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As filed with the Securities and Exchange Commission on December 17, 2007

Registration No. 333-147951

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM S-4/A

Amendment No. 1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

THE AES CORPORATION
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)		   4991
(Primary Standard Industrial
Classification Code Number)		   54-1163725
(I.R.S. Employer
Identification No.)

4300 Wilson Boulevard, Suite 1100
Arlington, Virginia 22203
(703) 522-1315
(Address, including zip code, and telephone number,
including area code, of Registrant's principal executive offices)

Brian Miller
Executive Vice President,
General Counsel and Secretary
The AES Corporation
4300 Wilson Boulevard
Arlington, Virginia
(703) 522-1315
(Name, address, including zip code, and telephone number,
including area code, of agent for service)

Copies to:

Andrew Schleider, Esq.
Shearman & Sterling LLP
599 Lexington Avenue
New York, New York 10022

        Approximate date of commencement of proposed sale of the securities to the public: Upon consummation of the Exchange Offer described herein.

        If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. o

        If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

        If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

CALCULATION OF REGISTRATION FEE
Title of Each Class of
Securities to be Registered
   Amount to
be Registered
   Proposed Maximum
Offering Price
Per Unit(1)
   Proposed Maximum
Aggregate Offering
Price
   Amount of
Registration Fee
7.75% senior notes due 2015   $500,000,000   100%   $500,000,000   $15,350
8.0% senior notes due 2017   $1,500,000,000   100%   $1,500,000,000   $46,050
(1)
Estimated solely for the purposes of calculating the registration fee in accordance with Rule 457(f) under the Securities Act of 1933, as amended.

        The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, dated December 17, 2007

PROSPECTUS

         LOGO

The AES Corporation

OFFER TO EXCHANGE
Unregistered 7.75% Senior Notes due 2015
($500,000,000 aggregate principal amount issued October 15, 2007)
for
7.75% Senior Notes due 2015
that have been registered under the Securities Act of 1933
and
Unregistered 8.0% Senior Notes due 2017
($1,500,000,000 aggregate principal amount issued October 15, 2007)
for
8.0% Senior Notes due 2017
that have been registered under the Securities Act of 1933

TERMS OF EXCHANGE OFFER


        Please see "Risk Factors" beginning on page 13 for a discussion of certain factors you should consider in connection with the exchange offer.

        Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the senior securities to be distributed in the exchange offer, nor have any of these organizations determined that this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is                  , 2007


TABLE OF CONTENTS

 
   Page
TABLE OF CONTENTS   i
FORWARD-LOOKING STATEMENTS   ii
SUMMARY   1
RISK FACTORS   13
RATIO OF EARNINGS TO FIXED CHARGES   31
USE OF PROCEEDS   31
SELECTED CONSOLIDATED FINANCIAL DATA   32
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   34
BUSINESS   89
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE   134
EXECUTIVE COMPENSATION   139
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS   175
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS   177
THE EXCHANGE OFFER   178
DESCRIPTION OF THE EXCHANGE NOTES   189
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS   203
PLAN OF DISTRIBUTION   207
LEGAL MATTERS   207
EXPERTS   207
CHANGES IN REGISTRANT'S CERTIFYING ACCOUNTANT   208
WHERE YOU CAN FIND MORE INFORMATION   209
INDEX TO FINANCIAL STATEMENTS   F-1

        You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different or additional information. If anyone provides you with different or additional information, you should not rely on it. You should assume that the information contained in this prospectus is accurate only as of the date of this prospectus. Our business, financial condition, results of operations and prospects may have changed since then. We are not making an offer of the notes in any jurisdiction where the offer is not permitted.

        Unless the context otherwise requires, references to "AES," "we," "us" and "our" in this prospectus are references to The AES Corporation, including all of its consolidated subsidiaries and affiliates. The term "The AES Corporation" or "parent company" refers only to the parent, publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates. References to "$" and "dollars" are to United States dollars.

        This prospectus will refer to the 7.75% senior notes due 2015 issued on October 15, 2007 as the "unregistered 2015 notes", and the 8.0% senior notes due 2017 issued on October 15, 2007 as the "unregistered 2017 notes", and collectively as the "unregistered notes." This prospectus will refer to the registered 7.75% senior notes due 2015 as the "exchange 2015 notes," and the registered 8.0% senior notes due 2017 as the "exchange 2017 notes," and collectively as the "exchange notes." The unregistered 2015 notes and the exchange 2015 notes are collectively referred to as the "2015 notes," and the unregistered 2017 notes and the exchange 2017 notes are collectively referred to as the "2017 notes." The unregistered notes and the exchange notes are collectively referred to as the "notes."

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        Each holder of an unregistered note wishing to accept the exchange offer must deliver the unregistered notes to be exchanged, together with the letter of transmittal that accompanies this prospectus and any other required documentation, to the exchange agent identified in this prospectus. Alternatively, you may effect a tender of unregistered notes by book-entry transfer into the exchange agent's account at The Depository Trust Company ("DTC"). All deliveries are at the risk of the holder. You can find detailed instructions concerning delivery in the section called "The Exchange Offer" in this prospectus and in the accompanying letter of transmittal.

        If you are a broker-dealer that receives exchange notes for your own account you must acknowledge that you will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of the exchange notes. The letter of transmittal accompanying this prospectus states that by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an "underwriter" within the meaning of the Securities Act. You may use this prospectus, as we may amend or supplement it in the future, for your resales of exchange notes. We will make this prospectus available to any broker-dealer for use in connection with any such resale for a period of 90 days after the date of expiration of this exchange offer or such shorter period which will terminate when the broker-dealers have completed all resales subject to applicable prospectus delivery requirements.


FORWARD-LOOKING STATEMENTS

        Certain statements contained in this prospectus that are not purely historical are forward-looking statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. 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, uncertainties and other factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements. In addition to the factors described under "Risk Factors" in this prospectus, some of these factors include:

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        In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this prospectus might not occur. 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.

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SUMMARY

        This summary highlights selected information from this prospectus. It may not contain all of the information that is important to you. We urge you to read carefully the entire prospectus and the other documents to which it refers to understand fully the terms of the exchange notes. Unless the context otherwise requires, the terms "AES," "we," "our," "us," and "the Company" refer to The AES Corporation, including all of its subsidiaries and affiliates, collectively.


The Company

        We are a global power holding company and through our subsidiaries, we operate a portfolio of electricity generation and distribution businesses and investments on five continents and in 28 countries. We operate two main types of businesses. The first is our distribution and transmission business, which we refer to as Utilities, in which we operate electric utilities and sell power to customers in the retail (including residential), commercial, industrial and governmental sectors. These customers are typically end-users of electricity. The second is our Generation business, where we sell power to wholesale customers such as utilities or other intermediaries. In addition to our traditional generation and distribution operations, we are also developing an alternative energy business. The revenues and earnings growth of both our Utilities and Generation businesses vary with changes in electricity demand.

        Our Utilities business consists primarily of 15 distribution companies owned or operated under management agreements in eight countries with over 11 million end-user customers. All of these companies operate in a defined service area. This segment is composed of:

        Performance drivers for these businesses include, among other things, 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.

        Utilities face relatively little direct competition due to significant barriers to entry which are present in these markets. In this segment, we primarily face competition in our efforts to acquire businesses. 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 have accumulated more significant portfolios. Relevant competitive factors for Utilities include financial resources, governmental assistance, regulatory restrictions and access to non-recourse financing. In

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certain locations, our utilities 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. We can provide no assurance that deregulation will not adversely affect the future operations, cash flows and financial condition of our Utilities business. The results of operations of our Utilities business are sensitive to changes in economic growth and regulation, abnormal weather conditions in the area in which they operate, as well as the success of the operational changes that have been implemented (especially in emerging markets).

        In our Generation business we generate and sell electricity primarily to wholesale customers. Performance drivers for our Generation business include, among other things, plant reliability, fuel costs and fixed-cost management. Growth in this business is largely tied to securing new power purchase agreements, expanding capacity in our existing facilities and building new power plants. Our Generation business includes our interests in 97 power generation facilities owned or operated under management agreements totaling 37 gigawatts of capacity installed in 22 countries.

        Approximately 68% of the revenues from our Generation business are from plants that operate under power purchase agreements of five years or longer for 75% or more of the output capacity. These long-term contracts reduce the risk associated with volatility in the market price for electricity. We also reduce our exposure to fuel supply risks by entering into long-term fuel supply contracts or through fuel tolling contracts where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. As a result of these contractual agreements, these facilities have relatively predictable cash flows and earnings. These facilities face most of their competition prior to the execution of a power sales agreement, often during the development phase of a project or upon expiration of an existing agreement. Our competitors for these contracts include other independent power producers and equipment manufacturers, as well as various utilities and their affiliates. During the operational phase, we traditionally have faced limited competition due to the long-term nature of the generation contracts. However, since competitive power markets have been introduced and new market participants have been added, we have and will continue to encounter increased competition in attracting new customers and maintaining our current customers as our existing contracts expire.

        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 facilities 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. These facilities compete with numerous other independent power producers, energy marketers and traders, energy merchants, transmission and distribution providers and retail energy suppliers. Competitive factors for these facilities include price, reliability, operational cost and third party credit requirements.

        As described above, AES operates within two primary businesses, the generation of electricity and the distribution of electricity. AES previously reported its financial results in three business segments: contract generation, competitive supply and regulated utilities. As of December 31, 2006, we have changed the definition of our segments in order to report information by geographic region and by line of business. We believe this change more accurately reflects the manner in which we manage the Company.

        Our businesses include Utilities and Generation within four defined geographic regions: (1) North America, (2) Latin America, (3) Europe, CIS and Africa, which we refer to as "Europe & Africa" and (4) Asia and the Middle East, which we refer to as "Asia". Three regions, North America, Latin America and Europe & Africa, are engaged in both our Generation and Utility businesses. Our Asia region only has Generation businesses. Accordingly, these businesses and regions account for seven segments. "Corporate and Other" includes corporate overhead costs which are not directly associated

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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 development and operational costs related to our Alternative Energy business which is currently not material to our presentation of operating segments. Under AES's Alternative Energy group, AES operates 1,015 MW of wind generation in the United States.

        Our goal is to continue building on our traditional lines of business, while expanding into other essential energy-related areas. We believe that this is a natural expansion for us. 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 also will build on our existing capabilities in areas beyond power including greenhouse gas emissions offset projects, electricity transmission, water desalination, and other businesses. 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 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. We continue to emphasize growth through "greenfield" development, platform expansion, privatization of government-owned assets, and mergers and acquisitions and continue to develop and maintain a strong development pipeline of projects and opportunities. The Company sees growth investments as the most significant contributor to long-term shareholder value creation. 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 own assessment of value in the AES portfolio.

        Underpinning this growth focus is an operating model which benefits from a diverse power generation portfolio that is largely contracted, reducing fuel cost and demand risks, and from an electric utility portfolio heavily weighted to faster-growing emerging markets.

        The Company believes that success with its business development activities will be the single most important factor in its financial success in terms of value creation and it is directing increasing resources in support of business development globally. The Company also believes that high oil prices, increasing regulation of greenhouse gases, faster than expected global economic growth and a weak dollar present opportunities for value creation, based on the Company's current business portfolio and business strategies. Slower global economic growth, which will impact demand growth for utilities and some generation businesses, is one of the most significant downside scenarios affecting value creation. Other important scenarios that could impair future value include low oil prices and a strong dollar.

        Beginning with our annual report on Form 10-K, as amended for the year ended December 31, 2006, we realigned our reportable segments. We previously reported under three segments: Regulated Utilities, Contract Generation and Competitive Supply. We currently report seven segments, which include:

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        The new segment reporting more accurately reflects how we view and manage the Company internally in terms of decision making and assessing performance. We manage our business primarily on a geographic basis in two distinct lines of business—the generation of electricity and the distribution of electricity. These businesses are distinguished by the nature of the customers, operational differences, cost structure, regulatory environment and risk exposure.

Latin America

        Our Latin American operations accounted for 63%, 61% and 55% of consolidated revenues in 2006, 2005, and 2004, respectively. AES began operating in Latin America in 1993 when it acquired the CTSN power plant in Argentina. Since that time, AES has expanded its presence in the region and now has operations in eight Latin American countries. These operations include a total of 48 generation plants owned and operated under management agreements with a total generating capacity of 11,224 MW. AES owns and operates eight utilities, distributing a total of 45,785 GWh, in addition to operating one utility under management agreement, which distributes 1,626 GWh to customers.

        Our Generation business in Latin America consists of 48 generation facilities with the capacity to generate 11,224 MW. This capacity includes our new 125 MW Los Vientos diesel-fired peaking facility, which came on line in January, 2007 and serves the largest power market in Chile. AES also has two coal plants under construction in Chile, Guacolda III and Ventanas III with 152 MW and 267 MW generation capacity respectively, and one plant under construction in Panama, the Changuinola hydro plant with 223 MW capacity.

        We own eight Utility businesses, including electricity distribution businesses located in Argentina (EDELAP and EDES), Brazil (AES Eletropaulo and AES Sul) and El Salvador (CAESS, AES CLESA, DEUSEM and EEO). Another Utility business, La Electricidad de Caracas ("EDC") was sold in May 2007. We also manage another utility under contract in the Dominican Republic. These businesses sell electricity under regulated tariff agreements and each has transmission and distribution capabilities. AES 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. 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.

North America

        Our North American operations accounted for 25%, 26% and 29% of consolidated revenues in 2006, 2005 and 2004, respectively. AES began operating in North America in 1985, when it developed its first power plant in Deepwater, Texas. Since then AES has grown its North America business and currently owns a total of 21 generation facilities with 9,892 MW generating capacity and one integrated utility, distributing approximately 16,287 GWh of electricity to customers with 3,599 MW of generation capacity.

        In North America, we have 21 generation facilities, including seven gas-fired plants, ten coal-fired plants, three petroleum coke-fired plants and one biomass-fired plant, in the United States, Puerto Rico and Mexico.

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        We have one integrated utility in North America, IPL, which we own through IPALCO Enterprises Inc. ("IPALCO"), the parent holding company of IPL. IPL is engaged in generating, transmitting, distributing and selling electric energy to more than 465,000 customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL also owns and operates four generation facilities. Two 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 3,599 MW.

Europe & Africa

        Our operations in Europe & Africa accounted for 12%, 12% and 13% of our consolidated revenues in 2006, 2005 and 2004, respectively. AES began operations in Europe & Africa in 1992, when we acquired the AES Kilroot power plant in Northern Ireland. Since that time, AES has grown in this region and now has a presence in 11 countries. AES's operations in the region now include a total of 15 generation plants owned or operated under management agreements with a total of 10,530 MW generation capacity. AES owns and operates three utilities, distributing a total of 8,960 GWh with 927 MW of capacity. In addition, AES operates two utilities under management agreement in the region, which distribute a total of 2,096 GWh.

        We own 13 generation facilities in Europe & Africa, and operate two additional generation facilities under management contract in Kazakhstan. These generation facilities have the capacity to generate 10,530 MW. In 2006, we began commercial operation of AES Cartagena, our first power plant in Spain with 1,200 MW capacity. AES Maritza East 1 is a 670 MW lignite-fired power plant currently under construction in Bulgaria.

        We own three Utility businesses in Europe & Africa, including an integrated utility in Cameroon (AES SONEL) and two distribution businesses in Ukraine (Kievoblenergo and Rivneenergo). AES acquired a 56% interest in AES SONEL in 2001. AES SONEL generates, transmits and distributes electricity to approximately 538,000 customers. AES SONEL has an installed generating capacity of 927 MW, and a small plant under construction. Our two distribution businesses in Ukraine serve over 1.2 million customers, while the two distribution businesses we operate under management agreements in Kazakhstan together serve over 554,000 customers.

Asia

        Our Asian operations accounted for 7%, 6% and 7% of consolidated revenues in 2006, 2005 and 2004, respectively. AES began operations in Asia in 1994 when we acquired the Cili power plant in China. Since that time AES's Generation business has expanded and it now operates 13 power plants with a total capacity of 5,369 MW in six countries. AES only operates generation facilities in Asia.

        We have 13 generation facilities with the capacity to generate 5,369 MW. Over half of our facilities and capacity are located in China, where AES joined with Chinese partners to build Yangcheng, the first "coal-by-wire" power plant with the capacity of 2100 MW. In 2000, AES was selected by the Sultanate of Oman to build, own and operate a 456 MW and 20 MIGD combined power and desalinated water facility, which achieved commercial operations in 2003. In 2001, AES was awarded

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the right to build, own and operate for 25 years a 756 MW and 40 MIGD combined power and desalinated water facility, the first such facility to be awarded to the private sector in Qatar. This facility commenced commercial operations in 2004. AES also owns and operates two oil-fired facilities in Pakistan (Lal Pir and Pak Gen), which have been in operations for the last nine years. In India, AES acquired a 420 MW coal-fired power plant (OPGC) in 1998. In Sri Lanka, we own a 168 MW diesel-fired power plant that began commercial operations in 2003. AES Amman East is a 370 MW combined-cycle gas power plant under construction in Jordan.


Recent Developments

        We made an offer to purchase for cash up to $1.24 billion aggregate principal amount of our 8.75% Senior Notes due 2008 (the "2008 Notes"), the 9.00% Second Priority Senior Secured Notes due 2015 (the "2015 Notes") and 8.75% Second Priority Senior Secured Notes due 2013 (the "2013 Notes" and together with the 2015 Notes, the "Second Priority Notes"), in accordance with the terms and conditions described in our Offer to Purchase and the related Letter of Transmittal, each dated October 16, 2007. Early settlement for the tender offer was on October 30, 2007 and final settlement was on November 14, 2007, and we accepted for purchase a total of $192.6 million principal amount of the 2008 Notes, $600.0 million principal amount of the 2015 Notes and approximately $447.4 million principal amount of the 2013 Notes (representing the acceptance by us of a prorated amount). At settlement, none of the 2015 Notes, approximately $9.3 million principal amount of the 2008 Notes and approximately $752.6 million principal amount of the 2013 Notes remained outstanding.


Company Information

        We were incorporated in the State of Delaware in 1981. Our principal executive office is located at 4300 Wilson Boulevard, Arlington, Virginia 22203, and our telephone number is (703) 522-1315. Our website address is http://www.aes.com. Material contained on our website is not part of and is not incorporated by reference in this prospectus. Our filings with the Securities and Exchange Commission ("SEC") are available from our website free of charge.

        The name "AES" and our logo are AES owned trademarks, service marks or trade names. All other trademarks, trade names or service marks appearing or incorporated by reference in this prospectus are owned by their respective holders.

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Summary of the Exchange Offer

        On October 15, 2007, we issued $500 million aggregate principal amount of unregistered 7.75% senior notes due 2015 and $1.5 billion aggregate principal amount of unregistered 8.0% senior notes due 2017.

        On October 15, 2007, we and the initial purchasers of the unregistered notes entered into a registration rights agreement in connection with such debt offerings in which we agreed that you, as a holder of unregistered notes, would be entitled to exchange your unregistered notes for exchange notes registered under the Securities Act but otherwise having substantially identical terms to the respective unregistered notes. This exchange offer is intended to satisfy these rights. After the exchange offer is completed, you will no longer be entitled to any registration rights with respect to your notes. The exchange notes will be our obligations and will be entitled to the benefits of the base indenture and supplemental indentures relating to the unregistered notes. The form and terms of the exchange notes are identical in all material respects to the form and terms of the respective unregistered notes, except:

        For additional information on the terms of the exchange offer, see "The Exchange Offer."

The Exchange Offer   We are offering to exchange $1,000 principal amount of:

 
 
•
 
7.75% senior notes due 2015 which have been registered under the Securities Act of 1933 for each $1,000 principal amount of our outstanding unregistered 2015 notes that were issued on October 15, 2007. As of the date of this prospectus, $500 million in aggregate principal amount of our unregistered 2015 notes are outstanding.

 
 
•
 
8.0% senior notes due 2017 which have been registered under the Securities Act of 1933 for each $1,000 principal amount of our outstanding unregistered 2017 notes that were issued on October 15, 2007. As of the date of this prospectus, $1.5 billion in aggregate principal amount of our unregistered 2017 notes are outstanding.

Expiration of Exchange Offer
 
The exchange offer will expire at 12:00 p.m., midnight, New York City time, on January 18, 2008, unless we decide to extend the expiration date.

Conditions of the Exchange Offer
 
We will not be required to accept for exchange any unregistered notes, and we may amend or terminate the exchange offer if any of the following conditions or events occurs:

 
 
•
 
the exchange offer, or the making of any exchange by a holder, violates applicable law, rule, or regulation or any applicable interpretation of the staff of the SEC;
         

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•
 
any action or proceeding shall have been instituted or threatened with respect to the exchange offer which, in our judgment, would impair our ability to proceed with the exchange offer; and

 
 
•
 
any law, rule or regulation or applicable interpretation of the staff of the SEC has been issued or promulgated which, in our good faith determination, does not permit us to effect the exchange offer.

 
 
We will give oral or written notice of any non-acceptance, amendment or termination to the registered holders of the unregistered notes as promptly as practicable. We reserve the right to waive any conditions of the exchange offer.

Resale of Exchange Notes
 
Based on interpretative letters of the SEC staff to third parties unrelated to us, we believe that you can resell and transfer the exchange notes you receive pursuant to this exchange offer, without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that:

 
 
•
 
any exchange notes to be received by you will be acquired in the ordinary course of your business;

 
 
•
 
you are not engaged in, do not intend to engage in and have no arrangement or understanding with any person to participate in the distribution of the unregistered notes or the exchange notes;

 
 
•
 
you are not an "affiliate" (as defined in Rule 405 under the Securities Act) of AES or, if you are such an affiliate, you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable;

 
 
•
 
if you are a broker-dealer, you have not entered into any arrangement or understanding with AES or any "affiliate" of AES (within the meaning of Rule 405 under the Securities Act) to distribute the exchange notes;

 
 
•
 
if you are a broker-dealer, you will receive exchange notes for your own account in exchange for unregistered notes that were acquired as a result of market-making activities or other trading activities and that you will deliver a prospectus in connection with any resale of such exchange notes; and

 
 
•
 
you are not acting on behalf of any person or entity that could not truthfully make these representations.

 
 
If you wish to accept the exchange offer, you must represent to us that these conditions have been met.
         

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If our belief is inaccurate and you transfer any exchange notes without delivering a prospectus meeting the requirements of the Securities Act or without an exemption from registration under the Securities Act, you may incur liability under the Securities Act. We do not assume or indemnify you against such liability.

Accrued Interest on the Exchange Notes and Unregistered Senior Notes
 
Like the unregistered notes, the exchange notes will accrue interest from and including October 15, 2007. We will pay interest on the exchange 2015 notes and the exchange 2017 notes semi-annually on April 15 and October 15 of each year, commencing April 15, 2008.

 
 
Holders of unregistered notes that are accepted for exchange will be deemed to have waived the right to receive any payment in respect of interest accrued from and including October 15, 2007, until the date of the issuance of the exchange notes. Consequently, holders of exchange notes will receive the same interest payments that they would have received had they not accepted the exchange offer.

Procedures for Tendering Unregistered Senior Notes
 
If you wish to participate in the exchange offer, you must transmit a properly completed and signed letter of transmittal, and all other documents required by the letter of transmittal, to the exchange agent at the address set forth in the letter of transmittal. These materials must be received by the exchange agent before 12:00 p.m., midnight, New York City time, on January 18, 2008, the expiration date of the exchange offer. You must also provide:

 
 
•
 
a confirmation of any book-entry transfer of unregistered notes tendered electronically into the exchange agent's account with DTC. You must comply with DTC's standard operating procedures for electronic tenders, by which you will agree to be bound in the letter of transmittal; or

 
 
•
 
physical delivery of your unregistered notes to the exchange agent's address as set forth in the letter of transmittal.

 
 
The letter of transmittal must also contain the representations you must make to us as described under "The Exchange Offer—Resale of Exchange Notes."

Special Procedures for Beneficial Owners
 
If you are a beneficial owner of unregistered notes that are held through a broker, dealer, commercial bank, trust company or other nominee and you wish to tender such unregistered notes, you should contact the person promptly and instruct the person to tender your unregistered notes on your behalf.
         

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Guaranteed Delivery Procedures for Unregistered Senior Notes
 
If you cannot meet the expiration deadline, or you cannot deliver your unregistered notes, the letter of transmittal or any other required documentation, or comply with DTC's standard operating procedures for electronic tenders on time, you may tender your unregistered notes according to the guaranteed delivery procedures set forth under "The Exchange Offer—Guaranteed Delivery Procedures."

Withdrawal Rights
 
You may withdraw the tender of your unregistered notes at any time prior to 12:00 p.m., midnight, New York City time, on January 18, 2008, the expiration date.

Consequences of Failure to
Exchange
 
If you are eligible to participate in this exchange offer and you do not tender your unregistered notes as described in this prospectus, you will not have any further registration rights. In that case, your unregistered notes will continue to be subject to restrictions on transfer. As a result of the restrictions on transfer and the availability of exchange notes, the unregistered notes are likely to be much less liquid than before the exchange offer. The unregistered notes will, after the exchange offer, bear interest at the same rate as the respective exchange notes.

Certain U.S. Federal Income Tax Consequences
 
The exchange of the unregistered notes for exchange notes pursuant to the exchange offer will not be a taxable exchange for U.S. federal income tax purposes.

Use of Proceeds
 
We will not receive any proceeds from the issuance of exchange notes pursuant to the exchange offer.

Exchange Agent for Unregistered Senior Notes
 
Wells Fargo Bank, National Association, the trustee under the indenture for the unregistered notes, is serving as the exchange agent in connection with the exchange offer. Wells Fargo Bank, National Association can be reached at Corporate Trust Operations, MAC N9303-121, P.O. Box 1517, Minneapolis, Minnesota 55480, Attn: Reorg; its telephone number is (800) 344-5128 or (612) 667-9764 and its facsimile number is (612) 667-6282.

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Summary Description of the Exchange Notes

        The following is a brief summary of some of the terms of the notes. For a more complete description of the terms of the notes, see "Description of the Exchange Notes."

Exchange Notes   •   $500,000,000 aggregate principal amount of registered 7.75% senior notes due 2015; and

 
 
•
 
$1,500,000,000 aggregate principal amount of registered 8.0% senior notes due 2017.

Maturity
 
The exchange 2015 notes will mature on October 15, 2015. The exchange 2017 notes will mature on October 15, 2017.

Interest
 
The exchange 2015 notes bear interest at an annual rate equal to 7.75%. The exchange 2017 notes bear interest at an annual rate equal to 8.0%. Interest on the exchange notes will be paid on each April 15 and October 15, beginning April 15, 2008.

Ranking
 
The exchange notes will be our direct, unsecured and unsubordinated obligations and will rank:

 
 
•
 
equal in right of payment with all of our senior unsecured debt;

 
 
•
 
effectively junior in right of payment to (a) our secured debt to the extent of the value of the assets securing such debt and (b) the debt and other liabilities (including trade payables) of our subsidiaries; and

 
 
•
 
senior in right of payment to our subordinated debt.

 
 
As of September 30, 2007:

 
 
•
 
we had approximately $2.2 billion of senior unsecured debt, $2.0 billion of secured debt and $731 million of subordinated debt outstanding; and

 
 
•
 
our subsidiaries had approximately $21.6 billion of debt and other liabilities, including trade payables, outstanding.

 
 
The indenture under which the exchange notes will be issued contains no restrictions on the amount of additional unsecured indebtedness that we may incur or the amount of indebtedness (whether secured or unsecured) that our subsidiaries may incur. The indenture permits us to incur secured debt subject to the covenants described under "Description of the Exchange Notes—Certain Covenants of AES—Restrictions on Secured Debt."

Change of Control
 
Upon the occurrence of a change of control (as described in "Description of the Exchange Notes—Repurchase of Notes Upon a Change of Control"), you may require us to repurchase some or all of your exchange notes at 101% of their principal amount, plus accrued and unpaid interest to the date of repurchase.
         

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Optional redemption
 
We may redeem some or all of the exchange notes at par plus a Make-Whole Amount (as defined). See "Description of the Exchange Notes—Optional Redemption."

Covenants
 
We have agreed to certain restrictions on incurring secured debt and entering into sale and leaseback transactions. See "Description of the Exchange Notes—Certain Covenants of AES."

Trustee
 
Wells Fargo Bank, National Association.

Risk factors
 
See "Risk Factors" for a discussion of the factors you should consider carefully before deciding to invest in the notes.

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RISK FACTORS

        You should consider carefully the following risks, along with the other information contained in this prospectus. Additional risks and uncertainties also may adversely affect our business and operations including those discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this prospectus. If any of the following events actually occur, our business and financial results could be materially adversely affected.

Risks Relating to the Notes

The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including the notes, 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.

        Furthermore, our subsidiaries face various restrictions in their ability to distribute cash to The AES Corporation. Most of the subsidiaries are obligated, pursuant to loan agreements, indentures or project financing arrangements, to satisfy certain restricted payment covenants or other conditions before they may make distributions to The AES Corporation. In addition, the payment of dividends or the making of loans, advances or other payments to The AES Corporation may be subject to legal or regulatory restrictions. Business performance and local accounting and tax rules may limit the amount of retained earnings, 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 on 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 therefor, 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 the notes offered hereby.

The notes will be effectively subordinated to the liabilities of our subsidiaries.

        Our subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due on the notes offered hereby or to make any funds available therefor, whether by dividends, fees, loans or other payments. Any right we have to receive any assets of any of our subsidiaries upon any liquidation, dissolution, winding up, receivership, reorganization, assignment for the benefit of creditors, marshaling of assets and liabilities or any bankruptcy, insolvency

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or similar proceedings (and the consequent right of the holders of our 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). Accordingly, the notes will be effectively subordinated to all liabilities of our subsidiaries, including guarantees by our subsidiaries of our obligations, including our obligations under our senior secured credit facility. At September 30, 2007, our subsidiaries had $21.6 billion of outstanding liabilities, including outstanding indebtedness. The indenture governing the notes does not limit the ability of our subsidiaries to incur additional indebtedness, including guaranteeing debt of The AES Corporation.

The notes will be effectively subordinated to our secured debt.

        The notes will be unsecured general obligations of The AES Corporation, and therefore will be effectively subordinated to all of the secured debt of The AES Corporation to the extent of the value of the assets securing such debt. As of September 30, 2007, The AES Corporation had a total of $2.0 billion of secured debt outstanding, including amounts outstanding under our senior secured credit facility and our Second Priority Senior Secured Notes, which are secured by, among other things, a lien on certain of our accounts and a pledge of most of our directly held subsidiaries. The indenture governing the notes limits but does not prohibit The AES Corporation from incurring additional secured debt and there are significant exceptions to this covenant. See "Description of the Exchange Notes—Certain Covenants of AES—Restrictions on Secured Debt."

You cannot be sure that an active trading market will develop for these notes, which may hinder your ability to liquidate your investment.

        The notes are a new issue of securities with no established trading market, and we do not intend to list them on any securities exchange. The initial purchasers of the restricted notes have been making a market in the restricted notes, and we have been informed by the initial purchasers that they intend to make a market for the exchange notes after the exchange offer is completed. However, the initial purchasers may cease their market-making at any time. In addition, the liquidity of the trading market in the notes, and the market price quoted for the notes, may be adversely affected by changes in the overall market for fixed income securities and by changes in our financial performance or prospects or in the prospects for companies in our industry generally. In addition, such market-making activity will be subject to limits imposed by the Securities Act and the Securities Exchange Act of 1934 (the "Exchange Act"), and may be limited during this exchange offer and the pendency of any shelf registration statement. As a result, you cannot be sure that an active trading market will develop for the notes. If no active trading market develops, you may not be able to resell your notes at their fair market value or at all.

Risks Relating to Our Business

Our disclosure controls and procedures and internal control over financial reporting were determined not to be effective as of September 30, 2007, December 31, 2006, December 31, 2005 and December 31, 2004, as evidenced by the material weaknesses that existed in our internal controls. 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 at the end of 2006, 2005 and 2004 and at September 30, 2007. A material weakness is a deficiency, 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

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interim financial statements will not be prevented or detected. Our management concluded that as of September 30, 2007, December 31, 2006, December 31, 2005 and December 31, 2004, 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 we are required to disclose in our reports under the Exchange Act was recorded, processed, summarized and reported accurately. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Controls and Procedures."

        During the remediation efforts to correct the material weakness that was identified at the end of 2004, errors were discovered in our financial statements which resulted from such material weakness, as well as errors resulting from newly identified material weaknesses. These errors required us to restate our financial statements that were previously filed in AES's annual report on Form 10-K for the year ended December 31, 2004 and AES's quarterly report on Form 10-Q for the quarter ended March 31, 2005. During the 2005 year-end closing process and the first quarter of 2006, additional errors were identified relating to the existing material weakness and newly identified material weaknesses that required us to restate prior period financial statements on January 19, 2006 and April 4, 2006. During the 2006 year-end closing process further errors were identified relating to existing material weaknesses as well as related to newly identified material weaknesses that required us to restate our previously filed annual financial statements in AES's 2006 annual report on Form 10-K originally filed on May 23, 2007 and to restate our previously issued condensed consolidated interim financial statements for the three months ended March 31, 2006 and 2007 in its 10-Q/A filed with the SEC on August 17, 2007, for the three and six months ended June 30, 2006 in its Form 10-Q filed with the SEC on August 9, 2007 and for the three and nine months ended September 30, 2006 in its Form 10-Q filed on November 6, 2007. Finally, in the third quarter of 2007, as a result of new controls implemented during remediation of material weaknesses, we identified additional errors relating to lease accounting at our Southland and Pakistan subsidiaries. These errors and other adjustments, including adjustments relating to the treatment of Special Obligations in Brazil, required us to restate our financial statements for the fifth time in AES's amended 2006 annual report on Form 10-K/A filed on August 7, 2007 and in its amended quarterly report on Form 10-Q/A for the quarter ended March 31, 2007, filed on August 17, 2007. To address these material weaknesses in our internal control over financial reporting, each time we prepared our annual and quarterly reports we performed additional analysis and other post-closing procedures in order to prepare our consolidated financial statements in accordance with generally accepted accounting principles. 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.

        Although we reported remediation of certain material weaknesses as of December 31, 2006 and continue to execute plans to remediate the remaining material weaknesses in 2007, 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 our consolidated financial statements.

        Management, including our chief executive officer ("CEO") and chief financial officer ("CFO"), does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be

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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 until 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, while 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 September 30, 2007, we had approximately $17.2 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.

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,

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letter of credit reimbursement agreements and agreements to pay, in certain circumstances, the project lenders or other parties.

        As of September 30, 2007, we had approximately $17.2 billion of outstanding indebtedness on a consolidated basis, of which approximately $4.9 billion was recourse debt of The AES Corporation and approximately $12.3 billion was non-recourse debt. In addition, at September 30, 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 $514 million at September 30, 2007. While the lenders under our non-recourse project financings generally do not have direct recourse to The AES Corporation (other than to the extent of any credit support given by The AES Corporation), defaults thereunder 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.

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Risks Associated with our Ability to Raise Needed Capital

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

        The AES Corporation requires cash primarily to fund:

        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 "Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity" set forth below.

        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 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 all of the principal outstanding under our senior secured credit facility 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:

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        In addition, our inability to issue securities pursuant to our existing shelf-registration statement on Form S-3 and the material weaknesses in our internal controls over financial reporting may also limit our ability to access the capital markets on a timely basis. Should future access to capital not be available, 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 counterparties; it will limit the amount of credit available to The AES Corporation to meet its other liquidity needs.

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

        Part of our strategy is to grow our business by developing Generation and Utility businesses in less developed economies where the return on our investment may be greater than projects in more developed economies. Commercial lending institutions sometimes refuse to provide non-recourse project financing in certain less developed economies, and in these situations we have sought and will continue to seek direct or indirect (through credit support or guarantees) project financing from a limited number of multilateral or bilateral international financial institutions or agencies. As a precondition to making such project financing available, the lending institutions may also require governmental guarantees of certain project and sovereign related risks. There can be no assurance, however, that project financing from the international financial agencies or that governmental guarantees will be available when needed, and if they are not, we may have to abandon the project or invest more of our own funds which may not be in line with our investment objectives and would leave less funds for other projects.

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 our consolidated financial statements, as well as from transaction exposure associated with transactions in currencies other than an entity's functional currency. While our 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

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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, Venezuelan bolivar and Argentine peso. As our Brazilian and Argentine businesses primarily identify their local currency as its functional currency, devaluation of these currencies has resulted in deferred translation losses (foreign currency translation adjustments recognized in accumulated other comprehensive loss) based on positive net asset positions. Devaluation has also resulted in foreign currency transaction losses primarily associated with U.S. dollar debt at these businesses. Our Venezuelan business has now been sold. 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 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:

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        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 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.

        The 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.

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Risks Associated with our Operations

We do a significant amount of business outside the United States which presents significant risks.

        During 2006, approximately 78% of our revenue was 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:


        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"), a state owned 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 $638 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.

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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 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 earthquake, flood, lightning, hurricane 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

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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.

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 to fulfill 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 experience) 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

25


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:

        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:

26

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

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

        In some joint venture agreements where we do have majority control of the voting securities, we have entered into shareholder agreements granting protective minority rights to the other shareholders. For example, Brasiliana is a holding company in which we have a controlling equity interest and through which we own three of our four Brazilian businesses: Eletropaulo, Tiete and Uruguaiana. We entered into a shareholders' agreement with an affiliate of BNDES (referred to herein as 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.

        In accordance with the terms of the shareholders' agreement, we and BNDES have each selected appraisers to determine the value of Brasiliana. Since the valuations provided by these two appraisers differed by more than 10%, a third appraiser has been selected to also determine the value of Brasiliana. As of the date of this prospectus, the third appraiser has not completed its evaluation. Pursuant to the shareholders' agreement, the base sale price for BNDES to exercise its drag-along right will be the weighted average of the valuations provided by the three appraisers. Once 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 you 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 assure you that we will not have to record a loss if the sale price is below the book-value of our investment in Brasiliana.

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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 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.

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 'Qualified Facilities' ("QFs") if certain market conditions are met. Pursuant to this authority, the FERC has proposed to remove the purchase/sale obligation for all utilities located within the control areas of the Midwest Transmission System Operator, Inc., PJM Interconnection, L.L.C., ISO New England, Inc. and the New York Independent System Operator. 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

28


law does not affect existing contracts, as a result of the changes to PURPA, our QFs 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 Energy Policy Act of 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 regional transmission organizations and independent system operators 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.

        Finally, EPAct 2005 affects nearly every aspect of the energy business and energy regulation. We are still in the process of analyzing the new law's effects, and those effects could have a material adverse effect on our business.

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 contained in "Business—Environmental and Land Use Regulations." 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 made and will continue to make 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.

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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.

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RATIO OF EARNINGS TO FIXED CHARGES

        Our ratio of earnings to fixed charges is as follows:

 
   Nine Months Ended
September 30,
   Year Ended December 31,
 
   2007
   2006
   2005
   2004
   2003
   2002
 
    
   (restated)

   (restated)

   (restated)

   (restated)

   (restated)
Ratio of Earnings to Fixed Charges*   1.74x   1.20x   1.43x   1.25x   1.17x   0.18x*
*
Earnings were inadequate to cover fixed charges for the year ended December 31, 2002. The dollar amount of the earnings deficiency was $1.596 billion.

        For the purpose of computing the ratio of earnings to fixed charges, earnings consist of income from continuing operations before income taxes and minority interest, plus depreciation of previously capitalized interest, plus fixed charges, less capitalized interest, less excess of earnings over dividends of less-than-fifty-percent-owned companies, less minority interest in pre-tax income of subsidiaries that have not incurred fixed charges, less preference security dividend requirements of a consolidated subsidiary. Fixed charges consist of interest (including capitalized interest) on all indebtedness, amortization of debt discount and capitalized expenses, preference security dividend requirements of a consolidated subsidiary, and that portion of rental expense which we believe to be representative of an interest factor.


USE OF PROCEEDS

        We will not receive any proceeds from the exchange offer. In consideration for issuing the exchange notes contemplated by this prospectus, we will receive unregistered notes from you in like principal amount. The unregistered notes surrendered in exchange for the exchange notes will be retired and canceled and cannot be reissued. Accordingly, issuance of the exchange notes will not result in any change to our indebtedness.

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SELECTED CONSOLIDATED FINANCIAL DATA

        The following table sets forth our selected financial data as of the dates and for the periods indicated. We derived the statement of operations data for the years ended December 31, 2004, 2005 and 2006 and the balance sheet data as of December 31, 2005 and 2006 from our audited consolidated financial statements included in this prospectus. We derived the statement of operations data for the years ended December 31, 2002 and 2003 and the balance sheet data as of December 31, 2002, 2003 and 2004 from our audited consolidated financial statements for those years, which are not included in this prospectus. We derived the statement of operations data for the nine months ended September 30, 2006 and 2007, and the balance sheet data as of September 30, 2007, from our unaudited condensed consolidated financial statements (hereinafter our "unaudited consolidated financial statements" and together with our audited consolidated financial statements, our "consolidated financial statements") included in this prospectus. We derived the historical balance sheet data as of September 30, 2006, from our unaudited condensed consolidated balance sheet, which is not included in this prospectus.

        Our unaudited consolidated financial statements have been prepared on the same basis as our audited consolidated financial statements and, in our opinion, reflect all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of such financial statements in all material respects. The results for any interim period are not necessarily indicative of the results that may be expected for a full year or any future period. You should read the selected historical consolidated financial data in conjunction with the information included under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and accompanying notes included in this prospectus.

        The information presented in the following tables has been adjusted to reflect the restatements of our financial results which are more fully described in note 1 to our audited consolidated financial statements under the caption "General and Summary of Significant Accounting Policies—Restatement" and in note 1 to our unaudited consolidated financial statements under the caption "Financial Statement Presentation—Restatement of Consolidated Financial Statements" included in this prospectus.

        Acquisitions, disposals, reclassifications and changes in accounting principles affect the comparability of information included in the tables below. Please refer to the notes to our consolidated financial statements included in this prospectus for further explanation of the effect of such activities.

 
   Nine Months Ended
September 30,
   (Restated)(1)
Year Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
   2003
   2002
  
 
    
   (Restated)(1)

    
    
    
    
    
  
 
   (Dollars and shares in millions, except per share amounts)

  
Statement of Operations Data:                                            
  Revenues   $ 9,924   $ 8,615   $ 11,564   $ 10,320   $ 8,745   $ 7,708   $ 6,653  
  Income (loss) from continuing operations     482     149     135     402     172     183     (1,845 )
  Discontinued operations, net of tax     (594 )   20     48     188     132     (681 )   (1,821 )
  Extraordinary item, net of tax     —     21     21     —     —     —     —  
  Cumulative effect of change in accounting principle, net of tax     —     —     —     (3 )   —     41     (376 )
   
 
 
 
 
 
 
 
  Net (loss) income available to common stockholders   $ (112 ) $ 190   $ 204   $ 587   $ 304   $ (457 ) $ (4,042 )
   
 
 
 
 
 
 
 
                                             

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Basic earnings (loss) earnings per share:                                            
  Income (loss) from continuing operations   $ 0.72   $ 0.23   $ 0.21   $ 0.62   $ 0.27   $ 0.32   $ (3.42 )
  Discontinued operations     (0.89 )   0.03     0.07     0.29     0.20     (1.16 )   (3.38 )
  Extraordinary item, net of tax     —     0.03     0.03     —     —     —     —  
  Cumulative effect of change in accounting principle     —     —     —     (0.01 )   —     0.07     (0.70 )
   
 
 
 
 
 
 
 
  Basic earnings (loss) per share   $ (0.17 ) $ 0.29   $ 0.31   $ 0.90   $ 0.47   $ (0.77 ) $ (7.50 )
   
 
 
 
 
 
 
 

Diluted earnings (loss) per share:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Income (loss) from continuing operations   $ 0.71   $ 0.22   $ 0.20   $ 0.61   $ 0.27   $ 0.32   $ (3.42 )
  Discontinued operations     (0.88 )   0.03     0.07     0.28     0.20     (1.16 )   (3.38 )
  Extraordinary item, net of tax     —     0.03     0.03     —     —     —     —  
  Cumulative effect of change in accounting principle     —     —     —     (0.01 )   —     0.07     (0.70 )
   
 
 
 
 
 
 
 
  Diluted earnings (loss) per share   $ (0.17 ) $ 0.28   $ 0.30   $ 0.88   $ 0.47   $ (0.77 ) $ (7.50 )
   
 
 
 
 
 
 
 
 
   Nine Months Ended
September 30,
   (Restated)
December 31,
  
 
   2007
   2006
   2005
   2004
   2003
   2002
  
 
   (Dollars in millions)

  
Balance Sheet Data:                                      
  Total assets   $ 33,350   $ 31,201   $ 28,995   $ 28,417   $ 29,133   $ 34,516  
  Non-recourse debt (long-term)     11,058   $ 9,834   $ 10,318   $ 10,587   $ 10,055   $ 5,117  
  Non-recourse debt (long- term)—Discontinued operations     —   $ 324   $ 453   $ 726   $ 702   $ 4,768  
  Recourse debt (long-term)     4,484   $ 4,790   $ 4,682   $ 5,010   $ 5,862   $ 6,755  
  Stockholders' equity (deficit)     3,199   $ 2,965   $ 1,612   $ 957 (3) $ (121 )(3) $ (823 )(2)(3)
(1)
See note 1 to our audited consolidated financial statements under the caption "General and Summary of Significant Accounting Policies—Restatement" and in note 1 to our unaudited consolidated financial statements under the caption "Financial Statement Presentation—Restatement of Consolidated Financial Statements" included in this prospectus.

(2)
A $28 million reduction to Stockholders' equity was recognized as of January 1, 2002 as the cumulative effect of the correction of errors for all periods preceding January 1, 2002. The correction was not material to the financial data presented herein as of and for the five years ended December 31, 2002–December 31, 2006.

(3)
The impact of the restatement adjustments on stockholders' equity were $(4), $(19) and $32 million as of December 31, 2004, 2003 and 2002, respectively. The impact of the restatement adjustments to net income was an increase to net losses of $5 million and $41 million for the years ended December 31, 2003 and 2002, respectively.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

Our Businesses

        AES is one of the world's largest global power companies, providing essential electricity services in 28 countries on five continents. We operate two main types of businesses. The first is our distribution and transmission business, which we refer to as Utilities, in which we operate electric utilities and sell power to customers in the retail (including residential), commercial, industrial and governmental sectors. These customers are typically end users of electricity. The second is our Generation business, where we sell power to wholesale customers such as utilities or other intermediaries. The revenues and earnings growth of both our Utilities and Generation businesses vary with changes in electricity demand.

        Our Utilities business consists primarily of 15 distribution companies owned or operated under management agreements in eight countries with over 11 million end-user customers. All of these companies operate in a defined service area. This segment is composed of:

        Performance drivers for these businesses include, among other things, 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.

        Utilities face relatively little direct competition due to significant barriers to entry which are present in these markets. In this segment, we primarily face competition in our efforts to acquire businesses. 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 have accumulated more significant portfolios. Relevant competitive factors for Utilities include financial resources, governmental assistance, regulatory restrictions and access to non-recourse financing. In certain locations, our utilities 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. We can provide no assurance that deregulation will not adversely affect the future operations, cash flows and financial condition of our Utilities business. The results of operations of our Utilities business are sensitive to changes in economic growth and regulation, abnormal weather conditions in the area in which they operate, as well as the success of the operational changes that have been implemented (especially in emerging markets).

        In our Generation business, we generate and sell electricity primarily to wholesale customers. Performance drivers for our Generation business include, among other things, plant reliability, fuel costs and fixed-cost management. Growth in this business is largely tied to securing new power

34


purchase agreements, expanding capacity in our existing facilities and building new power plants. Our Generation business includes our interests in 97 power generation facilities owned or operated under management agreements totaling 37 gigawatts of capacity installed in 22 countries.

        Approximately 68% of the revenues from our Generation business are from plants that operate under power purchase agreements of five years or longer for 75% or more of the output capacity. These long-term contracts reduce the risk associated with volatility in the market price for electricity. We also reduce our exposure to fuel supply risks by entering into long-term fuel supply contracts or through fuel tolling contracts where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. As a result of these contractual agreements, these facilities have relatively predictable cash flows and earnings. These facilities face most of their competition prior to the execution of a power sales agreement, often during the development phase of a project or upon expiration of an existing agreement. Our competitors for these contracts include other independent power producers and equipment manufacturers, as well as various utilities and their affiliates. During the operational phase, we traditionally have faced limited competition due to the long-term nature of the generation contracts. However, since competitive power markets have been introduced and new market participants have been added, we have and will continue to encounter increased competition in attracting new customers and maintaining our current customers as our existing contracts expire.

        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 facilities 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. These facilities compete with numerous other independent power producers, energy marketers and traders, energy merchants, transmission and distribution providers and retail energy suppliers. Competitive factors for these facilities include price, reliability, operational cost and third party credit requirements.

        As described above, AES operates within two primary businesses, the generation of electricity and the distribution of electricity. AES previously reported its financial results in three business segments: contract generation, competitive supply and regulated utilities. As of December 31, 2006, we have changed the definition of our segments in order to report information by geographic region and by line of business. We believe this change more accurately reflects the manner in which we manage the Company.

        Our businesses include Utilities and Generation within four defined geographic regions: (1) North America, (2) Latin America, (3) Europe, CIS and Africa, which we refer to as "Europe & Africa" and (4) Asia and the Middle East, which we refer to as "Asia". Three regions, North America, Latin America and Europe & Africa, are engaged in both our Generation and Utility businesses. Our Asia region only has Generation businesses. 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 development and operational costs related to our Alternative Energy business which is currently not material to our presentation of operating segments. Under AES's Alternative Energy group, AES operates 1,015 MW of wind generation in the United States.

        Our goal is to continue building on our traditional lines of business, while expanding into other essential energy-related areas. We believe that this is a natural expansion for us. 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 also will build on our existing capabilities in areas beyond power including greenhouse gas emissions offset

35


projects, electricity transmission, water desalination, and other businesses. 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 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. We continue to emphasize growth through "greenfield" development, platform expansion, privatization of government-owned assets, and mergers and acquisitions and continue to develop and maintain a strong development pipeline of projects and opportunities. The Company sees growth investments as the most significant contributor to long-term shareholder value creation. 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 own assessment of value in the AES portfolio.

        Underpinning this growth focus is an operating model which benefits from a diverse power generation portfolio that is largely contracted, reducing fuel cost and demand risks, and from an electric utility portfolio heavily weighted to faster-growing emerging markets.

        The Company believes that success with its business development activities will be the single most important factor in its financial success in terms of value creation and it is directing increasing resources in support of business development globally. The Company also believes that high oil prices, increasing regulation of greenhouse gases, faster than expected global economic growth and a weak dollar present opportunities for value creation, based on the Company's current business portfolio and business strategies. Slower global economic growth, which will impact demand growth for utilities and some generation businesses, is one of the most significant downside scenarios affecting value creation. Other important scenarios that could impair future value include low oil prices and a strong dollar.

Restatement of Consolidated Financial Statements

        The Company restated its consolidated financial statements as of and for the years ended December 31, 2004, 2005, and 2006 in its 2006 Form 10-K/A filed with the Securities and Exchange Commission (the "SEC") on August 7, 2007, which consolidated financial statements are included in this prospectus. The adjustments presented in the restatement were the result of the identification of certain financial statement errors relating to these years, which had they been corrected on a cumulative basis in the 2006 consolidated financial statements, would have materially misstated the results of operations in 2006 and prior periods.

        The Company also restated the previously issued condensed consolidated financial statements for the three months ended March 31, 2006 and 2007 in its 10-Q/A filed with the SEC on August 17, 2007, for the three and six months ended June 30, 2006 in its Form 10-Q filed with the SEC on August 9, 2007 and for the three and nine months ended September 30, 2006 in its Form 10-Q filed on November 6, 2007. The errors that were identified related to accounting for derivative instruments, leases, income taxes, share-based compensation and certain items in the Company's Brazil and EDC subsidiaries.

        In each of these restatements, the prior period financial statements were also restated to:

36

        The following management's discussion and analysis of financial condition and results of operations reflects the correction of errors that were contained in the Company's prior period financial statements, the change in the Company's segments and the reclassification of businesses reported as discontinued operations. For a more detailed discussion of these matters, see the notes referred to above.

2006 Performance Highlights

 
   December 31,
  
 
   2006
   2005
   2004
  
 
   ($ in millions)

  
Revenue   $ 11,564   $ 10,320   $ 8,745  
Gross Margin     3,398     2,928     2,558  
Gross Margin as a % of Revenue     29.4 %   28.4 %   29.3 %
Diluted Earnings Per Share from Continuing Operations     0.20     0.61     0.27  
Net Cash Provided by Operating Activities     2,360     2,232     1,497  

Revenue

        We achieved record revenues of $11.6 billion, an increase of 12.6% from $10.3 billion last year. Higher power prices, largely driven by the pass-through of higher fuel costs, together with increased demand and favorable foreign currency trends were the primary contributors.

Gross margin

        We achieved record gross margin of $3.4 billion, an increase of 16.1% from $2.9 billion in 2005. Favorable volume and foreign currency translation were the primary contributors to the increase.

Diluted earnings per share from continuing operations

        Diluted earnings per share from continuing operations were $0.20 compared to $0.61 in 2005. This decrease was primarily driven by the Brazil restructuring charges. Excluding the Brazil restructuring charges, earnings per share increased due to higher gross margin (primarily Latin American volume and foreign exchange) and lower net interest expense (debt retirements and lower interest rates). These gains were partially offset by higher general and administrative expenses resulting from increased development spending. The restructuring of our Brazil holding company, Brasiliana, eliminated restrictions on dividend payments to AES from three of our four principal Brazil businesses (Eletropaulo, Tiete, and Uruguaiana). The restructuring resulted in non-cash after-tax charges of approximately $500 million, or $0.76 per share, primarily related to a loss on sale of Eletropaulo stock in a secondary offering, recognizing deferred currency adjustments and certain debt prepayment premiums, partially offset by favorable tax benefits.

Net cash from operating activities

        We also achieved record cash flows from operating activities of $2.4 billion, 5.7% higher than 2005. Higher operating cash flows primarily reflect an increase in net earnings adjusted for non cash items.

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Nine Months Ended September 30, 2007 Performance Highlights

        The following table provides operating highlights for the three and nine months ended September 30, 2007 and 2006, respectively.

 
   Nine Months Ended
September 30,
  
 
   2007
   2006
   % Change
  
 
   (Restated)
(in millions, except per share amounts)

  
Revenue   $ 9,924   $ 8,615   15   %
Gross margin   $ 2,584   $ 2,598   (1) %
Diluted earnings per share from continuing operations   $ 0.71   $ 0.22   223   %
Net cash provided by operating activities   $ 1,848   $ 1,879   (2) %

Revenue

        Revenue increased 15% to $9.9 billion for the nine months ended September 30, 2007 compared with the same period in 2006 primarily due to higher rates and volume, foreign currency translation and the acquisition of Termoelectrica del Golfo ("TEG")/Termoelectrica del Peñoles ("TEP") and a controlling interest in Itabo.

Gross margin

        During the same period, gross margin decreased slightly as increased cost and lower volume related to gas supply curtailment and hydrology issues in Latin America and lower emission allowance sales offset the impact of favorable foreign currency translation, higher rates and volume in North America and contributions from new businesses.

Diluted earnings per share from continuing operations

        Diluted earnings per share from continuing operations increased $0.49 or 223%, primarily due to a restructuring of certain of the Company's Brazilian subsidiaries in third quarter 2006. This restructuring resulted in a non-cash, after-tax charge of approximately $500 million, or $0.76 per diluted share. Additionally, first quarter 2006 results included an $87 million gain, or $0.13 per diluted share, associated with the sale of Kingston in Ontario. Excluding the impacts of these transactions, the increase in earnings per diluted share from continuing operations was primarily driven by the increased cost and lower volume related to gas supply curtailments and hydrology issues in Latin America, lower sales of excess emission allowances and increased spending to strengthen our financial organization and support new business development initiatives and, partially offset by favorable foreign currency trends, higher rates and volume in North America and contributions from new businesses.

Net cash provided by operating activities

        Net cash provided by operating activities decreased 2% or $31 million for the nine months ended September 30, 2007 primarily due to the sale of EDC in May 2007. Excluding the impacts from EDC, net cash from operating activities would have increased by approximately $162 million driven by an overall increase in net working capital resulting from an increase in accounts payable and other accrued liabilities offset by increased accounts receivable.

Sale of EDC

        On February 22, 2007, we entered into a definitive agreement with PDVSA dated February 15, 2007, to sell all of our shares of EDC, a Latin America distribution business reported in the Latin America Utilities segment, for $739 million net of any withholding taxes. In addition, the agreement provided for the payment of a US$120 million dividend in 2007. On March 1, 2007, the shareholders of

38


EDC approved and declared a US$120 million dividend to all shareholders of record as of March 9, 2007. A wholly-owned subsidiary of the Company was the owner of 82.14% of the outstanding shares of EDC, and therefore, on May 31, 2007, this subsidiary received approximately US$97 million in dividends.

        The closing of the sale of EDC and the payment of the purchase price occurred on May 16, 2007. During the first quarter of 2007, the Company recognized an impairment charge of approximately $638 million related to this sale. As a result of the final disposition of EDC in May 2007, the Company recognized an additional impairment charge of approximately $38 million net of income and withholding taxes. The total impairment charge of $676 million represented the net book value of the Company's investment in EDC less the selling price. The impairment expense is included in the loss from disposal of discontinued business line item on the statement of operations for all periods presented in this prospectus.

Key Initiatives

People Development

        People development continues to be a major initiative as we look to improve our technical and leadership skills. We continued to expand the AES Learning Center, a program developed in partnership with the University of Virginia's Darden School of Business, which offers a range of courses on effective leadership, general management and functional skills, such as finance. In 2006, the Center launched a Financial Leadership Development Program to elevate performance among our financial groups worldwide. We also expanded the program internationally to Brazil, Cameroon, Kazakhstan, the Middle East and Ukraine. In addition to classroom training, we added an online AES Learning Center and now have an inventory of more than 150 technical and managerial courses offered online, making these classes available on a real-time basis.

        We continue to place top priority on ensuring a safe working environment for AES people, contractors and customers.

Material Weakness Remediation

        Over the course of the past year, the Company has worked diligently to continue to strengthen its controls over financial reporting, with particular emphasis on remediating its material weaknesses. For further discussion of the status of the Company's material weaknesses as of September 30, 2007, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Controls and Procedures."

Debt Restructuring

        Our existing businesses continued to focus on plant and distribution system operational excellence, reliability and customer service. We also benefited from favorable debt capital markets in a number of countries to restructure and refinance debt, extend maturities, and increase liquidity. In many instances favorable market conditions permitted refinancing dollar-denominated obligations into local currency, to reduce overall foreign exchange exposure.

        On October 10, 2007, the Company issued the unregistered 2015 notes and the unregistered 2017 notes, which are hereby offered for exchange for the exchange 2015 notes and the exchange 2017 notes, respectively.

        For further discussion of the terms of the exchange notes, please see "Description of the Exchange Notes."

Growth Projects and Building a Pipeline of New Initiatives

        Portfolio management, which can include business restructuring and sale of all or a portion of businesses, was an important area of focus and success in 2006. We achieved important milestones in

39


restructuring several of our Brazil businesses through a secondary offering of shares in our Eletropaulo subsidiary and using the proceeds to retire debt that had restrictive covenants precluding dividend payments to be received by AES. We sold a minority share of our Gener subsidiary in Chile, which increased the liquidity of those shares and we believe reduced the discount the local Chile stock market had been placing on Gener shares due to the prior illiquidity. We also sold our 50% equity position in a power project in Canada and sold a power plant in the U.K., both in negotiated transactions. We have worked to manage operational and financial risk through appropriate use of interest rate, energy, and foreign exchange risk management instruments and through effective procurement strategies.

        The Company continues to maintain a robust development pipeline. We are increasing resources in 2007 at both the corporate and business level in support of business development opportunities, which may include expansions at existing locations, which we call platform extensions, new greenfield investments, privatization of government assets, and mergers and acquisitions. In addition, as part of our efforts to identify attractive investment opportunities in related businesses, we look to participate in adjacent energy and infrastructure businesses such as wind power generation, reducing or offsetting greenhouse gas emissions, Liquid Natural Gas ("LNG") regasification, desalination and other alternative energy initiatives. These efforts may result in forming joint ventures, technology sharing or licensing arrangements, and other innovative market offerings.

        In our core power and alternative energy businesses, we continued to build a strong development pipeline of projects, primarily platform expansions and new construction projects that follow our long-term contract generation business model. In the core Generation business, we brought one new power project into service in 2006, a 1,200 MW, $920 million gas-fired power project in Cartagena, Spain (included in Europe & Africa generation). We began construction on a new 670 MW lignite-fired power plant in Bulgaria, supported by a long-term customer contract, and have secured new long-term customer contracts for new projects in Chile, Jordan and Panama. We also entered into purchase agreements to acquire two generation facilities in Mexico, which we consummated in February 2007.

        During the third quarter of 2007, we announced plans to begin construction of the Buffalo Gap 3 wind farm, a 170 MW expansion of its Buffalo Gap wind farm in Texas. Once completed, the project will increase capacity at Buffalo Gap to 524 MW, making it one of the largest operating wind farms in the United States. We also announced plans to expand its wind generation business into China through the creation of a joint venture with Guohua Energy Investment Co. Ltd., one of China's leading producers of renewable energy. The joint venture will construct, own, and operate a 49.5 MW wind farm. Through its investment in the joint venture, we will become the first U.S.-based power company with wind generation facilities in China.

        In the third quarter of 2007, we announced that the Department of Minerals and Energy of the Republic of South Africa (DME) has selected the AES consortium as the Preferred Bidder to build, own and operate two open cycle gas turbine peaking power plants, a 760 MW plant in KwaZulu Natal Province and a 342 MW plant in the Eastern Cape Province. We were also declared the winning bidder to acquire the 660 MW Masinloc coal fired plant in the Philippines.

        The Company's project backlog of construction projects as of September 30, 2007 totaled 1,982 gross MW of new generation capacity with a total expected investment of approximately $3.5 billion through 2010.

        We expect to fund growth investments from net cash from operating activities and/or the proceeds from the issuance of debt, common stock or other securities, asset sales, and partner equity contributions. Certain of the alternative energy business opportunities may be considered start-up businesses that will need to be funded initially through cash equity contributions, and may have limited debt financing opportunities initially. We believe there are sufficient attractive investment opportunities that may exceed available cash and net cash from operating activities in future periods.

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Critical Accounting Estimates

        The consolidated financial statements of AES are prepared in conformity with generally accepted accounting principles in the United States of America, which requires the use of estimates, judgments, and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. AES's significant accounting policies are described in note 1 to the audited consolidated financial statements included in this prospectus

        An accounting estimate is considered critical if:

        Management believes that the accounting estimates employed are appropriate and the resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. Listed below are certain significant estimates and assumptions used in the preparation of our consolidated financial statements.

Revenue Recognition

        The revenue of the Utilities businesses is classified as regulated on the consolidated statement of operations. Revenues from the sale of energy are recognized in the period in which the energy is delivered. The calculation of revenues earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. The revenues from the Generation segment are classified as non-regulated and are recorded based upon output delivered and capacity provided at rates as specified under contract terms or prevailing market rates. Revenues from power sales contracts entered into after 1991 with decreasing scheduled rates are recognized based on the output delivered at the lower of the amount billed or the average rate over the contract term.

Allowance for Doubtful Accounts

        The Company maintains an allowance for doubtful accounts for estimated uncollectible accounts receivable. The allowance is based on the Company's assessment of known delinquent accounts, historical experience, and other currently available evidence of the collectibility and aging of accounts receivable. There is an increased level of exposure related to the Company's regulated utilities receivables in certain non U.S. locations which are due from local municipalities and other governmental agencies. These customers are often large and normally pay within extended timeframes. The amount of historical experience is limited in some cases due to the recent nature of AES acquisitions subsequent to privatization. In addition, local political and economic factors often play a part in a municipality's current ability or willingness to pay. The Company monitors these situations closely and continues to refine its reserving policy based on both historical experience and current knowledge of the related political/economic environments.

Income Tax Reserves

        We are subject to income taxes in both the United States and numerous foreign jurisdictions. Our worldwide income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the Internal Revenue Service and other taxing authorities. The Company and certain of its subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these

41


examinations in each of the taxing jurisdictions when determining the adequacy of the provision for income taxes. Tax reserves have been established, which the Company believes to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While the Company believes that the amount of the tax estimates is reasonable, it is possible that the ultimate outcome of current or future examinations may exceed current reserves in amounts that could be material.

        Through December 31, 2006 the Company determined its tax liabilities in accordance with SFAS No. 5 Accounting for Contingencies ("SFAS No. 5"). Effective January 1, 2007 the Company adopted the provisions set forth in FIN No. 48 Accounting for Uncertainty in Income Taxes. Under FIN No. 48, positions taken on the Company's income tax return which satisfy a more-likely-than-not threshold will be recognized in the financial statements.

Long-Lived Assets

        In accordance with SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets, ("SFAS No. 144"), we periodically review the carrying value of our long-lived assets held and used, other than goodwill and intangible assets with indefinite lives, and assets to be disposed of when circumstances indicate that the carrying amount of such assets may not be recoverable or the assets meet the held for sale criteria under SFAS No. 144. These events or circumstances may include the relative pricing of wholesale electricity by region and the anticipated demand and cost of fuel. If the carrying amount is not recoverable, an impairment charge is recorded for the amount by which the carrying value of the long-lived asset exceeds its fair value. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery was probable. For non-regulated assets, an impairment charge would be recorded as a charge against earnings.

        The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, that is, other than a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for measurement, if available. In the absence of quoted market prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow projections or other indicators of fair value such as bids received, comparable sales or independent appraisals.

        In connection with the periodic evaluation of long-lived assets in accordance with the requirements of SFAS No. 144, the fair value of the asset can vary if different estimates and assumptions would have been used in our applied valuation techniques. In cases of impairment described in note 17 to the audited consolidated financial statements included in this prospectus, we made our best estimate of fair value using valuation methods based on the most current information. We have been in the process of divesting certain assets and their sales values can vary from the recorded fair value as described in note 20 to the consolidated financial statements included in this prospectus. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions, and management's analysis of the benefits of the transaction.

Goodwill

        We test goodwill for impairment annually and whenever events or circumstances make it more likely than not that impairment may have occurred, such as a significant adverse change in the business climate or a decision to sell or dispose all or a portion of a business unit. Determining whether an impairment has occurred requires valuation of the respective business unit, which we estimate using a discounted cash flow method. In applying this methodology, we rely on a number of factors, including actual operating results, future business plans, economic projections and market data.

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        If this analysis indicates goodwill is impaired, measuring the impairment requires a fair value estimate of each identified tangible and intangible asset. In this case, we supplement the cash flow approach discussed above with independent appraisals, as appropriate.

Pension and Other Postretirement Obligations

        Certain of our foreign and domestic subsidiaries maintain defined benefit pension plans (the "plan") covering substantially all of their respective employees. Pension benefits are generally based on years of credited service, age of the participant and average earnings. The measurement of our pension obligations, costs and liabilities is dependent on a variety of assumptions used by our actuaries. These assumptions include estimates of the present value of projected future pension payments to all plan participants, taking into consideration the likelihood of potential future events such as salary increases and demographic experience. These assumptions may have an effect on the amount and timing of future contributions. The plan actuary conducts an independent valuation of the fair value of pension plan assets.

        The assumptions used in developing the required estimates include the following key factors:

        The effects of actual results differing from our assumptions are accumulated and amortized over future periods and, therefore, generally affect our recognized expense in such future periods.

        Sensitivity of our pension funded status and stockholders' equity to the indicated increase or decrease in the discount rate assumption is shown below. Note that these sensitivities may be asymmetric, and are specific to the base conditions at year-end 2006. They also may not be additive, so the impact of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown. The December 31, 2006 funded status is affected by December 31, 2006 assumptions. Pension expense for 2006 is affected by December 31, 2005 assumptions. The impact on pension expense from a one percentage point change in these assumptions is shown in the table below (in millions):

Increase of 1% in the discount rate   $ (7)  
Decrease of 1% in the discount rate   $ 22  
Increase of 1% in the long-term rate of return on plan assets   $ (23 )
Decrease of 1% in the long-term rate of return on plan assets   $ 23  

Regulatory Assets and Liabilities

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

43


status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income.

Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

        AES generally uses quoted exchange prices to the extent they are available to determine the fair value of derivatives. In the absence of actively quoted market prices, we seek indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, AES will estimate prices, when possible, based on available historical and near-term future price information as well as utilizing statistical methods. When external valuation models are not available, the company utilizes internal models for valuation. For individual contracts, the use of different valuation models or assumptions could have a material effect on the calculated fair value.

New Accounting Standards

        In September 2006, the Financial Accounting Standards Board ("FASB") issued SFAS No. 157, Fair Value Measurement, ("SFAS 157"). SFAS 157 provides enhanced guidance for using fair value to measure assets and liabilities. The standard applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. The standard does not expand the use of fair value in any new circumstances.

        Over 40 current accounting standards within GAAP require (or permit) entities to measure assets and liabilities at fair value. Prior to the issuance of SFAS 157, the methods for measuring fair value were diverse and inconsistent, especially for items that are not actively traded. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company's mark-to-model value. The standard also requires expanded disclosure of the effect on earnings for items measured using unobservable data.

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        Under SFAS 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. SFAS 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity's own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy.

        SFAS 157 will apply to our interim and annual financial statements for periods beginning after January 1, 2008. We are currently evaluating the effect of this new standard on our consolidated financial statements.

        In February 2007, the FASB issued SFAS No. 159 The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115 ("SFAS 159"), which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item's fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for the Company on January 1, 2008. We are currently evaluating the effect of SFAS 159 on our consolidated financial statements and whether we intend to adopt fair value measurements for any eligible assets or liabilities.

        As discussed in Note 12, in June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes ("FIN 48") which applied to our financial statements beginning January 1, 2007. The Company adopted FIN 48 on January 1, 2007 and recorded the cumulative effect of applying the provisions of this Interpretation as an adjustment to beginning retained earnings. FIN 48 applies to all tax positions accounted for in accordance with FASB Statement No. 109. The cumulative effect of the adoption resulted in an increase to beginning accumulated deficit of $53 million.

        The Company previously disclosed that we were evaluating the impact of the following standards: EITF 06-6: Application of Issue No. 05-7 Debtor's Accounting for a Modification (or Exchange) of Convertible Debt Instruments; EITF 06-7: Issuer's Accounting for a Previously Bifurcated Conversion Option in a Convertible Debt Instrument When the Conversion Option No Longer Meets the Bifurcation Criteria in FASB Statement No. 133; and EITF 06-11: Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. We have assessed and determined that these standards will not have a material impact on our consolidated financial statements.

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Consolidated Results of Operations

 
   Nine Months Ended September 30,
   Year Ended December 31,
  
Results of operations
   2007
   2006
(Restated)
(1)
   $ change
   2006
(Restated)
(1)
   2005
(Restated)
(1)
   2004
(Restated)
(1)
   $ change
2006 vs.
2005
   $ change
2005 vs.
2004
  
 
   (in millions, except per share data)

  
Revenue:                                                  
  Latin America Generation   $ 2,475   $ 1,905   $ 570   $ 2,616   $ 2,145   $ 1,584   $ 471   $ 561  
  Latin America Utilities     3,795     3,430     365     4,595     4,161     3,205     434     956  
  North America Generation     1,622     1,444     178     1,871     1,785     1,676     86     109  
  North America Utilities     796     780     16     1,032     951     885     81     66  
  Europe & Africa Generation     682     590     92     852     735     697     117     38  
  Europe & Africa Utilities     482     419     63     571     505     463     66     42  
  Middle East & Asia Generation     686     611     75     785     600     570     185     30  
  Corporate and Other(2)     (614 )   (564 )   (50 )   (758 )   (562 )   (335 )   (196 )   (227 )
   
 
 
 
 
 
 
 
 
Total Revenue   $ 9,924   $ 8,615   $ 1,309   $ 11,564   $ 10,320   $ 8,745   $ 1,244   $ 1,575  
Gross Margin:                                                  
  Latin America Generation   $ 633   $ 781   $ (148 ) $ 1,054   $ 857   $ 616   $ 197   $ 241  
  Latin America Utilities     758     684     74     884     596     517     288     79  
  North America Generation     531     458     73     565     599     594     (34 )   5  
  North America Utilities     245     212     33     277     301     303     (24 )   (2 )
  Europe & Africa Generation     168     173     (5 )   249     186     182     63     4  
  Europe & Africa Utilities     63     95     (32 )   112     112     60     —     52  
  Middle East & Asia Generation     153     158     (5 )   200     242     252     (42 )   (10 )
Total Corporate and Other(3)     (231 )   (144 )   (87 )   (248 )   (190 )   (147 )   (58 )   (43 )
Interest expense     (1,281 )   (1,323 )   42     (1,763 )   (1,826 )   (1,816 )   63     (10 )
Interest income     363     316     47     426     375     254     51     121  
Other expense     (90 )   (162 )   72     (449 )   (110 )   (113 )   (339 )   3  
Other income     324     74     250     106     157     150     (51 )   7  
Gain (loss) on sale of investments     10     98     (88 )   98     —     (1 )   98     1  
Loss on sale of subsidiary stock     —     (536 )   536     (539 )   —     (24 )   (539 )   24  
Asset impairment expense     (38 )   (16 )   (22 )   (28 )   (16 )   (49 )   (12 )   33  
Foreign currency transaction losses on net monetary position     (2 )   (76 )   74     (88 )   (145 )   (109 )   57     (36 )
Equity in earnings of affiliates     56     65     (9 )   72     71     63     1     8  
Income tax expense     (601 )   (280 )   (321 )   (334 )   (483 )   (365 )   149     (118 )
Minority interest expense     (534 )   (428 )   (106 )   (459 )   (324 )   (195 )   (135 )   (129 )
   
 
 
 
 
 
 
 
 
Income from continuing operations     482     149     333     135     402     172     (267 )   230  
Income from operations of discontinued businesses     71     79     (8 )   105     188     41     (83 )   147  
(Loss) gain from disposal of discontinued businesses     (665 )   (59 )   (606 )   (57 )   —     91     (57 )   (91 )
Extraordinary items     —     21     (21 )   21     —     —     21     —  

Cumulative effect of accounting change
 
 
—
 
 
—
 
 
—
 
 
—
 
 
(3
)
 
—
 
 
3
 
 
(3
)
   
 
 
 
 
 
 
 
 
Net income   $ (112 ) $ 190   $ (302 ) $ 204   $ 587   $ 304   $ (383 ) $ 283  
   
 
 
 
 
 
 
 
 
PER SHARE DATA:                                                  
  Basic income per share from continuing operations   $ 0.72   $ 0.23   $ 0.49   $ 0.21   $ 0.62   $ 0.27   $ (0.41 ) $ 0.35  
  Diluted income per share from continuing operations   $ 0.71   $ 0.22   $ 0.49   $ 0.20   $ 0.61   $ 0.27   $ (0.41 ) $ 0.34  
(1)
For information regarding the restatements of our financial results, see note 1 to our consolidated financial statements under the caption "General and Summary of Significant Accounting Policies—Restatement" and note 1 to our unaudited consolidated financial statements under the caption "Financial Statement Presentation—Restatement of Consolidated Financial Statements" included in this prospectus.

(2)
Corporate and Other includes revenues from Alternative Energy and intersegment eliminations of revenues related to transfers of electricity from Tiete (generation) to Eletropaulo (utility).

(3)
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.

46

Overview of Nine Months Ended September 30, 2007 versus the Same Period 2006

        Results for the nine months ended September 30, 2007 were impacted by, among other things, increased costs from gas supply curtailments, low hydrology and spot prices for electricity in the Company's businesses in Argentina and Chile, particularly in the third quarter 2007. In many cases the fuel curtailments in this region forced these businesses to operate using higher priced fuels or to purchase energy at higher spot prices to fulfill contracts.

        Many of our contracted generation and regulated utilities have a component of fuel pass-through or fuel indexing in their contracts or regulated rates. Therefore, in a rising fuel cost environment, revenue at our subsidiaries may increase in response to the increase in fuel cost without a commensurate impact on gross margin; however, this often will negatively impact gross margin as a percentage of revenue. The sale of excess emission allowances will have an opposite impact on gross margin as a percentage of revenue as emission allowances generally have zero cost basis, so increases to revenue will be matched to increases in gross margin.

        The following is a summary discussion of the condensed consolidated revenue and gross margin which is followed by a discussion by segment.

        Revenues increased $1.3 billion, or 15%, to $9.9 billion for the nine months ended September 30, 2007, from $8.6 billion for the nine months ended September 30, 2006. Excluding the estimated impacts of foreign currency translation of approximately $381 million, revenues would have increased approximately 11% for the nine months ended September 30, 2007, as compared to the nine months ended September 30, 2006. The increase in revenues, after adjusting for favorable foreign exchange rates, was primarily due to higher rates and volume of approximately $712 million in Latin America, North America and Europe & Africa. Additionally, the Company's recent acquisition, TEG/TEP in Mexico, and the consolidation of Itabo in the Dominican Republic in June 2006 contributed approximately $220 million to the growth.

        Gross margin decreased $14 million, or 1%, to $2.6 billion for the nine months ended September 30, 2007. Excluding the impacts of foreign currency translation of approximately $115 million, gross margin would have decreased approximately $129 million or 5% for the nine months ended September 30, 2007, as compared to the nine months ended September 30, 2006. This decrease in gross margin, was primarily due to gas supply curtailments, low hydrology and higher spot prices for electricity in the Company's businesses in Argentina, Chile and Brazil of approximately $158 million, a cumulative charge of $48 million related to transmission costs at Tiete in Brazil and lower sales of excess emission allowances of approximately $48 million; partially offset by rate and volume increases in North America and contributions from new businesses of approximately $139 million. Gross margin as a percentage of revenue decreased to 26% in the nine months ended September 30, 2007, versus 30% in the nine months ended September 30, 2006 primarily due to increased costs related to the gas supply curtailment and low hydrology in Latin America, the cumulative transmission charge at Tiete and the impact of fewer sales of emissions allowance, outpacing the increased margins achieved through rate increases in North America.

47

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 Nine Months Ended September 30,
   For the Years Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
  
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
  
Latin America Generation   $ 2,475   25 % $ 1,905   22 % $ 2,616   23 % $ 2,145   21 % $ 1,584   18 %
Latin America Utilities     3,795   38 %   3,430   40 %   4,595   40 %   4,161   40 %   3,205   37 %

        Generation revenue for the nine months ended September 30, 2007 increased $570 million, or 30%, compared to the nine months ended September 30, 2006, primarily due to higher contract and spot prices at Gener (in Chile) and Alicura (in Argentina) of approximately $339 million; higher intercompany sales at Tiete of approximately $80 million; contributions of approximately $78 million due the consolidation of Itabo (beginning June 2006). The impact of favorable foreign currency translation was approximately $26 million for the nine months ended September 30, 2007 as compared to the nine months ended September 30, 2006.

        Utilities revenue for the nine months ended September 30, 2007 increased $365 million, or 11%, compared to the nine months ended September 30, 2006, primarily as the result of favorable foreign currency translation of approximately $282 million and increased volume sales of approximately $81 million, primarily at Eletropaulo in Brazil.

        Generation revenue increased $471 million, or 22%, due to increased intercompany volume sales and contract energy prices from Tiete to Eletropaulo in Brazil, the acquisition of the controlling shares of Itabo (which resulted in full consolidation of Itabo beginning in June 2006) in the Dominican Republic and an increase in spot market and contract energy prices at Gener in Chile and Alicura and Parana in Argentina.

        Utilities revenue increased $434 million, or 10%, due to favorable foreign currency translation impacts, increased demand Eletropaulo primarily from increased volume for industrial and commercial customers due to improved economic conditions and increased tariff rates at CAESS/EEO in El Salvador.

        Generation revenue increased $561 million, or 35% due to increased intercompany volume sales and contract energy prices from Tiete to Eletropaulo in Brazil, higher contract energy prices at Gener in Chile and increased volume at Alicura in Argentina and Gener.

        Utilities revenue increased $956 million, or 30% due to favorable foreign currency translation impacts, the recognition of a retroactive tariff increase as well as an increase in the average customer tariff due to a rate increase at Eletropaulo in Brazil in 2005.

48


        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 Nine Months Ended September 30,
   For the Years Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
  
Gross Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
  
Latin America Generation   $ 633   24 % $ 781   30 % $ 1,054   31 % $ 857   29 % $ 616   24 %
Latin America Utilities     758   29 %   684   26 %   884   26 %   596   20 %   517   20 %

        Generation gross margin for the nine months ended September 30, 2007 decreased $148 million, or 19%, compared to the nine months ended September 30, 2006, primarily due to increased cost from gas supply curtailments, low hydrology and higher spot prices for electricity in the Company's businesses in Argentina and Chile as well as at Uruguaiana in Brazil of approximately $163 million, partially offset by increased intercompany sales at Tiete in Brazil.

        Utilities gross margin for the nine months ended September 30, 2007 increased $74 million or 11% compared to the nine months ended September 30, 2006, primarily due to favorable foreign currency translation of approximately $112 million; lower cost in Brazil of approximately $53 million; increased cost recorded in the prior year of approximately $46 million related to a labor contingency reserve at Eletropaulo in Brazil offset by reduced tariff rates primarily at Eletropaulo of approximately $142 million.

        Generation gross margin increased $197 million, or 23%, due to increased intercompany volume sales and contract energy prices from Tiete to Eletropaulo in Brazil, an increase in spot market and contract energy prices at Gener in Chile and the acquisition of the controlling shares of Itabo in the Dominican Republic, partially offset by higher purchased electricity and fuel prices at Uruguaiana in Brazil and higher transmission costs, regulator fees and unfavorable foreign exchange rates at Tiete in Brazil.

        Utilities gross margin increased $288 million, or 48%, due to the recording of $192 million of gross bad debts reserve in the second quarter of 2005 related to the collectibility of certain municipal receivables at Eletropaulo and Sul in Brazil, favorable foreign exchange rates in Eletropaulo and a decrease in purchased electricity volume and prices at Eletropaulo. The increase in Utilities gross margin was partially offset by the increase for legal reserves at Eletropaulo.

        Generation gross margin increased $241 million, or 39%, due to higher contract energy prices at Gener in Chile, partially offset by increased purchased electricity and fuel volumes at Andres in the Dominican Republic, unfavorable foreign exchange rates at Gener and Tiete in Brazil and higher transmission costs at Gener.

        Utilities gross margin increased $79 million, or 15%, due to higher overall revenues and favorable foreign exchange rates at Eletropaulo in Brazil. The increase in Utilities gross margin was partially offset by the recording of $192 million of gross bad debts reserve in the second quarter of 2005 related to the collectibility of certain municipal receivables at Eletropaulo and Sul in Brazil, increased transmissions costs and legal reserves at Eletropaulo.

49


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 Nine Months Ended September 30,
   For the Years Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
  
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
  
North America Generation   $ 1,622   16 % $ 1,444   17 % $ 1,871   16 % $ 1,785   17 % $ 1,676   19 %
North America Utilities     796   8 %   780   9 %   1,032   9 %   951   9 %   885   10 %

        Generation revenue for the nine months ended September 30, 2007 increased $178 million, or 12%, compared to the nine months ended September 30, 2006, primarily due to the Company's recent acquisition of TEG/TEP, which contributed approximately $143 million over the prior year and increases in rate and volume sales of approximately $68 million primarily driven by the Company's New York facility offset by lower emission sales of $40 million.

        Utilities revenue for the nine months ended September 30, 2007 increased $16 million, or 2%, compared to the nine months ended September 30, 2006, primarily as the result of increased volume sales of $40 million offset by decreased rates of $22 million at IPL.

        Generation revenue increased $86 million, or 5%, primarily due to higher spot market prices of $75 million in New York, increased charge rates for fuel and variable maintenance costs of $20 million in Puerto Rico, increased tariff rates and volume of $11 million at Deepwater in Texas primarily due to a new contract, a $9 million increase in sales of emission allowances in New York, higher volumes at Thames in Connecticut, and improved operating performance at Southland in California. These increases were partially offset by lower volume and an outage in 2006 at Merida III in Mexico.

        Utilities revenue increased $81 million, or 9%, primarily due to higher pricing at IPL in Indiana due to the pass through of higher fuel costs and an increase in costs recovered from a NOx compliance construction program, slightly offset by a decrease in quantity of kWh sold, due to a 20% decrease in the cooling degree days and a 10% decrease in heating degree days compared to 2005.

        Generation revenue increased $109 million, or 7%, primarily due to higher prices of $43 million and an increase in the sale of emission allowances at our business in New York, higher contract prices of $33 million at Merida III in Mexico, higher prices of $24 million in Puerto Rico, and favorable currency impacts of $9 million in Mexico. These increases were partially offset by a decrease in contract price at Shady Point in Oklahoma and outages at Thames in Connecticut.

        Utilities revenue increased $66 million, or 7%, primarily due to increase in tariffs and volume at IPL in Indiana. The volume increase was primarily due to a 37% increase in cooling degree days compared to 2004, as well as an increased customer base of approximately 4,300 customers or 1% during 2005.

50


        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 Nine Months Ended September 30,
   For the Years Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
  
Gross Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
  
North America Generation   $ 531   21 % $ 458   18 % $ 565   17 % $ 599   20 % $ 594   23 %
North America Utilities     245   9 %   212   8 %   277   8 %   301   10 %   303   12 %

        Generation gross margin for the nine months ended September 30, 2007 increased $73 million, or 16%, compared to the nine months ended September 30, 2006, primarily due to the acquisition of TEG/TEP of $44 million and net increases in rate and volume sales in New York of $66 million offset by lower sales of excess emissions allowances of $40 million.

        Utilities gross margin for the nine months ended September 30, 2007 increased $33 million, or 16%, compared to the nine months ended September 30, 2006, primarily due to increased volume sales of $32 million at IPL.

        Generation gross margin decreased $34 million, or 6%, primarily due to outages in 2006 at Warrior Run in Maryland, Hawaii, Ironwood in Pennsylvania and several plants in New York, as well as a scheduled reduction in pricing of the power purchase agreements for our Hawaii plant. The decrease was partly off set by higher energy margins and sales of emission allowances by $9 million in New York and increased contract prices at Deepwater in Texas.

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

        Generation gross margin increased $5 million, or 1%, with an increase in sale of emissions allowances in New York of $43 million, an increase in contract prices at Deepwater in Texas and higher volume at Warrior Run in Maryland and our Hawaii plant. These increases were partly offset by a decrease in contract pricing at Shady Point in Oklahoma, outages incurred at Thames in Connecticut, and lower dispatch at Southland in California.

        Utilities gross margin decreased $2 million or 1% primarily due to IPL in Indiana having produced a greater portion of their electricity during 2005 using peaking unit resources as a result of higher electricity demand caused by higher average temperatures in the third quarter of 2005 as well as an increase in market price of purchased power.

51


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 Nine Months Ended September 30,
   For the Years Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
  
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
  
Europe & Africa Generation   $ 682   7 % $ 590   7 % $ 852   7 % $ 735   7 % $ 697   8 %
Europe & Africa Utilities     482   5 %   419   5 %   571   5 %   505   5 %   463   5 %

        Generation revenue for the nine months ended September 30, 2007 increased $92 million, or 16%, compared to the nine months ended September 30, 2006, primarily due to increased volume and rate sales of $77 million in Kazakhstan and Hungary and favorable foreign currency translation of approximately $53 million, partially offset by lower sales of excess emission allowances of $28 million and lower volume at Kilroot. The decrease in emission sales is primarily attributable to a decrease in the market value of European Union allowances for CO2 emissions due to an oversupply of allowances credits.

        Utilities revenue for the nine months ended September 30, 2007 increased $63 million, or 15%, compared to the nine months ended September 30, 2006, primarily due to increased tariff rates of approximately $39 million in the Ukraine and approximately $19 million due to favorable foreign currency translation.

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

        Utilities revenue increased $66 million, or 13%, primarily due to increased demand and tariff rates at Sonel in Cameroon and at our businesses in the Ukraine.

        Generation revenue increased $38 million, or 5%, primarily due to increased volume sales and contract energy prices at both Borsod and Tisza II in Hungary and at Ekibastuz in Kazakhstan and increased sales in Kazakhstan through our centralized trading office in Altai.

        Utilities revenue increased $42 million, or 9%. Excluding the impact of foreign currency translation, Utilities revenue increased primarily due to higher volume sales and tariff rates at our businesses in the Ukraine and higher volumes at Sonel in Cameroon.

52


        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 Nine Months Ended September 30,
   For the Years Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
  
Gross Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
  
Europe & Africa Generation   $ 168   7 % $ 173   7 % $ 249   7 % $ 186   6 % $ 182   7 %
Europe & Africa Utilities     63   2 %   95   4 %   112   3 %   112   4 %   60   2 %

        Generation gross margin for the nine months ended September 30, 2007 decreased $5 million, or 3%, compared to the nine months ended September 30, 2006, primarily due to lower sales of excess emissions allowances of approximately $28 million, partially offset by approximately $20 million related to rate and volume increases in Kazakhstan.

        Utilities gross margin for the nine months ended September 30, 2007 decreased $32 million, or 34%, compared to the nine months ended September 30, 2006, primarily due to higher fuel cost resulting from lower hydrology, higher cost related to staffing and higher depreciation of approximately $27 million at SONEL in Cameroon.

        Generation gross margin increased $63 million, or 34%, primarily due to higher pricing on improved volumes at Ekibastuz and our centralized trading office Altai, both in Kazakhstan, margin on CO2 emission allowance sales by Tisza II in Hungary and Bohemia in the Czech Republic.

        Utilities gross margin was flat compared to the prior year primarily due to higher expenses at Sonel in Cameroon, offset by improved volume sales and tariff rates for Sonel and our businesses in Ukraine.

        Generation gross margin increased $4 million, or 2%, primarily due to higher sales volumes at Tisza II in Hungary, partially offset by increased costs at the Maikuben coal mine in Kazakhstan.

        Utilities gross margin increased $52 million, or 87%, primarily due to higher overall revenues, better demand and lower fixed expenses at Sonel in Cameroon.

Asia

        The following table summarizes revenue for the Generation segment in Asia for the periods indicated (in millions):

Asia
   For the Nine Months Ended
September 30,
   For the Years Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
  
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
   Revenue
   % of
Total
Revenue
  
Asia Generation   $ 686   7 % $ 611   7 % $ 785   7 % $ 600   6 % $ 570   7 %

53

        Generation revenue for the nine months ended September 30, 2007 increased $75 million, or 12%, compared to the nine months ended September 30, 2006, primarily due to higher dispatch in Pakistan of approximately $67 million, offset by lower volumes in China.

        Asia revenues increased $185 million, or 31%, to $785 million in 2006 from $600 million in 2005. Excluding the estimated impacts of foreign currency translation, revenues would have remained constant at 31% from 2005 to 2006. The Asia business consists entirely of Generation revenue. Revenues increased primarily due to increased dispatch of approximately $150 million at the two Pakistan power generation plants, Lal Pir and Pak Gen, as well as $31 million of improvements at Kelanitissa primarily due to favorable dispatch which accounted for $16 million of the increase and increased rates which accounted for $15 million of that increase.

        Asia Generation revenue increased $30 million, or 5%, to $600 million in 2005 from $570 million in 2004. Excluding the estimated impacts of foreign currency translation, revenues would have remained constant at 13% from 2004 to 2005. Revenue increased primarily due to increased volumes at Ras Laffan in Qatar of $35 million; at Kelanitissa in Sri Lanka for $12 million; and at Lal Pir in Pakistan for $8 million.

        The following table summarizes gross margin for the Generation segment in Asia for the periods indicated (in millions):

Asia
   For the Nine Months Ended
September 30,
   For the Years Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
  
Gross Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
   Gross
Margin
   % of
Total
Gross
Margin
  
Asia Generation   $ 153   6 % $ 158   6 % $ 200   6 % $ 242   8 % $ 252   10 %

        Generation gross margin for the nine months ended September 30, 2007 decreased $5 million, or 3%, compared to the nine months ended September 30, 2006, primarily due to decreased volume at Chigen in China. The impact of higher revenue at Pakistan and Kelanitissa produced a relatively flat impact on gross margin given the related increased cost.

        The gross margin of Asia decreased $42 million, or 17%, to $200 million in 2006 from $242 million in 2005. Gross margins decreased primarily due to a $16.4 million increase in unfavorable variable operating and maintenance costs and $5.5 million of increases associated with a rural grid fund tax.

        Gross margin decreased $10 million, or 4%, to $242 million in 2005 from $252 million in 2004. Generation gross margin increased $32 million, or 13%, primarily due to improved volume in the Middle East markets of $53 million, which was partially offset by an increase in unfavorable rate variances and depreciation of $17 million and $8 million respectively.

54

Corporate and Other Expenses

        Corporate and other expenses include general and administrative expenses related to corporate staff functions and/or initiatives—primarily executive management, finance, legal, human resources, information systems and certain development costs which are not allocable to our business segments. In addition, this line item includes net operating results from other businesses which are immaterial for the purposes of separate segment disclosure and, the effects of eliminating transactions, such as management fee arrangements and self-insurance charges, between the operating segments and corporate.

        Corporate and other expenses increased $87 million, or 60%, to $231 million for the nine months ended September 30, 2007 from $144 million for the nine months ended September 30, 2006. The increase is primarily due to higher spending related to the strengthening of our finance organization and professional fees to complete the restatement and remediation efforts of approximately $45 million and higher business development spending to support new initiatives of approximately $29 million.

        Corporate and other expenses increased $58 million, or 31%, to $248 million in 2006 from $190 million in 2005. The increase is primarily due to increases in higher corporate development spending primarily in support of our Alternative Energy and Latin American businesses.

        Corporate and other expenses increased $43 million, or 29%, to $190 million in 2005 from $147 million in 2004. This increase was primarily the result of higher professional and consulting fees associated with the restatement of the company's financial statements as well as increased compensation costs. For years ended December 31, 2006, 2005 and 2004, Corporate and Other were 2% of total revenues.

Interest expense

        Interest expense decreased $42 million, or 3%, to $1,281 million for the nine months ended September 30, 2007 from $1,323 million for the nine months ended September 30, 2006. The decrease for the nine months ended September 30, 2007 is attributable to an agreement reached between one of our Brazilian subsidiaries and a large customer in the third quarter of 2006 to settle mutual accounts receivable and payable between the two parties. This agreement allowed for an inflation adjustment on the liability that resulted in $20 million of additional interest expense recognized in the third quarter of 2006 at the Brazilian subsidiary. The inflation adjustment on the receivable balance is included in interest income. Interest expense also decreased due to the benefits of debt retirement activities and lower interest rates at several of our Latin American subsidiaries. These decreases were offset by new debt at one of our subsidiaries in New York and one in Kazakhstan, debt at recently acquired businesses, an increase in interest rate at one of our Brazilian subsidiaries, and negative impacts from foreign currency translation in Brazil.

        Interest expense decreased $63 million, or 3%, to $1,763 million in 2006 from $1,826 million in 2005. Interest expense decreased primarily due to the benefits of debt retirements principally in the U.S., Brazil and the Dominican Republic, lower interest rates at certain of our businesses, and decreased amortization of deferred financing costs, offset by negative impacts from foreign currency translation in Brazil.

        Interest expense increased $10 million, or 1%, to $1,826 million in 2005 from $1,816 million in 2004. Interest expense increased primarily due to negative impacts from foreign currency translation in Brazil, offset by the benefits of debt retirements in the U.S. and lower interest rate hedge related costs.

Interest income

        Interest income increased $47 million, or 15%, to $363 million for the nine months ended September 30, 2007 from $316 million for the nine months ended September 30, 2006. The increase is

55


primarily due to $12 million in interest income recognized at one of our subsidiaries in Brazil on restricted judicial escrow deposits, interest income at recently acquired businesses, favorable foreign currency translation in Brazil, interest income on investments and cash equivalents principally at Brazil and Kazakhstan and approximately $19 million in interest income recognized in the second quarter of 2007 related to a gross receipts tax recovery at two of our Latin American businesses. These increases were offset by reduced interest income from lower regulatory asset balances at one of our Brazilian subsidiaries and $22 million recognized as interest income in the third quarter of 2006 related to an accounts receivable inflation adjustment associated with an agreement between one of our Brazilian subsidiaries and a large customer to settle mutual accounts receivable and payable between the two parties (the inflation adjustment on the payable balance is included in interest expense), and interest income at one of our subsidiaries in the Dominican Republic related to the settlement of certain net receivables with the government in February 2006.

        Interest income increased $51 million, or 14%, to $426 million in 2006 from $375 million in 2005. Interest income increased primarily due to favorable foreign currency translation on the Brazilian Real higher cash and short-term investment balances at certain of our subsidiaries and interest income at one of our subsidiaries in the Dominican Republic related to the settlement of certain net receivables with the government.

        Interest income increased $121 million, or 48%, to $375 million in 2005 from $254 million in 2004. Interest income increased primarily due to favorable foreign currency translation on the Brazilian Real and higher cash and short-term investment balances at certain of our subsidiaries combined with higher short-term interest rates.

Other income

 
   Nine Months Ended
September 30,
   Years Ended December 31,
 
   2007
   2006
   2006
   2005
   2004
 
   (in millions)
Gain on extinguishment of liabilities   $ 14   $ 23   $ 45   $ 82   $ 70
Gain on sale of assets     14     3     18     7     11
Legal/dispute settlement     17     1     1     10     11
Contract settlement gain     137     —     —     —     —
Gross receipts tax recovery     93     —     —     —     —
Other     49     47     42     58     58
   
 
 
 
 
Total other income   $ 324   $ 74   $ 106   $ 157   $ 150
   
 
 
 
 

        Other income increased $250 million to $324 million for the nine months ended September 30, 2007 from $74 million for the nine months ended September 30, 2006. The increase is primarily due to a $137 million contract settlement gain at one of our subsidiaries in New York, a $93 million gross receipts tax recovery at two of our Latin American subsidiaries, and $17 million related to a legal settlement during the first quarter of 2007 at one of our subsidiaries in Brazil.

        Other income decreased $51 million to $106 million in 2006 from $157 million in 2005. Other income decreased primarily due to activity at our Brazilian subsidiaries, including the expiration of a tax liability of $70 million and a gain related to the determination of the collectibility of the Sao Paulo municipality agreement in 2005.

        Other income increased $7 million to $157 million in 2005 from $150 million in 2004. Other income increased primarily due to the expiration of a tax liability in Brazil during 2005 coupled with

56


gains on liability and debt extinguishments at one of the Company's subsidiaries in Latin America and one in Europe and Africa.

Other expense

 
   Nine Months Ended
September 30,
   Years Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
  
 
   (in millions)

  
Loss on extinguishment of liabilities   $ (4 ) $ (63 ) $ (181 ) $ (3 ) $ (33 )
Regulatory special obligations     —     —     (139 )   —     —  
Write-down of disallowed regulatory assets     —     —     (36 )   —     —  
Legal/dispute settlement     (22 )   (16 )   (31 )   (30 )   (5 )
Loss on sale and disposal of assets     (34 )   (19 )   (28 )   (47 )   (22 )
Marked-to-market loss on commodity derivatives     (2 )   (3 )   —     —     (5 )
Other     (28 )   (61 )   (34 )   (30 )   (48 )
   
 
 
 
 
 
Total other expense   $ (90 ) $ (162 ) $ (449 ) $ (110 ) $ (113 )
   
 
 
 
 
 

        Other expense decreased $72 million to $90 million for the nine months ended September 30, 2007 from $162 million for the nine months ended September 30, 2006. The decrease is primarily due to a $40 million loss on the retirement of senior subordinated debentures at the parent, publicly-held holding company, The AES Corporation, excluding its subsidiaries and affiliates (the "parent company") and charges of $22 million related to debt extinguishments at our businesses in El Salvador, both recognized during the first quarter of 2006, as well as the regulatory assets write-off and increase in legal contingencies items mentioned above. These decreases were offset by a $22 million charge recorded in the first quarter of 2007 related to an increase in legal reserves in Kazakhstan.

        Other expense increased $339 million to $449 million in 2006 from $110 million in 2005. Other expense increased primarily due to losses associated with the early extinguishment of debt at several of our Latin American businesses, special obligations charges and a write-down of disallowed regulatory assets at one of our subsidiaries in Brazil.

        Other expense decreased $3 million to $110 million in 2005 from $113 million in 2004. Other expense decreased primarily due to higher losses related to equity swap agreements to retire debt at the parent company in 2004, offset by higher losses on sales and disposals of assets at one of our subsidiaries in Brazil and increased legal settlement costs at the parent company and one of our North American subsidiaries in 2005.

Asset Impairment Expense

        Asset impairment expense increased $22 million to $38 million for the nine months ended September 30, 2007 from $16 million for the nine months ended September 30, 2006. Asset impairment expense for the nine months ended September 30, 2007 consisted primarily of an impairment charge of $25 million triggered by a failure of a compressor at our Placerita subsidiary. This was coupled with an impairment charge of $10 million related to the curtailment of operations at Coal Creek, a coal mine owned by our subsidiary Cavanal Minerals in the third quarter of 2007. Asset impairment expense for the nine months ended September 30, 2006 consisted primarily of a pre-tax impairment charge of $11 million related to AES Ironwood, a gas-fired combined cycle generation plant located in the United States. This impairment was caused by a forced outage which was necessary to repair a

57


damaged combustion turbine. This was coupled with an impairment charge of $5 million related to a decrease in the market value of five held-for-sale gas turbines at our subsidiary Itabo located in the Dominican Republic.

        As discussed in Note 17 to the audited consolidated financial statements, asset impairment expense for the year ended 2006 was $28 million and consisted primarily of the following:

        During the fourth quarter of 2006, there was a pre-tax impairment charge of $6 million related to AES China Generating Co. Ltd. (Chigen) equity investment in Wuhu, a coal-fired plant located in China. The equity impairment in Wuhu was required as a result of a goodwill impairment analysis at Chigen. During the second quarter of 2006, there was a pre-tax impairment charge of $11 million related to AES Ironwood, a gas-fired combined cycle generation plant located in the United States. The fixed asset impairment was caused by a forced outage which was necessary in order to repair a damaged combustion turbine.

        Asset impairment expense for the year 2005 was $16 million and consisted primarily of the following:

        During the third quarter of 2005, there was a pre-tax impairment charge of $6 million related to Totem Gas Storage, LLC (Totem). The investment asset impairment was due to AES's notification from the sole managing member's intention to dissolve, liquidate, and terminate Totem. This charge, combined with a $1.5 million impairment recognized in the fourth quarter of 2004, represented a complete write-down of AES's investment in Totem. During the first quarter of 2005, there was a pre-tax impairment charge of $5 million related to AES Southland (Southland). The fixed asset impairment was booked when, in the course of evaluating the impairment of long lived assets in accordance with SFAS No. 144, it was determined that the net book value of the peaker units were not fully realizable. During the fourth quarter of 2005, there was an additional pre-tax impairment charge of $2.5 million which represented the remaining carrying value of these units.

        Asset impairment expense for the year 2004 was $49 million and consisted primarily of the following:

        During the fourth quarter of 2004, there was a pre-tax impairment charge of $15 million related to Aixi, a coal-fired power plant located in China. The investment asset impairment was booked when, in the course of evaluating the impairment of long lived assets in accordance with SFAS No. 144, it was determined that the net book value of this facility was not fully realizable due to circumstances surrounding its operational performance. During the fourth quarter of 2004, there was a pre-tax impairment charge of $25 million related to Deepwater, a petroleum coke-fire cogeneration plant. The investment asset impairment of capitalized costs associated with emission-related improvements was recorded when it was determined that a different strategy would be used to reduce emissions and that the improvements had no alternative uses.

Gain (loss) on sale of investments

        Gain on sale of investments decreased $88 million to $10 million for the nine months ended September 30, 2007 from $98 million for the nine months ended September 30, 2006. Gain on sale of investments for the nine months ended September 30, 2007 included a net gain of $10 million on the sale of 0.91% of our ownership in Gener in May 2007. Gain on sale of investments for the nine months ended September 30, 2006 included a net gain of $87 million on the sale of our equity investment in a power project in Canada (Kingston) in March 2006, and a net gain of $9 million on the transfer of Infoenergy, a wholly owned AES subsidiary, to Brasiliana in September 2006. Brasiliana is 54% owned by BNDES, but controlled by AES. This transaction was part of the Company's agreement with BNDES to terminate the SUL Option, which was a one-year call option to acquire a 53.85% ownership

58


interest of Sul and which would require the Company to contribute its equity interest in Sul to Brasiliana. The Sul Option became exercisable on December 22, 2005.

        Gain on sale of investments was $98 million in 2006 and was primarily comprised of the following:

        There was no gain on sale of investments in 2005 and a $1 million loss on sale of investments in 2004.

Loss on sale of subsidiary stock

        As discussed in Note 13 to the unaudited consolidated financial statements, in September 2006, Brasiliana's wholly owned subsidiary, Transgás, sold a 33% economic ownership in Eletropaulo, a regulated electric utility in Brazil. Despite the reduction in economic ownership, there was no change in Brasiliana's voting interest in Eletropaulo and Brasiliana continues to control Eletropaulo. Brasiliana received $522 million in net proceeds on the sale. On October 5, 2006, Transgás sold an additional 5% economic ownership in Eletropaulo for $78 million in net proceeds. For the year ended 2006 and nine months ended September 30, 2006, AES recognized a pre-tax loss of $539 million and $536 million, respectively, as a result of the recognition of previously deferred currency translation losses.

        In December 2004, an IPO of 35% of the shares of Barka was completed pursuant to the terms of the power and water purchase agreement. For the twelve months ended December 31, 2004, AES recognized a pre-tax loss of $24 million as a result of the sale of Barka shares.

Foreign currency transaction losses on net monetary position

        The following table summarizes the losses on the Company's net monetary position from foreign currency transaction activities.

 
   Nine months ended September 30,
   Years Ended December 31,
  
 
   2007
   2006
   2006
   2005
   2004
  
 
   (in millions)

  
AES Corporation   $ 12   $ (15 ) $ (17 ) $ 10   $ (8 )
Argentina     (8 )   (6 )   (3 )   (5 )   (6 )
Brazil     (2 )   (49 )   (56 )   (96 )   (58 )
Dominican Republic     1     —     —     1     (28 )
Pakistan     (4 )   (13 )   (18 )   (22 )   (17 )
Chile     (1 )   —     —     (20 )   (3 )
Kazakhstan     8     —     1     (4 )   14  
Colombia     (7 )   3     (1 )   (5 )   (8 )
Cameroon     —     2     2     (4 )   5  
Other     (1 )   2     4     —     —  
   
 
 
 
 
 
Total(1)   $ (2 ) $ (76 ) $ (88 ) $ (145 ) $ (109 )
   
 
 
 
 
 
(1)
Includes $31 million and $46 million of losses on foreign currency derivative contracts for the nine months ended September 30, 2007 and 2006, respectively. Includes $(58) million, $(119) million and $(89) million of losses on foreign currency derivative contracts for December 31, 2006, 2005 and 2004, respectively.

59

        The Company recognized $2 million foreign currency transaction losses for the nine months ended September 30, 2007 compared to $76 million for the nine months ended September 30, 2006. The $74 million decrease was primarily due to fluctuations in AES Corporation, Brazil, Pakistan, Kazakhstan and Colombia.

        The $12 million foreign currency gain at AES Corporation for the nine months ended September 30, 2007 compared to the $15 million loss for the nine months ended September 30, 2006 is primarily the result of favorable rates for the Euro.

        The decrease in foreign currency transaction losses in Brazil of $47 million is due to a decrease in foreign currency transaction losses of $21 million in Eletropaulo primarily as a result of swap contracts that were fully paid and executed in 2006 as Eletropaulo converted U.S. Dollar debt to Brazilian Real debt. Eletropaulo also experienced higher foreign currency transaction gains of $18 million associated with energy purchases denominated in U.S. Dollar as the Brazilian Real appreciated 17% for the nine months ended September 30, 2007. Sul extinguished U.S. Dollar denominated debt in the second quarter of 2006, resulting in less foreign currency transaction gains in 2007 of $14 million. The change in the functional currency of Brasiliana Energia, S.A. to Brazilian Real in the fourth quarter of 2006 resulted in less foreign currency transaction losses of $13 million in 2007 as no foreign currency transaction gains or losses were recorded in 2007. Additionally, foreign currency transaction losses decreased by $10 million related to a forward exchange contract in Tiete during the third quarter of 2006 that was fully paid and executed by the end of 2006.

        The decrease in foreign currency transaction losses in Pakistan is due to repayment of Yen denominated debt, coupled with a 3% depreciation of the Yen to the US Dollar, which resulted in a reduction of $9 million foreign currency translation losses for the nine months ended September 30, 2007.

        The favorable change in foreign currency transaction gains in Kazakhstan of $8 million for the nine months ended September 30, 2007, is primarily due to $6 million foreign currency transaction gains recorded on debt denominated in currencies other than the Kazakh Tenge functional currency and $3 million foreign currency transaction gains related to energy sales denominated and fixed in the U.S. Dollar.

        The decrease in foreign currency transaction gains of $10 million Colombia is primarily due to the appreciation of the Colombian Peso by 11% for the nine months ended September 30, 2007 compared to 2006 at Chivor (a U.S. dollar functional currency subsidiary).

        The Company recognized foreign currency transaction losses of $88 million in 2006 compared to losses from foreign currency transactions of $145 million in 2005. The $57 million decrease in losses for 2006 as compared to 2005 was primarily related to lower foreign currency transaction losses in Brazil and Chile offset by increased foreign currency transaction losses at the parent company. Foreign currency movements typically result from changes in U.S. Dollar exchange rates at subsidiaries whose functional currency is not the U.S. Dollar, as well as gains or losses on monetary assets and liabilities denominated in a currency other than the functional currency of the entity and gains or losses on foreign currency derivatives.

        The reduction in foreign currency transaction losses in Brazil is primarily due to a reduction in derivative transaction losses as a result of the reduction in U.S. Dollar denominated debt balances at Eletropaulo partially offset by a decrease in foreign currency transaction gains associated with U.S. Dollar denominated debt balances as the Brazilian Real appreciated 13% in 2006 as compared to 2005. The reduction in foreign currency transaction losses in Chile is primarily due to the devaluation of the

60


Chilean Peso by 4% in 2006 versus 2005, resulting in decreased losses on foreign currency derivative contracts at Gener.

        The Company recognized foreign currency transaction losses of $145 million in 2005 compared to losses from foreign currency transactions of $109 million in 2004. The $36 million increase in losses for 2005 as compared to 2004 was primarily related to the gains in the Dominican Republic partially offset by losses in Brazil and Chile. The Dominican Peso devalued 11.3% in 2005 as compared to a 31.2% appreciation in 2004 contributing to $29 million of the change year over year partially related to one of our Dominican businesses which has a net monetary liability position denominated in the Dominican Peso. The Brazilian Real appreciated 11.7% during 2005 compared to 7.5% in 2004 offsetting the overall decrease in foreign currency losses by $38 million. The Chilean Peso appreciated 15.9% during 2005 compared to no change in 2004. The appreciation of the Chilean Peso increased losses of foreign currency derivative contracts in our Chilean businesses offsetting the overall decrease in foreign currency losses by $17 million.

Equity in earnings of affiliates

        Equity in earnings of affiliates decreased $9 million, or 14%, to $56 million for the nine months ended September 30, 2007 from $65 million for the nine months ended September 30, 2006. The decrease was primarily due to the favorable settlement of a legal claim in the first quarter of 2006 related to AES Barry, an equity method investee of AES, decreased earnings at Itabo, an equity method investment in the Dominican Republic in 2006 as compared to 2007, as well as the sale of Kingston during the first quarter of 2006. The decrease was partially offset by the impact of decreased losses at Cartagena, an equity method investment in Spain in 2006 as compared to 2007.

        Equity in earnings of affiliates increased $1 million, or 1%, to $72 million in 2006 from $71 million in 2005. The increase was primarily due to the settlement of a legal claim in 2006 related to AES Barry, an equity method investment of AES during the first quarter of 2006, and higher earnings at several affiliates in Latin America. The increase was offset by the impact of increased losses at Cartagena, an equity method investment in Spain, in 2006 as compared to 2005.

        Equity in earnings of affiliates increased $8 million, or 13%, to $71 million in 2005 from $63 million in 2004. The increase was primarily due to a plant fire causing lower earnings in 2004 at our affiliate in Canada, improved operations from our affiliates in India and the Netherlands, partially offset by reduced earnings due to higher coal prices at our affiliates in China.

Other non-operating expense

        Other non-operating expense was $45 million for the nine months ended September 30, 2007 and was due to an other than temporary impairment in the Company's investment in AgCert, a United Kingdom based corporation that produces emission reduction credits. The Company acquired its investment in AgCert in May 2006 and, as required by generally accepted accounting principles, defined these securities as "available for sale". The market value of these securities, based on traded market prices, materially declined during the first half of 2007. Based on accounting guidance outlined in FAS 115, Accounting for Certain Investments in Debt and Equity Securities, management concluded that the decline was "other than temporary" and recorded an impairment charge of $40 million in the second quarter of 2007. Additionally, a charge of $5 million was also recorded for the decrease in value of the AgCert warrants in the second quarter of 2007.

        During the third quarter of 2007, the value of this investment further declined by approximately $7 million. Management concluded that the decline was temporary and recorded the loss in

61

accumulated other comprehensive loss. At September 30, 2007, the remaining investment in AgCert was approximately $5 million.

Income taxes

        Income tax expense on continuing operations increased $321 million to $601 million for the nine months ended September 30, 2007 from $280 million for the nine months ended September 30, 2006. The Company's effective tax rates were 37% and 33% for the nine months ended September 30, 2007 and 2006, respectively. The net increase in effective tax rate for the nine month period in 2007 compared to the same period in 2006 was, in part, due to tax expense caused by the other-than-temporary impairment in the Company's investment in AgCert, the impact of an appreciating Real in certain of our Brazilian subsidiaries and the release of a valuation allowance at Eletropaulo in the second quarter of 2006 related to deferred tax assets for certain pension obligations offset by a tax benefit recorded upon the release of valuation allowance at one of our subsidiaries in Argentina in 2007. Additionally, the effective tax rate for the 2006 period was impacted by the $554 million pre-tax book loss on the sale by Transgás of shares of Eletropaulo preferred stock. This transaction resulted in a $69 million tax benefit for the Brazilian tax loss incurred on the sale of Eletropaulo shares and a $52 million tax benefit related to the release of valuation allowance at Transgás on its deferred tax asset for net operating loss carryforwards.

        Income tax expense related to continuing operations decreased $149 million to $334 million in 2006 from $483 million in 2005. The Company's effective tax rates were 36% for 2006 and 40% for 2005. The reduction in the 2006 effective tax rate was due, in part, to the second quarter 2006 release of a $43 million valuation allowance at the Company's Brazilian subsidiary, Eletropaulo, related to its deferred tax assets on certain pension obligations, a decrease in U.S. taxes on distributions from certain non-U.S. subsidiaries due to recent changes in tax laws, and the sale of Kingston in the first quarter of 2006, the gain on which was not taxable. The reduction in the 2006 effective tax rate was offset in part by the Special Obligation liabilities recorded at Eletropaulo and Sul.

        Income tax expense related to continuing operations increased $118 million to $483 million in 2005 from $365 million in 2004. The Company's effective tax rates were 40% for 2005 and 50% for 2004. The reduction in the 2005 effective tax rate was due, in part, to the reduction of taxes imposed on earnings of and distributions from the Company's foreign subsidiaries and adjustments derived from the Company's 2004 income tax returns filed in 2005.

Minority interest

        Minority interest expense increased $106 million to $534 million for the nine months ended September 30, 2007 from $428 million for the nine months ended September 30, 2006. The increase is primarily due to a decrease in our economic ownership in Eletropaulo from 34% to 16% during the third quarter of 2006 as well as increased earnings at Brasiliana Energia, a Brazilian subsidiary, offset by decreased earnings at Uruguaiana, a Brazilian subsidiary.

        Minority interest expense, net of tax, increased $135 million to $459 million in 2006 from $324 million in 2005. The increase is primarily due to higher earnings from our Brazilian companies offset by a decrease in the third quarter of 2006 in our economic ownership in Eletropaulo from 34% to 16%. We entered into a series of transactions to sell a portion of our shares in Eletropaulo as part of the restructuring of Brasiliana. See note 14 to the consolidated financial statements in this prospectus for a further discussion of the sale of Eletropaulo shares and Brasiliana restructuring.

        Minority interest expense, net of tax, increased $129 million to $324 million in 2005 from $195 million in 2004. The increase is primarily due to higher earnings from our subsidiaries in Brazil and Cameroon and the 2004 sale of our interest in Oasis.

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Discontinued operations

        In February 2007, the Company entered into a definitive agreement to sell its shares of EDC, a Latin America distribution business reported in the Latin America Utilities segment, for $739 million net of withholding taxes. In addition, the agreement provided for the payment of a US$120 million dividend in 2007 that was approved and declared by EDC shareholders on March 1, 2007. A wholly-owned subsidiary of the Company was the owner of 82.14% of the outstanding shares of EDC, and therefore, on May 31, 2007, received approximately US$97 million in dividends (representing approximately $99 million in gross dividends offset by fees). The closing of the sale occurred on May 8, 2007, and the actual transfer of the shares along with payment of the purchase price occurred on May 16, 2007. During the first quarter of 2007, the Company recognized an impairment charge of approximately $638 million related to this sale. As a result of the final disposition of EDC in May 2007, the Company recognized an additional impairment charge of approximately $38 million net of income and withholding taxes. The total impairment charge of $676 million represented the net book value of the Company's investment in EDC less the selling price. The impairment expense is included in the loss from disposal of discontinued businesses line item on the condensed consolidated statement of operations for the nine months ended September 30, 2007.

        In May 2007, the Company's wholly-owned subsidiary, Central Valley, reached an agreement to sell 100% of its indirect interest in two biomass fired power plants located in central California (the 50MW Delano facility and the 25MW Mendota facility) for $51 million. These facilities, along with an associated management company (together, the "Central Valley Businesses") were included in the North America Generation segment. The AES Board of Directors approved the sale of the Central Valley Businesses in February 2007. As a result, Central Valley was reported as "held for sale" and the results of its operations and financial position are reflected in the discontinued operations line items in the Company's unaudited consolidated financial statements for the nine months ended September 30, 2007. The closing of the sale occurred on July 16, 2007 and the Company recognized a gain on the sale of approximately $12 million net of income and withholding taxes.

        In May 2006, the Company reached an agreement to sell 100% of its interest in Eden, a Latin America Utilities business located in Argentina. The Buenos Aires Province in Argentina approved the transaction in May 2007. Therefore, Eden, a consolidated subsidiary of AES, was classified as "held for sale" and reflected as such on the unaudited consolidated financial statements. In addition to the results of its operations, Eden has also recognized a $1 million unfavorable adjustment during the nine months ended September 30, 2007, to the originally recorded net loss on the sale as a result of the finalization of the sale transaction.

        In May 2006, the Company reached an agreement to sell AES Indian Queens Power Limited and AES Indian Queens Operations Limited, collectively "IQP", which is part of the Europe & Africa Generation segment. IQP is an Open Cycle Gas Turbine, located in the U.K. In September 2006, the Company completed the sale of IQP. Proceeds from the sale were $28 million in cash and the buyer assumed $30 million of IQP's debt. The results of operations of IQP for the nine months ended September 30, 2006, are reflected in the discontinued operations line items on the condensed consolidated statements of operations.

        The results of operations for EDC, Central Valley and Eden are reflected within discontinued operations for the nine months ended September 30, 2007. These three entities and IQP are reflected within discontinued operations for 2006 and the nine months ended September 30, 2006. Income from operations of discontinued businesses, net of tax, was $71 million and $79 million for the nine months ended September 30, 2007 and 2006, respectively. Income from operations of discontinued businesses, net of tax, was $105 million in 2006.

        In 2006, income from operations of discontinued businesses, net of tax, was $105 million related to the operations of EDC, Central Valley, Eden and IQP.

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        In 2005, income from operations of discontinued businesses, net of tax, was $188 million. Income from operations of EDC, Central Valley, Eden and IQP totaled approximately $157 million for 2005. Additionally, a reversal of approximately $31 million was recorded in the third quarter of 2005 at Eden, related to the release of valuation allowance previously recorded against its net deferred tax assets.

        Income from operations of discontinued businesses, net of tax, was $41 million in 2004. This loss was offset by a gain on disposal of discontinued businesses of $91 million during the year. Businesses sold during 2004 included Whitefield, AES Communications Bolivia, Colombia I, Ede Este, Wolf Hollow, Carbones Internacionales del Cesar S.A. and Granite Ridge. These entities were recorded in discontinued operations in prior years.

Extraordinary item

        As discussed in Note 6 to the unaudited consolidated financial statements, in May 2006, AES purchased an additional 25% interest in Itabo, a power generation business located in the Dominican Republic for approximately $23 million. Prior to May, the Company held a 25% interest in Itabo, through its Gener subsidiary, and had accounted for the investment using the equity method of accounting with a corresponding investment balance reflected in the "Investments in and advances to affiliates" line item on the consolidated balance sheets. As a result of the transaction, the Company consolidates Itabo and, therefore, the investment balance has been reclassified to the appropriate line items on the consolidated balance sheets with a corresponding minority interest liability for the remaining 50% interest not owned by AES. The Company realized an after-tax extraordinary gain of $21 million as a result of the transaction due to an excess of the fair value of the noncurrent assets over the purchase price.

Capital Resources And Liquidity

Overview

        We are a holding company that conducts all of our operations through subsidiaries. We have, to the extent achievable, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. This type of financing is non-recourse to other subsidiaries and affiliates and to us (as the parent company), and is generally secured by the capital stock, physical assets, contracts and cash flow of the related subsidiary or affiliate. At September 30, 2007, we had $4.9 billion of recourse debt and $12.3 billion of non-recourse debt outstanding. For more information on our long-term debt see note 3 to our unaudited consolidated financial statements included in this prospectus.

        In addition to the non-recourse debt, if available, we, as the parent company, provide a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition. These investments have generally taken the form of equity investments or loans, which are subordinated to the project's non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations and/or the proceeds from our issuances of debt, common stock, and other securities as well as proceeds from the sales of assets. Similarly, in certain of our businesses, we may provide financial guarantees or other credit support for the benefit of lenders or counterparties who have entered into contracts for the purchase or sale of electricity with our subsidiaries. In such circumstances, if a subsidiary defaults on its payment or supply obligation, we will be responsible for the subsidiary's obligations up to the amount provided for in the relevant guarantee or other credit support.

        We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. However, depending on market conditions and the unique characteristics of individual businesses, non-recourse debt may not be

64


available or may not be available on economically attractive terms. If we decide not to provide any additional funding or credit support to a subsidiary that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent and we may lose our investment in such subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to restructure the non-recourse debt financing. If such subsidiary is unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in such subsidiary. At September 30, 2007, we had provided outstanding financial and performance related guarantees or other credit support commitments to or for the benefit of our subsidiaries, which were limited by the terms of the agreements, in an aggregate of approximately $652 million (excluding those collateralized by letters of credit and other obligations discussed below).

        As a result of the AES parent company's below-investment-grade rating, counter-parties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, we may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. We may not be able to provide adequate assurances to such counterparties. In addition, to the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At September 30, 2007, we had $354 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations. These letters of credit were provided under our revolver and senior unsecured credit facility. We pay letter of credit fees ranging from 1.63% to 3.70% per annum on the outstanding amounts. In addition, we had less than $1 million in surety bonds outstanding at September 30, 2007. Management believes that cash on hand, along with cash generated through operations, and our financing availability will be sufficient to fund normal operations, capital expenditures, and debt service requirements.

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

Capital Expenditures

        The Company spent $1,728 million on capital expenditures during the first nine months of 2007, and $1.5 billion, $0.8 billion and $0.7 billion in 2006, 2005 and 2004, respectively. We anticipate capital expenditures for the full year 2007 to approximate between $2.3 to $2.5 billion excluding EDC, our former Venezuelan business. Planned capital expenditures include new project construction costs, environmental pollution control construction and expenditures for existing assets to increase their useful lives. Capital expenditures for 2007 are expected to be financed using internally generated cash provided by operations and project level financing and debt or equity financing at the AES parent company level.

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Cash Flows

 
   Nine Months Ended
September 30,
   Favorable/
(Unfavorable)
   Year Ended
December 31,
   Favorable/
(Unfavorable)
  
 
   2007
   2006
   07 vs. 06
   2006
   2005
   2004
   06 vs. 05
   05 vs. 04
  

(in millions)
    
  
Operating   $ 1,848   $ 1,879   (31 ) $ 2,360   $ 2,232   $ 1,497   $ 128   $ 735  
Investing     (1,335 )   (574 ) (761 )   (902 )   (661 )   (743 )   (241 )   82  
Financing     (274 )   (695 ) 421     (1,317 )   (1,339 )   (1,285 )   22     (54 )

        At September 30, 2007, cash and cash equivalents increased by $285 million from December 31, 2006 to $1,664 million. The change in cash was due to $1,848 million of cash provided by operating activities, $1,335 of cash used in investing activities, $274 million of cash used in financing activities and the positive effect of exchange rates on cash of $46 million.

        At December 31, 2006 we increased cash and cash equivalents by $203 million from December 31, 2005 to a total of $1,379 million. The change in cash balances was impacted by $2,360 million of cash provided by operating activities offset by a use of cash for investing and financing of $902 million and $1,317 million, respectively and the positive effect of foreign currency translation of cash balances of $62 million.

        Nine months ended September 30, 2007 versus 2006.    Net cash provided by operating activities decreased by $31 million to $1,848 million in the first nine months of 2007 compared to $1,879 million during the same period in 2006. Excluding the decrease in net cash provided by operating activities from EDC, which was sold in May 2007, net cash provided by operating activities would have increased $162 million. This increase was primarily due to:

        Fiscal Year 2006 versus 2005.    Net cash provided by operating activities increased by $128 million to $2,360 million during 2006 compared to $2,232 million during 2005. This increase was primarily due to:

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        The $781 million increase in "adjustments to net income" in 2006 from 2005 was primarily due to the reversal of non-cash adjustments for:

        The following table includes details of changes in operating assets and liabilities on the face of the Consolidated Statement of Cash Flows:

 
   2006
   2005
   Change
  
 
   (in millions)

  
Decrease in accounts receivable   $ 93   $ —   $ 93  
Increase in inventory     (13 )   (58 )   45  
(Increase) decrease in prepaid expenses and other current assets     (55 )   124     (179 )
Decrease in other assets     151     83     68  
Decrease in accounts payable and accrued liabilities     (382 )   (134 )   (248 )
(Decrease) increase in other liabilities     53     102     (49 )
   
 
 
 
Total   $ (153 ) $ 117   $ (270 )
   
 
 
 

        Accounts receivable decreased in the current year primarily due to lower energy pricing at our New York plant.

        Inventory increased in the current year primarily due to seasonal increases and higher coal pricing at New York and IPL.

        Increase in prepaid expenses and other current assets is primarily due to the cash impact of discontinuing the operations of EDC.

        Other assets decreased in the current year due to a decrease in regulatory assets at Eletropaulo as a result of the recovery of energy related costs and a decrease in a long term receivable due from the Government of Cameroon, SONEL's largest customer. These decreases were offset by an increase in long term customer receivables at Eletropaulo and a prepayment of an insurance premium at Maritza, in Bulgaria.

        Accounts payable and other current liabilities declined in the current year mainly due to the release of the SUL option, a decrease in accrued interest due to debt restructuring at Brasiliana and Eletropaulo and a decrease in swap payments due to lower energy pricing at New York.

        Other liabilities increased in the current year primarily due to the increase in long term deferred revenue at Lal Pir and Pak Gen, both located in Pakistan. These increases were partially offset by a decrease in pension liabilities at Eletropaulo, IPL and Sul.

        Nine months ended September 30, 2007 versus 2006.    Net cash used for investing activities in the first nine months of 2007 totaled $1,335 million compared to $574 million during the same period in 2006. This increase of $761 million was primarily attributable to the following:

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        Capital expenditures totaled $1,728 million during the first nine months of 2007, a $731 million increase over the $997 million balance during the same period in 2006. This was mainly due to increased spending of $232 million for the Maritza East 1 lignite-fired power plant in Bulgaria, $62 million for the Ventanas coal plant and $23 million for the Santa Lidia project, both at Gener in Chile, $48 million at New York in the U.S. related to Somerset and Cayuga facilities, $46 million for the flue gas desulphurization plant at Kilroot in Ireland, $45 million at Panama for the Changuinola project, $32 million related to our facility in Jordan, $20 million at Eletropaulo in Brazil primarily for maintenance projects and $19 million at IPL in the U.S. for environmental projects. In addition there was increased spending related to wind development projects of $130 million at our U.S. businesses. These increases were offset by decreases of $35 million in North America.

        Acquisitions-net of cash acquired totaled $316 million in the first nine months of 2007, a $303 million increase over the $13 million during the same period in 2006. This increase was mainly due to the purchase of two 230 MW petroleum coke-fired power plants at TEG/TEP in Mexico in the first quarter of 2007 for approximately $195 million, the purchase of a 51% interest in a joint venture with 26 MW existing capacity and a 390 MW development pipeline of hydroelectric projects in Turkey for approximately $76 million, and the purchase of Storm Lake and Lake Benton at Mid-West Wind in the U.S. for approximately $60 million.

        Proceeds from the sales of businesses totaled $835 million in the first nine months of 2007 and $817 million during the same period in 2006. The first nine months of 2007 included proceeds from the sale of our businesses EDC in Venezuela for $739 million, Central Valley in the U.S. for $51 million, Eden in Argentina for $17 million as well as proceeds from the sale of approximately 1% of our shares in AES Gener for $25 million. The same period in 2006 included proceeds of $522 million from the sale of Eletropaulo shares held by AES Transgás, $124 million from the sale of approximately 7.6% of our shares in AES Gener and $110 million from the sale of our Kingston business in Canada.

        The purchase of short-term investments, net of sales totaled $148 million in the first nine months of 2007, a $154 million decrease as compared to the same period in 2006. These transactions included a $262 million decrease in purchases, net at Tiete in Brazil as the result of a change in investment strategy in 2006 from investing in cash equivalents to investing in Brazilian government bonds, and a $62 million increase in purchases, net at Gener primarily due to the sale of investments to pay for dividends, debt and interest. This was offset by a $96 million increase in purchases, net at Ekibastuz in Kazakhstan for loan collateral, and an $80 million increase in purchases, net at Uruguaiana in Brazil due to new investments.

        Restricted cash balances increased $105 million in the first nine months of 2007. Restricted cash balances increased $48 million at New York, $42 million at Red Oak in the U.S., $28 million at Mid-West Wind, $26 million at Global Insurance, $21 million at Kilroot, $21 million at Eletropaulo, $15 million at Puerto Rico, $11 million at Ras Laffan in Qatar and $9 million at Panama. These were offset by decreases of $112 million at IPL, $15 million at Hawaii, $12 million at Alicura in Argentina and $11 million at Southland in the U.S.

        Proceeds from the sale of emission allowances totaled $10 million in the first nine months of 2007, a $65 million decrease from the same period in 2006. These sales occurred primarily at our businesses located in the U.S. and Europe in 2006.

        Purchases of emission allowances totaled $3 million in the first nine months of 2007, a $50 million decrease from the same period in 2006. These purchases were primarily at our businesses located in the U.S. in 2006.

        Debt service reserves and other assets decreased $63 million in the first nine months of 2007. This was mainly due to decreases of $72 million at Kilroot, $19 million at Tiete in Brazil, $12 million at Pak

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Gen in Pakistan and $10 million at Lal Pir in Pakistan. These were offset by an increase of $38 million at Eletropaulo.

        Fiscal Year 2006 versus 2005.    Net cash used in 2006 for investing activities totaled $902 million compared to $661 million for 2005, an increase of $241 million. This increase was primarily attributable to the following:

        Capital expenditures increased $634 million to $1,460 million during 2006 compared to 2005 mainly due to increased spending of $245 million for the Maritza East 1 lignite-fired power plant in Bulgaria, $161 million for wind development projects at Buffalo Gap 2 in the U.S., $83 million primarily for pollution control technology projects at IPL in the U.S., $41 million primarily for the Greenidge and Westover clean coal projects at New York in the U.S., $37 million at EDC in Venezuela and $33 million at Sul in Brazil.

        Acquisitions-net of cash acquired totaled $19 million in 2006 and $85 million in 2005, a $66 million reduction over 2005. This included $13 million to acquire an additional 25% of Itabo in the Dominican Republic and approximately $5 million to acquire the remaining shares in Alicura located in Argentina. The $85 million spent in the prior year related to our wind development businesses: the purchase of SeaWest's net assets and pre-construction costs for Buffalo Gap. Both operations are located in the U.S.

        Proceeds from the sale of businesses totaled $898 million in 2006 and $22 million in 2005, an increase of $876 million. The sales included $522 million from the sale by Transgás of Eletropaulo preferred shares and $80 million in a related sale by Brasiliana of its preferred shares in Eletropaulo, $123 million from the sale of approximately 7.6% of our shares in AES Gener, $110 million from the sale of our Kingston business in Canada, $33 million from the sale of unissued shares at EDC and $28 million from the sale of Indian Queens. The proceeds in 2005 included the sale of a minority interest in Barka Holdings, Ltd. for $22 million.

        The purchase of short-term investments, net of sales, increased $502 million during 2006 as compared to the same period in 2005. These transactions included a $255 million increase in net purchases at Tiete in Brazil due to a change in investment strategy from investing in cash equivalents to Brazilian government bonds, a $158 million decrease in the net sale of investments at EDC due to the release of a collateral deposit on local debt, a $70 million increase in net purchases at Eletropaulo in Brazil, funded by the redemption of financial treasury bills and a $30 million increase in net purchases at Gener as the result of additional time deposits acquired.

        Restricted cash balances in 2006 increased $102 million over 2005 balances. This change was comprised of the following increases: $59 million at Ras Laffan in Qatar, $31 million at IPL, $30 million at Kilroot in the United Kingdom, $26 million at Southland in the U.S. and $17 million at Parana in Argentina. These increases were offset by decreases of $44 million at New York, $26 million at Eletropaulo in Brazil and $26 million at Panama.

        Proceeds from the sales of emission allowances totaled $82 million in 2006, a $40 million increase over 2005. Purchases of emission allowances totaled $77 million in 2006, a $58 million increase over 2005. These sales and purchases occurred primarily by businesses located in the U.S. and Europe. Included in the purchases during 2006 was a $45 million commitment to purchase Certified Emission Reduction (CER) credits from AgCert International ("AgCert"). AgCert is an alternative energy, Ireland-based company which uses agricultural sources to produce greenhouse gas emission offsets under the Kyoto protocol.

        Debt service reserves and other assets totaled $46 million in 2006, a $146 million decrease over the balance in 2005. This was mainly due to decreases of $45 million at Tiete, $42 million at EDC, $22 million at Eletropaulo, $21 million at Ebute in Nigeria, $13 million at Panama, $10 million at

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Southland and $8 million at Sonel in Africa. These decreases were offset by an increase at Ironwood for $17 million and at Hawaii for $11 million, both located in the U.S.

        Purchases of long-term available-for-sale securities includes $52 million related to an investment in AgCert in 2006.

        Nine months ended September 30, 2007 versus 2006.    Net cash used in financing activities totaled $274 million in the first nine months of 2007 as compared to $695 million during the same period in 2006. This $421 million decrease was primarily attributable to a decrease in cash used for debt, net of repayments of $495 million, an increase in contributions from minority interests of $253 million and a decrease in payments for deferred financing of $28 million, offset by an increase in distributions to minority interests for $361 million.

        Debt issuances of non-recourse debt during the first nine months of 2007 were $1,169 million compared to $1,437 million during the same period in 2006. This decrease of $268 million was primarily due to a decrease in borrowings at Sul in Brazil of $495 million, at CAESS in El Salvador of $223 million, at Eletropaulo in Brazil of $145 million and at Clesa in El Salvador of $77 million. These decreases were offset by an increase in borrowings at TEG/TEP in Mexico for $227 million, at Sonel in Africa for $150 million, at Maritza in Bulgaria for $141 million, at Ekibastuz in Kazakhstan for $97 million and at IPL in the U.S. for $65 million.

        Debt repayments of non-recourse debt and revolving credit facilities, net during the first nine months of 2007 were $1,217 million compared to $1,980 million during the same period in 2006. The decrease of $763 million was primarily due to a decrease in repayments at Sul of $490 million, net at CAESS of $191 million, at Eletropaulo of $173 million, net at the parent company of $163 million, at EDC in Venezuela of $124 million, at Buffalo Gap in the U.S. of $116 million, at Lal Pir in Pakistan of $66 million, at Clesa of $62 million and at Gener in Chile of $55 million. These decreases were offset by an increase in repayments at TEG/TEP for $238 million, net at IPL for $170 million, at Buffalo Gap 2 in the U.S. for $116 million, at Alicura in Argentina for $68 million, at Kilroot in Ireland for $67 million and at Sonel for $52 million.

        Minority distributions were $571 million during the first nine months of 2007 compared to $210 million during the same period in 2006. This increase of $361 million includes dividends paid to minority shareholders primarily by Eletropaulo for $208 million and by Brasiliana Energia for $115 million and a $26 million return of capital by Barka to its minority partner.

        Minority contributions were $370 million during the first nine months of 2007 compared to $117 million during the same period in 2006. This increase of $253 million was primarily due to contributions received from the tax equity partners of $314 million at Buffalo Gap 2 and $31 million at Mid-West Wind offset by a decrease of $115 million at Buffalo Gap in the U.S.

        Fiscal Year 2006 versus 2005.    Net cash used in financing activities decreased by $22 million to $1,317 million during 2006 compared to $1,339 million during 2005. This change was attributable to a decrease in debt, net of issuances of $102 million an increase in contributions from minority interests of $124 million and an increase due to issuance of common stock of $52 million offset by an increase in distributions to minority interests of $149 million, an increase in payments for deferred financing of $65 million and an increase in payments for financed capital expenditures of $51 million.

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        Debt issuances of recourse debt, non-recourse debt and revolving credit facilities, net during 2006 were $3,169 million compared to $1,768 million during 2005. This increase of $1,401 million was due to an increase in borrowings at Brasiliana in Brazil of $744 million, at Maritza in Bulgaria of $240 million, at Itabo in the Dominican Republic of $177 million, at Buffalo Gap 2 in the U.S. of $116 million and at Lal Pir in Pakistan of $64 million. In addition, there were refinancings at Sul in Brazil for $476 million, at Panama for $287 million and at IPL in the U.S. for $156 million as well as bond issuances at CAESS for $207 million and at CLESA for $77 million, both located in El Salvador. These increases were offset by a decrease in borrowings at Eletropaulo in Brazil of $618 million, at Andres in the Dominican Republic of $160 million, at EDC in Venezuela of $141 million, at Wind in the U.S. of $110 million and at Tiete in Brazil of $80 million. There was also a decrease in refinancing at Gener in Chile for $31 million.

        Debt repayments during 2006 were $4,209 million compared to $2,910 million during 2005. The increase of $1,299 million was primarily due to repayments at Brasiliana for $1,032 million, at Sul for $446 million, at Panama for $281 million, at Tiete for $274 million, at CAESS for $175 million, at IPL for $130 million, at Buffalo Gap for $116 million, at Lal Pir for $57 million and at CLESA for $55 million. This increase was offset by a decrease in repayments at Eletropaulo of $594 million, at EDC of $408 million, at Andres of $112 million, at the parent of $108 million and at Gener of $58 million.

        Minority contributions during 2006 were $125 million compared to $1 million during 2005. This resulted in an increase of $124 million primarily due to Buffalo Gap in the U.S., which received a contribution from their tax equity partners of $117 million. Minority distributions were $335 million compared to $186 million during 2005. This increase of $149 million was primarily due to Tiete, which paid minority dividends of $170 million during 2006 compared to $66 million in 2005.

        Payments for deferred financing costs during 2006 were $86 million compared to $21 million during 2005. The $65 million increase in payments was primarily due to new financing at Maritza and refinancing at Sul.

        Financed capital expenditures increased $51 million during 2006 predominately at Buffalo Gap where we financed these acquisitions by paying for them over a period greater than three months.

Contractual Obligations

        A summary of our contractual obligations, commitments and other liabilities as of December 31, 2006 is presented in the table below (in millions).

Contractual Obligations
   Total
   Less
than 1
year
   1-3
years
   4-5
years
   After 5
years
   Footnote
Reference
Debt Obligations(1)   $ 16,035   $ 1,411   $ 2,639   $ 3,119   $ 8,866   8
Interest Payments on Long-Term Debt(2)     9,608     1,366     2,463     1,958     3,821   n/a
Capital Lease Obligations(3)     10     4     5     1     —   10
Other Long-term Liabilities Reflected on AES's Consolidated Balance Sheet under GAAP(4)     853     83     171     144     455   n/a
Operating Lease Obligations(5)     178     17     30     22     109   10
Sale Leaseback Obligations(6)     1,316     63     126     134     993   10
Electricity Obligations(7)     23,389     1,430     3,204     3,568     15,187   10
Fuel Obligations(8)     10,509     1,020     1,902     1,554     6,033   10
Other(9)     3,374     1,234     1,058     263     819   10
Total   $ 65,272   $ 6,628   $ 11,598   $ 10,763   $ 36,283    

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(1)
Includes non-recourse debt and recourse debt presented on our consolidated financial statements. Non-recourse debt borrowings are not a direct obligation of AES, the parent company, and are primarily collateralized by the capital stock of the relevant subsidiary and in certain cases the physical assets of, and all significant agreements associated with, such subsidiaries. These non-recourse financings include structured project financings, acquisition financing, working capital facilities and all other consolidated debt of the subsidiaries. Recourse debt borrowings are the borrowings of AES, the parent company. Note 8 to the audited consolidated financial statements included in this prospectus provides disclosure of these obligations.

(2)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancing, early redemptions, new debt issuances or certain interest on liabilities other than debt. Variable rate interest obligations are estimated based on rates as of December 31, 2006.

(3)
Several AES subsidiaries lease operating and office equipment and vehicles. These leases have been recorded as capital leases in Property, Plant and Equipment within "Electric Generation and Distribution Assets." Minimum contractual obligations include $2 million of imputed interest.

(4)
Other Long-Term Liabilities reflected on AES's consolidated balance sheet under GAAP include only those amounts that are contractual obligations. These amounts do not include (1) current liabilities on the consolidated balance sheet, (2) any taxes or regulatory liabilities, (3) contingencies, (4) pension and other post retirement employee benefit liabilities (see note 12 to the audited consolidated financial statements included in this prospectus).

(5)
As of December 31, 2006, the Company was obligated under long-term non-cancelable operating leases, primarily for office rental and site leases. These amounts exclude amounts related to the sale/leaseback discussed below in item (6).

(6)
Sale/Leaseback Obligations—In May 1999, a subsidiary of the Company acquired six electric generating stations from New York State Electric and Gas ("NYSEG"). Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. This transaction has been accounted for as a sale/leaseback with operating lease treatment.

(7)
Operating subsidiaries of the Company have entered into contracts for the purchase of electricity from third parties.

(8)
Fuel Obligations—Operating subsidiaries of the Company have entered into various contracts for the purchase of fuel subject to termination only in certain limited circumstances.

(9)
Amounts relate to other contractual obligations where the Company has an agreement to purchase goods or services that is enforceable and legally binding on the Company that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. These amounts exclude planned capital expenditures that are not contractually obligated.

Parent Company Liquidity

        The following discussion of "parent company liquidity" has been included because we believe it is a useful measure of the liquidity available to The AES Corporation, or the parent company, given the non-recourse nature of most of our indebtedness. Parent company liquidity as outlined below is not a measure under generally accepted accounting principles ("GAAP") and should not be construed as an alternative to cash and cash equivalents which are determined in accordance with GAAP, as a measure of liquidity. Cash and cash equivalents are disclosed in the Consolidated Statement of Cash Flows.

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Parent company liquidity may differ from that, of similarly titled measures used by other companies. Our principal sources of liquidity at the parent company level are:

        In December 2006, the parent company exercised its right to increase the revolving credit facility by $100 million to a total of $750 million. As of September 30, 2007, there were no outstanding borrowings against the revolving credit facility. The parent company had $44 million of letters of credit outstanding against the revolving credit facility as of September 30, 2007.

        The parent company entered into a $500 million senior unsecured credit facility agreement effective March 31, 2006. On May 1, 2006, the parent company exercised its option to extend the total amount of the senior unsecured credit facility by an additional $100 million to a total of $600 million. At September 30, 2007, the parent company had $100 million of outstanding borrowings under the senior unsecured credit facility. The parent company had $310 million of letters of credit outstanding against the senior unsecured credit facility as of September 30, 2007. The credit facility is being used to support AES's ongoing share of construction obligations for AES Maritza East 1 and for general corporate purposes.

        On October 15, 2007, the Company issued $2.0 billion aggregate principal amount of the unregistered notes hereby offered for exchange. The Company intends to use the net proceeds from the sale of the unregistered notes primarily to refinance a portion of its recourse debt. However, depending on the timing of the sources and uses of parent-level funds, up to $600 million of the net proceeds may be used to support the Company's near-term investment requirements such as our potential equity investment in Brasiliana, or for general corporate purposes. We have a right of first refusal under the Brasiliana shareholders' agreement to acquire BNDES's interest in Brasiliana, a holding company through which we own three of our Brazilian subsidiaries: Eletropaulo, Tiete and Uruguaiana. BNDES has begun the Brasiliana Sale and, depending upon the ultimate valuation of Brasiliana, we may decide to exercise our right of first refusal. We may also use our internally-generated free cash flow, additional financing transactions and portfolio management transactions, including (but not limited to) asset sales and subsidiary recapitalization transactions to fund our investments and for the refinancing of its recourse debt.

        If we do not exercise our right of first refusal, under the terms of the shareholders agreement, we may be required to sell our Brasiliana shares. In that event, the parent company's liquidity will increase when it receives proceeds from the sale of its shares in Brasiliana.

        On October 16, 2007, we commenced a tender offer for up to $1.24 billion senior notes, including $202 million of the 2008 Notes; $600 million of the 2015 Notes; and the remainder to its 2013 Notes.

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On October 30, 2007 and pursuant to the terms of the tender offer, the Company provided early settlement for the purchase of $193 million principal amount of the 2008 Notes and $598 million principal amount of the 2015 Secured Notes tendered and not withdrawn prior to October 29, 2007 for a total purchase price of $867 million, including tender premiums and accrued interest. The Company will record an expense in the fourth quarter and year ending December 31, 2007 of $45 million of tender consideration and $11 million of write-off of unamortized deferred financing costs on the 2008 and 2015 Secured Notes. There may be additional expense associated with the final settlement date, scheduled for the middle of November 2007. If the Company executes the tender offer on up to an additional $449 million principal amount of the 2013 Notes in the fourth quarter, it would record an additional tender consideration and write-off of deferred financing costs of approximately $35 million.

        The Company defines parent company liquidity as cash available to the parent company plus available borrowings under existing credit facilities. Parent company liquidity is reconciled to its most directly comparable GAAP financial measure, "cash and cash equivalents" at September 30, 2007 and December 31, 2006 as follows:

 
    
   December 31,
Parent Company Liquidity
   September 30,
2007
  2006
   2005
   2004
 
   (in millions)
Cash and cash equivalents   $ 1,664   $ 1,379   $ 1,176   $ 931
Less: Cash and cash equivalents at subsidiaries     1,045     1,122     908     640
   
 
 
 
Parent and qualified holding companies cash and cash equivalents     619     257     268     291
Borrowing available under revolving credit facility     706     662     356     352
Borrowing available under senior unsecured credit facility     190     227     —     —
   
 
 
 
Total parent liquidity   $ 1,515   $ 1,146   $ 624   $ 643
   
 
 
 

        Our parent recourse debt at year-end was approximately $4.8 billion, $4.9 billion, and $5.2 billion in 2006, 2005 and 2004, respectively. Our contingent contractual obligations were $995 million, $802 million, and $559 million at the end of 2006, 2005, and 2004, respectively.

        The following table summarizes our contingent contractual obligations at the parent company level as of September 30, 2007:

Contingent Contractual obligations
   Amount
   Number of
Agreements
   Exposure Range
for Each
Agreement
 
   (in millions)

    
    
Guarantees   $ 652   33   <$1 - $168
Letters of credit under the revolving credit facility     44   13   <$1 - $28
Letters of credit under the senior unsecured credit facility     310   15   <$1 - $219
Surety bonds     1   1   <$1
   
 
   
Total   $ 1,007   62    
   
 
   

        We have a varied portfolio of performance related contingent contractual obligations. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control,

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construction cost overruns, subsidiary default, political risk, buyer and tax indemnities, equity subscription, spot market power prices, supplier support and liquidated damages under power sales agreements for projects in development, under construction and operation. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations during 2007 or beyond, many of the events which would give rise to such an obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.

        While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets, the operating and financial performance of our subsidiaries, exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries' ability to declare and pay cash dividends to us (at the parent company level) is subject to certain limitations contained in project loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that our actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the parent company level with our revolving credit facility and senior unsecured credit facility. If, due to new corporate opportunities or otherwise, our capital requirements exceed amounts available from cash on hand or borrowings under our credit facilities, we may need to access the capital markets to raise additional debt or equity financing. However, the timing of our ability to access the capital markets may be affected as a result of prior period restatements of our financial statements and the material weaknesses in our internal controls over financial reporting as described below.

        Various debt instruments at the parent company level contain certain restrictive covenants. The covenants provide for, among other items:

Non-Recourse Debt Financing

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

        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 the accompanying condensed

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consolidated balance sheet related to such defaults was $514 million at September 30, 2007, all of which is non-recourse debt.

        None of the subsidiaries that are currently in default are owned by subsidiaries that currently meet the applicable definition of materiality in the parent company's corporate debt agreements in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact 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 trigger an event of default and possible acceleration of the indebtedness under the parent company's outstanding debt securities.

Off-Balance Sheet Arrangements

        In May 1999, one of our subsidiaries acquired six electric generating plants from New York State Electric and Gas. Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. We have accounted for this transaction as a sale/leaseback transaction with operating lease treatment. Accordingly, we have not recorded these assets on our books and we expense periodic lease payments, which amounted to $54 million in 2005, as incurred. The lease obligations bear an imputed interest rate of approximately 9% which approximates fair market value. We are not subject to any additional liabilities or contingencies if the arrangement terminates, and we believe that the dissolution of the off-balance sheet arrangement would have minimal effects on our operating cash flows. The terms of the lease include restrictive covenants such as the maintenance of certain coverage ratios. Historically, the plants have satisfied the restrictive covenants of the lease, and there are no known trends or uncertainties that would indicate that the lease will be terminated early. See note 10 to the audited consolidated financial statements included in this prospectus for a more complete discussion of this transaction.

        IPL, a subsidiary of the Company, formed IPL Funding Corporation ("IPL Funding") in 1996 as a special-purpose entity to purchase retail receivables originated by IPL pursuant to a receivables sale agreement entered into with IPL. At the same time, IPL Funding entered into a purchase facility (the "Purchase Facility") with unrelated parties (the "Purchasers") pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, up to $50 million, of interests in the pool of receivables purchased from IPL. As collections reduce accounts receivable included in the pool, IPL Funding sells ownership interests in additional receivables acquired from IPL to return the ownership interests sold up to a maximum of $50 million, as permitted by the Purchase Facility. During 2006, the Purchase Facility was extended through May 29, 2007. IPL Funding is included in the consolidated financial statements of IPL. Accounts receivable on the accompanying consolidated balance sheets of IPALCO are stated net of the $50 million sold.

        IPL retains servicing responsibilities for its role as a collection agent on the amounts due on the sold receivables. However, the Purchasers assume the risk of collection on the purchased receivables without recourse to IPL in the event of a loss. While no direct recourse to IPL exists, it risks loss in the event collections are not sufficient to allow for full recovery of its retained interests. No servicing asset or liability is recorded since the servicing fee paid to IPL approximates a market rate.

        The carrying values of the retained interest is determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value. The key assumptions in estimating fair value are credit losses, the selection of discount rates, and expected receivables turnover rate. As a result of short accounts receivable turnover period and historically low credit losses, the impact of these assumptions has not been significant to the fair value. The hypothetical effect on the fair value of the retained interests assuming both a 10% and a 20%

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unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history.

        The losses recognized on the sales of receivables were $3 million, $2 million and $1 million for 2006, 2005 and 2004, respectively. These losses are included in Other operating expense on the consolidated statements of income. The amount of the losses recognized depends on the previous carrying amount of the financial assets involved in the transfer, allocated between the assets sold and the interests that continue to be held by the transferor based on their relative fair value at the date of transfer, and the proceeds received.

        There are no proceeds from new securitizations for each of 2006, 2005 and 2004. Servicing fees of $0.6 million were paid for each of 2006, 2005 and 2004.

        IPL and IPL Funding provide certain indemnities to the Purchasers, including indemnification in the event that there is a breach of representations and warranties made with respect to the purchased receivables. IPL Funding and IPL each have agreed to indemnify the Purchasers on an after-tax basis for any and all damages, losses, claims, liabilities, penalties, taxes, costs and expenses at any time imposed on or incurred by the indemnified parties arising out of or otherwise relating to the purchase facility, subject to certain limitations as defined in the Purchase Facility.

        Under the Purchase Facility, if IPL fails to maintain certain financial covenants regarding interest coverage and debt-to-capital ratios, it would constitute a "termination event." As of December 31, 2006, IPL was in compliance with such covenants.

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

Quantitative and Qualitative Disclosure About Market Risk

Overview Regarding Market Risks

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

Interest Rate Risks

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

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Foreign Exchange Rate Risk

        We are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in U.S. dollars or currencies other than their own functional currencies. Primarily, we are exposed to changes in the U.S. dollar/Brazilian Real exchange rate, the U.S dollar/Euro exchange rate and the U.S. dollar/ British Pound exchange rate. Whenever possible, these subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.

Commodity Price Risk

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

Value at Risk

        One approach we use to assess our risk and our subsidiaries' risk is value at risk ("VaR"). VaR measures the potential loss in a portfolio's value due to market volatility, over a specified time horizon, stated with a specific degree of probability. The quantification of market risk using VaR provides a consistent measure of risk across diverse markets and instruments. We adopted the VaR approach because we feel that statistical models of risk measurement, such as VaR, provide an objective, independent assessment of a component of our risk exposure. Our use of VaR requires a number of key assumptions, including the selection of a confidence level for expected losses, the holding period for liquidation and the treatment of risks outside the VaR methodology, including liquidity risk and event risk. VaR, therefore, is not necessarily indicative of actual results that may occur. Additionally, VaR represents changes in fair value and not the economic exposure to AES and its affiliates.

        Because of the inherent limitations of VaR, including those specific to Analytic VaR, in particular the assumption that values or returns are normally distributed, we rely on VaR as only one component in our risk assessment process. In addition to using VaR measures, we perform stress and scenario analyses to estimate the economic impact of market changes to our portfolio of businesses. We use these results to complement the VaR methodology.

        In addition, the relevance of the VaR described herein as a measure of economic risk is limited and needs to be considered in light of the underlying business structure. The interest rate component of VaR is due to changes in the fair value of our fixed rate debt instruments and interest rate swaps. These instruments themselves would expose a holder to market risk; however, utilizing these fixed rate debt instruments as part of a fixed price contract generation business mitigates the overall exposure to interest rates. Similarly, our foreign exchange rate sensitive instruments are often part of businesses which have revenues denominated in the same currency, thus offsetting the exposure.

        We have performed a company-wide VaR analysis of all of our material financial assets, liabilities and derivative instruments. Embedded derivatives are not appropriately measured here and are

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excluded since VaR is not representative of the overall contract valuation. The VaR calculation incorporates numerous variables that could impact the fair value of our instruments, including interest rates, foreign exchange rates and commodity prices, as well as correlation within and across these variables. We express Analytic VaR herein as a dollar amount of the potential loss in the fair value of our portfolio based on a 95% confidence level and a one-day holding period. Our commodity analysis is an Analytic VaR utilizing a variance-covariance analysis within the commodity transaction management system.

        The following table sets forth average daily VaR as of December 31, for the periods indicated.

Average Daily VAR
   Nine Months
Ended
September 30,
2007
   2006
   2005
   2004
 
   (in millions)
Foreign Exchange   $ 61   $ 36   $ 34   $ 27
Interest Rate   $ 117   $ 76   $ 114   $ 110
Commodity   $ 12   $ 24   $ 19   $ 9

        The VaR as of September 30, 2007 for foreign exchange, interest rate and commodities was $61 million, $117 million and $12 million, respectively. The increase in foreign exchange and interest rate VaR relative to the second quarter of 2007 is primarily due to higher market volatilities.

        During the year ended December 31, 2006, our average daily VaR for foreign exchange rate-sensitive instruments was $36 million. The daily VaR for foreign exchange rate-sensitive instruments was highest at the end of the second quarter, and equaled $45 million. The daily VaR for foreign exchange rate-sensitive instruments was lowest at the end of the fourth quarter, and equaled $20 million. These amounts include foreign currency denominated debt and hedge instruments. The foreign exchange VaR increased in the third quarter due to short-term hedge instruments. The proportion of non-USD denominated debt has increased in the AES portfolio. The diverse portfolio and low market volatilities contributed to a decrease in the foreign exchange VaR in the latter part of the year.

        During the year ended December 31, 2006, our average daily VaR for interest rate-sensitive instruments was $76 million. The daily VaR for interest rate-sensitive instruments was highest at the end of the first quarter, and equaled $111 million. The daily VaR for interest rate-sensitive instruments was lowest at the end of the third quarter and equaled $60 million. These amounts include the financial instruments that serve as hedges and the underlying hedged items. AES had decreased its portfolio of USD-denominated debt which in part led to the decrease in interest rate VaR.

        During the year ended December 31, 2006, our average daily VaR for commodity price-sensitive instruments was $24 million. The daily VaR for commodity price-sensitive instruments was highest at the end of the third quarter, and equaled $28 million. The daily VaR for commodity price-sensitive instruments was lowest at the end of the fourth quarter, and equaled $20 million. These amounts include the financial instruments that serve as hedges and do not include the underlying physical assets or contracts that are not permitted to be settled in cash.

        Trending daily VaR can provide insight into market volatility or consistency of a company's financial strategy. AES has increased the percentage of its portfolio of Brazilian Real and Euro denominated floating debt and reduced the percentage of US dollar-denominated fixed rate debt. This has in part led to the decrease in Interest Rate VaR from $110 million in 2004 to $76 million in 2006. The AES commodity VaR is reported for financially settled derivative products at its Eastern Energy business in New York State. From 2004 to 2006 there has been an increase in term and magnitude of hedging activity which has led to the increase in the daily VaR from $9 million in 2004 to $24 million in 2006.

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Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

        The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.

        The Company carried out the evaluation required by paragraph (b) of the Exchange Act Rules 13a-15 and 15d-15, under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our "disclosure controls and procedures" (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of September 30, 2007 and December 31, 2006, our disclosure controls and procedures were not effective to provide reasonable assurance that financial information we are required to disclose in our reports under the Securities and Exchange Act of 1934 was recorded, processed, summarized and reported accurately as evidenced by the material weaknesses described below.

        Management reported that material weaknesses existed in our internal controls as of December 31, 2006 and September 30, 2007 and is in the process of taking remedial steps to correct these weaknesses. To address the control weaknesses described below, the Company performed additional analysis and other post-closing procedures in order to prepare the consolidated financial statements in accordance with generally accepted accounting principles in the United States of America. Accordingly, management believes that the consolidated financial statements included in this prospectus fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented.

        Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. 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.

Changes in Internal Controls

        In the course of our evaluation of disclosure controls and procedures, management considered certain internal control areas in which we have made and are continuing to make changes to improve and enhance controls. There are no new reportable material weaknesses the quarter ended September 30, 2007. As discussed below, the Company continues to implement processes and controls to remediate its existing material weaknesses. Changes have been, and will continue to be made to our internal control over financial reporting in adapting these remediation processes.

        The CEO and CFO concluded that there were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurred during the quarter ended September 30, 2007 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

        The Company determined that material weaknesses in internal control over financial reporting existed as of December 31, 2006. These material weaknesses continued to exist as of September 30, 2007. The following is a discussion of the material weaknesses, any of which could result in a future misstatement of certain account balances that could result in a material misstatement to the annual or interim financial statements.

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Treatment of Intercompany Loans Denominated in Other Than the Functional Currency

        The Company previously reported it lacked effective controls to ensure the proper application of SFAS No. 52, Foreign Currency Translation, related to the treatment of foreign currency gains or losses on certain long term intercompany loan balances denominated in other than the entity's functional currency and lacked appropriate documentation for the determination of certain of its holding companies' functional currencies. The Company also previously reported it was incorrectly translating certain loan balances due to the fact that it lacked an effective assessment process to identify and document whether or not a loan was to be repaid in the foreseeable future at inception and to update this determination on a periodic basis. Also, the Company previously reported it had incorrectly determined the functional currency for one of its holding companies which impacted the proper translation of its intercompany loan balances.

        The Company had designed and implemented new controls to address this material weakness, but in testing these controls during and subsequent to the fourth quarter of 2006, the Company identified deficiencies in the execution and operating effectiveness of certain of the newly implemented controls.

Aggregation of Control Deficiencies at our Cameroonian Subsidiary

        The Company previously reported that AES SONEL, a 56% owned subsidiary of the Company located in Cameroon, lacked adequate and effective controls related to transactional accounting and financial reporting. These deficiencies included a lack of timely and sufficient financial statement account reconciliation and analysis, a lack of sufficient support resources within the accounting and finance group, inadequate preparation and review of purchase accounting adjustments incorrectly recorded in 2002, and errors in the translation of local currency financial statements to the U.S. Dollar.

Contract Accounting

        The material weakness previously identified as "Derivative Accounting" has been restated as "Contract Accounting". This restatement of this material weakness resulted from the fact that during remediation of the "Derivative Accounting" material weakness, the Company identified certain lease-related errors related to the accounting for contract modifications that occurred after the July 1, 2003 implementation of EITF 01-08, Determining Whether an Arrangement Contains a Lease (EITF 01-8). Accordingly, the Company believes that the restated material weakness more accurately reflects the ineffective operation of controls designed to ensure an adequate analysis and documentation of certain contracts, at inception and upon modification, to allow them to be adequately accounted for in accordance with US GAAP. The errors that have been identified during the remediation have been recorded as part of our restatement adjustments more fully described in note 1 to our audited consolidated financial statements under the caption "General and Summary of Significant Accounting Policies—Restatement" and note 1 to our unaudited consolidated financial statements under the caption "Financial Statement Presentation—Restatement of Consolidated Financial Statements" included in this prospectus.

Lack of Detailed Accounting Records for Certain Holding Companies

        While testing newly implemented controls for the Income Tax and Treatment of Intercompany Loan material weaknesses during and subsequent to the fourth quarter of 2006, the Company identified a risk related to a lack of maintenance of separate legal entity books and records for certain holding companies. While the Company believes it has manual processes in place to capture and segregate all material transactions related to these entities, there remains a risk that a material misstatement could occur related to an error in the translation of intercompany loan balances denominated in other than the entity's functional currency for these holding companies or in the Company's income tax provision

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calculations. In addition, there is a risk that as the Company continues to add holding companies, without establishing separate legal entity books and records, certain transactions may not be captured by the current manual processes.

Lack of Adequate Controls and Procedures Related to Granting and Reporting of Share-Based Compensation

        The Company determined that it lacked effective controls and procedures related to its accounting for share-based compensation resulting from weaknesses in its granting practices. These weaknesses include a lack of adequate understanding, communication and recording of the compensation expense based on the determination of appropriate measurement dates for accounting purposes. The errors identified from this review were adjusted in conjunction with the May 23, 2007 restatement of the financial statements for the years ended December 31, 2004 and 2005.

Material Weaknesses Remediation Plans as of September 30, 2007

        Management and our Board of Directors are committed to the remediation of these material weaknesses as well as the continued improvement of the Company's overall system of internal control over financial reporting. Management is implementing remediation plans for the weaknesses described below and has taken efforts to strengthen the existing finance organization and systems across the Company.

Treatment of Intercompany Loans Denominated in Other Than the Functional Currency

        As of December 31, 2005, the Company confirmed the correct evaluation and documentation of certain material intercompany loans with the parent denominated in currencies other than the entity's functional currency to ensure proper application of SFAS 52—"Foreign Currency Translation" and re-evaluated and documented the functional currencies of certain U.S. and non U.S. holding companies to ensure that proper SFAS 52 translations were being performed. During 2006, the Company implemented additional control procedures designed to ensure the appropriate documentation and evaluation of the determination of an entity's functional currency on a periodic basis, particularly as it relates to holding companies that might have material intercompany transactions. As of December 31, 2006, the Company had implemented new controls and procedures. The completed steps of the remediation plan included the following:

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        The Company continues to implement the remediation plans of the previously reported material weakness and it will continue to assess the operating effectiveness of these controls as well as identify areas for improvement to the current execution of certain controls prior to concluding on full remediation. In order to complete remediation of this material weakness, the Company has continued to improve policies, procedures and checklist to track the information, liquidation and changes to the Company's legal entities and intercompany loans and additional training has been provided to ensure such transactions are properly reviewed and documented. Subsequent testing of operating effectiveness testing is being performed for the newly implemented controls prior to concluding on remediation.

Aggregation of Control Deficiencies at our Cameroonian Subsidiary

        The Company performs monthly detailed analytical reviews of SONEL's financial statements to obtain assurance that reported results are not misstated. As part of its 2006 remediation plan, SONEL reported implementation of certain key controls related to the analytical review during the third and fourth quarters of 2006. In addition, the business unit performed limited self testing of the remediation work performed to date. Additional and more comprehensive testing of all key controls implemented as part of its 2007 remediation efforts is in process. The Company has executed or is in the process of executing the following steps in its remediation plan:

Contract Accounting

        The material weakness previously disclosed as a "Derivative Accounting" material weakness was restated to a "Contract Accounting" material weakness in the Company's audited consolidated financial statements. Although the material weakness was restated, the remediation plan disclosed prior to the restatement remained in place with the addition of the steps identified below. The Company believes it has implemented appropriate controls to ensure remediation of the previously identified material weakness, and will continue to assess the operating effectiveness of these controls as well as identify areas for improvement to the execution of current controls, before concluding on full remediation. During the third quarter of 2007 the Company made progress toward the completion of the remediation steps added after the August 2007 restatement. Such progress included the implementation

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of a new contract completeness certification process and the identification of certain contracts that will be subject to further US GAAP review. The Company also deployed additional online contract and derivative accounting training modules. As previously disclosed, the completed steps related to the remediation plan include the following:

        Additional steps added to the remediation plan as a result of the restated material weakness and which have not been completed:

Lack of Detailed Accounting Records for Certain Holding Companies

        While the Company believes it has manual processes in place to capture all material transactions there remains a risk that due to the lack of detailed records for these holding companies, transactions may not be timely captured or evaluated at the appropriate level of detail during the translation of intercompany loan balances denominated in other than the entity's functional currency for these holding companies or the computation of the tax provision. The completed steps related to the remediation plan include the following:

        The Company continues to execute on additional steps to the remediation plan. The following remediation steps are still in process:

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        The Company continues to implement the remediation plans of this material weakness and it will assess the operating effectiveness of these controls as well as identify areas for improvement to the current execution of certain controls prior to concluding on full remediation. In order to complete remediation of this material weakness, the Company will continue to improve policies and procedures to identify new legal entities. Subsequent testing of operating effectiveness testing will be performed for the newly implemented controls prior to concluding on remediation. The Company does not expect that this material weakness will be remediated by the end of 2007.

Lack of Adequate Controls and Procedures Related to Granting and Reporting of Share-Based Compensation

        The Company retained an outside consulting firm to assist with the collection and processing of data relating to the Company's share-based compensation grants and electronic discovery for the periods 1997-2007. The outside consulting firm also provided a team of forensic accountants to assist the Company with its: (i) evaluation of relevant SEC and FASB guidance relating to share-based compensation; (ii) implementation of procedures for review of electronic data, including emails; and (iii) analysis of the information used to determine measurement dates, strike prices and valuations required to reach the resulting accounting adjustments.

        The Company instituted a moratorium on grants of share-based compensation. On October 12, 2007, the Board lifted the moratorium on grants and/or modifications of shared-based compensation.

        The Company's remediation plan includes the following:

        As of September 30, 2007, the Company has documented and implemented its remediation plan for share based compensation. The new procedures and controls are being tested during the fourth quarter of 2007.

Management's Report on Internal Control over Financial Reporting as of December 31, 2006

        Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company's internal control over financial reporting is a process designed to provide reasonable assurance regarding

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the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America and includes those policies and procedures that:

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

        Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2006. In making this assessment, management used the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations (COSO).

        A material weakness is a significant deficiency (within the meaning of PCAOB Auditing Standard No. 2), or combination of significant deficiencies, that result in there being a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

        Management determined that the following material weaknesses in internal control over financial reporting that existed as of December 31, 2005 and were reported in the Company's Form 10-K/A filed on April 4, 2006 also existed as of December 31, 2006.

        Treatment of Intercompany Loans Denominated in Other Than the Functional Currency.    The Company previously reported it lacked effective controls to ensure the proper application of SFAS No. 52, Foreign Currency Translation, related to the treatment of foreign currency gains or losses on certain long term intercompany loan balances denominated in other than the entity's functional currency and lacked appropriate documentation for the determination of certain of its holding companies' functional currencies. The Company also previously reported it was incorrectly translating certain loan balances due to the fact that it lacked an effective assessment process to identify and document whether or not a loan was to be repaid in the foreseeable future at inception and to update this determination on a periodic basis. Also, the Company previously reported it had incorrectly determined the functional currency for one of its holding companies which impacted the proper translation of its intercompany loan balances.

        The Company had designed and implemented new controls to address this material weakness, but in testing these controls during and subsequent to the fourth quarter of 2006, the Company identified deficiencies in the execution and operating effectiveness of certain of the newly implemented controls. Therefore, the Company determined that the lack of effective controls could result in a more than

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remote likelihood of material misstatement and thus continues to represent a material weakness as of December 31, 2006.

        Aggregation of Control Deficiencies at our Cameroonian Subsidiary.    The Company previously reported that AES SONEL, a 56% owned subsidiary of the Company located in Cameroon, lacked adequate and effective controls related to transactional accounting and financial reporting. These deficiencies included a lack of timely and sufficient financial statement account reconciliation and analysis, a lack of sufficient support resources within the accounting and finance group, inadequate preparation and review of purchase accounting adjustments incorrectly recorded in 2002, and errors in the translation of local currency financial statements to the U.S. Dollar. As a result of the aggregation of control deficiencies, the Company determined that the lack of effectively designed and operating controls at SONEL could result in a more than remote likelihood of material misstatement and thus continues to represent a material weakness as of December 31, 2006.

        Contract Accounting.    The Company previously reported it lacked effective controls related to accounting for certain derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133). In the May 2007 restatement, the Company reported adjustments for several derivative-related errors related to the accounting for embedded derivatives in contracts that were executed prior to 2006. The Company also previously reported it lacked an effective control to ensure that an adequate hedge valuation was performed and lacked effective controls to ensure preparation of adequate documentation of the on-going assessment of hedge effectiveness, in accordance with SFAS 133, for certain interest rate and foreign currency hedge contracts entered into prior to 2005. During the course of remediating this material weakness, the Company developed a remediation plan which includes, among other controls, a broad review of contracts by the Company's accounting department so that the Company can identify and properly account for derivatives and hedging activities. After the May 2007 Restatement and as part of the Company's review of contracts within the remediation effort for this material weakness, the Company identified certain lease-related errors related to the accounting for contract modifications that occurred after the July 1, 2003 implementation of EITF 01-08, Determining Whether an Arrangement Contains a Lease (EITF 01-8). The contract modifications had not been evaluated for proper lease treatment. While leases are not derivative instruments, a contract must be evaluated as a lease and may be subject to the requirements of SFAS No. 133. These types of interconnections between accounting principles generally accepted in the United States (US GAAP) are a factor which played a significant role in the Company's decision to broaden the remediation of the "Derivative Accounting" material weakness into one that would address the adequate accounting for contracts under US GAAP. The completeness of the contract evaluation process is essential to establishing proper contract accounting in conformity with US GAAP. Accordingly, the Company determined that the restatement of the "Derivative Accounting" material weakness to "Contract Accounting" more accurately reflects the ineffective operation of controls designed to ensure an adequate analysis and documentation of certain contracts, at inception and upon modification, to allow them to be adequately accounted for in accordance with US GAAP. The errors that have been identified during the remediation have been corrected in the Company's restated audited consolidated financial statements included in this prospectus. As a result of these errors, and the lack of sufficient time to test operating effectiveness of newly implemented controls, the Company determined that the lack of effective controls could result in a more than remote likelihood of material misstatement and thus continued to represent a material weakness as of December 31, 2006.

        Management determined that the following material weaknesses existed as of December 31, 2005 and December 31, 2006, but were not previously identified or reported.

        Contract Accounting.    Although this material weakness was previously disclosed as a "Derivative Accounting" material weakness, as noted above, the "Derivative Accounting" material weakness has been restated as of December 31, 2006 as "Contract Accounting".

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        Lack of Detailed Accounting Records for Certain Holding Companies.    While testing newly implemented controls for the Income Tax and Treatment of Intercompany Loan material weaknesses during and subsequent to the fourth quarter of 2006, the Company identified a risk related to a lack of maintenance of separate legal entity books and records for certain holding companies. While the Company believes it has manual processes in place to capture and segregate all material transactions related to these entities, there remains a risk that a material misstatement could occur related to an error in the translation of intercompany loan balances denominated in other than the entity's functional currency for these holding companies or in the Company's income tax provision calculations. In addition, there is a risk that as the Company continues to add holding companies, without establishing separate legal entity books and records, certain transactions may not be captured by the current manual processes. As a result, the Company has determined that the failure to establish controls to maintain separate legal entity books and records for certain holding companies could result in a more than remote likelihood of material misstatement and represents a material weakness as of December 31, 2006.

        Lack of Adequate Controls and Procedures Related to Granting and Reporting of Share-Based Compensation.    The Company recently completed its review of share-based compensation and determined that it lacked effective controls and procedures related to its accounting for share-based compensation resulting from weaknesses in its granting practices. These weaknesses include an adequate understanding, communication and recording of the compensation expense based on the determination of appropriate measurement dates for accounting purposes. The errors identified from this review were adjusted in conjunction with the May 23, 2007 restatement of the financial statements for the years ended December 31, 2004 and 2005. As a result, the Company has determined that the lack of adequate controls and procedures related to share-based compensation could result in a more than remote likelihood of a material misstatement and represents a material weakness as of December 31, 2006.

        Lack of Adequate Procedures to Assess Whether an Investment in a Variable Interest Entity Should Be Consolidated.    During the course of year end 2006 closing procedures and during review of certain derivative contracts, the Company became aware of additional facts in the form of an additional contract, not originally considered during the implementation of FIN 46R, "Consolidation of Variable Interest Entities", that would have impacted the assessment as to which enterprise is the primary beneficiary of a variable interest entity in Cartagena, Spain, of which the Company is the majority investor. Based on this additional information, the Company has determined it is not the primary beneficiary and should therefore not have consolidated the business, rather the Company's interest in this variable interest entity should have been accounted for under the equity method as of the adoption of FIN 46R as of January 1, 2004 forward. The error was adjusted in conjunction with the May 23, 2007 restatement of the financial statements for the years ended December 31, 2004 and 2005. As a result of this error and the resulting impacts to the consolidated balance sheet, the Company has determined that the lack of adequate controls over procedures to ensure that all relevant contractual information has been identified and considered in the determination as to whether a variable interest entity should be consolidated in accordance with FIN 46R could result in a more than remote likelihood of a material misstatement and represents a material weakness as of December 31, 2006.

        As evidenced by the material weaknesses described above, management has concluded that, as of December 31, 2006, the Company did not maintain effective internal control over financial reporting.

        The Company's independent auditor has issued an attestation report on management's assessment of the Company's internal control over financial reporting as set forth on page F-2.

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BUSINESS

Overview

        AES is one of the world's largest global power companies, providing essential electricity services in 28 countries on five continents.

Our Businesses

        We operate two main types of businesses. The first is our distribution and transmission business, which we refer to as Utilities, in which we operate electric utilities and sell power to customers in the retail (including residential), commercial, industrial and governmental sectors. These customers are typically end users of electricity. The second is our Generation business, where we sell power to wholesale customers such as utilities or other intermediaries. The revenues and earnings growth of both our Utilities and Generation businesses vary with changes in electricity demand.

        Our Utilities business consists primarily of 15 distribution companies owned or operated under management agreements in eight countries with over 11 million end-user customers. All of these companies operate in a defined service area. This segment is composed of:

•
integrated utilities located in:

•
The United States—IPL,

•
Cameroon—AES SONEL.

•
distribution companies located in:

•
Brazil—AES Eletropaulo and AES Sul,

•
Argentina—EDELAP and EDES,

•
Dominican Republic—EDE Este,

•
El Salvador—CAESS, AES CLESA, DEUSEM and EEO,

•
Kazakhstan—Eastern Kazakhstan REC and Ust Kamenogorsk Heat Nets, and

•
Ukraine—Kievoblenergo and Rivneenergo.

        Performance drivers for these businesses include, among other things, 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.

        Utilities face relatively little direct competition due to significant barriers to entry which are present in these markets. In this segment, we primarily face competition in our efforts to acquire businesses. 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 have accumulated more significant portfolios. Relevant competitive factors for Utilities include financial resources, governmental assistance, regulatory restrictions and access to non-recourse financing. In certain locations our utilities 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. We can provide no assurance that deregulation will not adversely affect the future operations, cash flows and financial condition of our Utilities business. The results of operations of our Utilities business are sensitive to changes in economic growth and regulation, abnormal weather conditions in the area in which they operate, as well as the success of the operational changes that have been implemented (especially in emerging markets).

89


        In our Generation business, we generate and sell electricity primarily to wholesale customers. Performance drivers for our Generation business include, among other things, plant reliability, fuel costs and fixed-cost management. Growth in this business is largely tied to securing new power purchase agreements, expanding capacity in our existing facilities and building new power plants. Our Generation business includes our interests in 97 power generation facilities owned or operated under management agreements totaling 37 gigawatts of capacity installed in 22 countries.

        Approximately 68% of the revenues from our Generation business are from plants that operate under power purchase agreements of five years or longer for 75% or more of the output capacity. These long-term contracts reduce the risk associated with volatility in the market price for electricity. We also reduce our exposure to fuel supply risks by entering into long-term fuel supply contracts or through fuel tolling contracts where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. As a result of these contractual agreements, these facilities have relatively predictable cash flows and earnings. These facilities face most of their competition prior to the execution of a power sales agreement, often during the development phase of a project or upon expiration of an existing agreement. Our competitors for these contracts include other independent power producers and equipment manufacturers, as well as various utilities and their affiliates. During the operational phase, we traditionally have faced limited competition due to the long-term nature of the generation contracts. However, since competitive power markets have been introduced and new market participants have been added, we have and will continue to encounter increased competition in attracting new customers and maintaining our current customers as our existing contracts expire.

        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 facilities 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. These facilities compete with numerous other independent power producers, energy marketers and traders, energy merchants, transmission and distribution providers and retail energy suppliers. Competitive factors for these facilities include price, reliability, operational cost and third party credit requirements.

Recent Initiatives

        We are always seeking opportunities to grow our businesses and increase the value of our stock, both within our existing Generation and Utilities businesses and in new lines of businesses. When exploring new businesses, we seek opportunities that leverage the skills and experience we have developed in our core business. These core competencies include: financing, constructing and developing large, capital-intensive projects; negotiating and closing complex merger, acquisition, disposition and investment transactions; operating businesses that are heavily-regulated; and conducting business and establishing operations around the world, including in countries where relationships and insight into local rules, regulations, politics and business practices provide us with a competitive advantage.

        In our existing businesses we are currently seeing increased demand for power plants sited adjacent to coal resources in markets such as Vietnam, India and Indonesia. Some of the important drivers of performance for us in developing our alternative energy businesses include continued government support through regulation and incentives, continued progress towards liquid and transparent markets, particularly in the area of greenhouse gas emission credit trading, and the successful identification, execution and commercialization of new market opportunities in these nascent markets.

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        We are also developing an alternative energy business including wind generation, the supply of LNG, greenhouse gas emission reduction projects and new energy technologies. In Qatar and Oman we own and operate water desalination plants, and in the Dominican Republic we own and operate a LNG re-gasification terminal, which are ancillary to our existing power businesses.

Our Organization

        Our businesses include Utilities and Generation within four defined geographic regions: (1) North America, (2) Latin America, (3) Europe, CIS and Africa, which we refer to as "Europe & Africa" and (4) Asia and the Middle East, which we refer to as "Asia". Three regions, North America, Latin America and Europe & Africa, are engaged in both our Generation and Utility businesses. Our Asia region only has Generation businesses. 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 development and operational costs related to our Alternative Energy business which is currently not material to our presentation of operating segments. Under AES's Alternative Energy group, AES operates 1,015 MW of wind generation in the United States.

        Our goal is to continue building on our traditional lines of business, while expanding into other essential energy-related areas. We believe that this is a natural expansion for us. 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 also will build on our existing capabilities in areas beyond power including greenhouse gas emissions offset projects, electricity transmission, water desalination, and other businesses. 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 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. We continue to emphasize growth through "greenfield" development, platform expansion, privatization of government-owned assets, and mergers and acquisitions and continue to develop and maintain a strong development pipeline of projects and opportunities. The Company sees growth investments as the most significant contributor to long-term shareholder value creation. 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 own assessment of value in the AES portfolio.

        Underpinning this growth focus is an operating model which benefits from a diverse power generation portfolio that is largely contracted, reducing fuel cost and demand risks, and from an electric utility portfolio heavily weighted to faster-growing emerging markets.

        The Company believes that success with its business development activities will be the single most important factor in its financial success in terms of value creation and it is directing increasing resources in support of business development globally. The Company also believes that high oil prices, increasing regulation of greenhouse gases, faster than expected global economic growth and a weak dollar present opportunities for value creation, based on the Company's current business portfolio and business strategies. Slower global economic growth, which will impact demand growth for utilities and some generation businesses, is one of the most significant downside scenarios affecting value creation. Other important scenarios that could impair future value include low oil prices and a strong dollar.

        We believe that our organizational structure, including our use of regional management teams, is the most effective method to manage our business. We target geographic regions as primary areas of expansion because our regional management structure provides us with important relationships in key

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markets and helps us identify localities with a large and growing need for power and other favorable characteristics for new investment. Regional management also allows for a hands-on approach to operations and business developments, which helps us assess and manage the risks associated with our new investments in each region. As a large organization we believe we have the resources and the ability to capitalize on economies of scale and develop better operating and management practices to increase our overall efficiency and productivity. Finally, our broad geographic footprint reduces political, macroeconomic and other risks associated with conducting business in any particular region.

Segments

        Beginning with our 2006 Form 10-K, as amended, we realigned its reportable segments. We previously reported under three segments: Regulated Utilities, Contract Generation and Competitive Supply. The Company currently reports seven segments as of December 31, 2006, which include:

        The additional segment reporting better reflects how AES manages the company internally in terms of decision making and assessing performance. The Company manages its business primarily on a geographic basis in two distinct lines of business—the generation of electricity and the distribution of electricity. These businesses are distinguished by the nature of the customers, operational differences, cost structure, regulatory environment and risk exposure.

Latin America

        Our Latin America operations accounted for 63%, 61% and 55% of consolidated revenues in 2006, 2005, and 2004, respectively. AES began operating in Latin America in 1993 when it acquired the CTSN power plant in Argentina. Since that time, AES has expanded its presence in the region and now has operations in eight Latin American countries. These operations include a total of 48 generation plants owned and operated under management agreements with a total generating capacity of 11,224 MW. AES owns and operates 8 utilities, distributing a total of 45,785 GWh, in addition to operating one utility under management agreement, which distributes 1,626 GWh to customers.

        Our Generation business in Latin America consists of 48 generation facilities with the capacity to generate 11,224 MW. This capacity includes our new 125 MW Los Vientos diesel-fired peaking facility, which came on line in January, 2007 and serves the largest power market in Chile. AES also has two coal plants under construction in Chile, Guacolda III and Ventanas III with 152 MW and 267 MW generation capacities respectively, and one plant under construction in Panama, the Changuinola hydro plant with 223 MW capacity.

        We own eight Utility businesses, including electricity distribution businesses located in Argentina (EDELAP and EDES), Brazil (AES Eletropaulo and AES Sul) and El Salvador (CAESS, CLESA,

92

DEUSEM and EEO). Our ninth Utility business, EDC, was sold in May 2007. We also manage another utility under contract in the Dominican Republic. These businesses sell electricity under regulated tariff agreements and each has transmission and distribution capabilities. AES 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. 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.

North America

        Our North America operations accounted for 25%, 26% and 29% of consolidated revenues in 2006, 2005 and 2004, respectively. AES began operating in North America in 1985, when it developed its first power plant in Deepwater, Texas. Since then AES has grown its North America business and currently owns a total of 21 generation facilities with 9,892 MW generating capacity and one integrated utility, distributing approximately 16,287 GWh of electricity to customers with 3,599 MW of generation capacity.

        In North America, AES has 21 generation facilities, including seven gas-fired plants, ten coal-fired plants, three petroleum coke-fired plants and one biomass-fired plant, in the United States, Puerto Rico and Mexico.

        We have one integrated utility in North America, IPL, which we own through IPALCO Enterprises Inc. ("IPALCO"), the parent holding company of IPL. IPL is engaged in generating, transmitting, distributing and selling electric energy to more than 465,000 customers in the city of Indianapolis and neighboring areas within the state of Indiana. IPL also owns and operates four generation facilities. Two 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 3,599 MW.

Europe & Africa

        Our operations in Europe & Africa accounted for 12%, 12% and 13% of our consolidated revenues in 2006, 2005 and 2004, respectively. AES began operations in Europe & Africa in 1992, when we acquired the AES Kilroot power plant in Northern Ireland. Since that time, AES has grown in this region and now has a presence in 11 countries. AES's operations in the region now include a total of 15 generation plants owned or operated under management agreements with a total of 10,530 MW generation capacity. AES owns and operates three utilities, distributing a total of 8,960 GWh with 927 MW of capacity. In addition, AES operates 2 utilities under management agreement in the region, which distribute a total of 2,096 GWh.

        We own 13 generation facilities in Europe & Africa, and operate two additional generation facilities under management contract in Kazakhstan. These generation facilities have the capacity to generate 10,530 MW. In 2006, we began commercial operation of AES Cartagena, our first power plant

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in Spain with 1,200 MW capacity. AES Maritza East 1 is a 670 MW lignite-fired power plant currently under construction in Bulgaria.

        We own three Utility businesses in Europe & Africa, including an integrated utility in Cameroon (AES SONEL) and two distribution businesses in Ukraine (Kievoblenergo and Rivneenergo). AES acquired a 56% interest in AES SONEL in 2001. AES SONEL generates, transmits and distributes electricity to approximately 538,000 customers. AES SONEL has an installed generating capacity of 927 MW, and a small plant under construction. Our two distribution businesses in Ukraine serve over 1.2 million customers, while the two distribution businesses we operate under management agreements in Kazakhstan together serve over 554,000 customers.

Asia

        Our Asian operations accounted for 7%, 6% and 7% of consolidated revenues in 2006, 2005 and 2004, respectively. AES began operations in Asia in 1994 when we acquired the Cili power plant in China. Since that time AES's Generation business has expanded and it now operates 13 power plants with a total capacity of 5,369 MW in six countries. AES only operates generation facilities in Asia.

        AES has 13 generation facilities with the capacity to generate 5,369 MW. Over half of our facilities and capacity are located in China, where AES joined with Chinese partners to build Yangcheng, the first "coal-by-wire" power plant with the capacity of 2100 MW. In 2000, AES was selected by the Sultanate of Oman to build, own and operate a 456 MW and 20 MIGD combined power and desalinated water facility, which achieved commercial operations in 2003. In 2001, AES was awarded the right to build, own and operate for 25 years a 756 MW and 40 MIGD combined power and desalinated water facility, the first such facility to be awarded to the private sector in Qatar. This facility commenced commercial operations in 2004. AES also owns and operates two oil-fired facilities in Pakistan (Lal Pir and Pak Gen), which have been in operations for the last nine years. In India, AES acquired a 420 MW coal-fired power plant (OPGC) in 1998. In Sri Lanka, AES owns a 168 MW diesel-fired power plant that began commercial operations in 2003. AES Amman East is a 370 MW combined-cycle gas power plant under construction in Jordan.

Corporate and Other

        Corporate and other expenses include 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 inter company charges such as management fees and self insurance premiums which are fully eliminated in consolidation.

        In addition, Corporate and Other also includes net operating results of our Alternative Energy business which is not material to our presentation of operating segments. We own and operate 298 MW of wind generation capacity and operate an additional 298 MW capacity through operating and management or O&M agreements. We also have ownership interests in development-stage companies in Scotland, France and Bulgaria. In 2006, we began construction of the 233 MW Buffalo Gap 2 wind farm in Texas.

        The table below presents information about our consolidated operations and long-lived assets, by country, for years ended December 31, 2006 through December 31, 2004 and as of December 31, 2006

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and 2005, respectively. Revenues are recorded 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
 
   2006
   2005
   2004
   2006
   2005
 
   (in millions)
United States   $ 2,516   $ 2,311   $ 2,185   $ 5,872   $ 5,589
Non-U.S.                              
Brazil     4,161     3,823     2,925     4,567     4,130
Argentina     542     438     320     412     418
Chile     595     542     436     812     796
Dominican Republic     357     231     168     653     476
El Salvador     437     377     356     241     225
Pakistan     318     177     210     272     288
United Kingdom     222     208     215     303     282
Cameroon     302     288     272     407     354
Mexico     185     226     186     188     195
Puerto Rico     234     213     188     626     643
Hungary     304     230     192     225     209
Ukraine     269     217     190     106     97
Qatar     169     165     129     578     603
Colombia     184     182     132     398     407
Panama     144     134     117     450     454
Oman     114     113     110     337     346
Kazakhstan     215     158     137     175     150
Other Non-U.S.     296     287     277     575     490
   
 
 
 
 
Total Non-U.S.   $ 9,048   $ 8,009   $ 6,560   $ 11,325   $ 10,563
   
 
 
 
 
Total   $ 11,564   $ 10,320   $ 8,745   $ 17,197   $ 16,152
   
 
 
 
 

Facilities

        The following tables present information with respect to the facilities in each of our business segments as of December 31, 2006. The amounts under Gross Megawatt ("MW") and "Approximate Gigawatt Hours" represent the gross amounts for each facility without regard to our percentage of ownership interest in the facility.

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Segment—Latin America Generation

Business
   Location
   Fuel
   Gross
M W
   AES Equity
Interest
(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   —   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   82 % 2000
Gener—Energía Verde(4)   Chile   Biomass / Diesel   42   91 % 2000
Gener—Gener(5)   Chile   Hydro / Coal / Oil   807   91 % 2000
Gener—Guacolda   Chile   Coal   304   46 % 2000
Gener—Norgener   Chile   Coal / Pet Coke   277   91 % 2000
Chivor   Colombia   Hydro   1,000   91 % 2000
Andres   Dominican Republic   Gas   319   100 % 2003
Itabo(6)   Dominican Republic   Coal / Oil   472   48 % 2000
Los Mina   Dominican Republic   Gas   236   100 % 1997
Bayano   Panama   Hydro   260   49 % 1999
Chiriqui—Esti   Panama   Hydro   120   49 % 2003
Chirqui—La Estrella   Panama   Hydro   45   49 % 1999
Chirqui—Los Valles   Panama   Hydro   51   49 % 1999
           
       
            11,217        
           
       
(1)
AES operates these facilities through management or operations and maintenance agreements and owns no equity interest in these businesses

(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: Nueva Renca and 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

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Business
   Location
   Fuel
   Gross MW
   AES Equity
Interest
(Rounded)
   Expected Year
of Commercial
Operation
Guacolda III   Chile   Coal   152   46 % 2009
Ventanas III   Chile   Coal   267   91 % 2010
Changuinola   Panama   Hydro   223   83 % 2010
           
       
            642        
           
       

Segment—Latin America Utilities

Business
   Location
   Fuel
   Gross MW
   AES Equity
Interest
(Rounded)
   Year Acquired
or Began
Operation
EDC(1)(2)   Venezuela   Oil/Gas   2,616   82 % 2000
(1)
EDC plants: Amplicacion Tacoa, Tacoa, Arrecifes, Oscar Augusto Machado and Genevapca

(2)
AES sold its interest in EDC to the PDVSA in May 2007

Business
   Location
   Approximate
Number of
Customers
Served as of
12/31/2006
   Approximate
Gigawatt Hours
Sold in 2006
   AES Equity
Interest
(Rounded)
   Year
Acquired
Edelap   Argentina   302,845   2,450   90 % 1998
Eden   Argentina   306,885   2,273   90 % 1997
Edes   Argentina   156,908   751   90 % 1997
Eletropaulo   Brazil   5,468,727   31,656   16 % 1998
Sul   Brazil   1,071,860   7,545   100 % 1997
CAESS   El Salvador   491,631   2,091   75 % 2000
CLESA   El Salvador   281,473   764   64 % 1998
DEUSEM   El Salvador   53,000   95   74 % 2000
EEO   El Salvador   207,441   433   89 % 2000
EDC(1)   Venezuela   1,103,149   10,523   82 % 2000
       
 
       
        9,443,919   58,581        
       
 
       
(1)
AES sold its interest in EDC to the PDVSA in May 2007

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Business
   Location
   Approximate
Number of
Customers
Served as of
12/31/2006
   Approximate
Gigawatt Hours
Sold in 2006
   AES Equity
Interest
(Rounded)
EDE Este(1)   Dominican Republic   330,187   1,626   —
(1)
AES operates these facilities through management agreements and owns no equity interest in these businesses

Segment—North America Generation

Business(1)
   Location
   Fuel
   Gross M W
   AES Equity
Interest
(Rounded)
   Year Acquired
or Began
Operation
Mérida III   Mexico   Gas   484   55 % 2000
Termoelectrica del Golfo (TEG)(2)   Mexico   Pet Coke   230   100 % 2007
Termoelectrica del Peñoles (TEP)(2)   Mexico   Pet Coke   230   100 % 2007
Central Valley—Delano   USA -CA   Biomass   57   100 % 2001
Central Valley—Mendota   USA -CA   Biomass   28   100 % 2001
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
Hemphill   USA -NH   Biomass   16   67 % 2001
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
           
       
            9,977        
           
       
(1)
AES additionally owns and operates the Coal Creek Minerals coal mine in Oklahoma, USA

(2)
Acquired February, 2007

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Segment—North America Utilities

Business
   Location
   Fuel
   Gross M W
   AES
Equity Interest
(Rounded)
   Year
Acquired or
Began
Operation
IPL(1)   USA—IN   Coal/Gas/Oil   3,599   100 % 2001
(1)
IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg

Business
   Location
   Approximate
Number of
Customers Served as
of 12/31/2006
   Approximate
Gigawatt Hours
Sold in 2006
   AES
Equity Interest
(Rounded)
   Year
Acquired
IPL   USA—IN   468,867   16,287   100 % 2001

Segment—Europe & Africa Generation

Business(1)
   Location
   Fuel
   Gross
M W
   AES
Equity Interest
(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   Biomass/Coal   116   100 % 1996
Ekibastuz   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
Kilroot   United Kingdom   Coal/Oil   520   97 % 1992
           
       
            10,504        
           
       
(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 maintenance agreements and owns no equity interest in these businesses
Business
   Location
   Fuel
   Gross M W
   AES
Equity Interest
(Rounded)
   Expected
Year of
Commercial
Operation
Maritza East I   Bulgaria   Lignite   670   100 % 2009

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Segment—Europe & Africa Utilities

Business
   Location
   Fuel
   Gross M W
   AES
Equity Interest
(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
   Fuel
   Gross M W
   AES
Equity Interest
(Rounded)
   Expected
Year of
Commercial
Operation
SONEL(1)   Cameroon   Heavy Fuel Oil   13   56 % 2007
Business
   Location
   Approximate
Number of
Customers Served
as of 12/31/2006
   Approximate
Gigawatt Hours
Sold in 2006
   AES
Equity Interest
(Rounded)
   Year
Acquired
SONEL   Cameroon   538,257   3,374   56 % 2001
Kievoblenergo   Ukraine   833,005   3,639   89 % 2001
Rivneenergo   Ukraine   402,541   1,947   81 % 2001
       
 
       
        1,773,803   8,960        
       
 
       
Business
   Location
   Approximate
Number of
Customers Served as
of 12/31/2006
   Approximate
Gigawatt Hours
Sold in 2006
   AES Equity Interest
(Percent, Rounded)
Eastern Kazakhstan REC(1)(2)   Kazakhstan   460,087   2,096   —
Ust-Kamenogorsk Heat Nets(1)(3)   Kazakhstan   94,748   —   —
       
       
        554,835        
       
       
(1)
AES operates these facilities through management agreements and owns no equity interest in these businesses

(2)
Eastern Kazakhstan REC sells power to Shygys Energo Trade company, an AES subsidiary in Kazakhstan that distributes electricity to customers in Ust-Kamenogorsk and Semipalatinsk areas

(3)
Ust-Kamenogorsk Heat Nets provide transmission, and distribution of heat, with a total heat generating capacity of 224 Gcal

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Segment—Asia Generation

Business
   Location
   Fuel
   Gross M W
   AES
Equity Interest
(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 % 2004
Kelanitissa   Sri Lanka   Diesel   168   90 % 2003
           
       
            5,369        
           
       
Business
   Location
   Fuel
   Gross M W
   AES
Equity Interest
(Rounded)
   Expected
Year of
Commercial
Operation
Amman East(1)   Jordan   Gas   370   60 % 2009
(1)
Construction of the Amman East power plant commenced in May, 2007

Alternative Energy (included in Corporate and Other)

Business
   Location
   Fuel
   Gross M W
   AES
Equity Interest
(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   54   100 % 2006
Condon(1)   USA—OR   Wind   50   —   2005
Buffalo Gap(1)   USA—TX   Wind   121   —   2006
           
       
            298        
           
       
(1)
AES owns Condon and Buffalo Gap wind facilities together with third party equity investors with variable equity ownership interests. It also has ownership interests in development-stage companies in Scotland, France and Bulgaria.

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Business
   Location
   Fuel AES
   Gross M W
   AES Equity Interest
(Percent, Rounded)
Wind generation facilities(1)   USA   Wind   298   —
(1)
AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses
Business
   Location
   Fuel
   Gross M W
   AES
Equity Interest
(Rounded)
   Expected
Year of
Commercial
Operation
Buffalo Gap II   USA—TX   Wind   233   100 % 2007

Customers

        We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2006 total revenues.

Employees

        As of September 30, 2007, we employed approximately 30,000 people.

Regulatory Matters

        The Company is subject to complex energy, environmental and other governmental laws and regulations, both in the United States and in the other countries where it conducts business. These regulations affect most aspects of its business, including the development, ownership and operation of power generating facilities and in connection with the purchase and sale of electricity. The Company must also comply with applicable environmental and land use laws, rules and regulations.

Latin America

        In January and February 2002, the Argentine government adopted many new economic measures as a result of political, social and economic crisis. The new economic measures included: (i) the abandonment of the country's fixed dollar-to-peso exchange rate, (ii) the conversion of U.S. dollar denominated loans into pesos and (iii) the placement of restrictions on the convertibility of the Argentine peso. The regulations adopted in 2002 and 2003 in the energy sector effectively overturned the U.S. dollar based nature of the electricity sector. In the wholesale power market, electricity generators declared their costs of generation (which reflected their fuel costs) on a semi-annual basis. Under the current regulations, energy prices were partially converted from the original U.S. dollar denomination into Argentine pesos ("pesified"), following the pesification of the price of natural gas. However, the authorities permitted the production of cost for alternative fuels (fuel oil, coal) to reflect international costs. In order to avoid price increases associated with the use of alternative fuels, market regulations were changed so that the spot price is set considering only production costs declared with natural gas. Therefore, while generators receive remuneration for the use of alternative fuel, this cost is not considered when setting the spot price. Because of this, generation prices still reflect an artificially

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low fuel price, but due to the gas supply crisis and the subsequent agreement between the government and the gas producers to reset the prices, as described below, this effect has been offset and gas prices have returned to the levels of 2001 prior to the economic crises.

        During 2004, the Energy Secretariat reached agreements with natural gas and electricity producers to reform the energy markets. The agreement with natural gas producers established a recovery path that increased wellhead prices to 80% of the original U.S. dollar price of 2001 by July 2005 and a second path that reached export parity by the end of 2006. In the electricity sector, the Energy Secretariat passed Resolution 826/2004, inviting generators to partially contribute their existing and future credits in the Wholesale Electricity Market ("WEM") from January 2004 to December 2006 to fund the development and construction of two new combined cycle power plants to be installed by 2008/2009. In exchange, the Argentine government committed to reform the market regulation to match the pre-crisis rules prevailing before December 2001, including setting the capacity payment with a U.S. dollar reference and eliminating all regulations fixing an artificially low price in the wholesale market by 2009. As of May 31, 2005, the Argentine government reached an agreement on these reforms with more than 90% of generator companies. In October 2005, by Resolution 1193/2005 the Energy Secretariat and the power generators signed the final agreement for the management and operation of the projects intended to reset the electricity market. In February 2006, the Energy Secretariat approved the bylaws of the new companies, "Termoelectrica General San Martin S.A." and "Termoelectrica General Belgrano S.A." to be located in Timbues, next to Rosario city in Santa Fe province and in Campana city, Buenos Aires province, respectively. There can be no assurance, however, that the Argentine government will honor its commitment to release restrictive measures that it has placed upon wholesale prices after the new capacity is installed.

        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 enacted Law No. 25,790, which established the procedure for renegotiation of the public utilities concessions and extended the period for that process until December 31, 2007. In combination, these circumstances create significant uncertainty surrounding the performance of the electricity industry in Argentina, including the Argentina subsidiaries of AES.

        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, has been granted. Invoicing of the tariff increase commenced in August 2005. The Letter of Understanding also includes: (i) local cost adjustments to the tariff;(ii) elimination of penalties arising from potential energy supply shortages in Argentina; (iii) long-term payment terms for penalties owed to the customers; and (iv) other favorable conditions which are intended to benefit the company. The agreement was the first of its kind signed with UNIREN (Unit for the Renegotiation and Analysis of Public Services Contracts) in the Argentine electricity sector. Upon execution of the Letter of Understanding, AES agreed to postpone or suspend certain international claims; however, the Letter of Understanding provides that if the government does not fulfill its commitments, AES may re-start the international claim process. AES has postponed any action until the tariff reset is finalized. On January 20, 2006, the Argentine regulator (ENRE) postponed the public hearing for the tariff review process; a new date for these processes has not been set. On October 24, 2005, EDEN and EDES, two AES distribution businesses in Argentina, 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

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approved by a Governor Decree on November 30, 2005. This Letter of Understanding includes the following:

        This Letter of Understanding also includes other favorable conditions beneficial to these distribution facilities. AES agreed to postpone or suspend certain international claims; however, like the EDELAP Letter of Understanding, this Letter of Understanding provides that in case the government does not fulfill its commitments, AES may re-start the international claim process. AES has postponed any action with respect to international claims until the tariff reset is finalized.

        Under the present regulatory structure, the power industry in Brazil is regulated by the Brazilian government, acting through the Ministry of Mines and Energy ("MME") and the National Electric Energy Agency ("ANEEL"), an independent federal regulatory agency which has exclusive authority over the Brazilian power industry. ANEEL's main function is to ensure the efficient and economic supply of energy to consumers by monitoring prices and ensuring adherence to market rules by market participants in line with policies dictated by the MME. ANEEL supervises concessions for electricity generation, transmission, trading and distribution, including the approval of applications for the setting of tariff rates, and supervising and auditing the concessionaires. ANEEL's core areas of responsibility that are directly related to AES's businesses are: economic regulation, technical regulation and consumer affairs oversight.

        On December 11, 2003, the Brazilian government announced and proposed a new model for the Brazilian power sector (the "New Power Sector Model") and enacted Provisional Measures #144 and #145, which set forth the basic rules that will govern the New Power Sector Model. On March 15, 2004, Law #10848 was enacted, which sets forth the basis of the new regulatory framework and general rules for power commercialization, regulated by Decree #5163, of July 30, 2004 and other administrative rulings.

        The main points of the New Power Sector Model and its impact on AES businesses in Brazil are as follows:

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        As part of the implementation process of the New Power Sector Model, distribution companies signed amendments to concession contracts, which modified a clause relating to the tariffs with respect to: (i) methodology of power purchase cost pass-through (mentioned above); and (ii) exclusion of PIS/COFINS (taxes over revenue).

        The Electric Energy Commercialization Chamber ("CCEE") carried out the largest auction in the country's history on December 7, 2004, in which power distribution utilities bought energy to serve 100% of their markets projected for 2005, 2006 and 2007 entering into the corresponding Regulated Power Purchase Agreements—CCEAR. The Brazilian government inserted the rights for the CVA of energy purchased in the auctions into the concession contracts by an amendment to said contracts. The New Power Sector Model Law is currently being challenged on constitutional grounds before the Brazilian Supreme Court. To date, the Brazilian Supreme Court has not reached a final decision. Although the Company does not know when such a decision may be reached, the New Power Sector Model is currently in full force and it is very unlikely that it will be found unconstitutional.

        In order to maintain the economic and financial equilibrium of the concession, utilities are entitled to the following types of tariff adjustments contemplated in the concession contracts:

        The primary purpose of the Annual Tariff Adjustment ("IRT") is the maintenance of an adjusted tariff for inflation and the sharing of efficiency gains with consumers. The IRT uses a formula such that non-manageable (Parcel A) costs are passed through to the consumers and manageable (Parcel B) costs are indexed to inflation. An "X-Factor' is applied to capture the sharing of scale gains, effectively reducing the inflation index that is applied to Parcel B costs. The operations and maintenance costs considered in the tariff are based on the concept of a Reference Company, not on actual costs. In many cases, the Reference Company may not be reflective of distribution companies operating in Brazil and thus, under estimate true operating costs. ANEEL authorized an average adjustment of 11.45% (IRT) for Eletropaulo tariffs, effective July 4, 2006. The second tariff reset for Eletropaulo occurred in 2007, while the second tariff reset for Sul is scheduled for 2008.

        ANEEL's Resolution 234/06 establishes the methodology for the 2nd Cycle of Tariff Reset. The main aspects of this Resolution are detailed below:

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        On July 3, 2007, through Resolution 500/2007, ANEEL authorized Eletropaulo a tariff reset index of -8.43%, applicable to the Company's tariff as from July 4, 2007.

        The figure authorized by ANEEL is provisional, due to the fact that some items are still pending of definitions as mentioned above (example: reference company, bad debts, etc).

        Eletropaulo did not agree with some aspects of the Regulatory Rate Base and the X-Factor, and filed an administrative appeal at ANEEL.

        AES's business in Brazil is still attempting to resolve certain regulatory issues relating to a rationing program instituted in 2001. Specifically, on December 21, 2001, the President of Brazil issued a provisional measure which provided general authorization for: (i) pass-through to consumers of costs incurred by generators for the purchase of energy at spot prices during the rationing program and (ii) recovery in future years of revenue losses sustained by distributors during the rationing period, through an Extraordinary Tariff Adjustment ("RTE"). ANEEL, through a resolution issued on January 12, 2004, established AES Eletropaulo's RTE recovery period at 70 months and stated that Parcel A recovery will happen only after the RTE recovery.

        AES Sul is pursuing the annulment of ANEEL's Order 288, issued on May 16, 2002, in which ANEEL retroactively prohibited several companies, AES 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$373 million (historic values referring to 2001). AES Sul was granted a preliminary injunction ordering ANEEL to review CCEE's registers and calculations. This lawsuit awaits the judge's decision regarding ANEEL's petition to include CCEE as a co-defendant in the lawsuit. If the operations registered in CCEE are cleared with the effect of Order # 288 in place, AES Sul will owe a net amount of approximately R$80 million (historic values referring to 2001). If AES Sul is unsuccessful and unable to pay any amount that may be due to CCEE, or to other market agents, as a result of the operations registered therein, penalties and fines could be imposed up to and including the termination of the concession contract by ANEEL. AES 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 AES Sul loses the case, are reserved in AES Sul's books.

        AES' concession agreement with the State of Sao Paulo for the Tiete generation plant includes an obligation to increase generation capacity by 15% by the end of 2007. It is anticipated that AES, as well as other concessionaire generators, will not be able to meet this requirement due to regulatory and hydrological conditions making the increase impossible. 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.

        On February 13, 2007 ANEEL issued Resolution #250/07 in order to clarify and regulate the provisions of a 2003 law (Law# 10762/03), which had not yet been interpreted by ANEEL. This new resolution establishes guidelines for dividing costs associated with new connection (or load increase) requested by customers, between the distribution company and the corresponding customers. The

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effects regarding this Resolution were recognized on Regulatory Rate Base defined by ANEEL for the 2nd Cycle of tariff Reset. AES Sul is still evaluating the full effect of this new resolution.

        In Chile, the regulation of production schedules for electricity generation facilities is based on the marginal cost, which is the variable cost of the least expensive next unit required by the system at any time. Chile has four electricity systems. The major two interconnected electricity systems are the Central Interconnected System(Sistema Interconectado Central) ("SIC") and the Northern Interconnected System (Sistema Interconectado del Norte Grande) ("SING"), which cover almost 97% of the population of the country.

        The electricity market in Chile is divided into three distinct segments, generation, transmission and distribution. The regulatory framework was enacted in 1982, and the underlying foundation has remained unchanged, except for amendments which have focused on providing clarifications and additional incentives to market participants.

        Based on the Chilean electricity market framework, two electricity markets coexist: 1) a primary contract market for transactions between generators and customers, and 2) a secondary spot market for the exchange of energy and firm capacity among generators. In the primary market, customers, including regulated distribution companies and unregulated customers are obligated to enter into long-term power purchase agreements, which specify the volume and financial terms associated with the sale of energy and capacity.

        In the secondary market, the independent system operator (CDEC) in each system dispatches the plants in order to have, at any specific level of demand, the appropriate supply at the lowest possible marginal cost of production available in the system, considering transmission and reliability constraints.

        As a result, generation companies are free to enter into sales contracts with distribution companies and other customers for the sale of capacity and energy. However, the electricity necessary to fulfill these contracts is provided by the contracting generation company only if the generation company's marginal cost of production is low enough for its generating capacity to be dispatched to meet demand. Otherwise, the generation company will purchase electricity from other generation companies at the marginal cost of the system, which is lower than the production cost of the company.

        The prices paid to generation companies by distribution companies for capacity and energy to be resold to their retail customers are, pursuant to law, based on the expected average marginal cost of capacity or energy. In order to ensure price stability, however, the regulatory authorities in Chile established "node prices" to be set every six months for energy and capacity requirements of regulated consumers paid by distribution companies. Node prices for energy are calculated on the basis of the projections of the expected marginal costs within the system over the next 24 to 48 months, in the case of the SIC and the SING. The formula takes into account, among other things, assumptions regarding available supply and demand in the future. Node prices for capacity are based on the marginal investment required to meet peak demand, based on the cost of a diesel-fired turbine. Prices for capacity and energy sold to large customers (over 0.5 MW) and other generation companies purchasing on a contractual basis are unregulated and are often set with reference to node prices, alternative fuel prices, exchange rates and other factors. If average prices for capacity and energy sold to non-regulated customers differ from node prices by more than a defined percentage (5%-30%, calculated pursuant to regulations), node prices are adjusted upward or downward, as the case may be, so that the difference between such prices equals such percentage.

        On March 13, 2004, Law No. 19.940 was enacted establishing amendments to the existing Electricity Law, principally in relation to tolls charged for the use of high voltage network and transmission systems. The reduction of the minimum demand required to be considered as an

107


unregulated customer went from 2 MW to 0.5 MW. In addition, other factors considered are the reduction of the floating band for regulated price from 10% to 5%, the incorporation of elements to create an ancillary services market and the pricing mechanism for small and medium-sized electricity systems. The modifications contained in Law No. 19.940 maintain or improve the Company's position with regard to both the Company's current status and projected development and, in particular, with regard to the issues related with transmission tolls. In addition, the Regulations to the Electricity Law, Supreme Decree No. 327, which was modified on October 9, 2003 with respect to the clarification of the methodology utilized to calculate transmission tolls, has been replaced by Law No. 19.940.

        On March 25, 2004, the Argentine government published Resolution 265, which privileged the domestic supply of natural gas, immediately affecting the export of natural gas to neighboring countries (primarily Chile). However, this resolution provided suppliers with alternative means of supply under existing export contracts. Between April and June 2004, daily export restrictions to Chile fluctuated between 20% and 47% of contracted volumes, depending on domestic demand. At the end of 2004, the curtailments were less than 10% due to improved hydrological conditions in Argentina and Chile, and increased availability of Bolivian gas.

        This situation changed at the beginning of 2005 when as a result of high electricity demand and natural gas consumption in Argentina, in addition to the policy established by Compañia Administradora del Mercado Eléctrico ("CAMMESA") to conserve water under Resolution 839, the curtailments increased during summer months reaching a peak of almost 50%, equivalent to 402 Mmcf/d at the end of May 2005. From May until September 2005, the daily export restrictions to Chile fluctuated between 40% and 10%. In the last quarter of 2005, the restrictions were reduced by 7% to 12%, mainly due to improved hydrological conditions compared to the beginning of the year.

        Electrica Santiago, a subsidiary of the Company, produces electricity by burning natural gas produced in southern Argentina which is transported to central Argentina through a pipeline owned by Transportadora Gas del Norte S.A., or TGN, and then to Chile. The TGN pipeline supplies consumers in Argentina and Chile. Interruptions in the supply and/or transportation of natural gas by TGN would adversely affect the operations and financial condition of Electrica Santiago. Such potential interruptions would materially impair Electrica Santiago's ability to generate electricity and would force it to rely on the spot market to purchase electricity to meet its contractual commitments. Furthermore, because all combined-cycle plants in the SIC use the same pipeline to obtain their natural gas supplies from Argentina, a disruption of this supply would materially increase prices in the spot market. The reliance on the spot market to purchase electricity could have a material adverse effect on Electrica Santiago.

        On May 3, 2005, a bill to amend the Electric Law was approved by the Chilean congress which was promulgated by the executive branch on May 19, 2005 (Law No 20.018). The bill was designed to mitigate the effects of the restrictions on natural gas exports to Chile, which have been applied by the Argentine government since March 2004. The main aspects of Law 20.018 include:

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        These changes produced an improvement in the regulatory framework by reducing the risks of arbitrary regulatory intervention and creating a better investment environment. The first bid process was successfully carried out in October 2006. In November of 2006, Gener was awarded 1,355 GWH in the recent bidding process held by the electricity distribution companies.

        In 1994 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 Mining and Energy Planning Unit ("UPME") develops plans for the energy sector. These plans are then adopted by the Ministry of Mines and Energy. In addition to other initiatives, the general regulatory framework established free access in the networks, free entrance in the business, the creation of a wholesale market, the unbundling of activities, the principles for setting formulas for tariffs and the free selection of the provider by the consumer.

        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 offers its availability quantities for a 24 hour period with one price set for those 24 hours. The dispatch is arranged by price merit, and the spot price is set by the marginal unit. The system is one node.

        Colombia's spot market began in July 1995, and in 1996 a capacity payment was introduced for a term of 10 years. In December 2006, Regulation 071 was enacted which replaced the capacity charge with a reliability charge. This new charge has been in place since December 2006 and is expected to have a positive impact on Chivor for 2007 of US $15.5 million compared to the US $18.3 million that it received in 2006. Under the reliability charge mechanism, plants present firm energy price and volume offers in public auctions that are held three years prior to the initiation of supply. Plants are allowed to bid up to the maximum firm energy level which can be provided during drought conditions, as defined in a methodology utilized by the CREG. The new regulation includes a transition period from December 2006 to November 2009, during which the price is equal to US $13 per MWh 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.

        Bilateral contracts between a generator and suppliers are treated as financial instruments which are settled by the Market Administrator. These contracts are normally either "take or pay" or "take and pay" agreements, and normally have a term of one to three years. There is no regulatory obligation for an electricity supplier to hedge its consumers' demand, and the negotiation of energy contracts between generators and suppliers for unregulated customers is unrestricted. The contracts to supply energy to regulated (small) consumers must be assigned by the Load Servicing Entities ("LSE") through a public bidding process to determine the lowest offer.

        The General Electricity Law No. 125-01 was passed on July 26, 2001. New institutions were created to formulate energy policy and regulate the sector, including the Energy National Commission ("CNE") and the Superintendancy of Electricity ("SIE"). However, some of the new resolutions

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adopted by SIE are in conflict with the regulations created by the Ministry of Industry and Commerce prior to enactment of Law 125-01.

        During 2004, an increase in fuel prices caused a financial crisis in the Dominican Republic electrical sector. Specifically, 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 generators for electricity generated. The election of a new presidential administration in August 2004 has been accompanied by progress towards addressing the crisis in the electricity sector. Negotiations have intensified between the government, the multilateral lending and development agencies such as the IMF and the World Bank and the private electricity sector. The key issues that are the focus of these negotiations include (i) the failure to provide for full pass-through of the costs of electricity supply to consumers; (ii) the failure of the regulator to follow through on subsidy commitments, which has put the distribution companies in the position of effectively financing portions of the subsidy programs; and (iii) the fiscal deficit of the government of the Dominican Republic which requires multilateral lending to reconstitute the sector.

        During 2006, the Dominican Republic government has been paying both the subsidies and its own energy bills on time; the tariff has been modified to recognize the fuel generation basket, and there is increased support for fraud prosecution. Despite this improvement over prior years, the electricity sector has not completely recovered from the financial crisis of 2004. Last year it needed more then US $500 million to cover the current operations, and for 2007 an amount of US $400 million has been included in the budget, which indicates that the electricity sector in the Dominican Republic remains fiscally unstable, so that additional reforms may be needed.

        In December 2006, the Executive branch sent to congress a bill modifying the General Electricity Law. The bill criminalizes theft of electricity and simplifies the process that the Distribution companies must follow in order to detect and document fraud in the electric networks. The legislation will be considered and could be approved in the first quarter of 2007.

        In 1996, the government of El Salvador created a new regulatory framework through the enactment of the Electricity Law in October of 1996, as amended in June 2003. The Electricity Law regulates the generation, transmission, marketing, distribution and supply of electricity in El Salvador and provided the basis for private sector participation and competition in the Salvadoran energy sector, the unbundling of electricity generation, transmission and distribution, the privatization of electricity distribution and generation assets and the creation of a transparent regulatory structure.

        Under the Electricity Law, an independent regulator, Superindencia General de Electricidad y Telecomunicaciones ("SIGET"), was established, and the country's pubic electric company, Comisión Ejecutiva Hidroeléctrica de río Lempa ("CEL") was required to reorganize its generation, transmission and distribution assets to facilitate privatization. CEL separated its generation, transmission and distribution activities from one another and further divided its generation and distribution activities into operationally independent companies for purposes of privatization.

        El Salvador has five electricity distribution companies. AES controls four of these five distribution companies: CAESS, CLESA, EEO, and DEUSEM, which include rural electrification activities that were situated near the networks of these companies.

        The government has recently adopted certain revisions and adjustments to the regulatory system created by the Electricity Law, and additional modifications are under consideration. The government is studying how to further separate the activities of CEL and El Salvador Electricity Transmission Company ("ETESAL"), the transmission company that is owned by CEL, with the goal of privatizing ETESAL. In addition, new Salvadoran regulations have been recently issued aimed at facilitating the

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entry of electricity traders into the electricity market and improve the transparency of the pricing signals in the wholesale market.

        In June 2003, the government amended the Electricity Law to grant greater regulatory authority to SIGET and to create a compensatory fund in the wholesale market to promote stability in the price of energy on the spot market. SIGET has recently prepared norms and guidelines in the form of a manual, which will set minimum standards for electricity distribution companies for system design, distribution losses and costs, as well as service quality and reliability. In addition, as part of the Company's regular upcoming five-year tariff review process, SIGET is reviewing the characteristics of the demand curve for each of the Company's electricity distribution networks, in order to be able to better analyze and review the Company's proposed tariffs.

        During 2005, the Ministry of Economy ("Ministerio de Economía") proposed revising the dispatch rules for El Salvador's electricity market from a bidding to an economic dispatch basis. If this reform is adopted in the future, it may adversely affect the Company's ability to continue to generate margins on the energy it buys and sells for its customers. The proposal remains under discussion.

        In 1995, Panama initiated the reform of its electricity sector with the passage of legislation allowing private participation in power projects. This was followed in 1996 by the Public Services Regulatory Agency Law, which established new institutional arrangements for the regulation of public services, including electricity. In 1997, the Electricity Law was passed, calling for the restructuring of the Instituto de Recursos Hidráulicosy Electrificación ("IRHE"), the Panamanian government agency responsible for electricity generation, transmission and distribution. IRHE was divided into three distribution companies, four generation companies and one transmission company for privatization.

        In 1998, the country's three distribution companies were privatized, and were each granted 15-year concessions. The same year, the four generation companies were privatized, with the hydropower generators receiving 50-year concessions granting the use of water, and the thermal power generators receiving 40-year licenses. The transmission company remains understate ownership.

        The dispatch of the system is the responsibility of the Centro Nacional de Despacho ("CND"), which is part of the transmission company, Ente Regulador de los Servicios Públicos ("ETESA" or the "Regulator"). There is a surcharge levied on revenues in the system to cover the administrative costs of the CND and ETESA, which helps to promote the Regulator's political independence. The regulatory framework establishes the operation of generation plants on a merit-order dispatch basis. Dispatch priority is determined based on audited variable operating costs with the last unit dispatched determining the marginal cost of the system. Hydroelectric plants are dispatched in such a way as to optimize the use of water.

        The Panamanian electric system operates with both contract and spot markets. At the time of privatization, the distribution companies were assigned Power Purchase Agreements ("PPAs") with each of the generators, sufficient to meet the generators' peak energy demand requirements. The cost of electricity with respect to spot market purchases and PPAs approved by the electric industry regulator (including initial and new contracts) are a direct pass-through to residential and industrial users. The system is designed to preserve the financial health of the distribution companies and the entire electricity sector. Distribution companies are required to contract 100% of their annual energy requirements (although they can self-generate up to 15% of their demand), reducing uncertainty for generators and consumers. Tariffs were increased in 2003 and 2004, and the government subsidized a 2005 tariff increase.

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North America

        The federal government regulates wholesale power markets and transmission facilities in most of the continental U.S., while each of the fifty states regulates retail electricity markets and distribution. Over the past decade, there have been a number of federal and state legislative and regulatory actions that have altered how energy markets are regulated. A series of regulatory policies have been adopted in the United States by both the federal government and the individual states that encourage competition in wholesale and retail electricity markets.

        The FERC has ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric energy under the Federal Power Act ("FPA") and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act. In 1996, the FERC issued Order # 888, which mandated the functional separation of generation and transmission operations and required utilities to provide open access to their transmission systems. Each utility under the FERC's jurisdiction was required to file an Open Access Transmission Tariff. In 2000, the FERC issued Order # 2000, which established the functions and characteristics of Regional Transmission Organizations ("RTOs") as a means to ensure independent administration of the open access policy and to help increase investment in transmission infrastructure. On a regional basis RTOs assume functions traditionally handled by individual utilities, such as transmission access, security, coordination and planning. RTOs have been created and currently administer the interconnected transmission system in a number of the markets in which AES owns electric generation such as California and the Midwest.

        Beginning in the fall of 2001, regulatory officials in the United States began to re-examine the nature and pace of deregulation of electricity markets. This re-examination was primarily the result of extreme price volatility and energy shortages in California and portions of the western markets during the period from May 2000 through June 2001. The conclusions reached in this re-examination have not been uniform, but rather have differed from state to state and between the federal government and the states themselves. Thus, a number of states have advocated against restructuring and abandoned any efforts to proceed with deregulation of retail markets, while the FERC has continued its efforts to enhance "open access" electric transmission and enhance competition in bulk power (wholesale) markets, albeit at a somewhat slower pace. This has led to a number of confrontations and legal proceedings between the FERC and the states over jurisdiction. The Company believes that over the next decade the United States will continue to resemble a "patchwork quilt" of differing regulatory policies at the retail level.

        The Federal government, through regulations promulgated by the FERC, has primary jurisdiction over wholesale electricity markets and transmission services. Since 1986, the FERC has approved market based rate authority for many providers of wholesale generation, and the mix of market players since then has shifted toward non-utility entities, generally referred to as Independent Power Producers ("IPPs"), whose rates are negotiated rather than based on costs. The FERC has issued a number of orders that increase the reporting requirements of entities requesting market based rate authority. In May 2006, the FERC issued a rulemaking concerning the four criteria examined in granting market based rate authority and the resulting regulations may result in a somewhat more stringent analysis for obtaining such authority. Recently utilities have begun supplying their own generation again, through affiliate contracts, acquisition of distressed assets and traditional utility construction. These assets are generally included in base rate, and the building of generation by utilities represents a move back to traditional cost of service ratemaking regulation.

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        On August 8, 2005, the President signed into law the Energy Policy Act of 2005 ("EP Act 2005"). The legislation repealed the Public Utility Holding Company Act ("PUHCA of 1935") and replaced it with the Public Utility Holding Company Act of 2005 ("PUHCA of 2005"), which became effective on February 8, 2006. The repeal of the PUHCA of 1935 removed utility holding companies from the jurisdiction of the SEC and greatly reduced the financial, organizational and line of business restrictions imposed on utility holding companies. The PUHCA of 2005 increases federal and state access to books and records, but does not restrict mergers and acquisitions of non-contiguous utilities as did the previous law.

        Under Section 203 of the FPA, as amended by EPAct 2005, the FERC has increased authority to review mergers and acquisitions, including acquisitions of foreign utility companies. However, the FERC has issued regulations that give a holding company that owns a transmitting utility or an electric utility company and has captive U.S. customers (such as AES) blanket authority to acquire a foreign utility company upon making a notice filing containing specific certifications with respect to the protection of such customers from the effects of the acquisition.

        EPAct 2005 also provides the FERC with new authority to certify an Electric Reliability Organization ("ERO") that will set mandatory reliability standards for the U.S. grid. On April 4, 2006 the National Energy Regulatory Commission ("NERC") filed an application for certification as the ERO and a petition for approval of 102 Reliability Standards. The NERC was certified as the ERO on July 20, 2006, and the FERC initiated a rulemaking to review and approve the Reliability Standards. Although NERC has not historically had authority to mandate compliance with reliability standards, utilities generally choose to voluntarily comply with the standards. The new legislation gives the ERO the ability to create mandatory standards and would grant the ERO authority to enforce these standards through the issuance of financial penalties.

        Finally, EPAct 2005 amends the PURPA and instructs the FERC to promulgate regulations to implement the amendments. Pursuant to this directive the FERC has issued a final rule that:(i) prescribes new restrictive criteria that new cogeneration facilities must meet in order to be designated as QFs under PURPA; (ii) removes the restrictions on ownership of QFs by an entity that is primarily engaged in the generation or sale of electric power; and (iii) for new QFs eliminates certain regulatory exemptions that QFs previously received. On October 20, 2006, the FERC issued a final rule that effectively removes the requirement that utilities enter into new contracts to purchase energy and capacity produced by QFs having capacity greater than 20 MW if the utilities are located within the control areas of the Midwest Independent Transmission System Operator, Inc. ("Midwest ISO"), PJM Interconnection, L.L.C., ISO New England, Inc., the New York Independent System Operators or ERCOT. Utilities located in other regions of the United States must file a request to be relieved of the purchase obligation and the FERC will decide on a case by case basis whether QFs have access to competitive wholesale markets, and therefore, no longer require a mandatory buyer. We believe that the new rule will not have a material impact on the Company's existing contracts.

        On September 21, 2006, the FERC conditionally approved the California Independent System Operator's (CAISO) tariff filing to reflect Market Redesign and Technology Upgrade (MRTU). The new market design is scheduled to go into effect on November 1, 2007 and will include location based marginal pricing and a financially binding day-ahead energy market. The Company believes that the MRTU will not have a material impact on its existing facilities due to long-term contracts that remain in place. 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. See "Legal Proceedings."

        In addition to the FERC regulation described above, IPL is subject to regulation by the Indiana Utility Regulatory Commission ("IURC") as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of

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depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of public utility properties or securities and certain other matters.

        IPL's tariff rates for electric service to retail customers (basic rates and charges) are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve IPL, the staff of the IURC, the Indiana Office of Utility Consumer Counselor and other interested consumer groups and customers. Pursuant to statute the IURC is to conduct a periodic review of the basic rates and charges of all utilities at least once every four years.

        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 consumed from estimated fuel costs embedded in basic rates, subject to certain restrictions on the level of operating income. In addition IPL's rate authority provides for are turn on IPL's investment and recovery of the depreciation and operation and maintenance expenses associated with then itrogen oxide ("NOx") compliance construction program and its multipollutant plan.

        IPL participates in the restructured wholesale energy market operated by the Midwest ISO. The implementation of this restructured market marks a significant change in the way IPL buys and sells electricity and schedules generation. Prior to the restructured market, IPL dispatched its generation and purchased power resources directly to meet its demands. In the restructured market IPL offers its generation and bids its demand into the market on an hourly basis. The Midwest ISO settles these hourly offers and bids based on location based marginal prices or LMPs, 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 Midwest ISO region. The Midwest ISO evaluates the market participants' energy injections into, and withdrawals from, the system to economically dispatch the entire Midwest ISO 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, or "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, LMPs are volatile, and there are process, data, and model issues requiring editing and enhancement. IPL and other market participants have raised concerns with certain Midwest ISO transactions and the resolution of these items could impact our results of operations.

Europe & Africa

        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 of the EU as of January 2007 and will, upon accession to the EU, be subject to EU legislation.

        The principles of market liberalization in the EU electricity and gas markets were introduced under the Electricity and Gas Directives (Directive 1996/92/EC and Directive 1998/30/EC, respectively). 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 problems related to price formation in the electricity wholesale markets and the role of long-term agreements as a possible barrier to entry

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with a view to improving the competitive situation. The Hungarian Competition Authority launched a parallel inquiry into the national electricity and gas market and announced its preliminary findings in late 2005. These preliminary findings identified long-term contracts as a potential source of competition concern, in addition to other obstacles, such as having a single power buyer, the Hungarian Power Companies LTD (MVM). The EC has commenced a formal investigation into long-term power purchase contracts in Hungary, including the long-term power purchase contract entered into between AES Tisza Eromu Kft ("AESTisza") and the state owned electricity wholesaler, MVM. See "Hungary" below, for details of this investigation. In addition, the EC has launched an independent investigation into alleged abusive practices on the part of MVM.

        The EC has also introduced environmental legislation which impacts the electricity sector in general and includes:

        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.

        In 2004, in connection with the accession of Hungary as a member state of the EU, the Hungarian government provided notification to the EC of certain legislative arrangements concerning compensation to the state owned electricity wholesaler, MVM. The EC conducted a preliminary investigation to determine whether or not any alleged government aid was provided through MVM to its suppliers which was incompatible with the common market. The EC decided to open a formal investigation in 2005. AES Tisza is not a named party to the investigation, but could be adversely affected in the event that the EC concludes that AES Tisza is one of the beneficiaries of unlawful state aid by virtue of its power purchase arrangements with MVM. As an interested party, AES Tisza has made submissions to the EC in relation to the investigation. If the EC reaches a formal conclusion that the long-term power purchase arrangements are contrary to applicable EU law, it can require the Hungarian authorities to recover any aid involved. It is for the Hungarian authorities to execute the EC's decision in accordance with national law. The authorities may then seek to revise the contracts and/or require the repayment of certain funds received by generators pursuant to the contracts. It is not currently known whether the underlying contracts, including the contract with AES Tisza, will be revised or terminated or what reimbursement and/or compensation will be payable in connection with their revision or termination. Although the EC has not yet completed its formal investigation or

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published its conclusions, the Commissioner for Competition has indicated informally that she considers the long-term power purchase arrangements to be contrary to applicable EU law and has encouraged the Hungarian government to terminate the long-term power purchase arrangements.

        In early 2006, the Hungarian government enacted legislation to amend the Hungarian Electricity Act (Act 110 of 2001) to enable, among other things, the application of administrative pricing to the sale of electricity by generators to the state owned utility wholesaler, MVM. Implementing legislation was subsequently issued in November 2006 re-introducing administrative pricing which purports to impose a regulated price on the sale of electricity by generators, including AES Tisza, to the public utility sector. The regulated price is lower than that specified in the existing long-term power purchase agreement between AES Tisza and MVM. AES Tisza is in the process of assessing the implications of this legislation, including the impact on its current power purchase and financing arrangements and the ability of AES Tisza to challenge the re-introduction of administrative pricing by the Hungarian government.

        The Government of Kazakhstan has implemented a series of regulatory normative acts to encourage competition in wholesale and retail electricity markets.

        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 Committee for protection of competition of the Ministry of Industry and Commerce (the "Committee") and the Agency for regulation of the natural monopolies (the "Agency"). Each has the necessary authority for the supervision of the Kazakhstan power industry. However, because of certain contradictions between different regulations and the absence of a clear demarcation between rights and responsibilities of the Ministry, the Committee and the Agency, there is some uncertainty in the regulatory environment of the power sector.

        The Ministry's main function is to supervise the appropriate implementation of the Electricity Law (Law of Kazakhstan "On Power Industry" No. 588-II dated July 9, 2004) and other rules and regulations in the power sector, ensure the efficiency of the wholesale and retail power markets and ensure reliability of power supply through technical monitoring and licensing requirements.

        The Committee's authority arises under the Competition Law (Law of Kazakhstan "On competition and monopoly activity restriction" No. 173-III dated July 7, 2006), which authorized the antimonopoly body to issue approval in connection with large mergers and acquisitions, to monitor markets for monopolistic activity and competition protection and to control tariffs of dominant entities in different sectors of economy including wholesale and retail electricity markets.

        The Agency's main function, as is defined in the Natural Monopoly Law (Law of Kazakhstan "On natural monopolies" No. 272-I dated July 9, 1998), is to approve and regulate the tariffs of the "natural monopolists"(including heat generation, power transmission and distribution), to supervise the activity of the natural monopolists with respect to their investment policy and quality of services and provide customer protection.

        Kazakhstan has a wholesale power market, where generators and customers are free to sign contracts at negotiated prices. Power generating entities and retail supply companies are required to participate in the centralized power trade with some minimum required volumes set by the Ministry (up to 30% for generation companies and up to 50% for retail supply companies). 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.

        Starting in 2004, Kazakhstan introduced a retail market, as a result of which distribution companies had to transfer retail power supply functions to newly created retail companies. During a

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transition period retail prices are controlled by the Committee, though the government program resumes introduction of competitive retail pricing in the near future.

        Two hydro plants which are under AES concession, Kazakhstan's Ust-Kamenogorsk Hydro Plant ("UKHydro") and Kazakhstan's Shulbinsk Hydro Plant ("Shulbinsk Hydro"), together with AES Kazakhstan Ust-Kamenogorsk TET ("UKT"), 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. Nurenergo service LLP and Dostyk Energo LLP are two AES trading companies that participate in the Kazakhstan power markets, both of which may face regulation by the Committee relating to resale of power to customers located in Eastern Kazakhstan.

        In February 2007, the Committee initiated administrative proceedings against UK Hydro, and Shulbinsk Hydro and subsequently UKT and Nurenergo service LLP for alleged violation of Kazakhstan's antimonopoly laws. "Legal Proceedings."

        In 1995, Ukraine began restructuring the electrical energy sector from a single vertically integrated system operated by the Ministry of Energy and Electrification to a more regionalized system. In the revised system generation, local distribution and high voltage transmission were removed from the vertically integrated system. Local distribution and supply services were placed into 27 regionally defined operating companies. The Ministry of Energy and Electrification remained as a policy agency and also controlled shares (assets) of state joint stock companies. The President of Ukraine also created the NERC, which was to ensure the effective functioning of the electric energy sector and the formation of an electric energy market.

        Since 1996, the Ukrainian energy market has operated in a wholesale energy market model, under which AES Ukraine procures electricity from the WEM at the hourly spot process. One of the pre-conditions for privatization of the distribution companies in 2001 set forth by the government was repayment to the WEM of the historical debt of companies to be privatized by the investor over 5 years following privatization. In July 2005, the government issued a special resolution by which government debts to the population resulting from the default of Soviet banks could be offset against populations' debts for purchased electricity by means of so called "checks". This resolution allowed AES Ukraine to offset part of doubtful residential customers' receivables against its payables to the wholesale electric market for purchased power. In April 2006, a new Cabinet of Ministers resolution was issued to amend the "checks" scheme allowing AES Ukraine to offset the last portion of the restructured debt to wholesale market with "checks" that were collected from customers as payment of their electricity bills. Thus, AES Ukraine paid the last portion of the restructured debt using this offset mechanism rather than cash. In 2006, AES Ukraine successfully repaid there structured debt owed to the WEM by both of its businesses and became the first entity to be free of debt to the WEM in the country.

        Due to Parliamentary elections in 2006, significant staff changes took place in the key regulatory agencies. In particular, new Minister of Energy and NERC Chairman were appointed. NERC twice authorized 25% increases in end user tariffs for residential customers in 2006. A further increase to reach the actual cost of service for residential customers is expected in 2007.

        In October 2006, NERC proposed a new methodology for calculating wages and salaries which could result in an increase of about 25% in the tariff allowance for wages and salaries NERC also initiated the idea of introducing social tariffs for residential customers whose consumption is at or below 125 kWh/month and inclining block tariffs for residential customers are scheduled for implementation in April 2007. These social tariffs are designed to improve affordability for low-use

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customers. In combination with the inclining block tariff, the mechanisms should create an incentive for customers to manage their consumption. In all, the hope is that these measures reduce default rates and improve overall collection rates. However, it still remains to be determined how the system will work in practice.

        During 2006, the wholesale electricity market price increased approximately 17% due to increases in fuel prices and changes in the pricing arrangements for thermal generating companies.

        Regulations addressing various aspects of AES Ukraine activity that have been amended and/or drafted in the course of 2006 include: (i) electricity usage codes for legal and residential customers; (ii) connection to network fee methodology;(iii) methodology for calculation of the value of illegally consumed electivity; and (iv) tender procedure to be applied by distribution and supply companies.

        The Company expects that the tariff methodology applied for calculation of AES Ukraine tariffs is going to evolve in 2007 according to methodology provisions approved in 2001, as a result of which: (i) rate of return on new investment will decrease from 17% after tax to about 14% and (ii) technical and commercial loss allowances will decrease. In 2008, it is expected that (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" of operational expenses fixed in 2003 and inflated since then on an annual basis will be revised as well. The regulatory treatment of operational expenses in the tariff after 2008 is unclear at this point.

        AES Kilroot in Northern Ireland is subject to the regime established by the Large Combustion Plants Directive ("LCPD") and will therefore be required to comply with the increased restrictions on emissions imposed under that regime. It is also required to obtain a permit under the IPPC Directive to enable it to continue to operate. AES Kilroot will be implementing modifications to ensure that the plant complies with the requirements of the LCPD and the IPPC Directive.

        AES Kilroot is subject to regulation by the Northern Ireland Authority for Energy Regulation ("NIAER"). Under the terms of the generating license granted to AES Kilroot, the NIAER has the right to review and, subject to compliance with certain procedural steps and conditions, require the early termination of the long-term power purchase agreements under which AES Kilroot currently supplies electricity to Northern Ireland Electricity ("NIE") until 2010.

        On March 21, 2007, Order 2007 (Single Wholesale Market—Northern Ireland) was enacted, which provides for the introduction and regulation of a single wholesale electricity market for Northern Ireland and the Republic of Ireland. 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. AES Kilroot is assessing the potential impact of this new legislation.

        Following receipt of a complaint from Friends of the Earth claiming that the existing long-term power purchase agreements 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 AES Kilroot power plant and power purchase agreement in order to enable the EC to assess the complaint. DETI submitted a response to the EC on January 12, 2007. It is not possible at this stage to predict the outcome of this inquiry.

        The law governing the Cameroonian electricity sector was passed and promulgated in December 1998, which defines the new institutional organization of the electricity sector (Law

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no. 98/022 of 24 December 1998 governing the electricity sector). This law, and subsequent ministerial decrees and orders, govern the activities of the electricity sector, set the rates and basis for the calculation, recovery and distribution of royalties due by operators in the electricity sector, and spell out required documents and charges for the processing of applications relating to concession, license, authorization and declaration in order to carry out generation, transmission, distribution, importation, exportation and sales of electricity.

        The mission of the Electricity Sector Regulatory Board ("ARSEL") is to regulate and ensure the proper functioning of the electricity sector, maintain its economic and financial balance and safeguard 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 18, 2001 between the Republic of Cameroon and AES SONEL covers a twenty-year (20) period of which the first three years constituted a grace period to permit resolution of issues existing at the time of the privatization, and all penalties were waived. In 2004, AES SONEL and the Cameroonian government started renegotiating the concession contract. The issues included in this renegotiation process were: the quality of services requirements, the connection targets, the tariff formulation, the obligation of developing new generation capacity and the penalties regime. AES SONEL completed the renegotiation process and executed a new concession agreement on December 4, 2006.

Asia

        In 2002, the State Council of the Chinese government promulgated the National Power Industry Framework Reform Plan (the "Reform Plan"). The Reform Plan separates generation and transmission and introduces market-driven competition into China's electric power industry whereby generators will be required to compete in the market for their output, with a system of competitive bidding for on-grid tariffs.

        As a result of the Reform Plan, a new industry regulator, China's National Electricity Regulatory Commission ("China's NERC") was established. China's NERC's responsibilities include: promulgating operating rules for the electric power industry; supervising the operation of the electric power industry and safeguarding fair competition; monitoring the quality and standard of production by electric power enterprises; and issuing and administrating electric power service licenses.

        The ultimate adoption of the Reform Plan may result in market and regulatory changes.

        In April 2005, with a view to implementing the power industry reform, the National Development and Reform Commission released an interim regulation governing on-grid tariffs, along with two other regulations governing transmission and retail tariffs. All three came into effect on May 1, 2005 ("Interim Regulations"). Pursuant to the Interim Regulations, prior to adoption of a pooling system, the on-grid tariffs shall be appraised and ratified by the pricing authorities by reference to the economic life of power generation projects and determined in accordance with the principle of allowing independent power producers to cover reasonable costs and to obtain reasonable returns. However, the Interim Regulations further defined that the generation costs shall be the average costs in the industry, and reasonable returns shall be formulated on the basis of the interest rate of China's long-term treasury bond plus certain percentage points. The Interim Regulations will have far reaching consequences; but 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, except that it appears over the longer term, there will be increasing pressure on foreign-investors to renegotiate their PPAs.

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        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 to 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.

        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, distribution and transmission, while intra-state generation, distribution and transmission are regulated by SERCs. The Government of India assists states in arranging financing for restructuring of state utilities for financial turnaround and facilitates investment in power sector.

        In 2003, the Government of India enacted the Electricity Act 2003 ("New Act") 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 early 2004, the Government of India issued Guidelines for Determination of Tariff by Bidding Process for Procurement of Power by Distribution Licensees. In February 2005, the Government of India came out with the National Electricity Policy and in January 2006 published the National Tariff Policy (together "Policy"). CERC issued terms of conditions for tariff determination for inter-state generation and transmission and also notified open access for transmission.

        The Policy establishes deadlines to implement different provisions of the New 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.

        It is not clear whether existing and concluded power purchase agreements are subject to re-opening by regulatory bodies under the New Act and the Policy. If re-opened, the review could have an adverse impact on OPGC, the Company's generation facility in India. The Electricity Appellate Tribunal is operational for dispute resolution as per New Act. A decision of Appellate Tribunal can be challenged only in the Supreme Court of India.

Alternative Energy

        Under our plans for developing our Alternative Energy business, which includes wind generation, LNG re-gasification terminals, greenhouse gas emission credits and other initiatives, those businesses are, and would be, subject to complex laws and regulations and affected by changes in laws and regulations as well as changing governmental policies and regulatory actions. Many of AES' Alternative Energy planned businesses may be significantly impacted by federal, state, and international incentives and other promotional policies relating to renewable and emerging energy technologies, carbon emissions and environmental issues. These incentives and policies are implemented and administered by a wide variety of governmental bodies that operate at the local, state, national and transnational levels. Notably, our current operating wind energy business could be adversely impacted by any significant changes or failure by the U.S. Congress to extend the production tax credit incentive in section 45 of title 26 of the United States Code (currently set to expire on December 31, 2008). AES' Alternative Energy business may also be significantly impacted by laws and regulations relating to the relationships between independent or competitive providers and utilities, competitive wholesalers, and competitive retailers in markets where it operates. Laws and regulations governing these relationships are implemented and administered by a wide variety of governmental bodies that operate at the state, national and transnational levels. These multiple and often interacting factors could have a negative impact on the business and results of operations of AES' Alternative Energy business.

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Environmental and Land Use Regulations

        The Company is subject to various international, national, state and local environmental and land use laws and regulations. These laws and regulations primarily relate to discharges into the air and air quality, discharge of effluents into water and the use of water, waste disposal, remediation, noise pollution, contamination at current or former facilities or waste disposal sites, wetlands preservation and endangered species. Each of the countries in which the Company does business also has 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. AES 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 power 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 Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity for more detail. If these regulations change, the Company may be required to make significant capital or other expenditures to comply. There can be no assurance that the Company would be able to recover from our customers these compliance costs such that our business, financial conditions or results of operations would not be materially and 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 or interruptions 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 impact on our operations or results and we have expeditiously corrected the non-compliance as required.

        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 Environmental Protection Agency's ("EPA") rulemaking requiring adjustments to state implementation plans relating to NOx emissions (the "NOx SIP Call") required coal-fired electric generating facilities in 21 U.S. states and the District of Columbia 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. We have completed installing selective catalytic reduction ("SCR") and other NOx control technologies at three coal-fired units of our subsidiary, IPL in response to NOx SIP Call implementation and other proposed air emissions regulations that are discussed in more detail below.

        In March 2005, the EPA finalized two rules that will affect many of our U.S. coal-fired power generating plants. The first rule, the "Clean Air Interstate Rule" ("CAIR"), was promulgated on March 10, 2005 and requires 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 pollutants emissions begins in 2015. The second rule, the Clean Air Mercury Rule ("CAMR"), was promulgated on March 15, 2005 and requires reductions of mercury emissions from coal-fired power plants in two phases. The first phase will begin in 2010 and will require nationwide reduction of coal-fired power plant mercury emissions from 48 to 38 tons per year. The second phase will begin in 2018 and will require nationwide reduction of mercury emissions from these sources from 38 tons per year to 15 tons per year. CAMR also establishes

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stringent mercury emission performance standards for new coal-fired power plants. To implement the required emission reductions for these two new rules, the states will establish emission allowance-based "cap-and-trade" programs.

        Both the CAIR and CAMR have been challenged in federal court. No decisions have been rendered on the challenges. Also, a number of the 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, AES completed a multi-pollutant control project at its Greenidge power plant in New York state and initiated construction of a similar project at its Westover power plant in New York state. In addition, a flue gas desulphurization scrubber upgrade project was completed at the IPL Petersburg power plant, and construction of an SCR system was initiated at our Deepwater petroleum coke-fired power plant near Houston, Texas.

        While the exact impact and cost of these two new rules cannot be established until the states complete the process of assigning emission allowances to our affected facilities, 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.

        The New York State Department of Environmental Conservation ("NYSDEC") recently promulgated regulations requiring electric generators to reduce SO2 emissions by 50% below current U.S. Clean Air Act standards. The SO2 regulations began to be phased in beginning on January 1, 2005 with implementation to be 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 EPA published the "Regional Haze Rule" to reduce haze and protect visibility in designated federal areas. On June 15, 2005, 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 proposed amendment to the Regional Haze Rule would require 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. States are required to submit to the EPA their regional haze state implementation plans by December 2007. States that adopt the CAIR cap and trade program for SO2 and NOx are allowed to apply CAIR controls as a substitute for BART controls.

        Currently in the United States there are no federal mandatory greenhouse gas emission reduction programs (including carbon dioxide ("CO2")) affecting the Company's electricity power generation facilities. The U.S. Congress has debated a number of proposed greenhouse gas legislative initiatives, but to date there have been no new federal laws in this area. Nine states have entered into a memorandum of understanding under which the states would coordinate to establish rules that require the reduction in CO2 emissions from power plant operations with those states. This initiative is called the Regional Greenhouse Gas Initiative ("RGGI"). On August 15, 2006, seven northeastern U.S. states issued a finalized model rule to implement RGGI. When it goes into effect, the RGGI initiative 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. 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 reduce CO2 and other greenhouse gas emissions to 1990 levels by 2020. On October 24, 2007, New York State released its proposed rule to implement its state program as part of RGGI. Under the proposed New York State rule, our subsidiaries that are subject to RGGI in New York would need to secure CO2 allowance requirements directly from a planned auction or in the secondary CO2 emissions trading market. Because the proposed rule and the auction protocol remain subject to change and are

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not yet final, we cannot predict the impact of any final RGGI regulation on our financial statements or operations. We will review the impact of any final rule on our financial statements or operations, whether from New York or any other state participating in RGGI. Although specific implementation measures for RGGI and A.B. 32 have yet to be finalized, these greenhouse gas-related initiatives may potentially affect AES electric power generation facilities in California, New York, Connecticut and New Jersey. At present, the Company cannot predict whether compliance with potential future U.S. national, regional and state greenhouse gas emission reduction programs will have a material impact on our operations or results.

        In Europe the Company is, and will continue to be, required to reduce air emissions from our facilities to comply with applicable European Community ("EC") Directives, including Directive 2001/80/EC on the limitation of emissions of certain pollutants into the air from 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 opt-in, like the Company's AES Kilroot facility in the United Kingdom, must invest in abatement technology to achieve specific SO2 reductions. Generally, AES's other coal plants in Europe have opted-in but will not require any additional abatement technology to comply with the LCPD.

        In July 2003, the EC "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, there remain significant uncertainties regarding the application of the European Union Emissions Trading System which commenced operation in January 2005. Based on its current analyses, the Company expects that certain AES businesses will be under-allocated and others will be over-allocated. Although: i) we have a limited number of operating facilities that fall under EU ETS control, ii) a couple of these have very low baseline emissions because they are either biomass only or co-fire biomass, and iii) the risk and benefit at others are not the responsibility of AES as they are subject to change of law provisions that transfer responsibility for environmental compliance with these regulations to our off takers, the fact remains that the Company cannot predict whether compliance with the respective NAPs will have a material impact on our operations or results.

        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 countries that have ratified it to substantially reduce their greenhouse gas emissions including CO2. AES presently has generation operations in five countries that have ratified the Kyoto Protocol. Over the course of the next several years, as decisions surrounding implementation of the Kyoto Protocol become more detailed, the Company will have a better understanding of the impact of the Kyoto Protocol on itself. In the interim we announced on September 21, 2006, that we will produce 10 million tons of CO2 equivalent greenhouse gas offsets by 2012 in Asia, Africa, Europe and Latin America by developing and operating projects under the Clean Development Mechanism of the Kyoto Protocol. At present the Company cannot predict whether compliance with the Kyoto Protocol will have a material impact on its operations or results.

        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 2004 (69 Fed.

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Reg. 41579, July 9, 2004). The rule as currently issued will affect 12 U.S. AES power plants, the rule's requirements will 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 and may begin as early as 2008 for some of our U.S. plants. However, as a result of a recent United States Court of Appeals for the Second Circuit decision (Docket Nos. 04-6692 to 04-6699) remanding major parts of the 2004 rule back to U.S. EPA, we expect further delays in implementing the rule at many of our affected facilities. At present, the Company cannot predict whether compliance with the 316(b) rule will have a material impact on our operations or results.

        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, scrapmetal, 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.

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. It is reasonably possible, however, 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 the date of this prospectus.

        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$771 million (US$420 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 of 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,

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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. In June 2007, Eletropaulo's appeal to the Special Court was dismissed by the reporting judge. In November 2007, the Special Court rejected Eletropaulo's appeal of that dismissal. Eletropaulo has appealed that dismissal. 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. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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

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

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Placerita believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

        In August 2001, the Grid Corporation of Orissa, India ("Gridco"), filed a petition against the Central Electricity Supply Company of Orissa Ltd. ("CESCO"), an affiliate of the Company, with the Orissa Electricity Regulatory Commission ("OERC"), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC's August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO's distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to, and approved by, the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company's indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO's financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited ("AES ODPL"), and Jyoti Structures ("Jyoti") pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the "CESCO arbitration"). In the arbitration, Gridco appears to seek approximately $188.5 million in damages plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company has 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. Proceedings remain pending before the Indian Supreme Court regarding the presiding arbitrator's fees and the venue of future hearings, if any. 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 December 2001, a petition was filed by Gridco in the local Indian courts seeking an injunction to prohibit the Company and its subsidiaries from selling their shares in Orissa Power Generation Company Pvt. Ltd. ("OPGC"), an affiliate of the Company, pending the outcome of the above-mentioned CESCO arbitration. OPGC, located in Orissa, is a 420 MW coal-based electricity generation business from which Gridco is the sole off-taker of electricity. Gridco obtained a temporary injunction, but the District Court eventually dismissed Gridco's petition for an injunction in March 2002. Gridco appealed to the Orissa High Court, which in January 2005 allowed the appeal and granted the injunction. In December 2007, the Supreme Court of India lifted the injunction because the arbitral award in the CESCO arbitration had dismissed all of Gridco's claims against the Company and the other respondents. The Company 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 early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC's existing power purchase agreement ("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.

        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. Oral arguments on the appeal were heard November 30, 2007. The parties are awaiting the Seventh Circuit's decision.

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

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        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 AES 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 AES 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. AES 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 (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, AES Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in AES 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 solepossession of Horto Renner since September 2006 and of the rest of the Property since April 2006. The measures that must be taken by AES 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

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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 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. The Court subsequently ordered Red Oak to pay Raytheon approximately $16.3 million plus interest, which sum allegedly represented the amount of the letter of credit draw that had yet to be utilized for performance/construction issues. The Court also dismissed Red Oak's fraud claims, which decision was upheld on appeal. The parties have stipulated that Red Oak may assert claims for performance/construction issues if it has incurred costs on such claims. In September 2007, the parties filed a stipulation for the dismissal with prejudice of Raytheon's claim for $110 million in purported cost overruns and AES Red Oak's purported claims for consequential damages. The Court has not entered the stipulation to date. 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 complaint. Red

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Oak 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 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 will hear arguments on the petitions on January 25, 2008. 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 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 October 2006, CDEEE began making public statements that it intends to seek to compel the renegotiation and/or rescission of long-term power purchase agreements with certain power-generation 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 companies in the country (AES Andres, Itabo, and Dominican Power Partners) that could be adversely impacted by any actions taken by or at the direction of CDEEE.

        In January 2007, Eletropaulo Metropolitana Electricidad de São Paulo S.A. ("Eletropaulo") received notice from the municipal environmental agency of a penalty of approximately US$100,000. The penalty related to an Eletropaulo contractor attempting to dispose of tree trimming waste in a coal dump without a permit. The contractor has recognized responsibility in this case and has been negotiating the penalty. The current expectation is that the amount of the penalty will be reduced to approximately US$16,000.

        In February 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan initiated administrative proceedings against two hydro plants under AES

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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. In September 2007, the headquarters of the Competition Committee upheld the order. In October 2007, the Hydros appealed to the economic court of first instance. The Competition Committee subsequently asserted a counterclaim to enforce its order. In November 2007, the economic court upheld the Competition Committee's order requiring the Hydros to pay 2.6 billion KZT (US$22 million). The Hydros intend to appeal that decision. 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 Court of Appeals (first panel) has upheld the injunction. In separate but related proceedings, in September 2007, the Competition Committee ordered the Hydros to pay approximately 22.2 million KZT (US$200,000) in administrative fines for their alleged antimonopoly violations. In October 2007, the Hydros appealed the fines to the administrative court of first instance. The administrative court subsequently 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 indicated that it intends to investigate whether the Hydros have 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. If the Hydros do not prevail in the economic court and any proceedings in the court of appeals (first panel) with respect to the alleged damages, they will have to pay the alleged damages or risk seizure of their assets. Furthermore, if the Hydros do not prevail in the administrative court with respect to the fines, they will have to pay the fines or risk seizure of their assets.

        In June 2007, the Competition Committee ordered AES Ust-Kamengorskaya 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 consumers that have allegedly paid unreasonably high power prices since January 2007. In August 2007, the headquarters of the Competition Committee upheld the order. UKT subsequently appealed to the economic court of first instance. The Competition Committee subsequently asserted a counterclaim to enforce its order. In November 2007, the economic court 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 consumers, UKT intends to appeal the economic court's decision. In addition, the economic court has 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. UKT intends to appeal the injunction. Furthermore, in separate but related proceedings, in July 2007, the Competition Committee ordered UKT to pay approximately 88 million KZT (US$700,000) in administrative fines as estimated by UKT, for its alleged antimonopoly violations. UKT subsequently appealed the fines to the administrative court of first instance. The administrative court has not indicated when it intends to decide the case. 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. If UKT 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 UKT 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 July 2007 the Competition Committee ordered Nurenergoservice to pay approximately 17.8 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. In

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October 2007, Nurenergoservice appealed the order to the economic court of first instance. The Competition Committee subsequently asserted a counterclaim to enforce its order. The economic court has not yet decided on the merit but has issued an injunction to secure Nurenergoservice's alleged liability freezing Nurenergoservice's bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. 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 1.8 billion (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-Kamengorsk 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. Sogrinsk intends to appeal the merits of the order to the economic court of first instance. Sogrinsk's procedural challenges to the order have been unsuccessful in the economic court and the court of appeals (first panel). 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 has stated that it intends to investigate whether Irtysh Power and Light, LLP, an AES company which manages the state-owned Ust-Kamenogorsk Heat Nets system, has violated Kazakhstan's antimonopoly laws in January through November 2007. Irtysh believes it has meritorious claims and defenses and will assert them vigorously in any formal proceeding; however, there can be no assurances that it will be successful in its efforts.

        In 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 June 2007, IPL received a letter from an attorney purportedly representing a group of IPL employees and retirees (the "complainants"). The letter claims that IPL is recovering in rates on average approximately $19 million per year allegedly intended for the funding of the IPALCO Voluntary Employees' Beneficiary Association Trust ("VEBA Trust"), which provides healthcare and life insurance benefits for certain IPL retirees. IPL made contributions to the VEBA Trust through 2000, when the VEBA Trust was spun off to independent trustees by IPALCO. The spin off of the VEBA Trust was publicly disclosed by IPALCO in the Agreement and Plan of Share Exchange at the time of IPALCO's acquisition by AES. The letter asserts that IPL remains responsible for funding the VEBA Trust and requests that IPL back-fund the trust at the $19 million per year level and fund at the same level going forward. The letter further states that the complainants may file a complaint at the

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Indiana Utility Regulatory Commission ("IURC") if IPL does not fund the VEBA Trust as demanded. In November 2007, the complainants filed a complaint with the IURC regarding this VEBA Trust issue. The complaint seeks enforcement of the VEBA Trust-related portion of the 1995 final order and associated settlement agreement of IPL's base rate case, Cause No. 39938. The complaint requests that the IURC: (1) investigate IPL's alleged failure to fund the VEBA Trust; (2) order IPL to place the VEBA Trust in the financial position in which it would have been had IPL not ceased making annual contributions; and (3) order IPL to resume making annual contributions to the VEBA Trust. 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 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 Project. In October 2007, the Contractor denied AESEC's claims and asserted counterclaims to recover approximately €12.3 million (US$18 million) for, inter alia, alleged unpaid milestone and scope change order payments, and an unspecified amount for an alleged early completion bonus. 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 September 2007, the New York Attorney General issued a subpoena to the Company seeking documents and information concerning the Company's analysis and public disclosure of the potential impacts that greenhouse gas legislation and climate change from greenhouse gas 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$5.2 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.

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DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

        The Securities and Exchange Commission's Rule 10b5-1 permits directors, officers and other key personnel to establish purchase and sale programs. The rule permits such persons to adopt written plans at a time before becoming aware of material nonpublic information and to sell shares according to a plan on a regular basis (for example, weekly or monthly), regardless of any subsequent nonpublic information they receive. Rule 10b5-1 plans allow systematic, pre-planned sales that take place over an extended period and should have a less disruptive influence on the price of our stock. Plans of this type inform the marketplace about the nature of the trading activities of our directors and officers. We recognize that our directors and officers may have reasons totally unrelated to their assessment of the Company or its prospects in determining to effect transaction in our common stock. Such reasons might include, for example tax and estate planning, the purchase of a home, the payment of college tuition, the establishment of a trust, the balancing of assets, or other personal reasons.

        Mr. Paul Hanrahan, Mr. Robert Hemphill, Mrs. Flora Jaisinghani, Mr. Haresh Jaisinghani, Mr. Jay Kloosterboer, Mr. William Luraschi and Mr. Brian Miller adopted trading plans pursuant to Rule 10b5-1. Mr. Hanrahan, Mr. Luraschi and Mr. Miller terminated their plan during the first quarter of 2007.

Executive Officers of the Registrant

        The following individuals are our executive officers:

        Paul Hanrahan, 49 years old, has been our President and Chief Executive Officer since 2002. Prior to assuming his current position, Mr. Hanrahan was our Chief Operating Officer and Executive Vice President. In this role, he was responsible for business development activities and the operation of multiple electric utilities and generation facilities in Europe, Asia and Latin America. Mr. Hanrahan was previously the President and CEO of the AES China Generating Company, Ltd., a public company formerly listed on NASDAQ. Mr. Hanrahan also has managed other AES businesses in the United States, Europe and Asia. 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, 52 years old, became an Executive Vice President of the Company in 2006 and the Regional President of North America in 2005. Prior to joining us in 2004, Mr. Gee was Vice President of Strategic Planning for PG&E in San Francisco, California from 2000 until 2004. 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, 49 years old, has been an Executive Vice President and Chief Operating Officer of the Company since March 2007. Prior to becoming the Chief Operating Officer, Mr. Gluski was Executive Vice President and the Regional President of Latin America since 2005, and will continue as Regional President until a new Regional President is named. Mr. Gluski was Senior Vice President for the Caribbean and Central America from 2003 to 2005, was Group Manager and CEO of Electricidad de Caracas ("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 us 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.

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        Victoria D. Harker, 42 years old, has been an Executive Vice President and our Chief Financial Officer since January 2006. Prior to joining us, Ms. Harker held the positions of Acting Chief Financial Officer, Senior Vice President and Treasurer of MCI from November 2002 through January 2006. Prior to that, Ms. Harker served as Chief Financial Officer 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 her Bachelor of Arts degree in English and Economics from the University of Virginia and a Master's in Business Administration, Finance from American University.

        Robert F. Hemphill, Jr., 63 years old, has been an Executive Vice President of the Company since rejoining us in February 2004. Mr. Hemphill served as our Director from June 1996 to February 2004 and was an Executive Vice President from 1982 to June 1996. Prior to this, Mr. Hemphill held various leadership positions since joining us in 1982. Mr. Hemphill also serves on the Boards of Reactive Nanotechnologies, Inc., Trophogen Inc. and the Electric Drive Transportation Association. 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 Master's in Business Administration, Finance from George Washington University.

        Jay L. Kloosterboer, 46 years old, is our Executive Vice President of Business Excellence. Mr. Kloosterboer joined us in 2003 as Vice President and Chief Human Resource Officer. Prior to joining us, Mr. Kloosterboer held the positions of Vice President- Human Resources and Communications, Automation and Control Solutions; Vice President—Human Resources, Home & Building Control; Vice President- Human Resources, Aerospace Services; Vice President—Human Resources & Communications, Automotive Products Group and Director-Human Resources, Automotive Aftermarket of Honeywell International from 1996 to 2003. Mr. Kloosterboer also held management positions at General Electric and Morgan Stanley. He received his Bachelor of Arts degree from Marquette University and holds a Master of Arts degree from the New Mexico State University.

        William R. Luraschi, 43 years old, is our Executive Vice President of Business Development and President of the Alternative Energy Business. Mr. Luraschi joined us in 1993 and has been an Executive Vice President since July 2003. He was our General Counsel from January 1994 until May 2005. Mr. Luraschi also served as Corporate Secretary from February 1996 until June 2002. Prior to joining us, 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.

        Brian A. Miller, 41 years old, is our Executive Vice President, General Counsel and Corporate Secretary. Mr. Miller joined us 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 us, he was an attorney with the law firm Chadbourne & Parke, LLP. Mr. Miller received his 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, 44 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 us in 1993. He holds a Master's in Business Administration from the University of Greenwich Business School in London.

        Mark E. Woodruff, 49 years old, is an Executive Vice President of the Company and the Regional President of Asia. Prior to his most recent position, Mr. Woodruff was Vice President of North

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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 us is 1992. Prior to joining us 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.

Board of Directors

        Our Board of Directors includes the following individuals:

        Richard Darman, age 65, has been a Director of AES since July 2002. He served as Vice Chairman from December 2002 until May 2003, and was elected Chairman of the Board on May 1, 2003. In addition to his service as Chairman, Mr. Darman serves as Lead Independent Director of the Board. He is a Partner and Managing Director of The Carlyle Group ("Carlyle"), one of the world's largest private equity firms. He joined Carlyle in February 1993, after serving in the cabinet of the first Bush administration as Director of the U.S. Office of Management and Budget (from 1989 to 1993). Prior to joining the Bush cabinet, he was a Managing Director of Shearson Lehman Brothers, Deputy Secretary of the U.S. Treasury, and Assistant to the President of the United States. He graduated with honors from Harvard College in 1964 and from the Harvard Graduate School of Business Administration in 1967. He is a Trustee of the publicly traded IXIS Funds and Loomis Sayles Funds, Trustee of the Howard Hughes Medical Institute, and is Chairman of the Board of the Smithsonian National Museum of American History. Mr. Darman chairs the Finance and Investment Committee of the Board. Mr. Darman also serves as an ex-officio member of each other committee of the Board.

        Paul Hanrahan, age 50, has been a Director of AES since June 2002. At that time he was also appointed President and Chief Executive Officer. Prior to assuming his current position, Mr. Hanrahan was the Chief Operating Officer and Executive Vice President of AES where he was responsible for business development activities and the operation of multiple electric utilities and generation facilities in Europe, Asia and Latin America. In addition, Mr. Hanrahan was previously the President and Chief Executive Officer of AES China Generating Co. Ltd., a public company formerly listed on NASDAQ. He also managed other AES businesses in the U.S., Europe and Asia. Prior to joining AES, Mr. Hanrahan served as a line officer on a fast attack nuclear submarine, USS Parche (SSN 683). Mr. Hanrahan serves on the Board of Directors of Corn Products International, Inc. He is a graduate of Harvard School of Business and the U.S. Naval Academy.

        Kristina M. Johnson, age 51, has been a Director of AES since April 2004. Dr. Johnson is Provost and Senior Vice President for Academic Affairs at Johns Hopkins University. From July 1999 through August 2007, Dr. Johnson served as the chief academic and administrative officer at the Edmond T. Pratt, Jr., School of Engineering at Duke University. Prior to joining Duke, Dr. Johnson served on the faculty at the University of Colorado at Boulder, from 1985-1999 as a Professor of Electrical and Computer Engineering, and as a co founder and Director (1993-1997) of the National Science Foundation Engineering Research Center for Optoelectronic Computing Systems Center. Dr. Johnson received her BS with distinction, MS and PhD from Stanford University in Electrical Engineering. She is an expert in liquid crystal electro-optics and has over forty patents or patents pending in this field. Dr. Johnson currently serves on the Boards of Directors of Minerals Technologies, Inc., Boston Scientific, and Nortel Networks. Dr. Johnson serves on the Compensation Committee of the Board and is a member of the Technology Council.

        John A. Koskinen, age 68, has been a Director of AES since April 2004. Mr. Koskinen is President of the United States Soccer Foundation, a position he has held since June 2004. Previously, Mr. Koskinen served as Deputy Mayor and City Administrator for the District of Columbia from 2000 to 2003. From 2001 to 2004, Mr. Koskinen served as a Director of the U.S. Soccer Foundation and

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served on the Foundation's audit committee. Prior to his election as Deputy Mayor, he occupied several positions with the U.S. Government, including service from 1994 through 1997 as Deputy Director for Management, Office of Management and Budget. From 1998 to 2000, he served as Assistant to the President (President Clinton) and Chaired the President's Council on Year 2000 Conversion. Prior to his most recent service with the U.S. Government, in 1973, Mr. Koskinen joined the Palmieri Company, which specialized in turnaround management, as Vice President and later served as President and Chief Executive Officer from 1979 through 1993. Mr. Koskinen graduated with a JD, cum laude, from Yale University School of Law and a BA, magna cum laude, in physics from Duke University where he was a member of Phi Beta Kappa. Mr. Koskinen currently serves on the Board of Directors of American Capital Strategies. Mr. Koskinen serves on the Financial Audit Committee and Compensation Committee of the Board and chairs the Technology Council.

        Philip Lader, age 62, has been a Director of AES since April 2001. The former U.S. Ambassador to the Court of St. James's, he is Chairman of WPP Group plc, the global advertising and communications services company which includes J. Walter Thompson, Young & Rubicam, and Ogilvy & Mather. A lawyer, he is also a Senior Advisor to Morgan Stanley, a Director of Lloyd's of London, WPP Group plc, Rusal and Marathon Oil Corporations, Songbird Estates (Canary Wharf) plc, and a trustee of the RAND Corporation and the Smithsonian Museum of American History. Formerly White House Deputy Chief of Staff, Assistant to the President, Deputy Director of the Office of Management and Budget, and Administrator of the U.S. Small Business Administration, he also was President of Sea Pines Company, Executive Vice President of the U.S. holdings of the late Sir James Goldsmith, and president of universities in South Carolina and Australia. He was educated at Duke University (BA, Phi Beta Kappa, 1966), the University of Michigan (MA, 1967), Oxford University, and Harvard Law School (JD, 1972). Mr. Lader chairs the Nominating, Governance and Corporate Responsibility Committee of the Board and also serves on the Technology Council.

        John H. McArthur, age 74, has been a Director of AES since January 1997. He is the retired Dean of the Harvard Business School, and has been a private business consultant and active investor in various companies since prior to 1994. He is a member of the Boards of Directors of BCE Inc., Bell Canada, Bell Canada Enterprises, Cabot Corporation, KOC Holdings, A.S. Istanbul, Reuters Founders Share Company, London, and Telesat Canada. Mr. McArthur serves on the Financial Audit Committee and the Finance and Investment Committee of the Board.

        Sandra O. Moose, age 66, has been a Director of AES since April 2004. Dr. Moose is President of Strategic Advisory Services and previously was a Senior Vice President of The Boston Consulting Group ("BCG"). She joined BCG in 1968, was a Director since 1975, and a Senior Vice President through 2003. She managed BCG's New York Office from 1988-1998 and was appointed Chair of the East Coast. Dr. Moose received her PhD and MA in economics from Harvard University and BA summa cum laude in economics from Wheaton College. Dr. Moose serves on the Boards of Directors of Verizon Communications, Rohm and Haas Company, the Alfred P. Sloan Foundation and IXIS Advisor Funds and Loomis Sayles Funds where she is Chairperson of the Board of Trustees. Dr. Moose serves on the Nominating, Governance and Corporate Responsibility Committee and the Finance and Investment Committee of the Board.

        Philip A. Odeen, age 72, has been a Director of AES since May 1, 2003. He was elected the Alternate Lead Independent Director in November 2007. From October 2006 to September 2007, Mr. Odeen served as Non-Executive Chairman for Avaya. He served as Non-Executive Chairman for Reynolds and Reynolds Company from July 2004 until October 2006. Mr. Odeen retired as Chairman of TRW Inc. in December 2002. Prior to joining TRW in 1997, Mr. Odeen was President and Chief Executive Officer of BDM, which TRW acquired in 1997. From 1978 to 1992, Mr. Odeen was a Senior Consulting Partner with Coopers & Lybrand and served as Vice Chairman, management consulting services, from 1991 to 1992. From 1972 to 1978, he was Vice President of the Wilson Sporting Goods Company. Mr. Odeen has served in senior positions with the Office of the Secretary of Defense and

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the National Security Council staff. Mr. Odeen graduated Phi Beta Kappa with a BA in government from the University of South Dakota. He was a Fulbright Scholar to the United Kingdom and earned a master's degree from the University of Wisconsin. He is a member of the Boards of Directors of Avaya, Convergys Corporation, and Northrop Grumman Corporation. Mr. Odeen chairs the Compensation Committee and also serves on the Finance and Investment Committee of the Board.

        Charles O. Rossotti, age 67, has been a Director of AES since March 2003. Mr. Rossotti is a Senior Advisor with the Carlyle Group, one of the world's largest private equity firms. From November 1997 until November 2002, Mr. Rossotti was the Commissioner of Internal Revenue at the United States Internal Revenue Service ("IRS"). Prior to joining the IRS, Mr. Rossotti was a founder of American Management Systems, Inc., where he held the position of President from 1970 to 1989, Chief Executive Officer from 1981 to 1993 and Chairman from 1989 to 1997. From 1965 to 1969, he held various positions in the Office of Systems Analysis within the Office of the Secretary of Defense. Mr. Rossotti graduated magna cum laude from Georgetown University and received an MBA with high distinction from Harvard Business School. Mr. Rossotti serves on the Boards of Directors of Adesso Systems Corporation, Liquid Engines, Inc., Compusearch Systems, Inc., and Merrill Lynch & Co., Inc. Mr. Rossotti chairs the Financial Audit Committee of the Board.

        Sven Sandstrom, age 66, has been a Director of AES since October 2002. He is the former Managing Director of the World Bank, retiring from the Bank in December 2001. He is a member of the Governing Council and Treasurer of the International Union for the Conservation of Nature (IUCN). He co-chairs the funding negotiations for the Global Fund to Fight AIDS, TB and Malaria. He chairs the funding negotiations for the African Development Bank. Mr. Sandstrom serves on the Financial Audit Committee and the Nominating, Governance and Corporate Responsibility Committee of the Board.

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EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Executive Compensation Philosophy

        In all areas of our business, our policies seek to maximize long-term value for our stockholders. Consistent with this philosophy, we believe that stockholders benefit from compensation policies that attract the highest caliber people and retain and motivate these individuals. The Compensation Committee is responsible for designing, reviewing and administering our executive compensation program (the "Program"). The Program is designed to achieve the following objectives:

        To achieve these objectives, the Program relies on the following components of total compensation:

        The Compensation Committee varies the allocation among these four components of compensation so that the most senior executives in the Company, including the Chief Executive Officer, Chief Financial Officer and the three other executive officers and former executive officer named in the Summary Compensation Table in this prospectus, who have the greatest influence over our performance, are awarded compensation that has a significant portion highly dependent upon Company and individual performance. The Program is also designed to ensure that compensation awards vest in a manner that rewards consistency in performance over time.

        We believe that our Program, as currently structured, is consistent with the objectives of our compensation philosophy. However, our philosophy and our Program may evolve over time in response to factors such as market conditions, legal requirements or other factors, including subjective factors not currently known to us.

Targeted Compensation

        The Program targets setting overall compensation for each named executive officer in the middle range of total compensation for executives holding comparable positions in both our peer group of companies (the "Peer Group") and a broad set of similarly sized general industry and energy companies. Our Program and each of its components is benchmarked against compensation programs used by S&P 500 companies, as well as the programs of our Peer Group.

        To develop the Peer Group for our 2006 compensation, our senior management generated a list of companies with whom we compete for executive talent in the energy industry. The companies in the Peer Group have executives with backgrounds relevant to our business. The list was reviewed by our

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outside compensation consultants, who then, based on their review of our industry, suggested changes to the Peer Group which were then discussed with our management. The Peer Group includes CMS Energy, Calpine Corporation, Duke Energy, Dynegy, Edison International, FPL Group, NRG Energy, Pacific Gas & Electric, Reliant Resources, Southern Company, and TXU Energy.

        The Compensation Committee determines total compensation in the first quarter of each year based on available data. In 2006, the Compensation Committee reviewed both 2004 proxy statement data for the Peer Group as well as 2005 survey data. The Compensation Committee, with the assistance of our outside compensation consultants, made comparisons with similarly-situated executives in Peer Group companies based upon criteria such as type of position, business unit, career level, geographic region and company size. The Compensation Committee also reviewed survey data supplied by our outside compensation consultants in order to accurately reflect our competition for certain executive positions which do not necessarily require industry-specific experience (such as finance). The Program is designed to target energy industry market data for industry specific positions and the general industry survey data for functional or non-industry-specific positions, to ensure that the Company remains competitive in the markets where we compete for executive talent.

        When determining total compensation for each named executive officer, the Compensation Committee reviews "tally sheets," which demonstrate total compensation for the named executive officers. The tally sheets also review the value of long term compensation assuming different performance outcomes for the named executive officers. The Compensation Committee conducts this analysis looking forward for several years to ensure that compensation paid to the named executive officers is appropriate for these different company performance scenarios. If compensation is not appropriate, the Compensation Committee makes adjustments to the long term compensation awarded to each named executive officer at the time of grant.

        Although much of this analysis is based upon market data that provides an objective basis to evaluate our compensation policies, some adjustments are made based on subjective factors such as our views about the external market place, the degree of difficulty of a particular assignment, the individual's experience, the tenure of the individual in the role, and the individual's future potential.

        Additional information regarding the Compensation Committee's processes and procedures in determining executive officer compensation, including the role of the Chief Executive Officer and other executive officers, is contained in "Information About our Compensation Committee" in this prospectus.

Allocation among Components of Compensation

        After the overall targeted compensation has been established for each named executive officer, compensation is allocated among base salary and short, middle and long-term incentive compensation so that an executive's deviation from the median of total compensation, as compared to similarly situated executives in the Peer Group, is determined by individual and company performance. If individual and company performance exceed the pre-established performance measures, executives are compensated above the median of the Peer Group. Conversely, executives are compensated below the median of the Peer Group if individual and company performance is below the pre-established performance measures. The types of information used to evaluate performance and the data used to determine competitive compensation levels are the same for our named executive officers as they are for our other executive officers.

        The importance that the Program places on at-risk, performance-based compensation is shown by the allocation of the target level of overall compensation awarded to the named executive officers for 2006 among the various compensation elements of the Program. For the Chief Executive Officer, the base salary target is 10%-15%, the typical bonus target is 15%-20%, and the typical LTC target is

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65%-75%. For the other named executive officers, the base salary target is 20%-25%, the typical bonus target is 15%-20%, and the typical LTC target is 55%-65%.

Compensation for AES Executives

        The Program targets base salaries for our named executive officers generally at or below the median of the survey data provided by our compensation consultants. Base salaries reflect current practices within a named executive officer's specific market and geographic region and among executives holding similar positions in the Peer Group. In addition to these factors, the base salary for a named executive officer could be higher or lower, depending on a number of more subjective factors, including the executive's experience, the executive's sustained performance, the need to retain key individuals, recognition of roles that are larger in scope or accountability than standard market position; and market/competitive differences based upon a specific location.

        The base salary amounts paid to our named executive officers in 2006 are contained in the "Salary" column of the Summary Compensation Table in this prospectus.

        The Program provides named executive officers with an annual cash incentive to reward short-term individual performance. At the 2006 Annual Meeting of Stockholders, our stockholders approved The AES Corporation Performance Incentive Plan (the "Performance Incentive Plan"), which is available to our US-based employees, including the named executive officers. The Compensation Committee's specific objectives with the Performance Incentive Plan are to promote the attainment of our significant business objectives; encourage and reward management teamwork across the Company; and assist in the attraction and retention of employees vital to our success.

        The Performance Incentive Plan links annual cash incentive payments to performance based on factors that are drivers of our success—including individual, operational, safety, and financial goals—and also reflect annual incentives paid by other companies for comparable positions. Other considerations include an executive's leadership skills, the difficulty of his or her assignments, and the prospects for retaining the named executive officer. These awards are not guaranteed.

        The target annual cash incentive award for each named executive officer is assessed and approved annually and ranges from 80 to 150 percent of base salary, depending on an individual's specific job responsibilities. The award paid in a previous year is not a factor in determining the current year award. Because the amount of the award actually paid is based on the attainment of Company and individual performance goals, the Performance Incentive Plan payment for a specific named executive officer could be zero or as much as twice the target payment. For 2006, awards for all plan participants (including the named executive officers) were based on the following performance goals:

        If these performance goals are not fully achieved at year end, the annual awards are paid according to the percentage of the goals that were met. If threshold performance goals are not met, no payment is made. Performance goals may also be exceeded, which could make the payment under the annual award higher than the target. The Compensation Committee has the discretion to reduce the amount of any annual award if it concludes that a reduction is necessary or appropriate. The

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Compensation Committee cannot increase the amount of any award intended to be performance-based compensation under Section 162(m) of the Code.

        The level of achievement of each performance goal is confidential, has not been publicly disclosed, and the Compensation Committee has determined that disclosure of the levels of such goals would cause competitive harm to the Company. When the Compensation Committee set performance goals, the Compensation Committee intended for performance at target to be a challenging, but attainable, goal. The Compensation Committee also believed, at the time the performance goals were set, that performance at a level above the target was achievable but a stretch goal. The threshold, target and maximum pay-out levels of the Performance Incentive Plan awards for each named executive officer are shown in the "Estimated Future Payouts Under Non-Equity Incentive Plan Awards" columns of the Grants of Plan-Based Awards Table in this prospectus.

        For 2006, Company performance on cash flow targets was above the target performance level for the Performance Incentive Plan. Specifically, 120% of the 2006 cash flow target was met.

        Company performance on performance improvement and cost reductions was below the target performance level for the Performance Incentive Plan. Specifically, 90% of the 2006 performance improvement and cost reduction target was met.

        Company performance on safety met the minimum threshold, but was below the target performance level for such measure. Specifically, 80% of the 2006 safety target was met.

        Considering these performance results as compared to performance targets, the named executive officers (excluding Barry Sharp who was not eligible to receive a 2006 actual or target bonus) received an average bonus of 124% of the 2006 target amount, when consideration for performance of their personal objectives was measured.

        For Paul Hanrahan, the CEO, the following accomplishments were considered in determining that 145% of his 2006 individual performance targets were met:

        The Performance Incentive Plan awards paid out to the named executive officers for 2006 are set forth in the "Non-Equity Incentive Plan Compensation" column of the Summary Compensation Table in this prospectus.

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        The AES Corporation LTC Plan is available to all AES employees, including the named executive officers (subject to local labor laws). In 2006, approximately 1,900 AES employees in 17 countries received awards under the LTC Plan.

        Cash and equity-based awards under the LTC Plan link individual compensation with long-term value creation and our stock performance. During 2006, the following factors were considered in granting long-term compensation awards to the named executive officers: (1) the level of equity-based compensation paid to executives holding comparable positions in the Peer Group, (2) individual or personal performance and future potential, and (3) Company performance. For 2006, the Program included a mix of long term incentive awards under the LTC Plan. All 2006 annual grants to named executive officers under the LTC Plan were allocated as follows:

        The Compensation Committee has the discretion to amend the terms of any LTC plan award after it has been awarded, but not if such amendment would impair the rights of the holder of the award.

        The Program is designed to strike a balance between the objectives of market value creation and underlying economic performance by allocating 50% of LTC Plan in awards which can be settled in stock (RSUs and Options) and 50% of LTC Plan awards in awards which settle in cash (PUs).

        Paul Hanrahan's LTC Plan grant in February 2006 recognized his long-term contribution to AES and the effectiveness of his leadership. Victoria Harker joined the Company as Chief Financial Officer in January 2006 and received her first LTC Plan award at that time. The award recognized her past experience and potential contributions to AES, and reflected the market for newly appointed chief financial officers of comparable companies. William Luraschi's LTC Plan award recognized his ongoing contribution to AES and the Company continuity he provides in his executive position. Andres Gluski and Haresh Jaisinghani, who recently left the Company, were appointed to their executive positions at the beginning of 2006 and their LTC Plan awards reflected their promotion to their new roles and market data for new hires holding comparable positions at companies in the Peer Group.

        Information regarding the amounts and values of the LTC Plan awards is contained in the Summary Compensation Table and the Grants of Plan-Based Awards Table in this prospectus. A description of the terms of the awards is contained in "Narrative Disclosure Relating to the Summary Compensation Table and Grants of Plan-Based Awards Table" in this prospectus.

        PUs are performance-based awards that reward efficient generation of cash over a rolling three-year period. They use a cash generation metric to measure the net cash we generate by increasing revenue, reducing costs, and improving productivity, which we consider a significant source of stockholder value creation, and which directly links compensation with the performance of our business during the measurement period. The payment made, if any, under each PU depends upon the level of the PU's cash generation metric achieved over the three year measurement period.

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        Since PUs have a three-year performance period, the PUs we granted in 2006 have a measurement period ending in 2008 and, if paid out, will be paid in 2009. The PU payments made for the 2004-2006 performance period, were made under PUs granted in 2004.

        The following table illustrates possible payouts under the PUs granted in 2006 to the named executive officers, assuming these PUs fully vest. If less than 90% of the cash generation metric (the "Cash Value Added" or "CVA") is achieved for the three year measurement period, no payments will be made under these PUs. If CVA levels are achieved at the 90% level, each PU has a value of $0.50; if CVA levels are achieved at greater than 90% and less than 100% of the CVA target, or greater than 100% and less than 120% of the CVA target, the PU payout will be determined based on a straight-line interpolation, subject to a maximum value of $2.00 per unit. There is no increase in PU payments above the maximum value per unit if the CVA level is above 120%.

Value of Performance Units Based on 2006 Cash Value Added Target

Name & Principal Position
   Below 90% of
Performance
Target
   Equal to 90% of
Performance Target
   Equal to 100% of
Performance Target
   Equal or greater than
120% of Performance
Target
Paul Hanrahan, CEO   $ 0   $1,200,000
(2,400,000 units × $0.50)		   $2,400,000
(2,400,000 units × $1.00)		   $4,800,000
(2,400,000 units × $2.00)

Victoria Harker, EVP & CFO
 
$
0
 
$281,000
(562,500 units × $0.50)
 
$562,500
(562,500 units × $1.00)
 
$1,125,000
(562,500 units × $2.00)

William R. Luraschi, EVP
 
$
0
 
$375,000
(750,000 units $0.50)
 
$750,000
(750,000 units × $1.00)
 
$1,500,000
(750,000 units × $2.00)

Andres R. Gluski, EVP and COO
 
$
0
 
$318,750
(637,500 units × $0.50)
 
$637,500
(637,500 units × $1.00)
 
$1,275,000
(637,500 units × $2.00)

Haresh Jaisinghani, EVP
 
$
0
 
$325,000
(650,000 units × $0.50)
 
$650,000
(650,000 units × $1.00)
 
$1,300,000
(650,000 units × $2.00)

        Although the targeted CVA during the specific three year performance period is determined at the time the PU is granted, pre-established adjustments may be made to the CVA target based on changes to the Company's portfolio, such as an asset divestiture or sale of a portion of equity in a subsidiary. In addition, an external financial consultant is engaged at the end of each year to assist management and the Compensation Committee in calculating CVA. The target level of CVA for the PUs granted in 2006 is confidential, has not been publicly disclosed, and the Compensation Committee has determined that disclosure of its target level would cause competitive harm to the Company. At the time the Compensation Committee established the 2006 PU awards, the Compensation Committee intended for performance at the target level to be a challenging, but attainable, goal. It is our policy to grant PUs during the first quarter of each year at the Compensation Committee's first regularly scheduled meeting for the year. We may also grant PUs to an executive officer at the time he or she is hired or promoted to his or her position of an executive officer.

        The PUs granted in 2004 reached maturity at the end of 2006 and vested PUs were paid to participants in March 2007. The payout was based on our performance during the three-year period of 2004-2006. During that period, the Company's performance against its CVA target was above the predetermined target. Therefore, payout of these units was at $1.1076 per unit, slightly above the initial value of $1.00 per unit.

        The payment of the 2004 PU awards is reflected in the "Non-Equity Incentive Plan Compensation" column of the Summary Compensation Table in this prospectus.

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        A restricted stock unit represents the right to receive a single share of AES common stock or cash of equivalent fair market value. The RSUs granted to the named executive officers in 2006 will vest in equal installments over a three year period commencing on the first anniversary of the grant date if: (i) the executive continues to be employed by AES on each such date; and (ii) (A) the total stockholder return ("TSR") of AES, measured by the appreciation in stock price and dividends paid, exceeds the TSR of the S&P 500 Index for the three-year vesting period, or (B) the TSR of AES is positive, the S&P 500 Index is positive, and the TSR of AES is within 5 percent of the TSR of the S&P 500 Index (subject to the Compensation Committee's discretion to choose that the RSUs should not vest in such circumstance). Once RSUs vest, a named executive officer must continue to hold the RSUs for an additional two years before the named executive officer receives stock or cash for the RSUs.

        It is our policy to grant RSUs during the first quarter of each year at the Compensation Committee's first regularly scheduled meeting for the year. We may also grant RSUs to an executive officer at the time he or she is hired or promoted to his or her position as an executive officer.

        The first grant of RSU awards under the LTC Plan vested at the end of 2006 as our TSR exceeded the TSR of the S&P 500 over the 2004-2006 measurement period. Our TSR was 133%, while the TSR of the S&P 500 Index was 28%. Payout of these RSUs will be made as soon as administratively practicable in 2009.

        Vesting of the 2004 RSU awards is reflected in the Option Exercises and Stock Vested table in this prospectus and additional information regarding the awards is set forth in the Nonqualified Deferred Compensation Table (and its accompanying narrative) in this prospectus.

        An Option represents an individual's right to purchase shares of AES common stock at a fixed exercise price after the option vests. An Option only has value if our stock price exceeds the exercise price of the stock option after it vests. Options vest in equal installments over a three year period commencing on the first anniversary of the date the Option is granted, provided that the named executive officer continues to be employed by AES on such date. Options may also be used in specific cases, such as in recruiting an executive and to attract high caliber people. For example, on January 23, 2006, the Board provided our Chief Financial Officer with a sign-on LTC Plan Option grant. The grant was valued using the closing market price of our stock on January 23, 2006