or AES Transgas.

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 (see Note 1). Approximately $231 million was outstanding at December 31, 2002. The loans bear interest at the Selic (Brazilian interbank interest rate), 24.90% at December 31, 2002, plus 1%. 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.

EDC, a subsidiary of the Company, was not in compliance with two of its net worth covenants on $131 million and $9 million of non-recourse debt primarily due to the impact of the devaluation of the Venezuelan Bolivar. EDC requested and received from its lenders waivers for both covenants, which are effective through March 31, 2003. Of the related debt approximately $102 million is classified as non-recourse debt—long term in the accompanying consolidated balance sheets. The remainder is classified as non-recourse debt—current.

On December 13, 2002, Drax signed a standstill agreement with its senior lenders to provide Drax time to restructure its business after the termination of the Hedging Agreement. The standstill agreement provides temporary and/or permanent waivers by the senior lenders of defaults that have occurred or could occur up to the expiry of the standstill period on May 31, 2003 including a permanent waiver resulting from termination of the Hedging Contract Since certain of Drax's forward looking debt service cover ratios as of June 30, 2002 were below required levels, Drax, was not able to make any cash distributions to Drax Energy at that time. Drax expects that the ratios, if calculated as of December 31, 2002, would again be below the required levels at December 31, 2002 since any improvement in the ratios for the period ended December 31, 2002 would have required a favorable change in the forward curve for electricity prices during the period from June 30, 2002 to December 31, 2002 and such favorable change did not occur. As part of the standstill agreement signed by Drax and its senior lenders, the debt service coverage ratios as of December 31, 2002 were not calculated by the bank group. As a consequence of the foregoing, Drax was not permitted to make any distributions to Drax Energy and Drax Energy was unable to make the full amount of the interest payment of $11.5 million and £7.6 million due on its high yield notes on February 28, 2003. Drax Energy's failure to make the full amount of the required interest payment constitutes an event of default under its high yield notes, although pursuant to intercreditor agreements the holders of the high yield notes have no enforcement rights until 90 days following the delivery of certain notices under the intercreditor arrangements. Drax is currently a material subsidiary for certain bankruptcy-related events of default, and therefore certain bankruptcy events of Drax could result in a default under our corporate debt agreements. Given the default remedies to the lenders, the Company believes that a bankruptcy event is unlikely.

On March 21, 2002, Fifoots was placed in administrative receivership by its lenders. Fifoots defaulted on its debt after electricity prices in the United Kingdom fell below its marginal costs. AES wrote off its investment of approximately $53 million in Fifoots during the first quarter of 2002.

RECOURSE DEBT—Recourse debt obligations are direct borrowings of the AES parent corporation and at December 31, 2002 and 2001, consisted of the following (in millions):

In December 2002, the Company entered into secured credit facilities provided by a syndicate of financial institutions. The senior secured credit facilities include a $350 million senior secured revolving credit facility (all of which may be used for the issuance of standby and commercial letters of credit), a £52.25 million additional letter of credit, a $500 million tranche A term loan facility, a $427.25 million tranche B term loan facility and a $260.25 million tranche C term loan facility. The senior secured credit facilities refinanced in full: (i) an $850 million revolving credit facility due March 2003, (ii) a $425 million Term Loan Facility due August 2003, (iii) a £52.25 million letter of credit, and (iv) the $262.5 million EDC SELLS loans due 2003. The senior secured credit facilities will mature on December 12, 2005 provided that, on or prior to July 15, 2005, the Company's 4.5% junior subordinated convertible debentures due August 15, 2005 have been refinanced to mature after December 12, 2005. If the Company's 4.5% junior subordinated convertible debentures have not been refinanced in such a manner, then the senior secured credit facilities will mature on July 15, 2005.

In December 2002, concurrent with entering into the senior secured credit facilities, the Company issued $258 million of 10% Senior Secured Notes due December 12, 2005. The senior secured notes

were issued in exchange for: (i) $84 million of the $300 million 8.75% Senior Notes due December 2002, and (ii) $174 million of the $200 million Remarketable or Redeemable Securities ("ROARS") due June 2003. The remaining $216 million of the $300 million 8.75% Senior Notes due December 2002 were redeemed in cash at or prior to maturity on December 15, 2002. The remaining $26 million of the ROARS remain outstanding and are scheduled to mature on June 15, 2003.

The Company has accounted for the debt refinancing in accordance with the requirements of Emerging Issues Task Force Issue No. 96-19 (EITF 96-19) "Debtors Accounting for a Modification of Debt Instruments." Under EITF 96-19, the previously existing credit facility and notes which were exchanged are treated as extinguished. Accordingly, unamortized bond premiums and deferred financing costs related to the old notes, and early tender and other cash payments to the lenders were expensed resulting in a loss on extinguishment of $8 million which is included in other expense in the consolidated statement of operations. Payments of $42 million to third parties including legal, arrangement, and other fees associated with the newly issued debt instruments have been deferred and will be amortized over 3 years.

As part of the exchange offer, the Company entered into a written Treasury rate option that expires in June 2003. As of December 31, 2002, the value of this option was a liability of approximately $25 million.

Loans under the revolving credit facility and the term loan facilities bear interest, at the Company's option, at the base rate or the Adjusted London Interbank Offered Rate (LIBOR) plus, in each case, applicable margins of 6.5% for LIBOR loans and 5.5% for base rate loans. Upon the occurrence of and during the continuance of any event of default, the applicable margin on both the LIBOR loans and the base rate loans will increase by 2.0%.

The Company will pay commitment fees (at a rate of 0.50% per annum) on the unused portion of the revolving credit facility. Such fees are payable quarterly in arrears. The Company will pay an additional fee (at a rate of 1.0%) of each lender's commitment (in the case of the lenders under the senior secured revolving credit facility) or outstandings (in the case of the lenders under the tranche A, B and C term loan facilities) (in each case, after giving effect to any prepayment) under the senior secured facilities on January 31, 2004 and on January 31, 2005. The Company will also pay a letter of credit fee on the outstanding and undrawn amount of letters of credit issued under the senior secured credit facilities (at a rate of 6.5%) which shall be shared ratably by all lenders participating in the relevant letters of credit.

The senior secured credit facilities and senior secured notes are to be amortized as follows: on November 25, 2004, the Company is obligated to ratably repay each term loan facility (calculated, in the case of the tranche A term loan facility, on the sum of the original aggregate amount of the tranche A term loan facility plus the original aggregate commitments under the revolving credit facility) and cash collateralize the additional Drax letter of credit facility, and repay the notes in an amount such that, after giving effect to such repayment (and after giving effect to the mandatory prepayments made on or before such repayment), (i) the aggregate amount of such term loan facility is no greater than 50% of the original aggregate principal amount of such term loan facility, (ii) 50% of the maximum amount available under the letter of credit issued in respect thereof is cash collateralized or prepaid and (iii) the aggregate amount of such notes are no greater than 60% of the original principal amount of such notes.

The senior secured credit facilities are subject to mandatory prepayment on a ratable basis with the Company's 10% senior secured exchange notes due 2005:

As of March 21, 2003, approximately $276 million of proceeds from sales had been presented as mandatory prepayment in accordance with this agreement.

Certain of the Company's obligations under the senior secured credit facilities are guaranteed by its direct subsidiaries through which the Company owns its interests in the Shady Point, Hawaii, Southland, Warrior Run and EDC businesses. The Company's obligations under the senior secured credit facilities are, subject to certain exceptions, substantially secured, equally and ratably with its 10.0% senior secured notes due 2005, by: (i) all of the capital stock of domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by the Company and (ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements. The Company's obligations under the senior secured credit facilities are secured equally and ratably with the Company's obligations under the senior secured notes.

The Junior Subordinated Debentures are convertible into common stock of the Company at the option of the holder at any time at or before maturity, unless previously redeemed, at a conversion price of $27.00 per share.

FUTURE MATURITIES OF DEBT—Scheduled maturities of total debt for continuing operations at December 31, 2002 are (in millions):

Scheduled maturities of total debt for discontinued operations at December 31, 2002 are (in millions):

COVENANTS—The terms of the Company's senior and subordinated notes contain certain restrictive financial and non-financial covenants. The financial covenants provide for, among other items, maintenance of a minimum consolidated net worth, minimum consolidated cash flow coverage ratio and minimum ratio of recourse debt to recourse capital. The non-financial covenants include limitations on the Company's ability to incur additional debt, pay dividends to stockholders, provide guarantees and enter into sale and leaseback transactions.

The senior secured credit facilities contain customary covenants and restrictions on the Company's ability to engage in certain activities, including, but not limited to:

The senior secured credit facilities also contain financial covenants requiring the Company to maintain certain financial ratios including:

The terms of the Company's non-recourse debt, which is debt held at subsidiaries, include certain financial and non-financial covenants. These covenants are limited to subsidiary activity and vary among the subsidiaries. These covenants may include but are not limited to maintenance of certain reserves, minimum levels of working capital and limitations on incurring additional indebtedness.

As of December 31, 2002, approximately $483 million of restricted cash was maintained in accordance with certain covenants of the debt agreements, and these amounts were included within debt service reserves and other deposits in the consolidated balance sheets.

Various lender and governmental provisions restrict the ability of the Company's subsidiaries to transfer their net assets to the parent company. Such restricted net assets of subsidiaries amounted to approximately $6 billion at December 31, 2002.

Effective January 1, 2001, AES adopted SFAS No. 133, "Accounting For Derivative Instruments And Hedging Activities," which, as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. The adoption of SFAS No. 133 on January 1, 2001, resulted in a cumulative reduction to income of less than $1 million, net of deferred income tax effects, and a cumulative reduction of accumulated other comprehensive income in stockholders' equity of $93 million, net of deferred income tax effects.

For the years ended December 31, 2002 and 2001, the impacts of changes in derivative fair value, net of income taxes, primarily related to derivatives that do not qualify for hedge accounting treatment, were a gain of $42 million and a charge of $36 million, respectively. These amounts include a charge of $12 million and a charge of $6 million, after income taxes, related to the ineffective portion of derivatives qualifying as cash flow and fair value hedges for the years ended December 31, 2002 and 2001, respectively which is primarily recorded in other expense. There was no net effect on results of operations for the years ended December 31, 2002 and 2001, of derivative and non-derivative instruments that have been designated and qualified as hedging net investments in foreign operations.

Approximately $112 million of other comprehensive loss related to derivative instruments as of December 31, 2002 is expected to be recognized as a reduction to income from continuing operations over the next twelve months. A portion of this amount is expected to be offset by the effects of hedge accounting. The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for hedges of interest rate risk, as depreciation is recorded for hedges of capitalized interest, as foreign currency transaction and translation gains and losses are recognized for hedges of foreign currency exposure, and as electric and gas sales and purchases are recognized for hedges of forecasted electric and gas transactions. Amounts recorded in accumulated other comprehensive income (loss), after income taxes, during the years ended December 31, 2002 and 2001, were as follows (in millions):

	Years Ended December 31,
	2002			2001
Balance, beginning of year	$	(121	)	$	—
Transition adjustment on January 1, 2001		—			(93	)
Reclassification to earnings		(106	)		(32	)
Change in fair value		(171	)		4

Balance, December 31	$	(398	)	$	(121	)

AES utilizes derivative financial instruments to hedge interest rate risk, foreign exchange risk and commodity price risk. The Company utilizes interest rate swap, cap and floor agreements to hedge interest rate risk on floating rate debt. The majority of AES's interest rate derivatives are designated and qualify as cash flow hedges. Certain derivatives are not designated as hedging instruments, primarily because they do not qualify for hedge accounting treatment as defined by SFAS No. 133. The purpose of these instruments is to economically hedge interest rate risk, foreign exchange risk or commodity price risk. However, certain features of these contracts, primarily the inclusion of written options, cause them to not qualify for hedge accounting.

Currency forward and swap agreements are utilized by the Company to hedge foreign exchange risk which is a result of AES or one of its subsidiaries entering into monetary obligations in currencies other than its own functional currency. A portion of these contracts are designated and qualify as either fair value or cash flow hedges. Certain derivative instruments and other non-derivative instruments are designated and qualify as hedges of the foreign currency exposure of a net investment in a foreign operation. Approximately $13 million and $1 million of transaction losses, after income taxes, related to derivative and non-derivative instruments that have been designated as hedges of the foreign currency exposure of net investments in foreign operations are included in the foreign currency cumulative translation adjustment for the years ended December 31, 2002 and 2001, respectively.

The Company utilizes electric and gas derivative instruments, including swaps, options, forwards and futures, to hedge the risk related to electricity and gas sales and purchases. The majority of AES's electric and gas derivatives are designated and qualify as cash flow hedges.

The maximum length of time over which AES is hedging its exposure to variability in future cash flows for forecasted transactions, excluding forecasted transactions related to the payment of variable interest, is twenty-eight years. For the years ended December 31, 2002 and 2001, charges of $1 million and $4 million, after income taxes, were recorded for cash flow hedges that were discontinued because it became probable that the hedged forecasted transactions will not occur. A portion of the 2001 charge has been classified as discontinued operations. For the year ended December 31, 2002, two fair value hedges were discontinued because they failed to meet the hedge effectiveness criteria of SFAS No. 133. The discontinuance of hedge accounting for these contracts did not have an impact on earnings. For the year ended December 31, 2001, no fair value hedges were de-recognized or discontinued.

On April 1, 2002, Derivative Implementation Group ("DIG") Issue C-15, "Normal Purchases and Normal Sales Exception for Option Type Contracts and Forward Contracts in Electricity" became effective. DIG Issue C-15 is an interpretation of SFAS, No. 133, "Accounting for Derivative Instruments and Hedging Activities", recognized by the FASB with respect to the application of SFAS No. 133. DIG Issue C-15 allows certain contracts for the purchase or sale of electricity, both forward contracts and option contracts, to qualify for the normal purchases and normal sales exemption and does not require these contracts to be accounted for as derivatives under SFAS No. 133. In order for contracts to qualify for this exemption, they must meet certain criteria, which include the requirement for physical delivery of the electricity to be purchased or sold under the contract only in the normal course of business. Additionally, contracts that have a price based on an underlying index that is not clearly and closely related to the electricity being sold or purchased or that are denominated in a currency that is foreign to the buyer or seller are not considered normal purchases and normal sales and are required to be accounted for as derivatives under SFAS No. 133.

The Company has two contracts that previously qualified for the normal purchases and normal sales exemption of SFAS No. 133, but no longer qualify for this exemption due to the effectiveness of DIG Issue C-15 on April 1, 2002. Accordingly, these contracts are required to be accounted for as derivatives at fair value. The two contracts are a 30-year power sales contract at the Warrior Run plant in Maryland and a 3-year power sales contract at the Deepwater plant in Texas. Approximately 28 years remain on the Warrior Run contract and approximately two years remain on the Deepwater contract.

The contracts were valued as of April 1, 2002, and an asset and a corresponding gain of $127 million, net of income taxes, was recorded as a cumulative effect of a change in accounting principle in the second quarter of 2002. The majority of the gain recorded relates to the Warrior Run contract, as the asset value of the Deepwater contract on April 1, 2002, was less than $1 million. The Warrior Run contract qualifies and was designated as a cash flow hedge as defined by SFAS No. 133 and hedge accounting is applied for this contract subsequent to April 1, 2002.

The contract valuations were performed using current forward electricity and gas price quotes and current market data for other contract variables. The forward curves used to value the contracts include certain assumptions, including projections of future electricity and gas prices in periods where future prices are not quoted. Fluctuations in market prices and their impact on the assumptions will cause the value of these contracts to change. Such fluctuations will increase the volatility of the Company's reported results of operations.

OPERATING LEASES—As of December 31, 2002, the Company was obligated under long-term non-cancelable operating leases, primarily for office rental and site leases. Rental expense for operating leases, excluding amounts related to the sale/leaseback discussed below, was $31 million $32 million and $13 million in the years ended December 31, 2002, 2001and 2000, respectively, including commitments of businesses classified as discontinued amounting to $6 million in 2002, $16 million in 2001 and $6 million in 2000.

The future minimum lease commitments under these leases are as follows (in millions):

	Total		Discontinued Operations
2003	$	30	$	4
2004		20		4
2005		15		3
2006		11		1
2007		9		1
Thereafter		84		1

Total	$	169	$	14

SALE/LEASEBACK—In May 1999, a subsidiary of the Company acquired six electric generating stations from New York State Electric and Gas ("NYSEG"). Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. This transaction has been accounted for as a sale/leaseback with operating lease treatment. Rental expense was $54 million, $58 million and $54 million in 2002, 2001 and 2000, respectively.

Future minimum lease commitments are as follows (in millions): In connection with the lease of the two power plants, the subsidiary is required to maintain a rent reserve account equal to the maximum semi-annual payment with respect to the sum of the basic rent (other then deferrable basic rent) and fixed charges expected to become due in the immediately succeeding three-year period. At December 31, 2002, 2001 and 2000, the amount deposited in the rent reserve account approximated

$32 million, $32 million and $31 million, respectively. This amount is included in restricted cash and can only be utilized to satisfy lease obligations.

In connection with the lease agreements, the Subsidiary is required to maintain an additional liquidity account. The required balance in the additional liquidity account was initially equal to the greater of $65 million less the balance in the rent reserve account or $29 million. As of December 31, 2002, the Subsidiary had fulfilled its obligation to fund the additional liquidity account by establishing a letter of credit, issued by Fleet Bank in the stated amount of approximately $36 million (the Additional Liquidity Letter of Credit). This letter of credit was established by AES for the benefit of the Subsidiary. However, the Subsidiary is obligated to replenish or replace this letter of credit in the event it is drawn upon or needs to be replaced.

CONTRACTS—Operating subsidiaries of the Company have entered into "take-or-pay" contracts for the purchase of electricity from third parties. Purchases in 2002 were approximately $1,263 million, including purchases of businesses classified as discontinued of $44 million.

	Total		Discontinued Operations
2003	$	983	$	46
2004		831		15
2005		658		8
2006		477		—
2007		474		—
Thereafter		6,663		—

Total	$	10,086	$	69

Operating subsidiaries of the Company have entered into various long-term contracts for the purchase of fuel subject to termination only in certain limited circumstances. Purchases in 2002 were approximately $642 million, including commitments of businesses classified as discontinued of $399 million.

	Total		Discontinued Operations
2003	$	671	$	457
2004		583		358
2005		440		202
2006		255		58
2007		227		1
Thereafter		2,729		—

Total	$	4,905	$	1,076

In connection with an electricity sales agreement, a subsidiary of the Company assumed contingent liabilities related to plant performance. If plant availability and contract performance specifications are not met, then a subsidiary of the Company may be required to make payments of up to $137 million to a third party under the terms of a power sales agreement.

Several of the Company's power plants rely on power sales contracts with one or a limited number of entities for the majority of, and in some case all of, the relevant plant's output over the term of the power sales contract. The remaining term of power sales contracts related to the Company's power plants range from 5 to 28 years. However, the operations of such plants are dependent on the continued performance by customers and suppliers of their obligations under the relevant power sales contract, and, in particular, on the credit quality of the purchasers. If a substantial portion of the Company's long-term power sales contracts were modified or terminated, the Company would be adversely affected to the extent that it was unable to find other customers at the same level of contract profitability. Some of the Company's long-term power sales agreements are for prices above current spot market prices. The loss of one or more significant power sales contracts or the failure by any of the parties to a power sales contract to fulfill its obligations thereunder could have a material adverse impact on the Company's business, results of operations and financial condition.

Two of these types of contracts, at the Company's Warrior Run and Beaver Valley plants, are with customers 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. The Company's investment in these subsidiaries was approximately $184 million at December 31, 2002. For the year ended December 31, 2002, the Company recorded $5.9 million of net income from the three subsidiaries.

Additionally, 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 the AES Wolf Hollow 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.

During 2000, the wholesale electricity market in California experienced a significant imbalance in the supply of, and demand for electricity, which resulted in significant electricity price increases and volatility. California's two largest utilities were required to purchase wholesale power at higher market prices and to sell it at fixed prices to retail end users. Because the cost of wholesale power exceeded the price the utilities charged their retail customers, these utilities are facing severe financial difficulties. There can be no assurances that such utilities can, or will choose to, honor their financial commitments. In the event that such utilities become insolvent or otherwise choose not to honor their commitments, creditors (including certain of the Company's subsidiaries) may seek to exercise whatever

remedies may be available, including, among other things, placing the utilities into involuntary bankruptcy. There can be no assurances that amounts owing directly or indirectly from such utilities will be recovered. In addition, the California Independent System Operator has sought a Temporary Restraining Order over some of the generators, including AES subsidiaries, arguing that, in times of declared emergencies, generators are required to continue to provide electricity to the market even if there is no credit-worthy purchaser for the electricity. The bulk of the Company's revenues in California are not subject to this credit risk, because they are generated under a tolling agreement entered into by AES Southland. But the Company's other subsidiaries have some exposure to this risk. At December 31, 2002, 2001 and 2000, the Company had receivables of approximately $4 million, $13 million and $27 million, respectively, that are subject to this credit risk. In addition, because these utilities have defaulted on amounts due in the state sanctioned markets, the markets have sought to recover those amounts pro rata from other market participants, including certain of the Company's subsidiaries. Enron Corporation and several of its affiliates filed Chapter 11 bankruptcy petitions on December 2, 2001, in the U.S. Bankruptcy Court for the Southern District of New York. At that time, several of the Company's subsidiaries had outstanding long-term contracts for gas and electricity purchases and sales with Enron and its subsidiaries. The Company does not believe its exposure under these contracts is material and has not recorded any liability associated with these contracts. Other Enron subsidiaries were also under contract to provide engineering, procurement and construction ("EPC") services on three of the Company's greenfield construction projects, including AES Wolf Hollow in Texas, AES Lake Worth Generation in Florida, and the AES Ebute Barge project in Nigeria. To avoid delay, each respective AES subsidiary has put into place transition arrangements that allow the subcontractors to continue working on the project, while alternative arrangements for completing the projects are investigated. Such alternative arrangements could include, but are not limited to, procuring a partner for the current EPC contractor, replacing the current EPC contractor entirely or assigning the contract to the largest subcontractor. Although disruption or delay in the progress of construction has not occurred to date, there can be no assurance that such disruption or delay will not occur in the future. The Company does not believe any such disruption or delay will have a material adverse effect on the results of operations or financial position of the Company.

ENVIRONMENTAL—As of December 31, 2002, the Company has recorded cumulative liabilities associated with acquired generation plants of approximately $31 million for projected environmental remediation costs. During 2000, the Company incurred a $17 million environmental fine and was required to incur capital expenditures related to excess nitrogen oxide air emissions at certain of its generating facilities in California.

The EPA has commenced an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Federal Clean Air Act associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. The EPA's focus is on whether the changes were subject to new source review or new performance standards, and whether best available control technology was or should have been used. On August 4, 1999, the EPA issued a Notice of Violation ("NOV") to the Company's Beaver Valley plant, generally alleging that the facility failed to obtain the necessary permits in connection with certain changes made to the facility in the mid-to-late 1980s. The Company believes it has meritorious defenses to any actions asserted against it and expects to vigorously defend itself against the allegations.

In May 2000, the New York State Department of Environmental Conservation ("DEC") issued a NOV to NYSEG for violations of the Federal Clean Air Act and the New York Environmental Conservation Law at the Greenidge and Westover plants related to NYSEG's alleged failure to undergo an air permitting review prior to making repairs and improvements during the 1980s and 1990s. Pursuant to the agreement relating to the acquisition of the plants from NYSEG, AES Eastern Energy agreed with NYSEG that AES Eastern Energy will assume responsibility for the NOV, subject to a reservation of AES Eastern Energy's right to assert any applicable exception to its contractual undertaking to assume pre-existing environmental liabilities. The Company believes it has meritorious defenses to any actions

asserted against it and expects to vigorously defend itself against the allegations; however, the NOV issued by the DEC, and any additional enforcement actions that might be brought by the New York State Attorney General, the DEC or the U.S. Environmental Protection Agency ("EPA"), against the Somerset, Cayuga, Greenidge or Westover plants, might result in the imposition of penalties and might require further emission reductions at those plants. In addition to the NOV, the DEC alleged, after our acquisition of the Cayuga, Westover, Greenidge, Hickling and Jennison plants from NYSEG in May 1999, air permit violations at each of those plants. Specifically, DEC has alleged exceedences of the opacity emissions limitations at these plants. With respect to pre-May 1999 and post-May 1999 violations, respectively, DEC has notified NYSEG, on the one hand, and AES, on the other, of their respective liability for such alleged violations. To remediate these alleged violations, DEC has proposed that each of AES and NYSEG pay fines and penalties in excess of $100,000. Resolution of this matter could also require AES to install additional pollution control technology at these plants. NYSEG has asserted a claim against AES for indemnification against all penalties and other related costs arising out of DEC's allegations. However, no formal consent order has been issued by the DEC.

The Company's generating plants are subject to emission regulations. The regulations may result in increased operating costs or the purchase of additional pollution control equipment if emission levels are exceeded.

The Company reviews its obligations as it relates to compliance with environmental laws, including site restoration and remediation. Because of the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Based on currently available information, the Company does not believe that any costs incurred in excess of those currently accrued will have a material effect on the financial condition and results of operations of the Company.

DERIVATIVES—Certain subsidiaries and an affiliate of the Company entered into interest rate, foreign currency, electricity and gas derivative contracts with various counterparties, and as a result, the Company is exposed to the risk of nonperformance by its counterparties. The Company does not anticipate nonperformance by the counter parties.

The Company is exposed to market risks on derivative contracts and on other unmatched commitments to purchase and sell energy on a price and quantity basis. Such market risks are monitored to limit the Company's exposure.

GUARANTEES—In connection with certain of its project financing, acquisition, and power purchase agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments, excluding those collateralized by letter-of-credit and other obligations discussed below, were limited as of December 31, 2002, by the terms of the agreements, to an aggregate of approximately $627 million representing 51 agreements with individual exposures ranging from less than $1 million up to $100 million. Of this amount, $219 million represents credit enhancements for non-recourse debt that is recorded in the accompanying consolidated balance sheets. The Company is also obligated under other commitments, which are limited to amounts, or percentages of amounts, received by AES as distributions from its subsidiaries. This amounted to $25 million as of December 31, 2002. In addition, the Company has commitments to fund its equity in projects currently under development or in construction. At December 31, 2002, such commitments to invest amounted to approximately $65 million.

In the normal course of business, AES and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a subsidiary on a stand-

alone basis, thereby facilitating the availability of sufficient credit to accomplish the subsidiaries' intended business purposes.

As prescribed in Financial Accounting Standards Board Interpretation No. 45 ("FIN 45"), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," the Company will begin recording a liability for the fair value of obligations it undertakes for guarantees issued after December 31, 2002. The disclosure provisions of FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. The following information represents the disclosures required by FIN 45. The interpretation does not encompass guarantees of the Company's own future performance; however, these guarantees are included in the presentation below. The Company does not expect adoption of the liability recognition provisions of FIN 45 to have a material impact on our financial position or results of operations.

Amounts identified as credit enhancements for non-recourse debt represent credit enhancements made by the parent company and other subsidiaries for the benefit of the lenders associated with the non-recourse debt recorded as liabilities in the accompanying consolidated balance sheets. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. Amounts identified as performance related obligations primarily represent future performance commitments which the Company expects to fulfill within the normal course of business. Amounts presented in the above table represent the Company's current undiscounted exposure to guarantees, and the range of maximum undiscounted potential exposure to the Company as of December 31, 2002. Guarantee termination provisions vary from less than 1 year to greater than 20 years. Some result from the repayment of the underlying debt or obligations, the end of a contract period, assignment, asset sale, change in credit rating, or elapsed time.

The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, supplier support and liquidated damages under power purchase agreements for projects in development, under construction and operating. While the Company does not expect to be required to fund any material amounts under these contingent contractual obligations during 2003 or beyond that are not recorded on the balance sheet, many of the events which would give rise to such an obligation are beyond the Company's control. There can be no assurance that the Company would have adequate sources of liquidity to fund its obligations under these contingent contractual obligations if it were required to make substantial payments thereunder.

LETTERS OF CREDIT—At December 31, 2002, the Company had $213 million in letters of credit outstanding representing 19 agreements with individual exposures ranging from less than $1 million up to $84 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. Of this amount, $135 million represent credit enhancements for non-recourse debt that is recorded in the accompanying consolidated balance sheets.

The Company pays a letter-of-credit fee ranging from 1.35% to 7.00% per annum on the outstanding amounts. In addition, the Company had $6 million in surety bonds outstanding at December 31, 2002.

LITIGATION—In September 1999, a judge in the Brazilian appellate state court of Minas Gerais granted a temporary injunction suspending the effectiveness of a shareholders' agreement between the Company's joint venture ("SEB") and the state of Minas Gerais concerning CEMIG which granted SEB certain rights and powers in respect of CEMIG (the "Special Rights"). The temporary injunction was granted pending determination by the lower state court of whether the shareholders' agreement could grant SEB the Special Rights. In November 1999, the full state appellate court upheld the temporary injunction. In March 2000, the lower state court in Minas Gerais ruled on the merits of the case, holding that the shareholders' agreement was invalid where it purported to grant SEB the Special Rights. In April 2001, the state appellate court denied an appeal of the merits decision, and extended the injunction. In October 2001, SEB filed two appeals against the decision on the merits of the state appellate court, one to the Federal Superior Court and the other to the Supreme Court of Justice. In August 2002, SEB filed two interlocutory appeals against the state appellate court's refusal to consider SEB's appeal on the merits, one directed to the Federal Superior Court and the other to the Supreme Court of Justice. The appeals continue to be pending. The Company, together with SEB, intends to vigorously pursue by all legal means a restoration of the value of its investment in CEMIG. However, there can be no assurances that the Company and SEB will be successful in their efforts. Failure to prevail in this matter may limit the SEB's influence on the daily operation of CEMIG.

in contravention of the antitrust laws. The AES Southland businesses have provided documents and other information to the Department of Justice.

and local counsel. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend these lawsuits vigorously.

In October 2002, the Company, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp were named as defendants in purported class actions filed in the United States District Court for the Eastern District of Virginia. Between October 29, 2002 and December 4, 2002, six virtually identical lawsuits were filed against the same defendants in the same court. The lawsuits purport to be filed on behalf of a class of all persons who purchased the Company's stock between April 26, 2001 and February 14, 2002. The complaints purport to allege that certain statements concerning the Company's operations in the United Kingdom violated Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder. On December 4, 2002 defendants moved to transfer the seven actions to the United States District Court for the Southern District of Indiana. By stipulation dated December 9, 2002, the parties agreed to consolidate these actions into one action. On December 12, 2002 the Court entered an order consolidating the cases under the caption In re AES Corporation Securities Litigation, Master File No. 02-CV-1485. On January 16, 2003, the Court granted defendants' motion to transfer the consolidation action to the United States District Court for the Southern District of Indiana. The Company and the individuals believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

any additional amounts are owed by its subsidiary and such subsidiary intends to defend vigorously against such claims.

In November 2002, a lawsuit was filed against AES Wolf Hollow LLP and AES Frontier L.P., two subsidiaries of the Company, in Texas State Court by Stone and Webster, Inc. The complaint in the action alleges claims for declaratory judgment and breach of contract allegedly arising out of the denial of certain force majeure claims purportedly asserted by the plaintiff in connection with its construction of the Wolf Hollow project, a gas-fired combined cycle power plant being constructed in Hood County, Texas. Stone and Webster is the general contractor for the Wolf Hollow project. The subsidiary believes it has meritorious defenses to the claims asserted against it and intends to defend the lawsuit vigorously.

On September 25, 2002, Mountainview filed a demand for arbitration against Bechtel Power Corporation (the "Bechtel Arbitration"). The claims asserted in the Bechtel Arbitration relate to existing disputes between the parties regarding amounts that Bechtel asserts are owing by Mountainview due to purported services provided in connection with the construction of the Mountainview power project located in California. Mountainview seeks a determination in the arbitration that Mountainview has fully performed all obligations owing to Bechtel and Mountainview owes no further amounts to Bechtel. In December 2002, the members of the arbitration panel were appointed by the parties. In January 2003, Bechtel and the Company agreed to a further stay of the arbitration pending the parties' finalization of an agreement whereby the Mountainview project would be sold by the Company. In March 2003, in connection with the sale of Mountainview, the parties agreed to file a voluntary dismissal of the arbitration.

In December 2002, Enron filed a lawsuit in the Bankruptcy Court for the Southern District Court of New York against the Company, NewEnergy, and CILCO. Pursuant to the Complaint, Enron seeks to

recover approximately $13 million dollars from NewEnergy (and the Company as guarantor of the obligations of NewEnergy). Enron contends that NewEnergy and the Company are liable to Enron based upon certain accounts receivables purportedly owing from NewEnergy and an alleged payment arising from the purported termination by NewEnergy of a "Master Energy Purchase and Sale Agreement." In the Complaint, Enron seeks to recover from CILCO the approximate amount of $31.5 million dollars arising from the termination by CILCO of a "Master Energy Purchase and Sale Agreement" and certain accounts receivables that Enron claims are due and owing from CILCO to Enron. On February 13, 2003 the Company, NewEnergy and CILCO filed a motion to dismiss certain portion of the action and compel arbitration of the disputes with Enron. Also in February 2003, the Bankruptcy Court ordered the parties to mediate the disputes. The Company believes it has meritorious defenses to the claims asserted against it and intends to defend the lawsuits vigorously.

On February 26, 2003, the Company, Dennis W. Bakke, Roger W. Sant, and Barry J. Sharp were named as defendants in a purported class action lawsuit filed in the United States District Court for the Southern District of Indiana captioned Stanley L. Moskal and Barbara A. Moskal v. The AES Corporation, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp, 1:03-CV-0284 (Southern District of Indiana). The lawsuit purports to be filed on behalf of a class of all persons who engaged in "option transactions" concerning AES securities between July 27, 2002 and November 8, 2002. The complaint alleges that AES and the individual defendants failed to disclose information concerning purported manipulation of the California electricity market, the effect thereof on AES's reported revenues, and AES's purported contingent legal liabilities as a result thereof, in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. The Company and the individual defendants have not yet responded to the complaint.

The Company is also involved in certain legal proceedings in the normal course of business. Certain claims, suits and complaints have been filed or are pending against the Company.

RISKS RELATED TO REGULATED AND FOREIGN OPERATIONS—AES operates businesses in many regulated and foreign environments. There are certain economic, political, technological and regulatory risks associated with operating in these environments. Investments in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. During 2002 and 2001, the Company's financial position and results of operations were adversely affected by a significant devaluation of the Argentine peso, Brazilian Real and Venezuelan Bolivar relative to the U.S. dollar.

The distribution businesses, which the Company owns or has investments in, are subject to regulatory review or approval which could limit electricity tariff rates charged to customers or require the return of amounts previously collected. These regulatory environments are also subject to change, which could impact the results of operations.

In certain locations, particularly developing countries or countries that are in a transition from centrally planned to market-oriented economies, the electricity purchasers, both wholesale and retail, may be unable or unwilling to honor their payment obligations. Collection of receivables may be hindered in these countries due to ineffective systems for adjudicating contract disputes.

In 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. Due to the changes, the Company changed the functional currency for its businesses in Argentina to the peso. If the commercial arrangements or regulatory framework within which any of the businesses operate become indexed to a currency other than the peso, the functional currency of the respective business may change. The Argentine peso has experienced a significant devaluation relative to the U.S. dollar during 2002. The Company recorded foreign currency transaction losses on its U.S. dollar denominated net liabilities during 2002 of approximately $143 million before income taxes representing a decline in the Argentine peso to the U.S. dollar from 1.65 used at December 31, 2001 to 3.32 at December 31, 2002.

The effects of the crisis are not expected to have a significant negative impact on AES's parent cash flow, due primarily to the non-recourse financing structure in place at most of AES's Argentine businesses. The effects of the current circumstances on future earnings are much more uncertain and difficult to predict. At December 31, 2002, AES's total investment in the competitive supply business in Argentina was approximately $141 million and the total investment in the growth distribution business is approximately negative $61 million. These investment amounts are net of foreign currency translation losses. Depending on the ultimate resolution of these uncertainties, AES may be required in 2003 to record a material impairment loss or write off associated with the recorded carrying values of its investments.

and preferred shares, through loans and deferred purchase price financing arrangements provided by BNDES, the National Development Bank of Brazil and its wholly owned subsidiary BNDES Participacoes Ltda. ("BNDESPAR"), to AES Elpa and AES Transgas, respectively. As of December 31, 2002, AES Elpa and AES Transgas had approximately $542 million and $621 million of outstanding BNDES and BNDESPAR indebtedness, respectively. All of the common shares of Eletropaulo owned by AES Elpa are pledged to BNDES to secure the AES Elpa debt and all of the preferred shares of Eletropaulo owned by AES Transgas and AES Cemig Empreendimentos II, Ltd. (which owns approximately 7.4% of Eletropaulo's preferred shares, representing 4.4% economic ownership of Eletropaulo) are pledged to BNDESPAR to secure AES Transgas debt. AES has pledged its share of the proceeds in the event of the sale of certain of its businesses in Brazil, including Sul, Uruguaiana, Eletronet and AES Communications Rio, to secure the indebtedness of AES Elpa to BNDES for the repayment of the debt of AES Elpa. The interests underlying the Company's investments in Uruguaiana, AES Communications Rio and Eletronet have also been pledged as collateral to BNDES under the AES Elpa loan. As of December 31, 2002, Eletropaulo had $1.4 billion of outstanding indebtedness. The Company's total investment associated with Eletropaulo as of December 31, 2002, was approximately negative $1.0 billion, which is net of foreign currency translation losses and other comprehensive losses arising from minimum pension obligations.

BNDES and BNDESPAR may choose to foreclose on the collateral, and this may result in a loss and a corresponding write-off of a portion or all of the Company's investment in Eletropaulo. In addition, the default on the BNDES loan could also result in a cross-default to a BNDES loan in connection with our investment in CEMIG.

Although neither AES Elpa nor AES Transgas currently constitute "material subsidiaries" for purposes of the cross-default, cross acceleration and bankruptcy related events of default contained in AES's parent company indebtedness, Eletropaulo does constitute a "material subsidiary" for purposes of certain of such bankruptcy-related events of default. However, given that a bankruptcy proceeding would generally be an unattractive remedy for Eletropaulo's lenders, as it could result in an intervention by ANEEL or a termination of Eletropaulo's concession, and given that Eletropaulo is currently in negotiations to restructure such indebtedness, the Company believes such an outcome is unlikely. The Company cannot assure you, however, that such negotiations will be successful. As a result, AES may have to write-off some or all of the assets of Eletropaulo, AES Elpa or AES Transgas.

intervention by ANEEL or a termination of Sul's concession, and because Sul has completed negotiations for debt restructuring through 2003, we think such an outcome is unlikely. We cannot assure you, however, that future negotiations will be successful and AES may have to write off some or all of the assets of Sul or AES Cayman Guaiba. The Company's total investment associated with Sul as of December 31, 2002 was approximately $146 million, which is net of foreign currency translation losses.

CEMIG. An equity method affiliate of AES received a loan from BNDES to finance its investment in CEMIG, and the balance, including accrued interest, outstanding on this loan is approximately $700 million as of December 31, 2002. Approximately $57 million of principal and interest, which represents AES's share, is scheduled to be repaid in May 2003. If the equity method affiliate of the Company is not able to repay the amounts when due or is not able to refinance or extend the maturities of any or all of the payment amounts, BNDES may choose to seize the shares held as collateral. Additionally, the existing default on the debt used to finance the acquisition of Eletropaulo could result in a cross default on the debt used to finance the acquisition of CEMIG. In December 2002, AES recorded a charge related to the other than temporary impairment of the investment in CEMIG, as the shares in CEMIG were written-down to fair market value. Additionally, AES recorded a valuation allowance against a deferred tax asset related to the CEMIG investment. The total amount of these charges, net of tax, was $587 million, of which $264 million relates to the other than temporary impairment of the investment and $323 million relates to the valuation allowance against the deferred tax asset. At December 31, 2002, the Company's total investment associated with CEMIG was negative.

available to enable that payment to be made. As a result, Tiete Holdings intends to seek certain amendments to the debt obligations and the OPIC documentation designed to reduce the risk of defaults due to the limitation on dividend and interest on net worth payments, including amendments to allow debt payments to be made with the proceeds of loans from Tiete. Any loan by Tiete to its affiliates is subject to ANEEL approval. No assurance can be given, however, that these amendments will be adopted or that ANEEL will grant such approval.

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 third part of the agreement, Sul was permitted to record additional revenue and a corresponding receivable from the spot market in the fourth quarter of 2001. However, the electricity regulator, ANEEL promulgated Order 288 which retroactively changed certain previously communicated methodologies during May 2002, 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.

experiencing a negative growth of GDP, high unemployment, significant foreign currency fluctuations and political instability. Beginning December 2, 2002 Venezuela experienced a forty-five day nationwide general strike that affected a significant portion of the Venezuelan economy, including the city of Caracas and the oil industry. This general strike has affected the normal conduct of the business of EDC. In combination, these circumstances create significant uncertainty surrounding the performance, cash flow and potential for profitability of EDC. However, AES is not required to support the potential cash flow or debt service obligations of EDC. AES's total investment in EDC at December 31, 2002 was approximately $1.8 billion, which is net of foreign currency translation losses.

In January 1999, a joint resolution of the Ministry of Energy and Mines and the Ministry of Industry and Commerce established the basic tariff rates applicable during the Four Year Tariff Regime from 1999 through 2002. The tariffs were established by the Ministry of Energy and Mines using a combination of cost-plus and return on investment methodologies. The regulation that establishes basic tariff rates is expected to change for 2003, and this change may have an impact on the amount and timing of the cash flows and earnings reported by EDC.

LEVERAGED LEASE INVESTMENTS—CILCORP, which is classified as a discontinued operation in the consolidated financial statements, has investments in leveraged leases totaling $135 million. Related deferred tax liabilities total $108 million. The investment includes estimated residual values totaling $86 million. Leveraged lease residual value assumptions are adjusted on a periodic basis, based on independent appraisals. CILCORP was sold to Ameren Corporation in a transaction that closed on January 31, 2003.

SALE OF ACCOUNTS RECEIVABLE—IPL, a subsidiary of the Company, formed IPL Funding Corporation ("IPL Funding") in 1996 to purchase, on a revolving basis, up to $50 million of the retail accounts receivable and related collections of IPL in exchange for a note payable. IPL Funding is not

consolidated by IPL or IPALCO since it meets requirements set forth in SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" to be considered a qualified special-purpose entity. IPL Funding has entered into a purchase facility with unrelated parties ("the Purchasers") pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, up to $50 million of the receivables purchased from IPL. As of December 31, 2002, the aggregate amount of receivables purchased pursuant to this facility was $50.0 million. The net cash flows between IPL and IPL Funding are limited to cash payments made by IPL to IPL Funding for interest charges and processing fees. These payments totaled approximately $1.1 million, $2.3 million and $3.5 million for the years ended December 31, 2002, 2001 and 2000, respectively. IPL retains servicing responsibilities through its role as a collection agent for the amounts due on the purchased receivables. IPL and IPL Funding provide certain indemnities to the Purchasers, including indemnification in the event that there is a breach of representations and warranties made with respect to the purchased receivables. IPL Funding and IPL each have agreed to indemnify the Purchasers on an after-tax basis for any and all damages, losses, claims, liabilities, penalties, taxes, costs and expenses at any time imposed on or incurred by the indemnified parties arising out of or otherwise relating to the sale agreement, subject to certain limitations as defined in the agreements. The transfers of such accounts receivable from IPL to IPL Funding are recorded as sales; however, no gain or loss is recorded on the sale.

Under the receivables sale agreement, if IPL fails to maintain certain financial covenants regarding interest coverage and debt to capital, it would constitute a "termination event." As of December 31, 2002, IPL was in compliance with such covenants.

As a result of IPL's current credit rating, the facility agent has the ability to (i) replace IPL as the collection agent; and (ii) declare a "lock-box" event. Under a lock-box event or a termination event, the facility agent has the ability to require all proceeds of purchased receivables of IPL to be directed to lock-box accounts within 45 days of notifying IPL. In the facility agent's discretion, the lock-box account may be under the control of IPL (as collection agent) or under the control of the facility agent. A termination event would also give the Purchasers the option to discontinue the purchase of new receivables and cause all proceeds of the purchased receivables to be used to reduce the Purchaser's investment and to pay other amounts owed to the Purchasers and the facility agent. This would have the effect of reducing the operating capital available to IPL by the aggregate amount of such purchased receivables, currently $50 million.

OTHER—IPL has an agreement with a regulatory body that establishes certain performance measures for their system reliability and call center performance. If these measures are not maintained, penalties of up to $7 million per year can be assessed. During 2002, IPL was assessed penalties of $1.25 million.

LIQUIDITY—AES believes that its sources of liquidity will be adequate to meet its needs through the end of 2003. This belief is based on a number of assumptions, including, without limitation, the non-recourse nature of subsidiary debt, assumptions about exchange rates, pool prices, the ability of its subsidiaries to pay dividends and the timing and amount of asset sale proceeds. As discussed in Note 9, AES (as parent) completed an exchange offer which extended the maturities of the parent debt. In addition, as discussed in this Note 11, AES has numerous material contingent commitments. While AES does not expect to be required to fund any material amounts under these contingent contractual obligations during 2003, many of the events which would give rise to such an obligation are beyond AES's control.

12. COMPANY-OBLIGATED CONVERTIBLE MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS

During 1997, two wholly owned special purpose business trusts (AES Trust I and AES Trust II) issued Term Convertible Preferred Securities ("Tecons"). On March 31, 1997, AES Trust I issued 5 million of $2.6875 Tecons (liquidation value $50) for total proceeds of $250 million and concurrently purchased $250 million of 5.375% junior subordinated convertible debentures due 2027 of AES (individually the

5.375% Debentures). On October 29, 1997, AES Trust II issued 6 million of $2.75 Tecons (liquidation value $50) for total proceeds of $300 million and concurrently purchased $300 million of 5.5% junior subordinated convertible debentures due 2012 of AES (individually the 5.5% Debentures). During 2000, the Company called for redemption of AES Trust I and AES Trust II. Substantially all of AES Trust I Tecons were converted into approximately 14 million shares of AES common stock and substantially all of AES Trust II Tecons were converted into approximately 11 million shares of AES common stock.

During 1999, AES Trust III, a wholly owned special purpose business trust, issued 9 million of $3.375 Tecons (liquidation value $50) for total proceeds of approximately $518 million and concurrently purchased approximately $518 million of 6.75% junior subordinated convertible debentures due 2029 (individually, the 6.75% Debentures).

During 2000, AES Trust VII, a wholly owned special purpose business trust, issued 9.2 million of $3.00 Tecons (liquidation value $50) for total proceeds of approximately $460 million and concurrently purchased approximately $460 million of 6% junior subordinated convertible debentures due 2008 (individually, the 6% Debentures and collectively with the 6.75% Debentures, the Junior Subordinated Debentures). The sole assets of AES Trust III and VII (collectively, the Tecon Trusts) are the Junior Subordinated Debentures.

AES, at its option, can redeem the 6.75% Debentures after October 17, 2002, which would result in the required redemption of the Tecons issued by AES Trust III, for $52.10 per Tecon, reduced annually by $0.422 to a minimum of $50 per Tecon, and can redeem the 6% Debentures after May 18, 2003, which would result in the required redemption of the Tecons issued by AES Trust VII, for $51.88 per Tecons, reduced annually by $0.375 to a minimum of $50 per Tecon. The Tecons must be redeemed upon maturity of the Junior Subordinated Debentures.

The Tecons are convertible into the common stock of AES at each holder's option prior to October 15, 2029 for AES Trust III and May 14, 2008 for AES Trust VII at the rate of 1.4216 and 1.0811, respectively, representing a conversion price of $35.171 and $46.25 per share, respectively.

Dividends on the Tecons are payable quarterly at an annual rate of 6.75% by AES Trust III and 6% by AES Trust VII. The Trusts are each permitted to defer payment of dividends for up to 20 consecutive quarters, provided that the Company has exercised its right to defer interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the Tecons would accumulate quarterly and accrue interest and the Company may not declare or pay dividends on its common stock.

On November 30, 1999, three wholly owned special purpose business trusts (individually, AES RHINOS Trust I, II, and III, collectively, the Rhinos Trusts and with the Tecon Trusts, collectively the Trusts) issued trust preferred securities ("Rhinos"). The aggregate amount of Rhinos issued was approximately $250 million. Concurrent with the issuance of the Rhinos, the Rhinos Trusts purchased approximately $258 million of junior subordinated convertible notes due 2007. In October 2001, the Rhino Trusts were converted to an amortizing loan. The amortizing loan balance was paid in full by August 2002.

Interest expense for each of the years ended December 31, 2002, 2001 and 2000, includes approximately $63 million, $63 million and $71 million, respectively, related to the Tecon Trusts and approximately, $0 million, $17 million and $21 million for 2002, 2001 and 2000, respectively, related to the Rhinos Trusts.

Minority interest includes $100 million of cumulative preferred stock of subsidiaries at December 31, 2002 and 2001. In 2000, a subsidiary of the Company retired $25 million of its cumulative preferred stock at par value. The total annual dividend requirement was approximately $5 million at December 31, 2002. $22 million of the preferred stock is subject to mandatory redemption

requirements over the period 2003-2008. Except for the series of preferred stock subject to mandatory redemption discussed above, each series of preferred stock is redeemable solely at the option of the issuer at prices between $101 and $118 per share.

SALE OF STOCK—In May 2000, the Company sold 24.725 million shares of common stock at $37.00 per share. Net proceeds from the offering were $886 million. In November 2000, the Company sold 10 million shares of common stock at $52.50 per share. Net proceeds from the offering were $520 million.

STOCK SPLIT AND STOCK DIVIDEND—On April 17, 2000, the Board of Directors authorized a two-for-one stock split, effected in the form of a stock dividend, payable to stockholders of record on May 1, 2000. Accordingly, all outstanding shares, per share and stock option data in all periods presented have been restated to reflect the stock split.

SHARES ISSUED FOR ACQUISITIONS—In January 2001, the Company issued approximately 9.1 million shares valued at approximately $511 million to fund a portion of the acquisition of Gener. During March 2001, the Company issued approximately 41.5 million shares in the IPALCO pooling-of-interests transaction. During December 2000, the Company issued approximately 699,000 shares, valued at $51 million to fund the acquisition of KMR. Also, during 2000, the Company issued approximately 343,000 shares, valued at $16 million in various other acquisitions.

SHARES ISSUED FOR DEBT—During 2002, the Company swapped 21.6 million shares of Common stock at an average value of $3.39 per share, for approximately $117.2 million in senior subordinated notes. This resulted in a gain on retirement of approximately $44 million for the year ended December 31, 2002.

RESTRICTED STOCK—The Company issued restricted stock under various incentive stock option plans. Generally, under each plan, shares of restricted common stock with value equal to a stated percentage of participants' base salary are initially awarded at the beginning of a three-year performance period, subject to adjustment to reflect the participants' actual base salary. The shares remain restricted and nontransferable throughout each three-year performance period, vesting in one-third increments in each of the three years following the end of the performance period. At the end of a performance period, awards are subject to adjustment to reflect the Company's performance compared to peer companies. Final awards under the plans can range from zero up to 400% of the initial awards. Vested shares are no longer restricted and may be held or sold by the participant. Compensation expense of $0 million, $0 million and $8 million for 2002, 2001 and 2000, respectively, as measured by the market value of the common stock at the balance sheet date, has been recognized. In January 2001, the final performance evaluation was completed for one of the restricted stocks plans resulting in final awards of an additional 199,000 shares with approximately 101,000 shares becoming fully vested. All shares of restricted stock became fully vested on the date of merger with IPALCO. Under the terms of the restricted stock plan, no additional shares will be awarded.

STOCK OPTIONS—The Company has granted options to purchase shares of common stock under its two stock option plans- The AES Corporation 2001 Stock Option Plan and The AES Corporation 2001 Non-Officer Stock Option Plan. Under the terms of the plans, the Company may issue options to purchase shares of the Company's common stock at a price equal to 100% of the market price at the date the option is granted. The options become eligible for exercise under various schedules.

The AES Corporation 2001 Stock Option Plan—The 2001 plan was issued effective January 1, 2001 due to the expiration of the 1991 stock option plan previously used. The standard is that outstanding stock options become exercisable on a cumulative basis at fifty percent for each of two years from the date of grant and expire ten years from date of grant. Additionally, some options become exercisable in as little as one year (100% in one year), or as many as four years (25% each year). At December 31, 2002,

7.7 million shares were remaining for award under the plan. The maximum term of options granted is 10 years.

The AES Corporation 2001 Non-Officer Stock Option Plan—The 2001 plan was issued without shareholder approval and therefore, all AES officers are excluded from receiving grants under the plan. The standard is that outstanding stock options become exercisable on a cumulative basis at fifty percent for each of two years from the date of grant and expire ten years from date of grant. Additionally, some options become exercisable in as little as one year (100% in one year) or as many as four years (25% each year). At December 31, 2002, 118,707 shares were remaining for award under the plan. The maximum term of options granted is 10 years.

The following table summarizes information about stock options outstanding at December 31, 2002 (in thousands of shares):

COMMON STOCK HELD BY SUBSIDIARIES—The Company has a secured equity-linked loan ("SELLS Loan") of $225 million due in 2004 issued by AES New York Funding, LLC (the "NY SELLS Loan"). The NY SELLS loan was issued by a consolidated subsidiary and has been classified as non-recourse debt in the accompanying consolidated balance sheets.

The NY SELLS Loan is secured by (i) a pledge by AES New York Funding LLC (the "NY SELLS Borrower") of all of the limited liability company's membership interests and partnership interests in the subsidiaries of the NY SELLS Borrower that own or operate the Somerset, Cayuga, Westover, Greenidge, Hickling and Jennison coal-fired electric generating plants (the "NY Generating Assets") and (ii) approximately 218 million shares of common stock of the Company held in the name of the NY SELLS Borrower as of December 31, 2002.

The Company has no obligation to deliver any additional shares of the Company's common stock as collateral to secure the SELLS Loan.

The events of default with respect to the SELLS Loan includes (a) typical events of default related to the NY SELLS Borrower, and (b) the occurrence and continuance of an "Event of Default" under the Company's revolving credit agreement.

Upon the occurrence and during the continuance of an event of default, the lenders are entitled to accelerate the maturity of the NY SELLS Loan and to foreclose upon and sell the collateral. The lenders are not entitled to demand that the Company, nor is the Company obligated to, make any payment with respect to the SELLS Loan, repurchase any of the collateral or provide additional Company shares or other collateral.

The shares of Company stock that constitute collateral have not been registered under the Securities Act of 1933 and may not be sold in a foreclosure sale until so registered except in a manner exempt from the registration requirements of the Securities Act. The Company has agreed to cause the pledged Company shares to be registered by no later than November 28, 2004, or sooner if there has been a material adverse change in the business condition (financial or otherwise), operations, performance, properties or prospects of the NY SELLS Borrower or the NY Generating Assets, as the case may be.

The Company shares held in the name of the NY SELLS Borrower are not considered outstanding and therefore have been excluded from the calculation of earnings per share.

The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for (loss) income from continuing operations. In the table below, (loss) income represents the numerator (in millions) and shares represent the denominator (in millions):

There were approximately 28,207,330 and 4,048,700 and 173,000 options outstanding in 2002, 2001 and 2000 that were omitted from the earnings per share calculation because they were antidilutive. In 2002 and 2001, all Tecons and convertible debt were omitted from the earnings per share calculation because they were antidilutive. In 2000, a portion of the Tecons were omitted from the earnings per share calculation because they were antidilutive.

On April 1, 2002, the Company adopted SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." Among other items, this Statement rescinds FASB Statement No. 4, "Reporting Gains and Losses from Extinguishments of Debt." As a result, gains and losses from early extinguishments of debt in 2002, 2001 and 2000 are no longer reported as extraordinary items but have been reclassified to income from continuing operations.

INCOME TAX PROVISION—The (benefit) expense for income taxes on continuing operations consists of the following (in millions):

		Years Ended December 31,
		2002			2001			2000
Federal:
	Current	$	—		$	2		$	146
	Deferred		60			(12	)		(29	)
State:
	Current		6			—			20
	Deferred		(17	)		7			(2	)
Foreign:
	Current		118			179			204
	Deferred		(194	)		30			29

Total		$	(27	)	$	206		$	368

The Company records its share of earnings of its equity investees on a pre-tax basis. The Company's share of the investees' income taxes is recorded in income tax expense.

EFFECTIVE AND STATUTORY RATE RECONCILIATION—A reconciliation of the U.S. statutory Federal income tax rate to the Company's effective tax rate as a percentage of income before taxes (after minority interest) is as follows:

	Years Ended December 31,
	2002		2001		2000
Statutory Federal tax rate	35	%	35	%	35	%
State taxes, net of Federal tax benefit	1		1		1
Taxes on foreign earnings	(2	)	(4	)	(3	)
Valuation allowance	(32	)	—		—
Other-net	(1	)	—		(2	)

Effective tax rate	1	%	32	%	31	%

DEFERRED INCOME TAXES—Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, and (b) operating loss and tax credit carry forwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.

As of December 31, 2002, the Company had Federal net operating loss carry forwards for tax purposes of approximately $201 million expiring from 2019 through 2021, Federal general business tax credit carry forwards for tax purposes of approximately $51 million expiring in years 2005 through 2022, and Federal alternative minimum tax credits of approximately $8 million that carry forward without expiration. As of December 31, 2002, the Company had foreign net operating loss carry forwards of approximately $2.5 billion that expire at various times beginning in 2003, and some of which carry forward without expiration, and foreign investment and assets tax credits of approximately $36 million that expire at various times beginning in 2003 through 2007. The Company had state net operating loss carry forwards as of December 31, 2002, of approximately $495 million expiring in years 2003 through

2022, and state tax credit carry forwards of approximately $3 million expiring in years 2003 through 2010.

The valuation allowance increased by $759 million during 2002 to $876 million at December 31, 2002. This increase was primarily the result certain foreign net operating loss carry forwards, capital loss carry forwards and the cumulative effects of certain foreign currency translation losses. The ultimate realization of these deferred tax assets is not known at this time. The Company believes that it is more likely than not that the remaining deferred tax assets as shown below will be realized.

Undistributed earnings of certain foreign subsidiaries and affiliates aggregated approximately $1.2 billion and $1.4 billion at December 31, 2002 and 2001, respectively. The Company considers these earnings to be indefinitely reinvested outside of the United States and, accordingly, no U.S. deferred taxes have been recorded with respect to such earnings. Should the earnings be remitted as dividends, the Company may be subject to additional U.S. taxes, net of allowable foreign tax credits. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings.

Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The reduced tax rates for these operations will be in effect for the life of the related businesses, at the end of which ownership transfers back to the local government. The income tax benefits related to the tax status of these operations are estimated to be $41 million, $33 million and $29 million for the years ended December 31, 2002, 2001 and 2000, respectively.

(Loss) income from continuing operations before income taxes consisted of the following:

	Years Ended December 31,
	2002			2001		2000
U.S	$	(173	)	$	288	$	614
Non U.S		(2,444	)		364		560

Total	$	(2,617	)	$	652	$	1,174

PROFIT SHARING AND STOCK OWNERSHIP PLANS—The Company sponsors one defined contribution plan, qualified under section 401 of the Internal Revenue Code, which is available to eligible AES people. The plan provides for Company matching contributions, other Company contributions at the discretion of the Compensation Committee of the Board of Directors, and discretionary tax deferred contributions from the participants. Participants are fully vested in their own contributions and the Company's matching contributions. Participants vest in other Company contributions ratably over a five-year period ending on the 5th anniversary of their hire date. Company contributions to the plans were approximately $15 million, $13 million and $11 million for the years ended December 31, 2002, 2001 and 2000, respectively.

DEFERRED COMPENSATION PLANS—The Company sponsors a deferred compensation plan under which directors of the Company may elect to have a portion, or all, of their compensation deferred. The amounts allocated to each participant's compensation account may be converted into common stock units. Upon termination or death of a participant, the Company is required to distribute, under various methods, cash or the number of shares of common stock accumulated within the participant's deferred compensation account. Distribution of stock is to be made from common stock held in treasury or from authorized but previously unissued shares. The plan terminates and full distribution is required to be made to all participants upon any change of control of the Company (as defined in the plan document). No stock associated with distributions was issued during 2002, 2001, or 2000 under such plan.

Common stock units held under the AES deferred compensation plans do not represent issued shares of common stock. The deferred compensation liabilities related to such plans were approximately $1 million as of December 31, 2002 and 2001, and were convertible into approximately 857,000 and 795,000 shares at December 31, 2002 and 2001, respectively. For those electing to participate in the deferred compensation plans the amount of the stock unit award is based on the compensation and average stock price during the compensation period. The liabilities will only be settled in stock, except cash settlement is required in the event of certain recapitalization transactions, as defined in the plan documents.

In addition, the Company sponsors an executive officers' deferred compensation plan. At the election of an executive officer, the Company will establish an unfunded, nonqualified compensation arrangement for each officer who chooses to terminate participation in the Company's profit sharing and employee stock ownership plans. The participant may elect to forego payment of any portion of his or her compensation and have an equal amount allocated to a contribution account. In addition, the Company will credit the participant's account with an amount equal to the Company's contributions (both matching and profit sharing) that would have been made on such officer's behalf if he or she had been a participant in the profit sharing plan. The participant may elect to have all or a portion of the Company's contributions converted into stock units. Dividends paid on common stock are allocated to the participant's account in the form of stock units. The participant's account balances are distributable upon termination of employment or death.

The Company also sponsors a supplemental retirement plan covering certain highly compensated AES people. The plan provides incremental profit sharing and matching contributions to participants that would have been paid to their accounts in the Company's profit sharing plan if it were not for limitations imposed by income tax regulations. All contributions to the plan are vested in the manner provided in the Company's profit sharing plan, and once vested are nonforfeitable. The participant's account balances are distributable upon termination of employment or death.

DEFINED BENEFIT PLANS—Certain of the Company's subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Pension benefits are based on years of credited service, age of the participant and average earnings. Of the fifteen defined benefit plans, four

are at U.S. subsidiaries and the remaining are at foreign subsidiaries. These include one domestic and one foreign plan maintained at businesses classified as held for sale or discontinued operations at December 31, 2002. Prior to the consolidation of Eletropaulo in February 2002, the Company did not have significant benefit obligations from its foreign plans. Since the consolidation of Eletropaulo, the benefit obligation from foreign plans has become significant relative to the total; therefore, the 2002 amounts will distinguish between the U.S. and foreign plans.

Significant weighted average assumptions used in the calculation of pension benefits expense and obligation are as follows:

A subsidiary of the Company has a defined benefit plan, which has a benefit obligation of $411 million and $383 million at December 31, 2002 and 2001, respectively, and uses salary bands to determine future benefit costs rather than rate of compensation increases. As such, rates of compensation increase in the table above do not include amounts relating to this specific defined benefit plan.

Total pension cost for the years ended December 31, 2002, 2001 and 2000 includes the following components (in millions):

The changes in the benefit obligation of the plans combined for the years ended December 31, 2002 and 2001 are as follows (in millions):

The changes in the plan assets of the plans combined for the years ended December 31, 2002 and 2001 are as follows (in millions):

The funded status of the plans combined for the years ended as of December 31, 2002 and 2001 are as follows (in millions):

All of the Company's pension plans have been aggregated in the table above. All of the Company's plans at December 31, 2002 and 2001 had benefit obligations exceeding the fair value of the related plan's assets. The tables above include approximately $2 million, $3 million and $2 million in total pension cost for the years ended December 31, 2002, 2001 and 2000, respectively, benefit obligations of $410 million and $320 million, and fair value of assets of $299 million and $286 million related to businesses that are held for sale or discontinued as of December 31, 2002 and 2001, respectively.

From November 2000 through September 2001, a subsidiary of the Company implemented several Voluntary Early Retirement Programs ("VERP"). These programs offer enhanced retirement benefits upon early retirement to eligible employees. The VERP was available to all employees, except officers, whose combined age and years of service totaled at least 75 on June 30, 2001. Participation was limited to, and subsequently accepted by 550 qualified employees. Participants elected actual retirement dates in 2001. Additionally, the post-retirement benefits will be provided to VERP retirees until age 55 at which time they will be eligible to receive benefits from the independent Voluntary Employee Benefit Association trustee. The subsidiary recognized $0 million, $19 million and $57 million of pre-tax non-cash pension benefit costs for the VERP in 2002, 2001 and 2000, respectively.

In August 2002, a subsidiary of the Company implemented a VERP. The VERP was offered to 56 qualified plan participants. The 27 participants that accepted the offer retired effective September 1, 2002. The subsidiary recognized $3 million of pre-tax non-cash benefit costs for the VERP in 2002.

During 2000, a subsidiary of the Company curtailed one of its defined benefit plans. In connection with the curtailment, the subsidiary paid approximately $8 million and transferred approximately $145 million of plan assets to an independent trustee.

The Company operates in four business segments: contract generation, competitive supply, large utilities and growth distribution businesses. Contract generation businesses are businesses that supply wholesale electricity under long-term contracts for more than 75% of their output, and these businesses generally have little exposure to commodity price risk. Competitive supply businesses are businesses that supply wholesale electricity pursuant to short-term contracts or into spot electricity markets. Competitive supply businesses are generally exposed to commodity price risk. Large utility businesses are utilities of significant size that maintain a monopoly franchise within a defined service area, and these businesses are generally subjected to extensive regulation in their respective jurisdiction. Growth distribution businesses are distribution businesses that offer significant potential for growth because they face particular challenges related to operational difficulties such as outdated equipment, significant non-technical losses, cultural problems, emerging economies, less stable governments or regulatory regimes, or location in a developing nation that allow for operating improvements that would result in financial performance improvement that are typically greater that those seen in the large utility business. Although the nature of the product is the same, the segments are differentiated by the nature of the customers, operational differences and risk exposure. All balance sheet information for businesses that were discontinued during the year are broken out and shown separately in the chart below. All income statement related information is shown in the line "Discontinued operations" in the accompanying consolidated statements of operations.

The accounting policies of the four business segments are the same as those described in Note 1—General and Summary of Significant Accounting Policies. The Company uses gross margin to evaluate the performance of its business segments. Depreciation and amortization at the business segments are included in the calculation of gross margin. Corporate depreciation and amortization is reported within selling, general and administrative expenses in the consolidated statements of operations. Pre-tax equity in earnings is used to evaluate the performance of businesses that are significantly influenced by the

Company. Sales between the segments are accounted for at fair value as if the sales were to third parties. All intersegment activity has been eliminated with respect to revenue and gross margin.

Information about the Company's operations and assets by segment is as follows (in millions):

Revenues are recorded in the country in which they are earned and assets are recorded in the country in which they are located. Information about the Company's consolidated operations and long-lived assets by country are as follows (in millions):

The fair value of current financial assets, current financial liabilities, and debt service reserves and other deposits, are estimated to be equal to their reported carrying amounts. The fair value of non-recourse debt, excluding capital leases, is estimated differently based upon the type of loan. For variable rate loans, carrying value approximates fair value. For fixed rate loans, other than securities registered and publicly traded, the fair value is estimated using discounted cash flow analyses based on the Company's current incremental borrowing rates. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards and swaps, and energy derivatives is the estimated net amount that the Company would receive or pay to terminate the agreements as of the balance sheet date. The estimated fair values for certain of the notes and bonds included in non-recourse debt, and certain of the recourse debt and Tecons, which are registered and publicly traded, are based on quoted market prices.

The estimated fair values of the Company's assets and liabilities have been determined using available market information. The estimates are not necessarily indicative of the amounts the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

The estimated fair values of the Company's debt and derivative financial instruments as of December 31, 2002 and 2001 are as follows (in millions):

Amounts in the table above include the carrying amount and fair value of financial instruments of discontinued operations and assets held for sale, except for preferred stock with mandatory redemption of one of our discontinued operations that has a carrying amount of $22 million.

As of December 31, 2002, discontinued operations and assets held for sale had non-recourse debt with a carrying amount and fair value of $3,415 million and $4,994 million, respectively, foreign currency forwards and swaps, net (assets), with a carrying amount and fair value of $13 million, interest rate swaps (liabilities) with a carrying amount and fair value of $103 million and interest rate caps and floors, net (liabilities), with a carrying amount and fair value of $43 million.

The fair value estimates presented herein are based on pertinent information as of December 31, 2002 and 2001. The Company is not aware of any factors that would significantly affect the estimated fair value amounts since December 31, 2002.

Early extinguishments of debt. During the second quarter of 2002, the Company adopted SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." Among other items, this Statement rescinds FASB Statement No. 4, "Reporting Gains and Losses from Extinguishments of Debt." As a result, early extinguishments of debt are no longer reported as extraordinary items but are included in income from continuing operations. For the year ended December 31, 2002, the Company extinguished debt with a face value of approximately $117 million for approximately 21.6 million shares of the Company's common stock. This resulted in a gain of approximately $44 million for the year ended December 31, 2002 which is recorded in other income in the accompanying consolidated statement of operations. There were no early extinguishments of debt during 2001. In 2000, the Company recognized losses of approximately $11 million related to the early extinguishment of debts.

Stock-based compensation. In December 2002, the Financial Accounting Standards Board issued SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure." SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company expects to use the prospective method to transition to the fair value based method of accounting for stock-based employee compensation. All employee awards granted, modified, or settled after January 1, 2003, will be recorded using the fair value based method of accounting. The expanded disclosures required by SFAS No. 148 will be included in our quarterly financial reports beginning in the first quarter of 2003.

expect adoption of the liability recognition provisions of FIN 45 to have a material impact on our financial position or results of operations.

On March 21, 2003, AES reached an agreement to sell 100 percent of its ownership interest in both AES Haripur and AES Meghnaghat, both generation businesses in Bangladesh, to CDC Globeleq for approximately $127 million in cash, plus assumption of debt and subject to certain closing adjustments. The total AES book value in AES Haripur and AES Meghnaghat, including other comprehensive loss, is approximately $190 million as of February 28, 2003 which will result in an impairment loss being recorded in the first quarter of 2003. AES Haripur and AES Meghnaghat are included in the contract generation segment as of December 31, 2002 and will be reclassified as assets held for sale and discontinued operations in first quarter of 2003.

On March 25, 2003, AES announced an agreement to sell an approximately 32% ownership interest in AES Oasis Limited ("AES Oasis"). AES Oasis is a newly created company that will own two electric generation development projects and desalination plants in Oman and Qatar (AES Barka and AES Ras Laffan, respectively), the oil-fired generating facilities, AES LalPir and AES PakGen in Pakistan, as well as future power projects in the Middle East. AES expects this sale to close in the second or third quarter of 2003. Completion of the transaction is subject to certain conditions, including government and lender approvals. At the time of closing, AES will receive cash proceeds of approximately $150 million.

The following table summarizes the unaudited quarterly statements of operations for the Company for 2002 and 2001, giving effect to the acquisition of IPALCO as if it had occurred at the beginning of the earliest period presented (in millions, except per share amounts).

Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

There were no changes in or disagreements on any matters of accounting principles or financial disclosure between us and our independent auditors.

See the information with respect to the ages of the Registrant's directors in the table and the information contained under the caption "Election of Directors" on pages 5 through 7, inclusive, of the Proxy Statement for the Annual Meeting of Stock holders of the Registrant to be held on May 1, 2003, which information is incorporated herein by reference. See also the information with respect to executive officers of the Registrant under the caption entitled "Executive Officers and Significant Employees of the Registrant" in Item 1 of Part 1 hereof, which information is incorporated herein by reference.

See the information contained under the captions "Compensation of Executive Officers" and "Compensation of Directors" of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on May 1, 2003 which is incorporated herein by reference.

See the information contained under the caption "Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers" of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on May 1, 2003, which information is incorporated herein by reference.

During the fourth quarter of 2002, AES issued an aggregate of 13.6 million shares of its common stock in exchange for $63.3 million aggregate principal amount of its senior notes. The shares were issued without registration in reliance upon Section 3(a)(9) under the Securities Act of 1933.

See the information contained under the caption "Related Party Transactions" of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on May 1, 2003, which information in incorporated herein by reference.

Evaluation of Disclosure Controls and Procedures. Our chief executive officer and our chief financial officer, after evaluating the effectiveness of the Company's "disclosure controls and procedures" (as

defined in the Securities Exchange Act of 1934 Rules 13a-14c) and 15-d-14(c) as of a date (the "Evaluation Date") within 90 days before the filing date of this annual report, have concluded that as of the Evaluation Date, our disclosure controls and procedures were effective to ensure that material information relating to the Registrant and its consolidated subsidiaries is recorded, processed, summarized, and reported in a timely manner.

Changes in Internal Controls. There were no signficant changes in our internal controls or, to our knowledge, in other factors that could significantly affect such controls subsequent to the Evaluation Date.

(a) 1. Financial Statements. The following Consolidated Financial Statements of The AES Corporation are filed under "Item 8. Financial Statements and Supplementary Data."

The Company filed the following reports on Form 8-K during the quarter ended December 31, 2002. Information regarding the items reported on is as follows:

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, as amended, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.

THE AES CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

Schedule I—Condensed Financial Information of Registrant		S-2
Schedule II—Valuation and Qualifying Accounts		S-9

Schedules other than those listed above are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof.

THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF UNCONSOLIDATED BALANCE SHEETS (IN MILLIONS)

THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF UNCONSOLIDATED OPERATIONS (IN MILLIONS)

THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF UNCONSOLIDATED CASH FLOWS (IN MILLIONS)

Accounting for Subsidiaries and Affiliates—The AES Corporation (the "Company") has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated condensed financial information.

Revenues—Construction management fees earned by the parent from its consolidated subsidiaries are eliminated.

Income Taxes—The unconsolidated income tax expense or benefit computed for the Company in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, reflects the tax assets and liabilities of the Company on a stand-alone basis and the effect of filing a consolidated U.S. income tax return with certain other affiliated companies.

Accounts and Notes Receivable from Subsidiaries—Such amounts have been shown in current or long-term assets based on terms in agreements with subsidiaries, but payment is dependent upon meeting conditions precedent in the subsidiary loan agreements.

Reclassifications—Certain reclassifications have been made to conform with the 2002 presentation.

In December 2002, concurrent with entering into the senior secured credit facilities, the Company issued $258 million of 10% Senior Secured Notes due December 12th, 2005. The senior secured notes were issued in exchange for: (i) $84 million of the $300 million 8.75% Senior Notes due December 2002, and (ii) $174 million of the $200 million Remarketable or Redeemable Securities ("ROARS") due June 2003. The remaining $216 million of the $300 million 8.75% Senior Notes due December 2002 were redeemed in cash at or prior to maturity on December 15, 2002. The remaining $26 million of the ROARS remain outstanding and are scheduled to mature on June 15, 2003.

The Company will pay commitment fees (at a rate of 0.50% per annum) on the unused portion of the revolving credit facility. Such fees are payable quarterly in arrears. The Company will pay an additional fee (at a rate of 1.0%) of each lender's commitment (in the case of the lenders under the senior secured revolving credit facility or outstandings (in the case of the lenders under the tranche A, B and C term loan facilities) (in each case, after giving effect to any prepayment) under the senior secured facilities on January 31, 2004 and on January 31, 2005. The Company will also pay a letter of credit fee on the outstanding and undrawn amount of letters of credit issued under the senior secured credit facilities (at a rate of 6.5%) which shall be shared ratably by all lenders participating in the relevant letters of credit.

tranche A term loan facility plus the original aggregate commitments under the revolving credit facility) and cash collateralize the additional Drax letter of credit facility, and repay the notes in an amount such that, after giving effect to such repayment (and after giving effect to the mandatory prepayments made on or before such repayment), (i) the aggregate amount of such term loan facility is no greater than 50% of the original aggregate principal amount of such term loan facility, (ii) 50% of the maximum amount available under the letter of credit issued in respect thereof is cash collateralized or prepaid and (iii) the aggregate amount of such notes are no greater than 60% of the original principal amount of such notes.

The senior secured credit facilities are subject to mandatory prepayment on a ratable basis with the Company's 10% senior secured exchange notes due 2005:

As of March 21, 2003, approximately $276 million of proceeds from sales had been presented as mandatory prepayment in accordance with this agreement.

Future maturities of debt—Scheduled maturities of total debt at December 31, 2002 are (in millions):

Cash dividends received from consolidated subsidiaries and from affiliates accounted for by the equity method were as follows (in millions):

Delaware (State or other jurisdiction of incorporation or organization)		54 1163725 (I.R.S. Employer Identification No.)
1001 North 19th Street 20^th Floor Arlington, Virginia (Address of principal executive offices)		22209 (Zip Code)

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share		New York Stock Exchange
4.50% Junior Subordinated Debentures Due 2005 8.00% Senior Notes, Series A, Due 2008 AES Trust III, $3.375 Trust Convertible Preferred Securities		New York Stock Exchange New York Stock Exchange New York Stock Exchange

2002	High		Low		2001	High		Low
First Quarter	$	17.84	$	4.11	First Quarter	$	60.15	$	41.30
Second Quarter		9.17		3.55	Second Quarter		52.25		39.95
Third Quarter		4.61		1.56	Third Quarter		44.50		12.00
Fourth Quarter		3.57		0.95	Fourth Quarter		17.80		11.60

	Year Ended December 31,
	2002			2001			2000			1999			1998
	(in millions, except per share data)
Statement of Operations Data:
Revenues	$	8,632		$	7,645		$	6,206		$	3,772		$	3,237
(Loss) income from continuing operations		(2,590	)		446			806			365			453
Discontinued operations, net of tax		(573	)		(173	)		(11	)		(8	)		(12	)
Cumulative effect of change in accounting principle, net of tax		(346	)		—			—			—			—

Net (loss) income	$	(3,509	)	$	273		$	795		$	357		$	441
Basic (loss) earnings per share:
(Loss) income from continuing operations	$	(4.81	)	$	0.84		$	1.67		$	0.86		$	1.14
Discontinued operations		(1.05	)		(0.32	)		(0.01	)		(0.02	)		(0.03	)
Cumulative effect of change in accounting principle		(0.65	)		—			—			—			—

Basic (loss) earnings per share	$	(6.51	)	$	0.52		$	1.66		$	0.84		$	1.11

Diluted (loss) earnings per share:
(Loss) income from continuing operations	$	(4.81	)	$	0.83		$	1.61		$	0.84		$	1.10
Discontinued operations		(1.05	)		(0.32	)		(0.02	)		(0.02	)		(0.03	)
Cumulative effect of change in accounting principle		(0.65	)		—			—			—			—

Diluted (loss) earnings per share	$	(6.51	)	$	0.51		$	1.59		$	0.82		$	1.07

	December 31,
	2002			2001		2000		1999		1998
	(in millions)
Balance Sheet Data:
Total assets	$	33,776		$	36,812	$	33,038	$	23,222	$	12,900
Non-recourse debt (long-term)		10,928			11,515		9,456		6,086		4,448
Non-recourse debt (long-term)—Discontinued operations		3,243			1,034		3,407		3,435		57
Recourse debt (long-term)		5,778			4,913		3,458		2,167		1,644
Mandatorily redeemable preferred stock of subsidiary		22			22		22		22		—
Company obligated convertible mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of AES		978			978		1,228		1,318		550
Stockholders' (deficit) equity		(341	)		5,539		5,542		3,315		2,368

Generation Facilities		Dominant Fuel	Year of Acquisition or Commencement of Commercial Operations	Geographic Location	Gross MW	AES Equity Interest (percent)
	*Contract Generation*
*North America*
Kingston		Gas	1997	Canada	110	50
Beaver Valley		Coal	1987	USA	125	100
Thames		Coal	1990	USA	181	100
Shady Point		Coal	1991	USA	320	100
Hawaii		Coal	1992	USA	180	100
Southland-Alamitos		Gas	1998	USA	2,123	100
Southland-Huntington Beach		Gas	1998	USA	430	100
Southland-Redondo Beach		Gas	1998	USA	1,330	100
Warrior Run		Coal	2000	USA	180	100
Hemphill		Biomass	2001	USA	14	100
Mendota		Biomass	2001	USA	25	100
Medina Valley (1)		Gas	2001	USA	47	100
Ironwood		Gas	2001	USA	705	100
Red Oak		Gas	2002	USA	832	100
*South America*
Gener-Termoandes		Gas	2000	Argentina	643	99
Uruguaiana		Gas	2000	Brazil	600	100
Tiete (10 plants)		Hydro	1999	Brazil	2,650	53
GENER-Norgener		Oil	2000	Chile	277	99
GENER-Centrogener (9 plants)		Hydro	2000	Chile	756	99
GENER-Electrica de Santiago		Gas	2000	Chile	379	89
GENER-Energia Verde		Biomass	2000	Chile	39	99
GENER-Guacolda		Coal	2000	Chile	304	49
*Europe and Africa*
Bohemia		Coal	2001	Czech Republic	50	100
Elsta		Gas	1998	Netherlands	405	50
Ebute		Gas	2001	Nigeria	290	95
Kelvin (2)		Coal	2001	South Africa	600	95
Kilroot		Oil & Coal	1992	UK	520	97
Medway		Gas	1996	UK	688	25
Tisza II		Gas	1996	Hungary	860	100

Generation Facilities		Dominant Fuel	Year of Acquisition or Commencement of Commercial Operations	Geographic Location	Gross MW	AES Equity Interest (percent)
	*Contract Generation (continued)*
*Asia*
Khrami I		Hydro	2000	Georgia	113	0
Khrami II		Hydro	2000	Georgia	110	0
Mktvari		Gas	2000	Georgia	600	100
Xiangci-Cili		Hydro	1996	China	26	51
Wuhu		Coal	1996	China	250	25
Chengdu		Gas	1997	China	48	35
Hefei		Oil	1997	China	115	70
Jiaozuo		Coal	1997	China	250	70
Aixi-Chongqing Nanchuan		Coal	1998	China	50	70
Yangcheng		Coal	2001	China	2,100	25
OPGC		Coal	1998	India	420	49
Lal Pir (3)		Oil	1997	Pakistan	351	90
PakGen (3)		Oil	1998	Pakistan	344	90
Meghnaghat (3)		Gas	2002	Bangladesh	450	100
Barka (3)		Gas	2003	Oman	427	85
Ras Laffan (3)		Gas	2004	Qatar	750	55
Kelanitissa		Gas	2003	Sri Lanka	165	90
Mt. Stuart (1)		Oil	1999	Australia	288	100
Ecogen-Jeeralang (1)		Gas	1999	Australia	449	100
Ecogen-Yarra (1)		Gas	1999	Australia	510	100
Haripur (3)		Gas	2001	Bangladesh	360	100
*Caribbean*
Merida III		Gas	2000	Mexico	497	55
Puerto Rico		Coal	2002	USA	454	100
Itabo		Gas	2001	Dominican Republic	587	25
Los Mina		Oil	1996	Dominican Republic	210	100
Andres		Gas	2003	Dominican Republic	310	100
	*Competitive Supply*
*North America*
Deepwater		Pet Coke	1986	USA	143	100
Placerita		Gas	1989	USA	120	100
NY-Cayuga		Coal	1999	USA	306	100
NY-Greenidge		Coal	1999	USA	161	100
NY-Somerset		Coal	1999	USA	675	100
NY-Westover		Coal	1999	USA	126	100
Delano		Biomass	2001	USA	50	100
Mountainview Existing (4)		Gas	2001	USA	126	100
Whitefield		Biomass	2001	USA	14	100
Huntington Beach 3&4		Gas	2004	USA	450	100
Granite Ridge		Gas	2003	USA	720	100
Wolf Hollow		Gas	2003	USA	730	100
Lake Worth		Gas	2004	USA	205	100
Mountainview Development (4)		Gas	2003	USA	1,056	100

Generation Facilities		Dominant Fuel	Year of Acquisition or Commencement of Commercial Operations	Geographic Location	Gross MW	AES Equity Interest (percent)
	*Competitive Supply (continued)*
*South America*
San Nicolás-CTSN		Coal	1993	Argentina	650	88
Rio Juramento-Cabra Corral		Hydro	1995	Argentina	102	98
Rio Juramento-El Tunal		Hydro	1995	Argentina	10	98
San Juan-Sarmiento		Gas	1996	Argentina	33	98
San Juan-Ullum		Hydro	1996	Argentina	45	98
Quebrada de Ullum		Hydro	1998	Argentina	45	100
Alicura		Hydro	2000	Argentina	1,040	100
Central Dique		Gas	1998	Argentina	68	31
Parana		Gas	2001	Argentina	845	67
Caracoles		Hydro	2006	Argentina	123	100
*Europe and Africa*
Borsod		Coal	1996	Hungary	171	100
Tiszapalkonya		Coal	1996	Hungary	250	100
Ottana		Oil	2001	Italy	140	100
Indian Queens		Oil	1996	UK	140	100
Barry		Gas	1998	UK	230	100
Drax		Coal	1999	UK	4,065	100
Songas (2)		Gas	2003	Tanzania	112	49
*Asia*
Ekibastuz		Coal	1996	Kazakhstan	4,000	100
Altai-Shulbinsk Hydro		Hydro	1997	Kazakhstan	702	100
Altai-Sogrinsk CHP		Coal	1997	Kazakhstan	349	100
Altai-Ust Kamenogorsk Heat Nets		Coal	1998	Kazakhstan	310	0
Altai-Ust-Kamenogorsk CHP		Coal	1997	Kazakhstan	1,464	100
Altai-Ust-Kamenogorsk Hydro		Hydro	1997	Kazakhstan	331	100
*Caribbean*
Bayano		Hydro	1999	Panama	236	49
Chiriqui-La Estrella		Hydro	1999	Panama	42	49
Chiriqui-Los Valles		Hydro	1999	Panama	48	49
Panama		Oil	1999	Panama	42	49
Bayano		Hydro	2003	Panama	24	49
Esti		Hydro	2003	Panama	120	49
Chivor		Hydro	2000	Colombia	1,000	99
Colombia I		Gas	2000	Colombia	90	69
	*Large Utilities*
*North America*
CILCORP-Duck Creek (1)		Coal	1999	USA	366	100
CILCORP-Edwards (1)		Coal	1999	USA	772	100
CILCORP-Indian Trails (1)		Gas	1999	USA	19	100
IPALCO-Georgetown		Oil	2001	USA	79	100
IPALCO-Eagle Valley		Coal	2001	USA	364	100
IPALCO-Petersburg		Coal	2001	USA	1,842	100
IPALCO-Harding Street		Coal	2001	USA	1,146	100
*Caribbean*
EDC-generation (4 plants)		Gas	2000	Venezuela	2,616	87
	*Growth Distribution*
*Europe/ Africa*
SONEL		Hydro	2001	Cameroon	850	56

Distribution Facilities		Year of acquisition	Geographic Location	Approximate Number of Customers served	Approximate Gigawatt Hours	AES Equity Interest (percent)
	*Competitive Supply*
Eastern Kazakhstan REC		1999	Kazakhstan	291,000	1,455	0
Semipalatensk REC		1999	Kazakhstan	178,513	1,117	0
	*Large Utilities*
*North America*
IPALCO		2001	USA	449,550	16,256	100
CILCORP-Electricity (1)		1999	USA	193,000	6,743	100
*South America*
Eletropaulo		1998	Brazil	5,014,300	32,451	70
*Caribbean*
EDC-distribution		2000	Venezuela	1,199,805	10,726	87
	*Growth Distribution*
*South America*
Sul		1997	Brazil	975,000	7,300	98
Eden		1997	Argentina	272,122	1,708	60
Edes		1997	Argentina	140,823	573	60
Edelap		1998	Argentina	275,963	2,029	60
*Europe and Africa*
SONEL		2001	Cameroon	452,000	3,020	56
*Asia*
Telasi		1998	Georgia	370,000	2,200	75
Kievoblenergo		2001	Ukraine	763,000	3,840	75
Rivnooblenergo		2001	Ukraine	383,000	1,700	75
*Caribbean*
CLESA		1998	El Salvador	239,449	567	64
EDE Este		1999	Dominican Republic	300,000	2,996	50
CAESS		2000	El Salvador	451,772	1,697	75
DEUSEM		2000	El Salvador	47,108	75	74
EEO		2000	El Salvador	162,496	339	89

			Twelve Months Ended December 31, 2002		Twelve Months Ended December 31, 2001		% Change
			(in $millions)
Large Utilities:
	North America		$	818	$	836	(2	)%
	South America			1,685		—	NM
	Caribbean*			634		806	(21	)%

		Total Large Utilities	$	3,137	$	1,642	91	%

Growth Distribution:
	South America		$	263	$	781	(66	)%
	Caribbean*			559		635	(12	)%
	Europe/Africa			358		197	82	%

		Total Growth Distribution	$	1,180	$	1,613	(27	)%

		Total Regulated Revenues	$	4,317	$	3,255	33	%

			Twelve Months Ended December 31, 2002		Twelve Months Ended December 31, 2001		% Change
			(in millions)
Contract Generation:
	North America		$	830	$	742	12	%
	South America			738		807	(9	)%
	Caribbean*			180		204	(12	)%
	Europe/Africa			369		331	11	%
	Asia			361		333	8	%

		Total Contract Generation	$	2,478	$	2,417	3	%

Competitive Supply:
	North America		$	443	$	513	(14	)%
	South America			98		156	(37	)%
	Caribbean*			195		196	(1	)%
	Europe/Africa			1,012		1,025	(1	)%
	Asia			89		83	7	%

		Total Competitive Supply	$	1,837	$	1,973	(7	)%

		Total Non-Regulated Revenues	$	4,315	$	4,390	(2	)%

				2002			2001
				(Amounts in Millions, Except Shares and Par Value)
ASSETS
Current Assets:
	Cash and cash equivalents			$	780		$	802
	Restricted cash				181			357
	Short-term investments				211			215
	Accounts receivable – net of reserves of $424-2002; $239 -2001				1,239			1,127
	Inventory				384			468
	Receivable from affiliates				25			10
	Deferred income taxes – current				130			244
	Prepaid expenses				218			215
	Other current assets				708			382
	Current assets of discontinued operations and businesses held for sale				473			872

		Total current assets			4,349			4,692

Property, Plant and Equipment:
	Land				703			542
	Electric generation and distribution assets				19,125			16,326
	Accumulated depreciation and amortization				(4,204	)		(3,015	)
	Construction in progress				3,222			4,259

		Property, plant, and equipment — net			18,846			18,112

Other Assets:
	Deferred financing costs – net				433			368
	Project development costs				15			66
	Investments in and advances to affiliates				194			3,031
	Debt service reserves and other deposits				515			433
	Goodwill – net				1,388			2,367
	Deferred income taxes – noncurrent				968			—
	Long-term assets of discontinued operations and businesses held for sale				5,322			6,936
	Other assets				1,746			807

		Total other assets			10,581			14,008

			Total	$	33,776		$	36,812

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current Liabilities:
	Accounts payable			$	1,139		$	727
	Accrued interest				369			266
	Accrued and other liabilities				1,165			674
	Current liabilities of discontinued operations and businesses held for sale				497			812
	Recourse debt – current portion				26			488
	Non-recourse debt – current portion				3,315			1,961

		Total current liabilities			6,511			4,928

Long-Term Liabilities:
	Non-recourse debt				10,928			11,515
	Recourse debt				5,778			4,913
	Deferred income taxes				981			627
	Pension liabilities				1,273			216
	Long-term liabilities of discontinued operations and businesses held for sale				4,785			4,827
	Other long-term liabilities				2,065			1,739

		Total long-term liabilities			25,810			23,837

Minority Interest (including discontinued operations of $41 – 2002; $124 – 2001)					818			1,530
Commitments and Contingencies (Note 11)					—			—
Company-Obligated Convertible Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of AES					978			978
Stockholders' Equity (Deficit):
	Preferred stock, no par value – 50 million shares authorized; none issued				—			—
	Common stock, $.01 par value – 1,200 million shares authorized for 2002 and 2001, 776 million issued and 558 million outstanding in 2002, 645 million issued and 533 million outstanding in 2001				6			5
	Additional paid-in capital				5,312			5,225
	Retained earnings (accumulated deficit)				(700	)		2,809
	Accumulated other comprehensive loss				(4,959	)		(2,500	)

		Total stockholders' (deficit) equity			(341	)		5,539

			Total	$	33,776		$	36,812

		2002			2001			2000
		(Amounts in Millions, Except Shares and Par Value)
Revenues
Regulated		$	4,317		$	3,255		$	2,661
Non-regulated			4,315			4,390			3,545

	Total Revenues		8,632			7,645			6,206

Cost of sales
Regulated			(3,627	)		(2,416	)		(2,093	)
Non-regulated			(3,086	)		(3,052	)		(2,210	)

	Total cost of sales		(6,713	)		(5,468	)		(4,303	)

Selling, general and administrative expenses			(112	)		(120	)		(82	)
Severance and transaction costs			—			(131	)		(79	)
Interest expense			(2,031	)		(1,575	)		(1,262	)
Interest income			312			189			201
Other income			219			116			51
Other expense			(87	)		(65	)		(52	)
(Loss) gain on sale of investments and asset impairment expense			(1,600	)		18			143
Goodwill impairment expense			(612	)		—			—
Foreign currency transaction losses			(456	)		(30	)		(4	)
Equity in pre-tax (loss) earnings of affiliates			(203	)		176			475

(LOSS) INCOME BEFORE INCOME TAXES AND MINORITY INTEREST			(2,651	)		755			1,294
Income tax (benefit) expense			(27	)		206			368
Minority interest (income) expense			(34	)		103			120

(LOSS) INCOME FROM CONTINUING OPERATIONS			(2,590	)		446			806
Loss from operations of discontinued businesses (net of income tax benefit of $90, $10 and $5, respectively)			(573	)		(173	)		(11	)

(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE			(3,163	)		273			795
Cumulative effect of change in accounting principle (net of income tax benefit of $72)			(346	)		—			—

Net (loss) income		$	(3,509	)	$	273		$	795

BASIC (LOSS) EARNINGS PER SHARE:
(Loss) income from continuing operations		$	(4.81	)	$	0.84		$	1.67
Discontinued operations			(1.05	)		(0.32	)		(0.01	)
Cumulative effect of accounting change			(0.65	)		—			—

BASIC (LOSS) EARNINGS PER SHARE		$	(6.51	)	$	0.52		$	1.66

DILUTED (LOSS) EARNINGS PER SHARE:
(Loss) income from continuing operations		$	(4.81	)	$	0.83		$	1.61
Discontinued operations			(1.05	)		(0.32	)		(0.02	)
Cumulative effect of accounting change			(0.65	)		—			—

DILUTED (LOSS) EARNINGS PER SHARE		$	(6.51	)	$	0.51		$	1.59

				2002			2001			2000
				(Amounts in Millions)
OPERATING ACTIVITIES:
	Net (loss) income			$	(3,509	)	$	273		$	795
	Adjustments to net (loss) income:
		Cumulative effect of change in accounting principle			418			—			—
		Depreciation and amortization — continuing and discontinued operations			837			859			697
		Loss (gain) from sale of investments and asset impairment expense			1,600			(18	)		(143	)
		Goodwill impairment expense			612			—			—
		Loss on disposal and impairment write-down associated with discontinued operations			784			193			27
		Provision for deferred taxes			(315	)		47			(2	)
		Minority interest (earnings) expense			(34	)		103			120
		Foreign currency transaction losses			456			30			4
		Loss (earnings) of affiliates, net of dividends			285			(140	)		(320	)
		Other			16			(61	)		(56	)
	Changes in operating assets and liabilities:
		Decrease (increase) in accounts receivable			128			712			(270	)
		Decrease (increase) in inventory			129			(10	)		(56	)
		Increase in prepaid expenses and other current assets			(301	)		(34	)		(156	)
		Decrease (increase) in other assets			(160	)		295			(132	)
		(Decrease) increase in accounts payable			286			(125	)		257
		(Decrease) increase in accrued interest			98			(148	)		126
		Increase (decrease) in accrued and other liabilities			73			(368	)		(225	)
		Increase (decrease) in other liabilities			41			83			(160	)

			Net cash provided by operating activities		1,444			1,691			506

INVESTING ACTIVITIES:
	Property additions				(2,116	)		(3,173	)		(2,226	)
	Acquisitions-net of cash acquired				(35	)		(1,365	)		(1,818	)
	Increase in cash from Eletropaulo share swap				162			—			—
	Proceeds from the sales of assets				375			505			234
	Sale of short-term investments				70			670			81
	Purchase of short-term investments				(166	)		(649	)		(96	)
	Proceeds from sale of available-for-sale securities				92			59			114
	Affiliate advances and equity investments				(29	)		(133	)		(515	)
	Decrease (increase) in restricted cash				25			832			(1,110	)
	Project development costs				(22	)		(105	)		(96	)
	Debt service reserves and other assets				23			45			(101	)

			Net cash used in investing activities		(1,621	)		(3,314	)		(5,533	)

FINANCING ACTIVITIES:
	Borrowings (repayments) under the revolving credit facilities, net				158			(70	)		(195	)
	Issuance of non-recourse debt and other coupon bearing securities				3,481			5,935			7,081
	Repayments of non-recourse debt and other coupon bearing securities				(3,389	)		(4,015	)		(2,831	)
	Payments for deferred financing costs				(67	)		(153	)		(136	)
	Distributions to minority interests, net				(11	)		(70	)		(54	)
	Issuance of common stock, net				—			14			1,508
	Common stock dividends paid				—			(15	)		(55	)

			Net cash provided by financing activities		172			1,626			5,318
			Effect of exchange rate changes on cash		(81	)		(31	)		(34	)

Total (decrease) increase in cash and cash equivalents					(86	)		(28	)		257
(Increase) decrease in cash and cash equivalents of discontinued operations and businesses held for sale					64			107			(48	)
Cash and cash equivalents, beginning					802			723			514

Cash and cash equivalents, ending				$	780		$	802		$	723

SUPPLEMENTAL DISCLOSURES:
	Cash payments for interest-net of amounts capitalized			$	2,007		$	1,846		$	1,191
	Cash payments for income taxes-net of refunds				(3	)		254			216
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
	Common stock issued for acquisitions				—			511			67
	Common stock issued for debt retirement				73			—			—
	Liabilities assumed in purchase transactions				—			1,362			2,098
	Liabilities consolidated in Eletropaulo transaction				4,907			—			—
	Conversion of AES Trust I and AES Trust II (see Note 12)				—			—			550

	Common Stock						Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Loss
	Common Stock			Additional Paid-In Capital									Treasury Stock
	Shares	Amount		Additional Paid-In Capital									Treasury Stock			Comprehensive
	(Amounts in Millions)
Balance at December 31, 1999	453.4	$	4	$	3,052		$	1,811		$	(995	)	$	(557	)	$	(295	)

Net income	—		—		—			795			—			—		$	795
Foreign currency translation adjustment (net of income tax benefit of $20)	—		—		—			—			(575	)		—			(575	)
Reclassification to earnings of realized gains on marketable securities (net of income tax benefit of $65)	—		—		—			—			(107	)		—			(107	)
Minimum pension liability adjustment (net of income tax benefit of $1)	—		—		—			—			(2	)		—			(2	)

Comprehensive income																$	111

Dividends declared	—		—		—			(55	)		—			—
Issuance of common stock through public offerings and Tecon conversions	59.2		1		1,946			—			—			—
Issuance of common stock pursuant to acquisitions	1.3		—		67			—			—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants	7.8		—		50			—			—			50
Tax benefit associated with the exercise of options	—		—		57			—			—			—

Balance at December 31, 2000	521.7		5		5,172			2,551			(1,679	)		(507	)

Cumulative effect of adopting SFAS No. 133 on January 1, 2001 (net of income tax benefit of $50)	—		—		—			—			(93	)		—		$	(93	)
Net income	—		—		—			273			—			—			273
Foreign currency translation adjustment (net of reclassification to earnings of $12, net of tax, for the sale or write off of investments in foreign entities and an income tax benefit of $38)	—		—		—			—			(636	)		—			(636	)
Unrealized losses on marketable securities (no income tax effect)	—		—		—			—			(48	)		—			(48	)
Minimum pension liability adjustment (net of income tax benefit of $10)	—		—		—			—			(16	)		—			(16	)
Change in derivative fair value (including a reclassification to earnings of ($32) million, net of tax, and an income tax benefit of $11)	—		—		—			—			(28	)		—			(28	)

Comprehensive loss																$	(548	)

Dividends declared	—		—		—			(15	)		—			—
Issuance of common stock pursuant to acquisitions	9.4		—		511			—			—
Retirement of treasury stock	—		—		(507	)		—			—			507
Issuance of common stock under benefit plans and exercise of stock options and warrants	2.1		—		34			—			—			—
Tax benefit associated with the exercise of options	—		—		15			—			—			—

Balance at December 31, 2001	533.2	$	5	$	5,225		$	2,809		$	(2,500	)	$	—

	December 31, 2002		December 31, 2001
	(in millions)		(in millions)
ASSETS:
Cash	$	109	$	62
Accounts receivable, net		183		444
Inventory		115		159
PP&E		4,234		5,322
Other assets		954		1,398

Total assets	$	5,595	$	7,385

LIABILITIES:
Accounts payable	$	104	$	92
Current portion of long-term debt		170		223
Long-term debt		3,242		3,156
Other liabilities		1,706		1,871

Total liabilities	$	5,222	$	5,342

	Contract Generation			Competitive Supply			Large Utilities			Growth Distribution			Total
Carrying amount at December 31, 2001	$	1,124		$	149		$	—		$	1,094		$	2,367
Goodwill acquired during the period		—			—			780			—			780
Impairment losses from annual analysis		—			(5	)		(607	)		—			(612	)
Impairment losses from adoption of SFAS No. 142		—			(80	)		—			(681	)		(761	)
Concessions reclassed to other assets		(11	)		—			—			(152	)		(163	)
Translation adjustments and other		(7	)		(2	)		(173	)		(41	)		(223	)

Carrying amount at December 31, 2002	$	1,106		$	62		$	—		$	220		$	1,388

			December 31,
	Interest Rate (1)	Final Maturity	December 31,
	Interest Rate (1)	Final Maturity	2002			2001
VARIABLE RATE:
Bank loans	7.75%	2022	$	7,258		$	5,760
Commercial paper	5.72%	2008		406			501
Notes and Bonds	8.82%	2030		856			889
Debt to (or guaranteed by) multilateral or export credit agencies	5.16%	2024		934			945
Other	13.14%	2022		455			602
FIXED RATE:
Bank loans	9.43%	2014		982			1,892
Commercial Paper	11.93%	2005		146			63
Notes and bonds	8.82%	2029		5,995			5,922
Debt to (or guaranteed by) multilateral or export credit agencies	4.89%	2016		347			165
Other	1.72%	2027		279			118

SUBTOTAL				17,658			16,857

Less: Non-recourse debt of discontinued operations				(3,415	)		(3,381	)

SUBTOTAL				14,243			13,476
Less: Current maturities				(3,315	)		(1,961	)

TOTAL			$	10,928		$	11,515

	Interest Rate (1)	Final Maturity	First Call Date (2)	2002			2001
Corporate revolving bank loan	—	2002	2000	$	—		$	70
Corporate revolving bank loan	8.10%	2005	—		228			—
Term loan	—	2002	—		—			425
Term loan	—	2002	—		—			188
Term loan	8.12%	2005	—		500			—
Term loan	7.99%	2005	—		427			—
Term loan	7.94%	2005	—		260			—
Senior notes	—	2002	—		—			300
Senior notes	8.00%	2008	2000		199			200
Senior notes	9.50%	2009	—		750			750
Senior notes	9.38%	2010	—		850			850
Senior notes	8.88%	2011	—		537			600
Senior notes	8.38%	2011	—		217			196
Senior notes	8.75%	2008	—		400			400
Senior notes	10.00%	2005	—		258			—
Remarketable or Redeemable Securities	7.38%	2013	2003		26			200
Senior subordinated notes	10.25%	2006	2001		231			250
Senior subordinated notes	8.38%	2007	2002		316			325
Senior subordinated notes	8.50%	2007	2002		349			375
Senior subordinated debentures	8.88%	2027	2004		125			125
Convertible junior subordinated debentures	4.50%	2005	2001		150			150
Unamortized discounts					(19	)		(3	)

SUBTOTAL					5,804			5,401
Less: Current maturities					(26	)		(488	)

Total				$	5,778		$	4,913

Contingent contractual obligations	Amount		Number of Agreements	Term Range (years)	Maximum Exposure Range for Each Agreement	Credit Enhancements for Non-Recourse Debt		Performance Related Obligations
	(amounts in $millions, except agreements and years)
Guarantees	$	652	52	<1 – 20+	<$1 – $100	$	273	$	379
Letters of credit — under the Revolver.		104	14	<1 – 2	<$1 – $36		51		53
Letters of credit — outside the Revolver		109	5	<1 – 2	<$1 – $84		84		25
Surety bonds		6	6	<1	<$1 – $3		—		6

Total	$	871	77			$	408	$	463

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Total Outstanding	Weighted- Average Remaining Life (In Years)	Weighted- Average Exercise Price		Total Exercisable	Weighted- Average Exercise Price
$0.78 – $3.24	1,048	9.6	$	2.15	—	$	—
$3.25 – $9.88	4,787	2.5		5.39	4,707		5.34
$9.89 – $14.40	19,828	8.4		13.03	19,775		13.04
$14.41 – $22.85	2,924	5.7		17.85	2,884		17.89
$22.86 – $58.00	4,648	7.4		44.11	3,683		41.85
$58.01 – $80.00	9	7.7		61.42	8		61.19

Total	33,244	7.2	$	16.37	31,057	$	15.75

	December 31, 2002							December 31, 2001						December 31, 2000
	Income			Shares	$ per Share			Income		Shares	$ per Share			Income		Shares	$ per Share
BASIC (LOSS) EARNINGS PER SHARE:
(Loss) income from continuing operations	$	(2,590	)	538.9	$	(4.81	)	$	446	532.2	$	0.84		$	806	482.1	$	1.67
EFFECT OF DILUTIVE SECURITIES:
Stock options and warrants		—		—		—			—	5.3		(0.01	)		—	9.9		(0.03	)
Stock units allocated to deferred compensation plans		—		—		—			—	0.6		—			—	0.5		—
Tecons and other convertible debt, net of tax		—		—		—			—	—		—			19	21.1		(0.03	)

DILUTED (LOSS) EARNINGS PER SHARE	$	(2,590	)	538.9	$	(4.81	)	$	446	538.1	$	0.83		$	825	513.6	$	1.61

	December 31,
	2002			2001
Differences between book and tax basis of property	$	1,196		$	1,274
Other taxable temporary differences		121			109

Total deferred tax liability	$	1,317		$	1,383

Operating loss carry forwards		(787	)		(469	)
Capital loss carry forwards		(348	)		—
Bad debt and other book provisions		(153	)		(109	)
Retirement costs		(389	)		(66	)
Tax credit carry forwards		(91	)		(135	)
Other deductible temporary differences		(542	)		(338	)

Total gross deferred tax asset		(2,310	)		(1,117	)
Less: valuation allowance		876			117

Total net deferred tax asset		(1,434	)		(1,000	)

Net deferred tax (asset)/liability	$	(117	)	$	383

	2002						2001
	U.S.			Foreign
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation at beginning of year	$	727		$	182		$	827
Effect of foreign currency exchange rate change on beginning balance		—			(56	)		(25	)
Service cost		7			7			9
Interest cost		50			136			61
Plan acquired		—			1,526			4
VERP benefits		3			—			19
Benefits paid		(53	)		(121	)		(61	)
Actuarial loss		49			222			86
Other		8			6			(11	)

Benefit obligation as of December 31	$	791		$	1,902		$	909

	2002						2001
	U.S.			Foreign
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year	$	549		$	55		$	685
Fair value of plan acquired		—			698			—
Effect of foreign currency exchange rate change on beginning balance		—			(2	)		(6	)
Actual return on plan assets		(40	)		52			(32	)
Benefits paid		(53	)		(121	)		(58	)
Employer Contributions		19			147			29
Other		(1	)		1			(14	)

Fair value of plan assets as of December 31	$	474		$	830		$	604

	2002						2001
	U.S.			Foreign
Funded status	$	(317	)	$	(1,072	)	$	(305	)
Unrecognized net actuarial loss		221			613			92
Other		—			(7	)		2

Accrued benefit cost as of December 31	$	(96	)	$	(466	)	$	(211	)

	2002						2001
	U.S.			Foreign
Accrued benefit liability	$	(273	)	$	(1,089	)	$	(237	)
Accumulated other comprehensive loss		177			623			26

Net amount recognized	$	(96	)	$	(466	)	$	(211	)

		Revenues(1)		Depreciation and Amortization		Gross Margin(2)		Pre-Tax Equity in (Loss) Earnings(3)			Total Assets		Investment in and Advances to Affiliates			Property Additions
Year Ended December 31, 2002
Contract Generation		$	2,478	$	232	$	1,050	$	75		$	12,640	$	671		$	1,009
Competitive Supply			1,837		181		179		(3	)		7,294		7			470
Large Utilities			3,137		286		685		(275	)		7,967		(484	)		300
Growth Distribution			1,180		96		5		—			3,040		(20	)		102
Discontinued Businesses			—		—		—		—			2,432		—			234
Corporate			—		2		—		—			403		20			1

	Total	$	8,632	$	797	$	1,919	$	(203	)	$	33,776	$	194		$	2,116

		Revenues(1)		Depreciation and Amortization		Gross Margin(2)		Pre-Tax Equity in (Loss) Earnings(3)			Total Assets		Investment in and Advances to Affiliates		Property Additions
Year Ended December 31, 2001
Contract Generation		$	2,417	$	255	$	854	$	54		$	11,995	$	660	$	941
Competitive Supply			1,973		184		484		(9	)		8,846		46		1,334
Large Utilities			1,642		203		618		144			7,444		2,292		378
Growth Distribution			1,613		111		221		(13	)		4,316		12		89
Discontinued Businesses			—		—		—		—			3,869		—		428
Corporate			—		3		—		—			342		21		3

	Total	$	7,645	$	756	$	2,177	$	176		$	36,812	$	3,031	$	3,173

	December 31, 2002				December 31, 2001
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets:
Foreign currency forwards and swaps, net	$	17	$	17	$	14	$	14
Energy derivatives, net		201		201		7		7
Liabilities:
Non-recourse debt		17,658		20,447		16,857		17,064
Recourse debt		5,804		3,895		5,401		4,730
Tecons		978		284		978		626
Interest rate swaps		557		557		166		166
Interest rate caps and floors, net		115		115		72		72

	Quarter Ended 2002 (As restated (2))
	Mar 31			Jun 30			Sep 30			Dec 31
Revenues	$	2,228		$	2,080		$	2,110		$	2,214
Gross margin		681			437			587			214
Income (loss) from continuing operations		178			(101	)		(214	)		(2,453	)
Discontinued operations		(19	)		(141	)		(100	)		(313	)
Cumulative effect of change in accounting principle		(473	)		127			—			—
Net loss		(314	)		(115	)		(314	)		(2,766	)
Basic loss per share: (1,2)
Income (loss) from continuing operations	$	0.33		$	(0.19	)	$	(0.40	)	$	(4.50	)
Discontinued operations		(0.03	)		(0.26	)		(0.18	)		(0.58	)
Cumulative effect of accounting change		(0.88	)		0.23			—			—

Basic loss per share	$	(0.58	)	$	(0.22	)	$	(0.58	)	$	(5.08	)

Diluted loss per share: (1,2)
Income (loss) from continuing operations	$	0.33		$	(0.19	)	$	(0.40	)	$	(4.50	)
Discontinued operations		(0.03	)		(0.26	)		(0.18	)		(0.58	)
Cumulative effect of accounting change		(0.88	)		0.23			—			—

Diluted loss per share	$	(0.58	)	$	(0.22	)	$	(0.58	)	$	(5.08	)

Date		Item Reported On
October 3, 2002		Item 5 – press release regarding the Company's exchange offer for its notes maturing in 2002 and 2003 and its remarketable or redeemable securities due 2013 (puttable in 2013)
October 24, 2002		Item 5 – Electropaulo update and announcement of Company's third quarter earnings release
October 28, 2002		Item 5 – press release reporting the Company's extension of the early tender date for the exchange offer
October 31, 2002		Item 5 – press release reporting the Company's extension of the early tender date for the exchange offer
November 4, 2002		Item 5 – press release reporting the Company's waiver of the early tender deadline
November 12, 2002		Item 5 – press release reporting that the Company extended the expiration date of the exchange offer and changed certain terms of the exchange offer

November 13, 2002		Item 5 – the Company filed certain financial data for the five years ending December 31, 2001 and certain sections of its Management Discussion Analysis in order to report the impact of the Company's classification of certain businesses as discontinued operations pursuant to SFAS No. 144 (financial statements were filed)
November 20, 2002		Item 5 – press release reporting the Company's waiver of the early tender deadline for its exchange offer
November 20, 2002		Item 5 – Form 6-Ks filed by its subsidiaries AES Drax Holdings Limited and AES Drax Energy dated November 19, 2002 announcing certain recent developments
November 27, 2002		Item 5 – press release reporting the status of the Company's exchange offer
December 4, 2002		Item 5 – press release reporting the Company's extension of the expiration date of the exchange offer
December 9, 2002		Item 5 – press release reporting the Company's extension of the expiration date of the exchange offer
December 10, 2002		Item 5 – press release reporting the Company had reached the minimum condition for its exchange offer
December 12, 2002		Item 5 – press release reporting that the Company's subsidiary, Eletropaulo Metropolitana Electricidade de Sao Paulo S.A., announced that it had extended its pending offer to exchange any of three combinations of cash and new notes for approximately $100 million of its outstanding commercial paper that was due and unpaid on December 9, 2002
December 12, 2002		Item 5 – press release reporting the Company's extension of the expiration date of the exchange offer
December 13, 2002		Item 5 – press release reporting that the Company had successfully completed its $2.1 billion bank and bond refinancing comprised of a $1.6 billion senior secured credit facility and its exchange offer relating to $500 million of its outstanding debt securities
December 17, 2002		Item 5 and Item 7 – to file certain agreements the Company executed as part of its bank refinancing and bond exchange and file the Form 6-K of the Company's subsidiary AES Drax Holdings Limited
December 20, 2002		Item 4 – notification of change of independent accountant for the Company's subsidiaries, C.A. La Electricidad de Caracas and Corporación EDC and its subsidiaries, from Porta Cachiafeiro Laria y Asociados (a former member firm of Arthur Andersen LLP) to Lara, Marambio y Asociados (a member firm of Deloitte Touche Tohmatsu)

3.1		Sixth Restated Certificate of Incorporation of The AES Corporation.
3.2		By-Laws of The AES Corporation, as amended.
4.1		There are numerous instruments defining the rights of holders of long-term indebtedness of the Registrant and its consolidated subsidiaries, none of which exceeds ten percent of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any of such agreements to the Commission upon request.
4.2		Senior Indenture, dated December 31, 2002, between The AES Corporation and Wells Fargo Bank Minnesota, National Association, as Trustee is herein incorporated by reference to Exhibit 4.1 of the Form 8-K filed on December 17, 2002.
4.3		Collateral Trust Agreement dated as of December 12, 2002 among The AES Corporation, AES International Holdings II, Ltd., Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, an individual trustee is herein incorporated by reference to Exhibit 4.2 of the Form 8-K filed on December 17, 2002.
4.4		Security Agreement dated as of December 12, 2002 made by The AES Corporation to Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, as individual trustee is herein incorporated by reference to Exhibit 4.3 of the Form 8-K filed on December 17, 2002.
4.5		Charge Over Shares dated as of December 12, 2002 between AES International Holdings II, Ltd. and Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, as individual trustee is herein incorporated by reference to Exhibit 4.4 of the Form 8-K filed on December 17, 2002.
10.1		Amended Power Sales Agreement, dated as of December 10, 1985, between Oklahoma Gas and Electric Company and AES Shady Point, Inc. is incorporated herein by reference to Exhibit 10.5 to the Registration Statement on Form S-1 (Registration No. 33-40483).
10.2		First Amendment to the Amended Power Sales Agreement, dated as of December 19, 1985, between Oklahoma Gas and Electric Company and AES Shady Point, Inc. is incorporated herein by reference to Exhibit 10.45 to the Registration Statement on Form S-1 (Registration No. 33-46011).
10.3		The AES Corporation Profit Sharing and Stock Ownership Plan is incorporated herein by reference to Exhibit 4(c)(1) to the Registration Statement on Form S-8 (Registration No. 33-49262).
10.4		The AES Corporation Incentive Stock Option Plan of 1991, as amended, is incorporated herein by reference to Exhibit 10.30 to the Annual Report on Form 10-K of the Registrant for the fiscal year ended December 31, 1995.
10.5		Applied Energy Services, Inc. Incentive Stock Option Plan of 1982 is incorporated herein by reference to Exhibit 10.31 to the Registration Statement on Form S-1 (Registration No. 33-40483).
10.6		Deferred Compensation Plan for Executive Officers, as amended, is incorporated herein by reference to Exhibit 10.32 to Amendment No. 1 to the Registration Statement on Form S-1 (Registration No. 33-40483).
10.7		Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q of the Registrant for the quarter ended March 31, 1998, filed May 15, 1998.

10.8		The AES Corporation Stock Option Plan for Outside Directors as amended is incorporated herein by reference to the Registrant's 2003 Proxy Statement.
10.9		The AES Corporation Supplemental Retirement Plan is incorporated herein by reference to Exhibit 10.64 to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 1994.
10.10		The AES Corporation 2001 Stock Option Plan is incorporated herein by reference to Exhibit 10.12 to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 2000.
10.11		Second Amended and Restated Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.13 to the Annual Report of Form 10-K on the Registrant for the year ended December 31, 2000.
10.12		The AES Corporation 2001 Non-Officer Stock Option Plan.
10.13		The AES Corporation 2003 Long Term Compensation Plan is incorporated herein by reference to the Registrant's 2003 Proxy Statement.
10.14		The AES Corporation Employment Agreement with Paul T. Hanrahan.
10.15		The AES Corporation Employment Agreement with Barry J. Sharp.
10.16		The AES Corporation Employment Agreement with John R. Ruggirello.
10.17		The AES Corporation Employment Agreement with William R. Luraschi.
12		Statement of computation of ratio of earnings to fixed charges.
21.1		Subsidiaries of The AES Corporation.
23.1		Independent Auditors' Consent, Deloitte & Touche LLP.
23.2		Notice Regarding Consent of Arthur Andersen LLP.
24		Power of Attorney.
99.1		Certifications of Paul T. Hanrahan and Barry J. Sharp.
99.2		Amended and Restated Credit, Reimbursement and Exchange Agreement dated as of December 12, 2002 among The AES Corporation, the Subsidiary Guarantors party thereto, the Banks party thereto, the Revolving Fronting Banks and the Drax LOC Fronting Bank party thereto and Citicorp USA, Inc., as Administrative Agent and as Collateral Agent for the Bank Parties is herein incorporated by reference to Exhibit 99.2 of the Form 8-K filed on December 17, 2002.
99.3		Second Amended and Restated Pledge Agreement dated as of December 12, 2002 between AES EDC Funding II, L.L.C. and Citicorp USA, Inc., as Collateral Agent is herein incorporated by reference to Exhibit 99.3 of the Form 8-K filed on December 17, 2002.