UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2006

-OR-

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

COMMISSION FILE NUMBER 0-19281

The AES Corporation

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filter, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x      Accelerated filer o      Non-accelerated filer o

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates on June 30, 2006, the last business day after the Registrant’s most recently completed second fiscal quarter (based on the closing sale price of $18.45 of the Registrant’s Common Stock, as reported by the New York Stock Exchange on such date) was approximately $12.137 billion.

The number of shares outstanding of the Registrant’s Common Stock, par value $0.01 per share, on May 15, 2007, was 667,582,977.

THE AES CORPORATION
FISCAL YEAR 2006 FORM 10-K
TABLE OF CONTENTS

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PART I

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

FORWARD-LOOKING INFORMATION

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

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

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

·       our ability to manage our operation and maintenance costs;

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

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

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

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

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

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

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

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

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

·       changes in laws, rules and regulations affecting our business, including, but not limited to, deregulation of wholesale power markets and its effects on competition, the ability to recover net utility assets and other potential stranded costs by our utilities, the establishment of a regional transmission organization that includes our utility service territory, the application of market power criteria by the Federal Energy Regulatory Commission (“FERC”), changes in law resulting from new federal energy legislation, including the effects of the repeal of Public Utility Holding

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Company Act (“PUHCA”), and changes in political or regulatory oversight or incentives affecting our alternative energy businesses, including tax incentives;

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

·       the economic climate, particularly the state of the economy in the areas in which we operate;

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

·       our ability to meet our expectations in the development, construction, operation and performance of our alternative energy businesses, which rely, in part, on actual wind volumes in areas affecting our existing and planned wind farms performing consistently with our expectations, and actual wind turbine performance operating consistently with our expectations, the continued attractiveness of market prices for carbon offsets under markets governed by the Kyoto Protocol, and consistent and orderly regulatory procedures governing the application, regulation, issuance of Certified Emission Reduction (“CER”) credits and the extension of such regulations beyond 2012;

·       our ability to keep up with advances in technology;

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

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

·       the effects of litigation and government investigations;

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

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

·       our ability to attract and retain talented directors, management and other personnel, including, but not limited to, financial personnel in our foreign businesses that have extensive knowledge of United States Generally Accepted Accounting Principles (“GAAP”).

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.

Restatement Of Consolidated Financial Statements

Background

The Company has previously identified certain material weaknesses related to its system of internal control over financial reporting. These material weaknesses, as described in the Company’s previously filed Form 10-K for the year ended December 31, 2005 included the following general areas:

·       Aggregation of control deficiencies at our Cameroonian subsidiary;

·       Lack of U.S. GAAP expertise in Brazilian businesses;

·       Treatment of intercompany loans denominated in other than the functional currency;

·       Derivative accounting; and

·       Income taxes.

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In part, the continuing remediation of these material weaknesses resulted in the identification of certain material financial statement errors. The Company has restated its financial statements for years ended prior to December 31, 2005 on March 30, 2005, January 19, 2006 and April 4, 2006 largely as a result of material weaknesses. As part of the Company’s plan to eliminate these material weaknesses in internal control over financial reporting, the Company has embarked on a program, over a several year period, to improve the quality of its people, processes and financial systems. This has included a broad restructuring of the global finance organization to operate on a more centralized basis and the recruitment of additional accounting, financial reporting, income tax, internal control and internal audit staff around the world.

During the fourth quarter of 2006, in conjunction with these improvements, continued remediation of some of our material weaknesses and overall strengthening of controls across our businesses, the Company identified certain additional errors which required the restatement of previously issued consolidated financial statements for the years ended December 31, 2005 and December 31, 2004 and for the previously issued interim periods ending March 31, 2006, June 30, 2006 and September 30, 2006.

The Company’s remediation efforts for certain material weaknesses reported as of December 31, 2005, as well as improvements to controls across the Company, resulted in the identification of errors included in the current restatement. In addition, a number of immaterial errors were identified as a result of the continued strengthening of the global finance organization. The Company believes that the increase in technical tax and accounting expertise, increased staffing levels at certain of our businesses and at our corporate office, and a focused effort on increasing the number of financial audit activities have contributed to the overall improvement of the accuracy of our financial statements. It also resulted in the identification of material weaknesses in areas not previously reported, although not all weaknesses contributed to the need to restate the consolidated financial statements. For further discussion of our material weaknesses, see Item 9A of this Annual Report on Form 10-K.

The restatement adjustments resulted in a decrease to previously reported income from continuing operations and net income of $24 million for the year ended December 31, 2005 and an increase of $2 million for the year ended December 31, 2004. It also resulted in a decrease to previously reported income from continuing operations and net income of $3 million for the three months ending March 31, 2006, an increase to net income of $10 million for the six months ending June 30, 2006 and an increase to net income of $30 million for the nine months ending September 30, 2006. These interim period adjustments for the first three quarters of 2006 were largely the result of reversing errors previously corrected in these periods, which were not previously considered material either to the period in which they were corrected or the prior period to which they actually arose. Additionally, the cumulative adjustment for all periods prior to 2004 resulted in an increase to retained deficit of $50 million.

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The following table quantifies the net impact of the restatement corrections by key income statement line items for the years ended December 31, 2005 and 2004 and includes the resulting impact on diluted earnings per share from continuing operations. The primary line items affected include revenue, cost of sales, gain (loss) on foreign currency transactions, income tax expense and the related impacts on minority interest expense.

(1)          Minority interest and other includes $12 million and $13 million of minority interest expense for the periods ending December 31, 2005 and December 31, 2004, respectively, related to the impact of the restatement adjustments at entities with minority interests.

The Company has been cooperating with an informal inquiry by the Staff of the Securities Exchange Commission (“SEC”) concerning the Company’s restatements and related matters, and has been providing information and documents to the SEC Staff on a voluntary basis. Because the Company is unable to predict the outcome of this inquiry and the SEC Staff may disagree with the manner in which the Company has accounted for and reported the financial impact of the adjustments to previously filed financial statements, there may be a risk that the inquiry by the SEC could lead to circumstances in which the Company may have to further restate previously filed financial statements, amend prior filings or take other actions not currently contemplated.

The restatement adjustments include several key categories as described below:

Brazil Adjustments

Prior year errors related to certain subsidiaries in Brazil include the following:

·       decrease of the U.S. GAAP fixed asset basis and related depreciation at Eletropaulo of $21 million in 2005 and $16 million in 2004 (the impact net of tax and minority interest is $4 million in 2005 and $4 million in 2004); and

·       other errors identified through account reconciliation or review procedures.

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The cumulative impact on net income was an increase of $6 million and $3 million for the years ended December 31, 2005 and 2004, respectively.

La Electricidad de Caracas (“EDC”)

Prior year errors related to the Company’s Venezuelan subsidiary, EDC, include the following:

·       $22 million revenue increase predominantly related to an error in updating the current tariff rates in the unbilled revenue calculation for 2005,

·       $10 million increase in foreign currency transaction expense posted incorrectly to the balance sheet in 2005, and

·       other errors identified through account reconciliation or review procedures.

The cumulative impact of all EDC adjustments on net income was an increase of $2 million for each of the years ended December 31, 2005 and 2004.

Capitalization of Certain Costs

Certain errors were discovered with fixed asset balances at several of the Company’s facilities related to capitalization of development costs, overhead and capitalized interest. The cumulative impact on net income for capitalization errors was a decrease of $4 million for the year ended December 31, 2005 and a decrease of $2 million for the year ended December 31, 2004.

Derivatives

Adjustments were identified resulting from the detailed review of certain prior year contracts and include the following:

·       the evaluation of hedge effectiveness; and

·       the identification and evaluation of derivatives.

The most significant adjustment involved a power sales agreement signed in 2002 between the Company’s generation facility in Cartagena, Spain, an unconsolidated subsidiary accounted for using the equity method of accounting, and its power offtaker. The power sales agreement had a pricing component that was tied to the U.S. dollar, although the entity’s own functional currency was the Euro and that of the offtaker was the Euro. In addition, a maintenance service agreement related to the Cartagena facility included a pricing mechanism that was tied to changes in the U.S. dollar, when the entity’s functional currency was the Euro and the service provider’s functional currency was the Yen.

Under the guidance of Statement of Financial Accounting Standard (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” these contracts contained embedded derivatives that are required to be bifurcated from the contract and recorded at fair value with changes in fair value recognized in the results of operations. The net result of these adjustments was a decrease of $3 million and an increase of $4 million in equity in earnings of affilitates for the years ended December 31, 2005 and 2004, respectively.

The cumulative impact of all derivative adjustments on net income was a decrease of $4 million in 2005 and an increase of $5 million in 2004.

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Income Tax Adjustments

Income tax adjustments relate primarily to the following:

·       A $20 million adjustment to correct income tax expense in the fourth quarter of 2005 as a result of an incorrect 2004 tax return to accrual adjustment, previously disclosed in the Company’s Form 10-Q for September 30, 2006; and

·       A $21 million adjustment to record income tax benefit in 2004 as a result of a change in local income tax reporting for leases in Qatar, offset by adjustments to correct income tax expense for certain state deferred tax assets and other miscellaneous items.

The net impact of individual income tax adjustments resulted in an increase to income tax expense of approximately $18 million in 2005 and $7 million in 2004. The cumulative impact on income tax expense as a result of all restatement adjustments was an increase of approximately $27 million for the year ended December 31, 2005 and an increase of approximately $24 million for the year ended December 31, 2004.

Other Adjustments

As a result of work performed in the course of our year end closing process, certain other adjustments were identified which decreased net income by $6 million for the year ended December 31, 2005 and increased net income by $1 million for the year ended December 31, 2004.

Balance Sheet Adjustments

Adjustments at certain businesses in Brazil

The Company’s Brazilian business, Sul, records customer receipts used to provide line extensions as an offset against property, plant and equipment. However, the regulatory body of Brazil never issued any guidance with respect to the treatment of these customer receipts. As such, we believe that a more appropriate classification of these customer receipts would have been as a regulatory liability given that the actual treatment as an offset against property, plant and equipment was never approved by the regulatory body of Brazil. Additionally, the regulatory liability treatment provides for the possibility of a future obligation back to the customers, which was confirmed by a recent regulatory ruling. The increase to property, plant and equipment and increase to long-term regulatory liabilities was $93 million and $62 million at December 31, 2005 and 2004, respectively.

Cartagena Deconsolidation

Upon the Company’s adoption of Financial Interpretation No.46, Variable Interest Entities (“FIN No. 46R”), as of January 1, 2004, the Company incorrectly continued to consolidate our business in Cartagena, Spain. An adjustment was made to deconsolidate the Cartagena balance sheet and statement of operations and to reflect AES’ share of the results of it’s’ operations using the equity method of accounting. This resulted in a decrease to investments in affiliates of $55 and $39 million; a decrease in net property, plant and equipment of $570 and $387 million; and a decrease in non-recource debt of $579 and $497 million at December 31, 2005 and 2004, respectively.

Restricted Cash

Certain balance sheet reclassifications were recorded at December 31, 2005 and December 31, 2004 that were the result of errors in the presentation of restricted cash. These reclassifications resulted in a reduction in cash and cash equivalents and an increase in restricted cash by $63 million and $97 million, in 2005 and 2004, respectively.

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Share-based Compensation

The Company recently concluded an internal review of accounting for share-based compensation (the “LTC Review”), which originally was disclosed in the Company’s Form 8-K filed on February 26, 2007. As a result of the LTC Review, the Company identified certain errors in its previous accounting for share-based compensation. These errors required adjustments to the Company’s previous accounting for these awards under the guidance of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”), Financial Accounting Standards Board (“FASB”) Statement No. 123, Accounting for Stock-Based Compensation (“FAS No. 123”) and FASB Statement No. 123R (revised 2004), Share-Based Payment (“FAS No. 123R”). As described below, the Company is recording adjustments to its prior financial statements resulting in additional cumulative pre-tax compensation expense for the years 2000-2005 of $36 million ($26 million net of taxes). None of these adjustments, individually or in the aggregate, is quantitatively material to any period presented.

In addition, the Company has identified accounting for share-based compensation as a material weakness and has prepared a remediation plan to strengthen further its granting and accounting practices to avoid similar errors in the future. See Item 9A—Disclosure Controls and Procedures of this Form 10-K for further explanation of the material weakness and the Company’s remediation plans.

Background of the LTC Review

Beginning in mid-2006 the Company conducted limited assessments of its share-based compensation practices. Based on those assessments, it did not appear likely that the potential accounting adjustments relating to share-based compensation issues identified as of that time would be material to the Company’s prior period financial statements. However, information subsequently developed by the Company’s Internal Audit group indicated that there had been control deficiencies and inadequate oversight related to historical granting practices and accounting for share-based compensation.

Following consideration of this information, the Company determined that a more comprehensive review of prior period awards was warranted. Accordingly, in early February 2007, the Company requested that an outside consulting firm assist with the collection and processing of data relating to the Company’s share-based compensation awards. 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 e-mails; and (iii) analysis of the information used to determine measurement dates, strike prices and valuations required to reach the resulting accounting adjustments. The Company also asked an outside law firm to assist the Company with the LTC Review. This law firm had already been assisting the Company in responding to requests for documents and information from the SEC Staff principally relating to the Company’s restatements for the years 2002-2005. As disclosed in a Form 8-K filed on March 19, 2007, the Financial Audit Committee of the Company’s Board of Directors formed an Ad Hoc Committee of three independent directors to review the Company’s procedures, conclusions and recommendations regarding the LTC Review, as described herein.

Purposes and Scope of the LTC Review

The LTC Review was designed and conducted principally to determine whether any adjustments to the Company’s prior period financial statements were required as a result of incorrect accounting for share-based compensation, which includes stock options and restricted stock units. A secondary purpose of the LTC Review was to evaluate the Company’s historical practices and procedures for making share-based compensation awards, including the conduct of individuals involved in the granting process.

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The Company determined that a ten-year review period covering the years 1997-2006 (the “Review Period”) was appropriate. Supporting documentation was more readily available in more recent years and, in many instances, the Company experienced difficulty locating and/or gathering documentation for the years 1997-1999. Therefore, the Company determined that a review of years preceding 1997 was unlikely to result in information susceptible to meaningful analysis.

A significant accounting issue identified in the LTC Review related to the determination of the “measurement date” with respect to share-based compensation awards. During the Review Period, the Company had generally used the indicated grant date as the measurement date for accounting purposes, when in many cases the indicated grant date actually preceded the measurement date as correctly defined under Generally Accepted Accounting Principles (“GAAP”). The U.S. GAAP technical accounting literature in effect during the accounting periods under review defined the measurement date for purposes of determining share-based compensation expense as the date on which the Company finalized an individual’s share-based award, to include the number of units awarded at a determinable strike price.

The Company gathered documentation and conducted analysis related to measurement dates with respect to all of the grants awarded in the Review Period, a total of approximately 29,600 stock option grants, representing approximately 45,380,000 options as well as approximately 4,000,000 restricted stock units for non-directors. These grants included both the Company’s annual compensation awards, known as “on-cycle” grants, and all awards made at other times, referred to as “off-cycle” grants. The LTC Review was designed to assess the appropriate measurement date for each of the various types of grants awarded during the Review Period. The Company considered SEC guidance and GAAP in evaluating known facts and circumstances in an attempt reasonably to determine the date that the share-based compensation awards were final. The Company collected information through targeted searches of various sources, including human resources and accounting databases, paper and electronic files and servers, Board of Directors and Compensation Committee meeting minutes, payroll records, and acquisition and business development documentation. The Company also interviewed certain current and former employees, officers and directors.

Although there generally was less documentation readily available for the years 1997-1999, the Company did review grants in those years, and based on available information, attempted to make a reasonable assessment of the correct measurement dates and potential accounting adjustments for the purposes of assessing whether any charge from that period could be material to the Company’s financial statements in those years. Based on this analysis, the Company determined that any errors identified during that period would not have resulted in a material impact to the Company’s stockholders’ equity and no adjustments were made.

The Company’s Accounting Adjustments

As a result of the LTC Review, the Company has determined that adjustments resulting in charges for share-based compensation should be recorded for the years 2000 through 2005. The additional cumulative pre-tax compensation expense totals $36 million ($26 million net of taxes). The effect of recognizing additional non-cash, share-based compensation expense resulting from the charges mentioned above by year is as follows:

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The Company also is recording a charge of $1 million (pre-tax) relating to the first three previously reported quarters of 2006, which primarily relate to prior year grants in which expense was carried forward to 2006.

None of these adjustments, individually or in the aggregate, is quantitatively material to any period presented; however, the Company will reflect these adjustments by reducing stockholders’ equity by $25 million as of January 1, 2004 for the cumulative effect of the correction of errors for the periods from January 1, 2000 through December 31, 2003. General and administrative expense will be adjusted for the years ending December 31, 2004 and 2005 and the first three quarters of 2006 as outlined above.

Annual On-Cycle Awards.   Compensation charges for annual on-cycle grants were determined based upon facts and circumstances relating to the dates the awards were final and the selection of the appropriate strike prices. The Company determined new measurement dates based on a determination of the date an award was final using the following methodology. Grants to Executive Officers and certain other senior executives (“Senior Leaders”) were considered to be final for accounting purposes upon Compensation Committee approval of a fixed number of options at a specific exercise price, or in certain years based on subsequent action by the Company establishing the grant date and strike price. Grants to all other employees were considered to be final for accounting purposes on the date that management completed its allocation of substantially all awards to the pool of employees receiving awards. In addition to measurement date changes, the LTC Review identified three years in which the Company had set the strike price for the annual on-cycle grants either as the opening price or as the intra-day low trading price of the Company’s stock during a four-day period over which a Board meeting was held. To determine the fair market value of the stock on the re-determined measurement date for accounting purposes, the Company used the closing price of the stock on that date. Accordingly, for financial accounting purposes, the amount of compensation expense recorded by the Company reflects both measurement date changes and intrinsic value changes for annual on-cycle awards. The predominant causes of the charges relating to on-cycle grants were (i) with respect to Executive Officers and Senior Leaders, use of a grant date associated with an annual Board meeting, where the grant date and strike price had not been determined with finality until several days after the meeting; and (ii) with respect to all other employees, the failure to finalize a complete and accurate schedule of the awards to be made to the employees contemporaneously with the intended grant date.

Off-Cycle Grants.   Compensation charges for off-cycle grants also were based primarily upon the dates the awards were final. The majority of the measurement date changes with respect to off-cycle grants related to the following five categories: (1) awards to newly hired employees; (2) awards upon promotions of existing employees or other change in status; (3) awards made in conjunction with transactions or other successful business development efforts; (4) “Founders” and other similar awards made in recognition of outstanding service, and (5) corrections to previous awards subsequently determined to have been erroneous.

The predominant cause of the measurement date errors in each of these categories of awards was the lack of adequate contemporaneous documentation supporting the intended grant. Accordingly, the amount of compensation expense recorded by the Company for these categories of off-cycle awards is based primarily upon measurement date changes. The adjustments reflect available evidence concerning the dates on which: (i) the recipients were entitled to receive the awards, (ii) the grants were intended to be made, and (iii) the terms of the grants were final.

In addition to the categories above, off-cycle grants also were defined to include modifications of prior grants. Compensation charges for grant modifications were based upon an analysis of changes to vesting and exercise periods. As a result of its review, the Company has determined that certain modifications were calculated using an incorrect method and others were not communicated to appropriate accounting personnel. The most significant modification relates to a grant to a former CEO that was erroneously accounted for by using an intrinsic value calculation instead of a fair value calculation following the Company’s decision to adopt FAS 123 effective January 1, 2003. The Company is recording a $3.1 million charge to account for this error for the year 2003.

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Summary of Significant Charges By Grant Year

Set forth in this section is a summary of the charges resulting from grants awarded in the years 2000, 2001 and 2003, which make up more than 95% of the additional expenses requiring adjustments to the prior period financial statements. This information is different than the discussion and table above, which described the effect of recognizing these additional charges over the applicable accounting periods in the Company’s financial statements. For these years, further information concerning the type of grant (on-cycle or off-cycle), the categories of the recipients and the nature of the change resulting in the adjustment is set out below.

For grants made in 2000, the total charge resulting from the LTC Review is approximately $22.9 million. Of that amount, approximately $3.8 million resulted from the changes to the on-cycle grants to Executive Officers and Senior Leaders. Of the remaining amount, approximately $17.2 million resulted from the changes to the on-cycle grants to all other employees, and approximately $1.9 million resulted from off-cycle grants.

For grants made in 2001, the total charge resulting from the LTC Review is approximately $8.7 million. Of that amount, approximately $7.2 million resulted from the changes to on-cycle grants to Executive Officers and Senior Leaders. Of the remaining amount, approximately $250,000 resulted from the changes to the on-cycle grants to all other employees, and approximately $1.2 million resulted from off-cycle grants.

For grants made in 2003, the total charge is approximately $6.3 million. Of this amount, $3.1 million related to the modification to a grant to a former CEO as described above, and approximately $800,000 related to a grant to a director approved by shareholders where the grant date was recorded as having been finalized on the date of an earlier Board meeting. The remaining charges resulted from changes to certain on-cycle and off-cycle grants.

The Company’s Review of Historic Practices

As noted, the primary purpose of the LTC Review was to conduct a comprehensive review of the Company’s accounting for share-based compensation and to record any required adjustments in its financial statements. The LTC Review was not an independent investigation relating to historic practices and procedures. However, during the course of the LTC Review, the Company identified certain historical practices raising issues relating to share-based compensation and conducted a review of those practices, limited in scope as noted herein. Based on the information to date, the Company has identified certain historical issues and practices of concern relating to the annual on-cycle and off-cycle grants, which fall within the following five categories: (1) with respect to the 1997-1998 annual on-cycle grants, reported ratification of undocumented prior on-cycle grants by the Compensation Committee; (2) with respect to the 1999-2001 annual grants, after-the-fact selection of low strike prices within the four-day period during which Board meetings were held, and inaccurate Compensation Committee meeting minutes relating to grant date and strike price selection; (3) issuance of off-cycle grants prior to 2004 based on apparent, but not actual, delegation of authority, as well as general deficiencies in administration of off-cycle grants; (4) failure to establish and/or comply with certain formal corporate governance procedures in periods through 2004; and (5) lack of and/or insufficient controls and procedures, and/or lack of knowledge of applicable accounting standards, in connection with administration of share-based compensation. The Company notes that the senior officers who were primarily involved in the selection of the prices of the annual on-cycle grants from 1999-2001 were the Company’s President and CEO at the time, who retired in 2002; the Company’s CFO at the time, who left full time employment with the Company in early 2006 (he remains under an employment agreement through March 2008, although he is not active in management); and the Company’s General Counsel at the time, who presently is the Company’s Executive Vice President and President, Alternative Energy and is no longer involved in the Company’s legal functions or Board consideration or approval of share-based compensation.

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The information developed in the LTC Review did not establish that any officer or director of the Company manipulated the selection of grant dates or strike prices with actual knowledge that they were violating or causing the Company to violate accounting principles or requirements of the Company’s stock options plans, or that there was any effort to conceal information relating to the selection of grant dates or strike prices from the Company’s outside auditors. However, all of the matters described herein with respect to the Company’s general views and issues arising from the LTC Review are qualified by the fact that, in light of the limitations discussed herein, there may be additional documents, witnesses or other information not reviewed that might have indicated a different result

The limitations of the LTC Review include the fact that the Company did not review backups of data from the First Class System (“First Class”), the Company’s e-mail system prior to January 1, 2002, when the Company switched to Microsoft Outlook. The Company also did not attempt to restore approximately 460 computer tapes (the “Backup Tapes”) that are stored by an off-site storage vendor. The Company believes that these tapes comprise backups of certain Company electronic data (including e-mail) backed up on certain dates from approximately late 2001 through early 2004, but the Company has not located an index identifying the contents of the tapes.

The Company decided not to attempt to restore and review First Class or the Backup Tapes because: (i) the Company was able to review certain electronic data, including for the years 1997-2002, as well as paper files and other available information relating to the majority of the grants made during the Review Period; (ii) the Company believes that it is unlikely that information from these sources would materially alter the accounting adjustments that have been determined to be necessary; (iii) the Company has implemented or will implement measures necessary to provide effective controls and procedures in these areas; (iv) of the senior officers who were primarily involved in the selection of the prices of the annual on-cycle grants from 1999-2001, the former CEO is no longer with the Company, the former CFO is no longer an officer and is not active in the Company’s management, and the former General Counsel has a different position in the Company that does not involve corporate legal responsibilities or participation in Board consideration or approval of share-based compensation; and (v) based on consultation with a reputable information technology vendor, the Company determined that neither First Class nor the Backup Tapes could be restored for review without causing substantial delays in the LTC Review. In addition, while the Company conducted more than twenty interviews with persons who, by virtue of their position or otherwise, were believed to be most likely to have relevant knowledge, the Company did not interview every director or employee who may have had any involvement with options grants or accounting for share-based compensation.

ITEM 1.                 BUSINESS

Overview

We are a global power holding company incorporated in Delaware in 1981. Through our subsidiaries, we operate a portfolio of electricity generation and distribution businesses and investments on five continents and in 27 countries.

Our Businesses

We operate two types of businesses. The first is our distribution 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.

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Our Utilities business consists primarily of 13 distribution companies in seven countries with over 10 million end-use customers. All of these companies operate in a defined service area. This segment is comprised of:

·       integrated utilities located in:

·        the United States—Indianapolis Power & Light (“IPL”);

·   Cameroon—AES SONEL; and

·       distribution companies located in:

·        Brazil—AES Eletropaulo and AES Sul,

·        Argentina—Empresa Distribuidora La Plata S.A. (“EDELAP”), Empresa Distribuidora de Energia Norte (“EDEN”) and Empresa Distribuidora de Energia Sure (“EDES”),

·        El Salvador—Compañia de Alumbrado Eléctrico de San Salvador, S.A. de C.V. (“CAESS”), Compania, S. En C. de C.V. (“AES CLESA”), Distribuidora Electrica de Usulutan, S.A. de C.V. (“DEUSEM”) and Empresa Electrica de Oriente (“EEO”) 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).

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 94 power generation plants totaling over 35 gigawatts of capacity installed in 21 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, during the development phase of a project. Our competitors for these contracts include other independent power producers and equipment manufacturers, as well as various utilities and their affiliates. During the

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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.

We are also developing an alternative energy business including wind generation, the supply of liquefied natural gas (“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 business operations are organized along geographic lines, with regional management teams responsible for the financial results in their respective territories. Each of the four regions, (1) North America, (2) Latin America, (3) Europe, CIS & Africa, which we refer to as “Europe & Africa” and (4) Asia and the Middle East, which we refer to as “Asia”, are led by a Regional President reporting to our Chief Operating Officer (“COO”) who reports to the Chief Executive Officer (“CEO”). Our Alternative Energy business is led by an Executive Vice President, who reports to the CEO. Supporting these businesses is a business excellence group providing expertise in areas such as procurement, engineering and construction, safety, environment, information technology and performance improvement. This group is also led by an Executive Vice President who reports to the COO.

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.

Subsequent Events

On February 22, 2007, we entered into a definitive agreement with Petróleos de Venezuela, S.A., (“PDVSA”), pursuant to which we have agreed to sell to PDVSA all of our shares of EDC. The agreement is dated as of February 15, 2007. Subject to the terms and conditions in the agreement, PDVSA agreed to pay us a purchase price of US$739 million at closing, 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 EDC approved and declared a US$120 million dividend, payable on March 16, 2007, to all shareholders on record as of March 9, 2007. A wholly-owned subsidiary of the Company is the owner of 82.14% of the outstanding shares of EDC, and therefore, on March 16, 2007, this subsidiary received the equivalent of approximately US$99 million in Bolivares that is currently being held in trust at a U.S. bank until the funds can be converted to U.S. Dollars. Under the terms of the purchase and sale agreement with the Republic of Venezuela, PDVSA has agreed to ensure that the Company’s portion of the dividend is converted by the Venezuelan government’s Foreign Exchange Commission, CADIVI, from Bolivares into U.S. Dollars at the current official exchange rate within 90 days of the dividend payment date. As of the date of this filing, the conversion of the Company’s portion of the dividend from Bolivares to U.S. Dollars has been submitted to CADIVI and is awaiting their approval.

The agreement provided that PDVSA would acquire our EDC common shares in a tender offer. PDVSA commenced and publicly announced the commencement of concurrent tender offers in Venezuela and the United States (the “Offers”), on April 9, 2007. The Offers provided for the purchase of 2,704,445,687 of EDC common shares at a U.S. Dollar equivalent amount of $0.2734 per common share, which is consistent with the price per share implied by the purchase price within the agreement. The closing of the Offers occurred on May 8, 2007, the actual transfer of the shares along with payment of the purchase price occurred on May 16, 2007.

As a result of signing this agreement, we have concluded that a material impairment of our investment in EDC has occurred, which will be recorded in the first quarter ending March 31, 2007. This material impairment represents the net book value of our investment less the estimated purchase price. Management estimates that this pre-tax, non-cash charge will be in the range of $600 to $650 million.

We purchased a controlling interest in EDC in 2000. EDC is the largest private electric utility in Venezuela. It is a provider of power and light to approximately one million customers in the Caracas metropolitan area. EDC also owns and operates five generation plants with a total of 2,616 MW of generation capacity. These facilities collectively represent approximately 14% of the electricity consumed in Venezuela.

For the year ended December 31, 2006, EDC represented 5% of AES’ consolidated revenues and 12% of the Latin America Utilities segment revenues, 5% of AES’ consolidated gross margin and 17% of the Latin America Utilities segment gross margin. In addition, EDC represented 37% of AES’ consolidated net income and 36% of basic earnings per share. Excluding the net after-tax loss impact of $512 million related to the sale of Eletropaulo shares and debt restructuring, EDC represented 12% of AES’ consolidated net income and 12% of basic earnings per share. AES received a dividend of

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approximately $101 million from EDC in 2006. EDC’s five generation plants represented approximately 7% of AES’ approximate 35 gigawatts of capacity installed.

Segments

Beginning with this Annual Report on Form 10-K, AES 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:

·       Latin America Generation;

·       Latin America Utilities;

·       North America Generation;

·       North America Utilities;

·       Europe & Africa Generation;

·       Europe & Africa Utilities;

·       Asia Generation

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 American operations accounted for 58%, 58% and 54% 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 11,217 MW. AES owns and operates 9 utilities, distributing a total of 48,058 GWh, in addition to operating one utility under management agreement, which distributes 1,626 GWh to customers.

Latin American Generation.   Our Generation business in Latin America consists of 47 generation facilities with the capacity to generate 11,217 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.

Latin American Utilities.   We own 9 Utility businesses, including electricity distribution businesses located in Argentina (EDELAP, EDEN and EDES), Brazil (AES Eletropaulo and AES Sul) and El Salvador (CAESS, CLESA, DEUSEM and EEO). Our tenth 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

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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 23%, 25% and 27% 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 27 generation facilities with 13,576 MW generating capacity and one integrated utility, distributing approximately 16,287 GWh of electricity to customers.

North American Generation.   In North America, AES has 23 generation facilities, including seven gas-fired plants, ten coal-fired plants, three petroleum coke-fired plants and three biomass-fired plants, in the United States, Puerto Rico and Mexico.

North American Utilities.   AES has one integrated utility in North America, Indianapolis Power & Light Company (“IPL”), which it owns through IPALCO Enterprises Inc. (“IPALCO”), the parent holding company of IPL. IPL is engaged in generating, transmitting, distributing and selling electric energy to 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 12% 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 nine countries. AES’s operations in the region now include a total of 24 generation plants owned or operated under management agreements with a total of 11,431 MW generation capacity. AES owns and operates three utilities, distributing a total of 8,960 GWh, in addition to operating 2 utilities under management agreement in the region, which distribute a total of 2,096 GWh.

Europe & Africa Generation.   We own 11 generation facilities in Europe & Africa, and operate two additional generation facilities under management contract in Kazakhstan. These generation facilities have the capacity to generate 10,504 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.

Europe & Africa Utilities.   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 6% 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

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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.

Asia Generation.   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 intercompany 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.

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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 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.

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

(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

Generation under construction

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Segment—Latin America Utilities

(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

Distribution

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

Distribution businesses under AES management

(1)             AES operates these facilities through management agreements and owns no equity interest in these businesses

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Segment—North America Generation

(1)             AES additionally owns and operates the Coal Creek Minerals coal mine in Oklahoma, USA

(2)             Acquired February, 2007

Segment—North America Utilities

(1)             IPL plants: Eagle Valley, Georgetown, Harding Street and Petersburg

Distribution