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

FORM 10-K


ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2007

-OR-

o
TRANSITION REPORT FILED PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

COMMISSION FILE NUMBER 1-12291

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

Delaware
(State or other jurisdiction of
incorporation or organization)		   54 1163725
(I.R.S. Employer
Identification No.)

4300 Wilson Boulevard Arlington, Virginia
(Address of principal executive offices)
 
22203
(Zip Code)

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

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

Title of Each Class
   Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share   New York Stock Exchange

AES Trust III, $3.375 Trust Convertible Preferred Securities
 
New York Stock Exchange

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 o    No ý

          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.    o

          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):

Large accelerated filer ý   Accelerated filer o   Non-accelerated filer o
 (Do not check if a smaller reporting company)		   Smaller reporting company o

          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 29, 2007, the last business day of the Registrant's most recently completed second fiscal quarter (based on the closing sale price of $21.88 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $14.623 billion.

          The number of shares outstanding of the Registrant's Common Stock, par value $0.01 per share, on March 6, 2008, was 671,261,394.

DOCUMENTS INCORPORATED BY REFERENCE

          (a)     Portions of the 2008 Proxy Statement are incorporated by reference in Part III


EXPLANATORY NOTE

        The accompanying financial statements and management's discussion and analysis of financial condition and results of operations have been restated to reflect the correction of errors that were contained in the Company's 2006 Form 10-K/A filed with the Securities and Exchange Commission ("SEC") on August 7, 2007. The restatement adjustments impact our financial statements included in this Form 10-K as of December 31, 2006 and for the years ended December 31, 2006 and 2005. In addition to the restatement items discussion. The Company has entered into an agreement to sell two indirect wholly-owned subsidiaries with operations in Kazakhstan, AES Ekibastuz LLP and Maikuben West LLP. As required by Statement of Financial Accounting Standard No. 144, Accounting for the Impairment or Disposal of Long Lived Assets ("SFAS No. 144"), presentation of the assets and liabilities of these businesses are classified as held for sale. The combined impact of all restatement adjustments and reclassifications of AES Ekibastuz and Maikuben West to assets held for sale is set forth in the relevant sections of this filing. A discussion of the restatement and the reclassification is set forth in Item 7 Management's Discussion and Analysis—Restatement of Consolidated Financial Statements and Reclassification of Certain Subsidiaries to held for sale.

        The impact of the restatement adjustments was an increase to previously reported income from continuing operations and net income of $41 million and $43 million, respectively, for the year ended December 31, 2006. The impact of the restatement adjustments resulted in a decrease to previously reported income from continuing operations and net income of $37 million and $38 million, respectively, for the year ended December 31, 2005. The restatement adjustments also resulted in an increase to previously reported income from continuing operations and a decrease to net loss of $1 million, $8 million and $9 million, for the three, six and nine months ended March 31, June 30 and September 30, 2007, respectively.


THE AES CORPORATION

FISCAL YEAR 2007 FORM 10-K

TABLE OF CONTENTS

 
   Page
PART I   1
ITEM 1.   BUSINESS   2
  Overview   2
  Segments   6
  Customers   17
  Employees   17
  Executive Officers   17
  How to Contact AES and Sources of Other Information   19
  Regulatory Matters   20
  Subsequent Events   45
ITEM 1A. RISK FACTORS   47
ITEM 1B. UNRESOLVED STAFF COMMENTS   65
ITEM 2.   PROPERTIES   65
ITEM 3.   LEGAL PROCEEDINGS   66
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS   74
PART II   75
ITEM 5.   MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES   75
  Recent Sales of Unregistered Securities   75
  Market Information   75
  Holders   77
  Dividends   78
ITEM 6.   SELECTED FINANCIAL DATA   78
ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   80
  Restatement of Consolidated Financial Statements and Reclassification of Certain Subsidiaries to Held for Sale   80
  Overview of Our Business   85
  2007 Performance Highlights   89
  Consolidated Results of Operations   91
  Critical Accounting Estimates   103
  New Accounting Pronouncements   105
  Capital Resources and Liquidity   106
  Off-Balance Sheet Arrangements   117
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK   119
  Overview Regarding Market Risks   119
  Interest Rate Risks   119
  Foreign Exchange Rate Risk   119
  Commodity Price Risk   119
  Value at Risk   120
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA   122
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE   212
ITEM 9A. CONTROLS AND PROCEDURES   212
ITEM 9B. OTHER INFORMATION   223

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PART III   223
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE   223
ITEM 11. EXECUTIVE COMPENSATION   223
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS   223
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE   224
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES   224
PART IV   225
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES   225
SIGNATURES   231

ii


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:

1

        These factors in addition to other 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.

        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 and in 28 countries, with generation capacity totaling approximately 43,000 Megawatts ("MW") and distribution networks serving over 11 million people as of December 31, 2007. Our global workforce of 28,000 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 more than two decades we have been committed to providing safe and reliable energy.

        We 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.

        We are also developing an Alternative Energy business. Alternative Energy includes strategic initiatives such as wind generation and climate solutions. While alternative energy is not currently

2


material to our results of operations, it is a fast growing part of our business. We have more than 1,000 MW of wind projects in operation and are one of the fastest-growing producers of wind energy in the United States. In the area of climate solutions, we are building a global business for the production and marketing of greenhouse gas emissions offset credits and are currently developing projects in North America, Asia, Europe and Latin America.

        Our business model benefits from a diverse power generation portfolio that is largely contracted, which reduces the risk related to the market prices of electricity and fuel, while our electric utility portfolio consists of businesses in mature markets as well as faster-growing emerging markets. Portfolio management is becoming an increasing area of focus through which we have and will continue to sell or monetize a portion of certain businesses or assets when market values appear attractive. Furthermore, as we continue to expand and grow our business, we will maintain a focus on efforts to improve our business operations and management processes, including our internal controls over financial reporting.

        Our portfolio of power generation facilities employs a broad range of technologies and fuel sources, including coal, gas, fuel oil and renewable sources such as hydroelectric power, wind and biomass. We currently have more than 7,454 MW of hydropower in operation or under development in nine countries. When combined with the facilities employing renewable energy sources in our Alternative Energy business, our facilities generating power from renewable sources represented approximately 20% of our entire portfolio of generation capacity as of December 31, 2007.

        Our goal is to continue building on our traditional lines of business, while expanding into other essential energy-related areas, such as Alternative Energy. As we move into new lines of business, we will leverage the competitive advantages that result from our unique global footprint, local market insights and our operational and business development expertise. We continue to emphasize growth through "greenfield" development, platform expansion, privatization of government-owned assets, and mergers and acquisitions. We see investments with high growth potential as the most significant contributor to long-term shareholder value creation.

Key Business Lines

        AES's primary sources of revenue and gross margin today are from Utilities and Generation. 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 between Generation and Utilities for the years ended December 31, 2007, 2006 and 2005, respectively is shown below.


Revenue

         GRAPHIC

3


Gross Margin

         GRAPHIC

Generation

        We currently own or operate 121 Generation facilities in 26 countries on five continents. We have 12 new Generation facilities under construction. As part of our portfolio management activities, we have entered into an agreement to sell certain businesses in Kazakhstan. We are a major power source in 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. Our Generation business uses a wide range of technologies and fuel types including coal, combined-cycle gas turbines, hydroelectric power and biomass.

        Performance drivers for our Generation businesses include, among other things, plant reliability, fuel costs and fixed-cost management. Growth in Generation 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 2007, approximately 62% 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 that it has negotiated.

        Our Generation businesses with long-term contracts face most of their competition from other utilities and independent power producers 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

4


a fleet of low-cost coal fired plants, we have hedged the majority of our exposure to fuel, energy and emissions pricing for the next several years. Competitive factors for these facilities include price, reliability, operational cost and third party credit requirements.

Utilities

        AES distributes power to over 11 million people in eight countries on five continents and consists primarily of 15 companies owned or operated under management agreements, each of which operate in defined service areas. These businesses have a variety of structures ranging from pure distribution businesses to fully integrated utilities, which generate, transmit and distribute power. Our largest utility, Indianapolis Power & Light ("IPL"), has the exclusive right to provide retail services to approximately 465,000 customers in Indianapolis, Indiana. Eletropaulo Metropolitana Electricidad de São Paulo S.A ("AES Eletropaulo" or "Eletropaulo"), serving the São Paulo, Brazil area for over 100 years, has over five 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 serve more than 80% of the country's electricity customers. In May 2007, we completed the sale of La Electricidad de Caracas ("EDC"), our utility in Venezuela, for US$739 million, net of tax.

        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 participants, some of which have greater financial resources, have been engaged in distribution related businesses for periods longer than we have, 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.

Alternative Energy

        As demand for more sustainable and environmentally friendly sources of energy grows, we continue to invest in Alternative Energy, with a current focus on increasing our wind power capacity and building our climate solutions business for greenhouse gas ("GHG") reduction. Alternative Energy is not currently one of our primary lines of business, but we expect this high growth sector to be a material contributor to our revenue and gross margin in the future. AES entered the wind business in 2005 and today we have ten wind generation facilities with more than 1,000 MW of wind projects in operation. In addition, we are developing GHG reduction projects. Many countries that have approved the Kyoto Protocol are marketing the credits created. AES already operates in 18 of the developing countries that are eligible for these credits, which provides us with a good foundation for this new business.

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:

5

        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 ("MD&A"), and the Consolidated Financial Statements and related notes included elsewhere in this report.

Our Organization

        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. We organize our operations along our two primary lines of business and within four geographic regions: Latin America; North America; Europe & Africa; and, Asia & the Middle East ("Asia").

        We believe 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 so that each region is led by a regional president responsible for managing existing businesses and business development. The regional presidents report to our Chief Operating Officer ("COO"). Our Alternative Energy Group is led by an Executive Vice President that reports to the Chief Executive Officer ("CEO") and is based in Arlington, Virginia. Our Business Excellence Group, led by an Executive Vice President who reports to the COO, supports the regions in areas such as procurement, engineering and construction, safety, environment and information technology. Our global Business Excellence Group is developing processes to foster innovation, share knowledge and improve performance across our businesses. For further information on our management team, see Executive Officers discussion below.

Segments

        The Company currently reports seven operating segments:

        Three regions, North America, Latin America and Europe & Africa, are engaged in both Generation and Utility businesses. Our Asia region only has Generation. Accordingly, these businesses and regions account for seven segments. "Corporate and Other" includes 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; and revenue, development costs and operational costs related to our Alternative Energy business, which is currently not material to our presentation of operating segments.

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Latin America

        Our Latin America operations accounted for 64%, 62% and 61% of consolidated revenues in 2007, 2006, and 2005, respectively. The following table provides highlights of our Latin America operations:

Countries   Argentina, Brazil, Chile, Colombia,
Dominican Republic, El Salvador and Panama


Generation Capacity
 
11,224 GMW

Utilities Penetration
 
8.6 Million customers (48,755 GWh)

Generation Facilities
 
53 (including 5 under construction)

Utilities Businesses
 
9

Key Generation Businesses
 
Gener, Tietê and Alicura

Key Utilities Businesses
 
Eletropaulo, Sul, and Edelap

        The graph below shows the breakdown between our Latin America Generation and Utilities segments as a percentage of total Latin America revenue and as a percentage of total Latin America gross margin for the years ended December 31, 2007, 2006, and 2005. See Note 22—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.

Revenue   Gross Margin

GRAPHIC
 
GRAPHIC

        Latin America Generation.    Our largest generation business in Latin America, AES Tietê ("Tietê"), located in Brazil, represents approximately 21% of the total generation capacity in the state of São Paulo and is the 9th 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 five new generation plants under construction—three coal plants and one hydro plant in Chile and one hydro plant in Panama with a combined generation capacity of 924 MW.

7

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

Business
   Location
   Fuel
   Gross MW
   AES Equity Interest
(Percent, Rounded)
   Year
Acquired or
Began
Operation
Alicura   Argentina   Hydro   1,050   99 % 2000
Central Dique   Argentina   Gas / Diesel   68   51 % 1998
Gener—TermoAndes   Argentina   Gas   643   91 % 2000
Paraná-GT   Argentina   Gas   845   100 % 2001
Quebrada de Ullum(1)   Argentina   Hydro   45   0 % 2004
Rio Juramento—Cabra Corral   Argentina   Hydro   102   98 % 1995
Rio Juramento—El Tunal   Argentina   Hydro   10   98 % 1995
San Juan—Sarmiento   Argentina   Gas   33   98 % 1996
San Juan—Ullum   Argentina   Hydro   45   98 % 1996
San Nicolás   Argentina   Coal / Gas / Oil   675   99 % 1993
Tietê(2)   Brazil   Hydro   2,650   24 % 1999
Uruguaiana   Brazil   Gas   639   46 % 2000
Gener—Electrica de Santiago(3)   Chile   Gas / Oil   479   72 % 2000
Gener—Energía Verde(4)   Chile   Biomass / Diesel   49   80 % 2000
Gener—Gener(5)   Chile   Hydro / Coal / Oil   807   80 % 2000
Gener—Guacolda   Chile   Coal   304   40 % 2000
Gener—Norgener   Chile   Coal / Pet Coke   277   80 % 2000
Chivor   Colombia   Hydro   1,000   91 % 2000
Andres   Dominican Republic   Gas   319   100 % 2003
Itabo(6)   Dominican Republic   Coal / Oil   472   45 % 2000
Los Mina   Dominican Republic   Gas   236   100 % 1997
Bayano   Panama   Hydro   260   49 % 1999
Chiriqui—Esti   Panama   Hydro   120   49 % 2003
Chiriqui—La Estrella   Panama   Hydro   45   49 % 1999
Chiriqui—Los Valles   Panama   Hydro   51   49 % 1999
           
       
            11,224        
           
       
(1)
AES operates this facility through management or operations and maintenance agreements and owns no equity interest in this facility

(2)
Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mog-Guaçu, Nova Avanhandava and Promissão

(3)
Gener—Electrica de Santiago plants: Renca and Nueva Renca

(4)
Gener—Energia Verde Plants: Constitución, Laja and San Francisco de Mostazal

(5)
Gener—Gener plants: Ventanas, Laguna Verde, Laguna Verde Turbogas, Alfalfal, Maitenas, Queltehues, Volcán and Los Vientos. Los Vientos started full commercial operations in January, 2007

(6)
Itabo plants: Itabo, Santo Domingo, Timbegue, Los Mina and Higuamo
Business
   Location
   Fuel
   Gross MW
   AES Equity Interest
(Percent, Rounded)
   Expected
Year of
Commercial
Operation
Guacolda III   Chile   Coal   152   40 % 2009
Guacolda IV   Chile   Coal   152   40 % 2010
Santa Lidia   Chile   Hydro   130   80 % 2008
Ventanas III   Chile   Coal   267   80 % 2010
Changuinola   Panama   Hydro   223   83 % 2011
           
       
            924        
           
       

8

        Latin America Utilities.    Each of our Utilities businesses in Latin America sells electricity under regulated tariff agreements and each has transmission and distribution capabilities but none of them has generation capability. AES Eletropaulo, a consolidated subsidiary of which AES owns 16% and which has served the São Paulo, Brazil area for over 100 years, has over five 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 1 million customers. In May 2007, we sold EDC, our Utility business in Venezuela.

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

Business
   Location
   Approximate
Number of
Customers Served as
of 12/31/2007
   Gigawatt
Hours Sold in
2007
   AES Equity Interest
(Percent, Rounded)
   Year
Acquired
Edelap   Argentina   309,000   2,574   90 % 1998
Edes   Argentina   161,000   802   90 % 1997
Eletropaulo   Brazil   5,652,000   32,616   16 % 1998
Sul   Brazil   1,100,000   7,070   100 % 1997
EDE Este(1)   Dominican Republic   325,000   2,546   —    
CAESS   El Salvador   505,000   1,890   75 % 2000
CLESA   El Salvador   291,000   736   64 % 1998
DEUSEM   El Salvador   59,000   97   74 % 2000
EEO   El Salvador   217,000   424   89 % 2000
       
 
       
        8,619,000   48,755        
       
 
       
(1)
AES operates these facilities through management agreements and owns no equity interest in these businesses

North America

        Our North American operations accounted for 24%, 26% and 26% of consolidated revenues in 2007, 2006 and 2005, respectively. The following table provides highlights of our North America operations:

Countries   U.S., Puerto Rico and Mexico


Generation Capacity
 
9,876 GMW

Utilities Penetration
 
465,000 customers (16,967 GWh)

Generation Facilities
 
20

Utilities Businesses
 
1 Integrated Utility (includes 4 generation plants)

Key Generation Businesses
 
Eastern Energy (NY), Southland and TEG/TEP

Key Utilities Businesses
 
IPL

9

        The graph below shows the breakdown between our North American Generation and Utilities segments as a percentage of total North America revenue and as a percentage of total North American gross margin for the years ended December 31, 2007, 2006, and 2005. See Note 22—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.

Revenue   Gross Margin

GRAPHIC
 
GRAPHIC

        North American Generation.    Approximately 63% 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 plants, ten coal-fired plants, and three petroleum coke-fired plants in Puerto Rico and Mexico. In 2007, AES Eastern Energy, our Generation business in the State of New York was able to capitalize on favorable market conditions of its energy sales in the competitive spot market. Our businesses also generated revenue and gross margin growth from new investments, primarily through the acquisition of Termoelectrica del Golfo ("TEG") and Termoelectrica del Penoles ("TEP").

        AES's operating strategy is to continue to improve availability and lower the operating cost of its base load capacity. AES is committed to providing cleaner forms of reliable energy in the U.S. Since 1999, AES has invested more than $150 million in emissions control projects. In 2006, AES announced plans to invest in technology at AES Westover in New York, which is expected to reduce CO2 emissions by 95%, mercury emissions by 90% and NO2 emissions up to 90% once the project is complete.

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

Business
   Location
   Fuel
   Gross MW
   AES Equity Interest
(Percent, Rounded)
   Year
Acquired or
Began
Operation
Mérida III   Mexico   Gas   484   55 % 2000
Termoelectrica del Golfo (TEG)   Mexico   Pet Coke   230   99 % 2007
Termoelectrica del Peñoles (TEP)   Mexico   Pet Coke   230   99 % 2007
Placerita   USA - CA   Gas   120   100 % 1989
Southland—Alamitos   USA - CA   Gas   2,047   100 % 1998
Southland—Huntington Beach   USA - CA   Gas   904   100 % 1998
Southland—Redondo Beach   USA - CA   Gas   1,376   100 % 1998
Thames   USA - CT   Coal   208   100 % 1990
Hawaii   USA - HI   Coal   203   100 % 1992
Warrior Run   USA - MD   Coal   205   100 % 2000
Red Oak   USA - NJ   Gas   832   100 % 2002
Cayuga   USA - NY   Coal   306   100 % 1999
Greenidge   USA - NY   Coal   161   100 % 1999
Somerset   USA - NY   Coal   675   100 % 1999
Westover   USA - NY   Coal   126   100 % 1999
Shady Point   USA - OK   Coal   320   100 % 1991
Beaver Valley   USA - PA   Coal   125   100 % 1985
Ironwood   USA - PA   Gas   710   100 % 2001
Puerto Rico   USA - PR   Coal   454   100 % 2002
Deepwater   USA - TX   Pet Coke   160   100 % 1986
           
       
            9,876        
           
       

10

        North American 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 is engaged in generating, transmitting, distributing and selling electric energy to approximately 465,000 customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL also owns and operates four generation facilities that provide essentially all of the electricity it distributes. The two largest generating 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 3,699 MW. Over 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 and commercial which made up 44%, 38% and 18% of North America Utilities revenue for 2007.

Business
   Location
   Fuel
   Gross MW
   AES Equity Interest
(Percent, Rounded)
   Year
Acquired or
Began
Operation
IPL(1)   USA - IN   Coal/Gas/Oil   3,699   100 % 2001
(1)
IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg

Business
   Location
   Approximate
Number of
Customers Served as
of 12/31/2007
   Gigawatt
Hours Sold in
2007
   AES Equity Interest
(Percent, Rounded)
   Year
Acquired
IPL   USA - IN   465,000   16,967   100 % 2001

Europe & Africa

        Our operations in Europe & Africa accounted for 12%, 12% and 12% of our consolidated revenues in 2007, 2006 and 2005, respectively. The following table provides highlights of our Europe & Africa operations:

Countries   Cameroon, Czech Republic, Hungary, Kazakhstan, Netherlands, Spain, U.K., Turkey, Ukraine and Nigeria


Generation Capacity
 
11,457 GMW

Utilities Penetration
 
2.4 million customers (12,756 GWh)

Generation Facilities
 
19 (including 4 under construction)

Utilities Facilities
 
3 Utilities including 1 Integrated Utility (includes 11 generation plants)

Key Generation Businesses
 
Ekibastuz and Kilroot

Key Utilities Businesses
 
SONEL, Kyivoblenergo, Rivneenergo

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        The graph below shows the breakdown between our Europe & Africa Generation and Utilities segments as a percentage of total Europe & Africa revenue and as a percentage of total Europe & Africa gross margin for the years ended December 31, 2007, 2006, and 2005. See Note 22—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.

Revenue   Gross Margin

GRAPHIC
 
GRAPHIC

        Europe & Africa Generation.    In 2006, we began commercial operation of AES Cartagena ("Cartagena"), our first power plant in Spain, with 1,200 MW capacity. The results of operations for Cartagena, an unconsolidated entity, are 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. However, we recently announced an agreement to sell two of our facilities in Kazakhstan. As part of this agreement, AES will continue to operate these facilities 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.

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

Business(1)(3)
   Location
   Fuel
   Gross MW
   AES Equity Interest
(Percent, Rounded)
   Year
Acquired or
Began
Operation
Bohemia   Czech Republic   Coal/Biomass   50   100 % 2001
Borsod   Hungary   Biomass/Coal   96   100 % 1996
Tisza II   Hungary   Gas/Oil   900   100 % 1996
Tiszapalkonya   Hungary   Coal/Biomass   116   100 % 1996
Ekibastuz(3)   Kazakhstan   Coal   4,000   100 % 1996
Shulbinsk HPP(2)   Kazakhstan   Hydro   702   —   1997
Sogrinsk CHP   Kazakhstan   Coal   301   100 % 1997
Ust—Kamenogorsk HPP(2)   Kazakhstan   Hydro   331   —   1997
Ust—Kamenogorsk CHP   Kazakhstan   Coal   1,354   100 % 1997
Elsta   Netherlands   Gas   630   50 % 1998
Ebute   Nigeria   Gas   304   95 % 2001
Cartagena   Spain   Gas   1,200   71 % 2006
Girlevik II-Mercan   Turkey   Hydro   12   51 % 2007
Yukari-Mercan   Turkey   Hydro   14   51 % 2007
Kilroot   United Kingdom   Coal / Oil   520   97 % 1992
           
       
            10,530        
           
       
(1)
AES additionally owns and operates the Maikuben West coal mine in Kazakhstan, supplying coal to AES businesses and third parties

(2)
AES operates these facilities through management or operations and concession agreements and owns no equity interest in these businesses

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(3)
AES entered into a stock purchase agreement to sell its indirect wholly-owned subsidiary, Ekibastuz and the Maikuben West coal mine. The transaction is expected to close in the second quarter of 2008.
Business
   Location
   Fuel
   Gross MW
   AES Equity Interest (Percent, Rounded)
   Expected Year of Commercial Operation
I.C. Energy(1)   Turkey   Hydro   63   49 % 2010
Maritza East I   Bulgaria   Lignite   670   100 % 2009
           
       
            733        
           
       
(1)
JV with I.C. Energy. I.C. Energy Plants: Damlapinar Konya, Kepezkaya Konya, and Kumkoy Samsun

        Europe & Africa Utilities.    AES acquired a 56% interest in an integrated utility AES SONEL ("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 and distribution facilities in our Europe & Africa Utilities segment:

Business
   Location
   Fuel
   Gross MW
   AES Equity Interest
(Percent, Rounded)
   Year
Acquired or
Began
Operation
SONEL(1)   Cameroon   Hydro/Diesel/Heavy Fuel Oil   927   56 % 2001
(1)
SONEL plants: Bafoussam, Bassa, Djamboutou, Edéa, Lagdo, Logbaba I, Limbé, Mefou, Oyomabang I, Oyomabang II and Song Loulou, and other small remote network units
Business
   Location
   Approximate
Number of
Customers Served as
of 12/31/2007
   Gigawatt
Hours Sold in
2007
   AES Equity Interest
(Percent, Rounded)
   Year
Acquired
SONEL   Cameroon   571,000   3,360   56 % 2001
Kyivoblenergo   Ukraine   835,000   4,161   89 % 2001
Rivneenergo   Ukraine   405,000   1,791   81 % 2001
Eastern Kazakhstan REC(1)(2)   Kazakhstan   459,000   3,444   —    
Ust-Kamenogorsk Heat Nets(1)(3)   Kazakhstan   96,000   —   —    
       
 
       
        2,366,000   12,756        
       
 
       
(1)
AES operates these facilities through management agreements and owns no equity interest in these businesses

(2)
Shygys Energo Trade, a retail electricity company is 100% owned by 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.

(3)
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 Asian operations accounted for 7%, 7% and 6% of consolidated revenues in 2007, 2006 and 2005, respectively. Asia's Generation business operates 13 power plants with a total capacity of 5,369 MW in six countries and has one power plant under construction. AES only operates generation facilities in Asia. See Note 22—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 for our Asia operations:

Countries   China, Qatar, Pakistan, Oman, India, Sri Lanka and Jordan


Generation Capacity
 
5,369 GMW

Utilities Penetration
 
No Utilities businesses in Asia

Generation Facilities
 
15 (including 2 under construction)

Utilities Facilities
 
No Utilities businesses in Asia

Key Businesses
 
Yangcheng, Pak Gen and Lal Pir

        Asia Generation.    Over half of our facilities and generation capacity in Asia are 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 30% of the country's peak system capacity and 25% of the country's water supply. AES Amman East ("Amman East") is a 370 MW combined-cycle gas power plant under construction in Jordan. Commercial operations are expected to commence in 2009.

        In early February 2008, the Company signed an agreement with National Power Corporation ("NPC"), a state owned utility, to purchase a 600 MW coal-fired generation facility in Masinloc, Philippines for $930 million. The purchase will be primarily financed by non-recourse debt. The 10 year old plant, which is currently partially operational, consists of two turbines; one turbine is currently in working condition while the second turbine will require maintenance to return it to a working condition. The plant will require an additional investment, over the next six to 12 months, to bring it up to the required operational standard. The Masinloc plant is not currently compliant with government mandated environmental regulations. Masinloc will receive permits from the Philippine government to allow for the continued operation of the plant during its environmental clean-up period. The sale is expected to close in April 2008.

14

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

Business
   Location
   Fuel
   Gross MW
   AES Equity Interest
(Percent, Rounded)
   Year
Acquired or
Began
Operation
Aixi   China   Coal   51   71 % 1998
Chengdu   China   Gas   50   35 % 1997
Cili   China   Hydro   26   51 % 1994
Hefei   China   Oil   115   70 % 1997
Jiaozuo   China   Coal   250   70 % 1997
Wuhu   China   Coal   250   25 % 1996
Yangcheng   China   Coal   2,100   25 % 2001
OPGC   India   Coal   420   49 % 1998
Barka   Oman   Gas   456   35 % 2003
Lal Pir   Pakistan   Oil   362   55 % 1997
Pak Gen   Pakistan   Oil   365   55 % 1998
Ras Laffan   Qatar   Gas   756   55 % 2003
Kelanitissa   Sri Lanka   Diesel   168   90 % 2003
           
       
            5,369        
           
       
Business
   Location
   Fuel
   Gross MW
   AES Equity Interest
(Rounded)
   Expected
Year of
Commercial
Operation
Amman East(1)   Jordan   Gas   370   37 % 2009
Huanghua(2)   China   Wind   49.5   49 % 2009
(1)
Construction of the Amman East power plant commenced in May, 2007

(2)
Joint Venture with Guohua Energy Investment Co. Ltd.

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 our Alternative Energy business which is not material to our presentation of reporting segments. See Note 22—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.

15

        Set forth below is a list of our Alternative Energy facilities:

Business
   Location
   Fuel
   Gross MW
   AES Equity Interest
(Percent, Rounded)
   Year
Acquired or
Began
Operation
Altamont   USA - CA   Wind   43   100 % 2005
Palm Springs   USA - CA   Wind   30   100 % 2006
Tehachapi   USA - CA   Wind   58   100 % 2006
Storm Lake II(1)   USA - IA   Wind   80   100 % 2007
Lake Benton I(1)   USA - MN   Wind   107   100 % 2007
Condon(1)   USA - OR   Wind   50   NA (1) 2005
Buffalo Gap I(1)   USA - TX   Wind   121   NA (1) 2006
Buffalo Gap II(1)   USA - TX   Wind   233   NA (1) 2007
InnoVent   France   Wind   4   100 % 2007
Wind generation facilities(2)   USA   Wind   298       2005
           
       
            1,024        
           
       
(1)
AES owns these wind facilities together with third party equity investors with both parties in all project holding variable ownership interests. It also has ownership interests in development-stage companies in Scotland, France and Bulgaria

(2)
AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses
Business
   Location
   Fuel
   Gross MW
   AES Equity Interest
(Percent, Rounded)
   Expected
Year of
Commercial
Operation
Buffalo Gap III   USA - TX   Wind   170   NA   2008

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Financial Data by Country

        The table below presents information about our consolidated operations and long-lived assets, by country, for years ended December 31, 2007 through December 31, 2005 and as of December 31, 2007 and 2006, respectively. Revenues are recognized in the country in which they are earned and assets are recorded in the country in which they are located.

 
   Revenues
   Property, Plant &
Equipment, net
 
   2007
   2006
   2005
   2007
   2006
 
    
   (Restated)

   (Restated)

    
   (Restated)
 
   (in millions)
United States   $ 2,641   $ 2,573   $ 2,271   $ 6,448   $ 5,686
   
 
 
 
 
Non-U.S.                              
Brazil     4,748     4,119     3,792     5,335     4,611
Argentina     678     542     438     450     412
Chile     1,011     594     542     965     812
Dominican Republic     476     357     231     651     653
El Salvador     479     437     375     249     238
Pakistan     396     318     178     265     272
United Kingdom     235     222     208     383     303
Cameroon     330     300     288     504     407
Mexico     399     185     226     838     205
Puerto Rico     245     234     213     620     626
Hungary     344     304     230     240     225
Ukraine     330     269     217     103     106
Qatar     178     169     165     552     578
Colombia     213     184     182     393     398
Panama     175     144     134     582     449
Oman     105     114     113     331     337
Kazakhstan     284     215     158     52     47
Other Non-U.S.      321     296     286     1,059     580
   
 
 
 
 
Total Non-U.S.    $ 10,947   $ 9,003   $ 7,976   $ 13,572   $ 11,259
   
 
 
 
 
Total   $ 13,588   $ 11,576   $ 10,247   $ 20,020   $ 16,945
   
 
 
 
 

Customers

        We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2007 total revenues.

Employees

        As of December 31, 2007 we employed approximately 28,000 people.

Executive Officers

        The following individuals are our executive officers:

        Paul Hanrahan, 50 years old, has been the President and Chief Executive Officer ("CEO") since 2002. Prior to assuming his current position, Mr. Hanrahan was the Chief Operating Officer ("COO") and Executive Vice President. 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

17


has managed other AES businesses in the United States, Europe and Asia. 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.

        David S. Gee, 53 years old, became an Executive Vice President of the Company in 2006 and the Regional President of North America in 2005. Prior to joining the Company in 2004 as Vice President of Strategy, Mr. Gee was Vice President of Strategic Planning for PG&E in San Francisco, California from 2000 until 2005. Mr. Gee was a principal consultant for McKinsey & Co. from 1985 to 2000 in Houston, Mexico City and London. He was also an Associate for Baker Hughes and Booz Allen & Hamilton in Houston, Texas. Mr. Gee has a Bachelor of Science degree in Chemical Engineering from the University of Virginia and a Master of Science degree in Finance from the Sloan School of Management at the Massachusetts Institute of Technology.

        Andres R. Gluski, 50 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 since 2006. Mr. Gluski was Senior Vice President for the Caribbean and Central America from 2003 to 2006, was Group Manager and CEO of EDC (Venezuela) from 2002 to 2003, served as CEO of Gener (Chile) in 2001 and was Executive Vice President of EDC and Corporacion EDC. Prior to joining the Company in 1997, Mr. Gluski was Executive Vice President of Corporate Banking for Banco de Venezuela and Executive Vice President of Finance of CANTV in Venezuela. 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.

        Victoria D. Harker, 43 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 through 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.

        Robert F. Hemphill, Jr., 64 years old, has been an Executive Vice President of the Company since February 2005. Mr. Hemphill served as the Company's Director from June 1996 to February 2005 and was an Executive Vice President from 1982 to June 1996. Prior to this, Mr. Hemphill held various leadership positions since joining the Company in 1982. Mr. Hemphill also serves on the Boards of Altair Nanotechnologies and Phoenix Motorcars International. Mr. Hemphill received a Bachelor of Arts degree in Political Science from Yale University, a Master of Arts in Political Science from the University of California, Los Angeles, and a Masters in Business Administration, Finance from George Washington University.

        Jay L. Kloosterboer, 47 years old, is the Executive Vice President of Business Excellence. Mr. Kloosterboer joined the Company in 2003 as Vice President and Chief Human Resource Officer. Prior to joining the Company, Mr. Kloosterboer held various senior Human Resources positions at Honeywell International from 1996 to 2003. Mr. Kloosterboer also held management positions at General Electric and Morgan Stanley. He received a Bachelor of Arts degree from Marquette University and holds a Master of Arts degree from the New Mexico State University.

        William R. Luraschi, 44 years old, is an Executive Vice President of the Company and President of the Alternative Energy Business. Mr. Luraschi joined the Company in 1993 and has been an Executive Vice President since July 2003. He was the Company's General Counsel from January 1994 until May 2005. Mr. Luraschi also served as Corporate Secretary from February 1996 until June 2002. Prior to joining the Company, he was an attorney with the law firm of Chadbourne & Parke, LLP. Mr. Luraschi received a Bachelor of Science from the University Of Connecticut and holds a Juris Doctorate from Rutgers School of Law.

18

        Brian A. Miller, 42 years old, is an Executive Vice President of the Company, General Counsel and Corporate Secretary. 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.

        John McLaren, 45 years old, is an Executive Vice President of the Company, and Regional President of Europe & 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 2002 to 2003, Project Director from 2000 to 2002, and Business Manager for AES Medway Operations Ltd. from 1997 to 2000. Mr. McLaren joined the Company in 1993. He holds a Masters in Business Administration from the University of Greenwich Business School in London.

        Mark E. Woodruff, 50 years old, is an Executive Vice President of the Company and Regional President of Asia & Middle East. Prior to his current position, Mr. Woodruff was 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.

        Our Chief Executive Officer and our Chief Financial Officer 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 Chief Executive Officer provided a certification pursuant to Section 303A of the New York Stock Exchange Listed Company Manual on July 20, 2007.

        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. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on our website. 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.

        On July 30, 2007, the Company adopted a revised Code of Conduct applicable to all of its directors and employees, including its executive officers. The revised Code of Conduct aligns expectations regarding business conduct with updates to the Company's core values and reaffirms the

19


Company's commitment to doing business with the highest standard of integrity. There are no material substantive changes to the Code of Conduct. The revised Code of Conduct is posted on the Company's website at www.aes.com

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 US 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. The countries where we operate in this type of environment include Nigeria, Oman, Pakistan, Qatar, Sri Lanka and Jordan.

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 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, with the exception of any components that are directly passed through to the customer, which are usually adjusted through an automated process. In many instances, the tariffs can be adjusted between scheduled regulatory resets pursuant to an inflation 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 the most material 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.

20

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.

        Under the New Power Sector Model, every distribution utility is obligated to contract to meet 100% of its anticipated energy requirements over the coming five years in the regulated contractual market, through energy auctions from new proposed generation projects or existing generation facilities. The existing bilateral contracts are being honored, but cannot be renewed.

        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.

        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 operations 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 four 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. The tariff reset methodology will be the subject of a Public Hearing scheduled to take place on February 27, 2008.

        AES businesses in Brazil consists of: two distribution businesses—Eletropaulo, serving over five million customers in the Sao Paulo area, and AES Sul, serving over one million customers in the state of Rio Grande do Sul; and two generation businesses—Tiete, a 2,650 MW hydro-generation facility, and Uruguaiana, a 639 MW generation facility.

        On July 4, 2007, Eletropaulo had its periodic tariff review and reset, which resulted in an average tariff reduction of 8.43%. As part of the tariff reset process, ANEEL recalculated the regulatory return on capital for all of the distribution companies in Brazil based on current Brazilian interest rates, which have decreased since the last reset and a lower country risk. The lower regulatory return was one of the main drivers of the reduction in tariff. The next tariff reset for Sul is scheduled for April 2008.

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        Sul is pursuing the annulment of ANEEL's Order 288, issued on May 16, 2002, in which ANEEL retroactively prohibited several companies, Sul included, the opportunity to choose not to participate in the "exposition relief mechanism," which allowed these companies to sell the energy from Itaipu into the spot market. This lawsuit has a financial impact of about R$437.8 million (historic values referring to 2001 and 2002) or approximately US$248 million as of December 31, 2007. Sul was granted a preliminary injunction ordering ANEEL to review the Brazilian Electric Energy Commercialization Chamber or ("CCEE") registers, calculations and liquidation. This lawsuit awaits the judge's decision regarding either ANEEL's petition to include CCEE as a co-defendant in the lawsuit or ANEEL's compliance with the injunction. If the operations registered in CCEE are cleared with the effect of Order #288 in place, Sul will owe a net amount of approximately R$80 million (historic values referring to 2001) or approximately US$45 million as of December 31, 2007. Sul is current on all CCEE charges and costs incurred subsequent to the period in question in the Order #288 matter. All amounts, including the amount owed to CCEE in the event Sul loses the case, are reserved in Sul's books.

        AES Tietê's concession agreement with the State of Sao Paulo for its generation plant includes an obligation to increase generation capacity by 15% by the end of 2007. AES Tietê, as well as other concessionaire generators, were not able to meet this requirement due to regulatory, environmental and hydrological constraints. The matter is under consideration by the State Government of São Paulo. AES is seeking to resolve the issue through an extension of the deadline or other options. An adverse decision by the regulator could have a negative impact on the value of the plant, but at this time the positions of ANEEL and the State of Sao Paulo are not known.

        Chile.    Chile has four electricity systems. The two major interconnected electricity systems are the Central Interconnected System ("SIC"), covering 92% of the population of the country and 75% of the load, and the Northern Interconnected System ("SING"), covering 6% of the population and 24% of the load.

        Under Chile's Electric Law, the electricity market is 100% privately-owned. The Chilean Ministry of Economy and Energy regulates the granting of concessions to generation companies for hydroelectric facilities and to distribution companies for distribution networks. Concessions are not required for thermoelectric power plants. The National Energy Commission defines energy policy and generally oversees electric regulation. The Superintendency of Electricity and Fuels supervises compliance with quality of service and safety standards. In 2005, an autonomous commission, the Panel of Experts, was established to resolve technical disputes within the electricity sector.

        The Chilean electricity system is principally a contract-based market in which customer demand is supplied through long-term PPAs with generators. The PPAs specify the volume, price and term conditions for the sale of energy and capacity. The Electric Law establishes two types of customers: unregulated customers with demand in excess of 2 MW and regulated customers with demand less than or equal to 2 MW which are usually supplied by distribution companies. Customers with demand between 0.5 MW and 2 MW are allowed to choose either the regulated or unregulated regime every four years. Unregulated customers freely negotiate supply contracts directly with the generators or distribution companies.

        In order to minimize the operational cost of the system, independent load centers dispatch plants on a mandatory basis in order to achieve the lowest cost of production available to meet the level of demand at any given time, constrained to maintain safety and reliability of service. As a result, the electricity systems are intended to be near-perfect markets for the generation of electricity in which the lowest cost producer is used to satisfy demand before the next lowest cost producer is dispatched. As a result, although generation companies freely enter into PPAs with distribution companies and other customers for the sale of capacity and energy, the electricity necessary to fulfill these agreements is provided by the contracting generation company only if the generation company's marginal cost of

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production is low enough for its generating capacity to be dispatched to meet demand. Otherwise, the generation company will purchase electricity from other generation companies at the system marginal cost. The marginal cost of production is the cost of the least expensive next unit required to meet system demand at a given time.

        The cost of investment and operation of transmission systems are borne by generation companies and consumers (regulated tolls), in proportion to their use.

        In May 2005, there was an amendment to the Electric Law designed to provide incentive for future generation projects. In general, the law increased the flexibility of the regulated pricing system to respond to the higher generation cost scenario which resulted from the natural gas curtailments. One of the principal aspects of the law is the gradual replacement of node prices with prices awarded through public bid processes. Under the terms of the amendment, distribution companies are required to hold public bid processes for new supply contracts. Beginning in 2009, these contracts may not exceed 15 years, and will be awarded based on the lowest energy price offered.

        In addition, a procedure was established to govern the situation of distribution companies without contract supply. Law 20,220 ("Ley Tokman") published in the Official Gazette on September 14, 2007, obliges generation companies to continue with the energy supply to distribution companies that lose their contract either due to their bankruptcy, bankruptcy of their supplier, or the anticipated termination of the contract by arbitration award or court's decision. The law states that if a distribution company in that situation is not able to procure a new contract, then all the generation companies should supply to the distribution company at node prices (prices determined by the authority every six months), thereby assuming the costs of spot market prices, which becomes a credit only within a bankruptcy proceeding.

        On July 13, 2004, AES Gener and ESSA filed for arbitration with the International Court of Arbitration against certain Argentine natural gas producers, members of the Sierra Chata Consortium. The main purpose of the lawsuit was that the arbitral court ordered the producers to comply with their contractual obligations, deliver the total concentrated gas and/or to provide compensation for damages incurred by the plaintiffs. The International Court of Arbitration issued its final award on December 19, 2007. The award: (i) rejected the plaintiff's claim; (ii) declared the existence of a force majeure event; and (iii) declared the gas supply agreement terminated and exempted the Parties for any liability thereto.

        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 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 US$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

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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 will be held in May 2008. The closing price of each auction will determine the reliability charge for existing plants.

        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, 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 adopted many new economic measures since 2002. 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 power plants to be installed by 2008/2009. The time period for the funding was set from January 2004 through December 2006 and was subsequently extended through December 2007. 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. 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 and extended the period for that process until December 31, 2007.

        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 went effective in August 2005 and an additional 8% DVA increase became effective in January 2007.

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        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.

        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 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. 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.

        The maximum tariff to be charged by distribution companies to regulated customers is subject to the approval of the 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 the company's distribution businesses. The company has since appealed the new tariff schedule to the El Salvador Supreme Court.

        Currently, the Company faces the following regulatory actions:

        a)    Connection and reconnection charge regulations: The SIGET is currently in the process of approving changes in the methodology used for calculating and applying connection and reconnection charges. It is estimated that the changes being approved could reduce the annual revenues associated with connection and reconnection by as much as 30%.

        b)    Quality of Service ("QoS") regulations: QoS regulations are entering into the permanent application regime. As a result, quality requirements will be higher and enforced to their full extent. In addition, the distribution companies could be required to compensate customers as a result of not meeting the prescribed quality standards.

        Dominican Republic.    The Dominican Republic has one main interconnected system 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 spot market in the Dominican Republic commenced operations in June 2000. All participants in the Dominican electric system with available units are put in order of merit for dispatch based on lowest marginal cost. The order of merit determines the price to be paid for the electricity and the order in which each participant is dispatched. The order of merit is effective for one week. Sector participants may execute private contracts in which they agree to specific energy and capacity transactions.

        The regulatory framework in the Dominican electricity market establishes a methodology for calculating the firm capacity for each power generation unit. A new regulation recently passed by the CNE effectively changes the methodology for calculating firm capacity from a yearly to a monthly basis. While this new methodology has not yet been applied, it is estimated that it would result in a net reduction in the firm capacity payments paid to generators. The Company has sent a proposal to CNE proposing changes to the new firm capacity calculation that would help mitigate the impact of the new regulation.

        The financial and political 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 and 2006, the government has been 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 US$530 million in subsidies from the government to cover current operations. In 2007, the sector needed more than US$630 million and, at current fuel prices, the government has budgeted an amount of US$800 million for 2008.

        In October of 2006, CDEEE (Corporación Dominicana de Empresas Electricas Estatales), the state owned transmission and water company, began making public statements that it intends to seek to compel the renegotiation and/or recission of long-term power purchase agreements 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 owns 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.    Panama has one main interconnected system (the NIS). The National Authority of Public Services regulates power generation, transmission, interconnection and distribution activities in the electric power sector and is responsible for the planning and coordination of the NIS. 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 by the CND, which dispatches electricity from generation plants based on lowest marginal cost.

        In order to mitigate spot market volatility, generators can enter into long-term PPAs with distribution companies and large users. The terms and contents of PPAs are determined through a competitive bidding process. Generators can also enter into reserve supply contracts with each other. Distribution companies are required to contract 100% of their annual energy requirements (although they can self-generate up to 15% of their demand).

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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 an 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"), 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:

        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 are exempt from the PUHCA, and subject to FERC approval, have the right to sell power at market-based rates, either directly to the wholesale market or to a 3rd 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 owns 4 coal-fired generation plants with a combined total capacity of 1,268 MWs 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 transmission system and a Market Services Tariff that describes the rules and conditions of use for the various markets.

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        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/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 MWh.

        In addition to our generation businesses, we also operate 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.

        The IURC sets IPL's retail rates, has approval authority over any proposal to issue either equity or debt instruments, sets the rules and regulations that govern relations between IPL and its customers, prescribes the manner and form of IPL's accounting records, including the fixing of its depreciation rates, has approval authority over any sale, assignment, transfer or lease of IPL's assets, and establishes assigned service areas, within the boundaries of which IPL is authorized to furnish all retail electric service on an exclusive basis.

        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, involve consumer groups and customers. The last general rate case for IPL was completed in 1995. In addition, pursuant to statute, the IURC is required 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 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 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 the nitrogen oxide ("NOx") compliance construction program and its multipollutant plan. 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 fuel 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, or FAC, proceeding that its 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 fuel 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 FAC. Additionally, customer refunds may result if a utility's rolling 12-month operating income, determined at quarterly measurement dates, exceeds a utility'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 three most recently approved FAC filings, the IURC found that IPL's rolling annual net operating income was greater than the authorized annual net operating income by $24.6 million for the twelve months ended October 31, 2007; by $22.5 million for the twelve months ended July 31, 2007; and by $3.8 million for the twelve months ended April 30, 2007. Because IPL has had a cumulative net operating income deficiency, it has not been required to make customer refunds in its FAC proceedings. However, even though IPL has a cumulative net operating income deficiency, the IURC may still review IPL's basic rates and charges on a prospective basis at any time it chooses.

        In December 2007, IPL received a letter from the staff of the IURC requesting information relevant to its periodic review of its basic rates and charges. IPL subsequently provided information to staff and has engaged in discussions with staff on this matter. The IURC staff was concerned that the higher than usual 2007 earnings may continue in the future and IPL is evaluating alternatives for addressing the IURC's concerns. It is not clear what action, if any, the IURC staff will recommend as a result of its periodic review of IPL's basic rates and charges.

        IPL participates in the restructured wholesale energy market operated by the Midwest ISO ("MISO") and under the jurisdiction of the FERC since its implementation April 1, 2004. 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 before the commission, a consumer advocacy group representing some of IPL's industrial customers requested that a sub-docket be established to review MISO fuel cost components and IPL's generation and demand bidding practices. To date, no procedural schedule for this sub-docket has been established, and IPL cannot predict what refunds, if any, may be required, or for what period of time.

        Mexico.    Mexico has for the most part 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 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.

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        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 Merida ("Merida") and Tamuin facilities operate. Merida, a majority owned 484 MW generation business, provides power exclusively to CFE under a long-term contract. Tamuin 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 ("EC"), 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 EC published a proposal for a new common energy policy for Europe. The proposal focuses on consumer choice, fairer prices, cleaner energy and security of supply. A key component of the proposal is specific core energy objectives for the EU, including:

        In September 2007, and again in January 2008, the EC published further draft legislative proposals to realize its common energy policy and its ambitious environmental goals. These proposals are however still in the very early stages of parliamentary deliberation and it is not possible to predict at this stage whether and when they will be adopted and implemented.

        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

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Committee for protection of competition of the Ministry of Industry and Commerce (the "Committee") 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 and Kazakhstani Government result in certain contradictions between different laws and regulations as well as the absence of a clear demarcation between rights and responsibilities of the Ministry, the Committee and the Agency. This in turn results in some 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. The government is planning to introduce a real-time balancing market in 2008. 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.

        To date, the Agency approves and regulates all tariffs for power transmission and distribution. Under the law, power companies have to 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 decrease of the applicable tariffs and/or request introduction of the fixed prices for those power companies with prior record of anti-monopoly violations.

        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 Committee as dominant entities in the regional market because their aggregated share in the electricity supply commodity market in the region is 70%. These businesses are required to notify the competition authority about any power price increases for regional customers.

        Effective January 1, 2008, the Prime Minister of Kazakhstan has 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. It is not clear whether this order is legal, or if it will be maintained beyond the first quarter of 2008. One of AES's plants, AES Ekibastuz GRES 1, has agreed to the tariff freeze. The other AES plants in Kazakhstan are reviewing their options, but to date have not made a decision with regard to tariff levels for 2008.

        In February 2007, the Committee initiated administrative proceedings against UK Hydro, and Shulbinsk Hydro, an AES subsidiary, and subsequently AES Ust-Kamengorskaya TET LLP, ("UKT") and Nurenergoservice LLP, AES's electricity trading business in Kazakhstan, for alleged violation of Kazakhstan's antimonopoly laws. Initial decisions have been reached by the Courts in these proceedings. See Item 3 Legal Proceedings in this Form 10-K.

        In October 2007, Kazakhstan adopted amendments into Subsoil Law which allow the government to terminate any subsoil agreements in case of a threat to national interests or other reasons. The new law may have an impact on AES's Maikuben coal mine operation, which has a subsoil agreement with the government of Kazakhstan.

        In December 2007, the Kazakhstan government approved a resolution to introduce State price regulation for power sold to customers in the Southern zone via the North-South interconnects. All power companies located in the Northern zone with customers located in the Southern region are required to submit price information to the regulator, which then has the right to decrease the tariff based on a reasonable profit return approach.

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        In January 2008, the Ministry of Economy proposed to the Government a new tax on profit of non-resident legal entities from the sale of shares of a Kazakhstan company with a subsoil agreement and property located in Kazakhstan.

        In January 2008, the Ministry of Environment protection submitted a proposal to the Government on ratification of the Kyoto protocol.

        In January 2008, the Committee was reorganized into an independent state body, an Agency charged with the protection of competition. The role and functions of this new Agency in relation to the regulation of the power sector are not clear and will be determined in new rules and legislation.

        On February 4, 2008, the Company entered into a sale and purchase agreement with Kazakhmys PLC ("Kazakhmys"). Under the agreement, the Company is selling to Kazakhmys certain indirect wholly-owned subsidiaries with operations in 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, which collectively generated total revenues of approximately $185 million for the year ended December 31, 2007. The Company will receive consideration of approximately $1.1 billion at closing and will have the opportunity, over three years, to receive additional consideration of up to approximately $380 million under earn-out provisions, a management fee and a capital expenditure program bonus, for a total consideration of up to $1.48 billion. The management agreement, also entered into on February 4, 2008, pursuant to which an affiliate of the Company will manage the businesses sold to Kazakhmys, runs through December 2010, unless earlier terminated in accordance with the agreement. The sale is subject to certain regulatory and third-party approvals and to customary purchase price adjustments. The transaction is expected to close by the end of the second quarter of 2008.

        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. The litigation asserted against these businesses described above remains pending.

        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 independent power producers ("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 cost and there is no cap. At present we estimate that the additional cost, if any, due to license will be about US$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. The 2001 Electricity Act, which became effective in January 2003, brought the Hungarian electricity market into accord with EU directives in terms of third party access to the electricity grid and removal of subsidies, and defines a market that includes electricity generation companies, electricity distributors, power traders and an electricity grid operator.

        A gradual introduction of competition in the electricity market started in 2004, when the industrial users, constituting about 70% of total consumption, were allowed to choose their electricity suppliers. 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 new 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.

        As a member state of the EU, the Hungarian government notified the EC of arrangements concerning compensation to the state owned electricity wholesaler, MVM. The EC decided to open a formal investigation in 2005 to determine whether or not any government subsidies were provided by MVM to its suppliers which are incompatible with the common market. Although the EC has not completed its investigation or published any conclusions, the Commissioner for Competition has indicated informally that she considers the long term power purchase arrangements, including the contract with AES Tisza II power plant to be contrary to applicable EU laws and has encouraged the Hungarian government to terminate the long term PPAs. In December 2006, the Hungarian government carried out negotiations with the EC on this issue. If the Hungarian authorities follow the EC's decision, they may seek to revise the contracts and /or require the repayment of certain funds received by generators pursuant to the contracts. Simultaneously, at the end of 2006 and for the majority of 2007, the Hungarian government reintroduced administrative pricing for all electricity generators based on AES's agreements under the PPAs in place. A decision is expected in the near future.

        In January 2007, AES Summit Generation Limited, a holding company associated with AES operations in Hungary, notified the Hungarian government of a dispute concerning its acts and omissions related to AES's substantial investments in Hungary in connection with the re-introduction of

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the administrative prices for Hungarian electricity generators. In conjunction with this, AES and the Hungarian government have commenced International Centre for Settlement of Investment Disputes ("ICSID") arbitration proceedings under the Energy Charter Treaty in connection with the re-introduction of the administrative prices for the Hungarian electricity generators. In the meantime, pursuant to the new Electricity Act in force from January 1, 2008, administrative prices for electricity generators were subsequently abolished. Whether additional Hungarian government legislative initiatives pertaining to the electricity market related to recommendations of the EC Commissioner for Competition or other EU bodies or certain domestic political developments will be introduced in 2008 remains unclear. See Item 3 Legal Proceedings in this Form 10-K.

        In July 2007, the Prime Minister's office began a negotiation process with all the PPA generators regarding the possible renegotiation of the existing PPAs to bring them in line with the recommendations of the EC Commissioner for Competition. Some of the PPA generators agreed to amend their PPA which amendment was made conditional on the EU's approval; AES Tisza II's PPA has not been amended as part of this negotiation process.

        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 to the end user permitted by the regulator under the distribution and supply tariff in 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 with respect to the treatment of wages and salaries was effected at the end of 2007, by which adjustment for inflation has been replaced by adjustments based on the average industrial wage in the country.

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

        It is expected that the tariff methodology applied to the calculation of AES Ukraine's tariffs will further evolve beginning in 2009 pursuant to provisions approved in 2008 that included: (i) the rate of return on initial investment will be revised with a floor of 11%; (ii) commercial losses will not be allowed in the tariff; and (iii) the "black box" concept of operational expenses other than wages and salaries fixed in 2003 and inflated since then on an annual basis will be revised as well.

        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 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

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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 annualised 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 to be dispatched consistently during peak winter demand. However, NIAUR has 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 is currently challenging by way of judicial review proceedings the determination of NIAUR that the introduction of the SEM constitutes requisite arrangements to allow such early termination.

        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. 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 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 2006. 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 major active traders plus more than 20 smaller traders in the market) and also between generators and final customers. As early as February 2008, it is expected that a day ahead spot market will be incorporated into the Energy Exchange. AES Bohemia's electricity, steam, water and compressed air output is governed under bi-lateral 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 1,200 MW natural gas-fired plant located in Cartagena on the southeast coast of Spain, Cartagena. 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,

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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 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 energy 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 bi-lateral market dominated by state-owned entities. The state-owned Electricity Generation Company ("EUAS") and its subsidiaries, comprise approximately 23 GW of generation capacity and represent 48% of the market. Private producer's 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. 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 3 GWh annually, can contract through channels other than TEDAS.

        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 off 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, but then postponed the process indefinitely. The Turkish government has also announced plans to privatize all the state-owned generation assets by 2009, except for large hydro plants.

Asia & Middle East

        China.    In 2002, a new industry regulator, China's National Electricity Regulatory Commission (CERC) was established to promulgate the rules for and supervise the operation of the electric power industry and to administer electric power service licenses.

        In 2005, with a view to implementing power industry reform, the National Development and Reform Commission (NDRC) released interim regulations governing on-grid tariffs, along with two other regulations governing transmission and retail tariffs (the "Interim Regulations"). Pursuant to the Interim Regulations, prior to adoption of a pooling system, the on-grid tariffs shall be appraised and

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ratified by the pricing authorities by reference to the economic life of power generation projects and determined in accordance with the principle of allowing independent power producers 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. At this stage it is uncertain when the foregoing provision will be implemented or whether it will have a material adverse effect on the Company's businesses. In the long-term, foreign investors may be under pressure to renegotiate their PPAs.

        China's central government also issued a policy allowing the on-grid tariffs to be pegged to the fuel price in the case of significant fluctuations in fuel price. Seventy percent (70%) of the increase in fuel costs may be passed through in the tariff. Pursuant to this policy, the tariffs of our coal-fired facilities in China were increased in 2005 and 2006 to alleviate the escalation of fuel price.

        In March 2007, the Anhui Development and Reform Commission, ("ARDC") issued a notice to our Hefei business in China, that the State Council had made a decision to shut down small, inefficient, generation facilities in the Anhui Province by 2010 that were adding to the high level of pollution in China. As a result Hefei, an 115MW oil-fueled generation facility, will be shut down by the government in March 2008. The plant will become the property of the Anhui Province and AES Hefei will receive termination compensation of approximately $30 million (net of liquidation and termination costs). At this time neither party has any legal obligations related to this transaction, therefore AES will continue to reflect Hefei's results of operations within continuing operations of AES Corporation.

        Negotiations with the offtaker and the government are close to the final stage. The offtaker has agreed in principle to pay a termination fee to Hefei in March 2008. It is expected that Hefei will sign the termination agreement with the offtaker in March 2008 under the provincial government's supervision.

        In May 2007, NDRC and State Environmental Protection Administration of China also issued a regulation requiring that all new built coal-fuel power plants have to install and operate FGD equipment, and the operational coal-fuel power plants also need to complete the FGD equipment installation. All plants which have installed and operated FGD equipment will be granted on-grid tariff premium of RMB 0.15/MWH.

        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.

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,

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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 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 2006, the Company's subsidiaries operated businesses which had total approximate CO2 emissions of 84 million metric tonnes (ownership adjusted and including approximately 6 million metric tonnes from EDC which the Company sold in 2007). Approximately 38 million metric tonnes of the 84 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 is attempting to build a climate solutions business which would develop GHG credits for use by the Company and/or for sale, as set forth in the Risk Factor entitled "Our Alternative Energy businesses face uncertain operational risks," there is no guarantee that the business will be successful. And 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.

        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

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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. 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 incurred material costs to comply with Directive 2003/87/EC and applicable NAPs.

        On February 16, 2005, the "Kyoto Protocol to the United Nations Framework Convention on Climate Change" (the "Kyoto Protocol") became effective. The Kyoto Protocol requires the 40 developed countries that have ratified it (40 in total) to substantially 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 28 countries that the Company's subsidiaries currently operate in, all but three—the United States (including Puerto Rico), Kazakhstan and Turkey—have ratified the Kyoto Protocol. We are targeting production of approximately 24 million tonnes of issuable CO2 equivalent GHG offsets by 2011 in Asia, Africa, Europe and Latin America by developing and operating projects under the Clean Development and Joint Implementation Mechanisms of the Kyoto Protocol. There is no guarantee that we will be successful in this business. 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 2007, a United Nations Climate Change Conference was held in Bali, Indonesia. Over 180 countries sent representatives and a majority agreed to negotiate further reductions in GHG emissions for the period beginning after 2012 when Kyoto Protocol expires. The negotiations are expected to conclude prior to 2009. At present, the Company cannot predict whether compliance with the Kyoto Protocol or any agreements reached at the Climate Change Conference will have a material impact on the Company.

        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 in 2012 and beyond will have a material adverse effect on its consolidated operations or results.

        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 in this area. 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 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. The Court ruled that CO2 is a

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pollutant which potentially could be subject to regulation under the U.S. Clean Air Act 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. The U.S. EPA has not yet made any such determination, and current federal policy regarding CO2 emissions favors voluntary reductions, increased operating efficiency and continued research and technology development. However, the Court's decision and stimulus from regulators, politicians, non-governmental organizations, private parties and the courts and other factors could lead to a determination by the U.S. EPA to regulate CO2 emission 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 U.S. Clean Air Act.

        Ten northeastern states have entered into a memorandum of understanding under which the states coordinate to establish rules that require the reduction 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, are in the process of implementing rules to effectuate RGGI. Six of the ten states have issued draft regulations to implement RGGI for public comment. As proposed, RGGI is scheduled to become effective January 1, 2009 through various individual state laws and/or regulations. If RGGI is duly effectuated in each state, its laws and regulations will impose a cap on baseline CO2 emissions during the 2009 through 2014 period, and mandate 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. As currently proposed, it is anticipated that a significant portion of the allowances will be distributed through an auction process, which would require fossil fuel fired generating units to purchase allowances instead of direct allocations to affected generators.

        The Company's Eastern Energy business is located in New York. On October 24, 2007, the State of New York, a RGGI participant, released its proposed rule to implement its state program as part of RGGI. Public comments on the rule were due on December 24, 2007. Under the proposed New York implementing rule, each budgeted source of CO2 emissions will be required to surrender one CO2 allowance for each CO2 metric tonne emitted during a three-year compliance period. All power generating facilities in the State of New York would be subject to the rule. Unlike the previously implemented Federal SO2 and NOx cap-and-trade emissions programs, under the New York proposed rule, all allowances would be auctioned (rather than allocated to affected generating units) except for several small set aside accounts. Accordingly, the proposed rule, if implemented as proposed, would require that CO2 emitters acquire CO2 allowances either from the proposed auction or in the secondary emissions trading market. The details of the proposed auction mechanism, such as whether the auction would be regional or state-by-state, the frequency of the auctions, whether the allowance value will include a minimum reserve price, auction participant guidelines, creation of a fungible RGGI allowance emission unit that is legally tradable and enforceable across state borders and detailed market monitoring rules, are still being determined by New York State agencies.

        The Company's Thames business is located in Connecticut. The State of Connecticut passed legislation, effective July 1, 2007, which requires the Connecticut Department of Environmental Protection to auction, rather than allocate, CO2 emission allowances required by electric power generation facilities to comply with RGGI. The agency proposed regulations to implement RGGI on January 8, 2008. As in New York, these regulations and the auction mechanism are still being developed.

        The Company's Warrior Run business is located in Maryland. In April 2006, the Maryland General Assembly passed the Maryland Health Air Act which, among other thing things, required the State of Maryland to join RGGI. The Maryland Department of Environment ("MDE") proposed regulations to implement RGGI on February 1, 2008. The proposed rule would require 100% of the allowances the State receives to be auctioned. The proposed regulations, however, include a safety valve to control the

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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 legislation authorized the New Jersey Department of Environmental Protection to allocate or auction allowances under RGGI and established requirements for the agency to follow if allowances are conveyed to electricity generators using an auction. The agency has not yet proposed its regulation to implement RGGI. The Global Warming Response Act also directed the New Jersey Board of Utility Control to adopt an emissions portfolio standard or other mechanism to regulate any additional importation of power into the State as a result of RGGI.

        In 2006, of the approximately 38 million metric tonnes of CO2 emitted in the United States by the businesses operated by our subsidiaries (ownership adjusted), approximately 12 million metric tonnes were emitted in U.S. states participating in RGGI. We believe that due to the absence of allowance allocations, RGGI as currently contemplated could have an adverse impact on the Company's consolidated results of operations, financial condition and cash flows. For forecasting purposes, the Company has modeled the impact of CO2 compliance for 2009-2012 for its businesses that are subject to RGGI and that may not be able to pass through compliance costs. The model utilizes an allowance price of $3.05 per metric ton under RGGI. The source of this per tonne price estimate was the average price of a CO2 emissions voluntary compliance instrument on the Chicago Climate Exchange for the six month period ending November 15, 2007. 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 $30 million per year in 2009-2012. Given all of the uncertainties surrounding RGGI, including those discussed in the "Business—Regulatory Matters—Environmental and Land Use Regulations" section of this 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.

        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 January 25, 2007, the California Public Utility Commission adopted a CO2 emission performance standard applicable to all electricity generated within the state or delivered into the State. In addition, on February 8, 2008, the California Public Utility Commission issued a proposed recommendation that the State develop a GHG emission cap-and-trade program applicable to entities which "deliver" electricity into California. 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 (Utah and Montana) and two Canadian provinces (British Columbia and Manitoba). 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. The actual regulatory design of this program is not yet known.

        The Company owns IPL which is located in Indiana. On November 15, 2007, nine 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.

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        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, RGGI, A.B. 32, WCI, MGGRA and the Hawaiian regulations have yet to be finalized, these GHG-related initiatives may potentially 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:

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        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 Clean Air Act requirements alleged to have occurred prior to the Company's acquisition of the Greenidge, Westover, Jennison and Hickling 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 Greenidge, is undertaking an Upgrade Project at Westover 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 Greenidge and will submit proposals for new final emission limits to NYSDEC for approval after the Upgrade Project at Westover is complete.

        Other Air Emission Regulations.    The U.S. Clean Air Act and various state laws and regulations regulate emissions of air pollutants, including sulfur dioxide ("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 on March 10, 2006 and will require additional allowance surrender for SO2 and NOx emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR will be implemented in two phases. The first phase will begin in 2009 and 2010 for NOx and SO2, respectively. A second phase with additional allowance surrender obligations for both air emissions begins in 2015. To implement the required emission reductions for this rule, the states will establish emission allowance-based "cap-and-trade" programs. CAIR has been challenged in federal court. No decisions have been rendered to date on the challenge.

        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 Clean Air Act and vacated the rule. At this time it is not known whether the U.S. EPA will attempt to appeal the decision to the U.S. Supreme Court.

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        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 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, the Company completed installing selective catalytic reduction ("SCR") and other NOx control technologies at three coal-fired units of our subsidiary, Indianapolis Power and Light ("IPL"). In addition, the Company completed a multi-pollutant control project at its Greenidge power plant in the state of New York and is scheduled to complete construction of a similar project at its Westover power plant in the state of New York by the end of 2008. 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 these new rules.

        NYSDEC previously promulgated regulations requiring electric generators to reduce SO2 emissions by 50% below current Clean Air Act 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. As a result, in order to operate the Company's four electric generation facilities located in New York, installation of pollution control technology will likely be required.

        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 2008. 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

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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, the rule's requirements would be implemented via each plant's National Pollutant Discharge Elimination System ("NPDES") water quality permit renewal process, and 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 it must first prepare a Comprehensive Demonstration Study to assess each 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. However, as a result of the 2007 United States Court of Appeals for the Second Circuit decision (Docket Nos. 04-6692 to 04-6699) remanding major parts of the 2005 rule back to U.S. EPA, there could be 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 rule to address the Second Circuit's decisions and a draft of the new rule is expected to be issued later this year. Certain states in which the Company operates power generation facilities, such as New York State, 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 February 4, 2008, we entered into a stock purchase agreement with Kazakhmys. Under the agreement, we will sell to Kazakhmys two indirect wholly-owned subsidiaries with operations in Kazakhstan, AES Ekibastuz LLP and Maikuben West LLP, which generated total revenues of approximately $185 million for the year ended December 31, 2007. We will receive consideration of approximately $1.1 billion at closing and will have the opportunity to receive additional consideration of up to approximately $380 million under earn-out provisions, a management fee and a capital expenditure program bonus, for a total consideration of up to $1.48 billion. The management agreement, also entered into on February 4, 2008, has a three year term and runs through December 2010.

        We are retaining our facilities in Eastern Kazakhstan including Sogrinsk CHP and Ust-Kamenogorsk CHP its facilities under concession agreements, Shulbinsk HPP and Ust-Kamenogorsk HPP; and our energy trading business, Nurenergoservice L.L.P. The sale is subject to certain regulatory and third-party approvals and to customary purchase price adjustments. The transaction is expected to close by the end of the second quarter of 2008.

        In March 2007, the Anhui Development and Reform Commission, ("ARDC") issued a notice to our Hefei business in China, that the State Council had made a decision to shut down small, inefficient, generation facilities in the Anhui Province by 2010 that were adding to the high level of pollution in

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China. As a result Hefei, an 115 MW oil-fueled generation facility, will be shut down by the government in March 2008. The plant will become the property of the Anhui Province and AES Hefei will receive termination compensation of approximately $30 million (net of liquidation and termination costs). At this time neither party has any legal obligations related to this transaction, therefore AES will continue to reflect Hefei's results of operations within continuing operations of AES Corporation.

        In early February 2008, the Company signed an agreement with National Power Corporation ("NPC"), a state owned utility, to purchase a 600 MW coal-fired generation facility in Masinloc, Philippines for $930 million. The purchase will be primarily financed by non-recourse debt. The 10 year old plant, which is currently partially operational, consists of two turbines; one turbine is currently in working condition while the second turbine will require maintenance to return it to a working condition. The plant will require an additional investment over the next six to 12 months to bring it up to the required operational standard. The Masinloc plant is not currently compliant with government mandated environmental regulations. Masinloc will receive permits from the Philippine government to allow for the continued operation of the plant during its environmental clean-up period. The sale is expected to close in April 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

        Due to material weaknesses in our internal control over financial reporting, our disclosure controls and procedures and internal control over financial reporting were determined not to be effective for each fiscal quarter since December 31, 2004 through December 31, 2007. Our disclosure controls and procedures and internal control over financial reporting may not be effective in future periods as a result of existing or newly identified material weaknesses in internal controls.

        Our management reported material weaknesses in our internal control over financial reporting for each of the fiscal quarters since December 31, 2004 through December 31, 2007. 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. Our management concluded that for each of the fiscal quarters since December 31, 2004 through December 31, 2007, 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. For a discussion of material weaknesses reported by management as of December 31, 2007, see Item 9A Controls and Procedures in this Annual Report on Form 10-K.

        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 are costly, time consuming and require 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 over the past 3 years we have restated our annual financial statements six times to correct these errors.

        Although we reported remediation of certain material weaknesses as of December 31, 2007 and continue to execute plans to remediate the remaining material weaknesses in 2008, there can be no assurance as to when the remediation plans will be fully implemented, nor can there be any assurance that additional material weaknesses will not be identified in the future. Due to our decentralized structure and our disparate accounting systems, we have additional work remaining to remediate our material weaknesses in internal control over financial reporting. Until our remediation efforts are completed, we will continue to be at an increased risk that our financial statements could contain errors that will be undetected, and we will continue to incur significant expense and management burdens associated with the additional procedures required to prepare the consolidated financial statements.

        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.

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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. 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.

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 prohibits us from offering and selling our securities pursuant to our shelf registration statement on Form S-3, which has impaired and will continue to impair our ability to access the capital markets through the public sale of registered securities in a timely manner. We will regain our S-3 eligibility on June 1, 2008 if we timely file all required reports through that date.

        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.

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

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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, 2007, we had approximately $18.0 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:

        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 flow from operations may not be sufficient to repay at maturity all 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.

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

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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, which is in many cases the basis of dividend payments. Subsidiaries in foreign countries may also be prevented from distributing funds to The AES Corporation as a result of restrictions imposed by the foreign government or repatriating funds or converting currencies. Any right The AES Corporation has to receive any assets of any of its subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, assignment for the benefit of creditors, marshaling of assets and liabilities or any 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'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 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, 2007, we had approximately $18.0 billion of outstanding indebtedness on a consolidated basis, of which approximately $5.6 billion was recourse debt of The AES Corporation and approximately $12.4 billion was non-recourse debt. In addition, at December 31, 2007, The AES Corporation had provided:

        The AES Corporation is also obligated under other commitments, which are limited to amounts, or percentages of amounts, received by The AES Corporation as distributions from its project subsidiaries. In addition, The AES Corporation has commitments to fund its equity in projects currently under development or in construction.

        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 $118 million at December 31, 2007. While the lenders under our non-recourse

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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:

        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.

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:

        The AES Corporation's principal sources of liquidity are:

        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 2007 Form 10-K.

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        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. 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 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.

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

        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:

        In recent quarters beginning in 2007, credit conditions and credit markets have weakened considerably, which has made it difficult for many companies to arrange for financing on a recourse or non-recourse basis. Should future access to capital not be available to us, we may have to sell assets or decide not to build new plants or acquire 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.

        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. 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, counter parties 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 counter parties 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 counter parties; it will limit the amount of credit available to The AES Corporation to meet its other liquidity needs.

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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.

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 offsetting 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 and Argentine peso. As our Brazilian and Argentine businesses primarily identify their local currency as its functional currency, recent appreciation of these currencies has resulted in the decrease 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. In addition, because it is difficult to estimate the overall impact of foreign exchange fluctuations related to translation exposure on our results of operations, we do not separately quantify the impact on earnings.

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 business, also buys electricity in the

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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:

        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, a pre-tax impairment charge of $352 million was recognized 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. Several of our Alternative Energy initiatives may, if we are successful in developing

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them further, operate without long-term sales or fuel supply agreements, and, as a result, may experience significant volatility in their results of operations.

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

        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. However, we may not cover the entire exposure of our assets or positions to market price 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 significantly deviate from historical prices or if the price volatility 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.

Certain of our businesses are sensitive to variations in weather.

        Our energy business is 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 electric consumption 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 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:

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        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 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.

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:

        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

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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 are based on 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 minimize 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 at all or on terms similar to those presently available to us. Any such 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.

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.

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Much of our generation business is 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 for prices above current spot 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.

        We have sought to reduce this counter party credit risk under these 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.

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 experience (including both domestic and international) and financial resources similar to or greater than us. 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. The foregoing 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:

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        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.

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. 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, we have achieved a majority of our growth through acquisitions. We plan to 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:

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

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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 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 Alternative Energy businesses face uncertain operational risks.

        In many instances, our Alternative Energy businesses target industries that are created by, or are significantly affected by technological innovation or new lines of business that are outside our core expertise of Generation and Utilities. Given the nascent nature of these industries, our ability to predict actual performance results may be hindered and we ultimately may not be successful in these areas.

Our Alternative Energy businesses may experience higher levels of volatility.

        Our Alternative Energy efforts are, to some degree, focused on new or emerging markets. As these markets develop, long-term fixed price contracts for the major cost and revenue components may be unavailable, which may result in these businesses having relatively high levels of volatility.

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

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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:

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

        In addition, the Company may face actions from regulatory authorities relating to the structure of its business arrangements. As further described in Item 3 Legal Proceedings of this Form 10-K, the Company is facing antimonopoly regulatory actions in Kazahkstan from the Competition Committee. As noted in Item 1 Business—Regulatory Matters—IPL of this Form 10-K, in December 2007, IPL received a letter from the staff of the IURC, requesting information relevant to its periodic review of its rates and charges. In the letter, IURC staff indicated its concern that higher than usual 2007 earnings may continue in the future. It is not clear what action, if any, the IURC staff will recommend as a result of its review. As noted in Item 1 Business—Regulatory Matters—Hungary of this Form 10-K, the European Committee's Commissioner for Competition has indicated informally that she considers the long-term power purchase arrangements between the state-owned entity, MVM, and certain power generators, including the contract with AES Tisza II power plant to be contrary to applicable EU laws and has encouraged the Hungarian government to terminate the long-term power purchase agreements. If the Hungarian authorities follow the Commission's decision, they may seek to revise the contracts and/or require the power generators, including AES Tisza II, to repay certain funds. It is possible that the Company may also 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 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.

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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 Energy Policy Act of 2005 ("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 of 1935 and enacted PUHCA of 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 may spur an increased number of mergers and 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 regulation by many federal, state and local authorities, international treaties and foreign governmental authorities. These regulations generally involve 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

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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 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 2006, the Company's subsidiaries operated businesses which had total approximate CO2 emissions of 84 million metric tonnes (ownership adjusted and including approximately 6 million metric tonnes from EDC which the Company sold in 2007). Approximately 38 million metric tonnes of the 84 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. 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 Alternative Energy businesses face uncertain operational risks," there is no guarantee that the climate solutions business will be successful. And 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.

        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 to the United Nations Framework Convention on Climate Change" (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 make them more costly.

        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. The Court ruled that CO2 is a

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pollutant which potentially could be subject to regulation under the U.S. Clean Air Act 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. 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 regulators, politicians, 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.).

        At the state level, regional initiatives such as the Regional Greenhouse Gas Initiative, or RGGI, a cap-and-trade program covering CO2 emissions from electric power generation facilities in the Northeast, and the Western Climate Initiative, or WCI, are developing market-based programs to address GHG emissions. WCI's conceptual program design to achieve GHG reductions from the electric power generation industry is not expected to be available until August 2008. In addition, several states, including California, have adopted comprehensive legislation that, when implemented, would 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 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 states are in the process of promulgating regulations needed for implementation, with six of the ten states issuing drafts regulations to implement RGGI for public comment. The program is expected to become effective in January 2009 and the first regional auction of RGGI allowances needed to be acquired by power generators to comply with state programs implementing RGGI could be held sometime in 2008. Our subsidiaries in New York, New Jersey, Connecticut and Maryland will be subject to RGGI if the RGGI regulations are duly effectuated in each RGGI state. Of the approximately 38 million metric tonnes of CO2 emitted in the United States by our subsidiaries in 2006 (ownership adjusted), approximately 12 million metric tonnes were emitted in U.S. states participating in RGGI. We believe that due to the absence of allowance allocations, RGGI as currently contemplated could have an adverse impact on the Company's consolidated results of operations, financial condition and cash flows. For forecasting purposes, the Company has modeled the impact of CO2 compliance for 2009-2012 for its businesses that are subject to RGGI and that may not be able to pass through compliance costs. The model utilizes an allowance price of $3.05 per metric tonne under RGGI. The source of this per tonne price estimate was the average price of a CO2 emissions voluntary compliance instrument on the Chicago Climate Exchange for the six month period ending November 15, 2007. 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 $30 million per year in 2009-2012. Given all of the uncertainties surrounding RGGI, including those discussed in Item 1 Business—Regulatory Matters—Environmental and Land Use Regulations of this 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.

        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 recently expressed concern about providing financing for facilities which would emit

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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 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 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 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.

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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. 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, 2007. The Company has evaluated claims, in accordance with SFAS No. 5 Accounting for Contingencies, ("SFAS No. 5"), that it deems both probable and reasonably estimatable and accordingly, has recorded aggregate reserves for all claims for approximately $486 million as of December 31, 2007.

        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$825 million (US$492 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). 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 was transferred to CTEEP pursuant to the privatization. Subsequently, both Eletrobrás and CTEEP filed separate appeals to the Superior Court of Justice ("SCJ"). In June 2006, the 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 subsequently filed a motion for clarification of that decision, which was denied in February 2007. In April 2007, Eletropaulo filed appeals with the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil. Eletropaulo's appeal to the Special Court has been dismissed. However, the Supreme Court has not yet determined whether it will consider Eletropaulo's appeal. Eletrobrás may resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo may be required to provide security in the amount of its alleged liability. 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

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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 June 2007, the U.S. Supreme Court declined to review the September 2004 Decision. The Ninth Circuit's temporary stay of the remand to FERC expired in November 2007. 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"). After a temporary stay of the proceeding expired, 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

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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. An arbitration hearing with respect to liability was conducted on August 3-9, 2005 in India. Final written arguments regarding liability were submitted by the parties to the arbitral tribunal in late October 2005. 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 tribunal declared that the Company was the successful party and invited the parties to file papers on the allocation of costs. Gridco has filed a challenge of the arbitration award with the local Indian court. In January 2008, the Indian Supreme Court ruled that the respondents' petition concerning the presiding arbitrator's fees and the venue of any future proceedings was moot in light of the arbitration award in the respondents' favor. 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 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 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.

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        In April 2002, IPALCO, the pension committee for the Indianapolis Power & Light Company thrift plan ("Pension Committee"), and certain former officers and directors of IPALCO were named as defendants in a purported class action filed in the U.S. District Court for the Southern District of Indiana. In May 2002, an amended complaint was filed in the lawsuit. The amended complaint asserts that IPALCO and former members of the Pension Committee breached their fiduciary duties to the plaintiffs under the Employees Retirement Income Security Act by, inter alia, permitting assets of the thrift plan to be invested in the common stock of IPALCO prior to the acquisition of IPALCO by the Company and allegedly failing to disclose directly to each plan participant the individual defendants' personal transactions in IPALCO stock prior to the acquisition. In September 2003 the Court granted plaintiffs' motion for class certification. A trial addressing only the allegations of breach of fiduciary duty was held in February 2006. In March 2007, the Court issued a decision in favor of defendants and dismissed the lawsuit with prejudice. In April 2007, plaintiffs appealed the Court's decision to the U.S. Court of Appeals for the Seventh Circuit as to the former officers and directors of IPALCO, but not as to IPALCO or the Pension Committee. In December 2007, the Seventh Circuit affirmed the judgment in favor of the former officers and directors.

        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 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"). AES Florestal had been under the control of AES 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, AES 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 AES 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 environmental agency ("FEPAM") has also started a procedure

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(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. The measures that must be taken by Sul and CEEE are still under discussion pending receipt of correspondence from FEPAM.

        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$3.3 billion (US$1.6 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 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 (US$247 million). In March 2007, the dividends were determined to be worth approximately R$423 million (US$198 million). SEB's defense was ruled groundless by the Circuit Court in December 2006. In January 2007, SEB filed an appeal to the relevant Federal Court of Appeals. In April 2007, BNDES withdrew the attached dividends. BNDES may attempt to seize the attached CEMIG shares at any time. 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

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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 Appeal for the Second Circuit has been stayed since September 2006. Also, in February 2005, Itabo initiated arbitration against CDEEE and the Fondo Patrimonial de las Empresas Reformadas ("FONPER") in the International Chamber of Commerce ("ICC") seeking, among other relief, to enforce the arbitration provisions in the parties' contracts. In March 2006, Itabo and FONPER settled their respective claims. In September 2006, the ICC determined that it lacked jurisdiction to decide the arbitration as to Itabo and CDEEE. 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 October 2004, Raytheon Company ("Raytheon") filed a lawsuit against AES Red Oak, LLC ("Red Oak") in the Supreme Court of the State of New York, County of New York. The complaint purports to allege claims for breach of contract, fraud, interference with contractual rights and equitable relief relating to the construction and/or performance of the Red Oak project, an 800 MW combined cycle power plant in Sayreville, New Jersey. The complaint seeks the return of approximately $30 million that was drawn by Red Oak under a letter of credit that was posted by Raytheon for the construction and/or performance of the Red Oak project. Raytheon also seeks $110 million in purported additional expenses allegedly incurred by Raytheon in connection with the guaranty and construction agreements entered with Red Oak. In December 2004, Red Oak answered the complaint and filed breach of contract and fraud counterclaims against Raytheon. Red Oak's fraud counterclaims were later dismissed from the case. In May 2005, Raytheon filed a related action against Red Oak in the Superior Court of Middlesex County, New Jersey, seeking to foreclose on a construction lien in the amount of approximately $31 million on property allegedly owned by Red Oak. In September 2007 the New Jersey Superior Court denied Red Oak's motion for summary judgment against Raytheon's New Jersey action. In December 2007, the parties settled their disputes.

        In January 2005, the City of Redondo Beach ("City") of California issued an assessment against Williams Power Co., Inc., ("Williams") and AES Redondo Beach, LLC ("AES Redondo"), an indirect subsidiary of the Company, for approximately $72 million in allegedly overdue utility users' tax ("UUT"), interest, and penalties relating to the natural gas used at AES Redondo's power plant from May 1998 through September 2004 to generate electricity. In September 2005, the City Tax Administrator held AES Redondo and Williams jointly and severally liable for approximately $57 million in UUT, interest, and penalties. In October 2005, AES Redondo and Williams filed respective appeals with the City Manager, who appointed a Hearing Officer to decide the appeal. In December 2006, the Hearing Officer overturned the City's assessment against AES Redondo (but not Williams). In December 2006, Williams filed a petition for writ of mandate with the Los Angeles Superior Court challenging the Hearing Officer's decision. Pursuant to a court order, Williams later prepaid approximately $57 million to the City in order to litigate its petition and filed an amended petition. In March 2007, the City filed a petition for writ of mandate with the Superior Court challenging the Hearing Officer's decision as to AES Redondo. The Superior Court has heard final arguments but has not yet issued final decisions on Williams' and the City's respective petitions. In addition, in July 2005, AES Redondo filed a lawsuit in Superior Court seeking a refund of UUT paid since February 2005, and an order that the City cannot charge AES Redondo UUT going forward. Williams later filed a similar complaint that was related to AES Redondo's lawsuit. After authorizing limited discovery on disputed jurisdictional and other issues, including whether AES Redondo and Williams must prepay to the City any allegedly owed UUT prior to judicially challenging the merits of

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the UUT, the Court stayed the cases in December 2006. Furthermore, since December 2005, the Tax Administrator has periodically issued UUT assessments against AES Redondo and Williams for allegedly overdue UUT on the gas used at the power plant since October 2004 ("New UUT Assessments"). AES Redondo has filed objections to those and any future UUT assessments with the Tax Administrator, who has indicated that he will only consider the amount of the New UUT Assessments, not the merits of them, given his September 2005 decision. AES Redondo believes that it has meritorious claims and defenses, and it will assert them 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 US$135,000. The Company has appealed this decision to the Supreme Court.

        In February 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan initiated administrative proceedings against two hydroelectric plants under AES concession, Ust-Kamenogorsk HPP and Shulbinsk HPP (collectively, "Hydros") concerning their sales to an AES trading company, Nurenergoservice LLP, and other affiliated companies in alleged violation of Kazakhstan's antimonopoly laws. In August 2007, the Competition Committee ordered the Hydros to pay approximately 2.6 billion KZT (US$22 million) in damages for alleged antimonopoly violations in 2005 through January 2007. The damages set forth in orders were affirmed by the headquarters of the Competition Committee, the economic court of first instance, and the court of appeals (first panel). Therefore, in February 2008, the Hydros paid the damages. The court of appeals (second panel) has affirmed the Competition Committee's order with respect to Ust-Kamenogorsk HPP. The Hydros intend to file appeals with the court of appeals (second panel) (with respect to Shulbinsk HPP) and the supreme court (with respect to Ust-Kamenogorsk HPP). In addition, the economic court has issued an injunction to secure the Hydros' alleged liability, freezing the Hydros' bank accounts and prohibiting the Hydros from transferring or disposing of their property. The economic court later temporarily lifted the injunction to allow the Hydros to pay the damages, which as noted above, the Hydros did in February 2008. In separate but related proceedings, in September 2007, the Competition Committee ordered the Hydros to pay approximately 22 million KZT (US$188,000) in administrative fines for their alleged antimonopoly violations. In December 2007, the administrative court of first instance upheld the fines. Therefore, in February 2008, the Hydros paid the fines. The Competition Committee has indicated that it intends to investigate whether Ust-Kamenogorsk HPP has violated antimonopoly laws through November 2007. The Hydros believe they have meritorious claims and defenses; however, there can be no assurances that they will prevail in these proceedings.

        In June 2007, the Competition Committee ordered AES Ust-Kamengorsk TET LLP ("UKT") to pay approximately 835 million KZT (US$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 (US$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 (US$7 million) and rejected the damages to be paid to customers. The economic court later ordered UKT to pay the damages to the state by May 1, 2008. The economic court has also issued an injunction to secure UKT's alleged liability prohibiting UKT from transferring or disposing of its property; however, the injunction does not extend to UKT's bank accounts. The court of appeals (first panel) has affirmed the economic court's decisions with respect to the alleged damages and the injunction. In January 2008, the economic court issued a purported clarification of its November 2007 decision, reducing UKT's tariff as of January 2008, directing UKT to apply that reduced tariff prospectively, and ordering UKT to reimburse an unspecified amount to customers that paid at higher rates in 2007. UKT

72


has appealed the purported clarification to the court of appeals (first panel). In separate but related proceedings in July 2007, the Competition Committee ordered UKT to pay approximately 93 million KZT (US$800,000) in administrative fines as estimated by UKT, for its alleged antimonopoly violations. In February 2008, the administrative court upheld the Competition Committee's order in part, reducing the fines to approximately 70 million KZT (US$600,000). The Competition Committee 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. As UKT 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. Furthermore, as UKT did 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 July 2007 the Competition Committee ordered Nurenergoservice to pay approximately 18 billion KZT (US$150 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. In September 2007, the headquarters of the Competition Committee upheld the order. Nurenergoservice subsequently appealed to the economic court of first instance. In February 2008, the economic court stayed the case pending the completion of the transfer of the Competition Committee's authority and powers to a newly established antimonopoly agency, the Agency on the Protection of Competition. The court of appeals (first panel) has rejected the Competition Committee's appeal to lift the stay. Also, the economic court has issued an injunction to secure Nurenergoservice alleged liability, freezing Nurenergoservice's bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. The court of appeals (first panel) has upheld the injunction. Furthermore, in separate but related proceedings in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately 2 billion KZT (approximately US$15 million) in administrative fines for its alleged antimonopoly violations. In September 2007, after the headquarters of the Competition Committee upheld the order, Nurenergoservice appealed to the administrative court of first instance. In October 2007, the administrative court suspended the proceedings pending the resolution of the proceedings in the economic court and any proceedings in the court of appeals (first panel). The Competition Committee 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. If Nurenergoservice does not prevail in the economic court and any proceedings in 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. 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 TET 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. In August 2007, the economic court affirmed the order. In October 2007, the court of appeals affirmed the economic court's decision. The Competition Committee has not indicated whether it intends to assert claims against Sogrinsk for alleged antimonopoly violations post January 2007. Sogrinsk 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 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. However, the Competition Committee stated that it intends to investigate whether Irtysh has illegally coordinated with other AES companies concerning the sale of power. Irtysh

73


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 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.

        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 (US$19 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 GHG legislation and climate change from GHG emissions might have on the Company's operations and results. The Company is responding 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 US$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.

        During December 2007, Maikuben West was audited for the 2005 calendar year by the Tax Committee that oversees ecological payments. The initial results of the audit indicate that Maikuben West will be required to make a payment of approximately US$400,000. Maikuben West is appealing this finding in accordance with applicable law.

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 2007.

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PART II

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

Recent Sales of Unregistered Securities

        None.

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 6, 2008, was $19.44, per share. The Company 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:

 
   2007
   2006
Price Range of Common Stock
  High
   Low
   High
   Low
First Quarter   $ 22.61   $ 19.78   $ 17.71   $ 16.20
Second Quarter     23.90     20.87     18.76     16.40
Third Quarter     23.25     17.76     21.24     18.25
Fourth Quarter     22.53     20.21     23.72     20.21

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Performance Graph


THE AES CORPORATION
PEER GROUP INDEX/STOCK PRICE PERFORMANCE

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

         GRAPHIC

Source: Bloomberg

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

         GRAPHIC

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, 2002 in AES Common Stock, the S&P 500 Index and the S&P Utilities Index. The three year total return chart assumes $100 invested on December 31, 2004 in the same security and indices. 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 March 6, 2008, there were approximately 6,460 record holders of our common stock, par value $0.01 per share.

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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 are not allowed to pay cash dividends. 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. The terms of the indentures governing our outstanding Second Priority Senior Secured Notes also restrict our ability to pay dividends.

        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 that our project subsidiaries are subject to.

        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, 2007 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 23—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

 
   Year Ended December 31,
  
Statement of Operations Data
  
  2007
   2006
   2005
   2004
   2003
  
 
    
   (Restated)

   (Restated)

   (Restated)

   (Restated)

  
 
   (in millions, except per share amounts)

  
  Revenues   $ 13,588   $ 11,576   $ 10,247   $ 8,728   $ 7,676  
 
Income from continuing operations
 
 
495
 
 
176
 
 
365
 
 
183
 
 
177
 
  Discontinued operations, net of tax     (590 )   50     188     132     (681 )
  Extraordinary items, net of tax     —     21     —     —     —  
  Cumulative effect of change in accounting principle, net of tax     —     —     (4 )   —     41  
   
 
 
 
 
 
  Net (loss) income available to common stockholders   $ (95 ) $ 247   $ 549   $ 315   $ (463 )
   
 
 
 
 
 

Basic (loss) earnings per share:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Income from continuing operations, net of tax   $ 0.74   $ 0.27   $ 0.56   $ 0.29   $ 0.30  
  Discontinued operations, net of tax     (0.88 )   0.07     0.29     0.20     (1.15 )
  Extraordinary items, net of tax     —     0.03     —     —     —  
  Cumulative effect of change in accounting principle, net of tax     —     —     (0.01 )   —     0.07  
   
 
 
 
 
 
  Basic (loss) earnings per share   $ (0.14 ) $ 0.37   $ 0.84   $ 0.49   $ (0.78 )
   
 
 
 
 
 

Diluted (loss) earnings per share:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Income from continuing operations, net of tax   $ 0.73   $ 0.27   $ 0.56   $ 0.29   $ 0.30  
  Discontinued operations, net of tax     (0.87 )   0.07     0.28     0.20     (1.14 )
  Extraordinary items, net of tax     —     0.03     —     —     —  
  Cumulative effect of change in accounting principle, net of tax     —     —     (0.01 )   —     0.07  
   
 
 
 
 
 
  Diluted (loss) earnings per share   $ (0.14 ) $ 0.37   $ 0.83   $ 0.49   $ (0.77 )
   
 
 
 
 
 
 
 
   December 31,
  
Balance Sheet Data:
  
  2007
   2006
   2005
   2004
   2003
  
 
    
   (Restated)

   (Restated)

   (Restated)

   (Restated)

  
 
   (in millions)

  
  Total assets   $ 34,453   $ 31,274   $ 29,025   $ 28,449   $ 29,145  
  Non-recourse debt (long-term)   $ 11,297   $ 9,840   $ 10,308   $ 10,571   $ 10,038  
  Non-recourse debt (long-term)-Discontinued operations   $ 33   $ 342   $ 467   $ 742   $ 719  
  Recourse debt (long-term)   $ 5,332   $ 4,790   $ 4,682   $ 5,010   $ 5,862  
  Accumulated deficit   $ (1,241 ) $ (1,093 ) $ (1,340 )(2) $ (1,889 )(2) $ (2,204 )(1)(2)
  Stockholders' equity (deficit)   $ 3,164   $ 2,979   $ 1,583   $ 997   $ (99 )
(1)
An $8 million increase to accumulated deficit was recognized as of January 1, 2003 for the cumulative impact of the correction of errors for all periods preceding January 1, 2003. The correction was not material to the financial statement data presented herein as of and for the four years ended December 31, 2003 through December 31, 2006.

(2)
The impact of the restatement adjustments on accumulated deficit was an increase to accumulated deficit of $40 million, $2 million and $13 million as of December 31, 2005, 2004 and 2003, respectively.

79

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

Restatement of Consolidated Financial Statements and Reclassification of Certain Subsidiaries to Held for Sale

        The Company has previously identified certain material weaknesses related to its system of internal control over financial reporting. As described in the Company's 2006 Form 10-K/A filed on August 7, 2007, the following five material weaknesses were reported:

        As of December 31, 2007 the Company has remediated the following three material weaknesses:

        Accordingly, the following two material weaknesses remain unremediated as of December 31, 2007:


        In 2005, the Company prepared and documented its accounting analysis of a power purchase agreement ("the Deepwater Agreement") between AES Deepwater, one of our generation businesses in Deepwater, Texas and a third party. The assessment of the Deepwater Agreement included an analysis of whether the contract is a derivative under provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS No. 133"). Because the penalty clause in the Deepwater Agreement does not contain specific volumes upon which the penalties would be based, the Company concluded that these penalty provisions are not specific enough to be valued. Accordingly, the Company determined that the Deepwater Agreement was not a derivative under SFAS No. 133 and consulted with Deloitte & Touche LLP in reaching this conclusion.

        As part of the 2007 year-end closing process and in connection with the remediation of the Company's material weakness for contract accounting (see Item 9A Controls and Procedures for further discussion of this material weakness), the Company reviewed several hundred contracts relative to the risk of additional errors. The Deepwater Agreement received a second review as part of this process. In that review, the Company determined that there was no intent by the contracting parties to create a derivative contract, that the penalty clause had not changed, and that no penalties had been triggered under the Deepwater Agreement. The Company now believes, and its external auditors agree,

80


that even though there is no explicit formula for calculating penalties in the Deepwater Agreement, a minimum volume could be inferred from certain capacity requirement provisions in the Deepwater Agreement. Under this accounting interpretation, the penalty can be valued, making the contract subject to derivative accounting treatment. Accordingly, the Company has concluded that the Deepwater Agreement will be treated as a derivative under SFAS No. 133, valued and marked-to-market resulting in an adjustment to previously reported results. The impact of the Deepwater Adjustment resulted in an increase of approximately $30 million and a decrease of approximately $25 million to income from continuing operations and net income in 2006 and 2005, respectively.

        In addition to the Deepwater Adjustment, the Company has identified a number of smaller non-cash adjustments to its prior period financial statements ("Other Adjustments"), none of which is individually material. In the aggregate (excluding the Deepwater Adjustment) these out-of-period adjustments are not material to the Company's financial statements. Many of these errors were identified during the Company's remediation of previously identified material weaknesses, while others were identified during the year-end closing process, including errors relating to depreciation and accounting for judicial deposits in Brazil. We generally recognize these adjustments in the period in which they were identified. Because the Deepwater Adjustment has required a restatement, we also are recording these Other Adjustments in the proper periods. The Company has also entered into an agreement to sell two indirect wholly-owned subsidiaries with operations in Kazakhstan, AES Ekibastuz LLP and Maikuben West LLP. As required by SFAS No. 144 [Accounting for the Impairment or Disposal of Long-Lived Assets], ("SFAS No. 144"), presentation of the assets and liabilities of these businesses are classified as held for sale.

        As disclosed in the Company's Form 8-K dated March 3, 2008, as a result of the restatement, the Company was in default under its senior secured credit facility and its senior unsecured credit facility due to a breach of a representation related to its financial statements set forth in the credit agreements related to the facilities. The Company has obtained a waiver of these defaults from its lenders under these facilities.

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        The following table details the impact of the restatement on the Company's Consolidated Statements of Operations for the years ended December 31, 2006 and 2005:

 
   Year Ended December 31, 2006
   Year Ended December 31, 2005
  
 
   December 31, 2007 Restatement
   December 31, 2007 Restatement
  
 
   2006
Form 10-K/A
   Deepwater
   Other
Adjustments
   2007
Form 10-K
   2006
Form 10-K/A
   Deepwater
   Other
Adjustments
   2007
Form 10-K
  
Revenues:                                                  
  Regulated   $ 6,198   $ —   $ (44 ) $ 6,154   $ 5,617   $ —   $ (33 ) $ 5,584  
  Non-Regulated     5,366     52     4     5,422     4,703     (44 )   4     4,663  
   
 
 
 
 
 
 
 
 
    Total revenues     11,564     52     (40 )   11,576     10,320     (44 )   (29 )   10,247  
   
 
 
 
 
 
 
 
 
Cost of Sales:                                                  
  Regulated     (4,114 )   —     39     (4,075 )   (4,021 )   —     18     (4,003 )
  Non-Regulated     (4,052 )   —     (15 )   (4,067 )   (3,371 )   —     (3 )   (3,374 )
   
 
 
 
 
 
 
 
 
    Total cost of sales     (8,166 )   —     24     (8,142 )   (7,392 )   —     15     (7,377 )
   
 
 
 
 
 
 
 
 
  Gross margin     3,398     52     (16 )   3,434     2,928     (44 )   (14 )   2,870  
   
 
 
 
 
 
 
 
 
  General and administrative expenses     (305 )   —     4     (301 )   (225 )   —     4     (221 )
  Interest expense     (1,763 )   —     (6 )   (1,769 )   (1,826 )   —     (2 )   (1,828 )
  Interest income     426     —     8     434     375     —     6     381  
  Other expense     (449 )   —     (3 )   (452 )   (110 )   —     1     (109 )
  Other income     106     —     10     116     157     —     —     157  
  Gain on sale of investments     98     —     —     98     —     —     —     —  
  Loss on sale of subsidiary stock     (539 )   —     4     (535 )   —     —     —     —  
  Impairment expense     (28 )   —     11     (17 )   (16 )   —     —     (16 )
  Foreign currency transaction losses on net monetary position     (88 )   —     8     (80 )   (145 )   —     2     (143 )
  Equity in earnings of affiliates     72     —     1     73     71     —     (5 )   66  
   
 
 
 
 
 
 
 
 
  INCOME FROM CONTINUING OPERATIONS BEFORE INCOME BEFORE INCOME TAXES AND MINORITY INTEREST     928     52     21     1,001     1,209     (44 )   (8 )   1,157  
  Income tax expense     (334 )   (22 )   (6 )   (362 )   (483 )   19     (9 )   (473 )
  Minority interest expense     (459 )   —     (4 )   (463 )   (324 )   —     5     (319 )
   
 
 
 
 
 
 
 
 
  INCOME FROM CONTINUING OPERATIONS     135     30     11     176     402     (25 )   (12 )   365  
  Income from operations of discontinued businesses, net of income tax     105     —     2     107     188     —     —     188  
  Loss from disposal of discontinued businesses, net of income tax     (57 )   —     —     (57 )   —     —     —     —  
   
 
 
 
 
 
 
 
 
  INCOME BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE     183     30     13     226     590     (25 )   (12 )   553  
  Extraordinary items, net of income tax     21     —     —     21     —     —     —     —  
   
 
 
 
 
 
 
 
 
  INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE     204     30     13     247     590     (25 )   (12 )   553  
  Cumulative effect of change in accounting principle, net of income tax     —     —     —     —     (3 )   —     (1 )   (4 )
   
 
 
 
 
 
 
 
 
  Net income   $ 204   $ 30   $ 13   $ 247   $ 587   $ (25 ) $ (13 ) $ 549  
   
 
 
 
 
 
 
 
 
 
BASIC EARNINGS PER SHARE:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Income from continuing operations, net of tax   $ 0.21   $ 0.05   $ 0.01   $ 0.27   $ 0.62   $ (0.04 ) $ (0.02 ) $ 0.56  
  Discontinued operations, net of tax     0.07     —     —     0.07     0.29     —     —     0.29  
  Extraordinary item, net of tax     0.03     —     —     0.03     —     —     —     —  
  Cumulative effect of change in accounting principle, net of tax     —     —     —     —     (0.01 )   —     —     (0.01 )
   
 
 
 
 
 
 
 
 
  BASIC EARNINGS PER SHARE   $ 0.31   $ 0.05   $ 0.01   $ 0.37   $ 0.90   $ (0.04 ) $ (0.02 ) $ 0.84  
   
 
 
 
 
 
 
 
 

82

 
   Year Ended December 31, 2006
   Year Ended December 31, 2005
  
 
   December 31, 2007 Restatement
   December 31, 2007 Restatement
  
 
   2006
Form 10-K/A
   Deepwater
   Other
Adjustments
   2007
Form 10-K
   2006
Form 10-K/A
   Deepwater
   Other
Adjustments
   2007
Form 10-K
  
  DILUTED EARNINGS PER SHARE:                                                  
  Income from continuing operations, net of tax   $ 0.20   $ 0.04   $ 0.03   $ 0.27   $ 0.61   $ (0.04 ) $ (0.01 ) $ 0.56  
  Discontinued operations, net of tax     0.07     —     —     0.07     0.28     —     —     0.28  
  Extraordinary item, net of tax     0.03     —     —     0.03     —     —     —     —  
  Cumulative effect of change in accounting principle, net of tax     —     —     —     —     (0.01 )   —     —     (0.01 )
   
 
 
 
 
 
 
 
 
  DILUTED EARNINGS PER SHARE   $ 0.30   $ 0.04   $ 0.03   $ 0.37   $ 0.88   $ (0.04 ) $ (0.01 ) $ 0.83  
   
 
 
 
 
 
 
 
 

        The Other Adjustments in the table above include the following:

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        The following table details the impact of the restatement and certain reclassifications of businesses held for sale on the Company's Consolidated Balance Sheet as of December 31, 2006:

 
   As of December 31, 2006
  
 
    
    
   Held for Sale
    
  
 
   2006
Form 10-K/A
    
   2007
Form 10-K
  
 
   Restatement
   Maikuben
   Ekibastuz
  
ASSETS                                
  CURRENT ASSETS                                
    Cash and cash equivalents   $ 1,379   $ —   $ (2 ) $ (19 ) $ 1,358  
    Restricted cash     548     —     —     —     548  
    Short-term investments     640     —     —     —     640  
    Accounts receivable, net of reserves of $232     1,769     (1 )   (1 )   (2 )   1,765  
    Inventory     471     (11 )   (3 )   (12 )   445  
    Receivable from affiliates     76     15     —     —     91  
    Deferred income taxes—current     208     6     —     —     214  
    Prepaid expenses     109     1     —     (4 )   106  
    Other current assets     927     3     (1 )   (2 )   927  
    Current assets of held for sale and discontinued businesses     438     —     7     39     484  
   
 
 
 
 
 
      Total current assets     6,565     13     —     —     6,578  
   
 
 
 
 
 
  NONCURRENT ASSETS                                
  Property, Plant and Equipment:                                
    Land     928     —     —     (7 )   921  
    Electric generation and distribution assets     21,835     (230 )   (69 )   (72 )   21,464  
    Accumulated depreciation     (6,545 )   84     14     20     (6,427 )
    Construction in progress     979     25     (1 )   (16 )   987  
   
 
 
 
 
 
      Property, plant and equipment, net     17,197     (121 )   (56 )   (75 )   16,945  
   
 
 
 
 
 
  Other assets:                                
    Deferred financing costs, net of accumulated amortization of $188     279     33     (1 )         311  
    Investments in and advances to affiliates     595     (4 )   —     —     591  
    Debt service reserves and other deposits     524     (9 )   —     —     515  
    Goodwill     1,416     —     —     (2 )   1,414  
    Other intangible assets, net of accumulated amortization of $228     298     207     —     (7 )   498  
    Deferred income taxes—noncurrent     602     (1 )   —     —     601  
    Other assets     1,634     (46 )   —     (1 )   1,587  
    Noncurrent assets of held for sale and discontinued businesses     2,091     1     57     85     2,234  
   
 
 
 
 
 
      Total other assets     7,439     181     56     75     7,751  
   
 
 
 
 
 
  TOTAL ASSETS   $ 31,201   $ 73   $ —   $ —   $ 31,274  
   
 
 
 
 
 
LIABILITIES AND STOCKHOLDERS' EQUITY                                
  CURRENT LIABILITIES                                
    Accounts payable   $ 795   $ (2 ) $ —   $ (5 ) $ 788  
    Accrued interest     404     —     —     —     404  
    Accrued and other liabilities     2,131     19     (3 )   (4 )   2,143  
    Non-recourse debt-current portion     1,411     4     (3 )   (10 )   1,402  
    Current liabilities of held for sale and discontinued businesses     288     —     6     19     313  
   
 
 
 
 
 
      Total current liabilities     5,029     21     —     —     5,050  
   
 
 
 
 
 
LONG-TERM LIABILITIES                                
    Non-recourse debt     9,834     24     (11 )   (7 )   9,840  
    Recourse debt     4,790     —     —     —     4,790  
    Deferred income taxes-noncurrent     803     28     (13 )   (9 )   809  
    Pension liabilities and other post-retirement liabilities     844     —     —     —     844  
    Other long-term liabilities     3,554     6     (1 )   (3 )   3,556  
    Long-term liabilities of held for sale and discontinued businesses     434     1     25     19     479  
   
 
 
 
 
 
      Total long-term liabilities     20,259     59     —     —     20,318  
   
 
 
 
 
 
  Minority Interest (including discontinued businesses of $175     2,948     (21 )   —     —     2,927  
  Commitments and Contingent Liabilities (see Notes 12 and 13)                                
STOCKHOLDERS' EQUITY                                
    Common stock ($.01 par value, 1,200,000,000 shares authorized; 665,126,309 shares issued and outstanding at December 31, 2006     7     —     —     —     7  
    Additional paid-in capital     6,654     5     —     —     6,659  
    Accumulated deficit     (1,096 )   3     —     —     (1,093 )
    Accumulated other comprehensive loss     (2,600 )   6     —     —     (2,594 )
   
 
 
 
 
 
      Total stockholders' equity     2,965     14     —     —     2,979  
   
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY   $ 31,201   $ 73   $ —   $ —   $ 31,274  
   
 
 
 
 
 

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        The discussion below highlights the impact of certain adjustments on the Company's Consolidated Balance Sheet as of December 31, 2006. These errors were neither material individually, or in the aggregate. The primary adjustments recorded were as follows:

        The restatement adjustments had no material impact on net cash flows.

Overview of Our Business

        AES is a global power company. We own a portfolio of electricity generation and distribution businesses with generation capacity totaling approximately 43,000 MW and distribution networks serving over 11 million people. Our global footprint includes operations in 28 countries on five continents with 81% of our revenue for 2007 generated outside the United States.

        We operate two primary lines 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 within a defined service area. Each of our primary lines of business generates approximately half of our revenues. We are also developing an Alternative Energy business. Alternative Energy includes strategic initiatives such as wind generation and climate solutions, such as the production of emissions credits.

        Generation.    We currently own or operate 121 Generation facilities in 26 countries on five continents. We also have 12 new Generation facilities under construction. Our 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 power purchase agreements, to wholesale customers. Approximately 62% of the revenues from our Generation businesses during 2007 was derived from plants that operate under power purchase agreements of five years or longer for 75% or more of their output capacity. These businesses

85


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 low-cost coal fired plants, we have hedged the majority of our exposure to fuel, energy and emissions pricing for the next several years

        Utilities.    Our Utilities businesses distribute power to more than 11 million people in eight countries on five continents. Our Utilities business consists primarily of 15 companies owned and/or operated under management agreements, all of which operate in a defined service area. These businesses have a variety of structures ranging from pure distribution businesses to fully integrated utilities, which generate, transmit and distribute power. In May 2007, we completed the sale of EDC, our utility in Venezuela, for $739 million net of tax. As a result of the sale, we recognized an impairment charge of $680 million which represented the difference between the net book value of our investment in EDC and the sales price. This impairment charge and the results of the operations for EDC are reflected as discontinued operations for all periods presented in the Consolidated Financial Statements included in Item 8 of this Form 10-K.

        Alternative Energy.    Alternative Energy is not currently one of our primary lines of business, but we expect this high growth sector to be a material contributor to our revenue and gross margin in the future. As demand for more sustainable and environmentally friendly sources of energy grows, we continue to invest in Alternative Energy with a current focus on increasing our wind power capacity and building our climate solutions business for GHG reduction. AES entered the wind business in 2005 and today we have ten wind generation facilities with more than 1,000 MW of wind projects in operation. In addition, we are developing initiatives in other countries that are approved for GHG projects under the Kyoto Protocol and marketing the credits created. AES operates in 18 of the developing countries that are eligible for these credits which provides us with a good foundation for this new business.

        Segments.    Our Generation and Utilities businesses are 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. Our Asia region operates only Generation businesses. Accordingly, these businesses and regions account for seven operating segments. "Corporate and Other" includes corporate overhead costs which are not directly associated with the operations of our seven primary operating 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 operational costs related to our Alternative Energy business, which is currently not material to our operations.

        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

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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 power purchase agreements, 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 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, 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. In 2007, these afforts helped us overcome certain challenges that we face in our business, such as issues related to fuel supplies and forced purchases on the spot market at high prices.

Highlights of 2007

        Results of Operations.    In 2007, 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 2007 results of operations were positively impacted by a number of factors including, but not limited to: higher tariff rates at certain of our distribution businesses; contributions from recent acquisitions including TEG/TEP in Mexico in February 2007, where significant operational improvements were achieved, and a full year of operations at Itabo in the Dominican Republic; increased usage in both Brazil and the Ukraine; and favorable foreign currency translation at our Utilities businesses in Latin America.

        However, our business faced numerous challenges as well during 2007. Our results were negatively impacted by increased costs from gas supply curtailments, drier than normal hydrology and high spot prices for electricity at the Company's businesses in the Southern Cone of Latin America. Significantly lower than normal rainfall in Argentina caused our hydro-powered generation plant at AES Alicura to operate less. Therefore, we had to rely on our other plants, which use higher cost fuel sources, to deliver energy to our customers. The drier than normal hydrology conditions and other factors in Argentina resulted in significantly increased demand for gas and, in response, the government of Argentina placed restrictions (curtailments) on gas exports to Chile and Brazil. AES Uruguaiana, our gas powered generation plant in Brazil, receives its gas from Argentina and was negatively impacted by the Argentine gas curtailment because AES Uruguaina is obligated under its contract to deliver power to its customers at a contracted price. As a result, AES Uruguaina had to purchase fuel and energy on the open market at higher spot prices, which exceeded the amount that AES Uruguaiana could recover under its existing contracts. In the fourth quarter of 2007, we recognized an impairment charge of approximately $352 million with respect to our investment in AES Uruguaiana. Some of our gas-fired generation businesses servicing Chile were similarly impacted by the Argentine gas curtailment resulting in the purchase of higher priced fuel to operate these plants.

        During 2007, we recognized additional impairment charges of $52 million related to our investment in AgCert, a United Kingdom company that produces carbon emission credits ("CERs"), and $14 million related to prepaid CERs, due to AgCert's potential inability to deliver the CERs or to

87


repay the sums advanced by us; $25 million related to our Placerita subsidiary, a gas-fired combined cycle generation plant located in the United States, due to damage sustained to one of the plant's gas turbines; and $10 million related to the curtailment of operations at Coal Creek Minerals, LLC, a coal mining company owned by our subsidiary Cavanal Minerals. Our results of operations were also significantly affected by increased fuel costs across all four of our regions; a tariff reduction at Eletropaulo, one of our Latin America Utilities businesses; the sale of EDC; increased interest expense; and higher overhead costs as a result of our financial restatements and continued remediation of the material weaknesses in our internal control of financial reporting.

        Despite these challenges, we still had strong operating performance as demonstrated by the following financial achievements:

        We were also able to improved the parent company's capital structure by refinancing existing secured debt with unsecured debt at more favorable rates and with longer average maturities, which resulted in a decrease of secured debt as a percentage of total parent company debt from approximately 42% to 17%.

        Growth Strategy and Portfolio Management.    During 2007, we continued to execute our growth strategy. In February 2007, we acquired TEG/TEP, two 230 MW petroleum coke-fired power plants in Mexico, for $611 million, including cash and the assumption of debt. We added 427 MW of capacity to our wind operation portfolio, including the start-up of commercial operations at Buffalo Gap and the acquisition of Midwest Wind. Additionally, we commenced construction of a 170 MW expansion to Buffalo Gap III, one of our existing wind farms, which is expected to commence commercial operation in 2008. In early 2008, we also announced the Company's acquisition of a coal-fired generation facility in the Philippines for $930 million.

        The Company's growth project backlog (growth projects under construction) as of December 31, 2007 totaled over 2,240 GMW of new generation capacity with a total expected investment of approximately $4 billion through 2011. This includes fossil-fueled projects in Chile, Bulgaria and Jordan, hydroelectric projects in Panama and Turkey and a wind project in the United States. We also secured early-stage memorandums of understanding to develop power projects in countries such as Vietnam, Indonesia and India. Our business strategy is focused on global growth in our core Generation and Utilities businesses along with growth in related markets such as Alternative Energy, electricity transmission and water desalination. The Company sees growth investments as the most significant contributor to long-term shareholder value creation.

        The Company expects to fund growth investments from available cash, net cash from operating activities and/or the proceeds from debt (both recourse and non-recourse) and equity financing, asset sales and partner equity contributions. Certain of the Alternative Energy businesses may be considered start-up businesses that will need to be funded internally through cash equity contributions, and may have limited non-recourse debt financing opportunities initially. We see sufficient attractive investment opportunities that may exceed available cash and net cash from operating activities in future periods.

        The Company's growth strategies are complemented by an increased emphasis on portfolio management through which AES has and will continue to sell or monetize a portion of certain businesses or assets when market values appear significantly higher than the Company's assessment of

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its value as part of the AES portfolio. Portfolio management was an important area of focus in 2007 and will be a continuing area of focus in 2008 and beyond. In October 2007, we sold 10% of our interest in Gener, our subsidiary in Chile, for $306 million, which increased the liquidity of those shares and we believe reduced the discount the local Chilean stock market had been placing on Gener shares due to their prior illiquidity. In early 2008, we announced the sale of Ekibastuz and Maikuben, two of our Generation businesses in Kazakhstan, for an upfront price of $1.1 billion and management fees and earn out provisions that could generate additional consideration of up to approximately $380 million.

Outlook for the Future

        Management's strategy is to continue building on our traditional lines of business while expanding into other essential energy-related areas, such as Alternative Energy. As part of that mission, AES strives to improve both short and long-term profitability while positioning the Company to continue our success in the future.

        As we look to 2008 and beyond, we will work toward the following goals:

The Company also believes that high oil prices, increasing regulation of greenhouse gases, faster than expected global economic growth and a weak U.S. Dollar present opportunities for value creation, based on the Company's current business portfolio strategies. Slower global economic growth, which will impact demand growth for utilities and some generation businesses, is one of the most significant potential obstacles affecting value creation. Other important scenarios that could impair future value include higher oil prices and a strong U.S. Dollar.

2007 Performance Highlights

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
 
    
   (Restated)

   (Restated)

  
 
   ($'s in millions, except per share amounts)

  
Revenue   $ 13,588   $ 11,576   $ 10,247  
Gross Margin   $ 3,409   $ 3,434   $ 2,870  
Gross Margin as a % of Revenue     25.1 %   29.7 %   28.0 %
Diluted Earnings Per Share from Continuing Operations   $ 0.73   $ 0.27   $ 0.56  
Net Cash Provided by Operating Activities   $ 2,357   $ 2,351   $ 2,220  

        The following is a summary discussion of the consolidated revenue, gross margin, earnings per share, and net cash from operating activities.

        We achieved record revenues of $13.6 billion, an increase of 17% from $11.6 billion the previous year. The increase in revenues was primarily driven by higher prices across our Generation businesses

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of approximately $688 million; contributions from new acquisitions such as TEG/TEP and Itabo of approximately $286 million; and favorable currency translation of approximately $636 million primarily at our Utilities businesses in Latin America.

        Gross margin remained relatively flat at $3.4 billion, as improved operations in North America, favorable foreign currency translation in Brazil and contributions from recent acquisitions were offset by tariff reductions at Eletropaulo and ongoing gas supply curtailments and drier than normal hydrology at our businesses in Argentina and Chile.

        Diluted earnings per share from continuing operations increased $0.46 per share to $0.73 per share compared to $0.27 per share in 2006. This increase was primarily driven by higher revenues as a result of pass through fuel costs and the 2006 impact of our Brasiliana restructuring of approximately $0.76 per share; impairment charges related to Uruguaiana and AgCert of approximately ($0.34) per share; and the impact of the Mexican Tax Law Change of approximately ($0.07) per share. The remaining growth in earnings per share was attributable to the overall growth of the business.

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        Net cash provided by operating activities remained relatively flat at $2.4 billion. Excluding any contribution from EDC, net cash from operating activities would have increased by approximately $119 million, an increase of 6% from $2.1 billion in 2006 to $2.2 billion in 2007.

Consolidated Results of Operations

 
   Year Ended December 31,
  
Results of operations
   2007
   2006
(Restated)
   2005
(Restated)
   $ change
2007 vs. 2006
   $ change
2006 vs. 2005
  
 
   (in millions, except per share amounts)

  
Revenue:                                
  Latin America Generation   $ 3,510   $ 2,615   $ 2,145   $ 895   $ 470  
  Latin America Utilities     5,172     4,552     4,127     620     425  
  North America Generation     2,168     1,928     1,745     240     183  
  North America Utilities     1,052     1,032     951     20     81  
  Europe & Africa Generation     975     852     735     123     117  
  Europe & Africa Utilities     660     570     506     90     64  
  Asia Generation     889     785     600     104     185  
  Corporate and Other(1)     (838 )   (758 )   (562 )   (80 )   (196 )
   
 
 
 
 
 
Total Revenue   $ 13,588   $ 11,576   $ 10,247   $ 2,012   $ 1,329  
   
 
 
 
 
 
Gross Margin:                                
  Latin America Generation   $ 955   $ 1,052   $ 857   $ (97 ) $ 195  
  Latin America Utilities     865     888     584     (23 )   304  
  North America Generation     702     610     556     92     54  
  North America Utilities     313     277     301     36     (24 )
  Europe & Africa Generation     275     247     185     28     62  
  Europe & Africa Utilities     63     103     109     (40 )   (6 )
  Asia Generation     193     201     243     (8 )   (42 )
Total Corporate and Other(2)     (336 )   (245 )   (186 )   (91 )   (59 )
Interest expense     (1,788 )   (1,769 )   (1,828 )   (19 )   59  
Interest income     500     434     381     66     53  
Other expense     (255 )   (452 )   (109 )   197     (343 )
Other income     358     116     157     242     (41 )
Gain on sale of investments     134     98     —     36     98  
Loss on sale of subsidiary stock     —     (535 )   —     535     (535 )
Impairment expense     (408 )   (17 )   (16 )   (391 )   (1 )
Foreign currency transaction gains (losses) on net monetary position     24     (80 )   (143 )   104     63  
Equity in earnings of affiliates     76     73     66     3     7  
Other non-operating expense     (57 )   —     —     (57 )   —  
Income tax expense     (685 )   (362 )   (473 )   (323 )   111  
Minority interest expense     (434 )   (463 )   (319 )   29     (144 )
   
 
 
 
 
 
Income from continuing operations     495     176     365     319     (189 )
Income from operations of discontinued businesses     71     107     188     (36 )   (81 )

Loss from disposal of discontinued businesses
 
 
(661
)
 
(57
)
 
—
 
 
(604
)
 
(57
)

Extraordinary items
 
 
—
 
 
21
 
 
—
 
 
(21
)
 
21
 
Cumulative effect of accounting change     —     —     (4 )   —     4  
   
 
 
 
 
 
Net (loss) income   $ (95 ) $ 247   $ 549   $ (342 ) $ (302 )
   
 
 
 
 
 
Per share data:                                
Basic income per share from continuing operations   $ 0.74   $ 0.27   $ 0.56   $ 0.47   $ (0.29 )
Diluted income per share from continuing operations   $ 0.73   $ 0.27   $ 0.56   $ 0.46   $ (0.29 )
(1)
Corporate and Other includes revenues from Alternative Energy and inter-segment eliminations of revenues related to transfers of electricity from Tietê (generation) to Eletropaulo (utility).

(2)
Total Corporate and Other expenses include corporate general and administrative expenses 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 for our Generation and Utilities segments in Latin America for the periods indicated (in millions):

Latin America
   For the Years Ended December 31,
  
 
   2007
   2006
   2005
  
 
    
    
   (Restated)
   (Restated)
  
Revenue
   Revenue
   % of Total
Revenue
   Revenue
   % of Total
Revenue
   Revenue
   % of Total
Revenue
  
Latin America Generation   $ 3,510   26 % $ 2,615   23 % $ 2,145   21 %
Latin America Utilities     5,172   38 %   4,552   39 %   4,127   40 %

Fiscal Year 2007 versus 2006 Revenue

        Generation revenue increased $895 million, or 34%, from the previous year primarily due to higher rates and volume at Gener (in Chile) and Alicura (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 contributed approximately $87 million in revenue. The impact of favorable foreign currency translation was approximately $38 million.

        Utilities revenue increased $620 million, or 14%, from the previous year. This increase was primarily the result of favorable foreign currency translation of $493 million, and increased rates and volume in Brazil at our Sul facility and at our plants in El Salvador of $58 million and $41 million, respectively, offset by net decreases in tariff of $24 million at Eletropaulo (in Brazil).

Fiscal Year 2006 versus 2005 Revenue

        Generation revenue increased $470 million, or 22%, from the previous year primarily due to higher rates and volume at our Chile and Argentina businesses of $86 million and $99 million, respectively; higher sales offset by intercompany sales from Tietê in Brazil to Eletropaulo of approximately $137 million; and our increase in ownership of the controlling shares of Itabo in the Dominican Republic contributed approximately $115 million in revenue.

        Utilities revenue increased $425 million, or 10%, from the previous year. This increase was driven by favorable foreign currency translation of $413 million; a net increase of $19 million in rates and volume at Eletropaulo and increased tariff rates at CAESS and Clesa in El Salvador of $62 million, offset by lower intercompany sales at Infoenergy of $40 million.

        The following table summarizes gross margin for the Generation and Utilities segments in Latin America for the periods indicated (in millions):

Latin America
   For the Years Ended December 31,
  
 
   2007
   2006
   2005
  
 
    
    
   (Restated)
   (Restated)
  
Gross Margin
   Gross Margin
   % of Total
Gross
Margin
   Gross Margin
   % of Total
Gross
Margin
   Gross Margin
   % of Total
Gross
Margin
  
Latin America Generation   $ 955   28 % $ 1,052   31 % $ 857   30 %
Latin America Utilities     865   25 %   888   26 %   584   20 %

92

Fiscal Year 2007 versus 2006 Gross Margin

        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 in the Dominican Republic of $23 million and intercompany sales in Tietê of $103 million.

        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 (in Brazil) had increased rates and volume of $27 million and favorable foreign currency translation of $19 million.

Fiscal Year 2006 versus 2005 Gross Margin

        Generation gross margin increased $195 million, or 23%, from the previous year due to net increases in intercompany and volume sales from Tietê to Eletropaulo in Brazil of $137 million, an increase in spot market and contract energy prices at Gener in Chile of $88 million and $13 million from the acquisition of a controlling interest in Itabo in the Dominican Republic, these were partially offset by unfavorable foreign currency impacts of $30 million.

        Utilities gross margin increased $304 million, or 52%, from the previous year due to $192 million of additional gross bad debts reserves recognized in the second quarter of 2005 related to the collectibility of certain municipal receivables at Eletropaulo and Sul in Brazil, and favorable foreign currency impacts of $170 million. These increases were partially offset by higher legal reserves at Eletropaulo of $56 million.

North America

        The following table summarizes revenue for our Generation and Utilities segments in North America for the periods indicated (in millions):

North America
   For the Years Ended December 31,
  
 
   2007
   2006
   2005
  
 
    
    
   (Restated)
   (Restated)
  
Revenue
   Revenue
   % of Total
Revenue
   Revenue
   % of Total
Revenue
   Revenue
   % of Total
Revenue
  
North America Generation   $ 2,168   16 % $ 1,928   17 % $ 1,745   17 %
North America Utilities     1,052   8 %   1,032   9 %   951   9 %

Fiscal Year 2007 versus 2006 Revenue

        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 in Mexico 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 in Texas and lower emission sales of $39 million.

        Utilities revenue increased $20 million, or 2%, from the previous year primarily due to increased volume, offset by a slight decrease in tariff rates at IPL.

93

Fiscal Year 2006 versus 2005 Revenue

        Generation revenue increased $183 million, or 11%, due to the change in the mark-to-market adjustment related to Deepwater of approximately $96 million and an increase in revenues of $76 million at the New York facilities due to an increase in rates.

        Utilities revenue increased $81 million, or 9%, from the previous year primarily attributable to higher pricing at IPL due to the pass through of higher fuel costs.

        The following table summarizes gross margin for the Generation and Utilities segments in North America for the periods indicated (in millions):

North America
   For the Years Ended December 31,
  
 
   2007
   2006
   2005
  
 
    
    
   (Restated)
   (Restated)
  
Gross Margin
   Gross Margin
   % of Total
Gross
Margin
   Gross Margin
   % of Total
Gross
Margin
   Gross Margin
   % of Total
Gross
Margin
  
North America Generation   $ 702   21 % $ 610   18 % $ 556   19 %
North America Utilities     313   9 %   277   8 %   301   10 %

Fiscal Year 2007 versus 2006 Gross Margin

        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 in Mexico 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.

        Utilities gross margin increased $36 million, or 13%, primarily due to increased volume sales and deferred fuel cost recoveries at IPL.

Fiscal Year 2006 versus 2005 Gross Margin

        Generation gross margin increased $54 million, or 10%, from the previous year primarily due to the impact of the marked-to-market adjustment related to Deepwater of approximately $96 million, offset by a decrease of approximately $38 million related to outages at Warrior Run, Hawaii and Ironwood as well as a scheduled reduction in pricing of the power purchase agreements for our Hawaii plant of $13 million.

        Utilities gross margin decreased $24 million, or 8%, from the previous year primarily due to higher maintenance costs at IPL of $23 million as part of a scheduled outage on one of its large base load coal fired units that coincided with a project to enhance environmental emission technology to significantly reduce emissions as well as increased emissions allowances.

Europe & Africa

        The following table summarizes revenue for the Generation and Utilities segments in Europe & Africa for the periods indicated (in millions):

Europe & Africa
   For the Years Ended December 31,
  
 
   2007
   2006
   2005
  
 
    
    
   (Restated)
   (Restated)
  
Revenue
   Revenue
   % of Total
Revenue
   Revenue
   % of Total
Revenue
   Revenue
   % of Total
Revenue
  
Europe & Africa Generation   $ 975   7 % $ 852   7 % $ 735   7 %
Europe & Africa Utilities     660   5 %   570   5 %   506   5 %

94

Fiscal Year 2007 versus 2006 Revenue

        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.

        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.

Fiscal Year 2006 versus 2005 Revenue

        Generation revenue increased $117 million, or 16%, primarily due to increased volume sales and contract energy prices at Tisza II in Hungary of $73 million offset by decreased volume at Ekibastuz in Kazakhstan of $30 million, increased sales from our centralized trading office in Altai, Kazakhstan of $58 million, and CO2 emission allowance sales in Hungary of $16 million and Bohemia in the Czech Republic of $12 million.

        Utilities revenue increased $64 million, or 13%, primarily due to increased demand and tariff rates at SONEL in Cameroon of $17 million and $46 million at our businesses in the Ukraine.

        The following table summarizes gross margin for the Generation and Utilities segments in Europe & Africa for the periods indicated (in millions):

Europe & Africa
   For the Years Ended December 31,
  
 
   2007
   2006
   2005
  
 
    
    
   (Restated)
   (Restated)
  
Gross Margin
   Gross Margin
   % of Total
Gross
Margin
   Gross Margin
   % of Total
Gross
Margin
   Gross Margin
   % of Total
Gross
Margin
  
Europe & Africa Generation   $ 275   8 % $ 247   7 % $ 185   6 %
Europe & Africa Utilities     63   2 %   103   3 %   109   4 %

Fiscal Year 2007 versus 2006 Gross Margin

        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.

        Utilities gross margin decreased $40 million, or 39