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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-K

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COMMISSION FILE NUMBER 1-12291

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The AES Corporation
(Exact name of registrant as specified in its charter)

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

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

Securities registered pursuant to Section 12(g) of the Act:
None

         Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o

         Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes o    No ý

         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. ý

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

         Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

         The aggregate market value of the voting and non-voting common equity held by non-affiliates on June 30, 2008, the last business day of the Registrant's most recently completed second fiscal quarter (based on the closing sale price of $19.21 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $12.920 billion.

         The number of shares outstanding of the Registrant's Common Stock, par value $0.01 per share, on February 24, 2009, was 666,216,009.

DOCUMENTS INCORPORATED BY REFERENCE

         (a)    Portions of the 2009 Proxy Statement are incorporated by reference in Part III

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THE AES CORPORATION

FISCAL YEAR 2008 FORM 10-K

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PART I

        In this Annual Report the terms "AES", "the Company", "us", or "we" refer to The AES Corporation and all of its subsidiaries and affiliates, collectively. The term "The AES Corporation" refers only to the parent, publicly-held holding company, The AES Corporation, excluding its subsidiaries and affiliates.

FORWARD-LOOKING INFORMATION

        In this filing we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot assure you that they will prove to be correct.

        Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:

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the economic climate, particularly the state of the economy in the areas in which we operate, including the fact that the global economy has recently been in decline and faces considerable uncertainty for the foreseeable future which further increases many of the risks discussed in this Form 10-K;



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our ability to achieve expected rate increases in our Utility businesses;



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our ability to manage our operation and maintenance costs;



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the performance and reliability of our generating plants, including our ability to reduce unscheduled down-times;



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changes in the price of electricity at which our Generation businesses sell into the wholesale market and our Utility businesses purchase to distribute to their customers, and our ability to hedge our exposure to such market price risk;



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changes in the prices and availability of coal, gas and other fuels and our ability to hedge our exposure to such market price risk, and our ability to meet credit support requirements for fuel and power supply contracts;



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changes in and access to the financial markets, particularly those affecting the availability and cost of capital in order to refinance existing debt and finance capital expenditures, acquisitions, investments and other corporate purposes;



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changes in our or any of our subsidiaries' corporate credit ratings or the ratings of our or any of our subsidiaries' debt securities or preferred stock, and changes in the rating agencies' ratings criteria;



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changes in inflation, interest rates and foreign currency exchange rates;



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our ability to purchase and sell assets at attractive prices and on other attractive terms;



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our ability to locate and acquire attractive "greenfield" projects and our ability to finance, construct and begin operating our "greenfield" projects on schedule and within budget;



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the expropriation or nationalization of our businesses or assets by foreign governments, whether with or without adequate compensation;

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changes in laws, rules and regulations affecting our business, including, but not limited to, deregulation of wholesale power markets and its effects on competition, the ability to recover net utility assets and other potential stranded costs by our utilities, the establishment of a regional transmission organization ("RTO") that includes our utility service territory, the application of market power criteria by the Federal Energy Regulatory Commission ("FERC"), changes in law resulting from new federal energy legislation, including the effects of the repeal of Public Utility Holding Company Act of 1935 ("PUHCA 1935"), and changes in political or regulatory oversight or incentives affecting our wind business, our solar joint venture, our other renewables projects and our initiatives in greenhouse gas ("GHG") reductions and energy storage including tax incentives;



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changes in environmental, tax and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, mercury, and other substances;



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the economic climate, particularly the state of the economy in the areas in which we operate, including the fact that the global economy has recently been in decline and faces considerable uncertainty for the foreseeable future;



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variations in weather, especially mild winters and cooler summers in the areas in which we operate, and the occurrence of difficult hydrological conditions, hurricanes and other storms and disasters;



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our ability to meet our expectations in the development, construction, operation and performance of our wind businesses, which rely, in part, on actual wind volumes in areas affecting our existing and planned wind farms performing consistently with our expectations, and actual wind turbine performance operating consistently with our expectations;



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the success of our initiatives in other renewable energy projects, as well as climate solutions and energy storage projects, and the attractiveness of market prices for carbon offsets under markets governed by the Kyoto Protocol of the United Nations Framework Convention on Climate Change ("the Kyoto Protocol"), and consistent and orderly regulatory procedures governing the application, regulation, issuance of Certified Emission Reduction ("CER") credits and the extension of such regulations beyond 2012;



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our ability to keep up with advances in technology;



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the potential effects of threatened or actual acts of terrorism and war;



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changes in tax laws and the effects of our strategies to reduce tax payments;



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the effects of litigation and government investigations;



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decreases in the value of pension plan assets, increases in pension plan expenses and our ability to fund defined benefit pension and other post-retirement plans at our subsidiaries;



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changes in accounting standards, corporate governance and securities law requirements;



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our ability to remediate and compensate for the material weaknesses in our internal controls over financial reporting; and



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our ability to attract and retain talented directors, management and other personnel, including, but not limited to, financial personnel in our foreign businesses that have extensive knowledge of accounting principles generally accepted in the United States ("GAAP").

        These factors in addition to others described elsewhere in this Form 10-K and in subsequent securities filings, should not be construed as a comprehensive listing of factors that could cause results to vary from our forward looking information.

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        Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

ITEM 1.    BUSINESS

Overview

        We are a global power company. We own a portfolio of electricity generation and distribution businesses on five continents in 29 countries, with generation capacity totaling approximately 43,000 Megawatts ("MW") and distribution networks serving over 11 million people as of December 31, 2008. In addition, we have more than 3,000 MW under construction in ten countries. Our global workforce of 25,000 people provides electricity to people in diverse markets ranging from urban centers in the United States to remote villages in India. We were incorporated in Delaware in 1981 and for almost three decades we have been committed to providing safe and reliable energy.

        We own and operate two primary types of businesses. The first is our Generation business, where we own and/or operate power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. The second is our Utilities business, where we own and/or operate utilities to distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors in a defined service area.

        Our assets are diverse with respect to fuel source and type of market, which helps reduce certain types of operating risk. Our portfolio employs a broad range of fuels, including coal, gas, fuel oil, biomass and renewable sources such as hydroelectric power, wind and solar, which reduces the risks associated with dependence on any one fuel source. Our presence in mature markets helps reduce the volatility associated with our businesses in faster-growing emerging markets. In addition, our Generation portfolio is largely contracted, which reduces the risk related to the market prices of electricity and fuel. We also attempt to limit risk by hedging much of our currency and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the business that issued that debt. However, our business is still subject to these and other risks, which are further disclosed in Item 1A. Risk Factors of this Form 10-K.

        Our goal is to maximize value for our shareholders through continued focus on increasing the profitability of our existing portfolio and increasing free cash flow while managing our risk and employing rigorous capital allocation. We will continue to seek prudent expansion of our traditional Generation and Utilities lines of business, along with new investments in wind, solar, climate solutions and energy storage. Portfolio management has become an increased area of focus through which we have sold and will continue to sell or monetize a portion of certain businesses or assets when market values appear attractive. Furthermore, we will continue to focus on improving our business operations and management processes, including our internal controls over financial reporting.

Key Lines of Business

        AES's primary sources of revenue and gross margin today are from Generation and Utilities. These businesses are distinguished by the nature of the customers, operational differences, cost structure, regulatory environment and risk exposure. The breakout of revenue and gross margin

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between Generation and Utilities for the years ended December 31, 2008, 2007 and 2006, respectively is shown below.

Revenue
($ in billions)

Gross Margin
($ in billions)

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⁽¹⁾

Utilities gross margin includes the margin from generation businesses owned by the Company and from whom the utility purchases energy.

Generation

        We currently own or operate a portfolio of approximately 38,000 MW, consisting of 93 Generation facilities in 26 countries on five continents at our generation businesses. We also have approximately 2,900 MW of capacity currently under construction in six countries. We are a major power source in

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many countries, such as Panama where we are the largest generator of electricity, and Chile, where AES Gener ("Gener") is the second largest electricity generation company in terms of capacity. Our Generation business uses a wide range of technologies and fuel types including coal, combined-cycle gas turbines, hydroelectric power and biomass. Generation revenues were $8.3 billion, $6.6 billion and $5.4 billion for the years ended December 31, 2008, 2007 and 2006, respectively.

        Performance drivers for our Generation businesses include, among other factors, plant reliability, fuel costs and fixed-cost management. Growth in the Generation business is largely tied to securing new power purchase agreements ("PPAs"), expanding capacity in our existing facilities and building new power plants.

        The majority of the electricity produced by our Generation businesses is sold under long-term contracts, or PPAs, to wholesale customers. In 2008, approximately 61% of the revenues from our Generation business was from plants that operate under PPAs of five years or longer for 75% or more of their output capacity. These businesses often reduce their exposure to fuel supply risks by entering into long-term fuel supply contracts or fuel tolling contracts where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. These long-term contractual agreements result in relatively predictable cash flow and earnings and reduce exposure to volatility in the market price for electricity and fuel; however, the amount of earnings and cash flow predictability varies from business to business based on the degree to which its exposure is limited by the contracts it has negotiated.

        Our Generation businesses with long-term contracts face most of their competition from other utilities and independent power producers ("IPPs") prior to the execution of a power sales agreement during the development phase of a project or upon expiration of an existing agreement. Once a project is operational, we traditionally have faced limited competition due to the long-term nature of the generation contracts. However, as our existing contracts expire, the introduction of new competitive power markets has increased competition to attract new customers and maintain our current customer base.

        The balance of our Generation business sells power through competitive markets under short-term contracts or directly in the spot market. As a result, the cash flows and earnings associated with these businesses are more sensitive to fluctuations in the market price for electricity, natural gas, coal and other fuels. However, for a number of these facilities, including our plants in New York, which include a fleet of coal fired plants, we have hedged the majority of our exposure to fuel, energy and emissions pricing for 2009. Competitive factors for these facilities include price, reliability, operational cost and third party credit requirements.

Utilities

        AES utility businesses distribute power to over 11 million people in seven countries on five continents and consists primarily of 14 companies owned or operated under management agreements, each of which operate in defined service areas. These businesses also include 15 generation plants in two countries totaling approximately 4,400 MW. In addition, we have one generation plant under construction totaling 86 MW. These businesses have a variety of structures ranging from pure distribution businesses to fully integrated utilities, which generate, transmit and distribute power. Indianapolis Power & Light ("IPL"), has the exclusive right to provide retail services to approximately 470,000 customers in Indianapolis, Indiana. Eletropaulo Metropolitana Electricidad de São Paulo S.A ("AES Eletropaulo" or "Eletropaulo"), serving the São Paulo metropolitan region for over 100 years, has approximately six million customers and is the largest electricity distribution company in Brazil in terms of revenues and electricity distributed. In Cameroon, we are the primary generator and distributor of electricity and in El Salvador we provide distribution services to serve more than 80% of the country's electricity customers. Utilities revenues were $7.8 billion, $6.9 billion and $6.2 billion for the years ended December 31, 2008, 2007 and 2006, respectively.

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        Performance drivers for Utilities include, but are not limited to, reliability of service; management of working capital; negotiation of tariff adjustments; compliance with extensive regulatory requirements; and in developing countries, reduction of commercial and technical losses. The results of operations of our Utilities businesses are sensitive to changes in economic growth and regulation and abnormal weather conditions in the area in which they operate.

        Utilities face relatively little direct competition due to significant barriers to entry which are present in these markets. Where we do face competition is in our efforts to acquire existing businesses and develop new ones. In this arena, we compete against a number of other market participants, some of which have greater financial resources, have been engaged in distribution related businesses for longer periods of time and/or have accumulated more significant portfolios. Relevant competitive factors for our power distribution businesses include financial resources, governmental assistance, regulatory restrictions and access to non-recourse financing. In certain locations, our distribution businesses face increased competition as a result of changes in laws and regulations which allow wholesale and retail services to be provided on a competitive basis.

Wind, Solar and Other Initiatives

        In recent years, as demand for renewable sources of energy has grown, we have placed increasing emphasis on developing projects in wind, solar and the creation of greenhouse gas emission offset credits ("GHG credits"). We have also developed projects and/or made investments in climate solutions and energy storage. In 2005, we started a wind generation business ("AES Wind Generation"), which currently has 16 plants in operation in three countries totaling over 1,200 MW and is one of the largest producers of wind power in the U.S. In addition, over 400 MW are under construction in four countries outside the U.S. In March 2008, we formed AES Solar Energy LLC ("AES Solar"), a joint venture with Riverstone Holdings, LLC ("Riverstone"), a private equity firm, which has since commenced commercial operations of 8 plants totaling 24 MW of solar projects in Spain and has development potential in three other countries. In the area of climate solutions, we are developing and implementing projects to produce GHG credits and are currently developing projects in Asia, Europe and Latin America. In the U.S., we formed Greenhouse Gas Services, LLC as a joint venture with GE Energy Financial Services to create high quality verifiable emissions offsets for the voluntary U.S. market. We also formed a line of business to develop and implement utility scale energy storage systems (such as batteries), which store and release power when needed. While none of these initiatives are currently material to our operations, we believe that in the future, they may become a material contributor to our revenue and gross margin. However, there are risks associated with these initiatives, which are further disclosed in Item 1A—Risk Factors of this Form 10-K. As further described in "Our Organization and Segments" below, some of these projects will be managed within the region where they are located, while others are managed as business units.

Risks

        We routinely encounter and address risks, some of which may cause our future results to be different, sometimes materially different, than we presently anticipate. The categories of risk we have identified in Item 1A—Risk Factors of this Form 10-K include the following:

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Risks associated with our operations in areas with extensive current and future governmental and environmental regulation;



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Risks associated with our exposure to material litigation and regulatory proceedings;



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Risks associated with our disclosure controls and internal controls over financial reporting;



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Risks associated with our high levels of debt;



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Risks associated with the operation of power plants;

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Risks associated with revenue and earnings volatility; and



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Risks associated with our ability to raise needed capital.

        The categories of risk identified above are discussed and explained in greater detail in Item 1A—Risk Factors of this Form 10-K. These risk factors should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A"), and the Consolidated Financial Statements and related notes included elsewhere in this report.

Our Organization and Segments

        We believe our broad geographic footprint allows us to focus development in targeted markets with opportunities for new investment, and provides stability through our presence in more developed regions. In addition, our presence in each region affords us important relationships and helps us identify local markets with attractive opportunities for new investment. As a result, we have structured our organization into geographic regions, and each region is led by a regional president responsible for managing existing businesses. The regional presidents report to our Chief Operating Officer ("COO"), who in turn reports to our Chief Executive Officer ("CEO"). Both our CEO and COO are based in Arlington, Virginia.

        Through the end of 2008, we organized our operations along our two primary lines of business (Generation and Utilities) within four geographic regions: Latin America; North America; Europe & Africa; and Asia & the Middle East ("Asia"). Three regions, North America, Latin America and Europe & Africa, engaged in both Generation and Utility businesses. Our Asia region only had Generation. Accordingly, these businesses and regions accounted for seven segments:

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Latin America Generation;



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Latin America Utilities;



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North America Generation;



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North America Utilities;



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Europe & Africa Generation;



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Europe & Africa Utilities; and



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Asia Generation.

        In 2008, AES Wind Generation, climate solutions, and certain other initiatives were managed by our alternative energy group. The associated revenue, development costs and operational costs were reported under "Corporate and Other" since the results were not material to the presentation of our operating segments. "Corporate and Other" also included corporate overhead costs which are not directly associated with the operations of our seven primary operating segments; interest income and expense; other intercompany charges such as management fees and self-insurance premiums which are fully eliminated in consolidation.

        In early 2009, the Company began to implement certain organizational changes in an effort to streamline the organization. The new structure will continue to be organized along our two lines of business, but within three regions instead of four: (1) North America, (2) Latin America & Africa and (3) Europe, Middle East & Asia ("EMEA"). In addition, we will no longer have a separate alternative energy group. Instead, AES Wind Generation will be managed as part of our North America region while climate solutions projects will be managed in the region in which they are located. Management is currently evaluating the impact of the reorganization on the Company's externally reported segments in accordance with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information ("SFAS No. 131"). AES Solar is accounted for using the equity method and will continue to be reflected in Corporate and Other in 2009.

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Latin America

        Our Latin America operations accounted for 65%, 64% and 62% of consolidated AES revenues in 2008, 2007, and 2006, respectively. The following table provides highlights of our Latin America operations:

        The graph below shows the breakdown between our Latin America Generation and Utilities segments as a percentage of total Latin America revenue and gross margin for the years ended December 31, 2008, 2007, and 2006. See Note 15—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, gross margin and total assets by segment.

        Latin America Generation.    Our largest generation business in Latin America, AES Tietê ("Tietê"), located in Brazil, represents approximately 15% of the total generation capacity in the state of São Paulo and is the ninth largest generator in Brazil. AES holds a 24% economic interest in Tietê. In Argentina, we are one of the largest private power generators contributing 12% of the country's total power generation capacity. In Chile, we are the second largest generator of power. We currently have seven new generation plants under construction—five coal plants and one diesel plant in Chile and one hydro plant in Panama with a combined generation capacity of 1,715 MW.

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        Set forth below is a list of our Latin America Generation facilities:

Generation

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AES operates this facility through management or operations and maintenance agreements and owns no equity interest in this facility

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Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mog-Guaçu, Nova Avanhandava and Promissão

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Gener—Electrica Santiago plants: Renca and Nueva Renca

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Gener—Energia Verde Plants: Constitución, Laja and San Francisco de Mostazal

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Gener—Gener plants: Ventanas, Laguna Verde, Laguna Verde Turbogas, Alfalfal, Maitenas, Queltehues, Volcán and Los Vientos

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Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine)

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Generation under construction

        Latin America Utilities.    Each of our Utilities businesses in Latin America sells electricity under regulated tariff agreements and has transmission and distribution capabilities but none of them has generation capability. AES Eletropaulo, a consolidated subsidiary of which AES owns a 16% economic interest and which has served the São Paulo, Brazil area for over 100 years, has approximately six million customers and is the largest electricity distribution company in Brazil in terms of revenues and electricity distributed. Pursuant to its concession contract, AES Eletropaulo is entitled to distribute electricity in its service area until 2028. AES Eletropaulo's service territory consists of 24 municipalities in the greater São Paulo metropolitan area and adjacent regions that account for approximately 15% of Brazil's GDP and 44% of the population in the State of São Paulo, Brazil. AES Sul ("Sul"), a wholly owned subsidiary, serves over one million customers. In El Salvador, our Utilities businesses provide electricity to over 80% of the country, serving approximately one million customers.

        Set forth below is a list of our Latin America Utilities facilities:

Distribution

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North America

        Our North America operations accounted for 21%, 24% and 26% of consolidated revenues in 2008, 2007 and 2006, respectively. The following table provides highlights of our North America operations:

        The graph below shows the breakdown between our North America Generation and Utilities segments as a percentage of total North America revenue and gross margin for the years ended December 31, 2008, 2007, and 2006. See Note 15—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, gross margin and total assets by segment.

        North America Generation.    Approximately 60% of the generation capacity sold to third parties is supported by long-term power purchase or tolling agreements. Our North America Generation businesses consist of seven gas-fired, ten coal-fired and three petroleum coke-fired plants in the United States, Puerto Rico and Mexico.

        Four of our coal-fired plants, Cayuga, Greenridge, Somerset and Westover, representing capacity of 1,268 MW, operate together as one business, AES Eastern Energy. This business provides power to the Western New York power market under short-term contracts, as well as in the spot electricity market. We also operate three gas-fired plants, representing capacity of 4,327 MW, in the Los Angeles basin under a long-term tolling agreement. These plants are also operated as one business, AES Southland.

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        Set forth below is a list of our North America Generation facilities:

Generation

        North America Utilities.    AES has one integrated utility in North America, IPL, which it owns through IPALCO Enterprises Inc. ("IPALCO"), the parent holding company of IPL. IPL generates, transmits, distributes and sells electricity to approximately 470,000 customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL owns and operates four generation facilities that provide essentially all of the electricity it distributes. The two largest generation facilities are primarily coal-fired plants. The third facility has a combination of units that use coal (base load capacity) and natural gas and/or oil (peaking capacity). The fourth facility is a small peaking station that uses gas-fired combustion turbine technology. IPL's gross generation capability is 3,492 MW. More than half of IPL's coal is provided by one supplier with which IPL has long-term contracts. A key driver for the business is tariff recovery for environmental projects through the rate adjustment process. IPL's customers include residential, industrial, commercial and all other which made up 36%, 40%, 16% and 8%, respectively, of North America Utilities revenue for 2008.

IPL's generation facilities

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IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg

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Distribution

Europe & Africa

        Our operations in Europe & Africa accounted for 12%, 12% and 12% of our consolidated revenues in 2008, 2007 and 2006, respectively. The following table provides highlights of our Europe & Africa operations:

        The graph below shows the breakdown between our Europe & Africa Generation and Utilities segments as a percentage of total Europe & Africa revenue and gross margin for the years ended December 31, 2008, 2007, and 2006. See Note 15—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, gross margin and total assets by segment.

        Europe & Africa Generation.    In 2006, we began commercial operation of AES Cartagena ("Cartagena"), our first power plant in Spain, with 1,199 MW capacity. The results of operations for Cartagena, an unconsolidated entity, are included in the Equity in Earnings of Affiliates line item on the Consolidated Statements of Operations and therefore not reflected in these segment operating results. Today, AES operates five power plants in Kazakhstan which account for almost 30% of the country's total installed generation capacity. In 2008, we completed the sale of a generation plant and a coal mine in Kazakhstan, which we continue to operate under a management agreement through 2010. Key business drivers of this segment are: foreign currency exchange rates, new legislation and regulations including those related to the environment.

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        Set forth below is a list of our generation facilities in the Europe & Africa Generation segment:

Generation

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AES additionally manages the Maikuben West coal mine in Kazakhstan, supplying coal to AES businesses and third parties.

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AES manages these facilities through management or O&M agreements and owns no equity interest in these businesses.

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AES completed the sale of its indirect wholly-owned subsidiaries, the Ekibastuz generation plant and the Maikuben West coal mine in May 2008. AES now operates the facilities under a management agreement through 2010.

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AES operates these facilities under concession agreements until 2017.

Generation under construction

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Joint Venture with I.C. Energy. I.C. Energy Plants: Damlapinar Konya, Kepezkaya Konya, and Kumkoy Samsun. The joint venture is an unconsolidated entity and accounted for under the equity method of accounting.

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        Europe & Africa Utilities.    AES acquired a 56% interest in an integrated utility Société Nationale d'Electricité ("Sonel") in 2001. Sonel generates, transmits and distributes electricity to over half a million people and is the sole source of electricity in Cameroon. Our distribution businesses in Cameroon, the Ukraine and Kazakhstan together serve approximately 2.4 million customers.

        Set forth below is a list of the generation facilities and distribution businesses in our Europe & Africa Utilities segment:

Sonel's generation facilities

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Sonel plants: Bafoussam, Bassa, Djamboutou, Edéa, Lagdo, Logbaba I, Limbé, Mefou, Oyomabang I, Oyomabang II and Song Loulou, and other small remote network units

Distribution

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AES operates these facilities through management agreements and owns no equity interest in these businesses.

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Shygys Energo Trade, a retail electricity company, is 100% owned by Eastern Kazakhstan REC ("EK REC") and purchases distribution service from EK REC and electricity in the wholesale electricity market and resells to the distributions customers of EK REC.

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Ust-Kamenogorsk Heat Nets provide transmission and distribution of heat with a total heat generating capacity of 224 Gcal.

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Asia

        Our Asia operations accounted for 8%, 6% and 6% of consolidated revenues in 2008, 2007 and 2006, respectively. Asia's Generation business operates 13 power plants with a total capacity of 5,664 MW in eight countries and has one power plant under construction. In Asia, AES operates generation facilities only. See Note 15—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for revenue, gross margin and total assets by segment. The following table provides highlights of our Asia operations:

        Asia Generation.    Almost half of our generation capacity in Asia is located in China. In 1996, AES joined with Chinese partners to build Yangcheng, the first "coal-by-wire" power plant with the capacity of 2,100 MW. In 2003, AES started commercial operations of its combined power and desalination water facility in Oman, the first of its kind. We also have a combined power and desalination water facility, the first such facility to be awarded to the private sector, in Qatar. This facility generates over 18% of the country's peak system capacity and 23% of the country's water supply. In April 2008, the Company completed the purchase of a 92% interest in a 660 MW coal-fired thermal power generation facility in Masinloc, Philippines ("Masinloc"). AES Amman East ("Amman East") is a 380 MW combined-cycle gas power plant under construction in Jordan. Amman East achieved simple cycle commercial operation in 2008 and is expected to achieve combined cycle operation in 2009.

        Set forth below is a list of our generation facilities in Asia:

Generation

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Generation under construction

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(1)

Construction of the Amman East power plant commenced in May 2007.

Corporate and Other

        Corporate and Other includes general and administrative expenses related to corporate staff functions and initiatives—primarily executive management, finance, legal, human resources, information systems and certain development costs which are not allocable to our business segments; interest income and interest expense; and intercompany charges such as management fees and self insurance premiums which are fully eliminated in consolidation.

        In addition, Corporate and Other also includes the net operating results of AES Wind Generation, AES Solar, climate solutions, and certain other initiatives, which are not material to our presentation of reporting segments. See Note 15—Segment and Geographic Information in the Consolidated Financial Statements in Item 8 of this Form 10-K for information on revenue from external customers, gross margin and total assets by segment.

        In March 2008, we formed a joint venture called AES Solar LLC with Riverstone, a private equity firm to develop, own and operate solar installations. The joint venture is an unconsolidated entity and accounted for under the equity method of accounting. Since its launch, AES Solar has commenced commercial operations of 24 MW of solar projects in Spain and has development potential in three other countries.

        We own and operate 1,060 MW of wind generation capacity and operate an additional 215 MW capacity through operating and management agreements. Our wind business is located primarily in North America where we operate wind generation facilities that have generation capacity of 1,174 MW. Buffalo Gap III, a 170 MW capacity wind farm commenced commercial operations in August 2008.

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        Set forth below is a list of AES Wind Generation facilities:

Generation

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⁽¹⁾

Joint Venture with Guohua Energy Investment Co. Ltd.

⁽²⁾

AES owns these assets together with third party tax equity investors with variable ownership interests. The tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes, that vary over the life of the projects. The proceeds from the issuance of tax equity are recorded as Minority Interest in the Company's consolidated balance sheet.

⁽³⁾

AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses.

AES Wind Generation projects under construction

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⁽¹⁾

Joint Ventures with Guohua Energy Investment Co. Ltd. Huanghua I & II, Chenbáerhe and Xinaèrhue.

⁽²⁾

InnoVent plants: Frenouville, Audrieu, Boisbergues, Gapree and Croixrault-Moyencourt.

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Financial Data by Country

        The table below presents information about our consolidated operations and long-lived assets, by country, for each of the three years ended December 31, 2008, 2007 and 2006, respectively. Revenues are recognized in the country in which they are earned and assets are reflected in the country in which they are located.

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⁽¹⁾

Acquired in May 2008, revenues represent results for a partial year.

⁽²⁾

Currently under development, facility is not operational at this time.

Customers

        We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2008 total revenues. In our generation business, we own and/or operate power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. Our utilities sell to end-user customers in the residential, commercial, industrial and governmental sectors in a defined service area.

Employees

        As of December 31, 2008 we employed approximately 25,000 people.

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Executive Officers

        The following individuals are our executive officers:

        Paul Hanrahan, 51 years old, has been the President, CEO and a member of our Board of Directors since 2002. Prior to assuming his current position, Mr. Hanrahan was the Executive Vice President and COO. In this role, he was responsible for managing all aspects of business development activities and the operation of multiple electric utilities and generation facilities in Europe, Asia and Latin America. Mr. Hanrahan was previously the President and CEO of the AES China Generating Company, Ltd., a public company formerly listed on NASDAQ. Mr. Hanrahan also has managed other AES businesses in the United States, Europe and Asia. In March 2006, he was elected to the board of directors of Corn Products International, Inc. Prior to joining AES, Mr. Hanrahan served as a line officer on the U.S. fast attack nuclear submarine, USS Parche (SSN-683). Mr. Hanrahan is a graduate of Harvard Business School and the U.S. Naval Academy.

        Andres R. Gluski, 51 years old, has been an Executive Vice President and COO of the Company since March 2007. Prior to becoming the COO, Mr. Gluski was Executive Vice President and the Regional President of Latin America from 2006 to 2007. Mr. Gluski was Senior Vice President for the Caribbean and Central America (Venezuela, El Salvador, Panama and the Dominican Republic) from 2003 to 2006, Group Manager and CEO of La Electricidad de Caracas ("EDC") from 2002 to 2003, CEO of AES Gener (Chile) in 2001 and Executive Vice President of Finance and Shared Services of EDC and Corporacion EDC. Prior to joining AES in 2000, Mr. Gluski was Executive Vice President of Corporate Banking for Banco de Venezuela (Grupo Santander), Vice President for Santander Investment Banking, and Executive Vice President and CFO of CANTV (subsidiary of GTE) in Venezuela. Mr. Gluski has also worked with the International Monetary Fund in the Treasury and Latin American Departments, served as Director General of Public Finance and Senior Macro Economic Policy Advisor to the Minister of Planning of Venezuela, and was also a Member of the Board for the Venezuelan Investment Fund. Mr. Gluski is a graduate of Wake Forest University and holds a Master of Arts and a Doctorate in Economics from the University of Virginia.

        Ned Hall, 49 years old, has been an Executive Vice President, Regional President for North America and Chairman, Global Wind Generation and Energy Storage since June 2008. In December of 2008, Mr. Hall became Chairman, Greenhouse Gas Services, LLC, a joint venture between AES, GE and Mission Point. Prior to his current position, Mr. Hall was Vice President of the Company and President, Global Wind Generation from April 2005 to June 2008, Managing Director of AES Global Development from September 2003 to April 2005, and was an AES Group Manager from April 2001 to September 2003. Mr. Hall joined AES in 1988 as a Project Manager working in the Development Group and has held a variety of development and operating roles for AES, including assignments in the U.S., Europe, Asia and Latin America. He is a Registered Professional Engineer in the State of Massachusetts. Mr. Hall holds a BSME degree from Tufts University and an SM degree in finance/operations management from the MIT Sloan School of Management.

        Victoria D. Harker, 44 years old, has been an Executive Vice President and Chief Financial Officer ("CFO") since January 2006. Prior to joining the Company, Ms. Harker held the positions of Acting CFO, Senior Vice President and Treasurer of MCI from November 2002 to January 2006. Prior to that, Ms. Harker served as CFO of MCI Group, a unit of WorldCom Inc., from 1998 to 2002. Prior to 1998, Ms. Harker held several positions at MCI in the areas of finance, information technology and operations. Ms. Harker received a Bachelor of Arts degree in English and Economics from the University of Virginia and a Masters in Business Administration, Finance from American University.

        John McLaren, 46 years old, has been an Executive Vice President of the Company since 2006 and is the Regional President of Europe, Asia, Middle East & Africa. Mr. McLaren served as Vice President of Operations for AES Europe & Africa from 2003 to 2006 (and AES Europe, Middle East and Africa from May 2005 to January 2006), Group Manager for Operations in Europe & Africa from

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2002 to 2003, Project Director from 2000 to 2002, and Business Manager for AES Medway Operations Ltd. from 1997 to 2000. Mr. McLaren is a Chartered Director, a professional qualification for business leaders conferred by the Institute of Directors in London. Mr. McLaren joined the Company in 1993. He holds a Masters in Business Administration from the University of Greenwich Business School in London.

        Brian A. Miller, 43 years old, is an Executive Vice President of the Company, General Counsel, Corporate Secretary and Acting Chief Compliance Officer. Mr. Miller joined the Company in 2001 and has served in various positions including Vice President, Deputy General Counsel, Corporate Secretary, General Counsel for North America and Assistant General Counsel. Prior to joining AES, he was an attorney with the law firm Chadbourne & Parke, LLP. Mr. Miller received a bachelor's degree in History and Economics from Boston College and holds a Juris Doctorate from the University of Connecticut School of Law.

        Rich Santoroski, 44 years old, has been the Vice President, Global Risk & Commodity Organization since February 2008. Prior to his current position, Mr. Santoroski was Vice President, Energy & Natural Resources, a business development group, and Vice President, Risk Management. Mr. Santoroski joined AES in January 1999 to lead AES Eastern Energy's commodity management. Prior to AES, Mr. Santoroski held various engineering, trading and risk management positions at New York State Electric & Gas, including leading the energy trading group. He graduated from Pennsylvania State University with a Bachelor of Science in Electrical Engineering, and earned an MBA and a Master of Science in Electrical Engineering from Syracuse University. Mr. Santoroski is a Licensed Professional Engineer in the State of New York.

        Andrew Vesey, 53 years old, has been an Executive Vice-President and Regional President of Latin America since March 2008. Prior to his current position, Mr. Vesey was President and Chief Operating Officer for Latin America since July 2007 and Chief Operating Officer for Latin America since 2004. Mr. Vesey also served as Vice President and Group Manager for AES Latin America, DR-CAFTA Region from 2006 to 2007, Vice President of the Global Business Transformation Group from 2005 to 2006, and Vice President of the Integrated Utilities Development Group from 2004 to 2005. Prior to joining the Company in 2004, Mr. Vesey was a Managing Director of the Utility Finance and Regulatory Advisory Practice at FTI Consulting Inc, a partner in the Energy, Chemicals and Utilities Practice of Ernst & Young LLP, and CEO and Managing Director of Citipower Pty of Melbourne, Australia. He received his BA in Economics and BS in Mechanical Engineering from Union College in Schenectady, New York and his MS from New York University.

        Mark E. Woodruff, 51 years old, is an Executive Vice President of the Company who focuses on development. Prior to his current position, Mr. Woodruff was Regional President of Asia & Middle East from March 2007 through January 2008, Vice President of North America Business Development from September 2006 to March 2007 and was Vice President of AES for the North America West region from 2002 to 2006. Mr. Woodruff has held various leadership positions since joining the Company in 1992. Prior to joining the Company in 1991, Mr. Woodruff was a Project Manager for Delmarva Capital Investments, a subsidiary of Delmarva Power & Light Company. Mr. Woodruff holds a Bachelor of Science degree in Mechanical and Aerospace Engineering from the University of Delaware.

How to Contact AES and Sources of Other Information

        Our principal offices are located at 4300 Wilson Boulevard, Arlington, Virginia 22203. Our telephone number is (703) 522-1315. Our website address is http://www.aes.com. Our 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 our website. After the reports are filed with, or furnished to, the Securities and Exchange Commission ("SEC"), they are available from us free of charge. Material contained on our website is not part of and is not incorporated by reference in this Form 10-K.

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        Our CEO and our CFO have provided certifications to the SEC as required by Section 302 of the Sarbanes-Oxley Act of 2002. These certifications are included as exhibits to this Annual Report on Form 10-K.

        Our CEO provided a certification pursuant to Section 303A of the New York Stock Exchange Listed Company Manual on May 22, 2008.

        Our Code of Business Conduct ("Code of Conduct") and Corporate Governance Guidelines have been adopted by our Board of Directors. The Code of Conduct is intended to govern, as a requirement of employment, the actions of everyone who works at AES, including employees of our subsidiaries and affiliates. Our Ethics and Compliance Department provides training, information, and certification programs for AES employees related to the Code of Conduct. The Ethics and Compliance Department also has programs in place to prevent and detect criminal conduct, promote an organizational culture that encourages ethical behavior and a commitment to compliance with the law, and to monitor and enforce AES policies on corruption, bribery, money laundering and associations with terrorists groups. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on our website at www.aes.com. Any person may obtain a copy of the Code of Conduct or the Corporate Governance Guidelines without charge by making a written request to: Corporate Secretary, The AES Corporation, 4300 Wilson Boulevard, Arlington, VA 22203. If any amendments to, or waivers from, the Code of Conduct or the Corporate Governance Guidelines are made, we will disclose such amendments or waivers on our website.

Regulatory Matters

Overview

        In each country where we conduct business, we are subject to extensive and complex governmental regulations which affect most aspects of our business, such as regulations governing the generation and distribution of electricity and environmental regulations. These regulations affect the operation, development, growth and ownership of our businesses. Regulations differ on a country by country basis and are based upon the type of business we operate in a particular country.

Regulation of our Generation Businesses

        Our Generation businesses operate in two different types of regulatory environments:

        Market Environments.    In market environments, sales of electricity may be made directly on the spot market, under negotiated bilateral contracts, or pursuant to PPAs. The spot markets are typically administered by a central dispatch or system operator who seeks to optimize the use of the generation resources throughout an interconnected system (cost of the least expensive next generation plant required to meet system demand). The spot price is usually set at the marginal cost of energy or based on bid prices. In addition, many of these wholesale markets include markets for ancillary services to support the reliable operation of the transmission system, such as regulation (a service that corrects for short-term changes in electricity use that could impact the stability of the power system). Most of our businesses in Europe, Latin America and the U.S. operate in these types of liberalized markets.

        Other Environments.    We operate Generation assets in certain countries that do not have a spot market. In these environments, electricity is sold only through PPAs with state-owned entities and/or industrial clients as the offtaker. Examples of countries where we operate in this type of environment include Jordan, Nigeria, Oman, Pakistan, Puerto Rico, Qatar and Sri Lanka.

Regulation of our Distribution Businesses

        In general, our distribution companies sell electricity directly to end users, such as homes and businesses and bill customers directly. The amount our distribution companies can charge customers for electricity is governed by a regulated tariff. The tariff, in turn, is generally based upon a certain usage

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level that includes a pass through of costs to the customer that are not controlled by the distribution company, including the costs of fuel (in the case of integrated utilities) and/or the costs of purchased energy, plus a margin for the value added by the distributor, usually calculated as a fair return on the fair value of the company's assets. This regulated tariff is periodically reviewed and reset by the regulatory agency of the government. Components of the tariff that are directly passed through to the customer are usually adjusted through an automated process. In many instances, the tariffs can be adjusted between scheduled regulatory resets pursuant to an inflation adjustment or another index. Customers with demand above a certain level are often unregulated and can choose to contract with generation companies directly and pay a wheeling fee, which is a fee to the distribution company for use of the distribution system. Most of our utilities operate as monopolies within exclusive geographic areas set by the regulatory agency and face very limited competition from other distributors.

        Set forth below is a discussion of certain regulations we face in each country where we do business. In each country, the regulatory environment can pose material risks to our business, its operations and/or its financial condition. For further discussion of those risks, see the Risk Factors in Item 1A of this Annual Report on Form 10-K.

Latin America

        Brazil.    Brazil has one main interconnected electricity system, the National Interconnected System. The power industry in Brazil is regulated by the Brazilian government, acting through the Ministry of Mines and Energy and the National Electric Energy Agency, ("ANEEL"), an independent federal regulatory agency that has authority over the Brazilian power industry. ANEEL supervises concessions for electricity generation, transmission, trading and distribution, including the setting of tariff rates, and supervising and auditing of concessionaires.

        On March 15, 2004, the Brazilian government launched a proposed new model for the Brazilian power sector. The New Power Sector Model created two energy markets: (1) the regulated contractual market for the distribution companies, and (2) the free contract environment market, designed for traders and other large volume users.

        AES has two distribution businesses in Brazil—Eletropaulo, serving approximately six million customers in the São Paulo area, and Sul, serving over one million customers in the state of Rio Grande do Sul. Under the New Power Sector Model, every distribution utility is obligated to contract to meet 100% of its energy requirements in the regulated contractual market, through energy auctions from new proposed generation projects or existing generation facilities. Bilateral contracts are being honored, but cannot be renewed.

        The tariff charged by distribution companies to regulated customers is composed of a non-manageable cost component (Part A), which includes energy purchase costs and charges related to the use of transmission and distribution systems and is directly passed through to customers, and a manageable cost component (Part B), which includes operation and maintenance costs based on a reference company (a model distribution company defined by ANEEL), recovery of depreciated assets and a component for the value added by the distributor (calculated as net asset base multiplied by pre-tax weighted average cost of capital). Part B is reset every three to five years depending on the specific concession. There is an annual tariff adjustment to pass through Part A costs to customers and to adjust the Part B costs by inflation less an efficiency factor (X-Factor). Distribution companies are also entitled to extraordinary tariff revisions, in the event of significant changes to their cost structure.

        At ANEEL's Public Meeting on July 1, 2008, Eletropaulo was granted an 8.01% average tariff increase effective July 4, 2008. In the 2007 tariff reset process, certain items were determined to be provisional and this process is expected to be defined in the next tariff adjustment process (July, 2009).

        On May 16, 2002, ANEEL issued Order 288, a regulation that stipulated the retroactive denial to the choice of not participating in the "exposition relief mechanism", a tool that allowed the selling of

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energy from Itaipu Generating Co. in the spot market. Due to its negative impact, Sul filed a lawsuit seeking to annul Order 288, and as soon as the case went to court, Sul was granted a preliminary injunction that ordered ANEEL to review the Brazilian Electric Energy Commercialization Chamber ("CEEE") calculations and liquidation, an injunction that was later suspended. If Sul obtains a favorable final verdict, it will have a positive impact of about R$437.8 million (historic values referring to 2001 and 2002) or approximately $187.0 million, but if Sul's requests are not granted, under Order 288 Sul will owe a net amount of approximately R$146.7 million or approximately $62.6 million at December 31, 2008. All amounts are reserved in Sul's books, including the amount owed to CCEE in the event Sul loses the case.

        AES has two generation businesses in Brazil—Tietê, a 2,651 MW hydro-generation facility and AES "Uruguaiana", a 639 MW generation facility. Under the New Power Sector Model and in order to optimize the generation of electricity through Brazil's nationwide system, generation plants are allocated a generating capacity referred to as "assured energy" or the amount of energy representing the long-term average energy production of the plant defined by ANEEL. Together with the system operator, ANEEL establishes the amount of assured energy to be sold by each plant. The system operator determines generation dispatch which takes into account nationwide electricity demand, hydrological conditions and system constraints. In order to mitigate risks involved in hydroelectric generation, a mechanism is in place to transfer surplus energy from those who generated in excess of their assured energy to those who generated less than their assured energy. The energy that is reallocated through this mechanism is priced pursuant to an energy optimization tariff, designed to optimize the use of generation available in the system.

        Tietê is allowed to sell electric power within the two environments, maintaining the competitive nature of the generation. All the agreements, whether entered in the ACR (Regulated Contracting Environment) or in the ACL (Free Contracting Environment), are registered in the CCEE and they serve as basis for the accounting posting and the settlement of the differences in the short-term market. Generation companies must provide physical coverage from their own power generation for 100% of their sale contracts. The verification of physical coverage is accomplished on a monthly basis, based on generation data and on sale company contracts of the last 12 months. The failure to provide physical coverage exposes the generating company to the payment of penalties.

        Beginning in 2006, all Tietê's assured energy has been sold to Eletropaulo. The PPA entered into with Eletropaulo expires on December 31, 2015, and requires that the price of energy sold be adjusted annually based on the Brazilian inflation ("IGPM") variation. In October 2003, Tietê and Eletropaulo executed an amendment to extend the PPA through June 2028. However, this amendment was not approved by ANEEL. In response, Eletropaulo filed a suit against ANEEL and is currently awaiting the first-instance judgment. Based on the current rules concerning the purchase and sale of energy through the auction process, and because such rules remain in effect until 2015, the selling price may significantly differ from the current price adjusted under the terms of the existing PPA. If the PPA were terminated, Tietê would only be allowed to sell in the ACR or ACL.

        Tietê's concession agreement with the State of São Paulo for its generation plant includes an obligation to increase generation capacity by 15% originally to be accomplished by the end of 2007. Tietê, as well as other concessionaire generators, were not able to meet this requirement due to regulatory, environmental and hydrological constraints, and requested an extension of the term. Currently, the matter is under consideration by the Government of the State of São Paulo, after a decision by the Board of Officers of ANEEL, that ANEEL is not the appropriate authority to consider the extension, since the expansion obligation derives from the purchase and sale agreement between Tietê and the Government of São Paulo, and not from the concession agreement. Tietê is negotiating new conditions and a new deadline to fulfill the expansion requirement. There is a dispute alleging that Tietê failed to increase its generation capacity as established in the concession agreement. The dispute seeks to determine the application of penalties related to the concession agreement, and also to

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determine its termination. Judicial summons have been received and, in October 2008, Tietê presented its defense. On October 31, 2008, a decision was rendered ordering the Plaintiff to respond to Tietê's defense. Such a response has not been filed yet.

        Uruguaiana has been impacted by the energy crisis in Argentina, primarily through natural gas supply restrictions. During this period, Uruguaiana has been forced to purchase energy from the spot market and through bilateral contracts in order to satisfy its alleged obligations under the PPAs with the distribution companies. In August 2008, the Argentinean gas supplier sent a notification to Uruguaiana declaring force majeure under the gas supply agreement. Uruguaiana extended the effects of such force majeure to the PPAs with the distribution companies. After such declaration by the Argentinean gas supplier, Uruguaiana started negotiations with the four distribution companies to reduce the amount of energy contracted under the PPAs and resolve these matters. From August 2008 to December 2008, Uruguaiana and the distribution companies entered into amendments to reduce the energy amounts under the PPAs to the level of the bilateral agreements executed by Uruguaiana, suspend such agreements by December 2009 and settle all pending matters. Three of these distribution companies sought and received a decision by ANEEL declaring that they were entitled to involuntary exposures, which allows these distribution companies to purchase replacement energy in the market and recover the related additional costs, if any, through their tariffs. The fourth involuntary exposure request from a distribution company is under analysis by ANEEL.

        Chile.    In Chile, except for the small isolated systems of Aysén and Punta Arenas, generation activities are principally in two electric systems: the Central Interconnected Grid (known as the SIC), which supplies approximately 92% of the country's population; and the Northern Interconnected Grid (known as the SING), where the principal users are mining and industrial companies.

        In each of these grids, electricity generation is coordinated by the respective independent Economic Load Dispatch Center, or CDEC, in order to minimize operational costs and ensure the highest economic efficiency of the system, while fulfilling all quality of service and reliability requirements established by current regulations. In order to satisfy demand at the lowest possible cost at all times, each CDEC orders the dispatch of generation plants based strictly on variable generation costs, starting with the lowest variable cost, and does so independent of the contracts held by each generation company. Thus, while the generation companies are free to enter into supply contracts with their customers and are obligated to comply with such contracts, the energy needed to satisfy demand is always produced by the CDEC members whose variable production costs are lower than the system's marginal cost at the time of dispatch. In addition, the Chilean market is designed to include payments for capacity (or firm capacity), which are explicitly paid to generation companies for contributing to the system's sufficiency. The cost of investment and operation of transmission systems are borne by generation companies and consumers (regulated tolls) in proportion to their use.

        The Chilean Ministry of Economy, Development and Reconstruction grants concessions for the provision of the public service of electric distribution; and the National Commission for the Environment administers the system for evaluating the environmental impact of projects. Concessions are not required from government agencies to build and operate thermoelectric plants. The National Energy Commission establishes, regulates and coordinates energy policy. The Superintendency of Electricity and Fuels oversees compliance with service quality and safety regulations. The General Water Authority issues the rights to use water for hydroelectric generation plants. The Chilean electric system includes a Panel of Experts, an independent technical agency whose purpose is to analyze and resolve in a timely fashion conflicts arising between companies within the electric sector and among one or more of these companies and the energy authorities.

        Power generation is based primarily on long-term contracts between generation companies and customers specifying the volume, price and conditions for the sale of energy and capacity. The law recognizes two types of customers for generation companies: unregulated customers and regulated customers. Unregulated customers are principally consumers whose connected capacity is higher than

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2 MW, and consumers whose connected capacity is between 500 kW and 2 MW who have selected the unregulated pricing mechanism for a period of four years. These customers are not subject to price regulation; therefore, generation and distribution companies are able to freely negotiate prices and conditions for electricity supply with them. Regulated customers are those whose connected capacity is less than or equal to 500 KW, and those with connected capacity between 500 kW and 2 MW who have selected—also for four years—the regulated pricing system.

        The distinct electricity sector activities are regulated by the General Electricity Services Law, DFL No. 1/1982 enacted by the Mining Ministry, with its subsequent amendments: Law No. 19,490 (2004, known as the "Short Law I") and Law No. 20,01/005, or the "Short Law II", which did not modify the foundation of Chile's stable electricity sector model. These laws were rewritten and systematized under DFL No. 4/2007. Sector activities are also governed by the corresponding technical regulations and standards.

        In accordance with the amendment to the electricity law enacted in May 2005, new contracts assigned by distribution companies for consumption from 2010 onward must be awarded to generation companies based on the lowest supply price offered in public bid processes. These prices called "long-term node prices", include indexation formulas and are valid for the entire term of the contract, up to a maximum of 15 years. More precisely, the long-term energy node price for a particular contract is the lowest energy price offered by the generation companies participating in each respective bid process, while the long-term capacity node price is that set in the node price decree in effect at the time of the bid.

        The "Tokman Law", which was enacted in September 2007, requires that generation companies must continue to supply electricity to distribution companies whose supply contract may be terminated as a result of bankruptcy of the distribution company, its generation supplier, or the anticipated termination of the power purchase contract due to an arbitration award or court decision. The law states that in these situations, if the distribution company is not able to procure a new contract, all generation companies in the system must then supply the distribution company at node prices based on the generator's respective participation in the grid.

        Another statute, Law 20,257, was enacted in April 2008. Law 20, 257 promotes non-conventional renewable energy sources, such as solar, wind, small hydroelectric and biomass energy. The law requires that a percentage of the new power purchase contracts held by generation companies after August 31, 2007, be supplied from renewable sources. The required energy percentage begins at 5% for the period 2010-2015, and gradually increases to a maximum of 10% in 2024. A penalty is applied for each kWh not supplied in accordance with the law. Our businesses in Chile have developed a plan for complying with this law, which includes the sale of certain water rights, the purchasers of which have agreed to build a small hydroelectric plant and sell the energy to Gener at a fixed price.

        Colombia.    Colombia has one main national interconnected system (the "SIN"). In 1994 the Colombian Congress issued the laws of Domiciliary Public Services and the Electricity Law, which set the institutional arrangement and the general regulatory framework for the electricity sector. The Regulatory Commission of Electricity and Gas ("CREG") was created to foster the efficient supply of energy through regulation of the wholesale market, the natural monopolies of transmission and distribution, and by setting limits for horizontal and vertical economic integration. The control function was assigned to the Superintendency of Public Services.

        The wholesale market is organized around both bilateral contracts and a mandatory pool and spot market for all generation units larger than 20 MW. Each unit bids its availability quantities for a 24 hour period with one bid price set for those 24 hours. The dispatch is arranged by lowest to highest bid price and the spot price is set by the marginal price.

        The spot market started in July 1995, and in 1996 a capacity payment was introduced for a term of 10 years. In December 2006, a regulation was enacted that replaced the capacity charge with the

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reliability charge and established two implementation periods. The first period consists of a transition period from December 2006 to November 2012, during which, the price is equal to $13.045 per MWh ("megawatt hour") and volume is determined based on firm energy offers which are pro-rated so that the total firm energy level does not exceed system demand. The second period, in which the reliability charge will be determined, based on the energy price and volume offers submitted by new market participants bidding for new capacity for the system, begins in December 2012. The first reliability charge auction was held in May 2008 with the following results: (i) The reliability charge for existing plants for the period between December 2012 and November 2013 will be $13.998 per MWh; (ii) For new plants that successfully participated in the auction, the charge will be paid for 20 years starting December 2012; (iii) Three new projects won the auction for a total capacity of 429.6 MW starting in 2012.

        Furthermore, the CREG issued a proposal to create the "MOR" or Organized Regulated Market. The MOR will replace current bilateral contracts (assigned between traders and generators) for a centralized auction in which the System Operator buys energy for all regulated customers attended by the traders. The main provisions contained in the proposal include: i) it is mandatory for all traders to buy energy at the auction price and it is voluntary for sellers (generators and traders companies) to offer energy in each auction; ii) one price for the energy sales in the year; iii) the auctions are held one year before the actual dispatch moment and the commitment period of the auction is one year, iv) the proposal is to establish four auctions in each year, in order to cover the annual demand. We expect that a definitive resolution on this matter will be issued in the second quarter of 2009.

        Finally, ANDI—the Colombian Industry Guild, and the Energy Minister, among others, have raised objections to the increase in energy prices in the spot and bilateral contracts market for 2009 and 2010. In response, the regulator (CREG) issued new rules that allow traders to slowly adjust the tariffs to consumers and to promote competition. In general, these rules are not expected to create significant changes in the current regulation.

        Argentina.    Argentina has one main national interconnected system. The National Electrical Regulating Agency is responsible for ensuring the compliance of transmission and distribution companies to concessions granted by the Argentine government, and approves distribution tariffs. The regulatory entity authorized to manage and operate the wholesale electricity market in Argentina is Compañía Administradora del Mercado Mayorista Eléctrico, Sociedad Anómima, ("CAMMESA"), in coordination with the policies established by the National Secretariat of Energy.

        CAMMESA performs load dispatching and clears commercial transactions for energy and power. Sales of electricity may be made on the spot market at the marginal cost of energy to satisfy the system's hourly demand, or in the wholesale energy market under negotiated term contracts. As a result of the gas crisis earlier this decade, this mechanism was modified in 2003 by Resolution 240/03. At present, the price is determined as if all generating units in Argentina were operating with natural gas, even though they may be using other, more expensive, alternative fuels. In the case of generators using alternative fuels, CAMMESA pays the total variable cost of production, which may exceed the established spot price. Additionally, in the spot market, generators are also remunerated for their capacity to generate electricity in excess of supply agreements or private contracts executed by them.

        As the result of a political, social and economic crisis, the Argentine government has adopted many new economic measures since 2002, by means of the "Emergency Law" 25561 issued on January 6, 2002, extended by Law N? 26.456 issued on December 16, 2008 until December 31, 2009. The regulations adopted in the energy sector effectively terminated the use of the U.S. Dollar as the functional currency of the Argentine electricity sector. During 2004, the Energy Secretariat reached agreements with natural gas and electricity producers to reform the energy markets. In the electricity sector, the Energy Secretariat passed Resolution 826/2004, inviting generators to contribute a percentage of their sales margins to fund the development and construction of two new combined cycle power plants to be installed by 2008/2009. The time period for the funding was set from January 2004

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through December 2006 and was subsequently extended through December 2007. During 2008 both power plants have started the operation of the gas turbines, and during the second half of 2009 it is expected that the steam turbines will be installed and the plants will start to operate in combined cycle mode. In exchange, the Government committed to reform the market regulation to match the pre-crisis rules prevailing before December 2001. Additionally, participating generators will receive a pro-rata ownership share in the new generation plants after ten years.

        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 are no longer linked to the U.S. Dollar and U.S. inflation indices. As a consequence of the emergency declared by the above-mentioned laws and its resulting regulatory framework, the tariffs of all distribution companies were converted to pesos and were frozen at the peso national rate as of December 31, 2001. In October 2003, the Argentine Congress established a procedure for renegotiation of the public utilities concessions.

        On November 12, 2004, EDELAP, an AES distribution business, signed a Letter of Understanding with the Argentine government in order to renegotiate its concession contract and to start a tariff reform process, which was ratified by the National Congress on May 11, 2005. Final government approval was obtained on July 14, 2005. As a first step during this process, a Distribution Value Added ("DVA") increase of 28%, effective February 1, 2005, was granted. On October 24, 2005, EDEN and EDES, two AES distribution businesses, signed a Letter of Understanding with the Ministry of Infrastructure and Public Services of the Province of Buenos Aires to renegotiate their concession contracts and to start a tariff reform process, which was formally approved on November 30, 2005. An initial 19% DVA increase became effective in August 2005 and an additional 8% DVA increase became effective in January 2007. On July 31, 2008, ENRE (the national electricity regulatory agency) issued Resolution 324 that granted EDELAP a tariff increase DVA of approximately 18%. In addition, the Government established that a process to establish the RTI (integral tariff reset) will take place during February 2009. Upon execution of these Letters of Understanding, AES agreed to postpone or suspend certain international claims. However, these Letters of Understanding provide that if the government does not fulfill its commitments, AES may restart the international claim process. AES has postponed any action until the tariff reset is finalized.

        On August 25, 2008 the Province of Buenos Aires issued the Decree 1578, that granted EDES a tariff increase DVA of approximately 49%. This decree granted a rise in the tariff at all levels of consumption. The Government also established that the tariff review process will take place during 2009.

        El Salvador.    Electricity generators and distribution companies in El Salvador are linked through a single, main interconnected system managed by the Transactions Unit ("UT"). The transmission system is operated by ETESAL, a state-owned company. The El Salvador wholesale electricity market is comprised of: (1) a contract market based on contracts between electricity generators, distributors and trading companies and (2) a spot market for uncontracted electricity based upon bids from spot market participants specifying prices at which they are willing to buy or sell electricity.

        El Salvador has five electricity distribution companies, which came under private ownership as part of the privatization process that took place in 1998. AES controls four of these five distribution companies, encompassing about 80% of the national territory, serving about 1,100,000 customers. El Salvador's electricity industry is regulated under the General Electricity Law enacted in October 1996 and subsequently amended twice in June 2003, and in October 2007. The Superintendencia General de Electricidad y Telecomunicaciones ("SIGET") is an independent regulatory authority that regulates the electricity and telecommunications sectors in El Salvador.

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        The maximum tariff to be charged by distribution companies to regulated customers is subject to the approval of SIGET. The components of the electricity tariff are (a) the average energy price ("energy charge"), (b) the charges for the use of the distribution network ("distribution charge"), and (c) customer service costs ("service charge"). Both the distribution charge and service charge are based on average capital costs as well as operation and maintenance costs of an efficient distribution company. The energy charge is adjusted every six months to reflect the changes in the spot market price for electricity. The distribution charge and service charge are approved by SIGET every five years and have two adjustments: (1) an annual adjustment considering the inflation variation and (2) an automatic adjustment in April, July and October, provided that change in the adjusted value exceeds the value in effect by at least 10%.

        The distribution tariff for all five distribution companies in El Salvador was reset on December 4, 2007. The approved tariff schedule is valid for the next five years (2008-2012). One outcome of the tariff reset was a significant reduction in the distribution value added component of the tariff for each of AES's distribution businesses. On March 28, 2008, after negotiations with SIGET and the El Salvador Presidential House, a revised tariff schedule was enacted. It came into force on April 1, 2008. The negotiated tariff schedule included a higher technical losses index than originally recognized by SIGET. This permits the companies to recover an adequate portion of their technical losses through billing. The new tariffs improved distribution revenues by around 9% compared to the rates set on December 4, 2007. This schedule is valid for the period 2008-2012. As a result of this negotiation and the enactment of the new rate schedule, AES agreed to withdraw its appeal recourse before the El Salvador Supreme Court, which was introduced on December 11, 2007.

        As expected, SIGET approved new regulations for Service Connection and Reconnection charges, which came into force on November 3, 2008. The charges underwent a reduction of about 20% on average for these activities. In addition, there are also Quality of Service Regulations contained in SIGET resolution 192-E-2004, which require that distribution companies comply with certain Technical Product Standards, Technical Service Standards and Commercial Service Standards. The Quality of Service Standards became permanent in 2008, which means that they are now enforced to their full extent.

        On November 28, 2008 SIGET enacted the bylaw for the Operation of the Transmission System and the Wholesale Market based on Generation Costs, which provides rules for the Independent System Operator, who is responsible for administering and operating the wholesale market for electricity. From 1996 until the passing of the bylaw, the wholesale market was governed by a price-offer system, whereby each generator submitted a daily price offer for its available generation (limited by a price cap) and the offer price determined dispatch. Under the new bylaw, each generating unit will have audited variable costs (generating costs), which will determine the economic dispatch merit order. The bylaw also provides for additional capacity payments to providers as determined by the regulator. The variable costs mechanism enabling legislation has been enacted, and it provides for a preparation and transition period before the regulations are in full force and effect which is scheduled to occur in 2010.

        Currently, the Company does not face any regulatory action in El Salvador.

        Dominican Republic.    The Dominican Republic has one main interconnected system with 3,000 MW of installed capacity and four isolated systems. Under current regulations, the Dominican government retains ultimate oversight and regulatory authority as well as control and ownership of the transmission grid and the hydroelectric facilities in the country. In addition, the government shares ownership in certain generation and distribution assets. The Dominican government's oversight responsibilities for the electricity sector are carried out by the National Energy Commission ("CNE") and the Superintendency of Electricity.

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        The wholesale market in the Dominican Republic commenced operations in June 2000. This market includes a spot market and contract market. All participants in the Dominican electric system with available units are put in the spot market in order of merit for dispatch based on lowest marginal cost. The order of merit determines the order in which each participant is dispatched. The order of merit is effective for one week. The price to be paid for the electricity corresponds to the marginal cost of the last dispatched unit using natural gas. Sector participants may execute private contracts in which they agree to specific price, energy, and capacity transactions.

        The regulatory framework in the Dominican electricity market establishes a methodology for calculating the firm capacity, which is the supply that can be economically dispatched by a generating unit during peak demand, provided that the unit has a certain unavailability (mechanical in the case of thermal power plants, and primarily hydrological in the case of hydroelectric power plants). The total firm capacity of the electric system in a year is equal to the peak demand of that year. The capacity payment is regulated as the average fixed cost (monthly capital cost of the investment cost plus fixed operational and maintenance cost) of an oil-fired open cycle gas turbine, multiplied by a factor to take into account a reserve margin.

        The financial crisis in the Dominican Republic during 2004 caused a financial crisis in the electricity sector. The inability to pass through higher fuel prices and the costs of devaluation led to a gap between collections at the distribution companies and the amounts required to pay the generators. In 2005 the government committed itself to stay current with its energy bills and also to cover the potential deficit of distribution companies. During 2005, 2006, and 2007 the government was paying both the subsidies and its own energy bills on time. In December 2006, a bill with the primary goal of supporting fraud prosecution was sent to Congress by the Executive Branch. This bill was approved in July 2007 and is expected to help the sector reach financial sustainability by: criminalizing electrical fraud; setting new limits to non-regulated users in order to protect the distribution companies' market; allowing for service cutoff after only one bill due; and classifying as a national security breach the intentional damage or interruption of the national electricity grid.

        Despite these improvements, the electricity sector has not completely recovered from the financial crisis of 2004. In 2006 the electricity sector needed $530 million in subsidies from the government to cover current operations. In 2007, the sector needed more than $630 million and, at projected fuel prices, (petroleum at $75 per barrel) the government budgeted subsidies of $800 million for 2008. In 2008, because petroleum and all other fuels doubled in price, the subsidy of $800 million was not enough to cover additional costs, which reached $1,200 million. The Government has been trying to raise more funds, by allocating funds from the national budget, such as a recent approval of an additional $300 million in electricity subsidies supplementing 2008. In addition the Government has been trying to obtain credit from local banks and multilateral institutions.

        In October of 2006, CDEEE (Corporación Dominicana de Empresas Electricas Estatales), the state owned transmission and hydro company, began making public statements that it intends to seek to compel the renegotiation and/or rescission of long-term PPAs with certain power generating companies in the Dominican Republic. Although the details concerning CDEEE's statements are unclear and no formal government action has been taken, AES holds ownership interests in three power generation facilities in the country (AES Andres, Itabo and Dominican Power Partners) that could be adversely affected by the actions taken by the CDEEE, if any.

        Panama.    In 1998, as part of the privatization process, the Panamanian Government divided the Instituto de Recursos Hidráulicos y de Electrificación (IRHE's) assets and operations into four generation companies, three distribution companies and one transmission company. Following a public auction, 51% of shares in each distribution company were sold by the Panamanian Government in September 1998. This was followed in November 1998 by the sale of 49% of shares in each of the three state-owned hydroelectric generation companies and 51% of shares in the main thermoelectric generation

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company. These sales were completed in 1999. As a result of the sales, AES acquired control and operation of two of the hydroelectric companies.

        The Panamanian Government retained control of Empresa de Transmisión Eléctrica, S.A. (ETESA), the state-owned transmission company, which operates and controls the National Interconnected System (NIS) of 230Kv and certain 115Kv lines. Panama has one main interconnected system (the NIS) operated by ETESA. The transmission charges are reviewed and approved every four years by The National Authority of Public Services (ASEP); the current transmission tariffs are in effect until June 2009. The ASEP sets the framework for the tariff regime, determining transmission zones and rates applicable in the relevant zones and regulates power generation, transmission, interconnection and distribution activities in the electric power sector.

        The National Dispatch Center ("CND") is responsible for planning, supervising and controlling the integrated operation of the NIS and for ensuring its safe and reliable operation. The dispatch order is determined and planned by the CND, which dispatches electricity from generation plants based on lowest marginal cost. According to the Electricity Law, the order in which generators are dispatched must be based on maximizing efficient consumption of energy by minimizing the total cost of energy in the Panamanian power system.

        Distribution companies are required to contract 100% of their annual power requirements (although they can self-generate up to 15% of their demand). Generators can enter into long-term PPAs with distributors or unregulated consumers. In addition, generators can enter into alternative supply contracts with each other. The terms and contents of PPAs are determined through a competitive bidding process and are governed by the Commercial Rules. AES Panama participated in the last Public Bid of Long Term called EDEMET 01-08 for the supply of power and energy until the year 2022. The public bid was held on September 9, 2008 and part of the Public Bid for the sale of 100MW at $92.95/MWh from the year 2012 until the year 2021 and 41 MW at $99.87/MWh from the year 2013 until the year 2022 was awarded to AES Panama. AES Panama already contracted to sell an average of 86% of firm capacity through 2018.

        Under the Electricity Law, generation companies will not be granted new concessions if they would thereby account, directly or indirectly, for more than 25% of national electricity consumption. The percentage may be increased by the Panamanian Government where justified by competitive conditions subject to the approval of the ASEP. The percentage was increased to 40% by Executive Resolution No. 76 of October 19, 2005. This provision does not apply to licenses for thermal generation.

        Besides the PPA market, generators may buy and sell energy in the spot market. Energy sold in the spot market corresponds to the hourly differences between the actual dispatch of energy by each generator and its contractual commitments to supply energy. The energy spot price is set by the order in which generators are dispatched. The CND ranks generators according to their variable cost (thermal) and the value of water (hydroelectric), starting with the lowest value, thereby establishing on an hourly basis the merit order in which generators will be dispatched the following day in order to meet expected demand. This price ranking system is intended to ensure that national demand will be satisfied by the lowest cost combination of available generating units in the country. A generator whose dispatched energy is greater than its contractual commitments to supply energy at any given time is a seller in the energy spot market; the reverse is true for a generator whose dispatched energy is less than its contractual commitments to supply energy. Generators and unregulated consumers can purchase energy in the energy spot market, while only generators can sell energy in the energy spot market.

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North America

        United States.    The U.S. wholesale electricity market consists of multiple distinct regional markets that are subject to both federal regulation, as implemented by the FERC, and regional regulation as defined by rules designed and implemented by the Independent System Operator ("ISO"). These rules for the most part govern such items as the determination of the market mechanism for setting the system marginal price for energy and the establishment of guidelines and incentives for the addition of new capacity. The current regulatory framework in the U.S. is the result of a series of regulatory actions that have taken place over the past two decades, as well as numerous policies adopted by both the federal government and the individual states that encourage competition in wholesale and retail electricity markets.

        The federal government, through regulations promulgated by FERC, has primary jurisdiction over wholesale electricity markets and transmission services. While there have been numerous federal statutes enacted during the past 30 years, including the Public Utility Regulatory Policy Act of 1978 ("PURPA"), the Energy Policy Act of 1992 ("EPAct 1992") and the Energy Policy Act of 2005 ("EPAct 2005"), there are two fundamental regulatory initiatives implemented by FERC during that time frame that directly impact our U.S. businesses:

(a)

FERC approval of market based rate authority beginning in 1986 for many providers of wholesale generation; and



(b)

FERC issuance of Order #888 in 1996 mandating the functional separation of generation and transmission operations and requiring utilities to provide open access to their transmission systems.

        Several of our generation businesses in the U.S. currently operate as Qualifying Facilities ("QF's") as defined under PURPA. These businesses entered into long-term contracts with electric utilities that had a mandatory obligation at that time, as specified under PURPA, to purchase power from QF's at the utility's avoided cost (i.e. the likely costs for both energy and facilities that would have been incurred by the purchasing utility if that utility had to provide its own generating capacity). EPAct 2005 later amended PURPA to eliminate the mandatory purchase obligation in certain markets, but did so only on a prospective basis. Cogeneration facilities and small power production facilities that meet certain criteria can be QFs. To be a QF, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility's total energy output, and must meet certain efficiency standards. To be a QF, a small power production facility must generally use a renewable resource as its energy input and meet certain size criteria.

        Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators ("EWG's") as defined under EPAct 1992. These businesses were historically exempt from PUHCA 1935 and are also exempt from the Public Utility Holding Company Act of 2005 ("PUHCA 2005"), and subject to FERC approval, have the right to sell power at market-based rates, either directly to the wholesale market or to a third party offtaker such as a power marketer or utility/industrial customer. As an example, one of our larger generation businesses in the U.S. is Eastern Energy. A brief description of the regulatory environment under which Eastern Energy operates is provided below:

        Eastern Energy.    AES, through its Eastern Energy subsidiary, currently operates four coal-fired generation plants with a combined total capacity of 1,268 MW located in the state of New York. The plants sell power directly to the New York Independent System Operator ("NYISO"), a FERC approved regional operator which manages the transmission system in New York and operates the state's wholesale electricity markets. NYISO is regulated as an electric utility by the FERC and has an Open Access Transmission Tariff on file that incorporates rates and conditions for use of the

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transmission system and a Market Services Tariff that describes the rules and conditions of use for the various markets.

        The NYISO wholesale power markets are based on a combination of bilateral contracts, contracts for differences ("CFDs") which financially settle relative to an agreed upon index or floating price, and NYISO-administered day-ahead and real-time energy markets. The day-ahead market includes energy, regulation and operating reserves and is a financially binding commitment to produce or replace the products sold. The real time market, which also offers energy, regulation and operating reserves, is a balancing market and is not a financially binding commitment but rather a best effort standard. NYISO uses location based marginal pricing (i.e., pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand throughout the region) calculated at each node to account for congestion on the grid. Generators are paid the location marginal price at their node, while the end customer pays a zonal price that is the average of nodes within a zone. The market has a $1,000 per MWh cap on bids for energy. However, market rules also incorporate scarcity pricing mechanisms when the market is short of required operating reserves that can result in energy prices above $1,000 per MWh.

        In addition to our generation businesses, we also own IPL, a vertically integrated utility located in Indiana. A brief description of the regulatory environment under which IPL operates is provided below:

        IPL.    As a regulated electric utility, IPL is subject to regulation by the FERC and the Indiana Utility Regulatory Commission ("IURC"). As indicated below, the financial performance of IPL is directly impacted by the outcome of various regulatory proceedings before the IURC and FERC.

        IPL is subject to regulation by the IURC with respect to the following: its services and facilities; the valuation of property; the construction; purchase or lease of electric generating facilities; the classification of accounts; rates of depreciation; retail rates and charges; the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue); the acquisition and sale of some public utility properties or securities; and certain other matters.

        IPL's tariff rates for electric service to retail customers (basic rates and charges) are set and approved by the IURC after public hearings ("general rate case"). General rate cases, which have occurred at irregular intervals, include the participation of consumer advocacy groups and certain customers. The last general rate case for IPL was completed in 1995. In addition, pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all utilities at least once every four years, but the IURC has the authority to review the rates of any utility in its jurisdiction at any time it chooses. Such reviews have not been subject to public hearings.

        The majority of IPL customers are served pursuant to retail tariffs that provide for the monthly billing or crediting to customers of increases or decreases, respectively, in the actual costs of fuel (including purchased power costs) consumed from estimated fuel costs embedded in basic rates, subject to certain restrictions on the level of operating income. These billing or crediting mechanisms are referred to as "trackers". This is significant because fuel and purchased power costs represent a large and volatile portion of IPL's total costs. In addition, IPL's rate authority provides for a return on IPL's investment and recovery of the depreciation and operation and maintenance expenses associated with certain IURC-approved environmental investments. The trackers allow IPL to recover the cost of qualifying investments, including a return on investment, without the need for a general rate case.

        IPL may apply to the IURC for a change in its fuel charge every three months to recover its estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in its basic rates and charges. IPL must present evidence in each fuel adjustment charge ("FAC") proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power, or both, so as to provide electricity to its retail customers at the lowest cost reasonably possible.

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        Independent of the IURC's ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. Additionally, customer refunds may result if IPL's rolling 12-month operating income, determined at quarterly measurement dates, exceeds IPL's authorized annual net operating income and there are not sufficient applicable cumulative net operating income deficiencies against which the excess rolling twelve month net operating income can be offset.

        In IPL's two most recently approved FAC filings (FAC 81 and 82), the IURC found that IPL's rolling annual jurisdictional retail electric net operating income was lower than the authorized annual jurisdictional net operating income. However, in IPL's FAC 76 through 80 filings, the IURC found that IPL's rolling annual jurisdictional retail electric net operating income was greater than the authorized annual jurisdictional net operating income. Because IPL has a cumulative net operating income deficiency, IPL has not been required to make customer refunds in their FAC proceedings. However, in an effort to allay concerns raised by the IURC regarding IPL's level of earnings, in IPL's IURC approved FAC 79 and 80 IPL provided voluntary credits to its retail customers totaling $30 million and $2 million, respectively. IPL recorded a $30 million deferred fuel regulatory liability in March 2008 and a $2 million deferred fuel regulatory liability in June 2008, with corresponding and respective reductions against revenues for these voluntary credits. Approximately $30.3 million has been applied in the form of offsets against fuel charges that customers would have otherwise been billed during June 1, 2008 through December 31, 2008 and approximately $1.7 million remains to be applied as of December 31, 2008.

        IPL has participated in the restructured wholesale energy market since its implementation April 1, 2004. The restructured wholesale energy market is operated by Midwest Independent System Operator, Inc. ("MISO") and under the jurisdiction of the FERC. Prior to the implementation of these markets, IPL dispatched its generation and purchased power resources directly to meet its demands. In the MISO markets, IPL is obligated to offer its generation and to bid its demand into the market on an hourly basis. The MISO settles these hourly offers and bids based on location based marginal prices (i.e., pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand throughout the MISO region). The MISO evaluates the market participants' energy injections into, and withdrawals from, the system to economically dispatch the entire MISO system on a five-minute basis. Market participants are able to hedge their exposure to congestion charges, which result from constraints on the transmission system, with certain Financial Transmission Rights ("FTRs"). Participants are allocated FTRs each year and are permitted to purchase additional FTRs. As anticipated, and in keeping with similar market start-ups around the world, location marginal prices are volatile, and there are process, data and model issues requiring editing and enhancement. IPL and other market participants have raised concerns with certain MISO transactions and the resolution of those items could impact our results of operations.

        In IPL's March 2006 proceeding (FAC 71) before the IURC, a consumer advocacy group representing some of IPL's industrial customers requested that a sub-docket be established. Through the sub-docket, the industrial group was seeking a review of various FAC components including a review of IPL's treatment of transmission losses through ISO and an IURC order requiring IPL to provide customer refunds for past charges and changes to future ratemaking. Because of the uncertain outcome of the FAC 71 sub-docket, the IURC orders in IPL's FAC 71 through 81 proceedings had approved IPL's FAC factors on an interim basis, subject to refund. In December 2008, the IURC issued an order in which it determined that IPL should continue its current treatment of transmission losses and therefore removed the "subject to refund" provisions in its FAC 71 through 81 orders, as it pertains to the FAC 71 sub-docket.

        Mexico.    Mexico has a single national electricity grid (referred to as the "National Interconnected System"), covering nearly all of Mexico's territory. The only exception is the Baja California peninsula

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which has its own separate electricity system. Article 27 of the Mexican Constitution reserves the generation, transmission, transformation, distribution, and supply of electric power exclusively to the Mexican State for the purpose of providing a "public service". The Federal Electricity Commission ("CFE"), by virtue of Article 1 of the Energy Law, is granted sole and exclusive responsibility for providing this public service as it relates to the supply, transmission and distribution of electric power.

        In 1992, the Energy Law was amended to allow private parties to invest in certain activities in the Mexico electrical power market, under the assumption that "self-supply" generation of electric power is not considered a public service. These reforms allowed private parties to obtain permits from the Ministry of Energy for (i) generating power for self-supply; (ii) generating power through co-generation processes; (iii) generating power through independent production; (iv) small-scale production and (v) importing and exporting electrical power. Beneficiaries holding any of the permits contemplated under the Energy Law are required to enter into PPAs with the CFE with regard to all surplus power produced. It is under this basis that AES's Mérida ("Mérida") and TEG/TEP facilities operate. Mérida, a majority owned 484 MW generation business, provides power exclusively to CFE under a long-term contract. TEG/TEP provides the majority of its output to two offtakers under long-term contracts, and can sell any excess or surplus energy produced to CFE at a predetermined day-ahead price.

Europe & Africa

        European Union.    European Union ("EU") member states are required to implement EU legislation, although there is a degree of disparity as to how such legislation is implemented and the pace of implementation in the respective member states. EU legislation covers a range of topics which impact the energy sector, including market liberalization and environmental legislation. The Company has subsidiaries which operate existing generation businesses in a number of countries which are member states of the EU, including the Czech Republic, Hungary, the Netherlands, Spain and the United Kingdom. The Company also has subsidiaries which are in the process of constructing a generation plant in Bulgaria. Bulgaria became a member state of the EU as of January 1, 2007.

        The principles of market liberalization in the EU electricity and gas markets were introduced under the Electricity and Gas Directives. In 2005, the European Commission ("the Commission"), the legislative and administrative body of the EU, launched a sector-wide inquiry into the European gas and electricity markets. In the context of the electricity market, the inquiry has to date focused on identifying issues related to price formation in the electricity wholesale markets and the role of long-term agreements as a possible barrier to entry with a view to improving the competitive situation. In January 2007, the Commission published a proposal for a new common energy policy for Europe. In November 2008, the Commission published a second Strategic Energy Review aimed at developing the concept of a common European Energy Policy. It focused mainly on security of supply and infrastructure development. The Strategic Energy Review proposed reviews of the Gas Storage Directive in 2010 and an update of the Oil Stocks Directives.

        In October 2008, Energy Ministers reached political agreement on the "Third Liberalism Package," which includes five pieces of legislation, Electricity and Gas Directives, Electricity and Gas Regulations and Agency Regulation, which are expected to be passed by Parliament in early 2009 and come into force at the national level in 2009/2010. Little progress was made on this legislation during the fourth quarter of 2008, as legislative efforts focused instead on the "Green Package." The Green Package consists of 3 directives (Carbon Capture & Storage, EU Emissions Trading Scheme ("ETS"), and the Renewables Directive) which were agreed by the European Parliament in December 2008, along with a decision on Green House Gas burden sharing. The key elements of the Green Package include:

•

A 20% reduction in EU GHG emissions by 2020, as compared with 1990 levels, or 30% if other developed nations agree to take similar action by 2020;

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•

The ETS caps will deliver 21% GHG reduction by 2020 compared to 2005, distribution will be skewed to favor lower GDP member states, and auctioning will be phased in for some member states power sectors;



•

20% increase in energy efficiency; and



•

Minimum 10% target for renewable energy by 2020.

        Progress in the implementation of the directives referred to above varies from member state to member state. AES generation businesses in each member state will be required to comply with the relevant measures taken to implement the directives. See "Air Emissions" below, for a description of these Directives.

        Kazakhstan.    Under the present regulatory structure, the electricity generation and supply sector in Kazakhstan is mainly regulated by the Ministry of Energy and Mineral Resources (the "Ministry"), the Agency for protection of competition (the "AZK") and the Agency for Regulation of Natural Monopolies (the "Agency"). Each has the necessary authority for the supervision of the Kazakhstan power industry. However, the continuous changes in the law result in certain contradictions between different laws and regulations. This in turn results in uncertainty in the regulatory environment of the power sector.

        Kazakhstan has a wholesale power market, where generators and customers are free to sign contracts at negotiated prices. The power market infrastructure is evolving into a functioning centralized trading system. Since 2004, power producers, guaranteed suppliers and wholesale traders have been required to purchase and sell part of their electricity volumes on the electronic centralized power trading market. State-owned entities and natural monopolies are obligated to buy power through tenders and centralized trading. The wholesale transmission grid is owned by state-owned company KEGOC, which also acts as the system operator. The government is planning to introduce a real-time balancing market in 2009.

        To date, the Agency approves and regulates all tariffs for power transmission and distribution. Under the law, power companies which the AZK considers dominant entities must notify the Agency of the proposed increase of their prices and the Agency has the right to veto such proposed tariff increases. Further, the Agency has the right to request a decrease in the applicable tariffs and/or request introduction of the fixed prices for those power companies with prior record of anti-monopoly violations. In addition, the government introduced price regulation of the power sales from the Northern zone of the wholesale market to the southern region of Kazakhstan, and power companies involved in such transactions require approval for any tariff increase from the AZK.

        Two hydro plants which are under AES concession, Ust-Kamenogorsk and Shulbinsk, together with Ust-Kamenogorsk TET, all located in the Eastern Kazakhstan region, are recognized by the AZK as dominant entities in the Eastern Kazakhstan regional market because their aggregated share in the electricity supply commodity market in the region is 70%. These businesses are required to notify the AZK about any power price increases for regional customers. Additionally, in December 2008, Shulbinsk was included in the dominant companies list for the Taldykorgan region and Irtysh Power and Light together with Sogrinsk CHP were included in the dominant list of the East Kazakhstan region. Ekibastuz GRES, which is under AES management, must obtain approval from the AZK for power price increases for its customers in the southern region of Kazakhstan.

        Effective January 1, 2008, the Prime Minister of Kazakhstan ordered all generating plants in Kazakhstan to maintain fourth quarter 2007 price levels through the first quarter of 2008 in order to help moderate high inflation rates in Kazakhstan. Beginning in April 2008, the government permitted power plants to increase the electricity tariffs charged to their electricity retail companies by 13.6% for the remainder of 2008 and eliminated the electricity price restrictions for other customers.

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        In 2008, the parliament adopted a new competition law and amendments to the Electricity Law and Natural Monopoly legislation, which became effective as of January 2009. According to the new amendments to the Electricity Law, the Ministry should determine the groups of technologically identical power generation companies and set upper price ceilings for each group of power companies for seven years. In cases where such price ceiling is too low to support new investments, a power generation company will be able to apply for investment tariffs. The Ministry and the AZK have rights jointly to approve the investment programs, approve the investment tariffs and sign an investment contract with a power company. The legislation envisages large fines in the case of failures to implement investment programs. Trading companies will be prohibited and power plants will be able to conduct trading activities only in order to provide electricity supply to its customers during emergency shutdowns.

        The new competition law excludes from the list of antimonopoly violations agreed actions between affiliated companies. Amendments to the Natural Monopoly law give additional authority to the Agency to control allowed costs of natural monopoly companies and impose responsibility on these companies to eliminate non-technical losses within the timeframes set by the Agency. The law eliminates the price regulation of power companies recognized as dominant entities and the price regulation of power sales from the Northern to the southern region of Kazakhstan.

        In 2008, the Company, through an indirect wholly owned subsidiary, sold its assets in Northern Kazakhstan, including AES Ekibastuz LLP, the operator of the AES Ekibastuz power plant, and Maikuben West LLP, the owner of the AES Maikuben coal mine. In 2008, the Company continued to manage these businesses pursuant to a management agreement. The Company is retaining its facilities in Eastern Kazakhstan, including Sogrinsk CHP and Ust-Kamenogorsk CHP; its facilities under concession agreements, Shulbinsk HPP and Ust-Kamenogorsk HPP; and its trading business, Nurenergoservice L.L.P.

        Cameroon.    The law governing the Cameroonian electricity sector was passed in December 1998. The regulator is the Electricity Sector Regulatory Agency ("ARSEL") and its role is regulating and ensuring the proper functioning of the electricity sector, supervising the process of granting concessions, licenses and authorizations to operators, monitoring the application of the electricity regulation by the operators of the sector, approving and/or publicizing the regulated tariffs in the sector and safeguarding the interests of electricity operators and consumers. ARSEL has the legal status of a Public Administrative Establishment and is placed under the dual technical supervisory authority of the Ministries charged with electricity and finance.

        The concession agreement of July 2001 between the Republic of Cameroon and Sonel covers a twenty-year period. The first three years constituted a grace period to permit resolution of issues existing at the time of the privatization. In 2006, Sonel and the Cameroonian government signed an amended concession agreement. The amendment updates the schedule for investments to more than double the number of people Sonel serves over the next 15 years and provides for upgrading the generation, transmission and distribution system. Additionally, the concession agreement amended the tariff structure that results in an electricity price based on a reasonable return on the generation, transmission and distribution asset base and a pass through of a portion of fuel costs associated with increased thermal generation in years when hydrology is poor. The amended concession agreement has also reduced the cost of connection to facilitate access to electricity in Cameroon.

        Nigeria.    Nigeria's electricity sector consists of a generation market comprised of approximately 6 GW of installed capacity, with the state-owned entity, Power Holding Company of Nigeria ("PHCN") holding approximately 88% of the market share and two IPPs holding the remaining 12%. The IPPs, of which AES Nigeria Barges Ltd. ("AESNB") is one, maintain long term contracts with PHCN as the sole offtaker.

        All of Nigeria's distribution and transmission networks and companies are owned by state entities.

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        In March 2005, President Obasanjo signed the Power Sector Reform Bill into law, enabling private companies to participate in transmission and distribution in addition to electricity generation that had previously been legalized. The government has separated PHCN into eleven distribution firms, six generating companies, and a transmission company, all of which plan to be privatized. Several problems, including union opposition, have delayed the privatization indefinitely. However, it is envisaged that after the privatization process, the power sector will transform into a fully liberalized market.

        The Nigerian Electricity Regulatory Commission ("NERC") has also been established to regulate the electricity sector including the setting of tariffs and industry standards for future electricity sector development. NERC has asked the Company to revalidate our generation license. As part of the revalidation exercise, NERC is imposing certain conditions on the Company which are in conflict with its PPA and which may result in additional costs. The Company is reviewing the terms of the new license and plans to negotiate its terms and conditions to make them more consistent with our existing PPA. At this time, it is not clear what might be the final outcome of these negotiations. Under the terms of the PPA, the Company has a right to pass through any such additional cost and there is no cap. At present we estimate that the additional cost, if any, due to the license will be about $1 million.

        Hungary.    The Hungarian market has one main interconnected system. The state-owned electricity wholesaler, MVM, is the dominant exporter, importer and wholesaler of electricity. MVM's affiliated company, MAVIR is the Hungarian transmission system operator. Currently, Hungary is dependent on energy imports (mainly from Russia) since domestic production only partially covers consumption. Magyar Energia Hivatal (MEH), is the government entity responsible for regulation of the electricity industry in Hungary.

        With the adoption of a new Electricity Act by Hungary in 2007, which became effective January 1, 2008, Hungary is taking the final legislative step to implement a fully liberalized electricity market. By virtue of the Electricity Act, all customers become eligible to choose their electricity supplier. In the competitive market, generators sell capacity to wholesale traders, distribution companies, other generators, electricity traders and eligible customers at an unregulated price.

        Shortly before its accession to the European Union, the Hungarian government notified the European Commission of arrangements concerning compensation to the state owned electricity wholesaler, MVM. The Commission decided to open a formal investigation in 2005 to determine whether or not any government subsidies were provided by MVM to its suppliers which were incompatible with the common market. In June 2008, the Commission reached its decision that the PPAs, including AES Tisza's PPA, contain elements of illegal state aid. The decision requires Hungary to terminate the PPAs within six months of the June 2008 publication of the decision, and to recover the alleged illegal state aid from the generators within ten months of publication. Hungary and the Commission are in the process of resolving confidentiality matters relating to the wording of the decision, which has not yet been notified by the Commission to the generators. AES Tisza is challenging the Commission's decision in the Court of First Instance of the European Communities. Referring to the Commission's decision, Hungary adopted act number LXX of 2008 which terminates all long-term PPAs in Hungary, including AES Tisza's PPA, as of December 31, 2008, and requires generators to repay the alleged illegal state aid that was allegedly received by the generators through the PPAs, and provides for the possibility to offset stranded costs of the generators from the repayable state aid. Depending on the outcome of these events, there could be a material impact on the Company.

        At the end of 2006 and for all of 2007, the Hungarian government reintroduced administrative pricing for all electricity generators, overriding PPA pricing, including the pricing in AES Tisza's PPA. In January 2007, AES Summit Generation Limited, a holding company associated with AES Tisza's operations in Hungary, and AES Tisza notified the Hungarian government of a dispute concerning its

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acts and omissions related to AES's substantial investments in Hungary in connection with the reintroduction of the administrative pricing for Hungarian electricity generators. In conjunction with this, AES Summit and AES Tisza have commenced International Centre for Settlement of Investment Disputes ("ICSID") arbitration proceedings against Hungary under the Energy Charter Treaty in connection with Hungary's reintroduction of the administrative pricing for Hungarian electricity generators. In the meantime, pursuant to the new Electricity Act in force from January 1, 2008, administrative pricing for electricity generators was subsequently abolished.

        Hungary, pursuant to act number LXVII of 2008 introduced a special tax to be levied on energy companies including companies such as AES Tisza. The rate of the special tax is 8% and it is valid for two years, i.e., 2009 and 2010.

        Ukraine.    The electricity sector in Ukraine is regulated by the National Energy Regulatory Commission ("NERC"). Electricity costs to end users in Ukraine consist of three main components: 1) the wholesale market tariff is the price at which the distributor purchases energy on the wholesale market, 2) the distribution tariff covers the cost of transporting electricity over the distribution network, 3) the supply tariff covers the cost of supplying electricity to an end user. The total cost permitted by the regulator under the distribution and supply tariff each year is referred to as DVA. The distribution and supply tariffs for the five privatized distribution companies in Ukraine are established by the NERC on an annual basis, at which time an operational expense allowance is adjusted for inflation and the tariff is adjusted for the amount of capital that was invested for the year and the amount of energy that was distributed. A change in the methodology was effected at the end of 2007 with respect to the treatment of wages and salaries such that the adjustment for inflation replaced by an allowance based on the average industrial wage in the country.

        Due to Parliamentary elections in 2006, there were significant staff changes in the key regulatory agencies. In particular, a new Minister of Energy and a new NERC Chairman were appointed. NERC twice authorized 25% increases in end user tariffs for residential customers in 2006. During 2006, the wholesale electricity market price increased approximately 18% due to increases in fuel prices and changes in the pricing arrangements for thermal generating companies. During 2007, the wholesale electricity market price increased by 21% and during 2008, it increased by 49%.

        At the end of 2008, the tariff methodology for the calculation of the DVA in AES Ukraine's tariffs was to be comprehensively reviewed, including the rate of return on initial investment, operational expenses treatment, and definition and valuation of the rate base. However, in late 2008, NERC introduced minimal and short term changes into the tariff methodology with a view to delaying a comprehensive review until 2010. The delay is due to NERC's intention to develop a new methodology applicable to all distribution and supply companies. Short term changes implemented in 2009 include (a) setting rates of return on initial investment at the level of 15% after tax for 2009, (b) wages and salaries treatment remaining as per the mechanism introduced in 2007, (c) operational expenses subject to indexation by inflation and (d) other operational expenses subject to adjustment based on actual expenses given reasonable substantiation. In 2010, a comprehensive tariff methodology review will take place addressing the issues of (1) rate of return on investment, (2) rate base revaluation, and (3) operational expense allowance treatment.

        During the tariff review for 2009, NERC policies were directed by the provisions of the Presidential decree "On Additional Measures for Overcoming the Financial Crisis". This decree introduced a moratorium on natural monopolists' price increases until the financial situation in the Ukraine stabilizes. The DVA (total cost permitted in tariffs) approved for 2009, however, increased 3.8% for AES Kievoblenergo and 5.4% for AES Rivneenergo.

        United Kingdom.    AES Kilroot ("Kilroot") is subject to regulation by the Northern Ireland Authority for Utility Regulation ("NIAUR"). Under the terms of the generating license granted to Kilroot, the NIAUR has the right to review and, subject to compliance with certain procedural steps

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and conditions, require the early termination in 2010 of the long-term PPAs under which Kilroot currently supplies electricity to Northern Ireland Electricity ("NIE") until 2024.

        On March 21, 2007, Order 2007 (Single Wholesale Market—Northern Ireland) was enacted, which provided for the introduction and regulation of a single wholesale electricity market for Northern Ireland and the Republic of Ireland that began operation in November of 2007. The legislation grants powers to the Department of Enterprise, Trade and Investment, or NIAER, for a period of two years to modify existing arrangements within the electricity market in Northern Ireland, including the power to modify existing licenses and/or require the amendment or termination of existing agreements or arrangements, to allow for the creation of a single wholesale electricity market. Modifications have been made to Kilroot's license and agreements to accomplish the objectives of the single market and to allow for the separation of NIE into constituent bodies and the extraction of the management of the transmission system ("SONI") from NIE. These activities have been completed with reasonably minimal impact and with the maintenance of existing underlying guarantees for Kilroot.

        Revenues from the new market include a regulated capacity and an energy payment based on the system marginal price ("SMP"). Bidding principles restrict bids to short run marginal cost ("SRMC"). Total annual capacity payments are calculated as the product of the annualized fixed cost of a best new entrant ("BNE") peaking plant multiplied by the capacity required to meet the security standard. This capacity pot is then distributed on the basis of plant availability.

        Despite the new market mechanisms, Kilroot has continued to operate under its existing PPA which is able to subsist within the single wholesale market, although operating dispatch instructions are now a function of the new market inputs and system constraints and no longer the exclusive decision of NIE. The impact on the business has been minimal as the relatively higher price of gas has led Kilroot (a coal-fired plant) to be dispatched consistently during peak winter demand. However, NIAUR sought to invoke the introduction of the single electricity market ("SEM") as a rationale for the early termination in 2010 of the long-term PPAs between Kilroot and NIE. Kilroot challenged by way of judicial review proceedings the determination of NIAUR that the introduction of the SEM constituted requisite arrangements to allow such early termination. The hearing duly took place in May 2008 and found in favor of the Regulator. Although this grants the ability to the Regulator to terminate the contracts from 2010, the current expectation is that due to the value of the CO₂ allowances (that passes through to the consumer while Kilroot is under contract), the likely earliest date that cancellation would be invoked is after 2012 (when free allowances are due to cease).

        Following receipt of a complaint from Friends of the Earth claiming that the existing long-term PPAs with NIE in Northern Ireland are incompatible with EU law, the EC has requested certain information from the UK authorities related to these agreements, including information pertaining to the Kilroot power plant and PPA in order to enable the EC to assess the complaint. The Department of Enterprise Trade and Investment ("DETI") submitted a response to the EC on January 12, 2007 and there have been no further developments.

        Czech Republic.    The electricity industry in the Czech Republic is dominated by three vertically integrated companies ("CEZ", "E.ON" and "PRE") that both supply and distribute power. CEZ, which owns approximately 70% of the installed capacity, produced approximately 73% of the Czech Republic's energy in 2007. Electricity distribution is also dominated by these three entities: CEZ (62%); E.ON (25%); and PRE (13%). There are 22 generators with installed capacity of over 50 MW and 25 generators with installed capacities between 5-50 MW, none of which have a market share greater than 3%. In accordance with EU directives regarding market liberalization, all customers are able to select their energy supplier.

        Since August 2007, the Prague Energy Exchange has been trading energy in the form of base load and peak load on a monthly, quarterly and annual basis. The majority of electricity is, however, still traded on a bilateral basis between generators and distributors, independent traders (there are six

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major active traders plus more than 20 smaller traders in the market) and also between generators and final customers. In February 2008, a day ahead spot market was incorporated into the Energy Exchange as existed in Slovakia. As of March 2009, the Prague Energy Exchange will also include Hungary trades. AES Bohemia's electricity, steam, water and compressed air output is governed under bilateral contracts with industrial and municipal customers in the surrounding area.

        Spain.    Spain is a member of the EU and as such the Spanish Government has been taking steps to liberalize the country's electricity sector in accordance with EU directives. Since January 1, 2003, all customers have been eligible to choose their electricity supplier.

        AES currently operates and holds a 71% ownership interest in a 1,199 MW natural gas-fired plant located in Cartagena on the southeast coast of Spain. The plant sells energy into the Pan-Iberian electricity market ("MIBEL"). The MIBEL market was created in January 2004 when Spain and Portugal signed a formal agreement. This new market allows generators in the two countries to sell their electricity on both sides of Spanish-Portuguese border as one single market. OMEL, Spain's energy market regulator and Portugal's equivalent, OMIP, merged in April 2006, creating OMI, a single operator for the MIBEL electricity market, which began in the summer of 2006 with the objective of setting up a mechanism for harmonizing tariffs and of integrating the current management functions of the spot and forward markets.

        The state-owned transmission company, Red Eléctrica de España ("REE") owns 99% of the 400 kilovolt ("kV") grid and 98% of the 220 kV network. REE also operates as system operator and is responsible for technical management of the system and for monitoring transmission. Under the country's energy plan, REE plans to invest in strengthening the mainland grid, connecting new plants and improving interconnection throughout the country. Cartagena has two agreements in place with the REE: one governing the construction of the interconnection and the other specifying the specific terms and conditions of access.

        In September 2002, the Spanish Cabinet approved a 10-year energy plan which focuses on meeting the country's future energy requirements. The plan also reflects reliance on Special Systems which represents energy output from the facilities supplied by renewable energy sources, waste and cogeneration plants, and provides for new renewable tariffs (Royal Decree 661/207) and favorable regulation.

        Turkey.    The wholesale generation and distribution market in Turkey is primarily a bilateral market dominated by state-owned entities. The state-owned Electricity Generation Company ("EUAS") and its subsidiaries comprise approximately 24 GW of generation capacity and represent approximately 48% of the market. Private producers (with public off take) account for another 35%, and auto-producers and other industrial parties, the remaining 17%. The transmission network is owned and controlled by TEIAS, the State Transmission Company. TETAS, the Wholesale Market Pool, sets wholesale price based on average procurement costs from EUAS, auto-producers and Build Own Operate/Build Own Transfer/Transfer of Operating Rights producers. This wholesale price represents the buying price for TEDAS, the State Distribution Company, which controls distribution in 20 out of 21 regions. There is also a balancing spot market, with prices typically 20% higher than TETAS, which is growing and has a capacity of 70 Gigawatt hours ("GWh") of daily trade. The automatic price mechanism which is meant to halt the government subsidization has been approved, and implementation commenced in July 2008. With this mechanism, all major cost items (foreign exchange, gas price increases, inflation, among others) are expected to be reflected in the tariff. As a result, mid term market wholesale prices are expected to converge to the current spot market prices.

        Distribution companies can procure 100% of their needs from TETAS, but can also source up to 15% from other sources. Additionally, eligible customers, using greater than 1.2 GWh annually, can contract through channels other than TEDAS.

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        Retail electricity prices are determined by the distribution company or companies and approved by the electricity regulator, EMRA.

        Turkey has introduced a "renewable" feed-in tariff that sets a floor for renewable generation (wind and run of river hydro) for the first 10 years of operation. The floor is between 5.0 - 5.5 € cents per kWh and decreed by EMRA each year. AES's Turkey hydro assets fall under the renewable feed-in tariffs.

        In efforts to move to a fully liberalized market, Turkey began a formal tender process to privatize three of its distribution companies owned by the State Distribution Company in 2006. As of the end of 2008, the distribution companies in four regions (Baskent, Sakarya, Konya and Aras) have been put out to tender and the remaining distribution companies are expected to be privatized in 2009. The Turkish government has also announced plans to privatize all the state-owned generation assets by the 2009-2010 period, except for large hydro plants.

Asia & Middle East

        China:    In 2005, the National Development and Reform Commission ("NDRC") released interim regulations governing on-grid tariffs, along with two other regulations governing transmission and retail tariffs. Pursuant to the interim regulations, the on-grid tariffs shall be appraised and ratified by the pricing authorities by reference to the economic life of power generation projects and determined in accordance with the principle of allowing IPPs to cover reasonable costs and to obtain reasonable returns. Such costs were defined to be the average costs in the industry and reasonable returns will be calculated on the basis of the interest rate of China's long-term Treasury bond plus certain percentage points. In addition to the foregoing tariff setting mechanism, China's central government also issued a tariff adjustment policy allowing the on-grid tariffs to be pegged to the fuel price in the case of significant fluctuations in fuel price. Seventy percent of the increase in fuel costs may be passed through in the tariff. Pursuant to this policy, the tariffs of coal-fired facilities in China were increased in 2005 and 2006, and there were two rounds of tariff increments in 2008 to alleviate the escalation of fuel price; however, such adjustments fell short of compensating all businesses for coal price increases in 2008 in accordance with the above mentioned policy.

        Pursuant to the Renewable Energy Law of China, which came into effective on January 1, 2006, renewable resources such as wind, solar, biomass, geo-thermal, and hydro enjoy unrestricted generation and dispatch, and local grid interconnection is mandated to such plants. With a view to implementing the Renewable Energy Law, on August 2, 2007, various central government agencies jointly issued the Temporary Measures for Dispatching Electricity Generated by Energy Conservation Projects. Under this regulation, power plants are categorized into various groups and each group will, under certain circumstances, enjoy priority dispatch over the subsequent groups. The first group are renewable energy power plants, namely wind, hydro, solar, biomass, tidal-wave, geo-thermal and landfill gas power plants that satisfy certain environmental standards. The second group is nuclear power plants. The third group is power plants using 'modern coal' which includes co-generation power plants, and power plants utilizing residual heat, residual gas, coal-gangue (or waste coal) and coal mine methane. The last three groups are natural gas, conventional coal and oil-fired power plants. In other words, power plants using renewable resources will enjoy priority dispatch over power plants using fossil fuels. This is in line with the requirement that renewable energy power plants will enjoy unrestricted generation and dispatch under the Renewable Energy Law, as well as the Chinese government's policy objective to encourage comprehensive utilization of resources in an energy-efficient and environmental-friendly manner.

        In 2007, the Chinese government also issued a number of rules and procedures that govern the shutdown of small coal or oil-fired power plants. The types of plants to be shutdown include: (i) power plants with a capacity under 50 MW; (ii) power plants with a capacity of up to 100 MW which are over 20 years old; (iii) power plants with a capacity of up to 200 MW whose equipment has reached an end

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of its useful life; and (iv) power plants that have coal consumption rates that are higher than either 10% above the applicable provincial average or 15% above the national average. The shutdown procedures have been set in place to ensure that certain smaller power plants are appropriately shutdown and replaced by larger and more efficient power plants. The purpose of such rules and regulations is again in accord with China's policy to achieve energy conservation and emission reduction. The Hefei business, in which AES held a 70% interest, was shut down pursuant to this policy. A termination agreement with the offtaker was reached and executed on March 30, 2008 and the Hefei business received a termination payment in the amount of $39 million on March 31, 2008.

        India.    India's power sector is regulated by the Central Electricity Regulatory Commission ("CERC") at the national level and respective State Electricity Regulatory Commissions ("SERCs") at the state level. CERC is responsible for regulating interstate generation and central transmission, while intra-state generation, distribution and transmission are regulated by SERCs.

        In 2003, the Government of India enacted the Electricity Act 2003 to establish a framework for a multi-seller-multi-buyer model for the electricity industry and introduced significant changes in India's electricity sector. In accordance with the Electricity Act the Government of India came out with the National Electricity Policy in February 2005 and in January 2006 published the National Tariff Policy. The policies established deadlines to implement different provisions of the Electricity Act. However, the pace of actual implementation of the reform process is contingent on the respective state governments and SERCs, as electricity is a "concurrent" subject in India's constitution.

        Under the Electricity Act, there is no license required to set up generation plants and generators are allowed to sell to state utilities, traders, and open access consumers. The access to consumers is subject to regulatory provisions on transmission corridor availability and payment of cross subsidy surcharge. Under the National Tariff Policy, sales since the end of 2006 from new IPP's to distribution utilities are required to be on a competitive bidding basis. Two power exchanges have received licenses from CERC and have started operations in the past year. However, the volume of power trading on the power exchanges is short term and small, as the bulk of power is still traded through long term bilateral contracts.

        Philippines.    The Philippines have three major island grids—Luzon, Visayas, and Mindanao. Luzon is the largest grid, accounting for 79% and 71% respectively of installed capacity and gross generation. The Luzon and Visayas grids are interconnected through undersea cables. In June 2001, the Philippines Congress issued the Electric Power Industry Reform Act of 2001 ("EPIRA"), aiming at liberalizing the electricity sector, and transforming it from a single-buyer model in which National Power Company ("NPC") plays a dominant role in generation, transmission, and distribution, to a competitive market model, in which NPC is privatized and competition is introduced in generation and distribution.

        The Energy Regulatory Commission ("ERC") was created to be the governing body for the restructured power industry and to promote competition, encourage market development, ensure customer choice and penalize abuse of market power. As part of its role, the ERC regulates the rates charged by transmission and distribution companies and as such approves cost recovery of contracts between generators and distribution companies.

        The Power Sector Assets and Liabilities Management Corporation ("PSALM") was created in July 2001 to manage the sale, disposition and privatization of the NPC generation assets. As of 2008, PSALM has sold 2,771 MW of NPC owned generation assets (including the sale of the 660 MW Masinloc plant to AES), and is in the process of selling an additional 1,213 MW of capacity.

        EPIRA mandates PSALM to select and appoint qualified entities called Independent Power Producer Administrators ("IPPA") to administer and manage the energy output that has been contracted by NPC with IPPs. PSALM has initially appointed three independent trading teams to act as IPPA for these contracts, but it has now initiated the process for the sale of 1,700 MW of contracted capacity.

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        The Wholesale Electricity Spot Market ("WESM") started commercial operation in the Luzon grid in June 2006 with the primary objective of establishing a competitive, efficient, transparent, and reliable spot market for electricity. The market is organized around both bilateral contracts and a mandatory pool and spot market with the spot market consisting of an hour ahead market (ex-ante) and a real-time (ex-post) market. Each generating unit submits hourly bids. The dispatch is arranged by the lowest to highest bid price and the spot price is set by the marginal price of the last dispatched unit following the merit order.

Environmental and Land Use Regulations

        Overview.    The Company is subject to various international, national, state and local environmental and land use laws and regulations. These laws and regulations primarily relate to discharges into the air and air quality, discharge of effluents into water and the use of water, waste disposal, remediation, noise pollution, contamination at current or former facilities or waste disposal sites, wetlands preservation and endangered species. Many of the countries in which the Company does business also have laws and regulations relating to the siting, construction, permitting, ownership, operation, modification, repair and decommissioning of, and power sales from, such assets. In addition, international projects funded by the International Finance Corporation, the private sector lending arm of the World Bank are subject to World Bank environmental standards, which tend to be more stringent than local country standards. The Company often has used advanced environmental technologies (such as circulating fluidized bed ("CFB") coal technologies or advanced gas turbines) in order to minimize environmental impacts.

        Environmental laws and regulations affecting electric power generation facilities are complex, change frequently and have become more stringent over time. The Company has incurred and will continue to incur capital costs and other expenditures to comply with environmental laws and regulations. See Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Expenditures in this Form 10-K for more detail. If these regulations change or the enforcement of these regulations becomes more rigorous, the Company and its subsidiaries may be required to make significant capital or other expenditures to comply. There can be no assurance that the businesses operated by the subsidiaries of the Company would be able to recover any of these compliance costs from their counterparties or customers such that the Company's consolidated results of operations, financial condition and cash flows would not be materially adversely affected.

        Various licenses, permits and approvals are required for our operations. Failure to comply with permits or approvals, or with environmental laws, can result in fines, penalties, capital expenditures, interruptions or changes to our operations. While the Company has at times been out of compliance with environmental laws and regulations, past non-compliance has not resulted in the revocation of material permits or licenses and has not had a material adverse effect on our business, financial conditions or results of operations and we have expeditiously corrected the non-compliance as required. See Item 3—Legal Proceedings in this Form 10-K for more detail with respect to environmental disclosure.

        Greenhouse Gas Laws, Protocols and Regulations.    In 2008, the Company's subsidiaries operated electric power generation businesses which had total approximate direct CO₂ emissions of 83.8 million metric tonnes (ownership adjusted). Approximately 41.5 million metric tonnes of the 83.8 million metric tonnes were emitted in the United States (both figures ownership adjusted). The following is an overview of both the regulations that currently apply to our businesses and those that may be imposed over the next few years. Such regulations could have a material adverse effect on the electric power generation businesses of the Company's subsidiaries and on the Company's consolidated results of operations, financial condition and cash flows. In addition, while the Company through its climate solutions initiatives is developing and implementing projects to produce GHG offsets for use by the Company and/or for sale, as set forth in the Risk Factor entitled " Our renewable energy projects and

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other initiatives face considerable uncertainties including development, operational and regulatory challenges", there is no guarantee that these projects will be successful, especially in light of the global financial crisis and the Company's increased focus on preserving liquidity, which will likely result in slower growth for these activities. Further, even if our GHG offsets projects are successful, the level of potential benefit is unclear given current uncertainties regarding legislation and/or litigation concerning GHG emissions.

International

        In July 2003, the European Community "Directive 2003/87/EC on Greenhouse Gas Emission Allowance Trading" was created, which requires member states to limit emissions of CO₂ from large industrial sources within their countries. To do so, member states are required to implement EC-approved national allocation plans ("NAPs"). Under the NAPs, member states are responsible for allocating limited CO₂ allowances within their borders. Directive 2003/87/EC does not dictate how these allocations are to be made, and NAPs that have been submitted thus far have varied their allocation methodologies. For these and other reasons, uncertainty remains with respect to the implementation of the European Union Emissions Trading System ("EU ETS") that commenced in January 2005. The European Union has announced that it intends to keep the EU ETS in place after 2012, even if the Kyoto Protocol is not extended. The Company's subsidiaries operate seven electric power generation facilities, and another subsidiary has one under construction, within six member states which have adopted NAPs to implement Directive 2003/87/EC. Based on its current analyses, the Company does not expect that achieving and maintaining compliance with the NAPs to which its subsidiaries are subject will have a material impact on its consolidated operations or results. In particular, the risk and benefit associated with achieving compliance with applicable NAPs at several facilities of the Company's subsidiaries are not the responsibility of the Company's subsidiaries as they are subject to contractual provisions that transfer the costs associated with compliance to contract counterparties. However, in the event that such counterparties challenge or dispute these provisions, there can be no assurance that the Company and/or the relevant subsidiary would prevail in any such dispute. Furthermore, even if the Company and/or the relevant subsidiary does prevail, it would be subject to the cash and administrative burden associated with such dispute. Certain Company subsidiaries will, however, bear some or all of the risk and benefit associated with compliance with applicable NAPs at certain facilities. Based upon anticipated operations, CO₂ emission allowance allocations, and the costs to acquire offsets and emission allowances for compliance purposes, the Company's subsidiaries have not to date incurred material costs to comply with Directive 2003/87/EC and applicable NAPs, however, there can be no guarantees that compliance will not have a material adverse effect on our business in future periods.

        On February 16, 2005, the Kyoto Protocol became effective. The Kyoto Protocol requires the industrialized countries that have ratified it to significantly reduce their GHG emissions, including CO₂. The vast majority of developing countries which have ratified the Kyoto Protocol have no GHG reduction requirements. Many of the countries in which the Company's subsidiaries operate have no reduction obligations under the Kyoto Protocol. In addition, of the 29 countries that the Company's subsidiaries currently operate in, all but two—the United States (including Puerto Rico) and Kazakhstan—have ratified the Kyoto Protocol. While we have developed and are implementing certain climate solutions projects under the Clean Development and Joint Implementation Mechanisms of the Kyoto Protocol, there is no guarantee that we will be successful in developing these. To date, compliance with the Kyoto Protocol and EU ETS has not had a material adverse effect on the Company's consolidated results of operations, financial condition and cash flows. In December 2008, a United Nations Climate Change Conference was held in Poznan, Poland. Over 180 countries sent representatives and a majority agreed to continue to negotiate further reductions in GHG emissions for the period beginning after 2012 when Kyoto Protocol expires. At present, the Company cannot predict

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whether compliance with the Kyoto Protocol or any agreements reached at the Climate Change Conference will have a material impact on the Company in future periods.

        Even though it has been announced that the EU ETS will remain in place even if the Kyoto Protocol expires in 2012, there remains significant uncertainty with respect to the implementation of NAPs post-2012. The EU has indicated that a portion of the emission allowances given to member states will need to be auctioned under the NAPs and the Company cannot predict with any certainty if compliance with such programs will have a material adverse effect on its consolidated operations or results.

        Countries in Latin America and Asia in which subsidiaries of the Company operate may also choose to adopt regulations that directly or indirectly regulate GHG emissions from coal plants. For example, in April 2008 a Chilean law, was enacted that requires a percentage of all new power purchase contracts held after August 31, 2007 be supplied by renewable sources. The Company's subsidiary has developed a plan for complying with the law. See Regulatory Matters—Latin America—Chile. Another example is in China. One of the ways that China has chosen to address its stated goals of energy conservation and CO₂ emissions reduction is by putting regulations and procedures in place that govern the shut down of certain small coal and oil-fired power plants and encourage replacement with larger more efficient power plants. The Hefei project, formerly operated by subsidiaries of the Company in China, was shut down pursuant to these regulations. A termination agreement with the Hefei offtaker was executed on March 30, 2008 and a subsidiary of the Company received a termination payment in the amount of $39 million on March 31, 2008. The Company does not currently anticipate that implementation of such regulations would have a material adverse affect on the Company's consolidated financial condition or results of operations. See Regulatory Matters—Asia & Middle East—China. Although the Company does not currently believe that CO₂ laws and regulations that have been adopted to date in countries in Latin America and Asia in which subsidiaries of the Company operate will have a material adverse effect on the Company's consolidated financial condition or results of operations, the Company cannot predict with any certainty if future laws and regulations in these countries regarding CO₂ emissions will have a material adverse effect on the Company's consolidated financial condition or results of operations.

United States

        Currently in the United States there are no Federal mandatory GHG emissions reduction programs (including CO₂) affecting the electric power generation facilities of the Company's subsidiaries. The U.S. Congress is debating a number of proposed GHG legislative initiatives, but to date there have been no new federal laws regulating GHG emissions. Although several bills have been introduced in the U.S. Congress that would require reductions in CO₂ emissions, the Company is not able to predict whether any federal mandatory CO₂ emissions reduction program will be adopted and implemented in the immediate future. The new administration has, however, requested the development of new federal proposals by Congress and the U.S. EPA that could lead to the adoption of a mandatory program to reduce GHG emissions through, for example, an economy-wide cap-and-trade program, a carbon tax or a combination of both. The Company will continue to monitor new developments with respect to the possible federal regulation of CO₂ emissions from electricity power generation facilities.

        On April 2, 2007, the U.S. Supreme Court issued its decision in a case involving the regulation of CO₂ emissions from motor vehicles under the U.S. Clean Air Act ("CAA"). The Court ruled that CO₂ is a pollutant which potentially could be subject to regulation under the CAA and that the U.S. Environmental Protection Agency (the "U.S. EPA") has a duty to determine whether CO₂ emissions contribute to climate change or to provide some reasonable explanation why it will not exercise its authority. In response to the Court's decision, on July 11, 2008, the U.S. EPA issued an advanced notice of proposed rulemaking ("ANPR") to solicit public input on whether CO₂ emissions should be

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regulated from both mobile and stationary sources under the CAA. The U.S. EPA has not yet made any such determination. However, the Court's decision and stimulus from the new administration, regulators, members of Congress, states, non-governmental organizations, private parties and the courts and other factors could lead to a determination by the U.S. EPA to regulate CO₂ emissions from mobile and stationary sources, including electric power generation facilities. The Company will continue to monitor developments with respect to the regulation of CO₂ emissions under the CAA.

        Ten northeastern states have entered into a memorandum of understanding under which the states coordinate to establish rules that require reductions in CO₂ emissions from power plant operations within those states. This initiative is called the Regional Greenhouse Gas Initiative ("RGGI"). A number of these states in which our subsidiaries have generating facilities, including Connecticut, Maryland, New York and New Jersey, have implemented rules to effectuate RGGI. RGGI, which became effective January 1, 2009, imposes a cap on baseline CO₂ emissions during the 2009 through 2014 period, and mandates a ten percent reduction in CO₂ emissions during the 2015 to 2019 period. RGGI establishes a cap-and-trade program whereby power plants will require a carbon allowance for each ton of CO₂. Unlike the previously implemented federal sulfur dioxide ("SO₂") and NO_X cap-and-trade emissions programs, RGGI requires that CO₂ emitters acquire CO₂ allowances either from a RGGI auction or in the secondary emissions trading market, except for several small set-aside accounts for long term contracted plants and voluntary renewable energy. The auction rules include a minimum reserve price of $1.86 per allowance. This reserve price is subject to change. In addition, the auction platform and auction results are subject to review by an independent market monitoring firm. The first such auction occurred on September 25, 2008 and the clearing price per allowance was $3.07. The second such auction occurred on December 17, 2008 and the clearing price per allowance was $3.38. The third such auction is scheduled for March 18, 2009.

        The Company's Eastern Energy business is located in New York. Under the New York RGGI rule, each budgeted source of CO₂ emissions is required to surrender one CO₂ allowance for each CO₂ metric tonne emitted during a three-year compliance period. All fossil fuel powered generating facilities in New York that have a generating capacity of 25 or more MW are subject to the rule. In January 2009, Indeck Energy brought a legal challenge to the regulations adopted by three New York State agencies to implement RGGI. The Company will closely monitor developments with respect to this litigation.

        The Company's Thames business is located in Connecticut. The State of Connecticut passed legislation, effective July 1, 2007, which requires that the Connecticut Department of Environmental Protection develop necessary regulations to implement RGGI. The regulations adopted to implement RGGI include an auction of CO₂ emission allowances except for several set-aside accounts. AES Thames is eligible for a set-aside for the first compliance period, 2009-2011, which allows CO₂ allowances to be purchased at $2 per allowance in 2009, and $2 per allowance plus a consumer price indexing in years 2010 and 2011. Eligibility for the second compliance period, 2012-2014, is still to be determined.

        The Company's Warrior Run business is located in Maryland. In April 2006, the Maryland General Assembly passed the Maryland Healthy Air Act which, among other thing things, required the State of Maryland to join RGGI. The Maryland Department of Environment ("MDE") adopted regulations that require 100% of the allowances the State receives to be auctioned except for several small allowance set-aside accounts. The Maryland MDE regulations include a safety valve to control the economic impact of the CO₂ cap-and-trade program. If the auction closing price reaches $7, up to 50% of a year's allowances will be reserved for purchase by electric power generation facilities located within Maryland at $7 per allowance, regardless of auction prices.

        The Company's Red Oak business is located in New Jersey. The State of New Jersey adopted the Global Warming Response Act in July 2007 which established goals for the reduction of GHG emissions in the State. In furtherance of these goals, in January 2008, additional state legislation

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authorized the New Jersey Department of Environmental Protection ("NJDEP") to develop and adopt RGGI regulations and the NJDEP RGGI regulations became effective in 2008. The regulations adopted to implement RGGI include an auction of CO₂ emission allowances with procedures for the fixed-price sale of allowances to facilities with long-term power purchase contracts, directs allocation of allowances to cogeneration facilities meeting specified thermal efficiency criteria, and includes a CO₂ allowance set-aside designed to support the voluntary renewable energy market.

        In 2008, of the approximately 41.5 million metric tons of CO₂ emitted in the United States by the businesses operated by our subsidiaries (ownership adjusted), approximately 11.8 million metric tonnes were emitted in U.S. states participating in RGGI. We believe that due to the absence of allowance allocations, RGGI could have a material adverse impact on the Company's consolidated results of operations, financial condition and cash flows. While CO₂ emissions from businesses operated by subsidiaries of the Company are calculated globally in metric tonnes, RGGI allowances are denominated in short tons. (1 metric tonne equals 2,200 pounds and 1 short ton equals 2,000 pounds.) For forecasting purposes, the Company has modeled the impact of CO₂ compliance for 2009-2011 for its businesses that are subject to RGGI and that may not be able to pass through compliance costs. The model includes a conversion from metric tonnes to short tons as well as the impact of some market recovery by merchant plants and contractual and regulatory provisions. The model also utilizes an allowance price of $3.38 per allowance under RGGI. The source of this per tonne allowance estimate was the clearing price in the second RGGI allowance auction held in December 2008. Based on these assumptions, the Company estimates that the RGGI compliance costs could be approximately $29.1 million per year from 2009 through 2011, which is the last year of the first RGGI compliance period. Given all of the uncertainties surrounding RGGI, including the challenge to New York State's RGGI program and those discussed in the "Business—Regulatory Matters—Environmental and Land Use Regulations" section of this Form 10-K, and the fact that the assumptions utilized in the model may prove to be incorrect, there is a significant risk that our actual compliance costs under RGGI will differ from our estimates by a material amount and that our model could underestimate our costs of compliance.

        The Company's Southland and Placerita businesses are located in California. On September 27, 2006, the Governor of California signed the Global Warming Solutions Act of 2006, also called Assembly Bill 32 ("A.B. 32"). A.B. 32 directs the California Air Resources Board to promulgate regulations that will require the reduction of CO₂ and other GHG emissions to 1990 levels by 2020. On December 11, 2008, the California Air Resources Board unanimously adopted the Scoping Plan that outlines how the reductions in AB 32 will be met. The Scoping Plan follows closely the recommendations put forth by the California Public Utilities Commission and the California Energy Commission on February 8, 2008, including the first jurisdictional deliverer being the point of regulation for AB 32. A key component of the Scoping Plan is a cap-and-trade market that will be developed in coordination with the Western Climate Initiative as detailed below. In addition, other key recommendations include increasing energy efficiency and increasing the renewable portfolio goals to 33%. This program is expected to become effective in 2012.

        In February 2007, the governors of the Western U.S. states (Arizona, New Mexico, California, Washington and Oregon) established the Western Climate Initiative ("WCI"). The WCI has since been joined by two other states (Montana and Utah) and four Canadian provinces (British Columbia, Manitoba, Ontario, and Quebec). Participating states and provinces have agreed to cut GHG emissions to 15% below 2005 levels by 2020 and they are considering the implementation of a cap-and-trade program for the electricity industry to achieve this reduction. On September 23, 2008, the WCI issued its design recommendations for a cap-and-trade program which would apply to in-state electricity generators and the first jurisdictional deliverer of electricity into a WCI partner state. The final regulatory design of this program is not yet known.

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        The Company owns IPL which is located in Indiana. On November 15, 2007, six Midwestern state governors (including the governor of Indiana) and the premier of Manitoba signed the Midwestern Greenhouse Gas Reduction Accord ("MGGRA") committing the participating states and province to reduce GHG emissions through the implementation of a cap-and-trade program. Three states (including Indiana) and the province of Ontario have signed as observers.

        The Company owns a power generation facility in Hawaii. On June 30, 2007, the governor of Hawaii signed GHG legislation. By December 1, 2009, Hawaii's Greenhouse Gas Emissions Reduction Task Force will deliver to the legislature a work plan and regulatory scheme designed to reduce emissions of greenhouse gases to 1990 levels by 2020.

        At this time, other then the estimated impact of CO₂ compliance noted above for certain of its businesses that are subject to RGGI, the Company has not estimated the costs of compliance with other potential U.S. federal, state or regional CO₂ emissions reductions legislation or initiatives, such as A.B. 32, WCI, MGGRA and potential Hawaii regulations, due to the fact that these proposals are in earlier stages of development and any final regulations, if adopted, could vary drastically from current proposals. Although complete specific implementation measures for any federal regulations, A.B. 32, WCI, MGGRA and the Hawaiian regulations have yet to be finalized, these GHG-related initiatives will likely affect a number of the Company's U.S. subsidiaries. Any federal, state or regional legislation or regulations adopted in the U.S. that would require the reduction of GHG emissions could have a material adverse effect on the Company's consolidated results of operations, financial condition and cash flows.

        The possible impact of any future federal legislation or regulations or any regional or state proposal will depend on various factors, including but not limited to:

•

the geographic scope of legislation and/or regulation (e.g., federal, regional, state), which entities are subject to the legislation and/or regulation (e.g., electricity generators, load serving entities, electricity deliverers, etc.), the enactment date of the legislation and/or regulation and the compliance deadlines set forth therein;



•

the level of reductions of CO₂ being sought by the regulation and/or legislation (e.g., 10%, 20%, 50%, etc.) and the year selected as a baseline for determining the amount or percentage of mandated CO₂ reduction (e.g., 10% reduction from 1990 CO₂ emission levels, 20% reduction from 2000 CO₂ emission levels, etc.);



•

the legislative structure (e.g., a CO₂ cap-and-trade program, a carbon tax, CO₂ emission limits, etc.);



•

in any cap-and-trade program, the mechanism used to determine the price of emission allowances or offsets to be auctioned by designated governmental authorities or representatives;



•

the price of offsets and emission allowances in the secondary market, including any price floors on the costs of offsets and emission allowances and price caps on the cost of offsets and emission allowances;



•

the operation of and emissions from regulated units;



•

the permissibility of using offsets to meet reduction requirements (e.g., type of offset projects allowed, the amount of offsets that can be used for compliance purposes, any geographic limitations regarding the origin or location of creditable offset projects) and the methods required to determine whether the offsets have resulted in reductions in GHG emissions and that those reductions are permanent (i.e., the verification method);

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•

whether the use of proceeds of any auction conducted by responsible governmental authorities is reinvested in developing new energy technologies, is used to offset any cost impact on certain energy consumers or is used to address issues unrelated to power;



•

how the price of electricity is determined at the affected businesses, including whether the price includes any costs resulting from any new CO₂ legislation and the potential to transfer compliance costs pursuant to legislation, market or contract, to other parties;



•

any impact on fuel demand and volatility that may affect the market clearing price for power;



•

the effects of any legislation or regulation on the operation of power generation facilities that may in turn affect reliability;



•

the availability and cost of carbon control technology; and



•

any opportunities to change the use of fuel at the generation facilities of our subsidiaries or opportunities to increase efficiency.

NY Consent Decree

        In 2005, the Company entered into a Consent Decree (the "2005 Consent Decree") with the State of New York, and New York State Electric and Gas Corporation ("NYSEG") which resolves violations of CAA requirements alleged to have occurred at the Greenridge, Westover, Jennison and Hickling plants prior to the Company's acquisition of such plants. Under the terms of the 2005 Consent Decree, the Company is required to undertake projects to reduce emissions of air pollutants ("Upgrade Projects") or to cease operations of electric generating units at the plants. The Company completed an Upgrade Project at Greenridge in 2006 and a similar project at Westover in 2008 and has ceased operations of the electric generating units at Hickling and Jennison. In accordance with the 2005 Consent Decree, the Company is required to provide notifications to the New York State Department of Environmental Conservation ("NYSDEC") regarding the status of the Upgrade Projects and upon completion to propose new final emissions limits for NYSDEC's approval. The Company has received NYSDEC approval for proposed final emissions limits applicable to AES Greenridge and will submit proposals for new final emission limits to NYSDEC for approval after the Upgrade Project at Westover completes commercialization testing and final ratification in 2009.

        Other Air Emission Regulations.    The CAA and various state laws and regulations regulate emissions of air pollutants, including SO₂, NOx and particulate matter ("PM"). The applicable rules and the steps taken by the Company to comply are discussed in further detail below.

        Regarding NOx emissions, the U.S. EPA has required adjustments to state implementation plans (the "NOx SIP Call") so that coal-fired electric generating facilities in 21 U.S. states and the District of Columbia had to either (i) reduce their NOx emissions to levels equal to allowances under the plan or (ii) purchase NOx emissions allowances from other operators to meet actual emissions levels by May 31, 2004.

        Subsequently, the U.S. EPA finalized two rules that are relevant to our U.S. coal-fired power plants. The first rule, the "Clean Air Interstate Rule" ("CAIR"), was promulgated by the EPA on March 10, 2005, and required allowance surrender for SO₂ and NOx emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR contemplated two implementation phases. The first phase was to begin in 2009 and 2010 for NOx and SO₂, respectively. A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015. To implement the required emission reductions for this rule, the states were to establish emission allowance-based "cap-and-trade" programs. CAIR was subsequently challenged in federal court and on July 11, 2008, the U.S. Court of Appeals for the D.C. Circuit issued an opinion striking down CAIR. On September 19, 2008, EPA filed a petition for rehearing and rehearing en banc. On October 21,

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2008, the Court issued an order requesting that certain petitioners, including AES Beaver Valley and AES Warrior Run, file a response to EPA's petition by November 5, 2008, indicating whether any such petitioners were seeking a vacatur of CAIR and whether the Court should stay its mandate until EPA promulgates a revised rule. As of December 31, 2008, the Company had assets of approximately $11.6 million related to these SO₂ and NOx emission allowance programs. On December 23, 2008, the Court issued an opinion and order denying petitions for rehearing and, rather than vacating CAIR as originally ordered, remanding the ease to EPA without vacatur to enable EPA to remedy CAIR's flaws in accordance with the Court's July opinion. While the Court did not impose a timeline on EPA, the Court did indicate that the stay was not intended to be indefinite.

        The second rule, the Clean Air Mercury Rule ("CAMR"), was promulgated on March 15, 2006 and as proposed required reductions of mercury emissions from coal-fired power plants in two phases. The first phase was to begin in 2010 and require nationwide reduction of coal-fired power plant mercury emissions from 48 to 38 tons per year. The second phase was to begin in 2018 and require nationwide reduction of mercury emissions from these sources from 38 tons per year to 15 tons per year. CAMR also established stringent mercury emission performance standards for new coal-fired power plants. However, on February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit ruled that CAMR as promulgated violated the CAA and vacated the rule. U.S. EPA and an industry trade association subsequently appealed the decision to the U.S. Supreme Court. On February 3, 2009, an amendment to the CAA was introduced in the U.S. House of Representatives that would require the EPA to promulgate mercury emission standards for electric generating units. The EPA would have one year from the date the amendment is enacted to set maximum achievable control technology standards for electric generating units pursuant to Section 112 of the CAA. The amendment is designed to prevent EPA from regulating mercury emissions through a cap-and-trade program. When the D.C. Circuit vacated CAMR in February 2008, the court did not rule on whether such programs violate the CAA. On February 6, 2009, the Acting Solicitor General of the United States filed a motion in the U.S. Supreme Court to dismiss the EPA's request for review of the D.C. Circuit's February 2008 decision which vacated CAMR. According to the motion to dismiss, EPA intends to develop maximum achievable control technology standards for electric generating units pursuant to Section 112 of the CAA. The industry trade association's appeal is still pending and the U.S. Supreme Court has not yet decided whether to hear the appeal.

        Also, a number of states have indicated that they intend to impose more stringent emission limitations on power plants within their states rather than promulgate rules consistent with the originally contemplated CAIR and CAMR cap-and-trade programs. In response to CAIR, CAMR and potentially more stringent U.S. state initiatives on SO₂ and NOx emissions, subsidiaries of the Company completed installing selective catalytic reduction ("SCR") and other NOx control technologies at three coal-fired units of our subsidiary, IPL. Subsidiaries of the Company also completed a multi-pollutant control project at its Greenridge power plant in the state of New York. In addition, Westover construction of a similar project at its power plant in New York in 2008. The Westover project is expected to complete commercialization testing and final notification in 2009. In addition, a flue gas desulphurization scrubber upgrade project was completed at the IPL Petersburg power plant, and construction of an SCR system at our Deepwater petroleum coke-fired power plant near Houston, Texas was completed in March 2007.

        While the exact impact and cost of CAIR, any new federal mercury rules and any related state proposals cannot be established until, in the case of CAIR, the states complete the process of assigning emission allowances to our affected facilities, and in the case of the other rules, until they are promulgated, there can be no assurance that the Company's business, financial conditions or results of operations would not be materially and adversely affected by such rules.

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        NYSDEC previously promulgated regulations requiring electric generators to reduce SO₂ emissions by 50% below current CAA standards. The SO₂ regulations began to be phased in beginning on January 1, 2006 with implementation to have been completed by January 1, 2008. These regulations also establish stringent NOx reduction requirements year-round, rather than just during the summertime ozone season.

        In July 1999, the U.S. EPA published the "Regional Haze Rule" to reduce haze and protect visibility in designated federal areas. On June 15, 2005, U.S. EPA proposed amendments to the Regional Haze Rule that, among other things, set guidelines for determining when to require the installation of "best available retrofit technology" ("BART") at older plants. The amendment to the Regional Haze Rule required states to consider the visibility impacts of the haze produced by an individual facility, in addition to other factors, when determining whether that facility must install potentially costly emissions controls. The Regional Haze Rule was further amended on October 6, 2006 when U.S. EPA promulgated a rule allowing states to impose alternatives to BART, including emissions trading, if such alternatives were demonstrated to be more effective than BART. States were required to submit their regional haze state implementation plans to the U.S. EPA by December 2007.

        In Europe the Company is, and will continue to be, required to reduce air emissions from our facilities to comply with applicable EC Directives, including Directive 2001/80/EC on the limitation of emissions of certain pollutants into the air from large combustion plants (the "LCPD"), which sets emission limit values for NOx, SO₂, and particulate matter for large-scale industrial combustion plants for all member states. Until June 2004, existing coal plants could "opt-in" or "opt-out" of the LCPD emissions standards. Those plants that opted out will be required to cease all operations by 2015 and may not operate for more than 20,000 hours after 2008. Those that opted-in, like the Company's AES Kilroot facility in the United Kingdom, must invest in abatement technology to achieve specific SO₂ reductions. Kilroot is installing a new flue gas desulphurization system that is scheduled for commission in the first quarter of 2009. The Company's other coal plants in Europe are either exempt from the Directive due to their size or have opted-in but will not require any additional abatement technology to comply with the LCPD.

        Water Discharges.    The Company's facilities are subject to a variety of rules governing water discharges. In particular the Company is evaluating the impact of the U.S. Clean Water Act Section 316(b) rule regarding existing power plant cooling water intake structures issued by the U.S. EPA in 2005 (69 Fed. Reg. 41579, July 9, 2004) and the subsequent Circuit Court of Appeals decision which vacated significant portions of the rule (Docket Nos. 04-6692 to 04-6699). The rule as originally issued would affect 12 of the Company's U.S. power plants and the rule's requirements would be implemented via each plant's National Pollutant Discharge Elimination System ("NPDES") water quality permit renewal process. These permits are usually processed by state water quality agencies. To protect fish and other aquatic organisms, the 2004 rule requires existing steam electric generating facilities to utilize the best technology available for cooling water intake structures. To comply, a steam electric generating facility must first prepare a Comprehensive Demonstration Study to assess the facility's effect on the local aquatic environment. Since each facility's design, location, existing control equipment and results of impact assessments must be taken into consideration, costs will likely vary. The timing of capital expenditures to achieve compliance with this rule will vary from site to site. On January 25, 2007 the United States Court of Appeals for the Second Circuit decision (Docket Nos. 04-6692 to 04-6699) vacated and remanded major parts of the 2005 rule back to U.S. EPA. In November 2007, three industry petitioners sought review of the Second Circuit's decision by the U.S. Supreme Court and this review was granted by the U.S. Supreme Court in April 2008. Oral arguments were held in December 2008 and a decision by the U.S. Supreme Court is expected in 2009. The Second Circuit's decision, coupled with the appeal pending before the Supreme Court may result in further delays in implementing the rule at those affected facilities located in states which have either not been delegated authority to implement Section 316(b) of the U.S. Clean Water Act or are awaiting more specific direction from the U.S. EPA before proceeding. The U.S. EPA is currently drafting a new

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rule to address the Second Circuit's decision and while a draft of the new rule is expected to be issued later this year, it is possible that the U.S. EPA could delay the issuance of the draft rule pending a decision by the U.S. Supreme Court. Certain states in which the Company operates power generation facilities, such as New York, have been delegated authority and are moving forward with best technology available determinations in the absence of any final rule from U.S. EPA. At present, the Company cannot predict whether compliance with the anticipated new 316(b) rule will have a material impact on our operations or results.

        Waste Management.    In the course of operations, the Company's facilities generate solid and liquid waste materials requiring eventual disposal. With the exception of coal combustion products ("CCP"), its wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or recycling. CCP, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at some of our coal-fired power generation plant sites using engineered, permitted landfills. Waste materials generated at our electric power and distribution facilities include CCP, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree and land clearing wastes and polychlorinated biphenyl ("PCB") contaminated liquids and solids. The Company endeavors to ensure that all its solid and liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations.

Subsequent Events

        On December 23, 2008, in a transaction associated with the sale in November 2008 of 9.55% of the Company's shares in AES Gener, as further discussed in Item 8—Financial Statements and Supplementary Data, Note 17—Subsidiary Stock, the local Chilean SEC approved Gener's share issuance of approximately 945 million shares at a price of $162.50 Chilean Pesos. The proceeds of the share issuance were $246 million and Gener anticipates using these proceeds for future expansion plans, working capital and other operating needs. The preemptive rights period began on January 7, 2009 remained open for 30 days and closed on February 5, 2009. During the preemptive rights period AES, through its wholly-owned subsidiary, Cachagua, paid $175 million from the proceeds of the November 2008 share sale to maintain its current ownership percentage of approximately 70%.

        On February 9, 2009, the government of the Dominican Republic, the government-owned power companies and the power companies sector ("generation companies"), signed two Memorandums of Understanding (each an "MOU"). The first MOU provides for the settlement of outstanding 2008 accounts receivables ("2008 A/R") held by the generation companies from distribution companies through the payment of government-issued bonds of which the Company's three generation businesses have been allocated $110 million. This MOU also states that the bonds can be used to offset fiscal taxes, but that element will need to be approved by the National Congress of the Dominican Republic during their first legislative session of 2009. The second MOU acknowledges that the bond payment does not fully satisfy the outstanding 2008 A/R balance. The residual amount outstanding after the bond payment will be fully settled by the distribution companies, within a timeframe to be negotiated in the near future.

        It is AES' intention to accept these bonds as settlement for approximately $110 million of outstanding 2008 A/R, under the assumption that the bonds will have the ability to offset fiscal taxes. The Company's businesses will have approximately $58 million of 2008 A/R outstanding after the bond payment that will be subject to the terms of the second MOU. The intention of the distribution companies is to pay approximately $35 million of these receivables in 2009. Therefore, AES has appropriately reclassified $23 million to long-term receivables on the Company's Consolidated Balance Sheet included in Item 8 of this Form 10-K as of December 31, 2008.

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ITEM 1A.    RISK FACTORS

        You should consider carefully the following risks, along with the other information contained in or incorporated by reference in this Form 10-K. Additional risks and uncertainties also may adversely affect our business and operations including those discussed in Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K. If any of the following events actually occur, our business and financial results could be materially adversely affected.

Risks Associated with our Disclosure Controls and Internal Control over Financial Reporting

We recently completed the remediation of our material weaknesses in internal control over financial reporting. However, our disclosure controls and procedures may not be effective in future periods if our judgments prove incorrect or new material weaknesses are identified.

        For each of the fiscal quarters since December 31, 2004 through September 30, 2008, our management reported material weaknesses in our internal control over financial reporting. A material weakness is a deficiency (within the meaning of the Public Company Accounting Oversight Board ("PCAOB") Auditing Standard No. 5), or a combination of deficiencies, that adversely affects a company's ability to initiate, authorize, record, process, or report external financial data reliably in accordance with generally accepted accounting principles such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected. As a result of these material weaknesses, our management concluded that for each of the fiscal quarters since December 31, 2004 through September 30, 2008, we did not maintain effective internal control over financial reporting and concluded that our disclosure controls and procedures were not effective to provide reasonable assurance that financial information that we are required to disclose in our reports under the Exchange Act was recorded, processed, summarized and reported accurately.

        To address these material weaknesses in our internal control over financial reporting, each time we prepared our annual and quarterly reports we performed additional analyses and other post-closing procedures. These additional procedures were costly, time consuming and required us to dedicate a significant amount of our resources, including the time and attention of our senior management, toward the correction of these problems. Nevertheless, even with these additional procedures, the material weaknesses in our internal control over financial reporting caused us to have errors in our financial statements and since 2003 we had to restate our annual financial statements six times to correct these errors.

        The material weaknesses in our internal control over financial reporting also caused us to delay the filing of certain quarterly and annual reports with the SEC to dates that went beyond the deadline prescribed by the SEC's rules to file such reports. Under SEC rules, failure to timely file these reports prohibited us for a period of twelve months from offering and selling our securities pursuant to our shelf registration statement on Form S-3, which impaired our ability to access the capital markets through the public sale of registered securities in a timely manner. The failure to file our annual and quarterly reports with the SEC in a timely fashion also resulted in covenant defaults under our senior secured credit facility and the indenture governing certain of our outstanding debt securities. Such defaults required us to obtain a waiver from the lenders under the senior secured credit facility; however the default under the indentures was cured upon the filing of the reports within the permitted grace period. In addition to these problems, the material weaknesses in internal controls, the restatements of our financial statements and the delay in the filing of our annual and quarterly reports exposed us to other risks including, but not limited to:

•

litigation or an expansion of the SEC's informal inquiry into our restatements or the commencement of formal proceedings by the SEC or other regulatory authorities, which could require us to incur significant legal expenses and other costs or to pay damages, fines or other penalties;

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•

negative publicity;



•

ratings downgrades; or



•

the loss or impairment of investor confidence in the Company.

        As of December 31, 2008, our management has reported in this Annual Report on Form 10-K that for the first time in four years all of our previously identified material weaknesses had been remediated and that our internal control over financial reporting and our disclosure controls were effective. For a discussion of our completed remediation efforts and management assessment of our internal control over financial reporting and our disclosure controls, see Item 9A–Controls and Procedures in this Form 10-K. In making their assessment about the effectiveness of our internal control over financial reporting and our disclosure controls and procedures, management had to make certain judgments and it is possible that any number of their judgments were wrong and that our remediation efforts did not fully and completely cure the previously identified material weaknesses. There is also the possibility that there are other material weaknesses in our internal control that are unknown to us or that new material weaknesses may develop in the future. The existence of any material weakness in our internal control over financial reporting would subject us to all of the risks described above.

        Furthermore, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, changes in accounting practice or policy, or that the degree of compliance with the revised policies or procedures deteriorates over time. Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.

Our identification of material weaknesses in internal control over financial reporting caused us to miss deadlines for certain SEC filings and if further filing delays occur, they could result in negative attention and/or legal consequences for the Company.

        Our identification of the material weaknesses in internal control over financial reporting caused us to delay the filing of certain quarterly and annual reports with the SEC to dates that went beyond the deadline prescribed by the SEC's rules to file such reports.

        We did not timely file with the SEC our quarterly and annual reports for the year ended December 31, 2005, our quarterly reports for the second and third quarters of 2006, our annual report for the year ended December 31, 2006, and our quarterly report for the quarter ended March 31, 2007. Under SEC rules, failure to timely file these reports prohibited us for a twelve month period from offering and selling our securities pursuant to our shelf registration statement on Form S-3, which impaired our ability to access the capital markets through the public sale of registered securities in a timely manner.

        The failure to file our annual and quarterly reports with the SEC in a timely fashion also resulted in covenant defaults under our senior secured credit facility and the indenture governing certain of our outstanding debt securities. Such defaults required us to obtain a waiver from the lenders under the senior secured credit facility; however the default under the indentures was cured upon the filing of the reports within the permitted grace period.

        If we identify new material weaknesses, there will continue to be an increased risk that we will be unable to timely file future periodic reports with the SEC and that a related default under our senior secured credit facility and indentures could occur. In addition, the material weaknesses in internal controls, the restatements of our financial statements, and the delay in the filing of our annual and

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quarterly reports and any similar problems in the future could have other adverse effects on our business, including, but not limited to:

•

impairing our ability to access the capital markets, including, but not limited to the inability to offer and sell securities pursuant to a shelf registration statement on Form S-3;



•

litigation or an expansion of the SEC's informal inquiry into our restatements or the commencement of formal proceedings by the SEC or other regulatory authorities, which could require us to incur significant legal expenses and other costs or to pay damages, fines or other penalties;



•

additional covenant defaults, and potential events of default, under our senior secured credit facility and the indentures governing our outstanding debt securities, resulting from our failure to timely file our financial statements;



•

negative publicity;



•

ratings downgrades; or



•

the loss or impairment of investor confidence in the Company.

Risks Related to our High Level of Indebtedness

We have a significant amount of debt, a large percentage of which is secured, which could adversely affect our business and the ability to fulfill our obligations.

        As of December 31, 2008, we had approximately $18.1 billion of outstanding indebtedness on a consolidated basis. All outstanding borrowings under The AES Corporation's senior secured credit facility, our Second Priority Senior Secured Notes and certain other indebtedness are secured by certain of our assets, including the pledge of capital stock of many of The AES Corporation's directly-held subsidiaries. Most of the debt of The AES Corporation's subsidiaries is secured by substantially all of the assets of those subsidiaries. Since we have such a high level of debt, a substantial portion of cash flow from operations must be used to make payments on this debt. Furthermore, since a significant percentage of our assets are used to secure this debt, this reduces the amount of collateral that is available for future secured debt or credit support and reduces our flexibility in dealing with these secured assets. This high level of indebtedness and related security could have other important consequences to us and our investors, including:

•

making it more difficult to satisfy debt service and other obligations;



•

increasing the likelihood of a downgrade of our debt, which can cause future debt payments to increase and consume an even greater portion of cash flow;



•

increasing our vulnerability to general adverse economic and industry conditions;



•

reducing the availability of cash flow to fund other corporate purposes and grow our business;



•

limiting our flexibility in planning for, or reacting to, changes in our business and the industry;



•

placing us at a competitive disadvantage to our competitors that are not as highly leveraged; and



•

limiting, along with the financial and other restrictive covenants relating to such indebtedness, among other things, our ability to borrow additional funds as needed or take advantage of business opportunities as they arise, pay cash dividends or repurchase common stock.

        The agreements governing our indebtedness, including the indebtedness of our subsidiaries, limit, but do not prohibit, the incurrence of additional indebtedness. To the extent we become more leveraged, the risks described above would increase. Further, our actual cash requirements in the future may be greater than expected. Accordingly, our cash flows may not be sufficient to repay at maturity all

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of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. In recent months, these risks have increased as conditions in the global economy, including credit markets worldwide, have deteriorated dramatically. For further discussion of these global economic conditions and their potential impact on the Company, see Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Credit Crisis and the Macroeconomic Environment.

The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.

        The AES Corporation is a holding company with no material assets, other than the stock of its subsidiaries. All of The AES Corporation's revenue is generated through its subsidiaries. Accordingly, almost all of The AES Corporation's cash flow is generated by the operating activities of its subsidiaries. Therefore, The AES Corporation's ability to make payments on its indebtedness and to fund its other obligations is dependent not only on the ability of its subsidiaries to generate cash, but also on the ability of the subsidiaries to distribute cash to it in the form of dividends, fees, interest, loans or otherwise.

        However, our subsidiaries face various restrictions in their ability to distribute cash to The AES Corporation. Most of the subsidiaries are obligated, pursuant to loan agreements, indentures or project financing arrangements, to satisfy certain restricted payment covenants or other conditions before they may make distributions to The AES Corporation. In addition, the payment of dividends or the making of loans, advances or other payments to The AES Corporation may be subject to legal or regulatory restrictions. Business performance and local accounting and tax rules may limit the amount of retained earnings that may be distributed to us as a dividend. Subsidiaries in foreign countries may also be prevented from distributing funds to The AES Corporation as a result of foreign governments restricting the repatriation of funds or the conversion of currencies. Any right that The AES Corporation has to receive any assets of any of its subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, bankruptcy, insolvency or similar proceedings (and the consequent right of the holders of The AES Corporation's indebtedness to participate in the distribution of, or to realize proceeds from, those assets) will be effectively subordinated to the claims of any such subsidiary's creditors (including trade creditors and holders of debt issued by such subsidiary).

        The AES Corporation could receive less funds than it expects as a result of the current challenges facing the global economy, which could impact the performance of our businesses and their ability to distribute cash to The AES Corporation. For further discussion of the macroeconomic environment and its impact on our business, see Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Credit Crisis and the Macroeconomic Environment.

        The AES Corporation's subsidiaries are separate and distinct legal entities and, unless they have expressly guaranteed any of The AES Corporation's indebtedness, have no obligation, contingent or otherwise, to pay any amounts due pursuant to such debt or to make any funds available whether by dividends, fees, loans or other payments. While some of The AES Corporation's subsidiaries guarantee its indebtedness under its Senior Secured Credit Facility and certain other indebtedness, none of its subsidiaries guarantee, or are otherwise obligated with respect to, its outstanding public debt securities.

Even though The AES Corporation is a holding company, existing and potential future defaults by subsidiaries or affiliates could adversely affect The AES Corporation.

        We attempt to finance our domestic and foreign projects primarily under loan agreements and related documents which, except as noted below, require the loans to be repaid solely from the project's revenues and provide that the repayment of the loans (and interest thereon) is secured solely

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by the capital stock, physical assets, contracts and cash flow of that project subsidiary or affiliate. This type of financing is usually referred to as non-recourse debt or "project financing." In some project financings, The AES Corporation has explicitly agreed to undertake certain limited obligations and contingent liabilities, most of which by their terms will only be effective or will be terminated upon the occurrence of future events. These obligations and liabilities take the form of guarantees, indemnities, letter of credit reimbursement agreements and agreements to pay, in certain circumstances, the project lenders or other parties.

        As of December 31, 2008, we had approximately $18.1 billion of outstanding indebtedness on a consolidated basis, of which approximately $5.2 billion was recourse debt of The AES Corporation and approximately $12.9 billion was non-recourse debt. In addition, we have outstanding guarantees, letters of credit, and other credit support commitments which are further described in this Form 10-K in Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Parent Company Liquidity.

        Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total debt classified as current in our consolidated balance sheets related to such defaults was $129 million at December 31, 2008. While the lenders under our non-recourse project financings generally do not have direct recourse to The AES Corporation (other than to the extent of any credit support given by The AES Corporation), defaults there under can still have important consequences for The AES Corporation, including, without limitation:

•

reducing The AES Corporation's receipt of subsidiary dividends, fees, interest payments, loans and other sources of cash since the project subsidiary will typically be prohibited from distributing cash to The AES Corporation during the pendency of any default;



•

triggering The AES Corporation's obligation to make payments under any financial guarantee, letter of credit or other credit support which The AES Corporation has provided to or on behalf of such subsidiary;



•

causing The AES Corporation to record a loss in the event the lender forecloses on the assets;



•

triggering defaults in The AES Corporation's outstanding debt and trust preferred securities. For example, The AES Corporation's senior secured credit facility and outstanding senior notes include events of default for certain bankruptcy related events involving material subsidiaries. In addition, The AES Corporation's senior secured credit facility includes certain events of default relating to accelerations of outstanding debt of material subsidiaries; or



•

the loss or impairment of investor confidence in the Company.

        None of the projects that are currently in default are owned by subsidiaries that meet the applicable definition of materiality in The AES Corporation's senior secured credit facility in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. However, as a result of future write-down of assets, dispositions and other matters that affect our 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 of such subsidiary's debt, trigger an event of default and possible acceleration of the indebtedness under The AES Corporation's senior secured credit facility. The risk of such defaults may have increased as a result of the deteriorating global economy. For further discussion of these conditions, see Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Credit Crisis and the Macroeconomic Environment.

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Risks Associated with our Ability to Raise Needed Capital

The AES Corporation has significant cash requirements and limited sources of liquidity.

        The AES Corporation requires cash primarily to fund:

•

principal repayments of debt;



•

interest and preferred dividends;



•

acquisitions;



•

construction and other project commitments;



•

other equity commitments, including business development investments;



•

taxes; and



•

Parent Company overhead costs.

        The AES Corporation's principal sources of liquidity are:

•

dividends and other distributions from its subsidiaries;



•

proceeds from debt and equity financings at the Parent Company level; and



•

proceeds from asset sales.

        For a more detailed discussion of The AES Corporation's cash requirements and sources of liquidity, please see Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity in this 2008 Form 10-K.

        While we believe that these sources will be adequate to meet our obligations at the Parent Company level for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital or commercial lending markets, the operating and financial performance of our subsidiaries, exchange rates, our ability to sell assets, and the ability of our subsidiaries to pay dividends. Any number of assumptions could prove to be incorrect and therefore there can be no assurance that these sources will be available when needed or that our actual cash requirements will not be greater than expected. For example, in the current credit crisis, certain financial institutions have gone bankrupt. In the event that a bank who is party to our credit agreement or other facilities goes bankrupt or is otherwise unable to fund its commitments, we would need to replace that bank in our syndicate or risk a reduction in the size of the facility, which would reduce our liquidity. In addition, our cash flow may not be sufficient to repay at maturity the entire principal outstanding under our credit facilities and our debt securities and we may have to refinance such obligations. There can be no assurance that we will be successful in obtaining such refinancing and any of these events could have a material effect on us. For further discussion of these global economic conditions and their potential impact on the Company, see Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Credit Crisis and the Macroeconomic Environment.

Our ability to grow our business could be materially adversely affected if we were unable to raise capital on favorable terms.

        From time to time, we rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. Our ability to arrange for financing on either a recourse or non-recourse basis and the costs of such capital are dependent on numerous factors, some of which are beyond our control, including:

•

general economic and capital market conditions;

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•

the availability of bank credit;



•

investor confidence;



•

the financial condition, performance and prospects of The AES Corporation in general and/or that of any subsidiary requiring the financing; and



•

changes in tax and securities laws which are conducive to raising capital.

        Since 2007, credit conditions and credit markets have weakened considerably and deteriorated dramatically in 2008, which has made it difficult for many companies to arrange for financing on a recourse or non-recourse basis. For further discussion of these global economic conditions and their potential impact on the Company, see Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operation—Credit Crisis and the Macroeconomic Environment. Should future access to capital not be available to us, we may have to sell assets or decide not to build new plants or expand or improve existing facilities, either of which would affect our future growth.

A downgrade in the credit ratings of The AES Corporation or its subsidiaries could adversely affect our ability to access the capital markets which could increase our interest costs or adversely affect our liquidity and cash flow.

        If any of the credit ratings of The AES Corporation or its subsidiaries were to be downgraded, our ability to raise capital on favorable terms could be impaired and our borrowing costs would increase. Furthermore, depending on The AES Corporation's credit ratings and the trading prices of its equity and debt securities, counterparties may no longer be as willing to accept general unsecured commitments by The AES Corporation to provide credit support. Accordingly, with respect to both new and existing commitments, The AES Corporation may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace any credit support by The AES Corporation. There can be no assurance that such counterparties will accept such guarantees in the future. In addition, to the extent The AES Corporation is required and able to provide letters of credit or other collateral to such counterparties, it will limit the amount of credit available to The AES Corporation to meet its other liquidity needs.

We may not be able to raise sufficient capital to fund "greenfield" projects in certain less developed economies which could change or in some cases adversely affect our growth strategy.

        Part of our strategy is to grow our business by developing Generation and Utility businesses in less developed economies where the return on our investment may be greater than projects in more developed economies. Commercial lending institutions sometimes refuse to provide non-recourse project financing in certain less developed economies, and in these situations we have sought and will continue to seek direct or indirect (through credit support or guarantees) project financing from a limited number of multilateral or bilateral international financial institutions or agencies. As a precondition to making such project financing available, the lending institutions may also require governmental guarantees of certain project and sovereign related risks. There can be no assurance, however, that project financing from the international financial agencies or that governmental guarantees will be available when needed, and if they are not, we may have to abandon the project or invest more of our own funds which may not be in line with our investment objectives and would leave less funds for other projects. These risks have increased as a result of the recent credit crisis and the deteriorating global economy. For further discussion of these global economic conditions and their potential impact on the Company, see Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Credit Crisis and the Macroeconomic Environment.

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External Risks Associated with Revenue and Earnings Volatility

Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.

        Our exposure to currency exchange rate fluctuations results primarily from the translation exposure associated with the preparation of the Consolidated Financial Statements, as well as from transaction exposure associated with transactions in currencies other than an entity's functional currency. While the Consolidated Financial Statements are reported in U.S. Dollars, the financial statements of many of our subsidiaries outside the United States are prepared using the local currency as the functional currency and translated into U.S. Dollars by applying appropriate exchange rates. As a result, fluctuations in the exchange rate of the U.S. Dollar relative to the local currencies where our subsidiaries outside the United States report could cause significant fluctuations in our results. In addition, while our expenses with respect to foreign operations are generally denominated in the same currency as corresponding sales, we have transaction exposure to the extent receipts and expenditures are not denominated in the subsidiary's functional currency.

        We also experience foreign transaction exposure to the extent monetary assets and liabilities, including debt, are in a different currency than the subsidiary's functional currency. Moreover, the costs of doing business abroad may increase as a result of adverse exchange rate fluctuations. Our financial position and results of operations have been significantly affected by fluctuations in the value of a number of currencies, primarily the Brazilian real, Argentine peso, Chilean peso, Colombian peso and Philippine peso. As our Brazilian and Argentine businesses primarily identify their local currency as their functional currency, recent depreciation of these currencies has resulted in the increase of deferred translation losses (foreign currency translation adjustments recognized in accumulated other comprehensive loss) based on positive net asset positions. Devaluation has also resulted in foreign currency transaction losses primarily associated with U.S. Dollar debt at these businesses.

Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance.

        Some of our Generation businesses sell electricity in the wholesale spot markets in cases where they operate wholly or partially without long-term power sales agreements. Our Utility businesses and, to the extent they require additional capacity, our Generation businesses, also buy electricity in the wholesale spot markets. As a result, we are exposed to the risks of rising and falling prices in those markets. The open market wholesale prices for electricity are very volatile and often reflect the fluctuating cost of coal, natural gas, or oil. Consequently, any changes in the supply and cost of coal, natural gas, and oil may impact the open market wholesale price of electricity.

        Volatility in market prices for fuel and electricity may result from among other things:

•

plant availability;



•

competition;



•

demand for energy commodities;



•

electricity usage;



•

seasonality;



•

interest rate and foreign exchange rate fluctuation;



•

availability and price of emission credits;



•

input prices;

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•

hydrology and other weather conditions;



•

illiquid markets;



•

transmission or transportation constraints or inefficiencies;



•

availability of competitively priced renewables sources;



•

available supplies of natural gas, crude oil and refined products, and coal;



•

generating unit performance;



•

natural disasters, terrorism, wars, embargoes and other catastrophic events;



•

energy, market and environmental regulation, legislation and policies;



•

geopolitical concerns affecting global supply of oil and natural gas; and



•

general economic conditions in areas where we operate which impact energy consumption.

        The Company has faced gas curtailments in the past. For example, gas supply in the Argentine market is increasingly scarce and exports have been both taxed and curtailed. Gas supply curtailments can be exacerbated during the Argentine winter (May through September) when domestic demand for electricity experiences a seasonal increase. Since substantially all of the gas used in the Chilean power sector is currently imported from Argentina, gas curtailments can impact our Chilean operations through higher fuel costs and higher costs of purchased energy from the spot market. Our natural gas-fired plant in Southern Brazil, Uruguaiana, has also been impacted by limited fuel supply. Since 2004, Uruguaiana has had its gas supply interrupted from May to September. During this period, Uruguaiana purchases energy from the spot market and through bilateral contracts to fulfill its sales contracts and has paid higher fuel prices as a result. During the fourth quarter of 2007, the combination of gas curtailments and increases in the spot market price of energy triggered an impairment analysis of Uruguaiana's long-lived assets for recoverability. As a result of this impairment analysis, aggregate pre-tax impairment charges of $388 million were recognized in 2008 and 2007 which represents a full impairment of the fixed assets.

        In addition, our business depends upon transmission facilities owned and operated by others. If transmission is disrupted or capacity is inadequate or unavailable, our ability to sell and deliver power may be limited, which may have a material adverse impact on our business.

We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.

        We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity, fuel requirements and other commodities to lower our financial exposure related to commodity price fluctuations. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. We also enter into contracts which help us to hedge our interest rate exposure on variable debt. However, we may not cover the entire exposure of our assets or positions to market price (or interest rate) volatility, and the coverage will vary over time. Furthermore, the risk management procedures we have in place may not always be followed or may not work as planned. In particular, if prices of commodities (or interest rates) significantly deviate from historical prices or if the price volatility (or interest rates) or distribution of these changes deviates from historical norms, our risk management system may not protect us from significant losses. As a result, fluctuating commodity prices may negatively impact our financial results to the extent we have unhedged or inadequately hedged positions. In addition, certain types of economic hedging activities may not qualify for hedge accounting under GAAP, resulting in increased volatility in our net income. In addition, there is a risk that the current parties to these arrangements may fail or are unable to perform their obligations under these arrangements.

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Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks.

        We often rely on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of certain of our facilities. If these suppliers cannot perform, we would seek to meet our fuel requirements by purchasing fuel at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price.

        At times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility. We have also hedged a portion of our exposure to power price fluctuations through forward fixed price power sales. Counterparties to these agreements may breach or may be unable to perform their obligations. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements, or at all. If we were unable to enter into replacement PPAs, we would sell our plants' power at market prices.

        The failure of any supplier or customer to fulfill its contractual obligations to The AES Corporation or our subsidiaries could have a material adverse effect on our financial results. Consequently, the financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.

Certain of our businesses are sensitive to variations in weather.

        Our businesses are affected by variations in general weather conditions and unusually severe weather. Our businesses forecast electric sales on the basis of normal weather, which represents a long-term historical average. While we also consider possible variations in normal weather patterns and potential impacts on our facilities and our businesses, there can be no assurance that such planning can prevent these impacts, which can adversely affect our business. Generally, demand for electricity peaks in winter and summer. Typically, when winters are warmer than expected and summers are cooler than expected, demand for energy is lower, resulting in less demand for electricity than forecasted. Significant variations from normal weather where our businesses are located could have a material impact on our results of operations.

        In addition, we are dependent upon hydrological conditions prevailing from time to time in the broad geographic regions in which our hydroelectric generation facilities are located. If hydrological conditions result in droughts or other conditions that negatively affect our hydroelectric generation business, our results of operations could be materially adversely affected. In the past, our businesses in Latin America have been negatively impacted by lower than normal rainfall.

Risks Associated with our Operations

We do a significant amount of business outside the United States, including in developing countries, which presents significant risks.

        A significant amount of our revenue is generated outside the United States and a significant portion of our international operations is conducted in developing countries. Part of our growth strategy is to expand our business in developing countries because the growth rates and the opportunity to implement operating improvements and achieve higher operating margins may be greater than those typically achievable in more developed countries. International operations, particularly the operation, financing and development of projects in developing countries, entail significant risks and uncertainties, including, without limitation:

•

economic, social and political instability in any particular country or region;



•

adverse changes in currency exchange rates;

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•

government restrictions on converting currencies or repatriating funds;



•

unexpected changes in foreign laws and regulations or in trade, monetary or fiscal policies;



•

high inflation and monetary fluctuations;



•

restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;



•

threatened or consummated expropriation or nationalization of our assets by foreign governments;



•

difficulties in hiring, training and retaining qualified personnel, particularly finance and accounting personnel with U.S. GAAP expertise;



•

unwillingness of governments, government agencies, similar organizations or other counterparties to honor their contracts;



•

unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are economically advantageous to subsidiaries of the Company and economically unfavorable to counterparties, against such counterparties, whether such counterparties are governments or private parties;



•

inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;



•

adverse changes in government tax policy;



•

difficulties in enforcing our contractual rights or enforcing judgments or obtaining a just result in local jurisdictions; and



•

potentially adverse tax consequences of operating in multiple jurisdictions.

        Any of these factors, by itself or in combination with others, could materially and adversely affect our business, results of operations and financial condition. For example, in the second quarter of 2007, we sold our stake in EDC to Petróleos de Venezuela, S.A. ("PDVSA"), the state owned energy company in Venezuela after Venezuelan President Hugo Chavez threatened to expropriate the electricity business in Venezuela. In connection with the sale, we recognized an impairment charge of approximately $680 million. In addition, our Latin American operations experience volatility in revenues and gross margin which have caused and are expected to cause significant volatility in our results of operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability and currency devaluations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses.

The operation of power generation and distribution facilities involves significant risks that could adversely affect our financial results.

        The operation of power generation and distribution facilities involves many risks, including:

•

equipment failure causing unplanned outages;



•

failure of transmission systems;



•

the dependence on a specified fuel source, including the transportation of fuel;



•

catastrophic events such as fires, explosions, floods, earthquakes, hurricanes and similar occurrences; and



•

environmental compliance.

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        Any of these risks could have an adverse effect on our generation and distribution facilities. In addition, a portion of our generation facilities were constructed many years ago. Older generating equipment may require significant capital expenditures for maintenance. This equipment is also likely to require periodic upgrading and improvement. Breakdown or failure of one of our operating facilities may prevent the facility from performing under applicable power sales agreements which, in certain situations, could result in termination of a power purchase or other agreement or incurring a liability for liquidated damages.

        As a result of the above risks and other potential hazards associated with the power generation and distribution industries, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error or certain external events. The control and management of these risks depend upon adequate development and training of personnel and on the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems which reduce, but do not eliminate the possibility of the occurrence and impact of these risks.

        The hazards described above can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we believe is adequate, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently available to us or at all. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.

Our ability to attract and retain skilled people could have a material adverse effect on our operations.

        Our operating success and ability to carry out growth initiatives depends in part on our ability to retain executives and to attract and retain additional qualified personnel who have experience in our industry and in operating a company of our size and complexity, including people in our foreign businesses. The inability to attract and retain qualified personnel could have a material adverse effect on our business, because of the difficulty of promptly finding qualified replacements. In particular, we routinely are required to assess the financial and tax impacts of complicated business transactions which occur on a worldwide basis. These assessments are dependent on hiring personnel on a worldwide basis with sufficient expertise in U.S. GAAP to timely and accurately comply with U.S. reporting obligations. An inability to maintain adequate internal accounting and managerial controls and hire and retain qualified personnel could have an adverse affect on our ability to report our financial condition and results of operations.

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We have contractual obligations to certain customers to provide full requirements service, which makes it difficult to predict and plan for load requirements and may result in increased operating costs to certain of our businesses.

        We have contractual obligations to certain customers to supply power to satisfy all or a portion of their energy requirements. The uncertainty regarding the amount of power that our power generation and distribution facilities must be prepared to supply to customers may increase our operating costs. A significant under or over-estimation of load requirements could result in our facilities not having enough or having too much power to cover their obligations, in which case we would be required to buy or sell power from or to third parties at prevailing market prices. Those prices may not be favorable and thus could increase our operating costs.

We may not be able to enter into long-term contracts, which reduce volatility in our results of operations. Even when we successfully enter into long-term contracts, our generation businesses are dependent on one or a limited number of customers and a limited number of fuel suppliers.

        Many of our generation plants conduct business under long-term contracts. In these instances, we rely on power sales contracts with one or a limited number of customers for the majority of, and in some case all of, the relevant plant's output and revenues over the term of the power sales contract. The remaining terms of the power sales contracts range from 1 to 25 years. In many cases, we also limit our exposure to fluctuations in fuel prices by entering into long-term contracts for fuel with a limited number of suppliers. In these instances, the cash flows and results of operations are dependent on the continued ability of customers and suppliers to meet their obligations under the relevant power sales contract or fuel supply contract, respectively. Some of our long-term power sales agreements are at prices above current spot market prices and some of our long-term fuel supply contracts are at prices below current market prices. The loss of significant power sales contracts or fuel supply contracts, or the failure by any of the parties to such contracts that prevents us from fulfilling our obligations thereunder, could have a material adverse impact on our business, results of operations and financial condition. In addition, depending on market conditions and regulatory regimes, it may be difficult for us to secure long-term contracts, either where our current contracts are expiring or for new development projects. The inability to enter into long-term contracts could require many of our businesses to purchase inputs at market prices and sell electricity into spot markets. Because of the volatile nature of inputs and power prices, the inability to secure long-term contracts could generate increased volatility in our earnings and cash flows and could generate substantial losses during certain periods which could have a material impact on our business and results of operations.

        We have sought to reduce counter party credit risk under our long-term contracts in part by entering into power sales contracts with utilities or other customers of strong credit quality and by obtaining guarantees from the sovereign government of the customer's obligations. However, many of our customers do not have, or have failed to maintain, an investment grade credit rating, and our Generation business can not always obtain government guarantees and if they do, the government does not always have an investment grade credit rating. We have also sought to reduce our credit risk by locating our plants in different geographic areas in order to mitigate the effects of regional economic downturns. However, there can be no assurance that our efforts to mitigate this risk will be successful. These risks have increased as a result of the deteriorating global economy. For further discussion of these global economic conditions and their potential impact on the Company, see Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Credit Crisis and the Macroeconomic Environment.

Competition is increasing and could adversely affect us.

        The power production markets in which we operate are characterized by numerous strong and capable competitors, many of whom may have extensive and diversified developmental or operating

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experience (including both domestic and international) and financial resources similar to or greater than ours. Further, in recent years, the power production industry has been characterized by strong and increasing competition with respect to both obtaining power sales agreements and acquiring existing power generation assets. In certain markets, these factors have caused reductions in prices contained in new power sales agreements and, in many cases, have caused higher acquisition prices for existing assets through competitive bidding practices. The evolution of competitive electricity markets and the development of highly efficient gas-fired power plants have also caused, or are anticipated to cause, price pressure in certain power markets where we sell or intend to sell power. These competitive factors could have a material adverse effect on us.

Our business and results of operations could be adversely affected by changes in our operating performance or cost structure.

        We are in the business of generating and distributing electricity, which involves certain risks that can adversely affect financial and operating performance, including:

•

changes in the availability of our generation facilities or distribution systems due to increases in scheduled and unscheduled plant outages, equipment failure, labor disputes, disruptions in fuel supply, inability to comply with regulatory or permit requirements or catastrophic events such as fires, floods, storms, hurricanes, earthquakes, explosions, terrorist acts or other similar occurrences; and



•

changes in our operating cost structure including, but not limited to, increases in costs relating to: gas, coal, oil and other fuel; fuel transportation; purchased electricity; operations, maintenance and repair; environmental compliance, including the cost of purchasing emissions offsets and capital expenditures to install environmental emission equipment; transmission access; and insurance.

        Any of the above risks could adversely affect our business and results of operations, and our ability to meet publicly announced projections or analysts' expectations.

Some of our subsidiaries participate in defined benefit pension plans and their net pension plan obligations may require additional significant contributions.

        Certain of our subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Of the twenty four defined benefit plans, three are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries. Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be wrong, resulting in a shortfall of pension plan assets compared to pension obligations under the pension plan. The Company periodically evaluates the value of the pension plan assets to ensure that they will be sufficient to fund the respective pension obligations. The Company's exposure is mitigated due to the fact that the asset allocations in our largest plans are more heavily weighted to investments in fixed income securities that have not been as severely impacted by the recent equity market declines. Nevertheless, given the recent significant declines in financial markets, the value of these pension plan assets has declined and our future pension expense and funding obligations have increased. In addition, future downturns in the equity markets, or the failure of any of our assumptions underlying the estimates of our subsidiaries' pension plan obligations, could result in an increase in pension expense and funding requirements in future periods, which may be material. Our subsidiaries who participate in these plans are responsible for funding any shortfall of pension plan assets compared to pension obligations under the pension plan. This may necessitate additional cash contributions to the pension plans that could adversely affect our and our subsidiaries' liquidity.

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        For additional information regarding the funding position of the Company's pension plans, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates—Pension and Postretirement Obligations" and Note 13 to our Consolidated Financial Statements included in this annual report on Form 10-K.

Our business is subject to substantial development uncertainties.

        Certain of our subsidiaries and affiliates 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. Financing risk has also increased as a result of the deterioration of the global economy and the crisis in the financial markets, and as a result, we may forgo certain development opportunities. We believe that capitalized costs for projects under development are recoverable; however, there can be no assurance that any individual project will be completed and reach commercial operation. If these development efforts are not successful, we may abandon a project under development and write off the costs incurred in connection with such project. At the time of abandonment, we would expense all capitalized development costs incurred in connection therewith and could incur additional losses associated with any related contingent liabilities.

Our acquisitions may not perform as expected.

        Historically, acquisitions have been a significant part of our growth strategy. We may continue to grow our business through acquisitions. Although acquired businesses may have significant operating histories, we will have a limited or no history of owning and operating many of these businesses and possibly limited or no experience operating in the country or region where these businesses are located. Some of these businesses may be government owned and some may be operated as part of a larger integrated utility prior to their acquisition. If we were to acquire any of these types of businesses, there can be no assurance that:

•

we will be successful in transitioning them to private ownership;



•

such businesses will perform as expected;



•

we will not incur unforeseen obligations or liabilities;



•

such business will generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them; or



•

the rate of return from such businesses will justify our decision to invest our capital to acquire them.

        In April 2008, the Company completed the purchase of a 92% interest in a 660 gross MW coal-fired thermal power generation facility in Masinloc, Philippines ("Masinloc") from the Power Sector Assets & Liabilities Management Corporation, a state enterprise, for $930 million in cash. Immediately after the acquisition, the Company embarked upon a comprehensive rehabilitation program to improve the output, reliability and general condition of the plant. As a result, operating losses have been reduced and the business is expected to generate a profit in 2009. However, in the event that the progress made does not continue, or Masinloc performs worse than expected, the Company could incur further operating losses which could have a material adverse effect on our results of operations. Further losses could also trigger an impairment of the assets held by Masinloc.

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In some of our joint venture projects, we have granted protective rights to minority holders or we own less than a majority of the equity in the project and do not manage or otherwise control the project, which entails certain risks.

        We have invested in some joint ventures where we own less than a majority of the voting equity in the venture. Very often, we seek to exert a degree of influence with respect to the management and operation of projects in which we have less than a majority of the ownership interests by operating the project pursuant to a management contract, negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto significant actions. However, we do not always have this type of control over the project in every instance; and we may be dependent on our co-venturers to operate such projects. Our co-venturers may not have the level of experience, technical expertise, human resources, management and other attributes necessary to operate these projects optimally. The approval of co-venturers also may be required for us to receive distributions of funds from projects or to transfer our interest in projects.

        In some joint venture agreements where we do have majority control of the voting securities, we have entered into shareholder agreements granting protective minority rights to the other shareholders. For example, Brasiliana Energia ("Brasiliana") is a holding company in which we have a controlling equity interest and through which we own three of our four Brazilian businesses: Eletropaulo, Tietê and Uruguaiana. We entered into a shareholders' agreement with an affiliate of the Brazilian National Development Bank ("BNDES") which owns more than 49 percent of the voting equity of Brasiliana. Among other things, the shareholders' agreement requires the consent of both parties before taking certain corporate actions, grants both parties rights of first refusal in connection with the sale of interests in Brasiliana and grants drag-along rights to BNDES. In May, 2007, BNDES notified us that it intends to sell all of its interest in Brasiliana pursuant to public auction (the "Brasiliana Sale"). BNDES also informed us that if we fail to exercise our right of first refusal to purchase all of its interest in Brasiliana, then BNDES intends to exercise its drag-along rights under the shareholders' agreement and cause us to sell all of our interests in Brasiliana in the Brasiliana Sale as well. After the auction, if a third party offer has been received in the Brasiliana Sale, we will have 30 days to exercise our right of first refusal to purchase all of BNDES's interest in Brasiliana on the same terms as the third- party offer. If we do not exercise this right and BNDES proceeds to exercise its drag-along rights, then we may be forced to sell all of our interest in Brasiliana. Due to the uncertainty in the sale price at this point in time, we are uncertain whether we will exercise our right of first refusal should BNDES receive a valid third-party offer in the Brasiliana Sale and, if we do, whether we would do it alone or with joint venture partners. Even if we desire to exercise our right of first refusal, we cannot assure that we will have the cash on hand or that debt or equity financing will be available at acceptable terms in order to purchase BNDES's interest in Brasiliana. If we do not exercise our right of first refusal, we cannot be assured that we will not have to record a loss if the sale price is below the book value of our investment in Brasiliana.

Our renewable energy projects and other initiatives face considerable uncertainties including, development, operational and regulatory challenges.

        AES Wind Generation, AES Solar, our projects in climate solutions and our investments in projects such as energy storage are subject to substantial risks. Projects of this nature are relatively new, are supported financially by favorable regulatory incentives and have been developed through advancement in technologies which may not be proven, or which are unrelated to our core business.

        As a result, these projects face considerable risk, including the risk that favorable regulatory regimes expire or are adversely modified. In addition, because these projects depend on technology outside of our expertise in Generation and Utilities, there are risks associated with our ability to develop and manage such projects profitably. Furthermore, at the development or acquisition stage, because of the nascent nature of these industries, our ability to predict actual performance results may be hindered and the projects may not perform as predicted. There are also risks associated with the

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fact that many of these projects exist in new or emerging markets, where long-term fixed price contracts for the major cost and revenue components may be unavailable, which in turn may result in these projects having relatively high levels of volatility.

        These projects can be capital-intensive and generally require that we obtain third party financing, which may be difficult to obtain. As a result, these capital constraints may reduce our ability to develop these projects. These risks may be exacerbated by the current global economic crisis, including our management's increased focus on liquidity, which may also result in slower growth in the number of projects we can pursue. The economic downturn could also impact the value of our assets in these countries and our ability to develop these projects. If the value of these assets decline, this could result in a material impairment or a series of impairments which are material in the aggregate, which would adversely affect our financial statements.

The global credit crisis could impact our growth plans and the values of our assets.

        In the second half of 2007, conditions in the credit markets began to deteriorate in the United States and abroad. In the third and fourth quarter of 2008, this crisis and associated market conditions worsened dramatically, with unprecedented market volatility, widening credit spreads, volatile currencies, illiquidity, and increased counterparty credit risk. As a result of the deterioration in the global economy, the Company has placed a greater emphasis on preservation of liquidity. The Company currently intends to complete the projects it has under construction, those that have obtained financing and a select group of projects which may be able to obtain financing in these challenging financial markets. In the event that management determines that, because of macroeconomic challenges or other factors, certain of these or other projects in the pipeline cannot be financed, will not provide the returns originally anticipated, or are otherwise unfeasible, or that other uses of capital such as debt repayment or stock repurchases offer a better return on the Company's capital, or that the funds should be used for working capital, the Company may determine that it will not pursue certain projects in its pipeline, which will affect our growth.

        In addition, the global recession could impact the value of our assets around the world. For example, in 2008, we impaired certain projects in our pipeline, resulting in a charge to 2008 earnings. Further declines in asset values could result in additional write-downs, which could be material to our financial statements.

An impairment in the carrying value of goodwill would negatively impact our consolidated results of operations and net worth.

        Goodwill is initially recorded at fair value and is not amortized, but is evaluated for impairment at least annually, or more frequently if impairment indicators are present. In assessing the recoverability of goodwill, we make estimates and assumptions about sales, operating margin growth rates and discount rates based on our budgets, business plans, economic projections, anticipated future cash flows and marketplace data. There are inherent uncertainties related to these factors and management's judgment in applying these factors. The fair value of a reporting unit has been determined using an income approach based on the present value of future cash flows of each reporting unit. We could be required to evaluate the recoverability of goodwill prior to the annual assessment if we experience situations, including but not limited to, disruptions to the business, unexpected significant declines in operating results, divestiture of a significant component of our business or sustained market capitalization declines. There could also be impairments if our acquisitions do not perform as expected. See further discussion in Risk Factor, "Our Acquisitions May Not Perform as Expected." These types of events and the resulting analyses could result in goodwill impairment charges in the future. Impairment charges could substantially affect our financial results in the periods of such charges. As of December 31, 2008, we had $1.4 billion of goodwill, which represented approximately 4.1% of total assets. If current conditions in the global economy continue or worsen, this could increase the risk that we will have to impair goodwill.

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Risks associated with Governmental Regulation and Laws

Our operations are subject to significant government regulation and our business and results of operations could be adversely affected by changes in the law or regulatory schemes.

        Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any inability to obtain expected or contracted increases in electricity tariff rates or tariff adjustments for increased expenses, could adversely impact our results of operations or our ability to meet publicly announced projections or analyst's expectations. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions where we operate, particularly our Utilities where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:

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changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs, including but not limited to costs incurred to upgrade our power plants to comply with more stringent environmental regulations;



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changes in the determination of what is an appropriate rate of return on invested capital or a determination that a utility's operating income or the rates it charges customers is too high, resulting in a reduction of rates or consumer rebates;



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changes in the definition or determination of controllable or non-controllable costs;



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changes in the definition of events which may or may not qualify as changes in economic equilibrium;



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changes in the timing of tariff increases; or



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other changes in the regulatory determinations under the relevant concessions.

        Any of the above events may result in lower margins for the affected businesses, which can adversely affect our business.

        For example, as noted in Item 1—Business—Regulatory Matters—Hungary of this Form 10-K, in June 2008 the European Commission ("the Commission") reached its decision that the PPAs, including AES Tisza's PPA, contain elements of illegal state aid. The decision requires Hungary to terminate the PPAs within six months of the June 2008 publication of the decision, and to recover the alleged illegal state aid from the generators within ten months of publication. Hungary and the Commission are in the process of resolving confidentiality matters relating to the wording of the decision, which has not yet been notified by the Commission to the generators. AES Tisza is challenging the Commission's decision in the Court of First Instance of the European Communities. Referring to the Commission's decision, Hungary adopted act number LXX of 2008 which terminates all long-term PPAs in Hungary, including AES Tisza's PPA, as of December 31, 2008, and requires generators to repay the alleged illegal state aid that was allegedly received by the generators through the PPAs, and provides for the possibility to offset stranded costs of the generators from the repayable state aid. It is possible that the Company may face additional regulatory actions of this type and, depending on the outcome, such actions could have a material adverse impact on the Company.

        In addition, in many countries where we conduct business, the regulatory environment is constantly changing or the regulations can be difficult to interpret. As a result, there is risk that we may not properly interpret certain regulations and may not understand the impact of certain regulations on our business. For example, in October 2006, ANEEL, which regulates our utility operations at Sul and Eletropaulo in Brazil, issued Normative Resolution 234 requiring that utilities begin amortizing a liability called "Special Obligations" beginning with their second tariff reset cycle in 2007 or a later year as an offset to depreciation expense. As of May 23, 2007, the date of the filing of our 2006 Form 10-K, no industry positions or any other consensus had been reached regarding how ANEEL guidance should be applied at that date and accordingly, no adjustments to the financial statements were made relating to Special Obligations in Brazil. Subsequent to May 23, 2007, industry discussions

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occurred and other Brazilian companies filed Forms 20-F with the SEC reflecting the impact of Resolution 234 in their December 31, 2006 financial statements differently from how the Company accounted for Resolution 234. In the absence of any significant regulatory developments between May 23, 2007 and the date of these other filings, the Company determined that Resolution 234 required us to record an adjustment to our Special Obligations liability as of December 31, 2006. In part, the decision to record the adjustment led to the restatement of our financial statements in the third quarter of 2007. If we face additional challenges interpreting regulations or changes in regulations, it could have a material adverse impact on our business.

Our Generation business in the United States is subject to the provisions of various laws and regulations administered in whole or in part by the FERC, including the Public Utility Regulatory Policies Act of 1978 ("PURPA") and the Federal Power Act. The recently enacted EPAct 2005 made a number of changes to these and other laws that may affect our business. Actions by the FERC and by state utility commissions can have a material effect on our operations.

        EPAct 2005 authorizes the FERC to remove the obligation of electric utilities under Section 210 of PURPA to enter into new contracts for the purchase or sale of electricity from or to QF's if certain market conditions are met. Pursuant to this authority, the FERC has instituted a rebuttable presumption that utilities located within the control areas of the Midwest Transmission System Operator, Inc., PJM ("Pennsylvania, New Jersey and Maryland") Interconnection, L.L.C., ISO New England, Inc., the New York Independent System Operator and the Electric Reliability Council of Texas, Inc. are not required to purchase or sell power from or to QFs above a certain size. In addition, the FERC is authorized under the new law to remove the purchase/sale obligations of individual utilities on a case-by-case basis. While the new law does not affect existing contracts, as a result of the changes to PURPA, our QF's may face a more difficult market environment when their current long-term contracts expire.

        EPAct 2005 repealed PUHCA 1935 and enacted PUHCA 2005 in its place. PUHCA 1935 had the effect of requiring utility holding companies to operate in geographically proximate regions and therefore limited the range of potential combinations and mergers among utilities. By comparison, PUHCA 2005 has no such restrictions and simply provides the FERC and state utility commissions with enhanced access to the books and records of certain utility holding companies. The repeal of PUHCA 1935 removed barriers to mergers and other potential combinations which could result in the creation of large, geographically dispersed utility holding companies. These entities may have enhanced financial strength and therefore an increased ability to compete with us in the U.S. generation market.

        In accordance with Congressional mandates in the EPAct 1992 and now in EPAct 2005, the FERC has strongly encouraged competition in wholesale electric markets. Increased competition may have the effect of lowering our operating margins. Among other steps, the FERC has encouraged RTOs and ISOs to develop demand response bidding programs as a mechanism for responding to peak electric demand. These programs may reduce the value of our peaking assets which rely on very high prices during a relatively small number of hours to recover their costs. Similarly, the FERC is encouraging the construction of new transmission infrastructure in accordance with provisions of EPAct 2005. Although new transmission lines may increase market opportunities, they may also increase the competition in our existing markets.

        While the FERC continues to promote competition, some state utility commissions have reversed course and begun to encourage the construction of generation facilities by traditional utilities to be paid for on a cost-of-service basis by retail ratepayers. Such actions have the effect of reducing sale opportunities in the competitive wholesale generating markets in which we operate.

Our businesses are subject to stringent environmental laws and regulations.

        Our activities are subject to stringent environmental laws and regulations by many federal, state and local authorities, international treaties and foreign governmental authorities. These laws and

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regulations generally concern emissions into the air, effluents into the water, use of water, wetlands preservation, remediation of contamination, waste disposal, endangered species and noise regulation, among others. Failure to comply with such laws and regulations or to obtain any necessary environmental permits pursuant to such laws and regulations could result in fines or other sanctions. Environmental laws and regulations affecting power generation and distribution are complex and have tended to become more stringent over time. Congress and other domestic and foreign governmental authorities have either considered or implemented various laws and regulations to restrict or tax certain emissions, particularly those involving air and water emissions. See the various descriptions of these laws and regulations contained in Item 1 Business—Regulatory Matters—Environmental and Land Use Regulations of this Form 10-K. These laws and regulations have imposed, and proposed laws and regulations could impose in the future, additional costs on the operation of our power plants. We have incurred and will continue to incur significant capital and other expenditures to comply with these and other environmental laws and regulations. Changes in, or new, environmental restrictions may force us to incur significant expenses or expenses that may exceed our estimates. There can be no assurance that we would be able to recover all or any increased environmental costs from our customers or that our business, financial condition or results of operations would not be materially and adversely affected by such expenditures or any changes in domestic or foreign environmental laws and regulations.

Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and are taking actions which, in addition to the potential physical risks associated with climate change, could have a material adverse impact on our consolidated results of operations, financial condition and cash flows.

        As discussed in Item 1—Business—Regulatory Matters—Environmental and Land Use Regulations, at the international, federal and various regional and state levels, policies are under development to regulate GHG emissions, thereby effectively putting a cost on such emissions in order to create financial incentives to reduce them. In 2008, the Company's subsidiaries operated businesses which had total approximate CO₂ emissions of 83.8 million metric tonnes (ownership adjusted). Approximately 41.5 million metric tonnes of the 83.8 million metric tonnes were emitted by businesses located in the United States (both figures ownership adjusted). Federal, state or regional regulation of GHG emissions could have a material adverse impact on the Company's financial performance. The actual impact on the Company's financial performance and the financial performance of the Company's subsidiaries will depend on a number of factors, including among others, the GHG reductions required under any such legislation or regulations, the price and availability of offsets, the extent to which market based compliance options are available, the extent to which our subsidiaries would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on the ability of our subsidiaries to recover costs incurred. As a result of these factors, our cost of compliance could be substantial and could have a material impact on our results of operations. Another factor is the success of our climate solutions projects, which may generate credits that will help offset our GHG emissions. However, as set forth in the Risk Factor titled "Our renewable energy projects and other initiatives face considerable uncertainties including development, operational and regulatory challenges," there is no guarantee that the climate solutions projects will be successful. Also, the level of potential benefit is unclear given current uncertainties regarding legislation and/or litigation concerning GHG emissions.

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        In January 2005, based on European Community "Directive 2003/87/EC on Greenhouse Gas Emission Allowance Trading," the European Union Greenhouse Gas Emission Trading Scheme ("EU ETS") commenced operation as the largest multi-country GHG emission trading scheme in the world. On February 16, 2005, the Kyoto Protocol became effective. The Kyoto Protocol requires the 40 developed countries that have ratified it to substantially reduce their GHG emissions, including CO₂. To date, compliance with the Kyoto Protocol and the EU ETS has not had a material adverse effect on the Company's consolidated results of operations, financial condition and cash flows.

        The United States has not ratified the Kyoto Protocol. In the United States, there currently are no federal mandatory GHG emission reduction programs (including CO₂) affecting the electric power generation facilities of the Company's subsidiaries. However, there are several proposed GHG legislative initiatives in the United States Congress that would, if enacted, constrain GHG emissions, including CO₂, and/or impose costs on us that could be material to our business or results of operations.

        On April 2, 2007, the U.S. Supreme Court issued its decision in a case involving the regulation under the CAA of CO₂ emissions from motor vehicles. The Court ruled that CO₂ is a pollutant which potentially could be subject to regulation under the CAA and that the U.S. EPA has a duty to determine whether CO₂ emissions contribute to climate change or to provide some reasonable explanation why it will not exercise its authority. In response to the Court's decision, on July 11, 2008, the U.S. EPA issued an ANPR to solicit public input on whether CO₂ emissions should be regulated from both mobile and stationary sources under the CAA. The U.S. EPA has not yet made any such determination. Since electric power generation facilities, particularly coal-fired facilities, are a significant source of CO₂ emissions both in the United States and globally, the Court's decision, coupled with stimulus from the new administration, regulators, members of Congress, states, non-governmental organizations, private parties, the courts and other factors could result in a determination by the U.S. EPA to regulate CO₂ emissions from electric power generation facilities. While the majority of current state, regional and federal initiatives regarding CO₂ emissions contemplate market-based compliance mechanisms (e.g., cap-and-trade), such a determination by the U.S. EPA could result in CO₂ emission limits on stationary sources that do not include market-based compliance mechanisms (e.g., carbon tax, CO₂ emission limits, etc.). Any such regulations could increase our costs directly and indirectly and have a material adverse affect on our business and/or results of operations.

        At the state level, RGGI, a cap-and-trade program covering CO₂ emissions from electric power generation facilities in the Northeast, became effective in January 2009, and the WCI, is also developing market-based programs to address GHG emissions in seven western states. In addition, several states, including California, have adopted comprehensive legislation that, when implemented, will require mandatory GHG reductions from several industrial sectors, including the electric power generation industry. See "Business—Regulatory Matters—Environmental and Land Use Regulations" of this Form 10-K for further discussion about the environmental regulations we face. At this time, other than with regard to RGGI (further described below), the Company cannot estimate the costs of compliance with U.S. federal, regional or state CO₂ emissions reductions legislation or initiatives, due to the fact that these proposals are in earlier stages of development and any final regulations, if adopted, could vary drastically from current proposals.

        The RGGI program became effective in January 2009. The first regional auction of RGGI allowances needed to be acquired by power generators to comply with state programs implementing RGGI was held in September 2008 and the second was held in December 2008. The third auction is scheduled for March 2009. Our subsidiaries in New York, New Jersey, Connecticut and Maryland are subject to RGGI. Of the approximately 41.5 million metric tonnes of CO₂ emitted in the United States by our subsidiaries in 2008 (ownership adjusted), approximately 11.8 million metric tonnes were emitted in U.S. states participating in RGGI. We believe that due to the absence of allowance allocations,

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RGGI as currently contemplated could have an adverse impact on the Company's consolidated results of operations, financial condition and cash flows. While Co₂ emissions from businesses operated by subsidiaries of the Company are calculated globally in metric tonnes, RGGI allowances are denominated in short tons. (1 metric tonne equals 2,200 pounds and 1 short ton equals 2,000 pounds.) For forecasting purposes, the Company has modeled the impact of CO₂ compliance for 2009-2011 for its businesses that are subject to RGGI and that may not be able to pass through compliance costs. The model includes a conversion from metric tonnes to short tons as well as the impact of some market recovery by merchant plants and contractual and regulatory provisions. The model also utilizes an allowance price of $3.38 per metric tonne under RGGI. The source of this per allowance price estimate was the clearing price at the December 2008 RGGI allowance auction. The model also assumes, among other things, that RGGI will be structured solely on the public auction of allowances and that certain costs will be recovered by our subsidiaries. Based on these assumptions, the Company estimates that the RGGI compliance costs could be approximately $29.1 million per year from 2009 through 2011, which is the last year of the first RGGI compliance period. Given all of the uncertainties surrounding RGGI, including those discussed in Item 1—Business—Regulatory Matters—Environmental and Land Use Regulations of this Form 10-K and the fact that the assumptions utilized in the model may prove to be incorrect, there is a significant risk that our actual compliance costs under RGGI will differ from estimates by a material amount. If the actual costs are higher, this could have a material impact on our business and financial results.

        In addition to government regulators, other groups such as politicians, environmentalists and other private parties have expressed increasing concern about GHG emissions. For example, certain financial institutions have expressed concern about providing financing for facilities which would emit GHGs, which can affect our ability to obtain capital, or if we can obtain capital, to receive it on commercially viable terms. In addition, rating agencies may decide to downgrade our credit ratings based on the emissions of the businesses operated by our subsidiaries or increased compliance costs which could make financing unattractive. In addition, as disclosed in Item 3—Legal Proceedings of this Form 10-K, the New York Attorney General has issued a subpoena to the Company seeking documents and information concerning the Company's analysis and public disclosure of the potential impacts that GHG legislation and climate change from GHG emissions might have on the Company's operations and financial results. Environmental groups and other private plaintiffs have brought and may decide to bring additional private lawsuits against the Company because of its subsidiaries' GHG emissions.

        Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect the Company's business and operations. For example, extreme weather events could result in increased downtime and operation and maintenance costs at the electric power generation facilities and support facilities of the Company's subsidiaries. Variations in weather conditions, primarily temperature and humidity, attributable to climate change, also would be expected to affect the energy needs of customers. A decrease in energy consumption could decrease the revenues of the Company's subsidiaries. In addition, while revenues would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of the fossil-fuel fired electric power generation facilities of the Company's subsidiaries. Changes in temperature, precipitation and snow pack conditions also could affect the amount and timing of hydroelectric generation.

        If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on the electric power generation businesses of the Company's

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subsidiaries and on the Company's consolidated results of operations, financial condition and cash flows.

We and our affiliates are subject to material litigation and regulatory proceedings.

        We and our affiliates are parties to material litigation and regulatory proceedings. See Business—Legal Proceedings below. There can be no assurances that the outcome of such matters will not have a material adverse effect on our consolidated financial position.

The SEC is conducting an informal inquiry relating to our restatements.

        We have been cooperating with an informal inquiry by the SEC Staff concerning our past restatements and related matters, and have been providing information and documents to the SEC Staff on a voluntary basis. Because we are unable to predict the outcome of this inquiry, the SEC Staff may disagree with the manner in which we have accounted for and reported the financial impact of the adjustments to previously filed financial statements and there may be a risk that the inquiry by the SEC could lead to circumstances in which we may have to further restate previously filed financial statements, amend prior filings or take other actions not currently contemplated.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

ITEM 2.    PROPERTIES

        We maintain offices in many places around the world, generally pursuant to the provisions of long- and short-term leases, none of which are material. With a few exceptions, our facilities, which are described in Item 1 of this Form 10-K, are subject to mortgages or other liens or encumbrances as part of the project's related finance facility. In addition, the majority of our facilities are located on land that is leased. However, in a few instances, no accompanying project financing exists for the facility, and in a few of these cases, the land interest may not be subject to any encumbrance and is owned outright by the subsidiary or affiliate.

ITEM 3.    LEGAL PROCEEDINGS

        The Company is involved in certain claims, suits and legal proceedings in the normal course of business, some of which are described below. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company's financial statements. However, it is reasonably possible that some matters could be decided unfavorably to the Company, and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of December 31, 2008. The Company has evaluated claims, in accordance with SFAS No. 5, Accounting for Contingencies, ("SFAS No. 5") that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims for approximately $389 million and $486 million as of December 31, 2008 and 2007, respectively.

        In 1989, Centrais Elétricas Brasileiras S.A. ("Eletrobrás") filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. ("EEDSP") relating to the methodology for calculating monetary adjustments under the parties' financing agreement. In April 1999, the Fifth District Court found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$937 million ($400 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company,

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Companhia de Transmissão de Energia Elétrica Paulista ("CTEEP") (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the Fifth District Court rejected Eletropaulo's defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice ("SCJ") reversed the Appellate Court's decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo's liability, if any, should be determined by the Fifth District Court. Eletropaulo's subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil have been dismissed. Eletrobrás may resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo will be required to provide security in the amount of its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the Fifth District Court grants such request, Eletropaulo's results of operation may be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the Fifth District Court against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In September 1999, a state appellate court in Minas Gerais, Brazil, granted a temporary injunction suspending the effectiveness of a shareholders' agreement between Southern Electric Brasil Participacoes, Ltda. ("SEB") and the state of Minas Gerais concerning Companhia Energetica de Minas Gerais ("CEMIG"), an integrated utility in Minas Gerais. The Company's investment in CEMIG is through SEB. This shareholders' agreement granted SEB certain rights and powers in respect of CEMIG ("Special Rights"). In March 2000, a lower state court in Minas Gerais held the shareholders' agreement invalid where it purported to grant SEB the Special Rights and enjoined the exercise of the Special Rights. In August 2001, the state appellate court denied an appeal of the decision and extended the injunction. In October 2001, SEB filed appeals against the state appellate court's decision with the Federal Superior Court and the Supreme Court of Justice. The state appellate court denied access of these appeals to the higher courts, and in August 2002 SEB filed interlocutory appeals against such denial with the Federal Superior Court and the Supreme Court of Justice. In December 2004, the Federal Superior Court declined to hear SEB's appeal. However, the Supreme Court of Justice is considering whether to hear SEB's appeal. SEB intends to vigorously pursue a restoration of the value of its investment in CEMIG by all legal means; however, there can be no assurances that it will be successful in its efforts. Failure to prevail in this matter may limit SEB's influence on the daily operation of CEMIG.

        In August 2000, the FERC announced an investigation into the organized California wholesale power markets in order to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. FERC requested documents from each of the AES Southland, LLC plants and AES Placerita, Inc. AES Southland and AES Placerita have cooperated fully with the FERC investigations. AES Southland was not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. AES Placerita is currently subject to refund liability of $588,000 plus interest for spot sales to the California Power Exchange from October 2, 2000 to June 20, 2001 ("Refund Period"). In September 2004, the U.S. Court of Appeals for the Ninth Circuit issued an order addressing FERC's decision not to impose refunds for the alleged failure to file rates, including transaction specific data, for sales during 2000 and 2001 ("September 2004 Decision"). Although it did not order refunds, the Ninth Circuit remanded the case to FERC for a refund proceeding to consider remedial options. In March 2008, FERC issued its order on remand, requiring the parties to engage in settlement discussions before a settlement judge and establishing procedures for an evidentiary hearing if the settlement process failed. In addition, in August 2006 in a separate case, the Ninth Circuit confirmed the Refund Period, expanded the

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transactions subject to refunds to include multi-day transactions, expanded the potential liability of sellers to include any pre-Refund Period tariff violations, and remanded the matter to FERC ("August 2006 Decision"). Various parties filed petitions for rehearing in November 2007. The August 2006 Decision may allow FERC to reopen closed investigations and order relief. AES Placerita made sales during the periods at issue in the September 2004 and August 2006 Decisions. Both appeals may be subject to further court review, and further FERC proceedings on remand would be required to determine potential liability, if any. Prior to the August 2006 Decision, AES Placerita's potential liability for the Refund and pre-Refund Periods could have approximated $23 million plus interest. However, given the September 2004 and August 2006 Decisions, it is unclear whether AES Placerita's potential liability is less than or exceeds that amount. AES Placerita believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In August 2001, the Grid Corporation of Orissa, India ("Gridco"), filed a petition against the Central Electricity Supply Company of Orissa Ltd. ("CESCO"), an affiliate of the Company, with the Orissa Electricity Regulatory Commission ("OERC"), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC's August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO's distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company's indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO's financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate, pursuant to the Indian Arbitration and Conciliation Act of 1996, on the Company, AES Orissa Distribution Private Limited ("AES ODPL"), and Jyoti Structures ("Jyoti") pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the "CESCO arbitration"). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco's claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents' counterclaims were also rejected. The Company subsequently filed an application to recover its costs of the arbitration, which is under consideration by the tribunal. In addition, in September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in Orissa Power Generation Corporation Ltd ("OPGC"), and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco's challenge to the arbitration award is resolved. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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        In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC's existing PPA with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC's jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court's decision to the Supreme Court and sought stays of both the High Court's decision and the underlying OERC proceedings regarding the PPA's terms. In April 2005, the Supreme Court granted OPGC's requests and ordered stays of the High Court's decision and the OERC proceedings with respect to the PPA's terms. The matter is awaiting further hearing. Unless the Supreme Court finds in favor of OPGC's appeal or otherwise prevents the OERC's proceedings regarding the PPA's terms, the OERC will likely lower the tariff payable to OPGC under the PPA, which would have an adverse impact on OPGC's financials. OPGC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil ("MPF") notified AES Eletropaulo that it had commenced an inquiry related to the Brazilian National Development Bank ("BNDES") financings provided to AES Elpa and AES Transgás 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. In July 2004, the MPF filed a public civil lawsuit in federal court alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES's internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo's preferred shares at a stock-market auction; (4) accepting Eletropaulo's preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. ("Light") and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES's alleged violations. In June 2005, AES Elpa and AES Transgás presented their preliminary answers to the charges. In May 2006, the federal court ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal seeking to require the federal court to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal seeking to enjoin the federal court from considering any of the alleged violations. The MPF's lawsuit before the federal court has been stayed pending those interlocutory appeals. AES Elpa and AES Transgás believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

        AES Florestal, Ltd. ("Florestal"), had been operating a pole factory and had other assets, including a wooded area known as "Horto Renner," in the State of Rio Grande do Sul, Brazil (collectively, "Property"). Florestal had been under the control of AES Sul ("Sul") since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica ("CEEE"), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney's Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney's Office then requested an injunction which the judge rejected on September 26, 2008. The

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Public Attorney's office has a right to appeal the decision. The environmental agency ("FEPAM") has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul's name the Property that it acquired through the privatization but that remained registered in CEEE's name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a "Technical Cooperation Protocol" pursuant to which they requested a new deadline from FEPAM in order to present a proposal. The proposal was delivered on April 8, 2008. FEPAM responded by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE's operations. It is estimated that remediation could cost approximately R$14.7 million ($6.3 million). Discussions between Sul and CEEE are ongoing.

        In January 2004, the Company received notice of a "Formulation of Charges" filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the "Formulation of Charges," the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A., ("Itabo") Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A.) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the "Formulation of Charges" ("Constitutional Injunction"). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the "Formulation of Charges," and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court's decision. In July 2004, the Company divested any interest in Empresa Distribuidora de Electricidad del Este, S.A. The Superintendence of Electricity's appeal is pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In April 2004, BNDES filed a collection suit against SEB, a subsidiary of the Company, to obtain the payment of R$3.5 billion ($1.5 billion), which includes principal, interest and penalties under the loan agreement between BNDES and SEB, the proceeds of which were used by SEB to acquire shares of CEMIG. In May 2004, the 15th Federal Circuit Court ("Circuit Court") ordered the attachment of SEB's CEMIG shares, which were given as collateral for the loan, as well as dividends paid by CEMIG to SEB. At the time of the attachment, the shares were worth approximately R$762 million ($325 million). In December 2006, SEB's defense was ruled groundless by the Circuit Court, and in January 2007, SEB filed an appeal to the relevant Federal Court of Appeals. Subsequently, BNDES has seized a total of approximately R$630 million ($269 million) in attached dividends, with the approval of the Circuit Court. Also, in April 2008, BNDES filed a plea to seize the attached CEMIG shares. The Circuit Court will consider BNDES's request to seize the attached CEMIG shares after the net value of the alleged debt is recalculated in light of BNDES's seizure of dividends. SEB believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In July 2004, the Corporación Dominicana de Empresas Eléctricas Estatales ("CDEEE") filed lawsuits against Itabo, an affiliate of the Company, located in the Dominican Republic, in the First and

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Fifth Chambers of the Civil and Commercial Court of First Instance for the National District. CDEEE alleges in both lawsuits that Itabo spent more than was necessary to rehabilitate two generation units of an Itabo power plant and, in the Fifth Chamber lawsuit, that those funds were paid to affiliates and subsidiaries of AES Gener and Coastal Itabo, Ltd. ("Coastal"), a former shareholder of Itabo, without the required approval of Itabo's board of administration. In the First Chamber lawsuit, CDEEE seeks an accounting of Itabo's transactions relating to the rehabilitation. In November 2004, the First Chamber dismissed the case for lack of legal basis. On appeal, in October 2005 the Court of Appeals of Santo Domingo ruled in Itabo's favor, reasoning that it lacked jurisdiction over the dispute because the parties' contracts mandated arbitration. The Supreme Court of Justice is considering CDEEE's appeal of the Court of Appeals' decision. In the Fifth Chamber lawsuit, which also names Itabo's former president as a defendant, CDEEE seeks $15 million in damages and the seizure of Itabo's assets. In October 2005, the Fifth Chamber held that it lacked jurisdiction to adjudicate the dispute given the arbitration provisions in the parties' contracts. The First Chamber of the Court of Appeal ratified that decision in September 2006. In a related proceeding, in May 2005, Itabo filed a lawsuit in the U.S. District Court for the Southern District of New York seeking to compel CDEEE to arbitrate its claims. The petition was denied in July 2005. Itabo's appeal of that decision to the U.S. Court of Appeals for the Second Circuit has been stayed since September 2006. Further, in September 2006, in an International Chamber of Commerce arbitration, an arbitral tribunal determined that they lacked jurisdiction to decide arbitration claims concerning these disputes. Itabo believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In April 2006, a putative class action complaint was filed in the U.S. District Court for the Southern District of Mississippi ("District Court") on behalf of certain individual plaintiffs and all residents and/or property owners in the State of Mississippi who allegedly suffered harm as a result of Hurricane Katrina, and against the Company and numerous unrelated companies, whose alleged greenhouse gas emissions allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert unjust enrichment, civil conspiracy/aiding and abetting, public and private nuisance, trespass, negligence, and fraudulent misrepresentation and concealment claims against the defendants. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. In August 2007, the District Court dismissed the case. The plaintiffs have appealed to the U.S. Court of Appeals for the Fifth Circuit, which heard oral arguments in November 2008 and is considering the appeal. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In June 2006, AES Ekibastuz was found to have breached a local tax law by failing to obtain a license for use of local water for the period of January 1, 2005 through October 3, 2005, in a timely manner. As a result, an additional permit fee was imposed, bringing the total permit fee to approximately $135,000. The Company has appealed this decision to the Supreme Court.

        In June 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan ordered AES Ust-Kamenogorsk TETS LLP ("UKT") to pay approximately 835 million KZT ($7 million) to the state for alleged antimonopoly violations in 2005 through January 2007. The Competition Committee also ordered UKT to pay approximately 235 million KZT ($2 million), as estimated by the Company, to certain customers that allegedly have paid unreasonably high power prices since January 2007. In November 2007, the economic court of first instance upheld the Competition Committee's order in part, finding that UKT had violated Kazakhstan's antimonopoly laws, but reduced the damages to be paid to the state to 833 million KZT ($7 million) and rejected the damages to be paid to customers. The court of appeals (first panel) later affirmed the economic court's decision and, therefore, in June 2008, UKT paid the damages. The court of appeals (second panel) rejected UKT's appeal in June 2008. UKT has appealed to the Supreme Court of Kazakhstan. The

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Competition Committee's successor (the Antimonopoly Agency) has not indicated whether it intends to assert claims against UKT for alleged antimonopoly violations post January 2007. UKT believes it has meritorious claims and defenses; however, there can be no assurances that it will prevail in these proceedings.

        In July 2007, the Competition Committee ordered Nurenergoservice, an AES subsidiary, to pay approximately 18 billion KZT ($150 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. The Competition Committee's order was affirmed by the economic court in April 2008. Nurenergoservice's subsequent appeals have been unsuccessful to date, including at the court of appeals (first panel), which rejected Nurenergoservice's appeal in July 2008. Also, the economic court has issued an injunction to secure Nurenergoservice's alleged liability, freezing Nurenergoservice's bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. In separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately 2 billion KZT (approximately $17 million) in administrative fines for its alleged antimonopoly violations. Nurenergoservice subsequently appealed to the administrative court of first instance. That appeal has been stayed since October 2007 but could resume at any time. The Antimonopoly Agency has not indicated whether it intends to assert claims against Nurenergoservice for alleged antimonopoly violations post first quarter 2007. Nurenergoservice believes it has meritorious claims and defenses; however, there can be no assurances that it will prevail in these proceedings. As Nurenergoservice did not prevail in the economic court or the court of appeals (first panel) with respect to the alleged damages, it will have to pay the alleged damages or risk seizure of its assets. In February 2009, the Antimonopoly Agency seized approximately 783 million KZT ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice's alleged damages liability. Furthermore, if Nurenergoservice does not prevail in the administrative court with respect to the fines, it will have to pay the fines or risk seizure of its assets.

        In August 2007, the Competition Committee ordered Sogrinsk TETS, a thermal cogeneration plant under AES concession, to terminate its contracts with Nurenergoservice and Ust-Kamenogorsk HPP because of Sogrinsk's alleged antimonopoly violations in 2005 through January 2007. The Competition Committee did not order Sogrinsk to pay any damages or fines. The Kazakhstan courts have affirmed the order, including the Supreme Court of Kazakhstan in October 2008. The Antimonopoly Agency has not indicated whether it intends to assert claims against Sogrinsk for alleged antimonopoly violations post January 2007.

        In November 2007, the Competition Committee initiated an investigation of allegations that Irtysh Power and Light, LLP ("Irtysh"), an AES company which manages the state-owned Ust-Kamenogorsk Heat Nets system, had violated Kazakhstan's antimonopoly laws in January through November 2007 by selling power at below-market prices. In February 2008, the Competition Committee determined that the allegations were baseless. The Competition Committee subsequently appeared to initiate an investigation to determine whether Irtysh had illegally coordinated with other AES companies concerning the sale of power, but its successor (the Antimonopoly Agency) has not issued an order or otherwise taken any action on any such investigation to date. Irtysh believes it has meritorious claims and defenses and will assert them vigorously in any formal proceeding; however, there can be no assurances that it will be successful in its efforts.

        In December 2008, the Antimonopoly Agency ordered Ust-Kamenogorsk HPP ("UK HPP"), a hydroelectric plant under AES concession, to pay approximately 1.1 billion KZT ($9 million) for alleged antimonopoly violations in February through November 2007. The economic court has issued an injunction to secure UK HPP's alleged liability, among other things freezing UK HPP's bank accounts. Furthermore, the Antimonopoly Agency has initiated administrative proceedings against UK HPP seeking an unspecified amount of administrative fines for the alleged antimonopoly violations. UK HPP believes it has meritorious defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.

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        In June 2007, the Company received a letter from an outside law firm purportedly representing a shareholder demanding that the Company's Board conduct a review of certain stock option plans, procedures and historical granting and exercise practices, and other matters, and that the Company commence legal proceedings against any officer and/or director who may be liable for damages to the Company. The Board has established a Special Committee, which has retained independent counsel, to consider the demands presented in the letter in light of the work undertaken by the Company in its review of share-based compensation. The Company has not received any communication from the purported shareholder who made the demand since the second half of 2007.

        In July 2007, AES Energia Cartagena SRL, ("AESEC") initiated arbitration against Initec Energia SA, Mitsubishi Corporation, and MC Power Project Management, SL ("Contractor") to recover damages from the Contractor for its delay in completing the construction of AESEC's majority-owned power facility in Murcia, Spain. In October 2007, the Contractor denied AESEC's claims and asserted counterclaims to recover approximately €12 million ($17 million) for alleged unpaid milestone and scope change order payments, among other things, and an unspecified amount for an alleged early completion bonus. The final hearing is scheduled to begin in June 2009. AESEC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In November 2007, the International Brotherhood of Electrical Workers, Local Union No. 1395, and sixteen individual retirees, (the "Complainants"), filed a complaint at the Indiana Utility Regulatory Commission ("IURC") seeking enforcement of their interpretation of the 1995 final order and associated settlement agreement resolving IPL's basic rate case. The Complainants are requesting that the IURC conduct an investigation of IPL's failure to fund the Voluntary Employee Beneficiary Association Trust ("VEBA Trust"), at a level of approximately $19 million per year. The VEBA Trust was spun off to an independent trustee in 2001. The complaint seeks an IURC order requiring IPL to make contributions to place the VEBA Trust in the financial position in which it allegedly would have been had IPL not ceased making annual contributions to the VEBA Trust after its spin off. The complaint also seeks an IURC order requiring IPL to resume making annual contributions to the VEBA Trust. IPL filed a motion to dismiss and both parties are seeking summary judgment in the IURC proceeding. To date, no procedural schedule for this proceeding has been established. IPL believes it has meritorious defenses to the Complainants' claims and it will assert them vigorously in response to the complaint; however, there can be no assurances that it will be successful in its efforts.

        In September 2007, the New York Attorney General issued a subpoena to the Company seeking documents and information concerning the Company's analysis and public disclosure of the potential impacts that greenhouse gas ("GHG") legislation and climate change from GHG emissions might have on the Company's operations and results. The Company has produced documents and information in response to the subpoena.

        In October 2007, the Ekibastuz Tax Committee issued a notice for the assessment of certain taxes against AES Ekibastuz LLP. A portion of the assessment, approximately $1.7 million, relates to alleged environmental pollution. The review by the Ekibastuz Tax Committee is ongoing and their decision on any assessment, including the portion related to alleged environmental pollution, is not yet final. In addition, as the result of a subsequent tax audit which was completed on January 24, 2008, an additional amount of approximately 36 million KZT in principal, 20 million KZT in interest and 13 million KZT in penalty (collectively, approximately $600,000), was assessed as underpayment of taxes for the 2004 calendar year and VAT for January 2004. AES Ekibastuz appealed these assessments. However, this position was rejected by the Regional Tax Committee in a decision dated January 30, 2008. On February 29, 2008, AES Ekibastuz appealed to the Ministry of Finance of the Republic of Kazakhstan and is currently awaiting a decision.

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        In February 2008, the Native Village of Kivalina, Alaska, and the City of Kivalina filed a complaint in the U.S. District Court for the Northern District of California against the Company and numerous unrelated companies, claiming that the defendants' alleged greenhouse gas emissions are destroying the plaintiffs' alleged land. The plaintiffs assert nuisance and concert of action claims against the Company and the other defendants, and a conspiracy claim against a subset of the other defendants. The plaintiffs seek to recover relocation costs, indicated in the complaint to be from $95 million to $400 million, and other alleged damages from the defendants, which are not quantified. The Company has filed a motion to dismiss the case, which the plaintiffs have opposed. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        A public civil action has been asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the "Associação") relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld on the first appeal found that Eletropaulo should either repair the alleged environmental damage by demolishing certain construction and reforesting the area, pursuant to a project which would cost approximately $628,000, or pay an indemnification amount of approximately $5 million. Eletropaulo has appealed this decision to the Supreme Court and is awaiting a decision.

        In 2007, a lower court issued a decision related to a 1993 claim that was filed by the Public Attorney's office against Eletropaulo, the São Paulo State Government, SABESP (a state owned company), CETESB (a state owned company) and DAEE (the municipal Water and Electric Energy Department), alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from Pinheiros River into Billings Reservoir. The events in question occurred while Eletropaulo was a state owned company. The initial lower court decision in 2007 found the parties liable for the payment of R$517.46 million ($221 million) for remediation. Eletropaulo subsequently appealed the decision and Eletropaulo is still awaiting a decision on the appeal. The filing of the appeal suspended the lower court's decision. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In September 2008, IPL received a CAA Section 114 information request. The request seeks various information regarding production levels and projects implemented at IPL's generating stations, generally for the time period from January 1, 2001 to the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. At this time it is not possible to predict what impact, if any, this request may have on IPL, its results of operation or its financial position.

        In November 2007, the U.S. Department of Justice ("DOJ") indicated to AES Thames, LLC ("AES Thames") that the U.S. EPA had requested that the DOJ file a federal court action against AES Thames for alleged violations of the CAA, the Clean Water Act ("CWA"), the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and the Emergency Planning and Community Right-to-Know Act ("EPCRA"), in particular alleging that AES Thames had violated (i) the terms of its Prevention of Significant Deterioration ("PSD") air permits in the calculation of its steam load permit limit; and (ii) the CWA, CERCLA and EPCRA in connection with two spills of chlorinating agents. The DOJ subsequently indicated that it would like to settle this matter prior to filing a suit and negotiations are ongoing. During such discussions, the DOJ and EPA have accepted AES Thames method of operation and have asked AES Thames to seek a minor permit modification to clarify the air permit condition. On October 21, 2008, the DOJ proposed a civil penalty of $245,000 for the alleged violations. The Company believes that it has meritorious defenses to the claims asserted against it and if a settlement cannot be achieved, the Company will defend itself vigorously in any lawsuit.

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        In December 2008 there were press reports that the National Electricity Regulatory Entity of Argentina ("ENRE") had filed a criminal action in the National Criminal and Correctional Court of Argentina against the board of directors and administrators of EDELAP, an AES subsidiary. Although EDELAP has not been officially served with notice of the action, press reports have stated that ENRE's action concerns certain bank cancellations of EDELAP debt in 2006 and 2007, which were accomplished through transactions between the banks and related AES companies. According to press reports, ENRE claims that EDELAP should have reflected in its accounts the alleged benefits of the transactions that were allegedly obtained by the related companies. EDELAP believes that the allegations lack merit; however, there can be no assurances that its board and administrators will be successful in any formal proceedings concerning the allegations.

        In January 2009 an alleged shareholder of the Company filed a shareholder derivative and putative class action in Delaware state court against the Company and certain members of its board of directors. The plaintiff claims that Section 2.17(B) of the Company's bylaws, concerning shareholder action by written consent, is illegal under Delaware law. The plaintiff does not seek damages but declarations that Section 2.17(B) is unlawful and void and that the board member defendants breached their respective fiduciary duties of loyalty by adopting that bylaw in October 2008. The plaintiff further seeks to recover his litigation costs. The Company defendants believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

        A CAA Section 114 information request regarding Cayuga and Somerset was received in February 2009. The request seeks various operating and testing data and other information regarding certain types of projects at the Cayuga and Somerset facilities, generally for the time period from January 1, 2000 through the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. At this time it is not possible to predict what impact, if any, this request may have on Cayuga and/or Somerset, their results of operation or their financial position.

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        No matters were submitted to a vote of security holders during the fourth quarter of 2008.

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PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

        On August 7, 2008, the Company's Board of Directors approved a share repurchase plan for up to $400 million of its outstanding common stock. The Board authorization permits the Company to effect the repurchase of shares for a six month period. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time. The Company repurchased 10,691,267 shares of its common stock during the third quarter of 2008 and did not repurchase any shares of its common stock during the fourth quarter of 2008. The remaining amount authorized to be purchased under the share repurchase plan as of December 31, 2008 was $257 million. No shares were repurchased subsequent to December 31, 2008 and the board authorization of the plan expired on February 7, 2009.

Market Information

        Our common stock is currently traded on the New York Stock Exchange ("NYSE") under the symbol "AES." The closing price of our common stock as reported by the NYSE on February 24, 2009, was $6.82, per share. The Company repurchased 10,691,267 shares of its common stock in 2008 and did not repurchase any of its common stock in 2007 or 2006. The following tables set forth the high and low sale prices, and performance trends for our common stock as reported by the NYSE for the periods indicated:

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Performance Graph

THE AES CORPORATION
PEER GROUP INDEX/STOCK PRICE PERFORMANCE

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURNS
ASSUMES INITIAL INVESTMENT OF $100

Source: Bloomberg

        We have selected the Standard and Poor's ("S&P") 500 Utilities Index as our peer group index. The S&P 500 Utilities Index is a published sector index comprising the 32 electric and gas utilities included in the S&P 500.

        The five year total return chart assumes $100 invested on December 31, 2003 in AES Common Stock, the S&P 500 Index and the S&P 500 Utilities Index. The information included under the heading "Performance Graph" shall not be considered "filed" for purposes of Section 18 of the Securities Exchange Act of 1934 or incorporated by reference in any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934.

Holders

        As of February 24, 2009, there were approximately 7,722 record holders of our common stock, par value $0.01 per share.

Dividends

        We do not currently pay dividends on our common stock. We intend to retain our future earnings, if any, to finance the future development and operation of our business. Accordingly, we do not anticipate paying any dividends on our common stock in the foreseeable future.

        Under the terms of our Senior Secured Credit Facilities, which we entered into with a commercial bank syndicate, we have limitations on our ability to pay cash dividends and/or repurchase stock. In addition, under the terms of a guaranty we provided to the utility customer in connection with the AES Thames project, we are precluded from paying cash dividends on our common stock if we do not meet certain net worth and liquidity tests.

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        Our project subsidiaries' ability to declare and pay cash dividends to us is subject to certain limitations contained in the project loans, governmental provisions and other agreements to which our project subsidiaries are subject.

        See Item 12 (d) of this Form 10-K for information regarding Securities Authorized for Issuance under Equity Compensation Plans.

ITEM 6.    SELECTED FINANCIAL DATA

        The following table sets forth our selected financial data as of the dates and for the periods indicated. You should read this data together with Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and the notes thereto included in Item 8 in this Annual Report on Form 10-K. The selected financial data for each of the years in the five year period ended December 31, 2008 have been derived from our audited Consolidated Financial Statements. Our historical results are not necessarily indicative of our future results.

        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 included in Item 8 Financial Statements and Supplementary Data of this Form 10-K for further explanation of the effect of such activities. Please also refer to Item 1A Risk Factors and Note 24—Risks and Uncertainties to the Consolidated Financial Statements included in Item 8 of this Form 10-K for certain risks and uncertainties that may cause the data reflected herein not to be indicative of our future financial condition or results of operations.

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SELECTED FINANCIAL DATA

 

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ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview of Our Business

        AES is a global power company. We own or operate a portfolio of electricity generation and distribution businesses with generation capacity totaling approximately 43,000 MW and distribution networks serving over 11 million people. In addition, we have more than 3,000 MW under construction in ten countries. Our global footprint includes operations in 29 countries on five continents with 83% of our revenue in 2008 generated outside the United States.

        We operate two primary lines of business. The first is our Generation business, where we own and/or operate power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. The second is our Utilities business, where we own and/or operate utilities to distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. Each of our primary lines of business generates approximately half of our revenues.

        We are also continuing to expand our wind generation business and are pursuing additional renewables projects in solar, climate solutions, biomass and energy storage. These initiatives are not material contributors to our revenue, gross margin or income, but we believe that they may become material in the future.

        Generation.    We currently own or operate a portfolio of approximately 38,000 MW, consisting of 93 facilities in 26 countries on five continents at our generation businesses. We also have approximately 2,900 MW of capacity currently under construction in six countries. Our core Generation businesses use a wide range of technologies and fuel types including coal, combined-cycle gas turbines, hydroelectric power and biomass.

        The majority of the electricity produced by our Generation businesses is sold under long-term contracts, or PPAs, to wholesale customers. Approximately 61% of the revenues from our Generation businesses during 2008 was derived from plants that operate under PPAs of five years or longer for 75% or more of their output capacity. These businesses often reduce their exposure to fuel supply risks by entering into long-term fuel supply contracts or fuel tolling contracts where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. These long-term contractual agreements result in relatively predictable cash flow and earnings and reduce exposure to volatility in the market price for electricity and fuel; however, the amount of earnings and cash flow predictability varies from business to business based on the degree to which its exposure is limited by the contracts that it has negotiated.

        The balance of our Generation businesses sell power through competitive markets under short-term contracts or directly in the spot market. As a result, the cash flows and earnings associated with these businesses are more sensitive to fluctuations in the market price for electricity, natural gas, coal and other fuels. However, for a number of these facilities, including our plants in New York, which include a fleet of coal fired plants, we have hedged the majority of our exposure to fuel, energy and emissions pricing for 2009.

        Utilities.    Our Utilities businesses distribute power to more than 11 million people in seven countries on five continents. Our Utilities business consists primarily of 14 companies owned and/or operated under management agreements, all of which operate in a defined service area. These businesses also include 15 generation plants in two countries totaling approximately 4,400 MW. In addition, we have one generation plant under construction totaling 86 MW. These businesses have a variety of structures ranging from pure distribution businesses to fully integrated utilities, which generate, transmit and distribute power.

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        Renewables and Other Initiatives.    In recent years, as demand for renewable sources of energy has grown, we have placed increasing emphasis on developing projects in wind, solar, energy storage and the creation of carbon offsets. We have also developed projects and investments in climate solutions and energy storage. AES Wind Generation, which is one of the largest producers of wind power in the U.S., has 16 wind generation facilities in three countries with over 1,200 MW in operation and 11 wind generation facilities under construction in four countries. AES Solar, our joint venture with Riverstone Holdings, was formed to develop, own and operate utility-scale photo voltaic (PV) solar installations. Since its launch, AES Solar has developed eight plants totaling 24 MW of solar projects in Spain. In climate solutions, we have developed and are implementing projects to produce GHG Credits. In the U.S., we formed Greenhouse Gas Services, LLC as a joint venture with GE Energy Financial Services to create high quality verifiable offsets for the voluntary U.S. market. We also have formed an initiative to develop and implement utility scale energy systems (such as batteries), which store and release power when needed. While these renewables and other initiatives are not currently material to our operations, we believe that in the future, they may become a material contributor to our revenue and gross margin. However, there are risks associated with these initiatives, which are further disclosed in Item 1A—Risk Factors of this Form 10-K.

        Our Organization and Segments.    As of the end of 2008, our Generation and Utilities businesses were organized within four defined geographic regions: (1) Latin America, (2) North America, (3) Europe & Africa, and (4) Asia and the Middle East, ("Asia"). Three regions, North America, Latin America and Europe & Africa, are engaged in both Generation and Utility businesses while the Asia region operates only Generation businesses. Accordingly, these businesses and regions account for seven reportable segments. "Corporate and Other" includes corporate overhead costs which are not directly associated with the operations of our seven primary reportable segments; interest income and expense; other inter-company charges such as management fees and self-insurance premiums which are fully eliminated in consolidation; and revenue, development costs and the operational results related to AES Wind Generation and our other renewables projects, which are currently not material to our operations.

        Beginning in 2009, the Company began to implement certain organizational changes in an effort to streamline the organization. The new structure will continue to be organized along our two lines of business, but within three regions instead of four: (1) North America, (2) Latin America & Africa and (3) Europe, Middle East & Asia ("EMEA"). In addition, we will no longer have an alternative energy group, the operation of which was previously reported under "Corporate and other." Instead, AES Wind Generation, will be managed as part of our North America region (even though some projects are not in North America) while climate solutions projects will be managed in the region in which they are located. Management is currently evaluating the impact of the reorganization on the Company's externally reported segments in accordance with SFAS No. 131. AES Solar is accounted for using the equity method and will continue to be reflected in Corporate and Other in 2009.

        Key Drivers of Our Results of Operations.    Our Utilities and Generation businesses are distinguished by the nature of their customers, operational differences, cost structure, regulatory environment and risk exposure. As a result, each line of business has slightly different drivers which affect operating results. Performance drivers for our Generation businesses include, among other things, plant availability and reliability, management of fixed and operational costs and the extent to which our plants have hedged their exposure to fuel cost volatility. For our Generation businesses which sell power under short-term contract or in the spot market one of the most crucial factors is the market price of electricity and the plant's ability to generate electricity at a cost below that price. Growth in our Generation business is largely tied to securing new PPAs, expanding capacity in our existing facilities and building new power plants. Performance drivers for our Utilities businesses include, but are not limited to, reliability of service; negotiation of tariff adjustments; compliance with extensive regulatory requirements; management of working capital; and in developing countries, reduction of

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commercial and technical losses. The results of operations of our Utilities businesses are sensitive to changes in economic growth and weather conditions in the area in which they operate.

        One of the key factors which affect both our revenue and costs of sales is changes in the cost of fuel. When fuel costs increase, many of our Generation businesses with long-term contracts and our Utilities are able to pass these costs on to the customer through fuel pass-through or fuel indexing arrangements in their contracts or through increases in tariff rates. Therefore, in a rising fuel cost environment as was the case in 2007 and much of 2008, increases in fuel costs for these businesses often resulted in increases in revenue (though not necessarily on a one-for-one basis). While these circumstances may not have a large impact on gross margin, they can significantly affect gross margin as a percentage of revenue. Other factors that can affect gross margin include our ability to expand the number of facilities we own; and in our existing plants, to sign up new customers and/or purchasing parties, collect receivables from existing customers and operate our plants more efficiently.

        Another key driver of our results is the management of risk. Our assets are diverse with respect to fuel source and type of market, which helps reduce certain types of operating risk. Our portfolio employs a broad range of fuels, including coal, gas, fuel oil and renewable sources such as hydroelectric power, wind and solar, which reduces the risks associated with dependence on any one fuel source. For additional information regarding our facilities see Item 1—Our Organization and Segments. Our presence in mature markets helps reduce the volatility associated with our businesses in faster-growing emerging markets. In addition, as noted above, our Generation portfolio is largely contracted, which reduces the risk related to the market prices of electricity and fuel. We also attempt to limit risk by hedging much of our currency and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the business that issued that debt. However, our businesses are still subject to these risks, as further described in Item 1A—Risk Factors, "We may not be adequately hedged against our exposure to changes in commodity prices or interest rates."

Highlights of 2008

        Results of Operations.    In 2008, management continued to focus its efforts on increasing shareholder value by improving operations, executing our growth strategy and strategically managing our portfolio of businesses. Our 2008 results of operations were positively impacted by a number of factors including the gain on the sale of Ekibastuz and Maikuben in Kazakhstan, higher generation rates, utilities tariffs and favorable foreign currency translation.

•

revenues of $16.1 billion and gross margin of $3.7 billion, or 23% of revenue;



•

income from continuing operations of $1.2 billion, or $1.80 per diluted share; and



•

cash flow from operating activities of $2.2 billion.

        Our results were negatively impacted by higher fuel costs in Asia and the unfavorable impact of mark-to-market adjustments on derivative instruments. We also saw an increase in fixed costs, primarily in Brazil and Cameroon, related to maintenance, higher provisions for bad debt, contractor services and higher purchased energy costs.

        In the fourth quarter of 2008, and in response to the financial market crisis, we reviewed and prioritized projects in our development pipeline. As a result, we recognized an impairment charge of approximately $75 million ($34 million, net of minority interest and income taxes). The projects determined to be impaired primarily included two liquefied natural gas projects in North America and a non-power development project at one of our facilities in North America. As the Company continues to review and streamline its project pipeline, it is possible that further impairments could be identified in the future, some of which could be material. During 2008, we also recognized additional impairment charges of $36 million related to long-lived assets at Uruguaiana, our gas-powered generation plant in Brazil. The impairment was triggered by the combination of gas curtailments and increases in the spot

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market price of energy in 2007 that continued in 2008. Following an initial impairment charge in the fourth quarter of 2007, further charges were incurred in 2008 due to fixed asset purchase agreements in place. During the first half of 2008, we withdrew from projects in South Africa and Israel which resulted in impairment charges of $36 million. We also recognized an impairment of $18 million related to the shutdown of the Hefei plant in China.

        Investment and Financing Activities.    In addition to the financial results presented above, the additional highlights for the year ended December 31, 2008 include the following:

Financing activities

•

We were able to refinance recourse debt at lower interest rates and with extended maturities, reducing our 2009 recourse debt maturities from $467 million at December 31, 2007 to $154 million at December 31, 2008.



•

Our consolidated subsidiaries raised approximately $2.7 billion in 2008 for the purposes of refinancing existing debt and to fund acquisitions and construction. For example, in October, the Company obtained approximately $1 billion in non-recourse financing to support the development of Angamos, a 518 MW coal-fired generation facility in Chile. Angamos is expected to begin commercial operations in 2011.



•

We reduced outstanding recourse debt by $360 million and repurchased 10.7 million shares of our common stock at a total cost of $143 million.

Acquisitions

•

In April, the Company completed the purchase of a 92% interest in Masinloc, a 660 gross MW coal-fired thermal power generation facility in Masinloc, Philippines. The purchase price was $930 million in cash (excluding anticipated improvements). Non-recourse financing of $665 million was obtained to fund the acquisition and improve the facilities.

Investments in Renewable Energy and Related Projects

•

Wind Generation—Highlights from AES Wind Generation include the following:



•

The Company expanded its portfolio of wind generation businesses with the acquisition of Mountain View Power Partners ("Mountain View"), which consists of 111 wind turbines with a capacity of 67 MW in Palm Springs, California.



•

In July, we acquired a 49% interest in Guohua Hulunbeier Wind Farm, a 49.5 MW wind farm development in China. The Company also reached a separate agreement with Guohua to move to phase II of our jointly-owned Huanghua wind project to expand the facility, doubling the capacity to 99 MW. AES has a 49% interest in the Huanghua Project.



•

In December, the Company obtained financing to build a 156 MW wind farm in Kavarna, the largest in Bulgaria, and a 22 MW wind farm in Scotland. Additionally we acquired a 34 MW wind farm from our affiliate, InnoVent. All three are expected to commence commercial operations in 2009.



•

Solar Energy—In March, the Company formed AES Solar, a joint venture with Riverstone. AES Solar will develop land-based solar photovoltaic panels that capture sunlight to convert into electricity that feed directly into power grids. AES Solar has commenced commercial operations of 24 MW solar projects in Spain. Under the terms of the agreement, the Company and Riverstone will each provide up to $500 million of capital over the next five years. Through December 31, 2008, the Company has contributed total capital of $135 million.

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•

Climate Solutions—Highlights from our climate solutions activities include:



•

In April, the Company acquired the rights to the gas from a landfill project in El Salvador ("Nejapa"). Nejapa produces emission reduction credits and plans to build a 6 MW generation facility that could potentially increase to 25 MW in the future.



•

In June, as a result of a financial restructuring, the Company assumed 100% ownership of AgCert International Plc, an Irish company investing in GHG projects primarily in Brazil and Mexico. AgCert currently produces approximately 1.4 million tonnes per year of CERs.



•

In September, Greenhouse Gas Services LLC, the Company's joint venture with General Electric, announced an agreement with Google to co-develop projects to reduce GHG emissions and produce GHG credits. The first project will capture methane gas in North Carolina.

Construction

        As of December 31, 2008, the Company has more than 3,000 Gross MW of new generation capacity. The projects under construction include 14 core power projects totaling 2,993 MW and 11 wind power projects totaling 410 MW.

•

We began construction of Angamos, a 518 MW coal-fired generation facility in Chile expected to begin commercial operations in 2011.



•

We also further advanced our recent projects with the start of construction of three hydro projects in Turkey that are being developed through our investment made in May 2007 in the IC Ictas Energy Group.



•

In July, the Company achieved early successful testing of simple cycle operation for the Amman East facility in Jordan, a 380 MW natural gas-fired project expected to achieve full combined-cycle operation in the first half of 2009.



•

In August, the Company started commercial operations of the 170 MW Buffalo Gap III wind farm in Abilene, Texas, bringing the total wind generation capacity of the Buffalo Gap wind farm to 524 MW.

        For a complete listing of the Company's projects under construction or in development please see Item 1—Our Organizations and Segments.

Portfolio Management

•

In the first quarter of 2008, the Company finalized our termination agreement with the Chinese government and shut down Hefei, a 115 MW oil-fueled generation facility. The plant became the property of the Anhui Province and we received termination compensation of approximately $39 million in March 2008.



•

In May 2008, the Company completed the sale of Ekibastuz and Maikuben West, a coal-fired power plant and a coal mine with operations in Kazakhstan. Proceeds from the sale of these businesses totaled approximately $1.1 billion, a portion of which was used to pay down debt in June 2008. We have the opportunity to receive additional consideration of up to approximately $380 million under performance incentives and a management agreement to continue operation and management of the plants for the next three years.



•

In November 2008, the Company sold a 9.6% ownership in AES Gener for $175 million which reduced the Company's ownership percentage from 80.2% to 70.6%. As a result, the Company recognized a pre-tax loss of $31 million in the fourth quarter of 2008. The net proceeds from

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this transaction were used to participate in Gener's capital increase in February 2009 as discussed under Outlook for the Future.

•

In December 2008, the Company sold its 70% interest in Jiaozuo, a 250 MW coal-fired generation plant in China for net proceeds of $73 million. Prior periods have been restated to reflect this business within Discontinued Operations for all periods presented.

Credit Crisis and the Macroeconomic Environment

        In the second half of 2007, conditions in the credit markets began to deteriorate in the United States and abroad. In the third and fourth quarter of 2008, this crisis and associated market conditions worsened dramatically, with unprecedented market volatility, widening credit spreads, volatile currencies, illiquidity, and increased counterparty credit risk.

        Beginning in the second half of 2007, the Company began a series of debt-related initiatives, including the refinancing of approximately $2.0 billion of recourse debt in transactions executed in the fourth quarter of 2007 and the second quarter of 2008. As a result of these transactions, The AES Corporation reduced the 2009 maturities on its recourse debt from $467 million as of June 30, 2007 to $154 million as of December 31, 2008. The AES Corporation also eliminated many of the restrictive covenants in its 8.75% Second Priority Senior Secured Notes due 2013 and modified certain covenants contained in its senior secured credit facility. The amendments made the financial covenants less restrictive and made certain other changes, such as expanding the Company's ability to repurchase its own common stock. For further information regarding these covenant changes, see the Capital Resources and Liquidity—Parent Company Liquidity section of Management's Discussion and Analysis of Financial Condition and Results of Operations. In addition, The AES Corporation successfully replaced Lehman Commercial Paper with another bank as a lender under its senior secured credit facility.

        Because of the factors described above, management currently believes that it can meet its near-term liquidity requirements through a combination of existing cash and cash equivalent balances, cash provided by operating activities, financings, and, if needed, borrowings under its secured and unsecured credit facilities. Although there can be no assurance due to the challenging times currently faced by financial institutions, management believes that the participating banks under its facilities will be able to meet their funding commitments.

        The Company is also subject to credit risk, which includes risk related to the ability of counterparties (such as parties to our PPAs, fuel supply agreements, hedging agreements, and other contractual arrangements) to meet their contractual payment obligations or the potential nonperformance of counterparties to deliver contracted commodities or services at the contracted price. While counterparty credit risk has increased in the current crisis and there can be no assurances regarding the future, to date the Company has not suffered any material effects related to its counterparties.

        The global economic slowdown could also result in a decline in the value of our assets, which could result in material impairments of certain assets or result in an increase in our obligations which could be material to our operations. For example, as discussed above, during the fourth quarter of 2008, and in response to the financial market crisis, the Company reviewed and prioritized the projects in our development pipeline. As a result we recognized an impairment charge of approximately $75 million ($34 million, net of minority interest and income taxes). The projects that were impaired included two liquefied natural gas projects in North America and a non-power development project at one of our facilities in North America.

        In addition to the decline in development assets noted above, there is a risk that the fair value of other assets could also decline, resulting in additional impairment charges and/or a material increase in

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our obligations. Certain subsidiaries of the Company have defined benefit pension plans. The Company periodically evaluates the value of the pension plan assets to ensure that they will be sufficient to fund their respective pension obligations. Given the declines in worldwide asset values, we are expecting an increase in pension expense and funding requirements in future periods, which may be material. As of December 31, 2008 we expect the Company to make future employer contributions to its defined benefit pension plans in 2009 of approximately $154 million, of which $21 million will be made to its U.S. plans and $133 million to foreign plans primarily in Brazil (subject to changes in foreign currency exchange rates), compared to employer contributions made in 2008 of $197 million, of which $59 million was made to U.S. plans and $138 million to foreign plans. In Brazilian real ("R$") contributions for our subsidiaries in Brazil are expected to increase from R$236 million in 2008 to R$294 million in 2009. The decline in the fair value of pension plan assets will also result in increased pension expense in 2009, currently estimated at $124 million in 2009 (subject to changes in foreign currency exchange rates) compared to $60 million in 2008. Expense at our subsidiaries in Brazil, in local currency, is expected to be R$176 million in 2009 compared to R$77 million in 2008. See Item 1A—Risk Factors, "Some of our subsidiaries participate in defined benefit pension plans and their net pension plan obligations may require additional significant contributions."

        To date, other than the impacts described above, the global economic slowdown has not significantly impacted the Company. However, in the event that the credit crisis and global recession deteriorate further, or are protracted, there could be a material adverse impact on the Company. The Company could be materially impacted if such events or other events occur such that participating lenders under its secured and unsecured facilities fail to meet their commitments, or the Company is unable to access the capital markets on favorable terms or at all, is unable to raise funds through the sale of assets, or is otherwise unable to finance its activities or refinance its debt, or if capital market disruptions result in increased borrowing costs (including with respect to interest payments on the Company's variable rate debt). The Company could also be adversely affected if general economic or political conditions in the markets where the Company operates deteriorate, resulting in a reduction in cash flow from operations, a reduction in the value of currencies in these markets relative to the dollar (which could cause currency losses), an increase in the price of commodities used in our operations and construction, or if the value of its assets remain depressed or decline further. If any of the foregoing events occur, such events (or a combination thereof) could have a material impact on the Company, its results of operations, liquidity, financial covenants, and/or its credit rating.

        The Company could also be adversely affected if the foregoing effects are exacerbated or general economic or political conditions in the markets where the Company operates deteriorate, resulting in a reduction in cash flow from operations, a reduction in the value of currencies in these markets relative to the dollar (which could cause currency losses), an increase in the price of commodities used in our operations and construction or a decline in asset values.

Outlook for the Future

        In 2008, management continued to focus its efforts on improving operations, executing our growth strategy, managing our risk and strategically managing our portfolio of businesses. As market conditions deteriorated in the second half of 2008, our strategy evolved, with an increased emphasis on preserving liquidity. We also recognized that uncertain economic conditions could potentially slow global demand for power for some period of time. Accordingly, we scaled back our development plans mid-year to focus on projects that we believe will still have attractive returns and can still attract capital in difficult financial markets and on completing our projects that are currently under construction. If the Company has capital available for investment beyond these priorities (whether for further development, reductions in debt, or repurchases of stock), it will be allocated based on management's assessment of its most effective use.

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        Consistent with this strategy, in the fourth quarter of 2008, management conducted a review of its development pipeline, and determined that certain projects in the pipeline may not achieve financial close, will not provide the returns originally anticipated, or are otherwise unfeasible, or that other uses of capital such as debt repayment or stock repurchases offer a better return on the Company's capital. Accordingly, management has determined it will not pursue certain projects and will delay others until the credit markets recover. Furthermore, management will continue to review its pipeline and may further reduce the number of projects it pursues. The Company is also evaluating other options with respect to its pipeline, such as the addition of partners who can contribute capital, share project risk and/or provide strategic expertise. There can be no assurance regarding the outcome of any such decisions on the Company, its results of operations or its financial condition.

        The AES Corporation has $154 million in recourse debt maturing in 2009 compared with Parent Company liquidity of approximately $1.4 billion.

        With regard to its projects currently under construction, the Company believes that it can complete these projects through a combination of existing cash and cash equivalent balances, cash provided by operating activities, financings, and, if needed, borrowings under its secured and unsecured credit facilities. The Company has secured the financing for the vast majority of projects under construction.

        The Company is also focused on operational improvements and cost reductions to help further improve its cash flow from operations and enhance its financial flexibility. The Company has already commenced efforts to reduce costs and streamline our organization. These efforts include the reorganization of the Company from four regions to three regions, which is expected to eliminate redundancies and improve our cost structure.

Recent Events

        On December 23, 2008, the local Chilean SEC approved Gener's issuance of approximately 945 million new shares at a price of $162.50 Chilean Pesos. The proceeds of the share issuance were $246 million and Gener anticipates using these proceeds for future expansion plans, working capital and other operating needs. The preemptive rights period began on January 7, 2009 remained open for 30 days and closed on February 5, 2009. During the preemptive rights period AES, through its wholly-owned subsidiary, Cachagua, paid $175 million from the proceeds of the November 2008 share sale to maintain its current ownership percentage of approximately 70.6%.

2008 Performance Highlights

Revenue

        Revenue increased 19% to $16.1 billion in 2008 compared with $13.5 billion in 2007 primarily due to higher generation rates in Latin America, the impact of favorable foreign currency translation of approximately $350 million and utility tariffs and volume.

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Gross margin

        Gross margin increased 9% to $3.7 billion in 2008 compared with $3.4 billion in 2007 primarily due to higher generation rates in Latin America, favorable foreign currency impact, utility volume and tariff, partially offset by an increase in fixed costs associated with allowances for bad debts and higher purchased energy costs, primarily in Brazil and Cameroon. Gross margin as a percentage of revenue decreased to 23.1% in 2008 compared with 25.1% in 2007 driven by the increase in fixed costs.

        Our gross margin remained at approximately $3.4 billion in 2006 and 2007 and increased to $3.7 billion in 2008. Gross margin however declined in the fourth quarter of 2008 due to several factors including the mix of earnings within our portfolio, foreign currency exchange rates, commodity prices, and recent acquisitions, such as Masinloc in the Philippines. We believe that it is reasonably possible that the recent trend in gross margin reported in the fourth quarter will continue. The Company's future gross margin trends may be significantly impacted by currency exchange rates, commodity prices and the impact of any significant regulatory developments in each country where the Company conducts its business. The Company is subject to extensive and complex governmental regulations which affect most aspects of our business, such as regulations governing the generation and distribution of electricity and environmental regulations, as described more fully in the Business section of the Form 10-K.

Diluted earnings per share from continuing operations

        Diluted earnings per share from continuing operations increased $1.08 per share to $1.80 per share in 2008 compared to $0.72 per share in 2007. The 2008 results included a net positive impact of $0.74 per share relating to : (i) a gain from the sale of the Company's northern Kazakhstan businesses in the second quarter of 2008 of $905 million (pre-tax) or $1.31; (ii) additional tax expense of $144 million or $0.21 related to the repatriation of a portion of the Kazakhstan sale proceeds (iii) loss related to corporate debt restructuring charges of $55 million (pre-tax) or $0.05 (iv) impairment charges taken in the fourth quarter on certain LNG and other development efforts of $34 million (net of tax and minority interest) or $0.05, (v) other impairment charges in Brazil and South Africa of $45 million (net of tax and minority interest) or $0.06 and (vi) net currency translation and transaction losses of $0.20 per share. These were compared to 2007 results which included (i) a gain of approximately $0.15 per diluted share related to the acquisition of a leasehold interest at Eastern Energy in New York and the recovery of certain tax assets in Latin America; (ii) impairment charges related to Uruguaiana and AgCert of $0.33 per share and (iii) corporate debt retirement costs in 2007 of $0.08 per share. The remaining increase in diluted earnings per share from continuing operations from 2007 to 2008 of $0.08 per share is mainly the result of improved performance in 2008.

Net cash from operating activities

        Net cash from operating activities decreased 8% to $2.2 billion in 2008 compared with $2.4 billion in 2007. Excluding the decrease in net cash provided by operating activities from EDC in Venezuela, which was sold in May 2007, net cash provided by operating activities would have decreased $37 million. This decrease was primarily due to increased employer pension contributions at our U.S. and foreign subsidiaries and an increase in regulatory assets related to future recoverable purchased energy costs in Brazil. These decreases were partially offset by a decrease in cash used by a Brazilian subsidiary to pay income taxes in 2008 as a result of tax credits used as the primary payment method in 2008 and improved operations in Latin America and Europe & Africa. Please refer to Consolidated Cash Flows—Operating Activities for further discussion.

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Consolidated Results of Operations

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⁽¹⁾

Corporate and Other includes revenues from renewables and inter-segment eliminations of revenues related to transfers of electricity from Tietê (generation) to Eletropaulo (utility) in Latin America.

⁽²⁾

Total Corporate and Other expenses include corporate general and administrative expenses, expenses related to our renewables initiatives as well as certain inter-segment eliminations, primarily corporate charges for management fees and self insurance premiums.

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Segment Analysis

Latin America

        The following table summarizes revenue and gross margin for our Generation segment in Latin America for the periods indicated:

Fiscal Year 2008 versus 2007

        Generation revenue increased $955 million, or 27%, from the previous year primarily due to higher contract and spot prices and higher volume at Gener in Chile and our businesses in Argentina of approximately $508 million and $188 million, respectively, higher contract and spot prices at our businesses in the Dominican Republic of approximately $132 million, favorable foreign currency translation of approximately $77 million and higher spot prices at our businesses in Panama of approximately $45 million.

        Generation gross margin increased $439 million, or 46%, from the previous year primarily due to higher contract and spot prices and higher volume at Gener and our businesses in Argentina of approximately $318 million, higher contract and spot prices at our businesses in the Dominican Republic of approximately $86 million, favorable foreign currency translation of approximately $44 million, and higher spot prices at our businesses in Panama of approximately $30 million. These increases were partially offset by higher purchased energy prices of approximately $57 million at Uruguaiana in Brazil.

Fiscal Year 2007 versus 2006

        Generation revenue increased $895 million, or 34%, from the previous year primarily due to higher rates and volume at Gener and our businesses in Argentina of approximately $443 million and $95 million, respectively; and increased volume and intercompany sales from Tietê, in Brazil, to Eletropaulo, our Brazilian utility, of approximately $130 million. Our increase in ownership of the controlling shares of Itabo, in the Dominican Republic, which resulted in a change from the equity method of accounting consolidation, contributed approximately $87 million in revenue. The increase from foreign currency translation was approximately $38 million.

        Generation gross margin decreased $97 million, or 9%, from the previous year primarily due to increased cost from gas supply curtailments, drier than normal hydrology and higher spot prices for electricity in the Company's businesses in Argentina, Chile and Southern Brazil of approximately $173 million and one time transmission charges at Tietê of $39 million, offset in part, by higher sales at Itabo of $23 million and intercompany sales in Tietê of $103 million.

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        The following table summarizes revenue and gross margin for our Utilities segment in Latin America for the periods indicated:

Fiscal Year 2008 versus 2007

        Utilities revenue increased $739 million, or 14%, from the previous year primarily due to favorable foreign currency translation of approximately $357 million at our businesses in Brazil, increased rates primarily associated with higher pass-through purchased energy and transmission costs at Eletropaulo of approximately $148 million, and higher volume at Eletropaulo and Sul in Brazil of approximately $162 million and $30 million, respectively.

        Utilities gross margin increased $20 million, or 2%, from the previous year primarily due to higher volume at Eletropaulo of approximately $162 million and favorable foreign currency translation of approximately $67 million at our businesses in Brazil. These increases were partially offset by a decrease in the non-pass through rates at Eletropaulo as a result of the July 2007 tariff reset of approximately $74 million, increased fixed costs of approximately $71 million at Eletropaulo primarily due to higher provisions for bad debts and higher purchased energy costs at Eletropaulo of approximately $68 million.

Fiscal Year 2007 versus 2006

        Utilities revenue increased $620 million, or 14%, from the previous year primarily due to favorable foreign currency translation of $493 million, and increased rates and volume at Sul and at our plants in El Salvador of $58 million and $41 million, respectively, offset by a net decrease in tariffs of $24 million at Eletropaulo.

        Utilities gross margin decreased $23 million, or 3%, from the previous year primarily due to reduced tariff rates at Eletropaulo of $355 million offset by lower costs, favorable foreign currency translation of $148 million and higher volume of $74 million. Additionally, Sul had increased rates and volume of $27 million and favorable foreign currency translation of $19 million.

North America

        The following table summarizes revenue and gross margin for our Generation segment in North America for the periods indicated:

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Fiscal Year 2008 versus 2007

        Generation revenue increased $66 million, or 3%, from the previous year primarily due to higher volume of $38 million at TEG/TEP in Mexico, and net higher revenue at Merida in Mexico of $29 million primarily due to the pass-through of higher fuel costs offset by a revenue adjustment. In addition, revenue increased $8 million at Red Oak in New Jersey, due to higher pricing and availability bonuses. At Warrior Run in Maryland, revenue increased $12 million due to the pass-through of higher fuel costs and higher volume due to no significant outages in 2008. These effects were partially offset by lower volume in New York of $23 million primarily due to planned outages and lower capacity factors.

        Generation gross margin decreased $45 million, or 6%, and decreased as a percentage of revenue from the previous year due to lower gross margin in New York of $46 million mainly due to a planned outage and lower volume, and higher fuel prices and outages of $16 million at Deepwater in Texas. Gross margin decreased $13 million at TEG/TEP due primarily to outages and lower rates due to changes in the sales contract rates associated with the refinancing in 2007. These decreases were partially offset by a net increase in gross margin in Hawaii of $29 million primarily due to a $22 million net mark-to-market derivative gain on a coal supply contract and a one time use tax refund of $6 million.

Fiscal Year 2007 versus 2006

        Generation revenue increased $240 million, or 12%, from the previous year primarily due to approximately $200 million in new business as a result of our acquisition of TEG/TEP and approximately $96 million in higher rate and volume sales at the Company's New York facilities; offset by mark-to-market adjustments for embedded derivatives of $51 million at Deepwater and lower emission sales of $39 million.

        Generation gross margin increased $92 million, or 15%, from the previous year primarily due to approximately $62 million related to our acquisition of TEG/TEP and $90 million related to higher rates and volumes and lower cost at the Company's New York facilities offset by lower sales of excess emissions allowances of approximately $39 million.

        The following table summarizes revenue and gross margin for our Utilities segment in North America for the periods indicated:

Fiscal Year 2008 versus 2007

        Utilities revenue increased $27 million, or 3%, from the previous year primarily due to a $42 million increase in rate adjustments at IPL in Indiana, related to environmental investments, $42 million of higher fuel and purchased power costs and an $8 million increase in wholesale prices. These increases were offset by $32 million of credits to customers established during the first six months of 2008, $16 million of lower retail volume primarily due to unfavorable weather compared to 2007 and an $18 million decrease in wholesale volume.

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        Utilities gross margin decreased $52 million, or 17%, from the previous year primarily due to lower variable retail margin of $42 million driven by the credits to customers established during the first six months of 2008 and lower retail volume. In addition, IPL had higher maintenance expenses of $9 million primarily due to storm restoration costs and the timing and duration of major generating unit overhauls, an increase of $6 million in labor and benefits costs and an increase of $3 million in contractor and consulting costs. These decreases to gross margin were offset by a return recovered through rates on approved environmental investments of $14 million.

Fiscal Year 2007 versus 2006

        Utilities revenue increased $20 million, or 2%, from the previous year primarily due to increased volume due to weather, offset by a decrease in fuel charges passed through to customer at IPL.

        Utilities gross margin increased $36 million, or 13%, from the previous year primarily due to increased volume sales and a return recovered through rates on approved environmental investments at IPL.

Europe & Africa

        The following table summarizes revenue for our Generation segment in Europe & Africa for the periods indicated:

Fiscal Year 2008 versus 2007

        Generation revenue increased $185 million, or 19%, from the previous year primarily due to an increase in capacity income and energy payments at Kilroot in Northern Ireland of approximately $105 million, rate recovery and higher volume of approximately $93 million at our businesses in Hungary and favorable foreign currency translation in Hungary of $32 million. In addition, revenue at Kilroot increased approximately $21 million compared to the previous year primarily due to the unfavorable impact of two major overhauls in 2007. These increases were partially offset by a reduction in revenue of approximately $49 million in Kazakhstan following the sale of Ekibastuz and Maikuben in the second quarter of 2008 that was partially offset by approximately $12 million in management fees earned from continuing management agreements for those businesses. In addition, revenue at Kilroot was approximately $37 million lower due to the unfavorable impact of foreign currency translation.

        Generation gross margin increased $19 million, or 7%, from the previous year primarily due to higher rates and volume of $43 million at Tisza II in Hungary, and an increase in capacity income and fewer forced outages at Kilroot of approximately $32 million. These were offset by an increase in fixed costs of $24 million at Kilroot and Tisza II, unfavorable foreign currency translation of $12 million at Kilroot and a reduction in gross margin of $29 million in Kazakhstan following the sale of Ekibastuz and Maikuben in the second quarter of 2008 that was partially offset by $9 million in net gross margin from continuing management agreements for those businesses.

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Fiscal Year 2007 versus 2006

        Generation revenue increased $123 million, or 14%, from the previous year primarily due to favorable foreign currency translation of $77 million and increased rate and volume sales of approximately $60 million at our businesses in Kazakhstan.

        Generation gross margin increased $28 million, or 11%, from the previous year primarily due to rate and volume increases at our businesses in Kazakhstan and Kilroot of $44 million and $13 million, respectively. These increases were offset by lower emission sales in Hungary and Bohemia in the Czech Republic of approximately $28 million.

        The following table summarizes gross margin for our Utilities segments in Europe & Africa for the periods indicated:

Fiscal Year 2008 versus 2007

        Utilities revenue increased $122 million, or 18%, from the previous year primarily due to increased tariff rates of approximately $86 million at our businesses in Ukraine, approximately $30 million due to increased rates and volume and $26 million due to favorable foreign currency translation at Sonel in Cameroon. These increases were partially offset by an unfavorable foreign currency translation impact at our businesses in Ukraine of approximately $17 million.

        Utilities gross margin decreased $6 million, or 10%, from the previous year primarily due to higher fixed costs of approximately $55 million across the region, a mark-to-market derivative adjustment at Sonel of $9 million and the favorable impact in 2007 of fuel pass-through costs under a concession agreement of $6 million, partially offset by increased rates and volume at Sonel of approximately $36 million and increased tariff rates of approximately $23 million at our businesses in Ukraine.

Fiscal Year 2007 versus 2006

        Utilities revenue increased $90 million, or 16%, from the previous year primarily due to increased tariff rates and volume of approximately $57 million in the Ukraine and approximately $28 million in favorable foreign currency translation.

        Utilities gross margin decreased $40 million, or 39%, from the previous year primarily due to higher non-fuel operating and maintenance costs as well as higher fuel usage at Sonel.

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Asia

        The following table summarizes revenue and gross margin for our Generation segment in Asia for the periods indicated:

Fiscal Year 2008 versus 2007

        Generation revenue increased $447 million, or 55%, from the previous year primarily due to higher rates driven by increased pass-through fuel prices of $259 million and volume of $41 million at our Lal Pir and Pak Gen businesses in Pakistan, an increase in rates due to pass-through fuel prices at Kelanitissa in Sri Lanka, of approximately $55 million, and revenue generated from our new businesses, Masinloc in the Philippines, and Amman East in Jordan, of $148 million and $46 million, respectively. These increases were partially offset by unfavorable impact of foreign currency translation of $95 million in Pakistan.

        Generation gross margin decreased $33 million, or 19%, from the previous year primarily due to the impact of increased fuel prices on heat rate losses of approximately $14 million at Lal Pir and Pak Gen and a $15 million unfavorable impact on revenue from an amended PPA accounted for as a lease, and therefore revenue was recognized on a straight-line basis in accordance with EITF No. 01-8, Determining Whether an Arrangement Contains a Lease at Ras Laffan in Qatar. In addition, Masinloc generated a net gross margin loss of $18 million for the year ended December 31, 2008. These unfavorable effects were partially offset by the favorable impact of $14 million from the start of commercial operations in July 2008 at Amman East.

Fiscal Year 2007 versus 2006

        Generation revenue increased $99 million, or 14%, from the previous year primarily due to higher dispatch in Pakistan of $83 million and higher volume and rates at Kelanitissa of approximately $30 million offset by volume decreases of approximately $8 million at Chigen in China.

        Generation gross margin decreased $10 million, or 5%, from the previous year primarily due to decreased volume at Chigen.

Corporate and Other Expense

        Corporate and other expenses include general and administrative expenses, executive management, finance, legal, human resources, information systems and certain development costs which are not allocable to our business segments. In addition, this includes net operating results from AES Wind Generation and other renewables initiatives which are immaterial for the purposes of separate segment disclosure and, the effects of eliminating transactions, such as management fee arrangements and self-insurance charges, between the operating segments and corporate. For the years ended December 31, 2008, 2007 and 2006, Corporate and other expense was approximately 2 - 3% of total revenues.

        Corporate and other expense increased $19 million, or 6%, to $355 million in 2008 from $336 million in 2007. The increase was primarily due to higher spending of $16 million on

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SAP implementation projects and $27 million on the expansion of AES Wind Generation, climate solutions projects and our renewables initiatives, offset partially by a reduction in professional fees related to material weakness remediation efforts.

        Corporate and other expense increased $91 million, or 37%, to $336 million in 2007 from $245 million in 2006. The increase was primarily due to higher spending in professional fees of approximately $24 million primarily to complete the restatement of our financial statements and for continued material weakness remediation efforts, higher spending due to headcount increases primarily related to the strengthening of our finance organization of approximately $15 million and increased spending of $18 million for our SAP implementation projects.

Interest expense

        Interest expense increased $56 million, or 3%, to $1,844 million in 2008 primarily due to additional interest expense at our recently acquired subsidiary, Masinloc, interest expense associated with derivatives at Eletropaulo, Panama and Puerto Rico, as well as unfavorable foreign currency translation in Brazil. These increases were offset by decreases from the elimination of a financial transaction tax in Brazil, a decrease in regulatory liabilities at Eletropaulo, and a decrease in capitalized interest on development projects at Kilroot.

        Interest expense increased $19 million, or 1%, to $1,788 million in 2007 primarily due to unfavorable impacts from foreign currency translation in Brazil and interest expense associated with derivatives. These increases were offset by the benefits of debt retirement activity at several of our subsidiaries in Latin America and lower interest rates at one of our subsidiaries in Brazil.

Interest income

        Interest income increased $40 million, or 8%, to $540 million in 2008 primarily due to interest income on short-term investments and cash equivalents at two of our subsidiaries in Brazil, inflationary adjustments on accounts receivable at Gener, and interest earned on a convertible loan acquired in March 2008. These increases were offset by decreases due to lower interest income related to a gross receipts tax recovery at Tietê recorded during the second quarter of 2007 and decreased interest income related to derivatives at TEG/TEP.

        Interest income increased $66 million, or 15%, to $500 million in 2007 primarily due to favorable foreign currency translation on the Brazilian Real and higher cash and short-term investment balances at certain of our subsidiaries, offset by decreases at two of our Brazilian subsidiaries due to lower interest rates.

Other income

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        Other income increased $21 million to $379 million in 2008 primarily due to gains on the extinguishment of a gross receipts tax liability and legal contingency of $117 million and $75 million, respectively, at Eletropaulo, $29 million of insurance recoveries for damaged turbines at Uruguaiana, $32 million of cash proceeds related to a favorable legal settlement at Southland in California, and compensation of $18 million for the impairment associated with the settlement agreement to shut down Hefei. These increases were offset by a $135 million contract settlement gain in 2007 at Eastern Energy and a $93 million gross receipts tax recovery in 2007 at Eletropaulo and Tietê in 2007.

        Other income increased $242 million to $358 million in 2007 primarily due to the Eastern Energy contract settlement gain and tax recoveries in Brazil noted above in addition to favorable legal settlements at Eletropaulo and Red Oak. These increases were offset by a decrease in gains on the extinguishment of debt, which were driven by debt retirement activities at several of our businesses in Latin America in 2006.

Other expense

        Other expense decreased $92 million to $163 million in 2008, from $255 million in 2007, primarily due to a decrease in losses on sales and disposals of assets at Sul as well as an extinguishment of debt at the Parent Company. In 2008, there was a loss of $55 million on the retirement of Senior Notes at the Parent Company, compared to a loss of $90 million on a smaller debt retirement in 2007.

        Other expense decreased $196 million to $255 million in 2007 primarily due to higher losses in 2006 associated with debt retirement activities at several of our Latin American businesses, special obligation charges and the write-down of disallowed regulatory assets at Eletropaulo in 2006. In 2007, there was a loss of $90 million on the retirement of Senior Notes at the Parent Company, as well as higher losses on sales and disposals of assets at Eletropaulo and Sul.

Impairment Expense

        As discussed in Note 19—Impairment Expense to the Consolidated Financial Statements included in Item 8 of this Form 10-K, impairment expense for the year 2008 was $175 million and consisted primarily of the following:

        In the fourth quarter of 2008, and in response to the financial market crisis, the Company reviewed and prioritized projects in the development pipeline. From this review, the Company determined that the carrying value exceeded the future discounted cash flows for certain projects. As a result, the Company recorded an impairment charge of $75 million ($34 million, net of minority interest and income taxes) related to two liquefied natural gas projects in North America and a non-power development project at one of our facilities in North America. During 2008, the Company recognized additional impairment charges of $36 million related to long-lived assets at Uruguaiana. The impairment was triggered by a combination of gas curtailments and increases in the spot market price of energy in 2007 that continued in 2008. Following an initial impairment charge in the fourth quarter

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of 2007, further charges were incurred in 2008 due to fixed asset purchase agreements in place. During the first half of 2008, the Company withdrew from projects in South Africa and Israel which resulted in impairment charges of $36 million. The Company also recognized an impairment of $18 million related to the shut down of the Hefei plant in China.

        Impairment expense for the year 2007 was $408 million and consisted primarily of the following: In the fourth quarter of 2007, the Company recognized a pre-tax impairment charge of approximately $14 million related to a $52 million prepayment advanced to AgCert for a specified amount of future CER credits. AgCert, a United Kingdom based corporation that produces emission reduction credits, notified AES that it was not able to meet its contractual obligations to deliver CERs, which triggered an analysis of the asset's recoverability and resulted in the asset impairment charge. Also during the fourth quarter of 2007, there was a pre-tax impairment charge of approximately $352 million at Uruguaiana, a gas-fired thermoelectric plant located in Brazil. The impairment was the result of an analysis of Uruguaiana's long-lived assets, which was triggered by the combination of gas curtailments and increases in the spot market price of energy. In August 2007, there was a pre-tax impairment charge of $25 million triggered by the failure of a compressor at our Placerita subsidiary in California. The fixed asset impairment was caused by damage sustained to one of the plant's gas turbines. Also during the third quarter of 2007, a pre-tax fixed asset impairment charge of approximately $10 million was recognized related to the curtailment of operations at Coal Creek Minerals, LLC, a coal mining company owned by our subsidiary Cavanal Minerals located in the United States.

        Impairment expense for the year 2006 was $17 million and consisted primarily of the following: During the fourth quarter of 2006, there was a pre-tax impairment charge of $6 million related to AES China Generating Co. Ltd. ("Chigen") equity investment in Wuhu, a coal-fired plant located in China. The equity impairment in Wuhu was required as a result of a goodwill impairment analysis at Chigen. During the third quarter of 2006, there was an impairment charge of $5 million related to a decrease in the market value of five held for sale gas turbines at our subsidiary Itabo located in the Dominican Republic.

Gain on sale of investments

        Gain on sale of investments of $909 million in 2008 consisted primarily of the sale in May 2008 of our two wholly-owned subsidiaries in Kazakhstan, AES Ekibastuz LLP and Maikuben West LLP for a net gain of $905 million.

        There was no gain on sale of investments for the year ended December 31, 2007.

        Gain on sale of investments in 2006 of $98 million was the result of a net gain of $87 million from our sale of an equity investment in a power project in Canada (Kingston) in March 2006 and a net gain of $10 million related to our transfer of Infoenergy, a wholly owned AES subsidiary, to Brasiliana in September 2006. Brasiliana is 53.85% owned by BNDES, but controlled by AES. This transaction was part of the Company's agreement with BNDES to terminate the Sul Option.

(Loss) gain on sale of subsidiary stock

        In November 2008, Cachagua, our wholly owned subsidiary, which owned 80.2% of AES Gener S.A. ("Gener") shares prior to the transaction, sold 9.6% of its ownership in Gener to a third party. After this transaction, Cachagua's new ownership in Gener was 70.6%. As a result of this transaction, the Company recorded a net loss on the sale of shares of $31 million.

        Gain on sale of subsidiary stock in 2007 of $134 million was a result of net gains recognized on the sale of a 0.91% and 10.18% ownership interest in Gener in May and October of 2007, respectively.

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        As discussed in Note 17—Subsidiary Stock to the Consolidated Financial Statements in Item 8 of this Form 10-K, in September 2006, Brasiliana's wholly owned subsidiary, Transgás sold a 33% economic ownership in Eletropaulo, a regulated electric utility in Brazil. Despite the reduction in economic ownership, there was no change in Brasiliana's voting interest in Eletropaulo, and Brasiliana continues to control Eletropaulo. Brasiliana received $522 million in net proceeds on the sale. On October 5, 2006 Transgás, sold an additional 5% economic ownership in Eletropaulo for net proceeds of $78 million. In 2006, AES recognized a pre-tax loss of $535 million primarily as a result of the recognition of previously deferred currency translation losses.

Foreign currency transaction gains (losses) on net monetary position

        The following table summarizes the gains (losses) on the Company's net monetary position from foreign currency transaction activities:

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Includes $10 million, ($22) million and ($51) million of gains (losses) on foreign currency derivative contracts for the years ended December 31, 2008, 2007 and 2006, respectively.

        The Company recognized foreign currency transaction losses of $185 million for the year ended December 31, 2008. These consisted primarily of losses in Chile, the Philippines, Brazil, Argentina and Mexico partially offset by gains at The AES Corporation and in Kazakhstan.

•

Losses of $102 million in Chile were primarily due to the devaluation of the Chilean Peso by 28% in 2008, resulting in losses at Gener, a U.S. Dollar functional currency subsidiary, associated with its net working capital denominated in Chilean Pesos, mainly cash, accounts receivable and VAT receivables.



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Losses of $57 million in the Philippines were primarily due to remeasurement losses at Masinloc, a Philippine Peso functional currency subsidiary, on U.S. Dollar denominated debt resulting from depreciation of the Philippine Peso of 16% in 2008.



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Losses of $44 million in Brazil were primarily due to the realization of deferred exchange variance on past energy purchases made by Eletropaulo denominated in U.S. Dollar, resulting in foreign currency transaction losses of $41 million.



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Losses of $22 million in Argentina were primarily due to the devaluation of the Argentinean Peso by 10% in 2008, resulting in losses at Alicura, an Argentine Peso functional currency subsidiary, associated with its U.S. Dollar denominated debt.

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•

Losses of $9 million in Mexico were primarily due to the devaluation of the Mexican Peso by 26% in 2008, resulting in losses of approximately $9 million at TEG/TEP.



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Gains of $38 million at The AES Corporation were primarily due to debt denominated in British Pounds and gains on foreign exchange derivatives, partially offset by losses on notes receivable denominated in Euro.



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Gains of $11 million in Kazakhstan were primarily due to net foreign currency transaction gains of $16 million related to energy sales denominated and fixed in the U.S. Dollar, offset by $5 million of foreign currency transaction losses on external and intercompany debt denominated in other than functional currencies.

        Foreign currency transaction gains of $24 million for the year ended December 31, 2007 primarily consisted of gains at The AES Corporation and in Kazakhstan partially offset by losses in Argentina and Colombia.

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Gains of $31 million at The AES Corporation were primarily the result of favorable exchange rates for debt denominated in British Pounds and the Euro.



•

Gains of $10 million in Kazakhstan were primarily due to $12 million of gains related to debt denominated in currencies other than the Kazakh Tenge functional currency, partially offset by $3 million of losses related to energy sales denominated and fixed in the U.S. Dollar.



•

Losses of $8 million in Argentina were primarily due to the devaluation of the Argentine Peso by 3% in 2007, resulting in losses of $11 million at Alicura associated with its U.S. Dollar denominated debt.



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Losses of $7 million in Colombia were primarily due to the appreciation of the Colombian Peso by 11% in 2007 at Chivor, a U.S. Dollar function currency subsidiary.

        Foreign currency transaction losses of $80 million for the year ended December 31, 2006 primarily consisted of losses in Brazil, Pakistan and at The AES Corporation.

•

Losses of $49 million in Brazil were primarily the result of losses of $45 million at Eletropaulo from swap contracts that were paid and executed in 2006 as Eletropaulo converted U.S. Dollar debt to Brazilian Real debt.



•

Losses of $18 million in Pakistan were primarily the result of the depreciation of the Pakistani Rupee.



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Losses of $17 million at AES Corporation were primarily the result of unfavorable exchange rates for debt denominated in British Pounds and the Euro.

Other non-operating expense

        Other non-operating expense was $15 million in 2008 compared to $57 million in 2007. The 2008 expense related primarily to an impairment of the Company's investment in a company developing a "blue gas" (coal to gas) technology project. The Company made this investment in September 2007 and accounted for the investment in convertible preferred shares under the cost method of accounting. During the fourth quarter of 2008, the market value of the shares materially declined due to downward trends in the capital markets and management concluded that the decline was other-than-temporary and recorded an impairment charge of $10 million. Additionally, the Company recorded an other-than-temporary impairment charge of approximately $5 million related to its investments in other entities developing new energy technology and products.

        Other non-operating expense in 2007 reflected the impairment in the Company's investment in AgCert, a U.K. based corporation, publicly traded on the London Stock Exchange, that produces CER credits. The Company acquired its investment in AgCert in May 2006 and, similar to the circumstances stated above, the market value of the Company's investment materially declined during

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the first half of 2007 and the Company recorded an other-than-temporary impairment charge of $52 million in 2007. An additional charge of $5 million was recognized for the decrease in value of the AgCert warrants also held by the Company. The Company began consolidating AgCert in January 2008 when it became the primary beneficiary.

Income taxes

        Income tax expense on continuing operations increased $95 million, or 14%, to $774 million in 2008. The Company's effective tax rates were 28% for 2008 and 45% for 2007. The decrease in the 2008 effective tax rate was primarily due to the non-taxable gain of $905 million on the sale of the Kazakhstan businesses in the second quarter of 2008, offset by U.S. taxes on distributions from the Company's primary holding company to facilitate early retirement of parent debt in 2008. The decrease was also attributable to the implementation of a tax planning strategy that mitigated the impact of the Mexico Flat Rate Business Tax ("IETU") enacted in the fourth quarter of 2007. The strategy resulted in a reduction to deferred tax expense in 2008 of $24 million and $23 million at TEG and TEP, respectively.

        Income tax expense related to continuing operations increased $320 million, or 89%, to $679 million in 2007. The Company's effective tax rates were 45% for 2007 and 39% for 2006. The increase in the 2007 effective tax rate was due, in part, to an impairment at Uruguaiana for which no tax benefit was recorded, the impact of an appreciating Real in certain of our Brazilian subsidiaries, and the impact of income tax law changes in Mexico, partially offset by the nontaxable gain on the sales of shares of one of the Company's Chilean subsidiaries and a release of valuation allowance at one of our subsidiaries in Argentina.

Net equity in earnings of affiliates

        Net equity in earnings of affiliates decreased $43 million, or 57%, to $33 million in 2008 primarily due to the impact of increased coal prices at Yangcheng, a coal-fired plant in China, a decrease as a result of development costs related to AES Solar, formed in March 2008, and an additional write-off of three projects in Turkey that were abandoned in December 2007. Additionally, earnings decreased due to the sale of a wind project in the fourth quarter of 2007, a decrease in earnings at OPGC, in India, and decreased earnings due to a discontinuance of hedge accounting for a number of interest rate swaps at Guacolda in Chile. These losses were partially offset by a decrease in net losses at Cartagena in Spain primarily from a write-off of deferred financing costs in 2007 that did not recur in 2008.

        Net equity in earnings of affiliates increased $3 million, or 4%, to $76 million in 2007 primarily due to a full year of operations at Cartagena in 2007 and the absence of liquidated damages incurred in 2006 for construction delays. The increase was partially offset by a decrease in earnings in 2007 at AES Barry compared to 2006, due to proceeds received in 2006 from the settlement of a legal claim that did not recur in 2007.

Minority interest

        Minority interest expense, net of tax, increased $363 million, or 84%, to $794 million in 2008 primarily due to the decreased losses as a result of the impairment recognized at Uruguaiana during 2007, increased earnings at Eletropaulo, Gener, Itabo, Panama and Tietê, as well as an increase in minority shareholders from approximately 20% to approximately 29% as a result of the sale of shares in Gener in November 2008. These increases were partially offset by an impairment recognized in the Bahamas, a net loss at Masinloc, and decreased earnings at Ras Laffan, Sonel, and Caess-EEO & Clesa in El Salvador.

        Minority interest expense, net of tax, decreased $29 million, or 6%, to $431 million in 2007 primarily due to the recognition of previously deferred currency translation losses associated with the sale of Eletropaulo shares during the third quarter 2006, resulting in a decrease of our economic ownership in

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Eletropaulo from 34% to 16%. See Note 17—Subsidiary Stock to the Consolidated Financial Statements included in Item 8 of this Form 10-K for a further discussion of the sale of Eletropaulo shares and the Brasiliana restructuring. The decrease was also attributable to the minority interest impact of the impairment recognized at Uruguaiana in 2007, offset by increased earnings at Tietê.

Discontinued operations

        As further discussed in Note 21—Discontinued Operations and Held for Sale Businesses to the Consolidated Financial Statements included in Item 8 of this Form 10-K, Discontinued Operations includes the results of five businesses: Jiaozuo, a generation business in China, (sold in December 2008); La Electricidad de Caracas ("EDC"), a utility business in Venezuela, (sold in May 2007); Central Valley, a generation business in California (sold in July 2007); Eden, a utility business in Argentina (sold in June 2007), and Indian Queens, a generation business in the U.K. (sold in May 2006). Prior periods have been restated to reflect these businesses within Discontinued Operations for all periods presented.

        In 2008, income from operations of discontinued businesses, net of tax, was $12 million and reflected the operations of Jiaozuo, a coal-fired generation facility in China sold in December 2008. The Company received $73 million for its 70% interest in the business. The net gain on the disposition was $7 million.

        In 2007, income from operations of discontinued businesses, net of tax, was $79 million and reflected the operations of Jiaozuo, EDC, Central Valley and Eden. EDC and Central Valley were sold in May 2007 and July 2007 for $739 million and $51 million, respectively, and the Eden sale was finalized in June 2007, therefore their results are reflected in the Company's results of operations through their respective sales dates. The loss on the disposal of discontinued businesses was $661 million and primarily related to the $680 million loss on the sale of EDC.

        In 2006, income from operations of discontinued businesses, net of tax, was $115 million and reflected the operations of Jiaozuo, EDC, Central Valley, Eden and Indian Queens. Indian Queens was sold in May 2006 therefore its results are reflected in the Company's results of operations through the sale date. The loss on the disposal of discontinued businesses was $57 million and primarily related to the $62 million impairment charge recognized at Eden to adjust the carrying value of its assets to their estimated net realizable value when the Company reached an agreement to sell Eden in May 2006. The Eden sale was finalized in June 2007.

Extraordinary item

        In May 2006, AES purchased an additional 25% interest in Itabo, a power generation business located in the Dominican Republic for approximately $23 million. Prior to May, the Company held a 25% interest in Itabo, through its Gener subsidiary, and had accounted for the investment using the equity method of accounting with a corresponding investment balance reflected in the "Investments in and advances to affiliates" line item on the Consolidated Balance Sheets. As a result of the transaction, the Company consolidates Itabo and, therefore, the investment balance has been reclassified to the appropriate line items on the Consolidated Balance Sheets with a corresponding minority interest liability for the remaining 50% interest not owned by AES. The Company realized an after-tax extraordinary gain of $21 million as a result of the transaction due to an excess of the fair value of the noncurrent assets over the purchase price.

Critical Accounting Estimates

        The Consolidated Financial Statements of AES are prepared in conformity with GAAP, which requires the use of estimates, judgments, and assumptions that 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. AES's significant accounting policies are described in Note 1—General and

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Summary of Significant Accounting Policies to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

        An accounting estimate is considered critical if:

•

the estimate requires management to make assumptions about matters that were highly uncertain at the time the estimate was made;



•

different estimates reasonably could have been used; or



•

the impact of the estimates and assumptions on financial condition or operating performance is material.

        Management believes that the accounting estimates employed are appropriate and the resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. Management has discussed these critical accounting policies with the audit committee, as appropriate. Listed below are certain significant estimates and assumptions used in the preparation of the Consolidated Financial Statements.

Income Tax Reserves

        We are subject to income taxes in both the United States and numerous foreign jurisdictions. Our worldwide income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the Internal Revenue Service and other taxing authorities. The Company and certain of its subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the provision for income taxes. The Company adopted Financial Accounting Standards Board ("FASB") Interpretation ("FIN") No. 48, Accounting for Uncertainty in Income Taxes, ("FIN No. 48") effective January 1, 2007. The Interpretation prescribes a more-likely-than-not recognition threshold and establishes new measurement requirements for financial statement reporting of an entity's income tax positions. Tax reserves have been established, which the Company believes to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While the Company believes that the amount of the tax estimates are reasonable, it is possible that the ultimate outcome of current or future examinations may exceed current reserves in amounts that could be material.

Goodwill

        We test goodwill for impairment annually and whenever events or circumstances make it more likely than not that impairment may have occurred. Such indicators could include a significant adverse change in the business climate or a decision to sell or dispose all or a portion of a reporting unit. Goodwill impairment is evaluated using a two-step process. The first step is to identify if a potential impairment exists by comparing the fair value of a reporting unit with its carrying value. Determining whether an impairment has occurred requires the valuation of the respective reporting unit. The Company uses a discounted cash flow method to estimate the fair value. If the fair value of the reporting unit exceeds its carrying value, goodwill of the reporting unit is not considered to be impaired and no further analysis is required. In applying this methodology, we rely on a number of factors, including actual operating results, future business plans, economic projections and market data. Assumptions about operating results and growth rates are based on forecasts, future business plans, economic projections and anticipated future cash flows, among other things. Changes in any of these assumptions could result in management reaching a different conclusion regarding the potential impairment of a reporting unit. Our impairment analysis contains uncertainties from uncontrollable events that could positively or negatively impact the anticipated future economic and operating conditions.

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        If the carrying value exceeds the reporting unit's fair value, this could indicate potential impairment and step two of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. The measurement of impairment requires a fair value estimate of each identified tangible and intangible asset in the same manner the fair value would be determined in a business combination. In this case, we supplement the cash flow approach discussed above with appraisals, or other observable sources of fair value, as appropriate.

Regulatory Assets and Liabilities

        The Company accounts for certain of its regulated operations under the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, ("SFAS No. 71"). As a result, AES recognizes assets and liabilities that result from the regulated ratemaking process that would not be recognized under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred or included in future rate initiatives. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, any asset write-offs would be required to be recognized in operating income.

Fair Value

Fair Value of Financial Instruments

        A significant number of the Company's financial instruments are carried at fair value with changes in fair value recognized in earnings or other comprehensive income each period. The Company makes estimates regarding valuation of assets and liabilities measured at fair value in preparing the Consolidated Financial Statements. These assets and liabilities include short and long-term investments in debt and equity securities, included in the balance sheet line items "Short-term investments" and "Other assets (Noncurrent)", derivative assets, included in "Other current assets" and "Other assets (Noncurrent)" and derivative liabilities, included in "Accrued and other liabilities (current)" and "Other long-term liabilities". The Company uses valuation techniques and methodologies that maximize the use of observable inputs and minimize the use of unobservable inputs. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. The valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments' complexity. Investments are generally fair valued based on quoted market prices or other observable market data such as interest rate indices. The Company's investments are primarily certificates of deposit, government debt securities and money market funds. Derivatives are valued using observable data as inputs into internal valuation models. The Company's derivatives primarily consist of interest rate swaps, foreign currency instruments, and commodity and embedded derivatives. Additional discussion regarding the nature of these financial instruments and valuation techniques can be found in Note 6—Fair Value of Financial Instruments.

Accounting for Derivative Instruments and Hedging Activities

        We enter into various derivative transactions in order to hedge our exposure to certain market risks. We primarily use derivative instruments to manage our interest rate, commodity, and foreign currency exposures. We do not enter into derivative transactions for trading purposes.

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        Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities as amended, ("SFAS No. 133"), we recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value except where derivatives qualify and are designated as "normal purchase/normal sale" transactions. Changes in fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Income and expense related to derivative instruments are recognized in the same category as generated by the underlying asset or liability.

        SFAS No. 133 enables companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective and is designated and qualifies as a fair value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. The Company has no fair value hedges at this time. Changes in the fair value of a derivative that is highly effective and is designated as and qualifies as a cash flow hedge, are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. For all hedge contracts, the Company provides formal documentation of the hedge and effectiveness testing in accordance with SFAS No. 133.

        The Company adopted SFAS No. 157, Fair Value Measurement, ("SFAS No. 157") on January 1, 2008. SFAS No. 157 provides additional guidance on the definition of fair value and defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. SFAS No. 157 requires the Company to consider and reflect the assumptions of market participants in the fair value calculation. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk, both of the reporting entity (for liabilities) and of the counterparty (for assets). These factors were not previously considered in the fair value calculation. Due to the nature of the Company's interest rate swaps, which are typically associated with non-recourse debt, credit risk for AES is evaluated at the subsidiary level rather than at the Parent Company level. Nonperformance risk on the Company's derivative instruments is an adjustment to the initial asset/liability fair value position that is derived from internally developed valuation models that utilize observable market inputs.

        As a result of uncertainty, complexity and judgment, accounting estimates related to derivative accounting could result in material changes to our financial statements under different conditions or utilizing different assumptions. As a part of accounting for these derivatives, we make estimates concerning nonperformance, volatilities, market liquidity, future commodity prices, interest rates, credit ratings (both ours and our counterparty's), and exchange rates.

        The fair value of our derivative portfolio is generally determined using internal valuation models, most of which are based on observable market inputs including interest rate curves and forward and spot prices for currencies and commodities. The Company derives most of its financial instrument market assumptions from market efficient data sources (e.g. Bloomberg and Platt's). In some cases, where market data is not readily available, management uses comparable market sources and empirical evidence to derive market assumptions to determine a financial instrument's fair value. In certain instances, the published curve may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve. Additionally, in the absence of quoted prices, we may rely on "indicative pricing" quotes from financial institutions to input into our valuation model for certain of our foreign currency swaps. These indicative pricing quotes do not constitute either a bid or ask price and therefore are not considered observable market data. For individual contracts, the use of different valuation models or assumptions could have a material effect on the calculated fair value.

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Fair Value Hierarchy

        The Company uses valuation techniques and methodologies that maximize the use of observable inputs and minimize the use of unobservable inputs. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. The valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments' complexity.

        To increase consistency and enhance disclosure of the fair value of financial instruments, SFAS No. 157 creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. A financial instrument's level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. For more information regarding the fair value hierarchy, see Note 1—General and Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data in this Form 10-K.

New Accounting Pronouncements

        In September 2006, the FASB issued SFAS No. 157. SFAS No. 157 provides enhanced guidance for using fair value to measure assets and liabilities, but does not expand the application of fair value accounting to any new circumstances. The Company adopted SFAS No. 157 on January 1, 2008. See the Company's fair value policy in Note 1—General and Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data in this Form 10-K.

        SFAS No. 157 is applied prospectively, except for changes in fair value for existing derivative financial instruments that include an adjustment for a blockage factor, existing hybrid instruments measured at fair value and financial instruments accounted for in accordance with Emerging Issues Task Force ("EITF") Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities ("EITF No. 02-3"), under which day one gain or loss recognition was prohibited. For these instruments, the impact of the adoption of SFAS No. 157 can be recorded as an adjustment to beginning retained earnings in the year of adoption. The Company does not have any of these financial instruments; therefore there is no cumulative impact of the adoption of SFAS No. 157 for AES. The adoption of SFAS No. 157 did not materially impact the Company's financial condition, results of operations, or cash flows.

FSP No. 157-1: Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13 ("FSP No. 157-1").

        In February 2008, the FASB issued FASB Staff Position ("FSP") No. 157-1, Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement Under Statement 13, ("FSP No. 157-1"). FSP No. 157-1 excludes SFAS No. 13, Accounting for Leases, ("SFAS No. 13") and most other accounting pronouncements that address fair value measurement of leases from the scope of SFAS No. 157.

FSP No. 157-2: Effective Date of FASB Statement No. 157 ("FSP No. 157-2").

        In February 2008, the FASB issued FSP No. 157-2, which delays the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008, or January 1, 2009 for AES. AES continues to evaluate the future impact of SFAS No. 157 on these assets and liabilities but at this time does not believe that the impact will be material.

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FSP No. 157-3: Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active ("FSP No. 157-3").

        In October 2008, the FASB issued FSP No. 157-3, which clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. The guidance emphasizes that determining fair value in an inactive market depends on the facts and circumstances and may require the use of significant judgments. FSP No. 157-3 is effective upon issuance, including prior periods for which financial statements have not been issued, and therefore was effective for AES at September 30, 2008. The adoption of FSP No. 157-3 did not have a material impact on the Company.

SFAS No. 159: The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS No. 115 ("SFAS No. 159").

        In February 2007, the FASB issued SFAS No. 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item's fair value in subsequent reporting periods must be recognized in current earnings. The Company adopted SFAS No. 159 effective January 1, 2008. As allowed by the standard, the Company did not elect the fair value option for the measurement of any eligible assets or liabilities. Therefore, the January 1, 2008 adoption did not have an impact on the Company.

FSP FAS 133-1 and FIN 45-4: Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No.45; and Clarification of the Effective Date of FASB Statement No. 161 ("FSP No. FAS 133-1 & FIN 45-4" or "the FSP").

        In September 2008, the FASB issued the FSP to address the concerns of financial statement users that existing disclosure requirements under SFAS No. 133 do not adequately reflect the potential adverse effects of changes in credit risk on the financial statements of the sellers of credit derivatives. FSP No. FAS 133-1 & FIN 45-4 requires disclosure of additional information about these potential adverse effects of changes in credit risk on the financial position, financial performance, and cash flows of sellers of credit derivatives. The disclosures are required for all credit derivatives, whether freestanding or embedded in a hybrid instrument. The FSP also amends FIN No. 45 to require additional disclosure about the current status of the payment performance risk of a guarantee. This new disclosure applies to all guarantees, not just those related to credit risk. The provisions in the FSP are effective for reporting periods ending after November 15, 2008, or December 31, 2008 for AES. AES has incorporated these additional disclosures into its Form 10-K for the year ended December 31, 2008. Comparative disclosures are required for periods subsequent to adoption. Additionally, the FSP clarifies that SFAS No. 161 is effective for all periods, including quarterly and annual periods beginning after November 15, 2008, or January 1, 2009 for AES.

FSP No. FAS 140-4 and FIN 46(R)-8: Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities ("FSP No. FAS 140-4 & FIN 46(R)-8").

        In December 2008, the FASB issued FSP No. FAS 140-4 and FIN 46(R)-8, which expands the required disclosures pertaining to an enterprise's involvement with variable interest entities ("VIEs") and is intended to provide more transparent information related to that involvement. The new disclosure requirements include additional information regarding consolidated VIEs as well as a requirement for sponsors of a VIE to disclose certain information even if they do not hold a significant financial interest in the VIE. FSP No. FAS 140-4 & FIN 46(R)-8 is effective for reporting periods ending after December 15, 2008. The Company adopted FSP No. FAS 140-4 & FIN 46(R)-8 effective December 31, 2008 but there was no material change to our disclosures.

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        The following accounting standards have been issued, but as of December 31, 2008 are not yet effective and have not been adopted by AES.

SFAS No. 141(revised 2007): Business Combinations ("SFAS No. 141(R)") and SFAS No. 160: Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 ("SFAS No. 160").

        In December 2007, the FASB issued SFAS No. 141(R) and SFAS No. 160. SFAS No. 141(R) will significantly change how business acquisitions are accounted for at the acquisition date and in subsequent periods. The standard changes the accounting for the business combination at the acquisition date to a fair value based approach rather than the cost allocation approach currently used. Other differences include changes in the accounting for acquisition related costs, contingencies and income taxes. SFAS No. 160 changes the accounting and reporting for minority interests, which will be classified as a component of equity and will be referred to as noncontrolling interests. SFAS No. 141(R) and SFAS No. 160 will be effective for public companies for fiscal years beginning on or after December 15, 2008, January 1, 2009 for AES. SFAS No. 141(R) and SFAS No. 160 will be applied prospectively, except for the presentation and disclosure requirements in SFAS No. 160 for existing minority interests which will require retroactive adoption. Early adoption is prohibited. AES has not completed its analysis of the potential future impact of SFAS No. 141(R) and SFAS No. 160.

SFAS No. 161: Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133 ("SFAS No. 161").

        In March 2008, the FASB issued SFAS No. 161, which expands the disclosure requirements under SFAS No. 133. The enhanced quantitative and qualitative disclosures will include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity's financial position, financial performance and cash flows. SFAS No. 161 is effective for the Company on January 1, 2009. SFAS No. 161 also amends SFAS No. 107, Disclosures about Fair Value Instruments, ("SFAS No. 107") to clarify that derivative instruments are subject to SFAS No. 107 disclosure requirements regarding concentration of credit risk. The Company will incorporate the additional disclosures beginning with its Form 10-Q for the three months ending March 31, 2009.

SFAS No 162: The Hierarchy of Generally Accepted Accounting Principles ("SFAS No. 162").

        In May 2008, the FASB issued SFAS No. 162, which identifies the framework, or hierarchy for selecting accounting principles to be used in preparing financial statements presented in conformity with U.S. GAAP. SFAS No. 162 amends the existing U.S. GAAP hierarchy established and set forth in the American Institute of Certified Public Accountants ("AICPA") Statement of Auditing Standard No. 69, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles, ("SAS 69"). The framework serves as a guide in determining the appropriate accounting treatment to be used for a transaction or event. We do not expect SFAS No. 162 to have an impact on Company's current accounting practices. The Standard will become effective 60 days following the SEC's approval of Public Company Accounting Oversight Board ("PCAOB") amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.

FSP No. FAS 142-3: Determination of the Useful Life of Intangible Assets ("FSP No. FAS 142-3").

        In April 2008, the FASB issued FSP No. FAS 142-3, which amends the factors considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets, ("SFAS No. 142"). FSP No. 142-3 requires a consistent approach between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of an asset under SFAS No. 141(R). The FSP also requires enhanced disclosures when an intangible asset's expected

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future cash flows are affected by an entity's intent and/or ability to renew or extend the arrangement. FSP No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, January 1, 2009 for AES, and is to be applied prospectively. Early adoption is prohibited. AES has not completed its analysis of the potential impact of FSP No. 142-3, but does not believe the adoption will have a material impact on the Company's financial condition, results of operations, or cash flows.

FSP No. APB 14-1: Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) ("FSP No. APB 14-1").

        In May 2008, the FASB issued FSP No. APB 14-1, which clarifies that convertible debt instruments that may be settled in cash or other assets upon conversion are not addressed by APB No. 14, Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants. Additionally, FSP APB No. 14-1 requires an entity to separately account for the liability and equity components of a convertible instrument to reflect an entity's nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP APB No. 14-1 also expands the disclosure requirements regarding convertible debt instrument terms and how the instrument is reflected in an entity's financial statements. AES has reviewed the impact of FSP No. APB 14-1 and determined that FSP No. APB 14-1 is not applicable for any of the Company's instruments.

EITF 08-3: Accounting by Lessees for Maintenance Deposits ("EITF 08-3").

        In June 2008, the EITF issued EITF 08-3, which clarifies how a lessee accounts for nonrefundable maintenance deposits. Under EITF 08-3 nonrefundable maintenance deposits will be recorded as a deposit asset and as reimbursable maintenance is performed by the lessee, the underlying maintenance is expensed or capitalized in accordance with the lessee's accounting policy. EITF 08-3 is effective for the Company beginning on January 1, 2009. Early adoption is not permitted. The effect of adoption will be reflected as a change in accounting principle through a cumulative effect adjustment to the opening balance of retained earnings in the year of adoption. AES is currently reviewing the potential impact of EITF 08-3, but at this time does not believe it will have a material impact on the Company's financial statements.

FSP No. FAS 132(R)-1: Employers' Disclosures about Postretirement Benefit Plan Assets ("FSP No. FAS 132(R)-1").

        In December 2008, the FASB issued FSP No. FAS 132(R)-1, which provides guidance regarding an employers' disclosures about plan assets of a defined benefit pension or other postretirement plan. The FSP is effective for fiscal years ending after December 15, 2009, or the year ending December 31, 2009 for AES. The Company will incorporate the required disclosures in its Form 10-K for the year ending December 31, 2009.

EITF 08-6: Equity Method Investment Accounting Considerations ("EITF 08-6").

        In November 2008 EITF 08-6 was issued. This Issue clarifies the accounting for certain transactions and impairment considerations involving equity method investments. EITF 08-6 makes certain amendments to APB 18, The Equity Method of Accounting for Common Stock. The Company does not expect EITF 08-6 to have a significant impact on current practice. EITF 08-6 is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years, consistent with the effective dates of Statement 141(R) and Statement 160, or January 1, 2009 for AES.

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Capital Resources and Liquidity

Overview

        As discussed in Highlights of 2008, the Company began a number of initiatives as early as October 2007 and continuing throughout 2008 to mitigate our refinancing risks and manage our liquidity at the Parent Company as well as our subsidiaries. These efforts included reducing our discretionary growth investments, extending and smoothing our future debt maturities, and reducing our planned spending for overhead and development expenses.

        As a result of these efforts, Parent Company Liquidity at December 31, 2008 was approximately $1.4 billion. This is available to service $260 million of investment commitments over the next three years, which includes $154 million of scheduled debt maturities in 2009, before considering cash inflows and outflows related to distributions from subsidiaries, overhead and development expenses as well as cash taxes at the Parent Company.

        As of December 31, 2008, the Company had unrestricted cash and cash equivalents of $0.9 billion and short term investments of $1.4 billion. In addition, we had restricted cash and debt service reserves of $1.4 billion. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $12.9 billion and $5.2 billion, respectively. Of the approximately $1.1 billion of our short-term non-recourse debt $945 million is presented as current because it is due in the next twelve months and $129 million relates to defaulted debt. We expect such maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. Approximately $0.2 billion of our recourse debt matures within the next twelve months which we expect to repay using cash on hand at the Parent Company or through net cash provided by operating activities.

        We rely mainly on long-term debt obligations to fund our project development, construction and acquisition activities. We have, to the extent achievable, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates and is generally secured by the capital stock, physical assets, contracts and cash flow of the related subsidiary or affiliate. Generally our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. A portion or all of our variable rate non-recourse debt is generally fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency expected to be received for revenue generated from the benefiting project thereby reducing currency risk. As of December 31, 2008, approximately 92% of the Company's non-recourse debt is denominated in currency matched to the local currency of the subsidiary that incurred the debt. In certain cases the currency is matched through the use of derivative instruments. These derivatives can require that the Company post collateral to support the currency match. As of December 31, 2008, Gener had posted $25 million in the form of a letter of credit and $46 million in bank deposits to support this type of swap. Our non-recourse debt is funded by international commercial banks, multilateral institutions and local regional banks. For more information on our long-term debt, see Note 10—Long-Term Debt to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

        Given its long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company historically has tried to maintain at least 70% of its consolidated long-term obligations at fixed rates of interest including through the use of interest rate swaps and other interest rate related derivatives. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. While the Company believes that this represents an economic hedge, the Company may be required to mark-to-market all or a portion of these interest rate swaps and other derivatives. Presently, The Parent Company's only exposure to variable interest rate debt relates to indebtedness

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under its senior secured and unsecured credit facilities. On a consolidated basis, of the Company's $18.1 billion of total debt outstanding as of December 31, 2008, approximately $3.4 billion bore interest at variable rates of interest that was not subject to an interest rate swap which fixed the interest rate.

        In addition to utilizing non-recourse debt at a subsidiary level when available, 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 of a particular project. These investments have generally taken the form of equity investments or loans, which are subordinated to the project's non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations and/or the proceeds from our issuances of debt, common stock and other securities, as well as proceeds from the sales of assets. Similarly, in certain of our businesses, we may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity with our subsidiaries or lenders. In such circumstances, if a subsidiary defaults on its payment or supply obligation, we will be responsible for the subsidiary's obligations up to the amount provided for in the relevant guarantee or other credit support. At December 31, 2008, we had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our subsidiaries, which were limited by the terms of the agreements, in an aggregate of approximately $411 million (excluding investment commitments and those collateralized by letters of credit and other obligations discussed below).

        As a result of the Parent Company's below investment grade rating, as well as economic conditions that might have an effect on the appetite for corporate credit, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, we may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. We may not be able to provide adequate assurances to such counterparties. In addition, to the extent we are required and able to provide letters of credit or other collateral to such counterparties; this will reduce the amount of credit available to us to meet our other liquidity needs. At December 31, 2008, we had $207 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations. These letters of credit were provided under our revolver and senior unsecured credit facility. We paid letter of credit fees that averaged approximately 3.4% per annum in 2008 on the outstanding amounts.

        We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available or may not be available on economically attractive terms. See Credit Crisis and Macroeconomic Environment discussion above. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in such subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or such subsidiary chooses not to proceed with a project or is unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in such subsidiary.

        Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses.

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Capital Expenditures

        The Company spent $2.8 billion, $2.4 billion and $1.5 billion on capital expenditures in 2008, 2007 and 2006, respectively. A significant majority of these costs were funded with non-recourse debt consistent with our financial strategy. At December 31, 2008, the Company had a total of $1.8 billion of availability under long-term non-recourse construction credit facilities. As more fully described in Credit Crisis and Macroeconomic Environment above, we have taken steps to dramatically decrease the amount of new discretionary capital spending. We expect to continue funding projects that are currently in the construction phase using existing capital provided by these non-recourse credit facilities as supplemented by internally generated cash flows, Parent Company liquidity, contribution from existing or new partners and other funding sources. As a result, property, plant and equipment and long-term non-recourse debt are expected to increase over the next few years even though the rate of discretionary spending has been decreased. While we believe we have the resources to continue funding the projects in construction, there can be no assurances that we will continue to fund all these existing construction efforts.

        As of December 31, 2008, the Parent Company had $260 million in commitments to invest in our subsidiaries projects under construction and to purchase related equipment, excluding $151 million of such obligations already included in the letters of credits discussed above. The Company expects to fund these net investment commitments over time according to the following schedule: $166 million in 2009, $39 million in 2010 and $55 million in 2011. The exact payment schedules will be dictated by the construction milestones. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.

        The Company continues to assess the possible need for capital expenditures associated with international, federal, regional and state regulation of GHG emissions from electric power generation facilities. Legislation and regulations regarding GHG emissions, if enacted, may place significant costs on GHG emissions from fossil fuel-fired electric power generation facilities, particularly coal-fired facilities, and in order to comply, CO₂ emitting facilities may be required to purchase additional GHG emissions allowances or offsets under cap-and-trade programs, pay a carbon tax or to install new pollution-control equipment to capture and reduce the amount of GHG emitted from the facilities, in the event that reliable technology to do so is developed. The capital expenditures required to comply with any future GHG legislation and regulations could be significant and unless such costs can be passed on to customers or counterparties, such regulations could impair the profitability of some of the electric power generation facilities operated by our subsidiaries or render certain of them uneconomical to operate, either of which could have a material adverse effect on our consolidated results of operations and financial condition.

        With respect to our operations outside the United States, certain of the businesses operated by the Company's subsidiaries are subject to compliance with EU ETS and the Kyoto Protocol in certain countries and other country-specific programs to regulate GHG emissions. To date, compliance with the Kyoto Protocol and EU ETS has not had a material adverse effect on the Company's consolidated results of operations, financial condition and cash flows because of, among other factors, the cost of GHG emission allowances and/or the ability of our businesses to pass the cost of purchasing such allowances on to customers or counterparties. However, in the event that such counterparties or regulatory authorities challenge our ability to pass these costs on, there can be no assurance that the Company and/or the relevant subsidiary would prevail in any such dispute. Furthermore, even if the Company and/or the relevant subsidiary does prevail, it would be subject to the cash and administrative burden associated with such dispute.

        As discussed in Item 1: Business—Regulatory Matters—Environmental and Land Use Regulations, in the United States there presently are no federal laws or regulations regulating GHG emissions, although several legislative proposals are currently under consideration. In 2008, the Company's subsidiaries operated businesses which had total approximate CO₂ emissions of 83.8 million metric

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tonnes (ownership adjusted). Approximately 41.5 million metric tonnes of the 83.8 million metric tonnes were emitted in the United States (both figures ownership adjusted). Approximately 11.8 million metric tonnes were emitted in U.S. states participating in the RGGI. At this time, the federal legislative proposals under consideration applicable to electric power generation facilities generally incorporate market-based cap-and-trade programs which authorize facilities to comply through the acquisition of emissions allowances in lieu of capital expenditures. Certain of the states, either alone or as part of a regional initiative, in which our subsidiaries operate are in the process of developing programs to reduce GHG emissions, primarily CO₂, from the electric power generation facilities through cap-and-trade programs, which would allow CO₂ emitting facilities to comply by purchase additional GHG emissions allowances or offsets under cap-and-trade programs or by installing new pollution-control equipment to capture and reduce the amount of GHG emitted from the facilities, in the event that reliable technology to do so is developed. We believe that legislative or regulatory actions, if enacted, may require a material increase in capital expenditures at our subsidiaries.

        In the future the actual impact on our subsidiaries' capital expenditures from any potential federal program to regulate and reduce GHG emissions, if enacted, and the state and regional programs in the process of development, will depend on a number of factors, including among others, the GHG reductions required under any such legislation or regulations, the price and availability of offsets, the extent to which our subsidiaries would be entitled to receive GHG emissions allowances without having to purchase them, the quantity of allowances which our subsidiaries would have to purchase, the price of allowances, our subsidiaries' ability to recover or pass through costs incurred to comply with any legislative or regulatory requirements that are ultimately imposed and the use of market-based compliance options such as cap-and-trade programs. Another factor is the success of our climate solutions business, which may generate credits that will help offset our GHG emissions. However, as set forth in the Risk Factor titled "Our renewable energy projects and other initiatives face considerable uncertainties including development, operational and regulatory challenges," there is no guarantee that the climate solutions business will be successful. Even if our climate solutions business is successful, the level of benefit is unclear with regard to the impact of legislation or litigation concerning GHG emissions.

Common Stock Repurchase Program

        On August 7, 2008, the Company's Board of Directors approved a share repurchase plan of up to $400 million of its outstanding common stock over a six month period ending February 7, 2009. From the inception of the plan through December 31, 2008, the Company repurchased 10,691,267 shares at a total cost of $143 million, including commissions, using cash balances on hand. There were no share repurchases in the fourth quarter of 2008. No shares were repurchased subsequent to December 31, 2008 and the board authorization of the plan expired on February 7, 2009.

Consolidated Cash Flows

Operating Activities

        Net cash provided by operating activities decreased $188 million to $2,165 million during 2008 compared to $2,353 million during 2007. Excluding the decrease in net cash provided by operating activities from EDC in Venezuela, which was sold in May 2007, net cash provided by operating activities would have decreased $37 million. This decrease was partially due to a decrease of

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approximately $110 million at IPL in North America primarily due to an increase in regulatory assets, higher working capital requirements and an increase in employer pension contributions; $77 million at our Latin America Utilities due to an increase in regulatory assets primarily comprised of recoverable purchased energy costs, partially offset by improved net working capital; $65 million at our Asia Generation businesses due to decreased net operating results, principally due to losses at our newly acquired business in the Philippines, and increased receivables due to delayed offtaker payments and increased commodity prices impacting our Pakistan business; $45 million at our renewables businesses due to decreased margin performance and additional working capital requirements; and additional interest related to Parent Company debt. These decreases were partially offset by an increase in net cash provided by operating activities at our Latin America Generation businesses of approximately $250 million primarily due to improved margin performance and a decrease in cash used by one Brazilian subsidiary to pay income taxes in 2008 compared to 2007 as tax credits were the primary payment method in 2008. In addition, our Europe & Africa Utilities experienced an increase in net cash provided by operating activities of approximately $65 million due to improved performance and net working capital.

Investing Activities

        Net cash used for investing activities increased $1,601 million to $3,571 million during 2008 compared to net cash used of $1,970 million during 2007. This increase was largely attributable to the acquisition of Masinloc in the Philippines.

        Acquisitions, net of cash acquired totaled $1,135 million in 2008 compared to $315 million during 2007, an increase of $820 million. Masinloc is a 660 gross MW coal-fired thermal power generation facility purchased during the second quarter of 2008 for cash of approximately $930 million, as discussed in Note 22—Acquisitions and Dispositions to the Consolidated Financial Statements included in Item 8 of this Form 10-K. We also acquired Mountain View in the U.S. during the first quarter of 2008. The activity in 2007 was mainly due to the purchase of two 230 MW petroleum coke-fired power plants at TEG/TEP in Mexico and the purchase of 51% interest in a joint venture with 26 MW existing capacity and a 390 MW development pipeline of hydroelectric projects in Turkey.

        Other significant investing activities included:

        Capital expenditures totaled $2,840 million during 2008 compared to $2,425 million during 2007, an increase of $415 million. The increase was mainly due to a net increased spending of $370 million for plant construction at Gener and $144 million for wind development projects at our U.S. businesses which were partially offset by a decrease of $154 million due to completion of a plant at Maritza in Bulgaria in 2007.

        Proceeds from the sale of businesses totaled $1,328 million in 2008 and $1,136 million in 2007. The proceeds in 2008 included $1,084 million from the sale of Ekibastuz, a coal-fired generation plant, and Maikuben, a coal mine, in Kazakhstan, $171 million in net proceeds from the sale of a 10% ownership interest in AES Gener and $73 million in proceeds from the sale of Jiaozuo. In 2007 proceeds from the sale of businesses included $739 million from the sale of EDC, $331 million in proceeds from the sale of an 11% ownership interest in Gener, $51 million from the sale of Central Valley in the U.S. and $17 million for the sale of Eden in Argentina.

        The purchase of short-term investments, net of sales totaled $319 million in 2008, a $171 million decrease compared to 2007. These transactions included increases in net sales of $323 million and $209 million at Eletropaulo and Uruguaiana, respectively, as a result of a change to the investment strategy to acquire public debt and government securities. This was offset by a $229 million increase in net purchases at Brasiliana Energia in Brazil related to certificates of deposit, government debt securities and money market funds, a $93 million increase in net purchases at Alicura in Argentina related to the purchase of short-term bonds in 2008 and a $56 million increase in net purchases at Tietê in Brazil as the result of a change in investment strategy to invest in Brazilian government bonds.

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        Restricted cash balances increased $295 million in 2008. Restricted cash balances increased $215 million at Gener, $72 million at Chigen, $70 million at Kilroot, $24 million at TEG/TEP, and $20 million at Southland. These were offset by decreases of $49 million at New York, $30 million at Maritza, $18 million at Ebute in Nigeria and $14 million at Alicura.

        Cash used for advances to affiliate and equity investments was $240 million in 2008, an increase of $208 million, primarily from our investment in AES Solar. Additionally, the Company also made additional equity investments in Turkish Hydros and Asia renewables for the Huanghua joint venture wind project in Asia.

        Loan advances were $173 million in 2008, which consisted primarily of the Company's acquisition of a convertible loan from a Brazilian wind development business in the first quarter of 2008.

Financing Activities

        Net cash provided by financing activities increased $118 million to $362 million during 2008 compared to $244 million during 2007. This $118 million change was primarily attributable to an increase in debt, net of repayments of $138 million, a decrease in distributions to minority interests of $102 million and an increase in contributions from minority interests of $36 million offset by an increase in the purchase of treasury stock of $143 million under the Company's common stock repurchase plan.

        Net borrowings under revolving credit facilities were $298 million during 2008, compared to net repayments of $85 million during 2007. This increase in net borrowings of $383 million was primarily due to a $126 million reduction in repayments at IPL, $116 million in repayments at Buffalo Gap 2 in the U.S. in 2007, an increase in borrowings of $60 million, $48 million, $23 million, and $12 million at Pak Gen, Lal Pir, our Panama business, and CAESS in El Salvador, respectively.

        Issuances of recourse and non-recourse debt during 2008 were $2,783 million compared to $4,297 million during 2007. This decrease of $1,514 million was primarily due to a decrease in the issuance of recourse debt at the Parent Company of $1,375 million and issuances of non-recourse debt during 2007 of $454 million at TEG/TEP and $446 million at Eletropaulo. These decreases were offset in part by increases in the issuance of non-recourse debt of $629 million at Masinloc and $229 million at IPL.

        Repayments of recourse debt and non-recourse debt during 2008 were $2,297 million compared to $3,566 million during 2007. This decrease of $1,269 million was predominately due to a decrease in repayments of non-recourse debt of $515 million at Eletropaulo and $443 million at TEG/TEP, a decrease in repayments of recourse debt of $278 million at the Parent Company, and decreases in repayments of non-recourse debt of $226 million at Gener, $96 million at Alicura, $94 million at Kilroot, and $83 million at Sonel. These decreases were offset in part by increases in repayments of non-recourse debt of $309 million at IPL and $251 million at Buffalo Gap 3 in the U.S.

        Minority distributions were $597 million during 2008 compared to $699 million during 2007. This decrease of $102 million was primarily due to higher dividends paid to minorities (BNDES) at Brasiliana Energia during 2007.

        Minority contributions were $410 million during 2008 compared to $374 million during 2007. This increase of $36 million was primarily due to current year contributions of $240 million at Buffalo Gap 3, $77 million at Mountain View I and II and $52 million at Gener offset by the receipt of a contribution of $313 million from the tax equity partners at Buffalo Gap 2 in 2007.

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Contractual Obligations

        A summary of our contractual obligations, commitments and other liabilities as of December 31, 2008 is presented in the table below (in millions):

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⁽¹⁾

Includes recourse and non-recourse debt presented on the Consolidated Financial Statements. Non-recourse debt borrowings are not a direct obligation of AES, the Parent Company. Recourse debt represents the direct borrowings of AES, the Parent Company. See Note 10—Long-Term Debt to the Consolidated Financial Statements included in Item 8 of this Form 10-K which provides additional disclosure regarding these obligations. These amounts exclude capital lease obligations which are included in the capital lease category, see (3) below.

⁽²⁾

Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2008 and do not reflect anticipated future refinancing, early redemptions or new debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2008.

⁽³⁾

Several AES subsidiaries have leases for operating and office equipment and vehicles that are classified as capital leases within Property, Plant and Equipment. Minimum contractual obligations include $96 million of imputed interest.

⁽⁴⁾

The Company was obligated under long-term non-cancelable operating leases, primarily for office rental and site leases. These amounts exclude amounts related to the sale/leaseback discussed below in item (5).

⁽⁵⁾

Sale/Leaseback Obligations—represent a sales/leaseback with operating lease treatment at one of our New York subsidiaries.

⁽⁶⁾

Operating subsidiaries of the Company have entered into contracts for the purchase of electricity from third parties.

⁽⁷⁾

Operating subsidiaries of the Company have entered into fuel purchase contracts subject to termination only in certain limited circumstances.

⁽⁸⁾

Amounts relate to other contractual obligations where the Company has an enforceable and legally binding agreement to purchase goods or services that specifies all significant terms, including: quantity, pricing, and approximate timing. These amounts include planned capital expenditures that are contractually obligated.

⁽⁹⁾

These amounts do not include current liabilities on the Consolidated Balance Sheet except for the current portion of FIN No. 48 obligations. See the indicated notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on the items excluded. Derivatives (See Note 5—Derivative Instruments) and incentive compensation are excluded as the Company is not able to reasonably estimate the timing or amount of the future payments. In addition, the amounts do not include: (1) regulatory liabilities (See Note—9 Regulatory Assets and Liabilities), (2) contingencies (See Note 12—Contingencies), (3) pension and other post retirement employee benefit liabilities (see Note 13—Benefit Plans) or (4) any taxes (See Note 20—Income Taxes) except for FIN No. 48 obligations. Noncurrent FIN No. 48 obligations are reflected in the "Other" column of the table above as the Company is not able to reasonably estimate the timing of the future payments.

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Parent Company Liquidity

        The following discussion of "Parent Company Liquidity" has been included because we believe it is a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to cash and cash equivalents which are determined in accordance with GAAP, as a measure of liquidity. Cash and cash equivalents are disclosed in the Consolidated Statements of Cash Flows and the parent only unconsolidated statements of cash flows in Schedule I of this Form 10-K. Parent Company liquidity may differ from similarly titled measures used by other companies. The principal sources of liquidity at the Parent Company level are:

•

dividends and other distributions from our subsidiaries, including refinancing proceeds;



•

proceeds from debt and equity financings at the Parent Company level, including borrowings under our credit facilities; and



•

proceeds from asset sales.

        Cash requirements at the Parent Company level are primarily to fund:

•

interest;



•

principal repayments of debt;



•

acquisitions;



•

construction commitments;



•

other equity commitments;



•

taxes; and



•

Parent Company overhead and development costs.

        The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, "cash and cash equivalents" at December 31, 2008 and 2007 as follows:

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Recourse Debt Transactions:

Financing and Tender Offer

        In the second quarter of 2008, the Company completed a number of debt-related transactions that resulted in a net reduction of approximately $360 million of recourse debt. These transactions included $223 million of debt paid at maturity, the repurchase of the tendered $762 million of senior notes maturing from 2009 to 2013, and the issuance of $625 million of 8% Senior Unsecured Notes at par value due 2020. The notes repaid at maturity included $223 million outstanding 6.0% Junior Subordinated Convertible Debentures due May 15, 2008 and 8.75% Senior Unsecured Notes due June 15, 2008. On May 15, 2008, we issued $625 million of 8% Senior Unsecured Notes due 2020 ("2020 Notes") at par value. Deferred financing costs attributable to the issuance of the 2020 Notes were approximately $10 million.

        On June 19, 2008, the Company repurchased $762 million of senior notes maturing from 2009 to 2013 in connection with a tender process. Specifically, the Company repurchased $313 million of the 9.50% Senior Notes due 2009, (the "2009 Notes"), $209 million of the 9.375% Senior Notes due 2010, (the "2010 Notes"), $178 million of the 8.875% Senior Notes due 2011, (the "2011 Notes") and $62 million of the 8.75% Second Priority Senior Secured Notes due 2013 (the "2013 Notes"). The Company recognized and included a pre-tax loss on the retirement of the senior notes for the year ended December 31, 2008 of $55 million in "Other expense" which included $52 million of tender consideration.

        In connection with the tender offer for the senior notes, the Company also solicited and received consents from the note holders of the 2013 Notes to amend the related indenture so that the covenants conform substantially to the covenants contained in the indenture governing the Company's senior unsecured notes, with the exception of those covenants related to security.

Amendment of Credit Agreement

        On July 29, 2008, The AES Corporation and certain subsidiary guarantors amended and restated the Company's existing senior secured credit facility pursuant to the terms of the Fourth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2008 (the "Amended and Restated Credit Agreement"). The Amended and Restated Credit Agreement provides for a $200 million term loan facility maturing on August 10, 2011, and $750 million revolving credit facility maturing on June 23, 2010.

        The Company entered into the Amended and Restated Credit Agreement to, among other things: (i) increase the size of the Restricted Payments basket; (ii) reduce the required minimum Cash Flow Coverage Ratio (as defined therein) and increase the maximum Recourse Debt to Cash Flow Ratio (as defined therein); (iii) clarify and make modifications in the provisions that permit hedging activities; and (iv) make certain other changes, such as excluding certain equity-like securities from the definition of Recourse Debt, amending the financial reporting and environmental notice requirements, clarifying that the term "Permitted Business" includes climate solutions, carbon offsets, biofuels, battery storage and ancillary businesses, including related trading activities and amending certain other definitions and covenants.

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Recourse Debt:

        Our recourse debt at year-end was approximately $5.2 billion, $5.6 billion, and $4.8 billion in 2008, 2007 and 2006, respectively. The following table sets forth our Parent Company contingent contractual obligations as of December 31, 2008:

        As of December 31, 2008, the Company had $260 million of commitments to invest in subsidiaries under construction and to purchase related equipment, excluding $151 million of such obligations already included in the letters of credits discussed above. The Company expects to fund these net investment commitments over time according to the following schedule: $166 million in 2009, $39 million in 2010 and $55 million in 2011. The exact payment schedules will be dictated by the construction milestones. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.

        We have a diverse portfolio of performance related contingent contractual obligations. 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, subsidiary default, political risk, tax indemnities, spot market power prices, supplies support and liquidated damages under power sales agreements for projects in development, in operation and under construction. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations during 2009 or beyond, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.

        While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets (see "Credit Crisis and the Macroeconomic Environment"), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries' ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our secured revolving credit facility and senior unsecured credit facility. See Item 1A Risk Factors, "The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise."

        Various debt instruments at the Parent Company level, including our senior secured credit facilities, contain certain restrictive covenants. The covenants provide for, among other items:

•

limitations on other indebtedness, liens, investments and guarantees;

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•

limitations on dividends, stock repurchases and other equity transactions;



•

restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off balance sheet and derivative arrangements;



•

maintenance of certain financial ratios; and



•

financial and other reporting requirements.

        As of December 31, 2008, we were in compliance with these covenants.

Non-Recourse Debt:

        While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:

•

reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the parent level during the time period of any default;



•

triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;



•

causing us to record a loss in the event the lender forecloses on the assets; and



•

triggering defaults in our outstanding debt at the parent level.

        For example, our senior secured credit facilities and outstanding debt securities at the parent level include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the parent level includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.

        Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying Consolidated Balance Sheets amounts to $1.1 billion. The portion of current debt related to such defaults was $129 million at December 31, 2008, all of which was non-recourse debt related to three subsidiaries—Aixi, Kelanitissa and Kilroot.

        None of the subsidiaries that are currently in default are 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 acceleration under such indebtedness. At December 31, 2008 none of our subsidiaries met the definition of material subsidiary under our recourse debt agreements. 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 our financial position and results of operations or the financial position of the individual subsidiary, 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 outstanding debt securities.

Off-Balance Sheet Arrangements

        In May 1999, one of our subsidiaries acquired six electric generating plants 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. In May 2007, the subsidiary purchased a portion of the lessor's interest in a trust estate that holds the leased plants. Future minimum lease commitments under the lease agreement have been reduced by the subsidiary's interest in the plants. We have accounted for this transaction as a sale/leaseback

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transaction with operating lease treatment. We expense periodic lease payments as incurred, which amounted to $34 million, $42 million and $54 million for the years ended December 31, 2008, 2007 and 2006, respectively. We are not subject to any additional liabilities or contingencies if the arrangement terminates and we believe that the dissolution of the off-balance sheet arrangement would have minimal effects on our operating cash flows. The terms of the lease include restrictive covenants such as the maintenance of certain coverage ratios. Historically, the plants have satisfied the restrictive covenants of the lease and there are no known trends or uncertainties that would indicate that the lease will be terminated early. See Note 11—Commitments to the Consolidated Financial Statements included in Item 8 of this Form 10-K for a more complete discussion of this transaction.

        IPL, a consolidated subsidiary of the Company, formed IPL Funding Corporation ("IPL Funding") in 1996 as a special-purpose entity, consolidated by IPL, to purchase retail receivables originated by IPL pursuant to a receivables sale agreement entered into with IPL. At the same time, IPL Funding entered into a purchase facility (the "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 interests in the pool of receivables purchased from IPL. As collections reduce accounts receivable included in the pool, IPL Funding sells ownership interests in additional receivables acquired from IPL to return the ownership interests sold up to a maximum of $50 million, as permitted by the Purchase Facility. During 2008, the Purchase Facility was extended through May 27, 2009. Accounts receivable on the Company's Consolidated Balance Sheets are stated net of the $50 million sold.

        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 purchase facility, subject to certain limitations as defined in the Purchase Facility.

        Under the Purchase Facility, if IPL fails to maintain certain financial covenants regarding interest coverage and debt-to-capital ratios, it would constitute a "termination event." As of December 31, 2008, IPL was in compliance with such covenants. In addition, 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. A termination event would also (i) give the facility agent the option to take control of the lock-box account, and (ii) give the Purchasers the option to discontinue the purchase of additional interests in receivables and cause all proceeds of the purchased interests 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 interests in receivables (currently $50 million). Please refer to Note 25—Off-Balance Sheet and Related Party Transactions to the Consolidated Financial Statements in Item 8 of this Form 10-K for further details on IPL's servicing responsibilities and indemnification requirements under the Purchase Facility.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks

        We are exposed to market risks associated with interest rates, foreign exchange rates and commodity prices. We often utilize financial instruments and other contracts to hedge against such fluctuations. We also utilize financial derivatives for the purpose of hedging exposures to market risk.

Interest Rate Risks

        We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable-rate debt, fixed-rate debt and trust preferred securities, as well as interest rate swap, cap and floor and option agreements.

        Decisions on the fixed-floating debt ratio are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant's capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing.

Foreign Exchange Rate Risk

        In the normal course of business, we are 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 stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in U.S. Dollars or currencies other than their own functional currencies. Primarily, we are exposed to changes in the exchange rate between the U.S. Dollar and the following currencies: Brazilian Real, Kazakhstani Tenge, British Pound, Euro, Colombian Peso, Chilean Peso, Hungarian Forint, Pakistani Rupee and Philippine Peso. Certain subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.

Commodity Price Risk

        We are exposed to the impact of market fluctuations in the price of electricity, fuels and environmental credits. Although we primarily consist of businesses with long-term contracts or retail sales concessions, a portion of our current and expected future revenues are derived from businesses without significant long-term revenue or supply contracts. These businesses subject our results of operations to the volatility of prices for electricity, fuels and environmental credits in competitive markets. Where appropriate, we act to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy can involve the use of commodity forward contracts, futures, swaps and options. Some businesses hedge certain aspects of their commodity risks using financial hedge instruments. We also enter into short-term contracts for the supply of electricity and fuel in other competitive markets in which we operate.

Value at Risk

        One approach we use to assess our risk and our subsidiaries' risk is value at risk ("VaR"). 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. In particular, we measure Analytic VaR, which is calculated

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based on the volatilities and correlations of the different risk exposures of the portfolio. The quantification of market risk using VaR provides a consistent measure of risk across diverse markets and instruments. We adopted the VaR approach because we feel that statistical models of risk measurement, such as VaR, provide an objective, independent assessment of a component of our risk exposure. Our 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. Additionally, VaR represents changes in fair value of financial instruments and not the economic exposure to AES and its affiliates.

        Because of the inherent limitations of VaR, including those specific to Analytic VaR, in particular the assumption that values or returns are normally distributed, we rely on VaR as only one component in our risk assessment process. In addition to using VaR measures, we perform stress and scenario analyses to estimate the economic impact of market changes to our portfolio of businesses. We use these results to complement the VaR methodology.

        In addition, the relevance of the VaR described herein as a measure of economic risk, is limited and needs to be considered in light of the underlying business structure. The interest rate component of VaR is due to changes in the fair value of our fixed rate debt instruments and interest rate swaps. These instruments themselves would expose a holder to market risk; however, utilizing these fixed rate debt instruments as part of a fixed price contract generation business mitigates the overall exposure to interest rates. Similarly, our foreign exchange rate sensitive instruments are often part of businesses which have revenues denominated in the same currency, thus offsetting the exposure.

        We have performed a company-wide VaR analysis of all of our material financial assets, liabilities and derivative instruments. At AES, commodity derivatives are generally embedded derivatives. Embedded derivatives are not appropriately measured here and are excluded since VaR is not representative of the overall contract valuation. The VaR calculation incorporates numerous variables that could impact the fair value of our instruments, including interest rates, foreign exchange rates and commodity prices, as well as correlation within and across these variables. We express Analytic VaR herein 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. Our commodity analysis is an Analytic VaR utilizing a variance-covariance analysis within the commodity transaction management system and is reported for financially settled derivative products at AES Eastern Energy, L.P. in the state of New York as this is the only business with commodity transactions that are deemed derivatives that are not embedded and can be calculated using VaR. These commodity transactions are marked to market on a daily basis and collateral is then posted or recalled for any changes in exposures. However, not every transaction requires AES Eastern Energy, L.P. to post collateral, as several counterparties have caps defined in their transaction agreements. For those counterparties that do require AES Eastern Energy, L.P. to post collateral, two facilities that are non-recourse to The AES Corporation in the amounts of $75 million and $350 million are used to issue letters of credit. As of December 31, 2008, $20 million and $102 million have been utilized under these facilities.

        For the year ended December 31, 2008, our one-day VaR at fourth quarter-end for foreign exchange rate-sensitive instruments was $125 million. This amount includes foreign currency denominated debt and hedge instruments. The amount of foreign-currency denominated debt in our portfolio has remained fairly consistent from December 31, 2007 to December 31, 2008. However,

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higher currency market volatilities during the second half of 2008, particularly for the Brazilian Real and Euro, led to the increase in the one-day quarter-end VaR from December 31, 2007 to December 31, 2008.

        For the year ended December 31, 2008, our one-day VaR at fourth quarter-end for interest rate-sensitive instruments was $188 million. This amount includes the hedge instruments and underlying debt. The largest component of interest rate VaR is from USD-denominated, fixed-rate debt. During the second quarter of 2008, AES decreased its fixed-rate dollar-denominated debt by $170 million resulting in a lower one day interest rate VaR on June 30, 2008. Increases in one-day VaR for the third and four quarter-ends in 2008 were driven by market volatilities which sharply increased at third quarter-end but had moderated by fourth quarter-end.

        For the year ended December 31, 2008, our one-day VaR at fourth quarter-end for commodity price sensitive instruments was $7 million. This amount includes only the financially-settled derivative products at our AES Eastern Energy, L.P. business in New York. In the first two quarters of 2008, one-day VaR was higher than at year-end 2007 due to higher Western New York power prices in the beginning of 2008. Quarter-end VaR decreased during the second half of 2008, as AES decreased the term and volume of hedging activity. Lower power prices in the second half of the year also contributed to the decrease in VaR.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON THE FINANCIAL STATEMENTS

The Board of Directors and Stockholders of The AES Corporation:

        We have audited the accompanying consolidated balance sheet of The AES Corporation and its subsidiaries as of December 31, 2008, and the related consolidated statements of operations, stockholders' equity and cash flows for the year then ended. Our audit also included the financial statement schedules for the year ended December 31, 2008 listed in the accompanying Index to Item 15(a). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (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 audit provides a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The AES Corporation and its subsidiaries at December 31, 2008, and the consolidated results of their operations and their cash flows for the year ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules for the year ended December 31, 2008, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The AES Corporation's internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

McLean, Virginia
February 26, 2009

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON THE FINANCIAL STATEMENTS

To the Board of Directors and Stockholders of
The AES Corporation
Arlington, VA

        We have audited the accompanying consolidated balance sheet of The AES Corporation and subsidiaries (the "Company") as of December 31, 2007 and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the two years in the period ended December 31, 2007. Our audits also included the 2007 and 2006 information in the financial statement schedules on pages S2 - S8. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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 statement. 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.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The AES Corporation and subsidiaries as of December 31, 2007 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

        As discussed in Note 1 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" in 2007 and Statement of Financial Accounting Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans" in 2006.

/s/ Deloitte & Touche LLP

McLean, Virginia
March 14, 2008
(February 26, 2009 as to the Discontinued Operations and Reclassifications section of Note 1 and Note 21)

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THE AES CORPORATION

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2008 AND 2007

See Accompanying Notes to these Consolidated Financial Statements

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THE AES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2008, 2007, AND 2006

See Accompanying Notes to these Consolidated Financial Statements

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THE AES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2008, 2007, AND 2006

See Accompanying Notes to these Consolidated Financial Statements

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THE AES CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

YEARS ENDED DECEMBER 31, 2008, 2007, AND 2006

See Accompanying Notes to these Consolidated Financial Statements

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THE AES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2008, 2007, AND 2006

1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        The AES Corporation is a holding company (the "Parent Company") that through its subsidiaries and affiliates, (collectively, "AES" or "the Company") operates a geographically diversified portfolio of electricity generation and distribution businesses.

        PRINCIPLES OF CONSOLIDATION—The Consolidated Financial Statements of the Company include the accounts of The AES Corporation, its subsidiaries and controlled affiliates, and variable interest entities ("VIEs") of which the Company is the primary beneficiary. All intercompany transactions and balances have been eliminated in consolidation.

        A VIE is an entity (a) that has a total equity investment at risk that is not sufficient to finance its activities without additional subordinated financial support provided by any parties or (b) where the group of equity holders does not have (i) the ability to make significant decisions about the entity's activities, (ii) the obligation to absorb the entity's expected losses or (iii) the right to receive the entity's expected residual returns or (c) where the voting rights of some equity holders are not proportional to their obligations to absorb expected losses, receive expected residual returns or both, and substantially all of the entity's activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights.

        The Company is considered the primary beneficiary of a VIE and thus consolidates the VIE when the Company absorbs a majority of expected losses of the VIE, receives a majority of expected residual returns of the VIE (unless another enterprise receives this majority), or both. The Company performs a qualitative determination as to which variable interest holder is the primary beneficiary, but, when this is not clear, the Company will make the determination based on a computation and allocation of expected losses and expected residual returns. The primary beneficiary determination has not historically required significant judgments or assumptions to be made.

        The Company determines if it is the primary beneficiary when it becomes involved in the VIE. If the Company is the primary beneficiary, it reconsiders this decision when it sells or otherwise disposes of all or part of our variable interests to unrelated parties or if the VIE issues new variable interests to parties other than the Company or its related parties. Conversely, if the Company is not the primary beneficiary, it reconsiders this decision when it acquires additional variable interests in these entities.

        EQUITY METHOD INVESTMENTS—Entities (whether or not they are VIEs) over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method. The Company periodically assesses the recoverability of its equity method investments. If an identified event or change in circumstances requires an impairment evaluation, management assesses the fair value based on valuation methodologies, including discounted cash flows, estimates of sale proceeds and external appraisals, as appropriate. The difference between the carrying value of the equity method investment and its estimated fair value is recognized as an impairment when the loss in value is deemed other-than-temporary and included in "other non-operating expense" on the Consolidated Statements of Operations.

        In accordance with Accounting Principles Board ("APB") Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock ("APB No. 18") the Company discontinues the application of the equity method when an investment is reduced to zero and is not otherwise committed to provide further financial support for the investee. The Company resumes the application of the equity method if the investee subsequently reports net income to the extent that the Company's share of such net

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income equals the share of net losses not recognized during the period the equity method was suspended.

        DISCONTINUED OPERATIONS AND RECLASSIFICATIONS—Certain immaterial prior period amounts have been reclassified within the Consolidated Financial Statements to conform with current year presentation. In addition, in December 2008, the Company sold its coal-fired generation plant, Jiaozuo, in China. These operations were considered to be discontinued operations, as defined under Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"), and the prior period Consolidated Financial Statements in this Form 10-K have been restated to reflect this business as a discontinued operation as discussed in Note 21—Discontinued Operations and Held for Sale Businesses.

        USE OF ESTIMATES—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") 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. 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.

        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 or remaining maturity at the date of acquisition of three months or less to be cash and cash equivalents; such balances approximate fair value.

        RESTRICTED CASH—Restricted cash includes cash and cash equivalents which are restricted as to withdrawal or usage. The nature of restrictions includes restrictions imposed by the financing agreements such as security deposits kept as collateral, debt service reserves, maintenance reserves and others, as well as restrictions imposed by long-term power purchase agreements ("PPA").

        ALLOWANCE FOR DOUBTFUL ACCOUNTS—The Company maintains an allowance for doubtful accounts for estimated uncollectible accounts receivable. The allowance is based on the Company's assessment of known delinquent accounts, historical experience and other currently available evidence of the collectibility and the aging of accounts receivable.

        INVESTMENTS IN MARKETABLE SECURITIES—Short-term investments in marketable debt and equity securities consist of securities with original or remaining maturities in excess of three months but less than one year.

        Marketable debt 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 marketable securities that the Company does not intend to hold to maturity are classified as available-for-sale or trading and are reflected at fair value. Available-for-sale investments are marked-to-market at the end of each reporting period, with unrealized holding gains or losses, which represent changes in the market value

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of the investment, reflected in accumulated other comprehensive income ("AOCI") a separate component of stockholders' equity. In accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, ("SFAS No. 115"), when there is an other-than-temporary decline in the market value of available-for-sale or held-to-maturity investments, the Company recognizes an impairment charge which is classified as "other non-operating expense" on the Consolidated Statements of Operations. Investments classified as trading are marked-to-market on a periodic basis through the Consolidated Statements of Operations. Interest and dividends on investments are reported in interest income. Gains and losses on sales of investments are determined using the specific identification method.

        See Note 6—Fair Value of Financial Instruments and the Company's Fair Value policy for additional discussion regarding the determination of the fair value of the Company's investments in marketable debt and equity securities.

        PROPERTY, PLANT AND EQUIPMENT—Property, plant and equipment are stated at cost. The cost of renewals and betterments that extend the useful life of property, plant and equipment are capitalized.

        Construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly relating to construction in progress are capitalized during the construction period, provided the completion of the project is deemed probable, 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. Construction in progress balances are transferred to electric generation and distribution assets when each asset is ready for its intended use. Government subsidies are recorded as a reduction in fixed assets and reflected in investing activities.

        Depreciation, after consideration of salvage value and asset retirement obligations, is computed primarily using the straight-line method over the estimated useful lives of the assets, which are on a composite or component basis. Maintenance and repairs are charged to expense as incurred. Capital spare parts, including rotable spare parts, are included in electric generation and distribution assets. If the part is considered a component, it is depreciated over its useful life after the part is placed in service. If the part is deemed part of a composite asset, the part is depreciated over its useful life even when being held as a spare part.

        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. Make-whole payments in connection with early debt retirements are classified as investing activities.

        GOODWILL AND OTHER INTANGIBLES—In accordance with SFAS No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142"), the Company recognizes goodwill for the excess of the cost of an acquired entity over the net amount assigned to assets acquired and liabilities assumed. The Company evaluates goodwill and indefinite-lived intangible assets for impairment on an annual basis and whenever events or changes in circumstances trigger an analysis of its carrying value. The Company's annual impairment testing date is October 1^st. The evaluation of impairment involves

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comparing the current fair value of each of the Company's reporting units to their carrying value as required by SFAS No. 142. The income approach using a discounted cash flow model ("DCF Model") is primarily used in determining the current fair value of its reporting units. Finite-lived intangible assets are amortized over their useful lives which range from 2 - 95 years. The Company accounts for emission allowances as intangible assets and charges them to expense when sold or used; granted allowances are valued at zero.

        LONG-LIVED ASSETS—In accordance with SFAS No. 144, the Company evaluates the impairment of long-lived assets based on the projection of undiscounted cash flows when circumstances indicate that the carrying amount of such assets may not be recoverable or the assets meet the held for sale criteria under SFAS No. 144. These events or circumstances may include the relative pricing of wholesale electricity by region, anticipated demand and cost of fuel. If the carrying amount is not recoverable, an impairment charge is recognized for the amount by which the carrying value of the long-lived asset exceeds its fair value. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if recovery through approved rates was probable. For non-regulated assets, an impairment charge would be recognized as a charge against earnings.

        The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, that is, other than a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for measurement, if available. In the absence of quoted market prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow projections or other indicators of fair value such as bids received, comparable sales or appraisals.

        In connection with the periodic evaluation of long-lived assets in accordance with the requirements of SFAS No. 144, the fair value of the asset can vary if different estimates and assumptions would have been used in our applied valuation techniques. In cases of impairment described in Note 19—Impairment Expense, we made our best estimate of fair value using valuation methods based on the most current information at that time. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and management's analysis of the benefits of the transaction.

        ASSET RETIREMENT OBLIGATIONS—In accordance with SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"), the Company records the fair value of the liability for a legal obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, the Company 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 obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.

        CONDITIONAL ASSET RETIREMENT OBLIGATIONS—Pursuant to Financial Accounting Standards Board ("FASB") Interpretation ("FIN") No. 47, Accounting for Conditional Asset Retirement Obligations ("FIN No. 47"), the Company records the estimated fair value of conditional asset retirement obligations. The Company's asset retirement obligations covered by FIN No. 47 primarily include conditional obligations to demolish assets or return assets in good working condition at the end

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of the contractual or concession term, and for the removal of equipment containing asbestos and other contaminants.

        GUARANTOR ACCOUNTING—Pursuant to FIN No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others, at the inception of a guarantee, the Company records the fair value of a guarantee as a liability, with the offset dependent on the circumstances under which the guarantee was issued.

        INCOME TAXES—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. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. As discussed in Note 20—Income Taxes, in June 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes, ("FIN No. 48") which applied to our financial statements beginning January 1, 2007. The Company adopted FIN No. 48 on January 1, 2007 and recognized a cumulative effect of $53 million of applying the provisions of this Interpretation as an adjustment to beginning retained earnings. FIN No. 48 applies to all tax positions accounted for in accordance with SFAS No. 109, Accounting for Income Taxes, ("SFAS No. 109") and requires the Company's tax positions to be evaluated under a more-likely-than-not recognition threshold and measurement analysis before they can be recognized for financial statement reporting.

        Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid in one year. The Company's policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

        FOREIGN CURRENCY TRANSLATION—A business' 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. Translation adjustments are included in accumulated other comprehensive loss, a separate component of stockholders' equity. Gains and losses on intercompany foreign currency transactions which are long-term in nature, which the Company does not intend to settle in the foreseeable future, are also recognized in accumulated other comprehensive loss. 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.

        REVENUE RECOGNITION—The revenue of the Utilities business is classified as regulated on the Consolidated Statement of Operations. 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 estimated average price per customer class for that month. Differences between actual and estimated unbilled revenues have been immaterial. The revenues from the Generation business are classified as non-regulated and are recognized based upon output delivered and capacity provided at

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rates as specified under contract terms or prevailing market rates. The Company has businesses wherein it makes sales and purchases of power to and from Independent System Operators ("ISOs") and Regional Transmission Organizations ("RTOs"). In those instances, the Company accounts for these transactions on a net hourly basis because the transactions are settled on a net hourly basis.

        GENERAL AND ADMINISTRATIVE EXPENSES—General and administrative expenses include corporate and other expenses related to corporate staff functions and initiatives, primarily executive management, finance, legal, human resources, information systems and certain development costs which are not allocable to our business segments.

        REGULATORY ASSETS AND LIABILITIES—The Company accounts for certain of its regulated operations under the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"). As a result, AES records assets and liabilities that result from the regulated ratemaking process that are not recognized under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred due to the probability of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs previously deferred ceases to be probable, the asset write-offs are recognized in continuing operations.

        DERIVATIVES—The Company enters into various derivative transactions in order to hedge its exposure to certain market risks. AES primarily uses derivative instruments to manage its interest rate, commodity and foreign currency exposures. The Company does not enter into derivative transactions for trading purposes.

        Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS No. 133"), as amended, the Company recognizes all derivatives, except those designated as normal purchase or normal sales at inception as either assets or liabilities in the balance sheet and measures those instruments at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Gains and losses related to derivative instruments that qualify as hedges are recognized in the same category as generated by the underlying asset or liability. Gains or losses on derivatives that do not qualify for hedge accounting are recognized as interest income or expense for interest rate derivatives, foreign currency gains or losses on foreign currency derivatives, and revenue or cost of sales for commodity derivatives.

        SFAS No. 133 enables companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as, a fair value hedge are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as, a cash flow hedge are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions affect earnings. Any ineffectiveness is recognized in earnings immediately. The ineffective portion is recognized as interest income or expense for interest rate hedges, foreign currency gains or losses on foreign currency hedges, and

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1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

non-regulated revenue or non-regulated cost of sales for commodity hedges. For all hedge contracts, the Company maintains formal documentation of the hedge and effectiveness testing in accordance with SFAS No. 133. If AES deems that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

        For cash flow hedges of forecasted transactions, AES estimates the future cash flows represented by the forecasted transactions and evaluates the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from accumulated other comprehensive loss into earnings.

        See Note 6—Fair Value of Financial Instruments and the Company's fair value policy for additional discussion regarding the determination of the fair value of the Company's derivative assets and liabilities.

        SHARE-BASED COMPENSATION—The Company accounts for stock-based compensation plans under the fair value recognition provision of SFAS No. 123, Share-Based Payment, as amended by SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure ("SFAS No. 123(R)"). Currently, the Company uses a Black-Scholes Option pricing model to estimate the fair value of stock options granted to employees.

        AES adopted SFAS No. 123(R) effective January 1, 2006. For transition purposes, AES elected the modified prospective application method. Under this application method, SFAS No. 123(R) applies to new awards and to awards modified, repurchased or cancelled after January 1, 2006. The standard requires companies to recognize compensation cost relating to share-based payment transactions in their financial statements. That cost is measured on the grant date based on the fair value of the equity or liability instruments issued and is expensed on a straight-line basis over the requisite service period, net of estimated forfeitures.

        In addition, effective January 1, 2006, AES adopted FASB Staff Position ("FSP") No. SFAS 123(R)-3, Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards, which provides the Company the option to use the "short-cut method" for calculating the historical pool of windfall tax benefits upon adoption of SFAS No. 123(R).

        SALES OF STOCK BY A SUBSIDIARY—The issuance or sale of previously unissued shares of stock by a subsidiary of the Company are accounted for as capital transactions as permitted by SEC Staff Accounting Bulletin No. 51, Accounting for Sales of Stock by a Subsidiary ("SAB No. 51"). Sales of stock of a subsidiary when no new shares are issued are not treated as capital transactions and may result in either a gain or loss on the sale.

        PENSION AND OTHER POSTRETIREMENT PLANS—The Company adopted SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans ("SFAS No. 158"), effective December 31, 2006, which requires recognition of an asset or liability in the balance sheet reflecting the funded status of pension and other postretirement benefits plans with current-year changes in the funded status recognized in accumulated other comprehensive income. The plan assets are recorded at fair value. The Company recognized a cumulative adjustment to adopt the recognition provisions of SFAS No. 158 as of December 31, 2006. AES adopted the measurement date provisions

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of the standard, which require a year-end measurement date of plan assets and obligations for all defined benefit plans, for the fiscal year ended December 31, 2008, resulting in a cumulative adjustment to retained earnings of $1 million as of December 31, 2008.

        MINORITY INTEREST—Where the Company's ownership percentage of a consolidated subsidiary is less than 100 percent, the minority ownership interests are reported in our Consolidated Balance Sheets as "Minority Interest". The minority ownership interest in our earnings, net of tax, is classified as "Minority interest expense" in our consolidated statements of operations. Although in general, the minority ownership interest in earnings is calculated based on ownership percentage, certain of our wind businesses use the hypothetical liquidation at book value ("HLBV") method in consolidation. HLBV uses a balance sheet approach, which measures equity in income or loss by calculating the change in the amount of net worth partners are legally able to claim based on a liquidation of the entity at the beginning of a reporting period compared to the end of that period. This method is used in AES Wind ventures which contain agreements designating different allocations of value among investors, where the allocations change in form or percentage over the life of the venture.

        FAIR VALUE—The Company adopted SFAS No. 157, Fair Value Measurements ("SFAS No. 157") for financial assets and liabilities on January 1, 2008. SFAS No. 157 was applied prospectively, except for changes in fair value of existing derivative financial instruments that include an adjustment for a blockage factor, existing hybrid instruments measured at fair value and financial instruments accounted for in accordance with Emerging Issues Task Force ("EITF") Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities ("EITF No. 02-3"), under which day one gain or loss recognition was prohibited. For these instruments, the impact of the adoption of SFAS No. 157 can be recorded as an adjustment to beginning retained earnings in the year of adoption. The Company did not have any of these financial instruments; therefore there is no cumulative impact of the adoption of SFAS No. 157 for AES. The adoption of SFAS No. 157 did not materially impact the Company's financial condition, results of operations, or cash flows.

        The Company applies SFAS No. 157 to determine the fair value of short-term and long-term investments in marketable debt and equity securities, included in the balance sheet line items "Short-term investments" and "Other assets (Noncurrent)", derivative assets, included in "Other current assets" and "Other assets (Noncurrent)" and derivative liabilities, included in "Accrued and other liabilities (current)" and "Other long-term liabilities". Effective January 1, 2009, the Company will also apply SFAS No. 157 to nonrecurring fair value measurements of nonfinancial assets and liabilities.

        Fair value, as defined in SFAS No. 157, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. The principal or most advantageous market should be considered from the perspective of the reporting entity. SFAS No. 157 requires that the Company reflect the assumptions market participants would use in pricing an asset or liability based on the best information available. Reporting entities are required to consider factors that were not previously measured when determining the fair value of financial instruments. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk, both of the reporting entity (for liabilities) and of the counterparty (for assets). Due to the decentralization and nature of derivatives (interest rate swaps) associated with the

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Company's non-recourse debt, credit risk for AES on such derivatives is assessed at the subsidiary level rather than at the Parent Company level. SFAS No. 157 also excludes transaction costs and any adjustments for blockage factors, which were allowable under previous accounting standards, from the instruments' fair value determination.

        The Company uses valuation techniques and methodologies that maximize the use of observable inputs and minimize the use of unobservable inputs. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. The valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments' complexity.

        To increase consistency and enhance disclosure of the fair value of financial instruments, SFAS No. 157 creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. A financial instrument's level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows:

        Level 1—unadjusted quoted prices in active markets accessible by the reporting entity for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

        Level 2—pricing inputs other than quoted market prices included in Level 1 that are based on observable market data, that are directly or indirectly observable for substantially the full term of the asset or liability. These include quoted market prices for similar assets or liabilities, quoted market prices for identical or similar assets in markets that are not active, adjusted quoted market prices, inputs from observable data such as interest rate and yield curves, volatilities or default rates observable at commonly quoted intervals or inputs derived from observable market data by correlation or other means.

        Level 3—pricing inputs that are unobservable, or less observable, from objective sources. Unobservable inputs should only be used to the extent observable inputs are not available. These inputs maintain the concept of an exit price from the perspective of a market participant and should reflect assumptions of other market participants. An entity should consider all market participant assumptions that are available without unreasonable cost and effort. These are given the lowest priority and are generally used in internally developed methodologies to generate management's best estimate of the fair value when no observable market data is available.

        The fair value of the Company's investments in marketable debt and equity securities is generally based on quoted market prices or other observable market data such as interest rate indices. The Company's marketable investments are primarily certificates of deposit, government debt securities and money market funds. Derivatives are valued using observable data as inputs into internal valuation models. Additional discussion of the Company's investments in marketable debt and equity securities can be found in Note 4—Investments in Marketable Securities. The Company's derivatives primarily consist of interest rate swaps, foreign currency instruments, and commodity and embedded derivatives. Additional discussion regarding the nature of these financial instruments and valuation techniques can be found in Note 6—Fair Value of Financial Instruments.

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THE AES CORPORATION

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1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

NEW ACCOUNTING PRONOUNCEMENTS

SFAS No. 157, Fair Value Measurements

        In September 2006, the FASB issued SFAS No. 157. SFAS No. 157 provides enhanced guidance for using fair value to measure assets and liabilities, but does not expand the application of fair value accounting to any new circumstances. The Company adopted SFAS No. 157 on January 1, 2008. See the Company's Fair Value policy footnote above for additional details.

FSP No. 157-1: Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13 ("FSP No. 157-1").

        In February 2008, the FASB issued FASB Staff Position ("FSP") No. 157-1. FSP No. 157-1 excludes SFAS No. 13, Accounting for Leases, ("SFAS No. 13") and most other accounting pronouncements that address fair value measurement of leases from the scope of SFAS No. 157.

FSP No. 157-2: Effective Date of FASB Statement No. 157 ("FSP No. 157-2").

        In February 2008, the FASB issued FSP No. 157-2, which delays the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008, or January 1, 2009 for AES. AES continues to evaluate the future impact of SFAS No. 157 on these assets and liabilities but at this time does not believe the impact will be material.

FSP No. 157-3: Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active ("FSP No. 157-3").

        In October 2008, the FASB issued FSP No. 157-3, which clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. The guidance emphasizes that determining fair value in an inactive market depends on the facts and circumstances and may require the use of significant judgments. FSP No. 157-3 is effective upon issuance, including prior periods for which financial statements have not been issued, and therefore was effective for AES at September 30, 2008. The adoption of FSP No. 157-3 did not have a material impact on the Company.

SFAS No. 159: The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS No. 115 ("SFAS No. 159").

        In February 2007, the FASB issued SFAS No. 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item's fair value in subsequent reporting periods must be recognized in current earnings. The Company adopted SFAS No. 159 effective January 1, 2008. As allowed by the standard, the Company did not elect the fair value option for the measurement of any eligible assets or liabilities. Therefore, the January 1, 2008 adoption did not have an impact on the Company.

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1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

FSP FAS 133-1 and FIN 45-4: Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No.45; and Clarification of the Effective Date of FASB Statement No. 161 ("FSP No. FAS 133-1 & FIN 45-4" or "the FSP").

        In September 2008, the FASB issued the FSP to address the concerns of financial statement users that existing disclosure requirements under SFAS No. 133 do not adequately reflect the potential adverse effects of changes in credit risk on the financial statements of the sellers of credit derivatives. FSP No. FAS 133-1 & FIN 45-4 requires disclosure of additional information about these potential adverse effects of changes in credit risk on the financial position, financial performance, and cash flows of sellers of credit derivatives. The disclosures are required for all credit derivatives, whether freestanding or embedded in a hybrid instrument. The FSP also amends FIN No. 45 to require additional disclosure about the current status of the payment performance risk of a guarantee. This new disclosure applies to all guarantees, not just those related to credit risk. The provisions in the FSP are effective for reporting periods ending after November 15, 2008, or December 31, 2008 for AES. AES has incorporated these additional disclosures into its Form 10-K for the year ended December 31, 2008. Comparative disclosures are required for periods subsequent to adoption. Additionally, the FSP clarifies that SFAS No. 161 is effective for all periods, including quarterly and annual periods beginning after November 15, 2008, or January 1, 2009 for AES.

FSP No. FAS 140-4 and FIN 46(R)-8: Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities ("FSP No. FAS 140-4 & FIN 46(R)-8").

        In December 2008, the FASB issued FSP No. FAS 140-4 & FIN 46(R)-8, which expands the required disclosures pertaining to an enterprise's involvement with VIEs and is intended to provide more transparent information related to that involvement. The new disclosure requirements include additional information regarding consolidated VIEs as well as a requirement for sponsors of a VIE to disclose certain information even if they do not hold a significant financial interest in the VIE. FSP No. FAS 140-4 & FIN 46(R)-8 is effective for reporting periods ending after December 15, 2008 but there was no material impact to our disclosures.

        The following accounting standards have been issued, but as of December 31, 2008 are not yet effective and have not been adopted by AES.

SFAS No. 141(revised 2007): Business Combinations ("SFAS No. 141(R)") and SFAS No. 160: Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 ("SFAS No. 160").

        In December 2007, the FASB issued SFAS No. 141(R) and SFAS No. 160. SFAS No. 141(R) will significantly change how business acquisitions are accounted for at the acquisition date and in subsequent periods. The standard changes the accounting for the business combination at the acquisition date to a fair value based approach rather than the cost allocation approach currently used. Other differences include changes in the accounting for acquisition related costs, contingencies and income taxes. SFAS No. 160 changes the accounting and reporting for minority interests, which will be classified as a component of equity and will be referred to as noncontrolling interests. SFAS No. 141(R) and SFAS No. 160 will be effective for public companies for fiscal years beginning on or after December 15, 2008, January 1, 2009 for AES. SFAS No. 141(R) and SFAS No. 160 will be applied

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prospectively, except for the presentation and disclosure requirements in SFAS No. 160 for existing minority interests which will require retroactive adoption. Early adoption is prohibited. AES has not completed its analysis of the potential future impact of SFAS No. 141(R) and SFAS No. 160.

SFAS No. 161: Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133 ("SFAS No. 161").

        In March 2008, the FASB issued SFAS No. 161, which expands the disclosure requirements under SFAS No. 133. The enhanced quantitative and qualitative disclosures will include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity's financial position, financial performance and cash flows. SFAS No. 161 is effective for the Company on January 1, 2009. SFAS No. 161 also amends SFAS No. 107, Disclosures about Fair Value Instruments ("SFAS No. 107"), to clarify that derivative instruments are subject to SFAS No. 107 disclosure requirements regarding concentration of credit risk. The Company will incorporate the additional disclosures beginning with its Form 10-Q for the three months ending March 31, 2009.

SFAS No 162: The Hierarchy of Generally Accepted Accounting Principles ("SFAS No. 162").

        In May 2008, the FASB issued SFAS No. 162, which identifies the framework, or hierarchy for selecting accounting principles to be used in preparing financial statements presented in conformity with U.S. GAAP. SFAS No. 162 amends the existing U.S. GAAP hierarchy established and set forth in the American Institute of Certified Public Accountants ("AICPA") Statement of Auditing Standards No. 69, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles ("SAS 69"). The framework serves as a guide in determining the appropriate accounting treatment to be used for a transaction or event. We do not expect SFAS No. 162 to have an impact on the Company's current accounting practices. The Standard will become effective 60 days following the SEC's approval of Public Company Accounting Oversight Board ("PCAOB") amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.

FSP No. FAS 142-3: Determination of the Useful Life of Intangible Assets ("FSP No. FAS 142-3").

        In April 2008, the FASB issued FSP No. FAS 142-3, which amends the factors considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142. FSP No. 142-3 requires a consistent approach between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of an asset under SFAS No. 141(R). The FSP also requires enhanced disclosures when an intangible asset's expected future cash flows are affected by an entity's intent and/or ability to renew or extend the arrangement. FSP No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, January 1, 2009 for AES, and is to be applied prospectively. Early adoption is prohibited. AES has not completed its analysis of the potential impact of FSP No. 142-3, but does not believe the adoption will have a material impact on the Company's financial condition, results of operations, or cash flows.

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FSP No. APB 14-1: Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) ("FSP No. APB 14-1").

        In May 2008, the FASB issued FSP No. APB 14-1, which clarifies that convertible debt instruments that may be settled in cash or other assets upon conversion are not addressed by APB No. 14, Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants. Additionally, FSP APB No. 14-1 requires an entity to separately account for the liability and equity components of a convertible instrument to reflect an entity's nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP APB No. 14-1 also expands the disclosure requirements regarding convertible debt instrument terms and how the instrument is reflected in an entity's financial statements. AES has reviewed the impact of FSP No. APB 14-1 and determined that FSP No. APB 14-1 is not applicable for any of the Company's instruments.

EITF 08-3: Accounting by Lessees for Maintenance Deposits ("EITF 08-3").

        In June 2008, the Emerging Issues Task Force ("EITF") issued EITF 08-3, which clarifies how a lessee accounts for nonrefundable maintenance deposits. Under EITF 08-3, nonrefundable maintenance deposits will be recorded as a deposit asset and as reimbursable maintenance is performed by the lessee, the underlying maintenance is expensed or capitalized in accordance with the lessee's accounting policy. EITF 08-3 is effective for the Company beginning on January 1, 2009. Early adoption is not permitted. The effect of adoption will be reflected as a change in accounting principle through a cumulative effect adjustment to the opening balance of retained earnings in the year of adoption. AES is currently reviewing the potential impact of EITF 08-3, but at this time does not believe it will have a material impact on the Company's financial statements.

FSP No. FAS 132(R)-1: Employers' Disclosures about Postretirement Benefit Plan Assets ("FSP No. FAS 132(R)-1").

        In December 2008, the FASB issued FSP No. FAS 132(R)-1, which provides guidance regarding an employer's disclosures about plan assets of a defined benefit pension or other postretirement plan. The FSP is effective for fiscal years ending after December 15, 2009, or the year ending December 31, 2009 for AES. The Company will incorporate the required disclosures in its Form 10-K for the year ending December 31, 2009.

EITF 08-6: Equity Method Investment Accounting Considerations ("EITF 08-6").

        In November 2008, EITF 08-6 was issued. This Issue clarifies the accounting for certain transactions and impairment considerations involving equity method investments. EITF 08-6 makes certain amendments to APB 18. The Company does not expect EITF 08-6 to have a significant impact on current practice. EITF 08-6 is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years, consistent with the effective dates of Statement 141(R) and Statement 160, or January 1, 2009 for AES.

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2. INVENTORY

        Inventories primarily consist of coal, fuel oil and other raw materials used to generate power, and spare parts and supplies used to maintain power generation and distribution facilities. Most of the Company's inventories are reflected at the lower of cost or market using either the average cost method (81%) or the first-in, first-out ("FIFO") method (17%). The remaining 2% are valued using actual cost and specific identification.

        The following table summarizes our inventory balances as of December 31, 2008 and 2007:

3. PROPERTY, PLANT & EQUIPMENT

        The following table summarizes the components of the electric generation and distribution assets and other and estimated useful lives:

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Net electric generation and distribution assets and other related to Jiaozuo of $70 million and Ekibastuz and Maikuben of $151 million as of December 31, 2007 are excluded from the table above and are included in the noncurrent assets and liabilities of held for sale and discontinued businesses.

        The following table summarizes interest capitalized during development and construction on qualifying assets for the years ended December 31, 2008, 2007 and 2006:

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        Recoveries of liquidating damages from construction delays and government subsidies are reflected as a reduction in the related projects' construction costs. Approximately $11.5 billion of property, plant and equipment, net of accumulated depreciation, was mortgaged, pledged or subject to liens as of December 31, 2008.

        Depreciation expense, including the amortization of assets recorded under capital leases, was $973 million, $898 million and $802 million for the years ended December 31, 2008, 2007 and 2006, respectively.

        Net electric generation and distribution assets and other include unamortized internal use software costs of $104 million and $35 million as of December 31, 2008 and 2007, respectively. Amortization expense associated with software costs was $41 million, $20 million and $21 million for the years ended December 31, 2008, 2007 and 2006.

        The following table summarizes regulated and non-regulated generation and distribution facilities property, plant and equipment and accumulated depreciation as of December 31, 2008 and 2007:

        The following table summarizes the amounts recognized, which were related to asset retirement obligations, for the years ended December 31, 2008 and 2007:

        The Company's retirement obligations covered by SFAS No. 143 primarily include active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. The fair value of legally restricted assets for purposes of settling asset retirement obligations was less than $1 million as of December 31, 2008 and 2007.

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4. INVESTMENTS IN MARKETABLE SECURITIES

        The following table sets forth the Company's investments in marketable debt and equity securities classified as trading and available-for-sale as of December 31, 2008 and 2007 by type of investment and by level within the fair value hierarchy in accordance with SFAS No. 157. Financial assets and liabilities have been classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the determination of the fair value of the assets and liabilities and their placement within the fair value hierarchy levels.

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See the Company's fair value policy in Note 1 for further detail regarding the fair value hierarchy and Note 6—Fair Value of Financial Instruments for further detail on types of investments held.

⁽²⁾

Unsecured debentures are instruments similar to certificates of deposit that are held primarily by our subsidiaries in Brazil. The unsecured debentures and certificates of deposit included here do not qualify as cash equivalents under SFAS No. 95, Statement of Cash Flows, but meet the definition of a security under SFAS No. 115 and are therefore classified as available-for-sale securities.

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        The following table sets forth the Company's investments in marketable debt securities classified as held-to-maturity as of December 31, 2008 and 2007:

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At December 31, 2008 and 2007, $14 million and $28 million, respectively, of investments classified as held-to-maturity were restricted or pledged as collateral for certain debt arrangements.

        The amortized cost approximated fair value of the held-to-maturity investments at December 31, 2008 and 2007.

        As of December 31, 2008, the stated maturities for the investments (including restricted investments) ranged from one month to three years.

        The following table summarizes the unrealized gains and losses related to sales of and investments in available-for-sale securities. There were no realized gains or losses on the sale of available-for-sale securities.

        The Company recognized other-than-temporary impairment charges of $15 million and $52 million for the years ended December 31, 2008 and 2007, respectively. There was no other-than-temporary impairment expense in 2006. In 2008, the impairment primarily related to the Company's investment in a company developing a commercial facility for a "blue gas" (coal to gas) technology project. The Company made this investment in September 2007 and accounted for the investment in convertible preferred shares under the cost method of accounting. During the fourth quarter of 2008, the market value of the shares materially declined due to downward trends in the capital markets and management concluded that the decline was other-than-temporary and recorded an impairment charge of $10 million.

        In 2007, other-than-temporary impairment related to the Company's investment in AgCert International ("AgCert"). The Company made its first significant investment in the greenhouse gas ("GHG") emission area, acquiring a 9.9% ownership interest in AgCert for $52 million in May 2006

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and, in accordance with SFAS No. 115, classified these securities as "available-for-sale". AgCert is an Ireland-based company which uses agricultural sources to produce GHG emission offsets under the Kyoto protocol. At that time, our investment in the stock, which was traded on the London Stock Exchange was classified as a long-term available-for-sale investment and revalued at the end of each reporting period, with changes in the market value of the investment reflected in accumulated other comprehensive income. There was a material decline in the market value of these securities, based on a continual decline in the traded market price during the year ended December 31, 2007, and the Company recognized an other-than-temporary impairment charge of $52 million.

5. DERIVATIVE INSTRUMENTS

        AES utilizes derivative financial instruments to hedge interest rate risk, foreign exchange risk and commodity price risk. The Company utilizes interest rate derivatives to hedge interest rate risk on variable rate debt. Most of AES's interest rate derivatives are designated and qualify as cash flow hedges. Currency forwards, options and swap agreements are utilized by the Company to hedge foreign exchange risk. The Company utilizes electric and fuel derivative instruments, including swaps, options, forwards and futures, to hedge the risk related to electricity sales and fuel purchases.

        Certain derivatives are not designated as hedging instruments. While these instruments economically hedge interest rate risk, foreign exchange risk or commodity price risk, they do not qualify for hedge accounting treatment as defined by SFAS No. 133.

        The following table sets forth the Company's investments in derivative instruments as of December 31, 2008 by type of derivative and by level within the fair value hierarchy in accordance with SFAS No. 157. Financial assets and liabilities have been classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the

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determination of the fair value of the assets and liabilities and their placement within the fair value hierarchy levels.

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        The following table presents a reconciliation of all assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2008:

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Derivative assets and (liabilities) are presented on a net basis.



⁽²⁾

Liabilities transferred into Level 3 primarily resulted from an increase in the significance of the judgments used in applying observable inputs to credit valuation adjustments in the valuation of these derivative instruments.

        The maximum length of time over which AES is hedging its exposure to variability in future cash flows for forecasted interest, foreign currency and commodity transactions is 19 years, 20 years and 2 years, respectively. For the years ended December 31, 2008, 2007 and 2006, pre-tax (losses) gains of $(35) million, $(2) million, and $3 million, respectively, were reclassified into earnings as a result of the discontinuance of a cash flow hedge because it was probable that the forecasted transaction would not occur by the end of the originally specified time period (as documented at the inception of the hedging relationship) or within an additional two-month time period. The Company recognized after-tax (losses) gains of $(8) million, $6 million, and $18 million related to the ineffective portion of derivatives qualifying as cash flow hedges for the years ended December 31, 2008, 2007 and 2006, respectively.

        After-tax gains (losses) related to the changes in fair value of derivatives that do not qualify for hedge accounting were $10 million, $(21) million and $22 million for the years ended December 31, 2008, 2007 and 2006, respectively. The after-tax losses include embedded foreign currency derivatives, interest rate options, commodity derivatives and embedded derivatives. The composition and methodology for fair value determination of derivative assets and liabilities are further discussed in Note 6—Fair Value of Financial Instruments.

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5. DERIVATIVE INSTRUMENTS (Continued)

        Amounts recognized in accumulated other comprehensive loss due to hedges, after income taxes, during the years ended December 31, 2008, 2007 and 2006, respectively, are as follows:

        Approximately $16 million of the pre-tax accumulated other comprehensive loss related to derivative instruments as of December 31, 2008 is expected to be recognized as a decrease to income from continuing operations before income taxes over the next twelve months. This estimate includes estimated losses of $0 million, $1 million and $15 million related to foreign currency, commodity and interest rate instruments, respectively. The estimated commodity losses of $1 million relate to a power purchase agreement where the normal purchase normal sale scope exception from derivative accounting was elected as of December 31, 2008, which will also result in an estimated $8 million decrease to income from continuing operations before income taxes over the next twelve months due to the amortization of the derivative asset of $187 million. 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 recognized for hedges of interest that is capitalized, 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 fuel transactions. These balances are included in the Consolidated Statement of Cash Flows as operating and/or investing activities based on the nature of the underlying transaction.

6. FAIR VALUE OF FINANCIAL INSTRUMENTS

        The fair value of current financial assets, current financial liabilities, debt service reserves and other deposits is 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, the fair value is estimated using quoted market prices or discounted cash flow analyses. See Note 10—Long-Term Debt for additional information on the fair value and carrying value of debt. 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 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.

        In September 2006, the FASB issued SFAS No. 157, which provided a framework for measuring fair value and established a fair value hierarchy of the valuation techniques used to measure the fair value of financial assets and liabilities and expands disclosures about fair value measurement. The

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Company adopted the provisions of SFAS No. 157 as of January 1, 2008, for financial assets and liabilities. Although the adoption of SFAS No. 157 did not materially impact the Company's financial condition, results of operations or cash flow, additional disclosures about our fair value measurements are discussed below.

Valuation Techniques:

        SFAS No. 157 describes three main approaches to measuring the fair value of assets and liabilities: (1) market approach; (2) income approach and (3) cost approach. The market approach uses prices and other relevant information generated from market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future amounts to a single present value amount. The measurement is based on the value indicated by current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company does not currently determine the fair value of any of our financial assets and liabilities using the cost approach. Financial assets and liabilities that are measured at fair value on a recurring basis at AES fall into two broad categories: investments and derivatives. Our investments are generally measured at fair value using the market approach and our derivatives are valued using the income approach.

Investments

        These investments generally consist of debt and equity securities. Equity securities are adjusted to fair value using quoted market prices. Debt securities primarily consist of certificates of deposit, government debt securities and money market funds held by our Brazilian subsidiaries. The implementation of SFAS No. 157 did not result in a material change in the fair value of these investments due to the fact that these investments are primarily held by highly rated institutions and governmental agencies and therefore, the consideration of counterparty credit risk did not have a material impact on the determination of fair value. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to LIBOR), Selic (overnight borrowing rate) or IGPM (inflation) rates in Brazil and are adjusted based on the banks' assessment of the specific businesses. Fair value is determined based on comparisons to market data obtained for similar assets and are considered Level 2 inputs. The Company holds some auction rate securities through IPALCO Enterprises Inc. ("IPALCO"), a U.S. subsidiary in Indiana. The fair value of these securities was $2 million as of December 31, 2008. Based on the current credit environment, these were evaluated for potential impairment and were determined to not be impaired at this time. For more detail regarding the fair value of investments see Note 4—Investments in Marketable Securities.

Derivatives

        When deemed appropriate, the Company manages its risk from interest and foreign currency exchange rate and commodity price fluctuations through the use of derivative financial assets and liabilities. The Company's derivatives are primarily interest rate swaps on non-recourse debt to establish a fixed rate on variable rate debt, foreign exchange instruments to hedge against currency fluctuations and derivatives or embedded derivatives associated with commodity contracts. The Company's subsidiaries are counterparties to various interest rate swaps, interest rate options, foreign currency

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swaps and commodity and embedded derivatives in certain agreements, generally PPAs. The fair value of our derivative portfolio was determined using internal valuation models, most of which are based on observable market inputs including interest rate curves and forward and spot prices for currencies and commodities. The primary pricing inputs used in determining the fair value of our interest rate swaps and our foreign currency exchange swaps are LIBOR swap rates and forward foreign exchange curves with the same duration as the instrument as reported in published information provided by pricing services. For each derivative, the projected forward swap rate is used to determine the stream of cash flows over the remaining term of the contract. The cash flows are then discounted using a spot discount rate to determine the fair value. To the extent that management can estimate the fair value of these assets or liabilities without the use of significant unobservable inputs, these derivatives are included in Level 2.

        Derivative assets and liabilities included in Level 3 are also valued using the income approach. Consistent with our Level 2 financial assets and liabilities, the stream of cash flows over the remaining term of the contract is calculated. The cash flows are then discounted using a spot discount rate to determine the fair value. In certain instances, the published curve may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve. Additionally, in the absence of quoted prices, we may rely on "indicative pricing" quotes from financial institutions to input into our valuation model for certain of our foreign currency swaps. These indicative pricing quotes do not constitute either a bid or ask price and therefore are not considered observable market data. These fair value measurements also include adjustments for credit risk. The magnitude of the credit risk adjustment for contracts with certain counterparties resulted in a Level 3 classification for these contracts as of December 31, 2008.

Fair Value Considerations:

        In determining the fair value of our financial instruments, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk and risk of nonperformance of itself or the counterparty to the contract. The conditions and criteria used to assess these factors are:

Sources of Market Assumptions:

        The Company derives most of its financial instrument market assumptions from market efficient data sources (e.g., Bloomberg and Platt's). In some cases, where market data is not readily available, management uses comparable market sources and empirical evidence to derive market assumptions to determine a financial instrument's fair value.

Market liquidity:

        Market liquidity is assessed by the Company based on criteria as to whether the financial instrument participates in an active or inactive market. An active market can be defined as a spot market or settlement mechanism environment and also a potential forward/futures market that is based on the activity in the forward/futures market. A financial instrument is considered to be in an active market if the prices are fully transparent to the market participants, can be measured by market bid and ask quotes, the market has a relatively large proportion of trading volume as compared to the Company's current trading volume and the market has a significant number of market participants that

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will allow the market to rapidly absorb the quantity of the assets traded without significantly affecting the market price. Other factors the Company considers when determining whether a market is active or inactive include the presence of government or regulatory control over pricing that could make it difficult to establish a market based price upon entering into a transaction.

Nonperformance risk:

        The impact of nonperformance risk that includes credit risk considers changes in current market conditions, readily available information on nonperformance risk, letters of credit, collateral, other arrangements available and the nature of master netting arrangements. The Company and its subsidiaries are counterparties to various interest rate swaps, interest rate options, foreign currency swaps, derivatives and embedded derivatives which subject the Company to nonperformance risk. The financial instruments held at the subsidiary level are generally non-recourse to the Parent Company.

        Nonperformance risk on the investments held by the Company is incorporated in the investment's exit price that is derived from quoted market data that is used to mark-to-market the investment.

        Nonperformance risk on the Company's derivative instruments is an adjustment to the initial asset/liability fair value position that is derived from internally developed valuation models that utilize observable market inputs such as LIBOR interest swap rates, foreign exchange forward curves, and market commodity pricing or, in certain cases, utilize management assumptions to generate extrapolated inputs from observable market data. The Company adjusts for nonperformance risk by deducting a credit valuation adjustment ("CVA") that calculates counterparty risk based on the counterparty's margin or debt spread and the tenor of the respective derivative instrument. The counterparty for a derivative asset position is considered to be the bank or government sponsored banking entity or counterparty to the PPA of the respective subsidiary. The CVA for asset positions is based on the counterparty's credit ratings and debt spreads or, in the absence of readily obtainable credit information, the respective country debt spreads is used as a proxy. The counterparty for a derivative liability position is primarily the Parent Company or the subsidiary. The CVA for liability positions is based on the Parent Company's or the subsidiary's current debt spread, replacement margin with lenders, or in the absence of readily obtainable credit information, the debt spread of the subsidiary's offtaker or the respective country debt spreads are used as a proxy. If the instrument is recourse to the Parent Company, the Parent Company's current debt spread is used to adjust for nonperformance risk.

        All derivative instruments are analyzed individually and are subject to unique risk exposures. The aggregate counterparty credit risk adjustments applied to the Company's derivative asset position was $39 million for the year ended December 31, 2008 decreasing the asset position. The aggregate credit risk adjustments applied to the Company's derivative liability position was $105 million for the year ended December 31, 2008 decreasing the liability position.

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6. FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

Assets and Liabilities at Fair Value

        The following table summarizes the carrying value and fair value of the Company's financial assets and liabilities as of December 31, 2008 and 2007.

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⁽¹⁾

See the Company's fair value policy in Note 1 for further detail regarding the fair value hierarchy.

⁽²⁾

See Note 4—Investments in Marketable Securities for additional information regarding the classification of marketable securities in the Fair Value Hierarchy in accordance with SFAS No. 157.

⁽³⁾

See Note 5—Derivative Instruments for additional information regarding the classification of derivative instruments in the Fair Value Hierarchy in accordance with SFAS No. 157.

⁽⁴⁾

See Note 10—Long-Term Debt for additional information regarding the fair value of debt.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

7. INVESTMENTS IN AND ADVANCES TO AFFILIATES

        The following table summarizes the relevant effective equity ownership interest and carrying values for the Company's investments accounted for under the equity method as of December 31, 2008 and 2007.

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⁽¹⁾

Represent VIEs in which we hold a significant variable interest.

⁽²⁾

Represents participative loan receivable with Cartagena, included in the Receivable from Affiliates line item in the Consolidated Balance Sheets, that absorbs the Company's share of equity method losses as a result of the initial equity investment having been reduced to zero.

        AES Barry Ltd.—The Company holds a 100% ownership interest in AES Barry Ltd. ("Barry"), a 230 MW gas-fired combined cycle power plant in the United Kingdom. As a result of a debt agreement, no material financial or operating decisions can be made without the banks' consent, and the Company does not control Barry. As of December 31, 2008 and 2007 other long-term liabilities included $49 million and $74 million, respectively, related to this debt agreement.

        Cartagena Energia—The Company owns 71% of Cartagena Energia ("Cartagena") a 1200 MW power plant in Cartagena, Spain completed in November 2006. The Company's initial investment in Cartagena was approximately $29 million. Cartagena was determined to be a VIE and the Company is not the primary beneficiary due to the fact that the sole customer of the plant absorbs the majority of the commodity price risk. In December 2008, the Company's basis in its investment in Cartagena was reduced to zero and the equity method of accounting was suspended.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

7. INVESTMENTS IN AND ADVANCES TO AFFILIATES (Continued)

        CEMIG—The Company is a party to a joint venture/consortium agreement through which the Company has a 9.6% equity interest in Companhia Energetica de Minas Gerais ("CEMIG"), an integrated utility in Minas Gerais, Brazil. Although our interest in CEMIG is below the 20% threshold for significant influence, AES has significant influence over the operational and financial policies of CEMIG through representation on the board of directors of CEMIG. In 2002, the Company determined there was an other-than-temporary impairment of its investment in CEMIG and wrote it down to fair market value, $155 million. Additionally, AES established 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. As a result, the Company's investment in CEMIG, is a $484 million net liability at December 31, 2008 included in the Other Long-Term Liabilities line item on the Consolidated Balance Sheets. The Company has discontinued the application of the equity method in accordance with its accounting policy regarding equity method investments.

        AES Solar Energy Ltd.—In March 2008, the Company formed AES Solar Energy Ltd ("AES Solar"), a joint venture with Riverstone Holdings LLC ("Riverstone"). AES Solar will develop land-based solar photovoltaic panels that capture sunlight to convert into electricity that feed directly into power grids. AES Solar is accounted for under the equity method of accounting based on the Company's 50% ownership and significant influence but not control over the joint venture. Under the terms of the agreement, the Company and Riverstone will each provide up to $500 million of capital over the next five years. As of December 31, 2008, AES had invested approximately $135 million in the joint venture.

        Guohua AES (Huanghua) Wind Power Co., Ltd—In May 2007, the Company acquired a 49% interest in Guohua AES (Huanghua) Wind Power Co., Ltd. ("AES Huanghua"), a joint venture that is primarily engaged to develop, construct, own and operate wind farms in China. In the third quarter of 2008, the Company also acquired a 49% interest in three separate wind farm projects in China—Guohua AES ("Hulunbeier") Wind Power Co., Ltd.; Guohua AES ("Chenba'erhu") Wind Power Co., Ltd.; and Guohua AES ("Xinba'erhu") Wind Power Co., Ltd. The Company has invested approximately $20 million in the projects to date.

        Trinidad Generation Unlimited—In 2007, the Company began pursuing a development project to construct and operate a 720 MW combined cycle power plant in Trinidad through its wholly owned subsidiary, Trinidad Generation Unlimited ("TGU.") In July 2008, a shareholder agreement was executed establishing the Company's ownership interest in TGU at 60% with the remaining 40% interest held by the Government of Trinidad and Tobago. AES is not considered the primary beneficiary of TGU.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

7. INVESTMENTS IN AND ADVANCES TO AFFILIATES (Continued)

Summarized Financial Information

        The following tables summarize financial information of the Company's 50%-or-less owned affiliates and majority-owned unconsolidated subsidiaries that are accounted for using the equity method.

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⁽¹⁾

Includes information pertaining to Kingston Cogeneration Limited Partnership through March 2006 and U.S. Wind Force LLC through December 2006, the respective disposition dates, and Itabo through May 2006, at which time it became a consolidated subsidiary as a result of the Company's purchase of an additional 25% interest in Itabo. Upon consolidation of Itabo, the Company recognized an extraordinary gain of $21 million.

        At December 31, 2008, retained earnings included $137 million related to the undistributed earnings of affiliates. Distributions received from affiliates were $50 million, $59 million and $44 million for the years ended December 31, 2008, 2007 and 2006, respectively.

        Refer to Item 1 of this Form 10-K for additional information on these affiliates.

8. GOODWILL AND OTHER INTANGIBLE ASSETS

        SFAS No. 142 requires that goodwill be evaluated for impairment at the reporting unit level. A reporting unit is an operating segment as defined by SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, ("SFAS No. 131"), or a component or combination of components within an operating segment with similar economic characteristics that are one level below an operating segment. Generally, each AES business constitutes a reporting unit. Reporting units have been acquired generally 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

8. GOODWILL AND OTHER INTANGIBLE ASSETS (Continued)

        The following table summarizes the changes in the carrying amount of goodwill, by segment as of December 31, 2008, 2007 and 2006:

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⁽¹⁾

Includes goodwill acquired for the period of $65 million related to the acquisition of Masinloc.

        The Company conducts its annual goodwill impairment analysis as of October 1^st each year. For the years ended December 31, 2008 and 2007, the Company had no goodwill impairment. Goodwill impairment of $2 million was recognized during the year ended December 31, 2006 at one of our European generation plants. The fair value of the reporting unit was determined by the income approach using a discounted cash flow valuation model as current quoted market prices were not always available and there was not sufficient evidence that the reporting unit could be bought or sold in the market place between willing third parties. Goodwill impairment is included in "Impairment expense" on the Consolidated Statement of Operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

8. GOODWILL AND OTHER INTANGIBLE ASSETS (Continued)

        The following tables summarize the balances comprising other intangibles in the accompanying Consolidated Balance Sheets for the years ending December 31, 2008 and 2007:

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⁽¹⁾

All other consists primarily of market access, fuel sourcing and other intangible assets acquired upon the Company's acquisition of certain properties in the state of New York in 1999.

        In 2008, the Company acquired intangible assets of $85 million the largest of which was the acquisition of landfill gas rights in El Salvador. The acquired intangible assets included $59 million which were subject to amortization with an average amortization period of 20 years and $26 million of intangible assets not subject to amortization.

        The following table summarizes the estimated amortization expense, broken down by intangible asset category, for 2009 through 2013:

        Intangible asset amortization expense was $19 million, $23 million and $23 million for the years ended December 31, 2008, 2007 and 2006, respectively. Intangible assets included in the tables above that are not subject to amortization primarily consist of land use rights and emission allowances, which had a carrying value of $83 million at December 31, 2008 and $56 million at December 31, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

9. REGULATORY ASSETS & LIABILITIES

        The Company has recorded regulatory assets and liabilities that it expects to pass through to its customers in accordance with, and subject to, regulatory provisions as follows:

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⁽¹⁾

Past expenditures on which the Company does not earn a rate of return.

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DECEMBER 31, 2008, 2007, AND 2006

9. REGULATORY ASSETS & LIABILITIES (Continued)

⁽²⁾

Recoverable per ANEEL regulations through the Annual Tariff Adjustment ("IRT"). These costs are generally non-controllable costs and primarily consist of purchased electricity, energy transmission costs, and sector costs that are considered volatile. These costs are recovered in 24 installments through the annual IRT process and are amortized over the tariff reset period.

⁽³⁾

Deferred fuel costs incurred by our El Salvador subsidiaries associated with purchase of energy from El Salvador spot market and the power generation plants. In El Salvador, the deferred fuel adjustment represents the variance between the actual fuel costs and the fuel costs recovered in the tariffs. The variance is recovered semi-annually at the tariff reset period.

⁽⁴⁾

Includes assets with and without a rate of return. Other current regulatory assets that do not earn a rate of return were $9 million and $18 million, as of December 31, 2008 and 2007, respectively. Other noncurrent regulatory assets that do not earn a rate of return were $83 million and $82 million, as of December 31, 2008 and 2007, respectively. Those without a rate of return that are recoverable based on specific rate orders primarily consist of the following:

•

Deferred fuel costs: expected to be recovered through future fuel adjustment charges. In the United States, deferred fuel costs at IPL represent variances between estimated and actual fuel and purchased power costs. IPL is permitted to recover underestimated fuel and purchased power costs in future rates.

•

Transmission service costs and other administrative costs from IPL's participation in the Midwest ISO market. Recovery of costs is probable, but the timing is not yet determined.

Other Current and Noncurrent Regulatory Liabilities consist of:

•

Penalties and fees from regulators at our Brazil subsidiaries and financial transmission rights used to hedge exposure in the Midwest ISO market that are credited per specific rate orders.



•

Costs incurred by our Brazilian subsidiaries associated with monthly energy price variances between the wholesale energy market prices owed to the power generation plants producing free energy and the capped price reimbursed by the local distribution companies which are passed through to the final customers through energy tariffs.

⁽⁵⁾

SFAS No. 71 allows the defined pension and postretirement benefit obligation to be recorded as a regulatory asset equal to the previously unrecognized actuarial gains and losses and prior service costs that are expected to be recovered through future rates. Pension expense is recognized based on the plan's actuarially determined pension liability. Recovery of costs is probable, but not yet determined. The increase in the regulatory asset of $193 million at December 31, 2008 is primarily a result of a lower than expected return on assets in 2008.

⁽⁶⁾

Probable of recovery through future rates, based upon established regulatory practices, which permit the recovery of current taxes. This asset is offset by a deferred tax liability and is expected to be recovered, without interest, over the period book-tax timing differences reverse and become current taxes.

⁽⁷⁾

Payments received for costs expected to be incurred to improve the efficiency of our plants in Brazil that are recovered as part of the IRT.

⁽⁸⁾

Non-legal asset retirement obligation for removal costs which do not have an associated legal retirement obligation as defined by SFAS No. 143.

⁽⁹⁾

Obligations established by ANEEL in Brazil associated with electric utility concessions and represent amounts received from customers or donations not subject to return. These donations are allocated to support energy network expansion and to improve utility operations to meet customers' needs. The maturity term is established by ANEEL whose settlement shall occur when the concession ends.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

9. REGULATORY ASSETS & LIABILITIES (Continued)

        The current portion of regulatory assets and liabilities are recorded in either other current assets or accrued and other liabilities, respectively, on the accompanying Consolidated Balance Sheets. The noncurrent portion of the regulatory assets and liabilities is recorded in either other assets or other long-term liabilities, respectively, in the accompanying Consolidated Balance Sheets.

        The following table summarizes regulatory assets by region as of December 31, 2008 and 2007:

        The following table summarizes regulatory liabilities by region as of December 31, 2008 and 2007:

10. LONG-TERM DEBT

        The Company has two types of debt reported on its balance sheet: non-recourse and recourse debt. Non-recourse debt is used to fund investments and capital expenditures for construction and acquisition of our electric power plants, wind farms and distribution companies at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. The default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries. Recourse debt is direct borrowings by the Parent Company and is used to fund development, construction or acquisition and serves as equity investments or loans to the affiliates. This debt is with recourse to the Parent Company and is structurally subordinated to the affiliates' non-recourse debt.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

10. LONG-TERM DEBT (Continued)

        Recourse and non-recourse debt is carried at amortized cost. The following table summarizes the carrying amount and estimated fair values of the Company's recourse and non-recourse debt as of December 31, 2008 and 2007:

        The fair value of non-recourse debt, excluding capital leases, is estimated differently based upon the type of loan. For fixed rate loans, the fair value is estimated using quoted market prices or a discounted cash flow analysis. For variable rate loans, we reported that carrying value approximated fair value in 2007, as the average credit spread of AES' portfolio of variable rate notes was equivalent to the spread between LIBOR and the appropriate current yields. In late 2008, credit spreads increased significantly above historic levels. For the USD, Euro and British Pound markets where we believe the credit spread expansion is material, fair value was estimated using a discounted cash flow analysis. The increase in credit spreads was calculated as the difference between composite fair value curves published by pricing services for the appropriate issuer credit rating and LIBOR. For remaining currencies, we continue to report carrying value is equal to fair value. The estimated fair value was determined using available market information as of December 31, 2008 and 2007. The Company is not aware of any factors that would significantly affect the estimated fair value amounts since December 31, 2008.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

10. LONG-TERM DEBT (Continued)

NON-RECOURSE DEBT

        The following table summarizes the non-recourse debt of the Company as of December 31, 2008 and 2007:

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⁽¹⁾

Weighted average interest rate at December 31, 2008.

⁽²⁾

The Company has interest rate swaps and interest rate option agreements in an aggregate notional principal amount of approximately $3.6 billion on non-recourse debt outstanding at December 31, 2008. The swap agreements economically change the variable interest rates on the portion of the debt covered by the notional amounts to fixed rates ranging from approximately 1.93% to 7.00%. The option agreements fix interest rates within a range from 4.50% to 7.00%. The agreements expire at various dates from 2009 through 2027.

⁽³⁾

Variable rate notes and bonds consist of approximately $1.7 billion of debt issued by our Brazilian subsidiaries with a weighted average interest rate of 16.84% at December 31, 2008, and $132 million of auction rate bonds issued by IPL. These auction rate bonds have paid the penalty rate of 12% since late September 2008 due to failed auctions of these securities. Subsequent to December 31, 2008 IPL's auction rate bonds were able to be remarketed at rates lower than these penalty rates.

⁽⁴⁾

Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.

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DECEMBER 31, 2008, 2007, AND 2006

10. LONG-TERM DEBT (Continued)

⁽⁵⁾

Ekibastuz and Maikuben debt of $164 million and Jiaozuo debt of $3 million as of December 31, 2007 are excluded from non-recourse debt and are included in current and long-term liabilities of held for sale and discontinued businesses in the accompanying Consolidated Balance Sheets.

        Future principal payments on non-recourse debt as of December 31, 2008 are set forth in the table below:

        As of December 31, 2008, AES subsidiaries in operations had approximately $1.1 billion of a number of available but unused committed revolving credit lines to support their working capital, debt service reserves and other business needs. These credit lines can be used in one or more of the following ways: solely for borrowings; solely for letters of credit; or a combination of these uses. The weighted average interest rate on borrowing from these facilities was 11.54% at December 31, 2008. In addition to the committed credit lines described above, an operating subsidiary of the Company in Brazil had credit commitments from banks to lend up to $856 million at December 31, 2008. This credit commitment is subject to certain conditions and can only be used if the Company decides to exercise its preemptive rights to acquire the minority interest shares of Brasiliana held by a third-party in response to a decision by the partner to sell and exercise its preemptive rights to include our ownership portion in the sale. In addition to the credit lines described above, AES subsidiaries with facilities under construction had a total of approximately $2.0 billion of committed but unused credit facilities available to fund construction and other related costs.

Non-Recourse Debt Covenants, Restrictions and Defaults

        The terms of the Company's non-recourse debt 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. Compliance with certain covenants may not be objectively determinable.

        As of December 31, 2008 and 2007, approximately $697 million and $614 million, respectively, of restricted cash was maintained in accordance with certain covenants of the debt agreements, and these amounts were included within restricted cash and debt service reserves and other deposits in the accompanying Consolidated Balance Sheets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

10. LONG-TERM DEBT (Continued)

        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 $5 billion at December 31, 2008.

        The following table summarizes the Company's subsidiary non-recourse debt in default as of December 31, 2008 and is included in the current portion of non-recourse debt unless otherwise indicated:

        None of the subsidiaries that are currently in default is a material subsidiary under AES's corporate debt agreements whose acceleration of debt or bankruptcy would trigger an event of default or permit acceleration under such indebtedness. At December 31, 2008 none of our subsidiaries met the definition of material subsidiary under our recourse secured and unsecured bond indentures and our unsecured line of credit. All of the subsidiary guarantors under our recourse secured credit facilities are defined as material subsidiaries under that agreement. The bankruptcy or acceleration of material amounts of debt at these entities would cause a cross default under the recourse secured credit facilities. The subsidiary guarantors include the subsidiaries which own AES Eastern Energy, AES Warrior Run, AES Shady Point and AES Hawaii. 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 our financial position and results of operations or the financial position or results of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a "material subsidiary" and thereby upon a bankruptcy or acceleration of its non-recourse debt trigger an event of default and possible acceleration of the indebtedness under the AES Parent Company's outstanding debt securities.

        Sonel, our subsidiary in Cameroon, and Masinloc, our subsidiary in the Philippines, were in default on total non-recourse debt of $217 million and $598 million, respectively, at December 31, 2008 due to covenant breaches. Subsequent to December 31, 2008, both subsidiaries were able to amend the terms of their respective debt agreements and are no longer considered in default, therefore the debt was appropriately classified as long-term at December 31, 2008 and was excluded from the debt default table above.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

10. LONG-TERM DEBT (Continued)

RECOURSE DEBT

        The following table summarizes the recourse debt of the Company as of December 31, 2008 and 2007:

        Future principal payments on recourse debt as of December 31, 2008 are set forth in the table below:

Financing and Tender Offer

        In the second quarter of 2008, the Company completed a number of debt-related transactions that resulted in a net reduction of approximately $360 million in aggregate principal of recourse debt. These transactions, described in further detail below, included $223 million of debt paid at maturity, the

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DECEMBER 31, 2008, 2007, AND 2006

10. LONG-TERM DEBT (Continued)

repurchase of the $762 million of senior notes maturing from 2009 to 2013 that were tendered in the Company's publicly announced tender offer, and the issuance of $625 million of 8% Senior Unsecured Notes due 2020 at par value.

        The notes repaid at maturity included $223 million outstanding 6.0% Junior Subordinated Convertible Debentures due May 15, 2008 and 8.75% Senior Unsecured Notes due June 15, 2008.

        On May 15, 2008, we issued $625 million of 8% Senior Unsecured Notes due 2020 at par value. Deferred financing costs attributable to the issuance of these senior notes were approximately $10 million.

        On June 19, 2008 the Company repurchased $762 million aggregate principal of senior notes maturing from 2009 to 2013 in connection with its publicly announced tender offer. Specifically, the Company repurchased $313 million of the 9.50% Senior Notes due 2009, (the "2009 Notes"), $209 million of the 9.375% Senior Notes due 2010 (the "2010 Notes"), $178 million of the 8.875% Senior Notes due 2011 (the "2011 Notes"), and $62 million of the 8.75% Second Priority Senior Secured Notes due 2013 (the "2013 Notes"). The Company recognized and included a pre-tax loss on the retirement of the senior notes for the year ended December 31, 2008 of $55 million, in "Other expense" which included $52 million of tender consideration.

        In connection with the tender offer for the senior notes in 2008, the Company solicited and received consents from the remaining holders of the 2013 Notes to amend the related indenture to conform substantially all of the covenants, except those related to security, to those contained in the indenture governing the Company's senior unsecured notes.

Amendment of Credit Agreement

        On July 29, 2008, The AES Corporation and certain subsidiary guarantors amended and restated the Company's existing senior secured bank facility ("Bank Facility") pursuant to the terms of the Fourth Amended and Restated Credit and Reimbursement Agreement (the "Amended and Restated Credit Agreement"). The Amended and Restated Credit Agreement provides for a $200 million senior secured term loan ("Term Loan") maturing on August 10, 2011, and a Revolving Credit Facility ("the Revolver") with available borrowings up to $750 million, maturing on June 23, 2010. The Amended and Restated Credit Agreement is included as an exhibit to this Form 10-K.

        The Company entered into the Amended and Restated Credit Agreement primarily to accomplish the following: (i) increase the size of the Restricted Payments basket to allow the Company to repurchase or pay dividends on equity; (ii) reduce the required minimum Cash Flow Coverage Ratio (as defined therein) and increase the maximum Recourse Debt to Cash Flow Ratio (as defined therein); (iii) clarify and make modifications to the provisions that permit hedging activities; and (iv) make certain other changes, such as excluding certain equity-like securities from the definition of Recourse Debt, amending the financial reporting and environmental notice requirements, clarifying that the term "Permitted Business" includes climate solutions, carbon offsets, biofuels, battery storage and ancillary businesses, including related trading activities and amending certain other definitions and covenants.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

10. LONG-TERM DEBT (Continued)

        As of December 31, 2008, the Revolving Credit Facility accrued interest at LIBOR plus 1.5% and there were no outstanding borrowings against the Revolving Credit Facility. The Company had $30 million of letters of credit outstanding against the Revolving Credit Facility and $720 million was available under the Revolving Credit Facility.

        The Company's senior unsecured credit facility ("Credit Facility") had available borrowings of $423 million. At December 31, 2008, the Company had no outstanding borrowings under the Credit Facility. The Company had $177 million of letters of credit outstanding against the Credit Facility as of December 31, 2008. The Credit Facility, which accrues interest at a variable rate indexed to LIBOR and matures in 2010, is being used to support the Company's ongoing share of construction obligations for AES Maritza East 1 and for general corporate purposes. AES Maritza East 1 is a coal-fired generation project in Bulgaria that began construction in the second quarter of 2006 and is expected to commence operations in 2010.

Recourse Debt Covenants and Guarantees

        Certain of the Company's obligations under the Bank Facilities are guaranteed by its direct subsidiaries through which the Company owns its interests in the Shady Point, Hawaii, Warrior Run and Eastern Energy businesses. The Company's obligations under the Bank Facility and Second Priority Senior Secured Notes are, subject to certain exceptions, secured 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 Bank Facility is subject to mandatory prepayment under certain circumstances. The net cash proceeds from the sale of a Guarantor or any of its subsidiaries must be applied pro rata to repay the Term Loan using 60% of net cash proceeds, reduced to 50% when and if the parent's recourse debt to cash flow ratio is less than 5:1. The lenders have the option to waive their pro rata redemption. In the case of sales of assets of or equity interests in IPALCO or any of its subsidiaries, any net cash proceeds of the asset sale remaining after application to the Term Loan facility must be used to reduce commitments under the Revolver, unless the supermajority of banks otherwise agree or unless the facilities are rated at least Ba1 from Moody's and AES' corporate credit rating from S&P is at least BB-.

        The Bank Facility contains customary covenants and restrictions on the Company's ability to engage in certain activities, including, but not limited to, limitations on other indebtedness, liens, investments and guarantees; limitations on restricted payments such as shareholder dividends and equity repurchases; restrictions on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet or derivative arrangements; and other financial reporting requirements.

        The Bank Facility also contains financial covenants requiring the Company to maintain certain financial ratios including a cash flow to interest coverage ratio, calculated quarterly, which provides that a minimum ratio of the Company's adjusted operating cash flow to the Company's interest charges

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DECEMBER 31, 2008, 2007, AND 2006

10. LONG-TERM DEBT (Continued)

related to recourse debt of 1.3× must be maintained at all times and a recourse debt to cash flow ratio, calculated quarterly, which provides that the ratio of the Company's total recourse debt to the Company's adjusted operating cash flow must not exceed a maximum of 8.0× at any time of calculation.

        The terms of the Company's Senior Unsecured Notes, Credit Facility, and Second Priority Secured Notes contain certain covenants including, without limitation, limitation on the Company's ability to incur liens or enter into sale and leaseback transactions.

TERM CONVERTIBLE TRUST SECURITIES

        In 1999, AES Trust III, a wholly owned special purpose business trust, issued 9 million of $3.375 Term Convertible Preferred Securities ("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 (the "6.75% Debentures" of the Company). The TECONS are consolidated and classified as long-term recourse debt on the Company's balance sheet.

        AES, at its option, can redeem the 6.75% Debentures which would result in the required redemption of the TECONS issued by AES Trust III, currently for $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 at the rate of 1.4216, representing a conversion price of $35.17 per share.

        Dividends on the TECONS are payable quarterly at an annual rate of 6.75%. The Trust is 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. AES has not exercised the option to defer any dividends at this time. 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. All dividends due under the Trust have been paid.

        AES Trust III is a VIE under FIN No. 46(R). AES's obligations under the Junior Subordinated Debentures and other relevant trust agreements, in aggregate, constitute a full and unconditional guarantee by AES of the TECON Trusts' obligations under the trust securities issued the respective trust. Accordingly, AES consolidates the results of AES Trust III. As of December 31, 2008 and 2007, the sole assets of AES Trust III are the Junior Subordinated Debentures.

        In 2000, AES Trust VII, a wholly owned special purpose business trust and a VIE under FIN No. 46(R), 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 (the "6% Debentures"). In May 2008, the Company used a portion of the proceeds from the issuance of its 8% Senior Unsecured Notes due 2020 to redeem the 6% Debentures and AES Trust VII was dissolved. At December 31, 2007, the sole assets of AES Trust VII were the 6% Debentures.

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11. COMMITMENTS

        OPERATING LEASES—As of December 31, 2008, the Company was obligated under long-term non-cancelable operating leases, primarily for certain transmission lines, office rental and site leases. Rental expense for lease commitments under these operating leases for the years ended December 31, 2008, 2007 and 2006 was $74 million, $64 million and $17 million, respectively.

        The table below sets forth the future minimum lease commitments under these operating leases at December 31, 2008 for 2009 through 2013 and thereafter:

        CAPITAL LEASES—Several AES subsidiaries lease operating and office equipment and vehicles that are considered capital lease transactions. These capital leases are recognized in Property, Plant and Equipment within "Electric generation and distribution assets" and primarily relate to transmission lines at our subsidiaries in Brazil. The gross value of the leased assets for the years ended December 31, 2008 and 2007 was $95 million and $69 million, respectively.

        The following table is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments at December 31, 2008 for 2009 through 2013 and thereafter:

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        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. In May 2007, the subsidiary purchased a portion of the lessor's interest in a trust estate that holds the leased plants. Future minimum lease commitments under the lease agreement are reduced by the subsidiary's interest in the plants. Rental expense was $34 million, $42 million and $54 million for the years ended December 31, 2008, 2007 and 2006, respectively.

        The following table summarizes the future minimum lease commitments under the sale/leaseback arrangement at December 31, 2008 for 2009 through 2013 and thereafter:

        CONTRACTS—Operating subsidiaries of the Company have entered into contracts for the purchase of electricity from third parties that primarily include energy auction agreements at our Brazil subsidiaries with extended terms from 2009 through 2042. Purchases in the years ended December 31, 2008, 2007 and 2006 were approximately $1.5 billion, $2.2 billion and $1.2 billion, respectively.

        The table below sets forth the future commitments under these electricity purchase contracts at December 31, 2008 for 2009 through 2013 and thereafter:

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        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 the years ended December 31, 2008, 2007 and 2006 were $1.8 billion, $1.3 billion and $844 million, respectively.

        The table below sets forth the future commitments under these fuel contracts as of December 31, 2008 for 2009 through 2013 and thereafter:

        The Company's subsidiaries entered into other various long-term contracts. These contracts are mainly for construction projects, service and maintenance, transmission of electricity and other operation services. Payments under these contracts for the years ended December 31, 2008, 2007 and 2006 were $1.9 billion, $840 million and $596 million, respectively,

        The table below sets forth the future commitments under these other purchase contracts as of December 31, 2008 for 2009 through 2013 and thereafter:

12. CONTINGENCIES

        ENVIRONMENTAL—The Company reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of December 31, 2008, the Company has recognized liabilities of $30 million for projected environmental remediation costs. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of

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compliance or remediation could be higher or lower than the amount currently accrued. Based on currently available information and analysis, the Company believes that it is reasonably possible that costs associated with such liabilities or as yet unknown liabilities may exceed current reserves in amounts that could be material but cannot be estimated as of December 31, 2008.

        GUARANTEES, LETTERS OF CREDIT—In connection with certain project financing, acquisition, power purchase, and other 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. 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 and letters of credit. 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. In addition to the contingent obligations of the Parent Company identified in the table below, the Company's subsidiaries had letters of credit outstanding to support various contingent obligations. At December 31, 2008, these letters of credit at our consolidated subsidiaries totaled approximately $1.2 billion.

        The following table summarizes the Parent Company's contingent contractual obligations as of December 31, 2008:

        Most of the contingent obligations primarily relate to future performance commitments which the Company or its subsidiaries expect to fulfill within the normal course of business. Amounts presented in the above table represent the Parent Company's current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure to the Parent Company as of December 31, 2008. Guarantee termination provisions vary from less than one year to greater than 20 years. Some result from the end of a contract period, assignment, asset sale, and change in credit rating or elapsed time. The amounts above include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of subsidiaries of $48 million.

        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 2009 or beyond that are not recognized on the Consolidated Balance Sheet, many of the events which would give rise to such an obligation are beyond the Parent

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Company's control. There can be no assurance that the Parent 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.

        In 2008, the Parent Company paid letter of credit fees which averaged 3.4% per annum on the outstanding amounts of letters of credit.

        LITIGATION—The Company is involved in certain claims, suits and legal proceedings in the normal course of business, some of which are described below. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company's financial statements. However, it is reasonably possible that some matters could be decided unfavorably to the Company, and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of December 31, 2008. The Company has evaluated claims, in accordance with SFAS No. 5, Accounting for Contingencies, ("SFAS No. 5") that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims for approximately $389 million and $486 million at December 31, 2008 and 2007, respectively.

        In 1989, Centrais Elétricas Brasileiras S.A. ("Eletrobrás") filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. ("EEDSP") relating to the methodology for calculating monetary adjustments under the parties' financing agreement. In April 1999, the Fifth District Court found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$937 million ($400 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista ("CTEEP") (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the Fifth District Court rejected Eletropaulo's defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice ("SCJ") reversed the Appellate Court's decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo's liability, if any, should be determined by the Fifth District Court. Eletropaulo's subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil have been dismissed. Eletrobrás may resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo will be required to provide security in the amount of its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the Fifth District Court grants such request, Eletropaulo's results of operations may be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the Fifth District Court against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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        In September 1999, a state appellate court in Minas Gerais, Brazil, granted a temporary injunction suspending the effectiveness of a shareholders' agreement between Southern Electric Brasil Participacoes, Ltda. ("SEB") and the state of Minas Gerais concerning CEMIG, an integrated utility in Minas Gerais. The Company's investment in CEMIG is through SEB. This shareholders' agreement granted SEB certain rights and powers in respect of CEMIG ("Special Rights"). In March 2000, a lower state court in Minas Gerais held the shareholders' agreement invalid where it purported to grant SEB the Special Rights and enjoined the exercise of the Special Rights. In August 2001, the state appellate court denied an appeal of the decision and extended the injunction. In October 2001, SEB filed appeals against the state appellate court's decision with the Federal Superior Court and the Supreme Court of Justice. The state appellate court denied access of these appeals to the higher courts, and in August 2002 SEB filed interlocutory appeals against such denial with the Federal Superior Court and the Supreme Court of Justice. In December 2004, the Federal Superior Court declined to hear SEB's appeal. However, the Supreme Court of Justice is considering whether to hear SEB's appeal. SEB intends to vigorously pursue a restoration of the value of its investment in CEMIG by all legal means; however, there can be no assurances that it will be successful in its efforts. Failure to prevail in this matter may limit SEB's influence on the daily operation of CEMIG.

        In August 2000, the Federal Energy Regulation Commission ("FERC") announced an investigation into the organized California wholesale power markets in order to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. FERC requested documents from each of the AES Southland, LLC plants and AES Placerita, Inc. AES Southland and AES Placerita have cooperated fully with the FERC investigations. AES Southland was not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. AES Placerita is currently subject to refund liability of $588,000 plus interest for spot sales to the California Power Exchange from October 2, 2000 to June 20, 2001 ("Refund Period"). In September 2004, the U.S. Court of Appeals for the Ninth Circuit issued an order addressing FERC's decision not to impose refunds for the alleged failure to file rates, including transaction specific data, for sales during 2000 and 2001 ("September 2004 Decision"). Although it did not order refunds, the Ninth Circuit remanded the case to FERC for a refund proceeding to consider remedial options. In March 2008, FERC issued its order on remand, requiring the parties to engage in settlement discussions before a settlement judge and establishing procedures for an evidentiary hearing if the settlement process failed. In addition, in August 2006 in a separate case, the Ninth Circuit confirmed the Refund Period, expanded the transactions subject to refunds to include multi-day transactions, expanded the potential liability of sellers to include any pre-Refund Period tariff violations, and remanded the matter to FERC ("August 2006 Decision"). Various parties filed petitions for rehearing in November 2007. The August 2006 Decision may allow FERC to reopen closed investigations and order relief. AES Placerita made sales during the periods at issue in the September 2004 and August 2006 Decisions. Both appeals may be subject to further court review, and further FERC proceedings on remand would be required to determine potential liability, if any. Prior to the August 2006 Decision, AES Placerita's potential liability for the Refund and pre-Refund Periods could have approximated $23 million plus interest. However, given the September 2004 and August 2006 Decisions, it is unclear whether AES Placerita's potential liability is less than or exceeds that amount. AES Placerita believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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        In August 2001, the Grid Corporation of Orissa, India ("Gridco"), filed a petition against the Central Electricity Supply Company of Orissa Ltd. ("CESCO"), an affiliate of the Company, with the Orissa Electricity Regulatory Commission ("OERC"), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC's August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO's distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company's indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO's financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited ("AES ODPL"), and Jyoti Structures ("Jyoti") pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the "CESCO arbitration"). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco's claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents' counterclaims were also rejected. The Company subsequently filed an application to recover its costs of the arbitration, which is under consideration by the tribunal. In addition, in September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in Orissa Power Generation Corporation Ltd's ("OPGC"), and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco's challenge to the arbitration award is resolved. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC's existing PPA with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC's jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court's decision to the Supreme Court and sought stays of both the High Court's decision and the underlying OERC proceedings regarding the PPAs terms. In April 2005, the Supreme

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Court granted OPGC's requests and ordered stays of the High Court's decision and the OERC proceedings with respect to the PPA's terms. The matter is awaiting further hearing. Unless the Supreme Court finds in favor of OPGC's appeal or otherwise prevents the OERC's proceedings regarding the PPA's terms, the OERC will likely lower the tariff payable to OPGC under the PPA, which would have an adverse impact on OPGC's financials. OPGC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In March 2003, the office of the Federal Public Prosecutor for the State of Sao Paulo, Brazil ("MPF") notified AES Eletropaulo that it had commenced an inquiry related to the Brazilian National Development Bank ("BNDES") financings provided to AES Elpa and AES Transgás 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. In July 2004, the MPF filed a public civil lawsuit in federal court alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES's internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo's preferred shares at a stock-market auction; (4) accepting Eletropaulo's preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. ("Light") and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES's alleged violations. In June 2005, AES Elpa and AES Transgás presented their preliminary answers to the charges. In May 2006, the federal court ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal seeking to require the federal court to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal seeking to enjoin the federal court from considering any of the alleged violations. The MPF's lawsuit before the federal court has been stayed pending those interlocutory appeals. AES Elpa and AES Transgás believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

        AES Florestal, Ltd. ("Florestal"), had been operating a pole factory and had other assets, including a wooded area known as "Horto Renner," in the State of Rio Grande do Sul, Brazil (collectively, "Property"). Florestal had been under the control of AES Sul ("Sul") since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica ("CEEE"), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney's Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public

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Attorney's Office then requested an injunction which the judge rejected on September 26, 2008. The Public Attorney's office has a right to appeal the decision. The environmental agency ("FEPAM") has also started a procedure (Procedure no. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul's name the Property that it acquired through the privatization but that remained registered in CEEE's name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a "Technical Cooperation Protocol" pursuant to which they requested a new deadline from FEPAM in order to present a proposal. The proposal was delivered on April 8, 2008. FEPAM responded by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE's operations. It is estimated that remediation could cost approximately R$14.7 million ($6.3 million). Discussions between Sul and CEEE are ongoing.

        In January 2004, the Company received notice of a "Formulation of Charges" filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the "Formulation of Charges," the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A., ("Itabo") Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. ("Este")) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the "Formulation of Charges" ("Constitutional Injunction"). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the "Formulation of Charges," and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court's decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity's appeal is pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In April 2004, BNDES filed a collection suit against SEB, a subsidiary of the Company, to obtain the payment of R$3.5 billion ($1.5 billion), which includes principal, interest and penalties under the loan agreement between BNDES and SEB, the proceeds of which were used by SEB to acquire shares of CEMIG. In May 2004, the 15th Federal Circuit Court ("Circuit Court") ordered the attachment of SEB's CEMIG shares, which were given as collateral for the loan, as well as dividends paid by CEMIG to SEB. At the time of the attachment, the shares were worth approximately R$762 million ($325 million). In December 2006, SEB's defense was ruled groundless by the Circuit Court, and in January 2007, SEB filed an appeal to the relevant Federal Court of Appeals. Subsequently, BNDES has seized a total of approximately R$630 million ($269 million) in attached dividends, with the approval of

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the Circuit Court. Also, in April 2008, BNDES filed a plea to seize the attached CEMIG shares. The Circuit Court will consider BNDES's request to seize the attached CEMIG shares after the net value of the alleged debt is recalculated in light of BNDES's seizure of dividends. SEB believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In July 2004, the Corporación Dominicana de Empresas Eléctricas Estatales ("CDEEE") filed lawsuits against Itabo, an affiliate of the Company, in the First and Fifth Chambers of the Civil and Commercial Court of First Instance for the National District. CDEEE alleges in both lawsuits that Itabo spent more than was necessary to rehabilitate two generation units of an Itabo power plant and, in the Fifth Chamber lawsuit, that those funds were paid to affiliates and subsidiaries of AES Gener and Coastal Itabo, Ltd. ("Coastal"), a former shareholder of Itabo, without the required approval of Itabo's board of administration. In the First Chamber lawsuit, CDEEE seeks an accounting of Itabo's transactions relating to the rehabilitation. In November 2004, the First Chamber dismissed the case for lack of legal basis. On appeal, in October 2005 the Court of Appeals of Santo Domingo ruled in Itabo's favor, reasoning that it lacked jurisdiction over the dispute because the parties' contracts mandated arbitration. The Supreme Court of Justice is considering CDEEE's appeal of the Court of Appeals' decision. In the Fifth Chamber lawsuit, which also names Itabo's former president as a defendant, CDEEE seeks $15 million in damages and the seizure of Itabo's assets. In October 2005, the Fifth Chamber held that it lacked jurisdiction to adjudicate the dispute given the arbitration provisions in the parties' contracts. The First Chamber of the Court of Appeal ratified that decision in September 2006. In a related proceeding, in May 2005, Itabo filed a lawsuit in the U.S. District Court for the Southern District of New York seeking to compel CDEEE to arbitrate its claims. The petition was denied in July 2005. Itabo's appeal of that decision to the U.S. Court of Appeals for the Second Circuit has been stayed since September 2006. Further, in September 2006, in an International Chamber of Commerce arbitration, an arbitral tribunal determined that they lacked jurisdiction to decide arbitration claims concerning these disputes. Itabo believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In April 2006, a putative class action complaint was filed in the U.S. District Court for the Southern District of Mississippi ("District Court") on behalf of certain individual plaintiffs and all residents and/or property owners in the State of Mississippi who allegedly suffered harm as a result of Hurricane Katrina, and against the Company and numerous unrelated companies, whose alleged greenhouse gas emissions allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert unjust enrichment, civil conspiracy/aiding and abetting, public and private nuisance, trespass, negligence, and fraudulent misrepresentation and concealment claims against the defendants. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. In August 2007, the District Court dismissed the case. The plaintiffs have appealed to the U.S. Court of Appeals for the Fifth Circuit, which heard oral arguments in November 2008 and is considering the appeal. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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        In June 2006, AES Ekibastuz was found to have breached a local tax law by failing to obtain a license for use of local water for the period of January 1, 2005 through October 3, 2005, in a timely manner. As a result, an additional permit fee was imposed, bringing the total permit fee to approximately $135,000. The Company has appealed this decision to the Supreme Court.

        In June 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan ordered AES Ust-Kamenogorsk TETS LLP ("UKT") to pay approximately 835 million KZT ($7 million) to the state for alleged antimonopoly violations in 2005 through January 2007. The Competition Committee also ordered UKT to pay approximately 235 million KZT ($2 million), as estimated by the Company, to certain customers that allegedly have paid unreasonably high power prices since January 2007. In November 2007, the economic court of first instance upheld the Competition Committee's order in part, finding that UKT had violated Kazakhstan's antimonopoly laws, but reduced the damages to be paid to the state to 833 million KZT ($7 million) and rejected the damages to be paid to customers. The court of appeals (first panel) later affirmed the economic court's decision and, therefore, in June 2008, UKT paid the damages. The court of appeals (second panel) rejected UKT's appeal in June 2008. UKT has appealed to the Supreme Court of Kazakhstan. The Competition Committee's successor (the Antimonopoly Agency) has not indicated whether it intends to assert claims against UKT for alleged antimonopoly violations post January 2007. UKT believes it has meritorious claims and defenses; however, there can be no assurances that it will prevail in these proceedings.

        In July 2007, the Competition Committee ordered Nurenergoservice, an AES subsidiary, to pay approximately 18 billion KZT ($150 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. The Competition Committee's order was affirmed by the economic court in April 2008. Nurenergoservice's subsequent appeals have been unsuccessful to date, including at the court of appeals (first panel), which rejected Nurenergoservice's appeal in July 2008. Also, the economic court has issued an injunction to secure Nurenergoservice's alleged liability, freezing Nurenergoservice's bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. In separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately 2 billion KZT (approximately $17 million) in administrative fines for its alleged antimonopoly violations. Nurenergoservice subsequently appealed to the administrative court of first instance. That appeal has been stayed since October 2007 but could resume at any time. The Antimonopoly Agency has not indicated whether it intends to assert claims against Nurenergoservice for alleged antimonopoly violations post first quarter 2007. Nurenergoservice believes it has meritorious claims and defenses; however, there can be no assurances that it will prevail in these proceedings. As Nurenergoservice did not prevail in the economic court or the court of appeals (first panel) with respect to the alleged damages, it will have to pay the alleged damages or risk seizure of its assets. In February 2009, the Antimonopoly Agency seized approximately 783 million KZT ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice alleged damages liability. Furthermore, if Nurenergoservice does not prevail in the administrative court with respect to the fines, it will have to pay the fines or risk seizure of its assets.

        In August 2007, the Competition Committee ordered Sogrinsk TETS, a thermal cogeneration plant under AES concession, to terminate its contracts with Nurenergoservice and Ust-Kamenogorsk HPP because of Sogrinsk's alleged antimonopoly violations in 2005 through January 2007. The Competition

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Committee did not order Sogrinsk to pay any damages or fines. The Kazakhstan courts have affirmed the order, including the Supreme Court of Kazakhstan in October 2008. The Antimonopoly Agency has not indicated whether it intends to assert claims against Sogrinsk for alleged antimonopoly violations post January 2007.

        In November 2007, the Competition Committee initiated an investigation of allegations that Irtysh Power and Light, LLP ("Irtysh"), an AES company which manages the state-owned Ust-Kamenogorsk Heat Nets system, had violated Kazakhstan's antimonopoly laws in January through November 2007 by selling power at below-market prices. In February 2008, the Competition Committee determined that the allegations were baseless. The Competition Committee subsequently appeared to initiate an investigation to determine whether Irtysh had illegally coordinated with other AES companies concerning the sale of power, but its successor (the Antimonopoly Agency) has not issued any order or otherwise taken any action on any such investigation to date. Irtysh believes it has meritorious claims and defenses and will assert them vigorously in any formal proceeding; however, there can be no assurances that it will be successful in its efforts.

        In December 2008, the Antimonopoly Agency ordered Ust-Kamenogorsk HPP ("UK HPP"), a hydroelectric plant under AES concession, to pay approximately 1.1 billion KZT ($9 million) for alleged antimonopoly violations in February through November 2007. The economic court has issued an injunction to secure UK HPP's alleged liability, among other things freezing UK HPP's bank accounts. Furthermore, the Antimonopoly Agency has initiated administrative proceedings against UK HPP seeking an unspecified amount of administrative fines for the alleged antimonopoly violations. UK HPP believes it has meritorious defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.

        In June 2007, the Company received a letter from an outside law firm purportedly representing a shareholder demanding that the Company's Board conduct a review of certain stock option plans, procedures and historical granting and exercise practices, and other matters, and that the Company commence legal proceedings against any officer and/or director who may be liable for damages to the Company. The Board has established a Special Committee, which has retained independent counsel, to consider the demands presented in the letter in light of the work undertaken by the Company in its review of share-based compensation. The Company has not received any communication from the purported shareholder who made the demand since the second half of 2007.

        In July 2007, AES Energia Cartagena SRL, ("AESEC") initiated arbitration against Initec Energia SA, Mitsubishi Corporation, and MC Power Project Management, SL ("Contractor") to recover damages from the Contractor for its delay in completing the construction of AESEC's majority-owned power facility in Murcia, Spain. In October 2007, the Contractor denied AESEC's claims and asserted counterclaims to recover approximately €12 million ($17 million) for alleged unpaid milestone and scope change order payments, among other things, and an unspecified amount for an alleged early completion bonus. The final hearing is scheduled to begin in June 2009. AESEC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In November 2007, the International Brotherhood of Electrical Workers, Local Union No. 1395, and sixteen individual retirees, (the "Complainants"), filed a complaint at the Indiana Utility

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Regulatory Commission ("IURC") seeking enforcement of their interpretation of the 1995 final order and associated settlement agreement resolving IPL's basic rate case. The Complainants are requesting that the IURC conduct an investigation of IPL's failure to fund the Voluntary Employee Beneficiary Association Trust ("VEBA Trust"), at a level of approximately $19 million per year. The VEBA Trust was spun off to an independent trustee in 2001. The complaint seeks an IURC order requiring IPL to make contributions to place the VEBA Trust in the financial position in which it allegedly would have been had IPL not ceased making annual contributions to the VEBA Trust after its spin off. The complaint also seeks an IURC order requiring IPL to resume making annual contributions to the VEBA Trust. IPL filed a motion to dismiss and both parties are seeking summary judgment in the IURC proceeding. To date, no procedural schedule for this proceeding has been established. IPL believes it has meritorious defenses to the Complainants' claims and it will assert them vigorously in response to the complaint; however, there can be no assurances that it will be successful in its efforts.

        In September 2007, the New York Attorney General issued a subpoena to the Company seeking documents and information concerning the Company's analysis and public disclosure of the potential impacts that greenhouse gas ("GHG") legislation and climate change from GHG emissions might have on the Company's operations and results. The Company has produced documents and information in response to the subpoena.

        In October 2007, the Ekibastuz Tax Committee issued a notice for the assessment of certain taxes against AES Ekibastuz LLP. A portion of the assessment, approximately $1.7 million, relates to alleged environmental pollution. The review by the Ekibastuz Tax Committee is ongoing and their decision on any assessment, including the portion related to alleged environmental pollution, is not yet final. In addition, as the result of a subsequent tax audit which was completed on January 24, 2008, an additional amount of approximately 36 million KZT in principal, 20 million KZT in interest and 13 million KZT in penalty (collectively, approximately $600,000), was assessed as underpayment of taxes for the 2004 calendar year and VAT for January 2004. AES Ekibastuz appealed these assessments. However, this position was rejected by the Regional Tax Committee in a decision dated January 30, 2008. On February 29, 2008, AES Ekibastuz appealed to the Ministry of Finance of the Republic of Kazakhstan and is currently awaiting a decision.

        In February 2008, the Native Village of Kivalina, Alaska, and the City of Kivalina filed a complaint in the U.S. District Court for the Northern District of California against the Company and numerous unrelated companies, claiming that the defendants' alleged GHG emissions are destroying the plaintiffs' alleged land. The plaintiffs assert nuisance and concert of action claims against the Company and the other defendants, and a conspiracy claim against a subset of the other defendants. The plaintiffs seek to recover relocation costs, indicated in the complaint to be from $95 million to $400 million, and other alleged damages from the defendants, which are not quantified. The Company has filed a motion to dismiss the case, which the plaintiffs have opposed. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        A public civil action has been asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the "Associação") relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld on the first appeal found

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that Eletropaulo should either repair the alleged environmental damage by demolishing certain construction and reforesting the area, pursuant to a project which would cost approximately $628,000, or pay an indemnification amount of approximately $5 million. Eletropaulo has appealed this decision to the Supreme Court and is awaiting a decision.

        In 2007, a lower court issued a decision related to a 1993 claim that was filed by the Public Attorney's office against Eletropaulo, the Sao Paulo State Government, SABESP (a state owned company), CETESB (a state owned company) and DAEE (the municipal Water and Electric Energy Department), alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from Pinheiros River into Billings Reservoir. The events in question occurred while Eletropaulo was a state owned company. The initial lower court decision in 2007 found the parties liable for the payment of R$517.46 million ($221 million) for remediation. Eletropaulo subsequently appealed the decision and Eletropaulo is still awaiting a decision on the appeal. The filing of the appeal suspended the lower court's decision. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In September 2008, IPL received a Clean Air Act Section 114 information request. The request seeks various information regarding production levels and projects implemented at IPL's generating stations, generally for the time period from January 1, 2001 to the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the Clean Air Act. At this time it is not possible to predict what impact, if any, this request may have on IPL, its results of operation or its financial position.

        In November 2007, the U.S. Department of Justice ("DOJ") indicated to AES Thames, LLC ("AES Thames") that the U.S. EPA had requested that the DOJ file a federal court action against AES Thames for alleged violations of the Clean Air Act ("CAA"), the Clean Water Act ("CWA"), the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and the Emergency Planning and Community Right-to-Know Act ("EPCRA"), in particular alleging that AES Thames had violated (i) the terms of its Prevention of Significant Deterioration ("PSD") air permits in the calculation of its steam load permit limit; and (ii) the CWA, CERCLA and EPCRA in connection with two spills of chlorinating agents. The DOJ subsequently indicated that it would like to settle this matter prior to filing a suit and negotiations are ongoing. During such discussions, the DOJ and EPA have accepted AES Thames method of operation and have asked AES Thames to seek a minor permit modification to clarify the air permit condition. On October 21, 2008, the DOJ proposed a civil penalty of $245,000 for the alleged violations. The Company believes that it has meritorious defenses to the claims asserted against it and if a settlement cannot be achieved, the Company will defend itself vigorously in any lawsuit.

        In December 2008, there were press reports that the National Electricity Regulatory Entity of Argentina ("ENRE") had filed a criminal action in the National Criminal and Correctional Court of Argentina against the board of directors and administrators of EDELAP, an AES subsidiary. Although EDELAP has not been officially served with notice of the action, press reports have stated that ENRE's action concerns certain bank cancellations of EDELAP debt in 2006 and 2007, which were accomplished through transactions between the banks and related AES companies. According to press

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reports, ENRE claims that EDELAP should have reflected in its accounts the alleged benefits of the transactions that were allegedly obtained by the related companies. EDELAP believes that the allegations lack merit; however, there can be no assurances that its board and administrators will be successful in any formal proceedings concerning the allegations.

        In January 2009, an alleged shareholder of the Company filed a shareholder derivative and putative class action in Delaware state court against the Company and certain members of its board of directors. The plaintiff claims that Section 2.17(B) of the Company's bylaws, concerning shareholder action by written consent, is illegal under Delaware law. The plaintiff does not seek damages but declarations that Section 2.17(B) is unlawful and void and that the board member defendants breached their respective fiduciary duties of loyalty by adopting that bylaw in October 2008. The plaintiff further seeks to recover his litigation costs. The Company defendants believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

        A CAA Section 114 information request regarding Cayuga and Somerset was received in February 2009. The request seeks various operating and testing data and other information regarding certain types of projects at the Cayuga and Somerset facilities, generally for the time period from January 1, 2000 through the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. At this time it is not possible to predict what impact, if any, this request may have on Cayuga and/or Somerset, their results of operation or their financial position.

13. BENEFIT PLANS

        DEFINED CONTRIBUTION PLAN—The Company sponsors one defined contribution plan, qualified under section 401 of the Internal Revenue Code. All employees of the Company are eligible to participate in the plan except for those employees who are not covered by their collective bargaining agreement. The plan provides for Company matching contributions in Company stock, other Company contributions at the discretion of the Compensation Committee of the Board of Directors in Company stock, 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 fifth anniversary of their hire date. Company contributions to the plans were approximately $21 million, $22 million, and $21 million for the years ended December 31, 2008, 2007, and 2006, respectively.

        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 24 defined benefit plans, three are at U.S. subsidiaries and the remaining plans are at foreign subsidiaries. In May 2007, the Company sold EDC; the impact of this disposition is reflected in the tables below in the Plan settlements line item for the year ended December 31, 2007.

        The Company adopted the recognition provisions of SFAS No. 158, effective December 31, 2006, which requires recognition of an asset or liability in the balance sheet reflecting the funded status of pension and other post-retirement benefits plans with current-year changes in the funded status

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recognized in stockholders' equity. The Company recognized a cumulative adjustment to adopt the recognition provisions of SFAS No. 158 as of December 31, 2006. AES adopted the measurement date provisions of the standard, which require a year-end measurement date of plan assets and obligations for all defined benefit plans, for the fiscal year ended December 31, 2008 and accordingly, recognized a cumulative adjustment of $1 million to retained earnings as of December 31, 2008. Prior to the year ended December 31, 2008, seven of the Company's defined benefit plans used an early measurement date to value their plan assets and obligations.

        The following table reconciles the Company's funded status, both domestic and foreign, as of December 31, 2008 and 2007:

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        The following table summarizes the amounts recognized on the Consolidated Balance Sheets, both domestic and foreign, as of December 31, 2008 and 2007:

        The following table summarizes the Company's accumulated benefit obligation, both domestic and foreign, as of December 31, 2008 and 2007:

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        The table below demonstrates the significant weighted average assumptions used in the calculation of benefit obligation and net periodic benefit cost, both domestic and foreign, as of December 31, 2008 and 2007:

        A subsidiary of the Company has a defined benefit obligation of $528 million and $482 million at December 31, 2008 and 2007, respectively, and uses salary bands to determine future benefit costs rather than a rate of compensation increases. Rates of compensation increases in the table above do not include amounts related to this specific defined benefit plan.

        The Company establishes its estimated long-term return on plan assets considering various factors, which include the targeted asset allocation percentages, historic returns and expected future returns.

        The measurement of pension obligations, costs and liabilities is dependent on a variety of assumptions. These assumptions include estimates of the present value of projected future pension payments to all plan participants, taking into consideration the likelihood of potential future events such as salary increases and demographic experience. These assumptions may have an effect on the amount and timing of future contributions.

        The assumptions used in developing the required estimates include the following key factors:

•

Discount rates;



•

Salary growth;



•

Retirement rates;



•

Inflation;



•

Expected return on plan assets; and



•

Mortality rates.

        The effects of actual results differing from the Company's assumptions are accumulated and amortized over future periods and, therefore, generally affect our recognized expense in such future periods.

        Sensitivity of our pension funded status and stockholders' equity to the indicated increase or decrease in the discount rate and long-term rate of return on plan assets assumptions is shown below. Note that these sensitivities may be asymmetric, and are specific to the base conditions at year-end

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2008. They also may not be additive, so the impact of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown. The December 31, 2008 funded status is affected by December 31, 2008 assumptions. Pension expense for 2008 is affected by December 31, 2007 assumptions. The impact on pension expense from a one percentage point change in these assumptions is shown in the table below (in millions):

        The following table summarizes the components of the net periodic benefit cost, both domestic and foreign, for the years ended December 31, 2008 through 2006:

        For the year ended December 31, 2006, $(102) million (prior to the adjustment for the adoption of SFAS No. 158), was included in other comprehensive income arising from a change in the additional minimum pension liability.

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        The following table summarizes the amounts reflected in Accumulated Other Comprehensive Income on the Consolidated Balance Sheet as of December 31, 2008 that have not yet been recognized as components of net periodic benefit cost:

        The following table summarizes the Company's target allocation for 2008 and pension plan asset allocation, both domestic and foreign, as of December 31, 2008 and 2007:

        The U.S. plans seek to achieve the following long-term investment objectives:

•

Maintenance of sufficient income and liquidity to pay retirement benefits and other lump sum payments;



•

Long-term rate of return in excess of the annualized inflation rate;



•

Long-term rate of return (net of relevant fees that meet or exceed the assumed actuarial rate);



•

Long-term competitive rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates.

        Consistent with the above, the allocation is reviewed periodically to determine a suitable asset allocation which seeks to control risk through portfolio diversification and takes into account, among other possible factors, the above-stated objectives, in conjunction with current funding levels, cash flow conditions and economic and industry trends.

        The investment strategy of the foreign plans seeks to maximize return on investment while minimizing risk. Our assumed asset allocation uses a lower exposure to equities to closely match

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market conditions and near term forecasts. Some of the Company's plans hold investments that are illiquid. These assets are held by our subsidiaries in Brazil and total $279 million and represent 9% of total plan assets at December 31, 2008.

        The following table summarizes the scheduled cash flows for U.S. and foreign expected employer contributions and expected future benefit payments, both domestic and foreign:

14. STOCKHOLDERS' EQUITY

STOCK REPURCHASE

        On August 7, 2008, the Company's Board of Directors approved a share repurchase plan for up to $400 million of its outstanding common stock. The Board authorization permits the Company to repurchase shares over a six month period ending February 7, 2009. Shares of common stock repurchased under this plan through December 31, 2008 totaled 10,691,267 at a total cost of $143 million plus commissions of $0.3 million (average of $13.41 per share including commissions). The remaining amount authorized to be purchased under the share repurchase plan as of December 31, 2008 was $257 million. The shares of stock repurchased have been classified as treasury stock and accounted for using the cost method. A total of 10,691,267 shares were held in treasury stock at December 31, 2008. At December 31, 2007, there were no shares of common stock held in treasury stock. The Company did not retire any shares of treasury stock during the year ended December 31, 2008. No shares of common stock were repurchased subsequent to December 31, 2008 and the Board authorization of the plan expired on February 7, 2009.

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ACCUMULATED OTHER COMPREHENSIVE LOSS

        The following table summarizes the balances comprising accumulated other comprehensive loss net of tax, as of December 31, 2008 and 2007:

15. SEGMENT AND GEOGRAPHIC INFORMATION

        Through the end of 2008, the Company organized its operations along two primary lines of business (Generation and Utilities) within four geographic regions: Latin America; North America; Europe & Africa; and Asia & the Middle East ("Asia"). The reportable segments included:

•

Latin America Generation;



•

Latin America Utilities;



•

North America Generation;



•

North America Utilities;



•

Europe & Africa Generation;



•

Europe & Africa Utilities;



•

Asia Generation.

        The Company's segment reporting reflects how AES managed its operations internally in terms of decision making and evaluating performance through the end of 2008. The Company managed its business primarily on a geographic basis in two distinct lines of business—the generation of electricity ("Generation") and the distribution of electricity ("Utilities"). These businesses are distinguished by the nature of their customers, operational differences, cost structure, regulatory environment and risk exposure. Given the geographic dispersion of our operating units, we further disaggregated the lines of business by region into separate segments to provide further transparency to our shareholders and other external constituents.

        Three regions, North America, Latin America and Europe & Africa, are engaged in both Generation and Utility businesses. Our Asia region only has Generation businesses. Accordingly, these businesses and regions accounted for seven segments. In 2008, AES Wind Generation, climate solutions, and certain other initiatives were managed by our alternative energy group. The associated revenue, development costs and operational costs were reported under "Corporate and Other" since its results were not material to the presentation of our operating segments. "Corporate and Other" also included corporate overhead costs which are not directly associated with the operations of our seven

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primary operating segments; interest income and expense; other intercompany charges such as management fees and self-insurance premiums which are fully eliminated in consolidation.

        In early 2009, the Company began to implement certain organizational changes in an effort to streamline the organization. The new structure will continue to be organized along our two lines of business, but within three regions instead of four: (1) North America, (2) Latin America & Africa and (3) Europe, Middle East & Asia ("EMEA"). In addition, we will no longer have an alternative energy group. Instead, AES Wind Generation, will be managed as part of our North America region while climate solutions projects will be managed in the region in which they are located. Management is currently evaluating the impact of the reorganization on the Company's externally reported segments beginning with our Quarterly Report on Form 10-Q for the quarter ending March 31, 2009, as required under SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information ("SFAS No. 131").

        The Company uses both revenue and gross margin as key measures to evaluate the performance of its segments. Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No inter-segment revenue relationships exist in other segments. Gross margin is defined as total revenue less operating expenses including depreciation and amortization and local fixed operating and other overhead costs. Corporate allocations include certain management fees and self insurance activity which are reflected within segment gross margin. All intra-segment activity has been eliminated with respect to revenue and gross margin within the segment; inter-segment activity has been eliminated within the total consolidated results. All balance sheet information for businesses that were discontinued is segregated and is shown in the line "Discontinued Businesses" in the accompanying segment tables.

        The tables below present the breakdown of business segment balance sheet and income statement data as of and for the years ended December 31, 2008 through 2006:

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        The table below presents information about the Company's consolidated operations and long-lived assets, by country, for years ended December 31, 2008 through 2006 and as of December 31, 2008 and 2007, respectively. Revenues are recorded in the country in which they are earned and assets are recorded in the country in which they are located.

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⁽¹⁾

Acquired in May 2008, revenues represent results for a partial year.

⁽²⁾

Currently under development, facility is not operational at this time.

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16. SHARE-BASED COMPENSATION

        STOCK OPTIONS—AES grants options to purchase shares of common stock under stock option plans. Under the terms of the plans, the Company may issue options to purchase shares of the Company's common stock at a price equal to 100% of the market price at the date the option is granted. Stock options are generally granted based upon a percentage of an employee's base salary. Stock options issued under these plans in 2008, 2007 and 2006 have a three-year vesting schedule and vest in one-third increments over the three-year period. The stock options have a contractual term of ten years. At December 31, 2008, approximately 19 million shares were remaining for award under the plans. In all circumstances, stock options granted by AES do not entitle the holder the right, or obligate AES, to settle the stock option in cash or other assets of AES.

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

        Beginning January 1, 2006, the Company exclusively relies on implied volatility as the expected volatility to determine the fair value using the Black-Scholes option-pricing model. The implied volatility may be exclusively relied upon due to the following factors:

•

The Company utilizes a valuation model that is based on a constant volatility assumption to value its employee share options;



•

The implied volatility is derived from options to purchase AES common stock that are actively traded;



•

The market prices of both the traded options and the underlying share are measured at a similar point in time to each other and on a date reasonably close to the grant date of the employee share options;



•

The traded options have exercise prices that are both near-the-money and close to the exercise price of the employee share options; and



•

The remaining maturities of the traded options on which the estimate is based are at least one year.

        Pursuant to SAB No. 107, the Company used a simplified method to determine the expected term based on the average of the original contractual term and the pro rata vesting term. This simplified method was used for stock options granted during the years ended December 31, 2007 and 2006. In 2008, the Company continued to use the simplified method pursuant to SAB No. 110, which amends SAB No. 107 and allows for the continued use of the simplified method under certain circumstances for stock options accounted for under SFAS No. 123(R). This is appropriate given a lack of relevant

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stock option exercise data. This simplified method may be used as the Company's stock options have the following characteristics:

•

The stock options are granted at-the-money;



•

Exercisability is conditional only on performing service through the vesting date;



•

If an employee terminates service prior to vesting, the employee forfeits the stock options;



•

If an employee terminates service after vesting, the employee has a limited time to exercise the stock option; and



•

The stock option is nonhedgeable and not transferable.

        The Company does not discount the grant date fair values determined to estimate post-vesting restrictions. Post-vesting restrictions include black-out periods when the employee is not able to exercise stock options based on their potential knowledge of information prior to the release of that information to the public. The assumptions that the Company has made in determining the grant date fair value of its stock options and the estimated forfeiture rates represent its best estimate.

        Using the above assumptions, the weighted average fair value of each stock option granted was $7.65, $8.49 and $6.82, for the years ended December 31, 2008, 2007, and 2006, respectively.

        The following table summarizes the components of stock-based compensation related to employee stock options recognized in the Company's financial statements:

        There was no cash used to settle stock options or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2008, 2007 and 2006. As of December 31, 2008, $16 million of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted average period of approximately 1.7 years. There were no modifications to stock option awards during the year ended December 31, 2008.

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DECEMBER 31, 2008, 2007, AND 2006

16. SHARE-BASED COMPENSATION (Continued)

        A summary of the option activity for year ended December 31, 2008 follows (number of options in thousands, dollars in millions except per option amounts):

        The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the Company's closing stock price on the last trading day of the fourth quarter of 2008 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2008. The amount of the aggregate intrinsic value will change based on the fair market value of the Company's stock.

        The Company initially recognizes compensation cost on the estimated number of instruments for which the requisite service is expected to be rendered. In 2008, AES has estimated a forfeiture rate of 16.87% and 10.19% for stock options granted to non-officer employees and officer employees of AES, respectively. In 2007, based on actual experience, AES reevaluated the forfeiture rates for non-officer employees for its prior year grants and adjusted the rate to 14.70% from 8.55% for the plan year ended December 31, 2006. Those estimates will be revised if subsequent information indicates that the actual number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rates, the Company expects to expense $14 million on a straight-line basis over a three year period (approximately $4.6 million per year) related to stock options granted during the year ended December 31, 2008.

RESTRICTED STOCK

        Restricted Stock Units Without Market Conditions—The Company issues restricted stock units ("RSUs") without market conditions under its long-term compensation plan. The RSUs are generally granted based upon a percentage of the participant's base salary. The units have a three-year vesting schedule and vest in one-third increments over the three-year period. The units are then required to be held for an additional two years before they can be redeemed for shares, and thus become transferable.

        For the years ended December 31, 2008, 2007, and 2006, RSUs issued without a market condition had a grant date fair value equal to the closing price of the Company's stock on the grant date. The Company does not discount the grant date fair values to reflect any post-vesting restrictions. RSUs

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DECEMBER 31, 2008, 2007, AND 2006

16. SHARE-BASED COMPENSATION (Continued)

without a market condition granted to non-executive employees during the years ended December 31, 2008, 2007, and 2006 had grant date fair values per RSU of $18.87, $22.28 and $17.57, respectively.

        The following table summarizes the components of the Company's stock-based compensation related to its employee RSUs issued without market conditions recognized in the Company's financial statements:

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⁽¹⁾

59,000 RSUs were converted during the year ended December 31, 2008. No RSUs were converted during the years ended December 31, 2007 and 2006.

        There was no cash used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2008, 2007 and 2006. As of December 31, 2008, $16 million of total unrecognized compensation cost related to RSUs without the market condition is expected to be recognized over a weighted average period of approximately 1.8 years. There were no modifications to RSU awards during the year ended December 31, 2008.

        A summary of the RSUs activity for the year ended December 31, 2008 follows (number of RSUs in thousands, dollars in millions except per unit amounts):

        The weighted average grant date fair value of RSUs without a market condition granted during year ended December 31, 2008, was $18.87. The fair value of RSUs without a market condition that vested during the years ended December 31, 2008, 2007 and 2006 was $10 million, $10 million and $7 million, respectively. RSUs without a market condition vesting during the years ended December 31, 2008, 2007 and 2006 were 597,000, 714,000 and 569,000, respectively. 59,000 RSUs were converted

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DECEMBER 31, 2008, 2007, AND 2006

16. SHARE-BASED COMPENSATION (Continued)

during the year ended December 31, 2008. No RSUs were converted during the years ended December 31, 2007 and 2006.

        The total grant date fair value of RSUs granted without a market condition was $15 million during the year ended December 31, 2008.

        Restricted Stock Units With Market Conditions—Restricted stock units issued to officers of the Company have a three-year vesting schedule and include a market condition to vest. Vesting will occur if the applicable continued employment conditions are satisfied and the Total Stockholder Return ("TSR") on AES common stock exceeds the TSR of the Standard and Poor's 500 ("S&P 500") over the three-year measurement period beginning on January 1st in the year of grant and ending after three years on December 31st. In certain situations where the TSR of both AES common stock and the S&P 500 exhibit a gain over the measurement period, the grant may vest without the TSR of AES common stock exceeding the TSR of the S&P 500, if the Compensation Committee exercises its discretion to permit such vesting. The units are then required to be held for an additional two years subsequent to vesting before they can be redeemed for shares, and thus become transferable. In all circumstances, restricted stock units granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock unit in cash or other assets of AES.

        The effect of the market condition on restricted stock units issued to officers of the Company is reflected in the award's fair value on the grant date for the year ended December 31, 2008. A discount of 14% was applied to the closing price of the Company's stock on the date of grant to estimate the fair value to reflect the market condition for RSUs with market conditions granted during the year ended December 31, 2008. RSUs that included a market condition granted during the year ended December 31, 2008 and 2007 had a grant date fair value per RSU of $16.23 and $18.27, respectively.

        The following table summarizes the components of the Company's stock-based compensation related to its RSUs granted with market conditions recognized in the Company's financial statements:

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⁽¹⁾

No RSUs were converted during the years ended December 31, 2008, 2007 or 2006.

        There was no cash used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the years ended December 31, 2008, 2007 and 2006. As of December 31, 2008, $5 million of total unrecognized compensation cost related to RSUs with a market condition is expected to be recognized over a weighted average period of approximately 1.7 years. There were no modifications to RSU awards during the year ended December 31, 2008.

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DECEMBER 31, 2008, 2007, AND 2006

16. SHARE-BASED COMPENSATION (Continued)

        A summary of the restricted stock unit activity for the year ended December 31, 2008 follows (number of RSUs in thousands, $ in millions except per unit amounts):

        The weighted average grant date fair value of RSUs with a market condition granted during year ended December 31, 2008, was $16.23. RSUs with a market condition that vested during the years ended December 31, 2008 and 2007 were 352,000 and 548,000, respectively. No RSUs with a market condition vested during the year ended December 31, 2006. No RSUs were converted during the years ended December 31, 2008, 2007 and 2006.

        The total grant date fair value of RSUs with a market condition granted during the year ended December 31, 2008 was $3.9 million. If no discount was applied to reflect the market condition for RSUs issued to officers, the total grant date fair value of RSUs with a market condition granted during year ended December 31, 2008 would have increased by $0.6 million.

17. SUBSIDIARY STOCK

        Minority interest includes $60 million of cumulative preferred stock of subsidiaries at December 31, 2008 and 2007. The total annual dividend requirement was approximately $3 million at December 31, 2008 and 2007. Each series of preferred stock is redeemable solely at the option of the issuer at prices between $101 and $118 per share.

        On November 6, 2008, a wholly-owned subsidiary of the Company, Inversiones Cachagua Limitada ("Cachagua"), sold a 9.6% ownership interest in AES Gener in a private transaction for $174.9 million. The sale reduced the Company's ownership percentage of AES Gener from 80.2% to 70.6%. The Company recognized a pre-tax loss of $30.8 million, including $3.6 million of related fees, from this transaction in the fourth quarter of 2008. The net proceeds from this transaction was used exclusively for Gener's capital increase as approved by Gener's Extraordinary Shareholders Meeting on November 19, 2008. See further discussion of Gener's 2009 capital increase in Note 27—Subsequent Events.

        In May and October 2007, Cachagua sold a 0.9% and 10.2% ownership interest, respectively, in AES Gener for $330.9 million. The sale reduced the Company's ownership percentage of AES Gener to 80.2%. The Company recorded a pre-tax gain on the sale of $134.2 million, including $8.3 million of related fees.

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DECEMBER 31, 2008, 2007, AND 2006

17. SUBSIDIARY STOCK (Continued)

        Sale of Subsidiary Stock and Brasiliana Restructuring—In September 2006, Brasiliana's wholly owned subsidiary, Transgás, sold a 33% economic ownership in Eletropaulo, a regulated electric utility in Brazil. Despite the reduction in economic ownership, there was no change in Brasiliana's voting interest in Eletropaulo and Brasiliana continues to control Eletropaulo. Transgás received $522 million in net proceeds on the sale. On October 5, 2006 Transgás, sold an additional 5% economic ownership in Eletropaulo for $78 million in net proceeds. For the year ended December 31, 2006, AES recognized a pre-tax loss of $535 million primarily as a result of the recognition of previously deferred currency translation losses.

18. OTHER INCOME AND EXPENSE

        The components of other income are summarized as follows:

        Other income primarily includes gains on asset sales and extinguishments of liabilities, favorable judgments on legal settlements, and other income from miscellaneous transactions. Other income of $379 million for the year ended December 31, 2008 included $32 million of cash proceeds related to a favorable legal settlement at Southland in California, $23 million of gains associated with a sale of land at Eletropaulo and sales of turbines at Itabo, gains on the extinguishment of a tax liability and a legal contingency at Eletropaulo of $117 million and $75 million, respectively, $29 million of insurance recoveries for damaged turbines at Uruguaiana, and compensation of $18 million for the impairment associated with the settlement agreement to shut down Hefei. Other income of $358 million for the year ended December 31, 2007 included a $135 million contract settlement gain at Eastern Energy, a $93 million gross receipts tax recovery at Eletropaulo and Tiete and $25 million from favorable legal settlements totaling $25 million at Eletropaulo and Red Oak in New Jersey. Other income of $116 million for the year ended December 31, 2006 included debt retirement gains at several of our businesses in Latin America.

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DECEMBER 31, 2008, 2007, AND 2006

18. OTHER INCOME AND EXPENSE (Continued)

        The components of other expense are summarized as follows:

        Other expense primarily includes losses on asset sales and extinguishment of liabilities, charges from legal disputes, mark to market adjustments on commodity derivatives and losses from other miscellaneous transactions. Other expense of $163 million for the year ended December 31, 2008 included $69 million of losses on the retirement of debt at the Parent Company in connection with the refinancing in June 2008, as further discussed in Note 10—Long Term Debt, and IPALCO associated with a $375 million refinancing in April 2008, and losses on disposal of assets primarily at Eletropaulo in Brazil. Other expense of $255 million for the year ended December 31, 2007 included a loss of $90 million on the retirement of senior secured notes at the Parent Company, a $28 million increase in legal reserves in Kazakhstan and losses on the sale and disposal of assets at Eletropaulo and Sul. Other expense of $451 million for the year ended December 31, 2006 included losses on the early extinguishment of debt at several of our Latin American businesses and a loss of $37 million on the retirement of debt at the Parent Company. Other expense also included special obligation charges and a provision for recoverability of regulatory assets at Eletropaulo.

19. IMPAIRMENT EXPENSE

        Impairment expense for the years ended December 31, 2008, 2007 and 2006 consisted of:

        In the fourth quarter of 2008 and in response to the financial market crisis, the Company reviewed and prioritized projects in the development pipeline. From this review, the Company determined that

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DECEMBER 31, 2008, 2007, AND 2006

19. IMPAIRMENT EXPENSE (Continued)

the carrying value exceeded the future discounted cash flows for certain projects. In accordance with SFAS No. 144, the Company recorded a total pre-tax impairment charge of $75 million ($34 million, net of minority interest and income taxes) related to two liquefied natural gas projects in North America and a non-power development project at one of our facilities in North America. These projects were reported in the North America Generation segment.

        Following an initial impairment charge in the fourth quarter of 2007 at Uruguaiana, there were impairment charges of $36 million recognized during the first three quarters of 2008. The impairment was triggered by a combination of gas curtailments and increases in the spot market price of energy in 2007 that continued in 2008. The additional impairment charges in 2008 were primarily due to fixed asset purchase agreements in place. Uruguaiana is a thermoelectric generation plant located in Brazil and reported in the Latin America Generation segment.

        The Company recognized impairment charges totaling $31 million related to a project in South Africa the Company withdrew from during the first quarter of 2008. These represented project development costs and an impairment of turbine deposits related to the project. All costs capitalized and incurred on the project have been written off as no future benefit is expected from these assets. This project was reported in the Europe & Africa Generation segment.

        The Anhui Development and Reform commission issued notice to our Hefei plant in China, in March 2007 as a result of the 2007 State Council's decision to shut down smaller, inefficient and potentially polluting generation units nationwide. A settlement agreement was signed March 30, 2008 to end the contractual PPA arrangement. In accordance with SFAS No. 144, management concluded that the assets were impaired in March 2008, since the long-lived asset group would be sold or otherwise disposed of significantly before the end of its previously estimated life. As a result, impairment charges of $18 million were recognized associated with the settlement agreement to shut down the Hefei plant, which is reported in the Asia Generation segment.

        During the fourth quarter of 2007, the combination of gas curtailments and increases in the spot market price of energy triggered an impairment analysis of Uruguaiana's long-lived assets for recoverability. Based on the accounting guidance provided by SFAS No. 144, management concluded that an impairment occurred during fourth quarter 2007 due to the carrying amount of its long-lived asset exceeding its fair value. The expected present value of future cash flows was used to estimate fair value. As a result of this impairment analysis, a pre-tax impairment charge of $352 million was recognized which represents a full impairment of the fixed assets. Uruguaiana is a thermoelectric plant located in Brazil and is reported in the Latin America Generation segment.

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DECEMBER 31, 2008, 2007, AND 2006

19. IMPAIRMENT EXPENSE (Continued)

        In August 2007, Placerita, a gas-fired combined cycle generation plant located in the United States, sustained property damage to the compressor section in one of its gas turbines. This event triggered an impairment analysis of the plant's long-lived assets, which resulted in a pre-tax impairment charge of approximately $25 million, which represents the net book value of the plant. It was determined that no future net cash flows would be received from the use of this long-lived asset and it was fully impaired. Placerita is reported in the North America Generation segment.

        In May 2006, AES advanced AgCert, a United Kingdom based corporation that produces emission reduction credits, cash of $52 million. AES recognized this prepayment as a long-term asset as consideration for future CER credits and AgCert stock warrants. The asset is revalued each period based on current exchange rates. In the fourth quarter of 2007, AgCert notified AES that it was not able to meet its contractual obligations to deliver CERs, which triggered an analysis of the asset's recoverability. AgCert's financial information indicated a significant decrease in liquidity. As a result of the decline in liquidity and AgCert's inability to fulfill its contractual obligations for future delivery of the CERs, the Company recognized a pre-tax impairment charge of $14 million using the net present value of forecasted operations. This investment and long-term asset are reported in the Corporate and Other segment.

        During the third quarter of 2007, AES made a decision to curtail operations at Coal Creek Minerals, LLC ("Coal Creek"), a coal mining company, due to its inability to meet expected financial projections. The abandonment of Coal Creek triggered an impairment analysis of its long-lived assets, which resulted in a pre-tax impairment charge of approximately $10 million. The fair market value for fixed assets was estimated by evaluating the probability of all assets to be sold and the most recent sale price attributed to other assets recently sold. Coal Creek is owned by one of our subsidiaries, Cavanal Minerals, which is reported in the North America Generation segment.

        During the fourth quarter of 2006, as a result of performing the annual goodwill impairment analysis of AES China Generating Co. Ltd ("Chigen") in accordance with SFAS No. 142, a potential impairment of its equity investment in Wuhu, a coal-fired plant located in China, was identified. As part of the subsequent impairment analysis, the fair value of this investment was analyzed and determined to be less than the carrying value, resulting in a pre-tax impairment charge of $6 million. Chigen is reported in the Asia Generation segment.

        In June 2006, AES recognized a pre-tax impairment charge of $5 million related to five gas turbines that were classified as held for sale at Itabo. The impairment loss was recognized based on bids received from potential buyers that indicated the market value of the turbines was lower than the carrying value. Itabo is included in the results of the Latin America Generation segment. AES began consolidating Itabo subsequent to its purchase of an additional ownership interest in May 2006.

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DECEMBER 31, 2008, 2007, AND 2006

20. INCOME TAXES

INCOME TAX PROVISION

        The following table summarizes the expense for income taxes on continuing operations, for the years ended December 31, 2008, 2007 and 2006:

EFFECTIVE AND STATUTORY RATE RECONCILIATION

        The following table summarizes 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 for the years ended December 31, 2008, 2007 and 2006:

        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.

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DECEMBER 31, 2008, 2007, AND 2006

20. INCOME TAXES (Continued)

        As of December 31, 2008, the Company had federal net operating loss carry forwards for tax purposes of approximately $1.6 billion which expire from 2020 to 2027. Approximately $68 million of the net operating loss carry forward relates to stock option deductions and will be recorded to additional paid-in capital when realized. The Company also had federal general business tax credit carry forwards for tax purposes of approximately $18 million expiring primarily from 2021 to 2028, and federal alternative minimum tax credits of approximately $15 million that carry forward without expiration. The Company had state net operating loss carry forwards as of December 31, 2008 of approximately $3.0 billion expiring in years 2012 to 2028. The Company also has federal and state net operating loss carry forwards of $315 million expiring from 2025 to 2026 for a U.S. entity that is not included in its U.S. consolidated tax group. As of December 31, 2008, the Company had foreign net operating loss carry forwards of approximately $2.8 billion that expire at various times beginning in 2009 and some of which carry forward without expiration, and tax credits available in foreign jurisdictions of approximately $37 million, $5 million of which expire in 2009 to 2011, $21 million of which expire in 2012 to 2019 and $11 million of which carry forward without expiration.

        The valuation allowance decreased by $210 million during 2008 to $1.4 billion at December 31, 2008. This net decrease was primarily the result of decreases in deferred tax assets at certain Brazilian subsidiaries that required corresponding decreases in the valuation allowances.

        The valuation allowance increased by $178 million during 2007 to $1.6 billion at December 31, 2007. This net increase was primarily the result of increases in deferred tax assets at certain Brazilian subsidiaries that required corresponding increases in the valuation allowances.

        The valuation allowance decreased by $50 million during 2006 to $1.4 billion at December 31, 2006. This net decrease was primarily the result of the removal of valuation allowance against deferred tax assets at foreign subsidiaries.

        The Company believes that it is more likely than not that the remaining deferred tax assets as shown below will be realized when future taxable income is generated through the reversal of existing taxable temporary differences and income that is expected to be generated by businesses that have long-term contracts or a history of generating taxable income. The Company is monitoring the utilization of its deferred tax asset for its U.S. consolidated net operating loss carryforward. Although management believes it is more likely than not that this deferred tax asset will be realized through generation of sufficient taxable income prior to expiration of the loss carry forwards, such realization is not assured.

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DECEMBER 31, 2008, 2007, AND 2006

20. INCOME TAXES (Continued)

        The following table summarizes the deferred tax assets and liabilities, as of December 31, 2008 and 2007:

        The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested outside of the United States and, accordingly, no U.S. deferred taxes have been recorded with respect to such earnings as allowed under APB No. 23, Accounting for Income Taxes—Special Areas. 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 Company's income tax benefits related to the tax status of these operations are estimated to be $46 million, $56 million and $42 million for the years ended December 31, 2008, 2007 and 2006, respectively.

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DECEMBER 31, 2008, 2007, AND 2006

20. INCOME TAXES (Continued)

        The following table summarizes the income (loss) from continuing operations, before income taxes, net equity in earnings of affiliates and minority interest, for the years ended December 31, 2008, 2007 and 2006:

        In the third and fourth quarters of 2008, the Company implemented a planning strategy at Termoelectricia del Golfo and Termoelectrica del Peñoles, respectively. This strategy resulted in a deferred tax benefit of approximately $47 million. The benefit is a partial reversal of a $52 million deferred tax charge that was recorded in the fourth quarter of 2007 for the Mexican law change that established the Flat Rate Business Tax ("IETU").

UNCERTAIN TAX POSITIONS

        Uncertain tax positions have been classified as non-current income tax liabilities unless expected to be paid in one year. The Company's policy for interest and penalties related to income tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

        As of December 31, 2008 and 2007, the total amount of gross accrued income tax related interest included in the Consolidated Balance Sheets was $25 million and $29 million, respectively. The total amount of gross accrued income tax related penalties included in the Consolidated Balance Sheet as of December 31, 2008 and 2007 was $5 million and $8 million, respectively.

        The total expense for interest related to unrecognized tax benefits for the years ended December 31, 2008 and 2007 amounted to $2 million and $15 million, respectively. For the years ended December 31, 2008 and 2007, the total (benefit) expense for penalties related to unrecognized tax benefits amounted to $(2) million and $4 million, respectively.

        We are potentially subject to income tax audits in numerous jurisdictions in the U.S. and internationally until the applicable statute of limitation expires. Tax audits by their nature are often

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20. INCOME TAXES (Continued)

complex and can require several years to complete. The following is a summary of tax years potentially subject to examination in the significant tax and business jurisdictions in which we operate:

        As of December 31, 2008 and 2007, the total amount of unrecognized tax benefits was $555 million and $590 million, respectively. The total amount of unrecognized tax benefits that would benefit the effective tax rate as of December 31, 2008 and 2007 is $527 million and $533 million, respectively, of which $131 million and $144 million, respectively, would be in the form of tax attributes that would attract a full valuation allowance.

        The total amount of unrecognized tax benefits anticipated to result in a net decrease of unrecognized tax benefits within 12 months of December 31, 2008 is estimated to be between $20 million and $27 million. The estimated decrease is primarily due to anticipated audit closures, other tax payments and lapses in statutes of limitations.

        The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2008 and 2007:

        The Company and certain of its subsidiaries are currently under examination by the relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the amount of unrecognized tax benefit recorded. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe we have appropriately accrued for our uncertain tax benefits. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits and the range of anticipated increases or decreases in unrecognized tax benefits are subject to significant uncertainty. It is possible

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20. INCOME TAXES (Continued)

that the ultimate outcome of current or future examinations may exceed current unrecognized tax benefits in amounts that could be material, but cannot be estimated as of December 31, 2008. Our effective tax rate and net income in any given future period could therefore be materially impacted.

21. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

        The following table summarizes the income (loss) on disposal and impairment for the following discontinued operations for the years ended December 31, 2008, 2007 and 2006:

        In December 2008, the Company reached an agreement to sell its 70% equity interest in Jiaozuo AES Wanfang Power Co., Ltd. ("Jiaozuo"), which is reported in the Asia Generation segment, for approximately $73 million net of any withholding taxes. The AES Board of Directors approved the sale of Jiaozuo which closed on December 15, 2008 and the Company recognized a gain on the sale of approximately $7 million. Goodwill of $4 million was written off in connection with the gain on sale. This gain is included in the 2008 Gain (loss) from disposal of discontinued businesses line item on the consolidated Statement of Operations for the year ended December 31, 2008.

        On February 22, 2007, the Company entered into a definitive agreement with Petróleos de Venezuela, S.A., ("PDVSA") to sell all of its shares of EDC, a distribution business reported in the Latin America Utilities segment, for $739 million net of any withholding taxes. In addition, the agreement provided for the payment of a $120 million dividend in 2007 which was declared on March 1, 2007 payable to the EDC shareholders of record as of March 9, 2007. A wholly-owned subsidiary of the Company was the owner of 82.14% of the outstanding shares of EDC, and therefore, on May 31, 2007, received approximately $97 million in dividends (representing approximately $99 million in gross dividends offset by fees). The sale of EDC and the payment of the purchase price occurred on May 16, 2007. EDC is classified as "discontinued operations" and reflected as such on the face of the Consolidated Financial Statements for all periods presented. During the first quarter of 2007, the Company recognized an impairment charge of approximately $638 million related to this sale. As a result of the final disposition of EDC in May 2007, the Company recognized an additional impairment charge of approximately $42 million, net of income and withholding taxes. The total impairment charge of $680 million represented the net book value of the Company's investment in EDC less the selling price. The Company impaired the carrying value of EDC's electric generation and distribution assets to their net realizable value. The impairment expense was included in the loss from disposal of discontinued businesses line item on the Consolidated Statement of Operations for the year ended December 31, 2007.

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DECEMBER 31, 2008, 2007, AND 2006

21. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES (Continued)

        In July 2007, the Company's wholly-owned subsidiary, Central Valley, sold 100% of its indirect interest in two biomass fired power plants located in central California (the 50 MW Delano facility and the 25 MW Mendota facility) for $51 million. These facilities, along with an associated management company (together, the "Central Valley Businesses") were included in the North America Generation segment. Central Valley is classified as "discontinued operations" in the Company's Consolidated Financial Statements for all periods presented. The Company recognized a gain on the sale of approximately $20 million net of income and withholding taxes.

        In May 2006, the Company reached an agreement to sell 100% of its interest in Eden, a Latin America utility business located in Argentina. Therefore, Eden a wholly-owned subsidiary of AES, was classified as "held for sale" and reflected as such on the Consolidated Financial Statements. In 2006, the Company recognized a $62 million impairment charge to adjust the carrying value of Eden's assets to their estimated net realizable value. The impairment expense is included in the 2006 loss from disposal of discontinued businesses line item on the financial statements for the year ended December 31, 2007. The Buenos Aires Province in Argentina approved the transaction in May 2007.

        In September 2006, the Company completed the sale of AES Indian Queens Power Limited and AES Indian Queens Operations Limited, collectively "IQP", which was part of the Europe & Africa Generation segment. IQP is an Open Cycle Gas Turbine, located in the U.K. Proceeds from the sale were $28 million in cash and the buyer assumed $30 million of IQP's debt. The Company recognized a gain on disposal of discontinued businesses of $5 million in 2006. The results of operations of IQP and the associated gain on disposal are reflected in the discontinued operations line items on the Consolidated Financial Statements.

        Information for business components included in discontinued operations is as follows:

        As further discussed in Note 22—Acquisitions and Dispositions, in February 2008, the Company entered into an agreement to sell two of its wholly-owned subsidiaries in Kazakhstan, AES Ekibastuz LLP ("Ekibastuz") and Maikuben West LLP ("Maikuben"). These businesses are included in the Europe & Africa Generation segment. Total consideration for the transaction was approximately $1.1 billion with potential earn-out provisions up to an additional $381 million that may be awarded over a three-year period. These businesses generated total revenues of $114 million, $106 million, and $78 million, and net income (loss) of $61 million, $(35) million, and $(47) million for the years ended December 31, 2008, 2007 and 2006, respectively, excluding intercompany transactions. The assets and liabilities of these businesses were reclassified to "held for sale" on the Consolidated

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THE AES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

21. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES (Continued)

Balance Sheets for all periods presented prior to the completion of the sale on May 30, 2008. As a result of AES's continuing involvement in the management and operations of the businesses after the sale was completed, their results of operations continued to be reflected as part of income from continuing operations for all periods presented. Revenue recognized subsequent to the sale represented the management fees earned for the Company's continued management of the operations of the businesses.

22. ACQUISITIONS AND DISPOSITIONS

Acquisitions

        In April 2008, the Company completed the purchase of a 92% interest in a 660 gross MW coal-fired thermal power generation facility in Masinloc, Philippines ("Masinloc") from the Power Sector Assets & Liabilities Management Corporation, a state enterprise, for $930 million in cash. Project financing of $665 million was obtained from International Finance Corporation ("IFC"), the Asian Development Bank and a consortium of commercial banks. IFC is also an 8% minority shareholder in Masinloc. AES immediately embarked upon a comprehensive rehabilitation program to improve the output, reliability and general condition of the plant. Environmental clean-up costs have been estimated pending a detailed study. Including transaction costs and completion of the planned upgrade program to improve environmental and operational performance, the total project cost is estimated to be $1.1 billion. Beginning on the acquisition date in April 2008, the results of operations of Masinloc are reflected in the Consolidated Financial Statements. The Company finalized the purchase price allocation of this acquisition in the fourth quarter of 2008.

Dispositions

        On May 30, 2008, the Company completed the sale of two of its wholly-owned subsidiaries in Kazakhstan, Ekibastuz, a coal-fired generation plant, and Maikuben, a coal mine. Total consideration received in the transaction was approximately $1.1 billion with additional potential earn-out provisions, a three-year management fee arrangement and a capital expenditures program bonus of up to approximately $380 million. The earn-out bonus for 2008 is primarily based on EBITDA, a non-GAAP measure, and the calculation is currently being finalized. If the business meets the EBITDA threshold, the earn-out bonus could range from $60 million to $105 million depending on EBITDA. If the business does not meet the minimum EBITDA threshold, no earn-out bonus is paid. No earn-out provision has been recognized as of December 31, 2008, as the Company has not completed discussions with the counterparty relative to the calculation to permit recognition under U.S. GAAP. The earn-out will be recognized when it becomes determinable and probable.

        As a result of AES's continuing involvement in the management and operations of the businesses through its three-year management and operation agreement, the results of operations from Ekibastuz and Maikuben were included in income from continuing operations through the disposition date. Income earned as a result of the three-year management and operation agreement was recognized as management fee income for all periods subsequent to the disposition. The management fee income earned for the year ended December 31, 2008 was $12 million and is included as revenue in the Europe & Africa Generation segment. A portion of the sale proceeds was used to pay down recourse debt as discussed in Note 10—Long-Term Debt. The Company plans to use the remaining proceeds

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THE AES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

22. ACQUISITIONS AND DISPOSITIONS (Continued)

from the sale of these businesses to fund operations, invest in growth initiatives, or to pay down additional debt. Excluding income earned under the three-year management and operation agreement subsequent to the sale of the business in May 2008, Ekibastuz and Maikuben generated revenue of $114 million, $106 million and $78 million for the years ended December 31, 2008, 2007 and 2006, respectively.

23. 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. 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.

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

        The calculation of diluted earnings per share excluded 11,150,853, 5,740,727 and 5,164,492 options outstanding at December 31, 2008, 2007 and 2006, respectively, that could potentially dilute basic earnings per share in the future. Those options were not included in the computation of diluted earnings per share because the exercise price of those options exceeded the average market price during the related period. In 2008, all convertible debentures were included in the earnings per share calculation. In 2007 and 2006, all convertible debentures were omitted from the earnings per share calculation because they were antidilutive.

24. RISKS AND UNCERTAINTIES

        AES is a global power producer in 29 countries on five continents. See additional discussion of the Company's principal markets in Note 15—Segment and Geographic Information. Our principal lines of business are Generation and Utilities. The Generation line of business uses a wide range of technologies, including coal, gas, hydroelectric, and biomass as fuel to generate electricity. Our Utilities business is comprised of businesses that transmit, distribute, and in certain circumstances generate power. In addition, the Company continues to expand our reach into the renewables area. These efforts include projects primarily in wind and solar.

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THE AES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

24. RISKS AND UNCERTAINTIES (Continued)

        AES is a global power producer in 29 countries on five continents. See additional discussion of the Company's principal markets in Note 15—Segment and Geographic Information. Our principal lines of business are Generation and Utilities. The Generation line of business uses a wide range of technologies, including coal, gas, hydroelectric, and biomass as fuel to generate electricity. Our Utilities business is comprised of businesses that transmit, distribute, and in certain circumstances generate power. In addition, the Company continues to expand our reach into the renewables area. These efforts include projects primarily in wind and solar.

        POLITICAL AND ECONOMIC RISKS—The Company's market capitalization has been negatively impacted largely in the second half of 2008. During this period, credit markets and global markets deteriorated and experienced increased market volatility, which can pose risks to the overall liquidity of our businesses with heightened unpredictability in currencies, counterparty credit risk and the widening of credit spreads in certain markets. If market conditions are protracted or continue to deteriorate, the Company may be at risk to decreased earnings and cash flows due to, among other factors, adverse fluctuations in the commodities and foreign currency spot markets or deterioration in global macroeconomic conditions. With the tightening of the credit markets, there is a risk that future investments may not be able to be financed through accessing capital and debt markets and may be subject to restrictions in the near future. Currently, the Company has a below-investment grade rating from Standard & Poor's of BBB-. This may limit the ability of the Company to finance new and existing development projects to cash currently available on hand and through reinvestment of earnings. As of December 31, 2008, the Company had $903 million of unrestricted cash available. As a result of the impact of the 2008 credit market environment, the Company has evaluated current development projects in the pipeline to assess their future profitability. Impairment expense was recognized in the fourth quarter of 2008 related to these development projects in the pipeline that the Company considered to be impaired or for which they decided to cease future development efforts. These impairment charges represented a net $34 million impact on the Company's earnings, but impairments may continue or could increase in the future if the credit market continues to worsen.

        During 2008, approximately 83% of our revenue, and all of our revenue from discontinued businesses, was generated outside the United States and a significant portion of our international operations is conducted in developing countries. While our growth strategy has evolved as 2008 has progressed, to a focus on targeted projects in order to maintain our liquidity, we continue to invest in projects in developing countries because the growth rates and the opportunity to implement operating improvements and achieve higher operating margins may be greater than those typically achievable in more developed countries. International operations, particularly the operation, financing and development of projects in developing countries, entail significant risks and uncertainties, including, without limitation:

•

economic, social and political instability in any particular country or region;



•

adverse changes in currency exchange rates;



•

government restrictions on converting currencies or repatriating funds;



•

unexpected changes in foreign laws and regulations or in trade, monetary or fiscal policies;



•

high inflation and monetary fluctuations;

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THE AES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

24. RISKS AND UNCERTAINTIES (Continued)

•

restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;



•

threatened or consummated expropriation or nationalization of our assets by foreign governments;



•

unwillingness of governments, government agencies or similar organizations to honor their contracts;



•

inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;



•

adverse changes in government tax policy;



•

difficulties in enforcing our contractual rights or enforcing judgments or obtaining a just result in local jurisdictions; and



•

potentially adverse tax consequences of operating in multiple jurisdictions.

        Any of these factors, individually or in combination with others, could materially and adversely affect our business, results of operations and financial condition. In addition, our Latin American operations experience volatility in revenues and earnings which have caused and are expected to cause significant volatility in our results of operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability and currency devaluations being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these businesses.

        Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including any inability to obtain expected or contracted increases in electricity tariff rates or tariff adjustments for increased expenses, could adversely impact our results of operations or our ability to meet publicly announced projections or analyst's expectations. Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions in jurisdictions where we operate, particularly our Utilities where electricity tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:

•

changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs;



•

changes in the definition or determination of controllable or non-controllable costs;



•

changes in the definition of events which may or may not qualify as changes in economic equilibrium;



•

changes in the timing of tariff increases;



•

other changes in the regulatory determinations under the relevant concessions; or



•

changes in environmental regulations, including regulations relating to GHG emissions in any of our businesses.

        Any of the above events may result in lower margins for the affected businesses, which can adversely affect our business.

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THE AES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

24. RISKS AND UNCERTAINTIES (Continued)

        RISKS RELATED TO FOREIGN CURRENCIES—AES operates businesses in many foreign environments and such operations in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. The Company's financial position and results of operations have been significantly affected by fluctuations in the value of the Brazilian real, the Argentine peso, the Dominican Republic peso, the Euro, the Chilean peso, the Colombian peso and the Philippine peso relative to the U.S. Dollar.

        RISKS RELATED TO POWER SALES CONTRACTS—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 the power sales contracts related to the Company's power plants range from less than one to 41 years. No single customer accounted for 10% or more of total revenues in 2008, 2007, or 2006.

        The cash flows and results of operations of such plants are dependent on the credit quality of the purchasers and the continued ability of their customers and suppliers to meet their obligations under the relevant power sales contract. 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. 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.

25. OFF-BALANCE SHEET ARRANGEMENTS AND RELATED PARTY TRANSACTIONS

        IPL, a consolidated 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. IPL Funding is consolidated by IPL and 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. During 2008, this agreement was extended through May 26, 2009. Accounts receivable on the Company's Consolidated Balance Sheets are stated net of the $50 million sold.

        IPL retains servicing responsibilities for its role as a collection agent on the amounts due on the sold receivables. However, the Purchasers assume the risk of collection on the purchased receivables without recourse to IPL in the event of a loss. While no direct recourse to IPL exists, it risks loss in the event collections are not sufficient to allow for full recovery of its retained interests. No servicing asset or liability is recognized since the servicing fee paid to IPL approximates a market rate.

        The carrying values of the retained interest is determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value. The key assumptions in estimating fair value are credit losses, the selection of discount rates, and expected receivables turnover rate. As a result of short accounts receivable turnover period and historically low credit losses, the impact of these assumptions has not been significant to the fair value. The hypothetical effect on the fair value of the retained interests assuming both a 10% and a 20%

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THE AES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

25. OFF-BALANCE SHEET ARRANGEMENTS AND RELATED PARTY TRANSACTIONS (Continued)

unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history.

        The losses recognized on the sales of receivables were $2 million, $3 million and $3 million for the years ended December 31, 2008, 2007 and 2006, respectively. These losses are included in other operating expense on the Consolidated Statements of Operations. The amount of the losses recognized depends on the previous carrying amount of the financial assets involved in the transfer, allocated between the assets sold and the interests that continue to be held by the transferor based on their relative fair value at the date of transfer, and the proceeds received.

        IPL's retained interest in the receivables sold was $83 million and $64 million at December 31, 2008 and 2007, respectively. There were no proceeds from new securitizations for each of the years ended December 31, 2008, 2007 and 2006. Servicing fees of $0.6 million were received for each of the years ended December 31, 2008, 2007 and 2006.

        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 purchase facility, subject to certain limitations as defined in the Purchase Facility.

        Under the Purchase Facility, 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, 2008, 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. A termination event would also:

(i)

give the facility agent the option to take control of the lock-box account; and



(ii)

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).

        Our Panamanian businesses are partially owned by the Government of Panama (the "Government"). The Government, in turn, partially owns the distribution companies within Panama. For the years ended December 31, 2008, 2007 and 2006, our Panamanian businesses recognized electricity sales to the Government totaling $203 million, $168 million and $141 million, respectively. For the same period, our Panamanian businesses purchased electricity which excludes transmission

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THE AES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

25. OFF-BALANCE SHEET ARRANGEMENTS AND RELATED PARTY TRANSACTIONS (Continued)

charges from the Government totaling $27 million, $24 million and $15 million, respectively. As of December 31, 2008 and 2007, our Panamanian businesses owed the Government $2 million and $3 million, respectively, payable on normal trade terms. For the same period, the Government owed our Panamanian businesses $29 million and $44 million, respectively, payable on normal trade terms.

26. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly Financial Data

        The following tables summarize the unaudited quarterly statements of operations for the Company for 2008 and 2007. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for interim periods.

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THE AES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008, 2007, AND 2006

26. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (Continued)

27. SUBSEQUENT EVENTS

        On December 23, 2008, the local Chilean SEC approved Gener's share issuance of approximately 945 million shares at a price of $162.50 Chilean Pesos. The proceeds of the share issuance was $246 million and Gener anticipates using these proceeds for future expansion plans, working capital and other operating needs. The preemptive rights period began on January 7, 2009 remained open for 30 days and closed on February 5, 2009. During the preemptive rights period AES, through its wholly-owned subsidiary, Cachagua, paid $175 million to maintain its current ownership percentage of approximately 70.6%.

        On February 9, 2009, the government of the Dominican Republic, the government-owned power companies and the power companies sector ("generation companies"), signed two Memorandums of Understanding (each an "MOU"). The first MOU provides for the settlement of outstanding 2008 accounts receivables ("2008 A/R") held by the generation companies from distribution companies through the payment of government-issued bonds of which the Company's three generation businesses have been allocated $110 million. This MOU also states that the bonds can be used to offset fiscal taxes, but that element will need to be approved by the National Congress of the Dominican Republic during their first legislative session of 2009. The second MOU acknowledges that the bond payment does not fully satisfy the outstanding 2008 A/R balance. The residual amount outstanding after the bond payment will be fully settled by the distribution companies, within a timeframe to be negotiated in the near future.

        It is AES' intention to accept these bonds as settlement for approximately $110 million of outstanding 2008 A/R, under the assumption that the bonds will have the ability to offset fiscal taxes. The Company's businesses will have approximately $58 million of 2008 A/R outstanding after the bond payment that will be subject to the terms of the second MOU. The intention of the distribution companies is to pay approximately $35 million of these receivables in 2009. Therefore, AES has appropriately reclassified $23 million to long-term receivables on the Company's Consolidated Balance Sheet as of December 31, 2008.

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Change in Independent Registered Public Accounting Firm

        On December 7, 2007, the Company determined that following the completion of the audit for the fiscal year ended December 31, 2007, Deloitte would be dismissed as the Company's independent registered public accounting firm. The Company also appointed Ernst & Young ("E&Y") as its independent registered public accounting firm for the fiscal year ending December 31, 2008. The decision to change accountants was made by the Company's Board and its Financial Audit Committee in a joint meeting held on December 7, 2007.

        Deloitte's audit report dated March 14, 2008 on the Company's consolidated financial statements as of and for the years ended December 31, 2007 and December 31, 2006 included in its Form 10-K filed March 14, 2008 did not contain an adverse opinion or a disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope, or accounting principles, except that the audit report indicated that (i) as discussed in Note 1 to the consolidated financial statements, in 2007 the Company adopted FIN No. 48, Accounting for Uncertainty in Income Taxes; in 2006 the Company adopted SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans; and in 2005 the Company adopted FIN No. 47, Accounting for Conditional Asset Retirement Obligations and (ii) as discussed in Note 1 to the consolidated financial statements, the consolidated financial statements and the financial statement schedules were restated.

        During the years ended December 31, 2006 and December 31, 2007, there were no disagreements with Deloitte on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements, if not resolved to their satisfaction, would have caused Deloitte to make reference to the subject matter of the disagreement in connection with its audit report.

        During the years ended December 31, 2006 and December 31, 2007, there were no reportable events (as defined in Regulation S-K Item 304 (a)(1)(v)), except that as of December 31, 2006 and December 31, 2007, the Company's internal control over financial reporting was not effective due to the existence of material weaknesses as more fully described in the Company's Annual Report on Form 10-K/A for the year ended December 31, 2006 and its Annual Report on Form 10-K for the year ended December 31, 2007, respectively.

        The Company engaged E&Y as its independent registered public accounting firm for the fiscal year ending December 31, 2008. The Company has not consulted with E&Y during its two most recent fiscal years or during any subsequent interim period prior to its appointment as auditor regarding any matters described in Item 304(a)(2)(i) or Item 304(a)(2)(ii) of Regulation S-K.

ITEM 9A.    CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

        The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities and Exchange Act of 1934, as amended (the "Exchange Act"), is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to the chief executive officer ("CEO") and chief financial officer ("CFO"), as appropriate, to allow timely decisions regarding required disclosures.

        The Company carried out the evaluation required by paragraph (b) of the Exchange Act Rules 13a-15 and 15d-15, under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our "disclosure controls and procedures" (as

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defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of December 31, 2008, our disclosure controls and procedures were effective.

Management's Report on Internal Control Over Financial Reporting

        Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:

•

pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;



•

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and



•

provide reasonable assurance that unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements are prevented or detected timely.

        Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.

        Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations ("COSO").

        A material weakness is a deficiency (within the meaning of PCAOB Auditing Standard No. 5), or combination of deficiencies, that result in there being a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

        Management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2008, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which appears herein.

Remediation of Existing Material Weaknesses:

        The following material weaknesses that existed as of December 31, 2007 and were reported in the Company's 2007 Form 10-K filed on March 17, 2008, were remediated as of December 31, 2008:

Lack of Detailed Accounting Records for Certain Holding Companies:

        The Company previously reported that although it believed that it had manual processes in place to capture all material transactions, there remained a risk that due to lack of detailed records for these holding companies, transactions may not be timely captured or evaluated at the appropriate level of detail.

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        The Company designed and implemented new controls to address this material weakness in 2007 and 2008. The completed steps of the remediation plan included the following:

•

outlined a plan to communicate, document and track the formation, liquidation or changes to the Company's legal entities, including distribution of updated policies and procedures and checklists to track these changes;



•

expanded staffing and resources dedicated to the creation and maintenance of legal entity accounting records;



•

created a priority list of legal entities for purposes of establishing comprehensive general ledgers;



•

distributed and implemented updated policies, procedures and checklists to track the formation, liquidation and changes to the Company's legal entities;



•

implemented a consolidation review process for new legal entities;



•

completed the evaluation and review necessary for the establishment of general ledgers for the priority list of legal entities; and



•

provided training to the various corporate and field personnel concerning the maintenance of these legal entities in the Company's accounting databases.

        The Company tested the operating effectiveness of the control steps described above, and concluded that, as of December 31, 2008, this previously reported material weakness has been remediated.

Contract Accounting:

        The Company previously reported it lacked effective controls designed to ensure an adequate analysis and documentation of certain contracts, at inception and upon modification, to allow them to be adequately accounted for in accordance with U.S. GAAP. Certain of our contracts, at inception or upon modification, contain terms that trigger specific accounting treatment related to derivatives, hedges, lease accounting, variable interests and guarantees that our controls had not always effectively identified. These types of interconnections between accounting principles are significant factors that led to contract-related accounting adjustments in the Company's financial statements.

        During the course of remediating this material weakness, the Company developed a remediation plan which included, among other controls, a broad review of contracts by the Company's accounting department so that the Company can identify and properly account for leases, derivatives and hedging activities, variable interests under FIN No. 46(R), Consolidation of Variable Interest Entities and guarantees under FIN No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others—an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34. The completeness of the contract evaluation process is essential to establishing proper contract accounting in conformity with U.S. GAAP.

        The steps related to the remediation plan include the following:

•

engaged outside resources to assist management in refining comprehensive contract review policies and procedures for use by our subsidiaries when evaluating, reviewing and approving contracts that may qualify as derivatives or hedges, that may contain embedded derivatives, that may qualify as leases, or that may contain variable interests or guarantees;



•

developed an automated solution (implemented in February 2007) to collect and consolidate all material contracts at our subsidiaries to assist in the appropriate evaluation and documentation requirements in accordance with U.S. GAAP;



•

provided detailed training to subsidiaries on new policy and procedure guidance related to contract evaluation;

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•

centralized certain hedge assessments and valuations within the Corporate Accounting and Risk Management functions;



•

implemented an integrated automated software system to perform valuations, perform regression testing, document hedge effectiveness, calculate ineffectiveness and maintain a roll-forward of OCI for certain derivative instruments;



•

improved procedures to ensure the submission of contracts and contract modifications for U.S. GAAP evaluation;



•

provided additional training to both finance and non-finance employees who are responsible for hedging activities, development of power purchase agreements and negotiation of significant purchase contracts;



•

hired high level, qualified staff to provide expertise required to evaluate complex transactions and with knowledge and understanding of derivative valuation and hedge activities;



•

improved the review process to evaluate the accuracy of the accounting analysis for new and amended contracts;



•

established improved control procedures to identify variable interest entities for potential consolidation; and



•

performed an assessment of contracts dated prior to the implementation of the above controls (July 1, 2006) relative to the risk of additional errors. All contracts, which included a population of over 450, that were considered to have more than a minimal level of risk, were reviewed and analyzed to determine proper accounting treatment.

        The Company tested the operating effectiveness of the control steps described above, and concluded that, as of December 31, 2008, this previously reported material weakness has been remediated. While the Company believes that it has remediated the material weakness in this area, the Company will continue to evaluate the operating effectiveness of the controls that have been implemented to ensure that processes and procedures are continually enhanced and enforced to ensure timely recording, processing, summarizing and review of all significant contracts and contract modifications. Given the complexity of the industry in which the Company operates and the complexity of accounting assessments in the area of derivatives, hedges, lease accounting, variable interests and guarantees, no system of internal control process or environment will be able to provide absolute assurance that errors in the future will not occur, nor that judgments about accounting conclusions will not evolve over time. However, the Company believes it has established an effective internal control system over its contract accounting process that will allow for timely identification and assessment of potential accounting issues and the proper accounting treatment in the Company's financial statements.

Conclusion

        As evidenced by steps taken to remediate the material weaknesses described above, management has concluded that, as of December 31, 2008, the Company maintained effective internal controls over financial reporting.

Changes in Internal Control:

        During the quarter ended December 31, 2008, there were no significant changes other than those described above in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Board of Directors and Stockholders of The AES Corporation:

        We have audited The AES Corporation's internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The AES Corporation's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting at Item 9A. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, The AES Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of The AES Corporation and its subsidiaries as of December 31, 2008, and the related consolidated statements of operations, stockholders' equity and cash flows for the year then ended of The AES Corporation and our report dated February 26, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

McLean, Virginia
February 26, 2009

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ITEM 9B.    OTHER INFORMATION.

        None.

PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

        The following information is incorporated by reference from the 2009 Proxy Statement, File No. 001-12291, which will be filed on or around March XX, 2009 (the 2009 Proxy Statement):

•

Information regarding the directors required by this item found under the heading Board of Directors



•

Information regarding AES's Code of Ethics found under the heading AES Code of Business Conduct and Corporate Governance Guidelines



•

Information regarding compliance with Section 16 of the Exchange Act required by this item found under the heading Governance Matters—Section 16(a) Beneficial Ownership Reporting Compliance



•

Information regarding AES's Financial Audit Committee found under the heading The Committees of the Board—Financial Audit Committee (the "Audit Committee")

        Certain information regarding executive officers required by this Item is set forth as a supplementary item in Part I hereof (pursuant to Instruction 3 to Item 401(b) of Regulation S-K). The other information required by this Item, to the extent not included above, will be contained in our Proxy Statement for the 2009 Annual Meeting of Shareholders and is hereby incorporated by reference.

ITEM 11.    EXECUTIVE COMPENSATION

        The following information is contained in the 2009 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the heading Compensation Discussion and Analysis and the Compensation Committee Report on Executive Compensation under the heading Report of the Compensation Committee.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

(a)   Security Ownership of Certain Beneficial Owners.

        See the information contained under the caption "Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers" of the Proxy Statement for the 2009 Annual Meeting of Shareholders of the Registrant, which information is incorporated herein by reference.

(b)   Security Ownership of Directors and Executive Officers.

        See the information contained under the caption "Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers" of the Proxy Statement for the 2009 Annual Meeting of Shareholders of the Registrant, which information is incorporated herein by reference.

(c)   Changes in Control.

        None.

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(d)   Securities Authorized for Issuance under Equity Compensation Plans.

        The following table provides information about shares of AES common stock that may be issued under AES's equity compensation plans, as of December 31, 2008:

Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2008)

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⁽¹⁾

The following equity compensation plans have been approved by the Company's Stockholders:

(A)

The LTC Plan was adopted in 2003 and provided for 17,000,000 shares authorized for issuance thereunder. In 2008, an amendment to the Plan to provide an additional 12,000,000 shares was approved by AES' stockholders, bringing the total authorized shares to 29,000,000. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $17.22 (excluding RSU awards), with 13,824,055 shares available for future issuance.

(B)

The AES Corporation 2001 Stock Option Plan adopted in 2001 provided for 15,000,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $14.35, with 847,350 shares available for future issuance.

(C)

The AES Corporation 2001 Plan for Outside Directors adopted in 2001 provided for 2,750,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $8.96, with 2,045,728 shares available for future issuance.

(D)

The AES Corporation Second Amended and Restated Deferred Compensation Plan for Directors provided for 2,000,000 shares authorized for issuance. Column (b) excludes the Director stock units granted thereunder and there are 498,489 shares available for future issuance.

(E)

The AES Corporation Incentive Stock Option Plan adopted in 1991 provided for 57,500,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan included in Column (b) is $36.16. This plan terminated on June 1, 2001, such that no additional grants may be granted under the plan after that date. Any remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future issuance in light of this plan's termination and thus this amount (20,360,792 shares) is not included in Column (c) above.

⁽²⁾

Includes 5,385,976 (3,319,340 of which are vested and 2,066,636 are unvested) shares underlying RSU awards (assuming performance at a maximum level), 381,099 shares underlying Director stock unit awards, and 18,176,981 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 23,944,056 shares.

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⁽³⁾

The AES Corporation 2001 Non-Officer Stock Option Plan (the "2001 Plan") provided for 12,000,000 shares authorized for issuance. The weighted average exercise price of Options outstanding under this plan shown in Column (b) is $13.13, with 1,316,266 shares available for future issuance. This plan is described in the narrative below.

        The 2001 Plan was adopted by the Board on October 18, 2001, and became effective October 25, 2001. The 2001 Plan did not require approval of AES' stockholders under SEC or New York Stock Exchange rules and/or regulations at that time. All employees that are not Officers, Directors or beneficial owners of more than 10% of AES' common stock are eligible to participate in the 2001 Plan. The total aggregate number of shares for which Options can be granted pursuant to the 2001 Plan is 12,000,000. As of December 31, 2008, approximately 4,000 employees held Options under the 2001 Plan. The exercise price of each Option awarded under the 2001 Plan is equal to the fair market value of AES's common stock on the grant date of the Option. Options under the 2001 Plan generally vest as to 50% of their underlying shares on each anniversary of the Option grant date; however, grants dated October 25, 2001 vested in one year. Unless otherwise provided by the Compensation Committee of the Board, upon the death or disability of an employee, or a change of control (as defined therein), all Options granted under the 2001 Plan will become fully vested and exercisable. Unless otherwise provided by the Compensation Committee of the Board, in the event that the employee's employment with the Company terminates for any reason other than death or disability, all Options held by such employee will automatically expire on the earlier of (a) the date the Option would have expired had the employee continued in such employment or (b) 180 days after the date that such employee's employment ceases. The 2001 Plan will expire on October 25, 2011. The Board may amend, modify or terminate the 2001 Plan at any time.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

        The information regarding related party transactions required by this item is included in the 2009 Proxy Statement found under the headings Transactions with Related Persons, Proposal I: Election of Directors and The Committees of the Board are incorporated by reference.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

        The information concerning principal accountant fees and services included in the 2009 Proxy Statement contained under the heading Information Regarding The Independent Registered Public Accounting Firm's Fees, Services and Independence is incorporated by reference.

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)   Financial Statements.

(b)   Exhibits.

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(c)   Schedules.

Schedule I—Condensed Financial Information of Registrant
Schedule II—Valuation and Qualifying Accounts

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SIGNATURES

        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.

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THE AES CORPORATION AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENT SCHEDULES

Schedule I—Condensed Financial Information of Registrant		S-2
Schedule II—Valuation and Qualifying Accounts		S-8

        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.

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THE AES CORPORATION

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT

UNCONSOLIDATED BALANCE SHEETS

(IN MILLIONS)

See Notes to Schedule 1

S-2

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THE AES CORPORATION

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT

STATEMENTS OF UNCONSOLIDATED OPERATIONS

(IN MILLIONS)

See Notes to Schedule 1

S-3

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THE AES CORPORATION

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT

STATEMENTS OF UNCONSOLIDATED CASH FLOWS

(IN MILLIONS)

See Notes to Schedule 1

S-4

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THE AES CORPORATION

SCHEDULE I

NOTES TO SCHEDULE I

1. Application of Significant Accounting Principles

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

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

        Income Taxes—Effective January 1, 2007, the Company adopted the provisions set forth in FIN No. 48, Accounting for Uncertainty in Income Taxes, ("FIN No. 48"). Under FIN No. 48, positions taken on the Company's income tax return which satisfy a more-likely-than-not threshold will be recognized in the financial statements. The unconsolidated income tax expense or benefit computed for the Company in accordance with SFAS 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.

Selected Unconsolidated Balance Sheet Data:

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THE AES CORPORATION

SCHEDULE I

NOTES TO SCHEDULE I

1. Application of Significant Accounting Principles (Continued)

Selected Unconsolidated Operations Data:

2. Notes Payable

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(1)

The first call date represents the date that the Company, at its option, can call the related debt.

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THE AES CORPORATION

SCHEDULE I

NOTES TO SCHEDULE I

2. Notes Payable (Continued)

        FUTURE MATURITIES OF DEBT—Scheduled maturities of total debt for continuing operations at December 31, 2008 are:

3. Dividends from Subsidiaries and Affiliates

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

4. Guarantees and Letters of Credit

        GUARANTEES—In connection with certain of its project financing, acquisition, and power purchase agreements, the Company 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, 2008, by the terms of the agreements, to an aggregate of approximately $411 million representing 34 agreements with individual exposures ranging from less than $1 million up to $53 million.

        LETTERS OF CREDIT—At December 31, 2008, the Company had $207 million in letters of credit outstanding representing 19 agreements with individual exposures ranging from less than $1 million up to $131 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. In 2008, the Company paid letter of credit fees which averaged 3.4% per annum on the outstanding amounts. In addition, the Company had less than $1 million in surety bonds outstanding at December 31, 2008.

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THE AES CORPORATION

SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS

(IN MILLIONS)

S-8

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