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

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 AND RECLASSIFICATION
OF CERTAIN SUBSIDIARIES INTO DISCONTINUED OPERATIONS

The accompanying financial statements and managements discussion and analysis of financial condition and results of operations have been restated to reflect the correction of errors that were contained in the Company’s 2006 Annual Report on Form 10-K. In addition the Company has conformed certain financial information presented in this Form 10-K/A to the presentation of the discontinued operations in its first quarter 2007 Form 10-Q. Other than information relating to the restatement and conforming the presentation of discontinued operations as described below, no attempt has been made in this 10-K/A to amend or update other disclosures originally presented in the Form 10-K. Except as stated herein, this Form 10-K/A does not reflect events occurring after the filing of the Form 10-K on May 23, 2007 or amend or update those disclosures. Accordingly, this Form 10-K/A should be read in conjunction with our filings with the SEC subsequent to the filing of the Form 10-K.

In this Form 10-K/A, the term “August 2007 Restatement” refers collectively to the errors related to special obligations liabilities at the AES Eletropaulo and AES Sul subsidiaries and the errors related to accounting for leases at the AES Southland and Pakistan subsidiaries and the reclassification of EDC and Central Valley into discontinued operations. The term “May 2007 Restatement” refers collectively to the errors that were previously discussed in our 2006 Annual Report on Form 10-K that was filed on May 23, 2007.

The combined impact of the August and May 2007 Restatements resulted in a decrease to previously reported net income of $57 million for the year ended December 31, 2006; a decrease of $43 million for the year ended December 31, 2005 and an increase of $6 million for the year ended December 31, 2004. It also resulted in a decrease to previously reported net income of $9 million for the three months ended March 31, 2006; a decrease of $3 million for the six months ended June 30, 2006; an increase of $11 million for the nine months ended September 30, 2006 and a decrease of $6 million for the three months ended March 31, 2007. Additionally, the cumulative adjustment for all periods prior to 2004 resulted in an increase to retained deficit of $50 million.

On July 31, 2007, the Financial Audit Committee of the Board of Directors determined that the Consolidated Financial Statements and the financial information in the Form 10-K filed on May 23, 2007 should no longer be relied upon. The determination was made after discussion with the Company’s external auditors.

A. Adjustments and Reclassifications in Financial Statements

The following table details the impact of the August 2007 Restatement on the Company’s Consolidated Statement of Operations for the year ended December 31, 2006:

	Year Ended December 31, 2006
	2006				August 2007				Discontinued Operations							2006
	Form 10-K				Restatement				EDC			Central Valley				Form 10-K/A
Revenues:
Regulated		$	6,849			$	—		$	(651	)		$	—			6,198
Non-Regulated		5,450				(48		)	—				(36		)		5,366
Total revenues		12,299				(48		)	(651		)		(36		)		11,564
Cost of Sales:
Regulated		(4,578		)		—			465				—				(4,114		)
Non-Regulated		(4,090		)		(1		)	—				38				(4,052		)
Total cost of sales		(8,668		)		(1		)	465				38				(8,166		)
Gross margin		3,631				(49		)	(186		)		2				3,398
General and administrative expenses		(305		)		—			—				—				(305		)
Interest expense		(1,802		)		—			39				—				(1,763		)
Interest income		443				—			(17		)		—				426
Other expense		(308		)		(139		)	(2		)		—				(449		)
Other income		115				—			(9		)		—				106
Gain (loss) on sale of investments		98				—			—				—				98
Loss on sale of subsidiary stock		(539		)		—			—				—				(539		)
Asset impairment expense		(29		)		—			1				—				(28		)
Foreign currency transaction losses on net monetary position		(77		)		—			(11		)		—				(88		)
Equity in earnings of affiliates		72				—			—				—				72
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST		1,299				(188		)	(185		)		2				928
Income tax expense		(403		)		(1		)	72				(2		)		(334		)
Minority interest expense		(610		)		132			19				—				(459		)
INCOME FROM CONTINUING OPERATIONS		286				(57		)	(94		)		—				135
Income (loss) from operations of discontinued businesses net of income tax		11				—			94				—				105
(Loss) gain from disposal of discontinued businesses net of income tax		(57		)		—			—				—				(57		)
INCOME BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		240				(57		)	—				—				183
Income from extraordinary items net of income tax		21				—			—				—				21
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		261				(57		)	—				—				204
Cumulative effect of change in accounting principle net of income tax		—				—			—				—				—
Net income		$	261			$	(57	)	$	—			$	—			$	204

The following table details the impact of both the May 2007 Restatement and the August 2007 Restatement on the Company’s Consolidated Statement of Operations for the year ended December 31, 2005:

	Year Ended December 31, 2005
	As Originally				May 2007				2006				August 2007				Discontinued Operations							2006
	Filed				Restatement				Form 10-K				Restatement				EDC			Central Valley				Form 10-K/A
Revenues:
Regulated		$	5,737			$	515			$	6,252			$	—		$	(635	)		$	—			$	5,617
Non-Regulated		5,349				(580		)		4,769				(33		)	—				(33		)		4,703
Total revenues		11,086				(65		)		11,021				(33		)	(635		)		(33		)		10,320
Cost of Sales:
Regulated		(4,500		)		82				(4,418		)		—			397				—				(4,021		)
Non-Regulated		(3,408		)		4				(3,404		)		(1		)	—				34				(3,371		)
Total cost of sales		(7,908		)		86				(7,822		)		(1		)	397				34				(7,392		)
Gross margin		3,178				21				3,199				(34		)	(238		)		1				2,928
General and administrative expenses		(221		)		(4		)		(225		)		—			—				—				(225		)
Interest expense		(1,896		)		3				(1,893		)		—			67				—				(1,826		)
Interest income		391				4				395				—			(20		)		—				375
Other expense		19				(151		)		(132		)		—			22				—				(110		)
Other income		—				171				171				—			(14		)		—				157
Gain (loss) on sale of investments		—				—				—				—			—				—				—
Loss on sale of subsidiary stock		—				—				—				—			—				—				—
Asset impairment expense		—				(16		)		(16		)		—			—				—				(16		)
Foreign currency transaction losses on net monetary position		(89		)		(12		)		(101		)		—			(44		)		—				(145		)
Equity in earnings of affiliates		76				(6		)		70				—			1				—				71
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST		1,458				10				1,468				(34		)	(226		)		1				1,209
Income tax expense		(465		)		(60		)		(525		)		(3		)	46				(1		)		(483		)
Minority interest expense		(361		)		(8		)		(369		)		19			26				—				(324		)
INCOME FROM CONTINUING OPERATIONS		632				(58		)		574				(18		)	(154		)		—				402
Income (loss) from operations of discontinued businesses net of income tax		—				34				34				—			154				—				188
(Loss) gain from disposal of discontinued businesses net of income		—				—				—				—			—				—				—
INCOME BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		632				(24		)		608				(18		)	—				—				590
Income from extraordinary items net of income tax		—				—				—				—			—				—				—
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		632				(24		)		608				(18		)	—				—				590
Cumulative effect of change in accounting principle net of income tax		(2		)		(1		)		(3		)		—			—				—				(3		)
Net income		$	630			$	(25	)		$	605			$	(18	)	$	—			$	—			$	587

The following table details the impact of both the May 2007 Restatement and the August 2007 Restatement on the Company’s Consolidated Statement of Operations for the year ended December 31, 2004:

	Year Ended December 31, 2004
	As Originally				May 2007				2006				August 2007				Discontinued Operations							2006
	Filed				Restatement				Form 10-K				Restatement				EDC			Central Valley				Form 10-K/A
Revenues:
Regulated		$	4,897			$	275			$	5,172			$	—		$	(619	)		$	—			$	4,553
Non-Regulated		4,566				(346		)		4,220				10			—				(38		)		4,192
Total revenues		9,463				(71		)		9,392				10			(619		)		(38		)		8,745
Cost of Sales:
Regulated		(3,781		)		71				(3,710		)		—			382				—				(3,328		)
Non-Regulated		(2,900		)		9				(2,891		)		(3		)	—				35				(2,859		)
Total cost of sales		(6,681		)		80				(6,601		)		(3		)	382				35				(6,187		)
Gross margin		2,782				9				2,791				7			(237		)		(3		)		2,558
General and administrative expenses		(182		)		1				(181		)		—			—				—				(181		)
Interest expense		(1,932		)		12				(1,920		)		—			104				—				(1,816		)
Interest income		282				1				283				—			(29		)		—				254
Other expense		12				(135		)		(123		)		—			10				—				(113		)
Other income		—				157				157				—			(7		)		—				150
Gain (loss) on sale of investments		(45		)		44				(1		)		—			—				—				(1		)
Loss on sale of subsidiary stock		—				(24		)		(24		)		—			—				—				(24		)
Asset impairment expense		—				(50		)		(50		)		—			1				—				(49		)
Foreign currency transaction losses on net monetary position		(165		)		29				(136		)		—			27				—				(109		)
Equity in earnings of affiliates		70				(7		)		63				—			—				—				63
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST		822				37				859				7			(131		)		(3		)		732
Income tax expense		(359		)		(21		)		(380		)		(3		)	18				—				(365		)
Minority interest expense		(199		)		(12		)		(211		)		—			16				—				(195		)
INCOME FROM CONTINUING OPERATIONS		264				4				268				4			(97		)		(3		)		172
Income (loss) from operations of discontinued businesses net of income		34				(93		)		(59		)		—			97				3				41
(Loss) gain from disposal of discontinued businesses net of income		—				91				91				—			—				—				91
INCOME BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		298				2				300				4			—				—				304
Income from extraordinary items net of income tax		—				—				—				—			—				—				—
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		298				2				300				4			—				—				304
Cumulative effect of change in accounting principle net of income		—				—				—				—			—				—				—
Net income		$	298			$	2			$	300			$	4		$	—			$	—			$	304

The following table details the impact of the August 2007 Restatement on the Company’s Consolidated Balance Sheet as of December 31, 2006:

	As of December 31, 2006
	2006				August 2007				Discontinued Operations							2006
	Form 10-K				Restatement				EDC			Central Valley				Form 10-K/A
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	1,575			$	—		$	(191	)		$	(5	)		$	1,379
Restricted cash		548				—			—				—				548
Short—term investments		640				—			—				—				640
Accounts receivable, net of reserves of $233		1,903				—			(129		)		(5		)		1,769
Inventory		518				—			(45		)		(2		)		471
Receivable from affiliates		81				—			(5		)		—				76
Deferred income taxes—current		213				—			(5		)		—				208
Prepaid expenses		113				—			(4		)		—				109
Other current assets		943				—			(16		)		—				927
Current assets of held for sale and discontinued businesses		31				—			395				12				438
Total current assets		6,565				—			—				—				6,565
NONCURRENT ASSETS
Property, Plant and Equipment:
Land		950				—			(19		)		(3		)		928
Electric generation and distribution assets		23,990				—			(2,133		)		(22		)		21,835
Accumulated depreciation		(6,979		)		—			427				7				(6,545)
Construction in progress		1,113				—			(133		)		(1		)		979
Property, plant and equipment, net		19,074				—			(1,858		)		(19		)		17,197
Other assets:
Deferred financing costs, net of accumulated amortization of $188		285				—			(6		)		—				279
Investments in and advances to affiliates		596				—			(1		)		—				595
Debt service reserves and other deposits		524				—			—				—				524
Goodwill, net		1,419				—			—				(3		)		1,416
Other intangible assets, net of accumulated amortization of $171		305				—			(6		)		(1		)		298
Deferred income taxes—noncurrent		663				—			(59		)		(2		)		602
Other assets		1,627				28			(20		)		(1		)		1,634
Noncurrent assets of held for sale and discontinued businesses		105				—			1,950				36				2,091
Total other assets		5,524				28			1,858				29				7,439
TOTAL ASSETS		$	31,163			$	28		$	—			$	10			$	31,201
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	892			—			$	(96	)		$	(1	)		$	795
Accrued interest		412				—			(8		)		—				404
Accrued and other liabilities		2,227				—			(95		)		(1		)		2,131
Recourse debt-current portion		—				—			—				—				—
Non-recourse debt-current portion		1,453				—			(42		)		—				1,411
Current liabilities of held for sale and discontinued businesses		45				—			241				2				288
Total current liabilities		5,029				—			—				—				5,029
LONG-TERM LIABILITIES						—
Non-recourse debt		10,102				—			(268		)		—				9,834
Recourse debt		4,790				—			—				—				4,790
Deferred income taxes-noncurrent		790				9			(6		)		10				803
Pension liabilities and other post-retirement liabilities		883				—			(39		)		—				844
Other long-term liabilities		3,371				242			(57		)		(2		)		3,554
Long-term liabilities of held for sale and discontinued businesses		62				—			370				2				434
Total long-term liabilities		19,998				251			—				10				20,259
Minority Interest (including discontinued businesses of $175		3,100				(152		)	—				—				2,948
Commitments and Contingent Liabilities (see Notes 10 and 11)
STOCKHOLDERS’ EQUITY
Common stock ($.01 par value, 1,200,000,000 shares authorized; 665,126,309 issued and outstanding at December 31, 2006		7				—			—				—				7
Additional paid-in capital		6,654				—			—				—				6,654
Accumulated deficit		(1,025		)		(71		)	—				—				(1,096		)
Accumulated other comprehensive loss		(2,600		)		—			—				—				(2,600		)
Total stockholders’ equity		3,036				(71		)	—				—				2,965
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY		$	31,163			$	28		$	—			$	10			$	31,201

The following table details the impact of both the May 2007 and the August 2007 Restatements on the Company’s Consolidated Balance Sheet as of December 31, 2005:

	As of December 31, 2005
	As Originally				May 2007				2006				August 2007				Discontinued Operations							2006
	Reported				Restatement				Form 10-K				Restatement				EDC			Central Valley				Form 10-K/A
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	1,390			$	(69	)		$	1,321			$	—		$	(144	)		$	(1	)		$	1,176
Restricted cash		420				57				477				—			(40		)		—				437
Short-term investments		203				(4		)		199				—			—				—				199
Accounts receivable, net of reserves of $260		1,615				33				1,648				—			(127		)		(4		)		1,517
Inventory		460				(3		)		457				—			(34		)		(2		)		421
Receivable from affiliates		2				71				73				—			(2		)		—				71
Deferred income taxes—current		267				3				270				—			(12		)		—				258
Prepaid expenses		119				—				119				—			(6		)		—				113
Other current assets		756				(68		)		688				—			(18		)		—				670
Current assets of held for sale and discontinued businesses		—				35				35				—			383				7				425
Total current assets		5,232				55				5,287				—			—				—				5,287
NONCURRENT ASSETS
Property, Plant and Equipment:
Land		860				—				860				—			(20		)		(3		)		837
Electric generation and distribution assets		22,440				(139		)		22,301				—			(2,014		)		(21		)		20,266
Accumulated depreciation		(6,087		)		112				(5,975		)		—			338				5				(5,632		)
Construction in progress		1,441				(594		)		847				—			(166		)		—				681
Property, plant and equipment, net		18,654				(621		)		18,033				—			(1,862		)		(19		)		16,152
Other assets:
Deferred financing costs, net of accumulated amortization of 217		294				(19		)		275				—			(7		)		—				268
Investments in and advances to affiliates		670				(5		)		665				—			(1		)		—				664
Debt service reserves and other deposits		611				(65		)		546				—			—				—				546
Goodwill, net		1,428				(15		)		1,413				—			—				(3		)		1,410
Other intangible assets, net of accumulated amortization of $127		—				284				284				—			(7		)		(1		)		276
Deferred income taxes—noncurrent		807				(24		)		783				—			(85		)		—				698
Other assets		1,736				(327		)		1,409				21			(16		)		(7		)		1,407
Noncurrent assets of held for sale and discontinued businesses		—				265				265				—			1,978				44				2,287
Total other assets		5,546				94				5,640				21			1,862				33				7,556
TOTAL ASSETS		$	29,432			$	(472	)		$	28,960			$	21		$	—			$	14			$	28,995
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	1,104			$	(13	)		$	1,091			—			$	(90	)		$	(3	)		$	998
Accrued interest		382				(2		)		380				—			(7		)		—				373
Accrued and other liabilities		2,122				(15		)		2,107				—			(67		)		(3		)		2,037
Recourse debt—current portion		200				—				200				—			—				—				200
Non-recourse debt—current portion		1,598				(151		)		1,447				—			(79		)		(1		)		1,367
Current liabilities of held for sale and discontinued businesses		—				51				51				—			243				7				301
Total current liabilities		5,406				(130		)		5,276				—			—				—				5,276
LONG-TERM LIABILITIES
Non-recourse debt		11,226				(588		)		10,638				—			(320		)		—				10,318
Recourse debt		4,682				—				4,682				—			—				—				4,682
Deferred income taxes-noncurrent		721				56				777				6			(8		)		14				789
Pension liabilities and other post-retirement liabilities		857				8				865				—			(36		)		—				829
Other long-term liabilities		3,280				54				3,334				48			(43		)		(2		)		3,337
Long-term liabilities of held for sale and discontinued businesses		—				136				136				—			407				2				545
Total long-term liabilities		20,766				(334		)		20,432				54			—				14				20,500
Minority Interest (including discontinued businesses of $122		1,611				15				1,626				(19		)	—				—				1,607
Commitments and Contingent Liabilities (see Notes 10 and 11)
STOCKHOLDERS’ EQUITY
Common stock ($.01 par value, 1,200,000,000 655,882,836 shares issued and outstanding at December 31, 2005		7				—				7				—			—				—				7
Additional paid-in capital		6,517				44				6,561				—			—				—				6,561
Accumulated deficit		(1,214		)		(72		)		(1,286		)		(14		)	—				—				(1,300		)
Accumulated other comprehensive loss		(3,661		)		5				(3,656		)		—			—				—				(3,656		)
Total stockholders’ equity		1,649				(23		)		1,626				(14		)	—				—				1,612
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY		$	29,432			$	(472	)		$	28,960			$	21		$	—			$	14			$	28,995

B. Narrative Discussion of Adjustments and Reclassifications

The following narrative explains the combined restatement adjustments and reclassifications that have been presented in both the 2006 Form 10-K filed on May 23, 2007 and this Form 10-K/A. The narrative is presented in three subsections, “Adjustments contained in the May 2007 Restatement;” “Adjustments presented in the August 2007 Restatement,” which presents adjustments made since the May 2007 Restatement; and Reclassifications into Discontinued Operations presented in this Form 10-K/A.

1. Adjustments contained in the May 2007 Restatement

Background

The Company had 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.

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 the 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 remediate 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 ended 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 May 2007 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/A.

The May 2007 Restatement adjustments included several key categories as described below:

Brazil Adjustments

Prior year errors related to certain subsidiaries in Brazil included 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.

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, included 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. The above noted adjustments related to EDC have been reclassified into discontinued operations for all periods presented in this Form 10-K/A.

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 included 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.

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 affiliates 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.

Income Tax Adjustments

Income tax adjustments related 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. These receipts. called “special obligations” were previously offset against property, plant and equipment. 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. See further discussion regarding additional pre-acquisition special obligations in August 2007 Restatement.

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 its 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-recourse debt of $579 and $497 million at December 31, 2005 and 2004, respectively.

Restricted Cash

reduction in cash and cash equivalents and an increase in restricted cash by $63 million and $97 million, in 2005 and 2004, respectively.

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 recorded adjustments to its prior financial statements that resulted 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, was quantitatively material to any period presented.

In addition, the Company identified accounting for share-based compensation as a material weakness and 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/A 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 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.

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 is as follows:

	Pre-Tax			After-Tax
Fiscal Year Ended (in millions)	Expense			Expense
2000		$	8		$	6
2001		$	15		$	11
2002		$	8		$	5
2003		$	4		$	3
2004		$	—		$	—
2005		$	1		$	1

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

None of these adjustments, individually or in the aggregate, was quantitatively material to any period presented; however, the Company reflected 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 were adjusted for the years ended 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 reflected 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.

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 was based primarily upon measurement date changes. The adjustments reflected 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 determined that certain modifications were calculated using an incorrect method and others were not communicated to appropriate accounting personnel. The most significant modification related 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 recorded a $3 million charge to account for this error for the year 2003.

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 that required 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 was approximately $23 million. Of that amount, approximately $4 million resulted from the changes to the on-cycle grants to Executive Officers and Senior Leaders. Of the remaining amount, approximately $17 million resulted from the changes to the on-cycle grants to all other employees, and approximately $2 million resulted from off-cycle grants.

For grants made in 2001, the total charge resulting from the LTC Review was approximately $8.7 million. Of that amount, approximately $7 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 million resulted from off-cycle grants.

For grants made in 2003, the total charge was approximately $6 million. Of this amount, $3 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

limited in scope as noted herein. Based on the information to date, the Company 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 noted 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.

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 were 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.

2. Adjustments presented in the August 2007 Restatement

Special Obligations in Brazil Subsidiaries

During October 2006, the National Agency for Electric Energy (“ANEEL”), which regulates our utility operations at AES Sul and AES Eletropaulo in Brazil, issued Normative Resolution 234 (the “Resolution”) requiring that utilities begin amortizing a liability called “Special Obligations” beginning with their second tariff reset cycle in 2007 or a later year as an offset to depreciation expense. This was followed by additional ANEEL guidance and clarifying communications. In February 2007, ANEEL issued Circular 236 and 296, both of which discussed the timing of when the amortization for Special Obligations liabilities should begin. In June 2007, ANEEL issued another resolution, Circular 1314, stating that two February 2007 resolutions (236 and 296) were no longer in force.

For AES Eletropaulo and AES Sul, the second tariff reset cycles start July 2007 and April 2008, respectively. Upon further review and interpretation of the resolution, the Company has determined that an adjustment should have been recorded to its financial statements for the year ended December 31, 2006 to reflect the Special Obligation requirements of the Resolution as a regulatory liability.

Special Obligations represent consumers’ contributions to the cost of expanding the electric power supply system. Property plant and equipment assets, regardless of the source of funds to acquire them, are depreciated based on the respective assets’ useful lives, as established by ANEEL for regulatory purposes. The Special Obligation liability was not previously amortized as a reduction of allowable costs for tariff or Brazilian Accounting Principles. The purpose of the Resolution is to adjust the tariff prospectively to offset the allowable cost for depreciation on these assets with amortization of the special obligation liability.

Upon issuance of the Resolution in October 2006 and throughout the subsequent clarifications issued through ANEEL, the Company evaluated the impact on its financial statements including discussing certain aspects of the issue with the Brazilian affiliate of its external audit firm. Accordingly, an adjustment was recorded in 2006 to its reported “Special Obligations” liability to reverse amortization at AES Sul to conform to its accounting for Special Obligations at AES Eletropaulo and with the reporting requirements of the ANEEL guidance. The Company consulted with the Brazilian affiliate of its external audit firm, in reaching this conclusion.

In 1997 and 1998, the Company acquired a 91% and 10% interest in AES Sul and AES Eletropaulo, respectively, under a concession agreement that allows AES to deliver service through 2027. Currently the Company owns a 100% and 16% acquired interest in AES Sul and AES Eletropaulo, respectively. At the time of acquisition, the fair value of Special Obligation liabilities (“the pre-acquisition liability”) was evaluated but was assigned a fair value of zero because it was not considered probable that the obligation would be required to be repaid or amortized as a reduction of allowable costs through the tariff. Given the Resolution, AES is required to establish the liability for U.S. GAAP purposes that would have existed as of the original purchase date, and then begin amortizing that liability in the future consistent with the prospective amortization for tariff purposes. The Company has recorded the establishment of this liability through a fourth quarter 2006 charge of $139 million to Other Expense. As a result of the Company’s consolidation of AES Eletropaulo, there is an offsetting reduction of $108 million to Minority Interest Expense.

The Company considered “the pre-acquisition liability” that was fair-valued at zero at the time of acquisition to determine whether the Resolution was a triggering event that would now make this liability probable as a reduction of allowable cost under tariff. The Company consulted with the Brazilian affiliate of its external audit firm regarding the pre-acquisition liability and determined that as of May 23, 2007, the

date of the filing of our 2006 Form 10-K, no industry positions or any other consensus had been reached regarding how ANEEL guidance should be applied at that date and accordingly, the Brazilian affiliate of its external audit firm was in agreement with the Company that no adjustments to the financial statements were made relating to Special Obligations in Brazil. Subsequent to May 23, 2007, industry discussions occurred and other Brazilian companies filed Forms 20-F with the SEC reflecting the impact of the Resolution in their December 31, 2006 financial statements. In the absence of any significant regulatory developments between May 23, 2007 and the date of these other filings, we now believe, and our auditors agree, that the October 2006 resolution issued by ANEEL required us to record an adjustment to our Special Obligations liability as of December 31, 2006.

While future cash flows will be reduced as a result of the offset to depreciation expense by the required amortization of the Special Obligation liability being included in the tariff, future gross margin and income from continuing operations will not be affected by this change.

Lease Accounting

In connection with the Company’s continued remediation efforts related to internal controls over financial reporting, the Company noted the certain errors that were discovered relating to its accounting for leases at its AES Southland subsidiary, a wholly-owned North American Generations business and its Pakistan subsidiary, a majority-owned Asia Generation business.

Both AES Southland and AES Pakistan executed power purchase agreements (“PPA’s”) with third party offtakers. Pursuant to the agreement at AES Southland, the third party offtaker calls on each unit as needed and in turn pays a fixed capacity payment and a variable payment for energy. Southland is not permitted to substitute dispatch from one unit to another. Capacity payments are specified in the agreement on a unit-by-unit basis and the variable energy payment is indexed to inflation. Pursuant to a settlement agreement between the offtaker and AES Pakistan, the offtaker agreed to resolve a historical capacity dispute, which recognized the right for AES to bill from both plants an additional available capacity above the previously determined Capped Capacity. This differential billing was to be billed on an amended rate schedule. The payments of the differential capacity per the amended rate schedule created a modification of the cashflows of the initial PPA agreement.

In accordance with EITF 01-08, “Determining Whether an Arrangement Contains a Lease” (“EITF 01-08”), an entity must reassess whether an arrangement requires lease accounting when certain changes including contractual terms; renewal or extension or changes in fulfillment of the arrangement exist. Upon reassessment of the arrangement and the subsequent modifications, the Company determined that the PPA with the third party offtakers in both cases qualified as a lease under the provisions of EITF 01-08. As a result, the revenue generated from the capacity payments should be accounted for on a straight-line basis. impact on net income as a result of the correction of these errors is an decrease of $26 million and $18 million and in 2006 and 2005, respectively and an increase of $4 million in 2004.

For these restatements the Company determined that the remediation efforts relative to its previously reported material weakness related to accounting for certain derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, was in fact viewed more broadly by the Company in the context of controls related to the accounting for contracts in general; specifically, the material weakness was viewed as a lack of sufficient controls designed to ensure the adequate analysis and documentation at inception and on an ongoing basis of whether or not certain contracts were adequately accounted for in accordance with U.S. GAAP. As such, the Company revised the title and description of the previously disclosed “Derivative Accounting” material weakness to reflect the above described broader view. Accordingly, the Company determined that no revision to the related remediation plan, as previously disclosed in the Company 2006 Form 10-K, was needed.

3. Reclassifications into Discontinued Operations presented in this Form 10-K/A

The Company reported discontinued operations in its Form 10-Q for the quarter ended March 31, 2007, as a result of the previously disclosed sales of EDC and Central Valley. As required by Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets,” presentation of the results of operations of these businesses through the date of sale are now reported in “Income (Loss) from Operations of Discontinued Businesses” in the Consolidated Statement of Operations. Correspondingly, the assets and liabilities of these businesses are reclassified to assets and liabilities ‘held for sale” in the Consolidated Balance Sheets. In accordance with SEC guidelines, when a company files or amends its annual financial statements as of a date on or after the date the company reports discontinued operations, the company must present the financial information in those prior period financial statements to reflect the discontinued operations. Accordingly, certain financial information presented in this Form 10-K/A has been conformed to the presentation of the discontinued operations in our first quarter 2007 Form 10-Q.

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.

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”), Compañia, S. En C. de C.V. (“AES CLESA”), Distribuidora Electrica de Usulután, 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 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 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

Since the Company’s filing of its 10-K, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan has continued to prosecute antimonopoly claims against two hydro plants under AES concession, Ust Kamenogorsk HPP and Shulbinsk HPP (collectively, “Hydros”), and an AES trading company, Nurenergoservice LLP. In addition, subsequent to the filing of the 10-K, the Competition Committee has asserted antimonopoly claims against another AES company, AES Ust-Kamengorskaya TET LLP (“UKT”).

In February 2007, the Competition Committee initiated administrative proceedings against the Hydros for allegedly using Nurenergoservice to increase power prices for consumers in alleged violation of Kazakhstan’s antimonopoly laws. The Competition Committee issued orders directing the Hydros to pay approximately 2.7 billion KZT (US$22 million) for alleged antimonopoly violations in 2005 through January 2007. The Hydros challenged the orders and the Competition Committee brought suit to enforce the orders in local court. In June 2007, the local court ruled in the Competition Committee’s favor, recalculated the damages, and ordered the Hydros to pay approximately 2.8 billion KZT (US$23 million) and terminate their contracts with Nurenergoservice. The Hydros appealed and, in July 2007, the first panel of the court of appeals overturned the local court’s decision and vacated the Competition Committee’s orders for inadequate investigation. The Competition Committee subsequently initiated an investigation of the Hydro’s alleged antimonopoly violations. The Competition Committee has stated that it will complete its investigation by September 14, 2007.

Also, in June 2007, the Competition Committee ordered AES Ust-Kamengorskaya TET LLP (“UKT”) to pay approximately 940 million KZT (US$8 million) in damages and fines to the state for alleged antimonopoly violations in 2005 through January 2007, and to pay damages to certain consumers that allegedly had been charged unreasonable power prices since January 2007. The Competition Committee does not quantify the damages allegedly owed to those consumers, but UKT estimates that such damages might equal or exceed approximately 235 million KZT (US$2 million). UKT has filed an administrative appeal of that order. The Competition Committee has stated that it will complete its review of UKT’s administrative appeal by August 20, 2007. If UKT does not prevail on administrative appeal and loses in any proceedings before the local court of first instance and the first panel of the court of appeals, UKT will have to pay the full amount of antimonopoly damages established in those court proceedings in order to be able to pursue further appeals of the antimonopoly claims asserted against it.

Furthermore, in July 2007 the Competition Committee ordered Nurenergoservice to pay approximately 17.8 billion KZT (US$147 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. That order supersedes the Competition Committee order against Nurenergoservice that is disclosed in the Company’s 10-Q for the first quarter of 2007. The Competition Committee has ordered Nurenergoservice to appear for a hearing on August 8, 2007, concerning Nurenergoservice’s alleged antimonopoly violations. Nurenergoservice has filed an administrative appeal of the July 2007 order. If Nurenergoservice does not prevail on administrative appeal and loses in any proceedings before the local court of first instance and the first panel of the court of appeals, Nurenergoservice will have to pay the full amount of antimonopoly damages established in those court proceedings in order to be able to pursue further appeals of the antimonopoly claims asserted against it.

The Competition Committee has not indicated whether it intends to assert claims against the Hydros and/or UKT for alleged antimonopoly violations post January 2007 and/or against Nurenergoservice for alleged antimonopoly violations post first quarter 2007. The Hydros, UKT, and Nurenergoservice believe they have meritorious defenses and will assert them vigorously in the above-referenced proceedings; however, there can be no assurances that they will be successful in their efforts.

In related proceedings, in March 2007 the local financial police initiated criminal proceedings against the General Director and the Finance Director of the Hydros, seeking from them approximately 1.6 billion KZT (US$13 million) in alleged damages relating to the Hydros’ alleged antimonopoly violations. Those criminal proceedings were later terminated pursuant to a settlement.

As of the date of this filing, we are in default under our secured and unsecured credit facilities as a result of the August 2007 Restatement. In addition, we need to obtain waivers of this default relating to our previously delivered financial statements before we will be able to borrow additional funds under our credit facilities. The Company is pursuing waivers with its senior bank lenders and expects to obtain them in the near term.

Segments

Beginning with this Annual Report on Form 10-K/A, 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 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 11,217 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 capacities 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 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 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 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 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 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.

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.

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.

	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.

Segment—Latin America Generation

							Year
				AES Equity			Acquired or
			Gross	Interest			Began
Business	Location	Fuel	M W	(Rounded)			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

Generation under construction

Expected

Year of

Gross

AES Equity Interest

Commercial

Business

Location

Fuel

M W

(Rounded)

Operation

Guacolda III

Chile

Coal

152

2009

Ventanas III

Chile

Coal

267

2010

Changuinola

Panama

Hydro

223

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

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

Distribution

		Approximate
		Number of		Approximate
		Customers Served as		Gigawatt Hours		AES Equity Interest			Year
Business	Location	of 12/31/2006		Sold in 2006		(Rounded)			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

Distribution businesses under AES management

		Approximate
		Number of	Approximate
		Customers Served as	Gigawatt Hours	AES Equity Interest
Business	Location	of 12/31/2006	Sold in 2006	(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

								Year
								Acquired or
					AES Equity Interest			Began
Business(1)	Location	Fuel	Gross M W		(Rounded)			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

Segment—North America Utilities

Year

Acquired or

AES Equity Interest

Began

Business

Location

Fuel

Gross M W

(Rounded)

Operation

IPL(1)

USA - IN

Coal/Gas/Oil

3,599

100%

2001

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

Distribution

Approximate

Number of

Approximate

Customers Served as

Gigawatt Hours

AES Equity Interest

Year

Business

Location

of 12/31/2006

Sold in 2006

(Rounded)

Acquired

IPL

USA - IN

468,867

16,287

100%

2001

Segment—Europe & Africa Generation

								Year
								Acquired or
					AES Equity Interest			Began
Business(1)	Location	Fuel	Gross M W		(Rounded)			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

Generation under construction

Expected

Year of

AES Equity Interest

Commercial

Business

Location

Fuel

Gross M W

(Rounded)

Operation

Maritza East I

Bulgaria

Lignite

670

100%

2009

Segment—Europe & Africa Utilities

Year

Acquired

AES Equity Interest

or Began

Business

Location

Fuel

Gross M W

(Rounded)

Operation

SONEL(1)

Cameroon

Hydro/Diesel/Heavy
Fuel Oil

927

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

Generation under construction

Expected

Year of

AES Equity Interest

Commercial

Business

Location

Fuel

Gross M W

(Rounded)

Operation

SONEL(1)

Cameroon

Heavy Fuel Oil

2007

Distribution

		Approximate
		Number of		Approximate
		Customers Served as		Gigawatt Hours		AES Equity Interest			Year
Business	Location	of 12/31/2006		Sold in 2006		(Rounded)			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

Distribution businesses under AES management

Approximate

Number of

Approximate

Customers Served as

Gigawatt Hours

AES Equity Interest

Business

Location

of 12/31/2006

Sold in 2006

(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 ShygysEnergo 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

Segment—Asia Generation

								Year
								Acquired or
						AES Equity Interest		Began
Business	Location	Fuel		Gross M W		(Rounded)		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

Generation under construction

Expected

Year of

AES Equity Interest

Commercial

Business

Location

Fuel

Gross M W

(Rounded)

Operation

Amman East(1)

Jordan

Gas

370

2009

(1) Construction of the Amman East power plant commenced in May, 2007

Alternative Energy (included in Corporate and Other)

Generation

						AES Equity Interest		Year
Business	Location	Fuel		Gross M W		(Rounded)		Acquired or
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.

Alternative Energy businesses under AES management

AES Equity Interest

Business

Location

Fuel

Gross M W

(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

Alternative Energy businesses under construction

Expected

Year of

AES Equity Interest

Commercial

Business

Location

Fuel

Gross M W

(Rounded)

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 December 31, 2006, we employed approximately 32,000 people.

How to Contact AES and Sources of Other Information

Our principal offices are located at 4300 Wilson Boulevard, Arlington, Virginia 22203. Our telephone number is (703) 522-1315. Our website address is http://www.aes.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and any amendments to such reports filed pursuant to section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 are posted on our website. After the reports are filed or furnished with the Securities and Exchange Commission (“SEC”), they are available from us free of charge. Material contained on our website is not part of and is not incorporated by reference in this Form 10-K/A.

Our Chief Executive Officer and our Chief Financial Officer have provided certifications to the SEC as required by Section 302 of the Sarbanes-Oxley Act of 2002. These certifications are included as exhibits to this Annual Report Form 10-K/A.

Our Chief Executive Officer provided a certification pursuant to Section 303A of the New York Stock Exchange Listed Company Manual on May 31, 2006.

Our Code of Business Conduct and Ethics (“Code of Conduct”) and Corporate Governance Guidelines have been adopted by our Board of Directors. The Code of Conduct is intended to govern as a requirement of employment the actions of everyone who works at AES, including employees of our subsidiaries and affiliates. The Code of Conduct and the Corporate Governance Guidelines are located in their entirety on our web site. Any person may obtain a copy of the Code of Conduct or the Corporate Governance Guidelines without charge by making a written request to: Corporate Secretary, The AES Corporation, 4300 Wilson Boulevard, Arlington, VA 22203. If any amendments to or waivers from the Code of Conduct or the Corporate Governance Guidelines are made, we will disclose such amendments or waivers on our website.

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

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

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.

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 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.

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

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

(i) an initial 19% DVA increase effective August 2005, and an additional DVA increase which will be in force in accordance with National Government policies (8% DVA increase was granted effective January 1, 2007);

(ii) penalties recorded during the 2002 to 2005 period will not be paid;

(iii) Quality Service Regime penalties will be reduced; and

(iv) full tariff reset proceedings will be carried out in 2007 with a new tariff in force since February 2008.

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.

Brazil. 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:

· It creates two energy commercialization environments: (1) the regulated contractual environment (ACR), intended for the distribution companies, and (2) the free contract environment (ACL), designed for traders and free consumers.

· As of January 2005, every distribution utility is obligated to meet 100% of its anticipated energy requirements, subject to the application of penalties. Compliance with such obligation requires distribution companies to contract for energy through: (i) auctions of energy from new (proposed) generation projects; (ii) auctions of energy from existing generation facilities; and (iii) other sources, including public calls to purchase energy from distributed generation; renewable energy

sources (through public auctions or the Brazilian Renewable Energy Incentive Program - PROINFA); pre-existing purchases made before Law #10848/04; and purchases from Itaipu.

· Distribution utilities can pass through up to 103% of their contracted load. ANEEL adopted a new pass through methodology in the annual tariff adjustment; and variations of the energy purchase costs are reflected in a tracking account (CVA), which records the monthly price variations of non-manageable costs, both positive and negative, over the course of the year.

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:

· annual tariff adjustments;

· tariff reset; and

· extraordinary revisions, in the event of significant changes in concessionaires’ cost structure.

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, underestimate 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:

(i) Regulatory WACC: same methodology as considered in the 1st Cycle of Tariff Reset, updating the financial indicators. WACC before tax considered is 15.08%. (17.07% in 1st Cycle);

(ii) Reference Company: ANEEL hired consultants to prepare a new methodology for the 2nd Cycle (still pending of definition);

(iii) Bad debts: It is expected that ANEEL promotes a Public Hearing to discuss this item (still pending);

(iv) Regulatory Rate Base:

a. Shielded Rate Base updated by IGPM;

b. Incremental assets (July/2003 to Oct/2006) evaluated though appraisal report;

c. Change in Special Obligations methodology;

(v) X-Factor: It was removed from its calculation the Xc parcel, which captured the consumers’ satisfaction level through an annual survey.

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 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.

Chile. 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 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:

· implementation of public bid processes for distribution companies for their consumptions starting after 2009;

· modification of regulated node price methodology, progressively replacing the node price with public bid prices and improvement in the correlation between regulated node prices and unregulated market prices in the interim period;

· stabilization of generation companies’ revenues by allowing them to enter into long-term fixed price contracts with distribution companies (maximum of 15 years);

· authorization of voluntary savings incentives which allow generation companies to directly negotiate demand reductions with final customers;

· determination that natural gas shortages can no longer be considered force majeure events and compensation to customers by generation companies which fail to operate due to gas shortages; and

· establishment of compensation for losses by generation companies when obligated to sell to distribution companies that are unable to independently contract adequate supplies.

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.

Colombia. 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.

Dominican Republic. 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 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.

El Salvador. 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 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.

Panama. 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 Hidráulicos y 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 under state 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.

North America

United States. 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.

Federal Regulation of Electricity

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.

On August 8, 2005, the President signed into law the Energy Policy Act of 2005 (“EPAct 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 Public Utility Regulatory Policies Act of 1978 (“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 qualifying facilities (“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 Item 3. Legal Proceedings in this Form 10-K/A.

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 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 a return on IPL’s investment and recovery of the depreciation and operation and maintenance expenses associated with the nitrogen oxide (“NOx”) compliance construction program and its multipollutant plan.

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. 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 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 (“AES Tisza”) 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:

· The EU Directive on Integrated Pollution Prevention and Control (1996/61/EC) (“IPPC Directive”) which requires member states to prevent or reduce pollution from a range of installations including electricity generation stations and introduces a permit regime to ensure the prevention or reduction of pollution from such installations.

· The Large Combustion Plants Directive (2001/80/EC) (“LCPD”) which introduced a regime for the reduction of emissions sulphur dioxide, nitrogen oxides and particulates from large combustion plants, with increased restrictions coming into effect in two phases from 2008 and 2016, respectively.

· The Renewables Directive (2001/77/EC) which deals with the promotion of electricity generated from renewable sources and sets a target of 12% of electricity consumed in the EU to be generated from renewable sources by 2010.

· The EU Emissions Trading Directive (2003/87/EC) which, among other things, established the EU Emissions Trading Scheme (“EUETS”) in respect of emissions of carbon dioxide effective January 1, 2005.

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.

Hungary. 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 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.

Kazakhstan. 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 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 (“UK Hydro”) 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. Nurenergoservice LLP and DostykEnergo 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 Nurenergoservice LLP for alleged violation of Kazakhstan’s antimonopoly laws. See Item 3. Legal Proceedings in this Form 10-K/A

Ukraine. 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 operates in a wholesale energy market model, under which AES Ukraine procures electricity from the wholesale energy market (hereinafter “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 the restructured 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 National Energy Regulatory Commission (“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 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.

United Kingdom. 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.

Cameroon. 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 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, sets the rates and basis for the calculation, recovery and distribution of royalties due by operators in the electricity sector, and spells 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

China. 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.

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. 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 US 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.

Environmental and Land Use Regulations

Overview. The Company is subject to various international, national, state and local environmental and land use laws and regulations. These laws and regulations primarily relate to discharges into the air and air quality, discharge of effluents into water and the use of water, waste disposal, remediation, noise pollution, contamination at current or former facilities or waste disposal sites, wetlands preservation and endangered species. 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 Item 7—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.

Air Emissions. The U.S. Clean Air Act and various state laws and regulations regulate emissions of air pollutants, including sulfur dioxide (“SO2”), nitrogen oxides (“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, Indianapolis Power and Light (“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 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. 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 large combustion plants (the “LCPD”), which sets emission limit values for NOx, SO2, and particulate matter for large-scale industrial combustion plants for all member states. Until June 2004, existing coal plants could “opt-in” or “opt-out” of the LCPD emissions standards. Those plants that opted out will be required to cease all operations by 2015 and may not operate for more than 20,000 hours after 2008. Those that 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 offtakers, 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.

Water Discharges. The Company’s facilities are subject to a variety of rules governing water discharges. In particular the Company is evaluating the impact of the U.S. Clean Water Act Section 316(b) rule regarding existing power plant cooling water intake structures issued by the U.S. EPA in 2004 (69 Fed. 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.

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

ITEM 1A. RISK FACTORS

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

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

Our disclosure controls and procedures and internal control over financial reporting were determined not to be effective as of 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. 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 more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. Our management concluded that as of 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 Securities Exchange Act of 1934 was recorded, processed, summarized and reported accurately. For a discussion of the material weaknesses reported by AES’s management as of December 31, 2006 and December 31, 2005 see Item 9A of this 2006 Annual Report on Form 10-K/A.

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 our Annual Report on Form 10-K for the year ended December 31, 2004 and our 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. In addition, 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 10-K’s and 10-Q’s for a fourth time. 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.

In the third quarter of 2007, as a result of new controls implemented during remediation of material weaknesses, the Company identified additional errors relating to lease accounting at its Southland and Pakistan subsidiaries. In part, these errors necessitated the filing of this Form 10-K/A, along with other adjustments described throughout this Form 10-K/A.

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 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.

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 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 2005 and 2006 annual 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 lender 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 facilities and indentures could occur. In addition, the material weaknesses in internal control, the restatements, and the delay in the filing of our quarterly reports and any similar problems in the future could have other adverse effects on our business, including, but not limited to:

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

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

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

· negative publicity;

· ratings downgrades; or

· the loss or impairment of investor confidence in the Company.

Risks Related to our High Level of Indebtedness

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

As of December 31, 2006, we had approximately $16.0 billion of outstanding indebtedness on a consolidated basis. All outstanding borrowings under The AES Corporation’s Senior Secured Credit Facility, our Second Priority Senior Secured Notes and certain other indebtedness are secured by certain of our assets, including the pledge of capital stock of many of The AES Corporation’s directly-held subsidiaries. Most of the debt of The AES Corporation’s subsidiaries is secured by substantially all of the assets of those subsidiaries. Since we have such a high level of debt, a substantial portion of cash flow from operations must be used to make payment on this debt. Furthermore, since a significant percentage of our assets are used to secure this debt, this reduces the amount of collateral that is available for future secured debt or credit support and reduces our flexibility in dealing with these secured assets. This high level of indebtedness and related security could have other important consequences to us and our investors, including:

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

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

· increasing our vulnerability to general adverse economic and industry conditions;

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

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

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

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

The agreements governing our indebtedness, including the indebtedness of our subsidiaries, limit but do not prohibit the incurrence of additional indebtedness. To the extent we become more leveraged, the risks described above would increase. Further, our actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due.

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

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

However, our subsidiaries face various restrictions in their ability to distribute cash to The AES Corporation. Most of the subsidiaries are obligated, pursuant to loan agreements, indentures or project financing arrangements, to satisfy certain restricted payment covenants or other conditions before they 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 therefore, whether by dividends, fees, loans or other payments. While some of The AES Corporation’s subsidiaries guarantee its indebtedness under its Senior Secured Credit Facility and certain other indebtedness, none of its subsidiaries guarantee, or are otherwise obligated with respect to, its outstanding public debt securities.

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

We attempt to finance our domestic and foreign projects primarily under loan agreements and related documents which, except as noted below, require the loans to be repaid solely from the project’s revenues

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

As of December 31, 2006, we had approximately $16.0 billion of outstanding indebtedness on a consolidated basis, of which approximately $4.8 billion was recourse debt of The AES Corporation and approximately $11.2 billion was non-recourse debt. In addition, at December 31, 2006, The AES Corporation had provided:

· financial and performance related guarantees or other credit support commitments to or for the benefit of its subsidiaries, which were limited by the terms of the agreements, to an aggregate of approximately $533 million; and

· $461 million in letters of credit outstanding and $1 million in surety bonds outstanding, which operate to guarantee performance relating to certain project construction and development activities and subsidiary operations.

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 $245 million at December 31, 2006. While the lenders under our non-recourse project financings generally do not have direct recourse to The AES Corporation (other than to the extent of any credit support given by The AES Corporation), defaults there under can still have important consequences for The AES Corporation, including, without limitation:

· reducing The AES Corporation’s receipt of subsidiary dividends, fees, interest, loan and other sources of cash since the project subsidiary will typically be prohibited from distributing cash to The AES Corporation during the pendancy of any default;

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

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

· triggering defaults in The AES Corporation’s outstanding debt and trust preferred instruments. For example, The AES Corporation’s Senior Secured Credit Facility and outstanding senior notes include events of default for certain bankruptcy related events involving material subsidiaries. In addition, The AES Corporation’s Senior Secured Credit Facility includes certain events of default relating to accelerations of outstanding debt of material subsidiaries; or

· the loss or impairment of investor confidence in the Company.

None of the projects that are currently in default are owned by subsidiaries that meet the applicable definition of materiality in The AES Corporation’s Senior Secured Credit Facility in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. However, as a result of future write down of assets, dispositions and other matters that affect our financial position and results

of operations, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration of such subsidiary’s debt, trigger an event of default and possible acceleration of the indebtedness under The AES Corporation’s Senior Secured Credit Facility.

Risks Associated with our Ability to Raise Needed Capital

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

The AES Corporation requires cash primarily to fund:

· principal repayments of debt;

· interest and preferred dividends;

· acquisitions;

· construction and other project commitments;

· other equity commitments, including business development investments;

· taxes; and

· parent company overhead costs.

The AES Corporation’s principal sources of liquidity are:

· dividends and other distributions from its subsidiaries;

· proceeds from debt and equity financings at the parent company level; and

· proceeds from asset sales.

For a more detailed discussion of The AES Corporation’s cash requirements and sources of liquidity, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” in this 2006 Form 10-K/A.

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:

· general economic and capital market conditions;

· the availability of bank credit;

· investor confidence;

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

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

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 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. As our Venezuelan business identifies the U.S. dollar as its functional currency, no deferred translation gains or losses are recognized. However, devaluation of the Venezuelan bolivar has resulted in foreign currency transaction gains associated with U.S. dollar at this subsidiary. 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:

· plant availability;

· competition;

· demand for energy commodities;

· electricity usage;

· seasonality;

· interest rate and foreign exchange rate fluctuation;

· availability and price of emission credits;

· input prices;

· weather;

· illiquid markets;

· transmission or transportation constraints or inefficiencies;

· availability of competitively priced alternative energy sources;

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

· generating unit performance;

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

· energy, market and environmental regulation, legislation and policies;

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

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

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.

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:

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

· adverse changes in currency exchange rates;

· government restrictions on converting currencies or repatriating funds;

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

· high inflation and monetary fluctuations;

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

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

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

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

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

· adverse changes in government tax policy;

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

· potentially adverse tax consequences of operating in multiple jurisdictions.

Any of these factors, by itself or in combination with others, could materially and adversely affect our business, results of operations and financial condition. For example, we recently sold our stake in EDC to PDVSA, a state owned company in Venezuela after Venezuelan President Hugo Chavez threatened to expropriate the electricity business in Venezuela. 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.

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

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

· equipment failure causing unplanned outages;

· failure of transmission systems;

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

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

· environmental compliance.

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 to keep it operating at peak efficiency. 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 the 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 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 there under, 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 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:

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

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

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

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:

· we will be successful in transitioning them to private ownership;

· such businesses will perform as expected;

· we will not incur unforeseen obligations or liabilities;

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

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

In 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. In Brasiliana, for example, where we have a controlling equity position, BNDES (or its affiliates) own more than 49 percent of the voting equity. If BNDES decides to sell all of its shares, it has “drag along” rights with respect to our shares, which means that, if BNDES finds a third party buyer that wants to purchase its shares and our shares, BNDES has the right to cause us to sell our shares in Brasiliana to this buyer. We do have certain protections against this drag along right, such as the price must be at least the fair market value of the shares, and we have a right to acquire all of BNDES shares at this same price. Nevertheless, if we declined to purchase the BNDES shares, we could be forced to sell our interest.

Our Alternative Energy businesses face uncertain operational risks.

In many instances, our Alternative Energy businesses target industries that are created by, or 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 priced 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:

· changes in the determination, definition or classification of costs to be included as reimbursable or pass-through costs;

(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 preceeding 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.

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

Restatement of Consolidated Financial Statements

The accompanying management’s discussion and analysis of financial condition and results of operations set forth in this Item 7 has been restated to reflect the correction of errors that were contained in the Company’s consolidated financial statements and other financial information for the years ended December 31, 2002 through 2006 as discussed below and in Note 1 of the Consolidated Financial Statements. In addition, the prior period financial statements have been restated to reflect the change in the Company’s segments as discussed below and in Note 22 of the Consolidated Financial Statements. The following management’s discussion and analysis of financial condition and results of operations should be read in conjunction with our restated Consolidated Financial Statements and the related Notes. In this Form 10-K/A, the term “August 2007 Restatement” refers collectively to the errors related to special obligations liabilities at the AES Eletropaulo and AES Sul subsidiaries and the errors related to accounting for leases at the AES Southland and Pakistan subsidiaries. The term “May 2007 Restatement” refers collectively to the errors that were previously discussed in our 2006 Annual Report on Form 10-K that was filed on May 23, 2007.

Other than information relating to the restatement and conforming the presentation of discontinued operations as described below, no attempt has been made in this 10-K/A to amend or update other disclosures originally presented in the Form 10-K. Except as stated herein, this Form 10-K/A does not reflect events occurring after the filing of the Form 10-K on May 23, 2007 or amend or update those disclosures. Accordingly, this Form 10-K/A should be read in conjunction with our filings with the SEC subsequent to the filing of the Form 10-K.

A. Adjustments and Reclassifications in Financial Statements

The following table details the impact of the August 2007 Restatement on the Company’s Consolidated Statement of Operations for the year ended December 31, 2006:

	Year Ended December 31, 2006
					Aug 2007				Discontinued Operations							2006 Form
	2006 Form 10-K				Restatement				EDC			Central Valley				10-K/A
Revenues:
Regulated		$	6,849			$	—		$	(651	)		$	—			6,198
Non-Regulated		5,450				(48		)	—				(36		)		5,366
Total revenues		12,299				(48		)	(651		)		(36		)		11,564
Cost of Sales:
Regulated		(4,578		)		—			465				—				(4,114		)
Non-Regulated		(4,090		)		(1		)	—				38				(4,052		)
Total cost of sales		(8,668		)		(1		)	465				38				(8,166		)
Gross margin		3,631				(49		)	(186		)		2				3,398
General and administrative expenses		(305		)		—			—				—				(305		)
Interest expense		(1,802		)		—			39				—				(1,763		)
Interest income		443				—			(17		)		—				426
Other expense		(308		)		(139		)	(2		)		—				(449		)
Other income		115				—			(9		)		—				106
Gain (loss) on sale of investments		98				—			—				—				98
Loss on sale of subsidiary stock		(539		)		—			—				—				(539		)
Asset impairment expense		(29		)		—			1				—				(28		)
Foreign currency transaction losses on net monetary position		(77		)		—			(11		)		—				(88		)
Equity in earnings of affiliates		72				—			—				—				72
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST		1,299				(188		)	(185		)		2				928
Income tax expense		(403		)		(1		)	72				(2		)		(334		)
Minority interest expense		(610		)		132			19				—				(459		)
INCOME FROM CONTINUING OPERATIONS		286				(57		)	(94		)		—				135
Income (loss) from operations of discontinued businesses net of income tax		11				—			94				—				105
(Loss) gain from disposal of discontinued businesses net of income tax		(57		)		—			—				—				(57		)
INCOME BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		240				(57		)	—				—				183
Income from extraordinary items net of income tax		21				—			—				—				21
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		261				(57		)	—				—				204
Cumulative effect of change in accounting principle net of income tax		—				—			—				—				—
Net income		$	261			$	(57	)	$	—			$	—			$	204

The following table details the impact of both the May 2007 and the August 2007 Restatements on the Company’s Consolidated Statement of Operations for the year ended December 31, 2005:

	Year Ended December 31, 2005
	As Previously				May 2007								Aug 2007				Discontinued Operations							2006 Form
	Reported				Restatement				2006 Form 10-K				Restatement				EDC			Central Valley				10-K/A
Revenues:
Regulated		$	5,737			$	515			$	6,252			$	—		$	(635	)		$	—			$	5,617
Non-Regulated		5,349				(580		)		4,769				(33		)	—				(33		)		4,703
Total revenues		11,086				(65		)		11,021				(33		)	(635		)		(33		)		10,320
Cost of Sales:
Regulated		(4,500		)		82				(4,418		)		—			397				—				(4,021		)
Non-Regulated		(3,408		)		4				(3,404		)		(1		)	—				34				(3,371		)
Total cost of sales		(7,908		)		86				(7,822		)		(1		)	397				34				(7,392		)
Gross margin		3,178				21				3,199				(34		)	(238		)		1				2,928
General and administrative expenses		(221		)		(4		)		(225		)		—			—				—				(225		)
Interest expense		(1,896		)		3				(1,893		)		—			67				—				(1,826		)
Interest income		391				4				395				—			(20		)		—				375
Other expense		19				(151		)		(132		)		—			22				—				(110		)
Other income		—				171				171				—			(14		)		—				157
Gain (loss) on sale of investments		—				—				—				—			—				—				—
Loss on sale of subsidiary stock		—				—				—				—			—				—				—
Asset impairment expense		—				(16		)		(16		)		—			—				—				(16		)
Foreign currency transaction losses on net monetary position		(89		)		(12		)		(101		)		—			(44		)		—				(145		)
Equity in earnings of affiliates		76				(6		)		70				—			1				—				71
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST		1,458				10				1,468				(34		)	(226		)		1				1,209
Income tax expense		(465		)		(60		)		(525		)		(3		)	46				(1		)		(483		)
Minority interest expense		(361		)		(8		)		(369		)		19			26				—				(324		)
INCOME FROM CONTINUING OPERATIONS		632				(58		)		574				(18		)	(154		)		—				402
Income (loss) from operations of discontinued businesses net of income tax		—				34				34				—			154				—				188
(Loss) gain from disposal of discontinued businesses net of income		—				—				—				—			—				—				—
INCOME BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		632				(24		)		608				(18		)	—				—				590
Income from extraordinary items net of income tax		—				—				—				—			—				—				—
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		632				(24		)		608				(18		)	—				—				590
Cumulative effect of change in accounting principle net of income tax		(2		)		(1		)		(3		)		—			—				—				(3		)
Net income		$	630			$	(25	)		$	605			$	(18	)	$	—			$	—			$	587

The following table details the impact of both the May 2007 and the August 2007 Restatements on the Company’s Consolidated Statement of Operations for the year ended December 31, 2004:

	Year Ended December 31, 2004
	As Previously				May 2007								Aug 2007				Discontinued Operations							2006 Form
	Reported				Restatement				2006 Form 10-K				Restatement				EDC			Central Valley				10-K/A
Revenues:
Regulated		$	4,897			$	275			$	5,172			$	—		$	(619	)		$	—			$	4,553
Non-Regulated		4,566				(346		)		4,220				10			—				(38		)		4,192
Total revenues		9,463				(71		)		9,392				10			(619		)		(38		)		8,745
Cost of Sales:
Regulated		(3,781		)		71				(3,710		)		(3,328		)	382				—				—
Non-Regulated		(2,900		)		9				(2,891		)		(3		)	—				35				(2,859		)
Total cost of sales		(6,681		)		80				(6,601		)		(3		)	382				35				(6,187		)
Gross margin		2,782				9				2,791				7			(237		)		(3		)		2,558
General and administrative expenses		(182		)		1				(181		)		—			—				—				(181		)
Interest expense		(1,932		)		12				(1,920		)		—			104				—				(1,816		)
Interest income		282				1				283				—			(29		)		—				254
Other expense		12				(135		)		(123		)		—			10				—				(113		)
Other income		—				157				157				—			(7		)		—				150
Gain (loss) on sale of investments		(45		)		44				(1		)		—			—				—				(1		)
Loss on sale of subsidiary stock		—				(24		)		(24		)		—			—				—				(24		)
Asset impairment expense		—				(50		)		(50		)		—			1				—				(49		)
Foreign currency transaction losses on net monetary position		(165		)		29				(136		)		—			27				—				(109		)
Equity in earnings of affiliates		70				(7		)		63				—			—				—				63
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST		822				37				859				7			(131		)		(3		)		732
Income tax expense		(359		)		(21		)		(380		)		(3		)	18				—				(365		)
Minority interest expense		(199		)		(12		)		(211		)		—			16				—				(195		)
INCOME FROM CONTINUING OPERATIONS		264				4				268				4			(97		)		(3		)		172
Income (loss) from operations of discontinued businesses net of income		34				(93		)		(59		)		—			97				3				41
(Loss) gain from disposal of discontinued businesses net of income		—				91				91				—			—				—				91
INCOME BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		298				2				300				4			—				—				304
Income from extraordinary items net of income tax		—				—				—				—			—				—				—
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		298				2				300				4			—				—				304
Cumulative effect of change in accounting principle net of income		—				—				—				—			—				—				—
Net income		$	298			$	2			$	300			$	4		$	—			$	—			$	304

The following table details the impact of the August 2007 Restatement on the Company’s Consolidated Balance Sheet as of December 31, 2006:

					As of December 31, 2006
	2006 Form				August 2007				Discontinued Operations								2006 Form
	10-K				Restatement				EDC				Central Valley				10-K/A
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	1,575			$	—			$	(191	)		$	(5	)		$	1,379
Restricted cash		548				—				—				—				548
Short-term investments		640				—				—				—				640
Accounts receivable, net of reserves of $233		1,903				—				(129		)		(5		)		1,769
Inventory		518				—				(45		)		(2		)		471
Receivable from affiliates		81				—				(5		)		—				76
Deferred income taxes—current		213				—				(5		)		—				208
Prepaid expenses		113				—				(4		)		—				109
Other current assets		943				—				(16		)		—				927
Current assets of held for sale and discontinued businesses		31				—				395				12				438
Total current assets		6,565				—				—				—				6,565
NONCURRENT ASSETS
Property, Plant and Equipment:
Land		950				—				(19		)		(3		)		928
Electric generation and distribution assets		23,990				—				(2,133		)		(22		)		21,835
Accumulated depreciation		(6,979		)		—				427				7				(6,545		)
Construction in progress		1,113				—				(133		)		(1		)		979
Property, plant and equipment, net		19,074				—				(1,858		)		(19		)		17,197
Other assets:
Deferred financing costs, net of accumulated amortization of $188		285				—				(6		)		—				279
Investments in and advances to affiliates		596				—				(1		)		—				595
Debt service reserves and other deposits		524				—				—				—				524
Goodwill, net		1,419				—				—				(3		)		1,416
Other intangible assets, net of accumulated amortization of $171		305				—				(6		)		(1		)		298
Deferred income taxes—noncurrent		663				—				(59		)		(2		)		602
Other assets		1,627				28				(20		)		(1		)		1,634
Noncurrent assets of held for sale and discontinued businesses		105				—				1,950				36				2,091
Total other assets		5,524				28				1,858				29				7,439
TOTAL ASSETS		$	31,163			$	28			$	—			$	10			$	31,201
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	892			—				$	(96	)		$	(1	)		$	795
Accrued interest		412				—				(8		)		—				404
Accrued and other liabilities		2,227				—				(95		)		(1		)		2,131
Recourse debt-current portion		—				—				—				—				—
Non-recourse debt-current portion		1,453				—				(42		)		—				1,411
Current liabilities of held for sale and discontinued businesses		45				—				241				2				288
Total current liabilities		5,029				—				—				—				5,029
LONG-TERM LIABILITIES
Non-recourse debt		10,102				—				(268		)		—				9,834
Recourse debt		4,790				—				—				—				4,790
Deferred income taxes-noncurrent		790				9				(6		)		10				803
Pension liabilities and other post-retirement liabilities		883				—				(39		)		—				844
Other long-term liabilities		3,371				242				(57		)		(2		)		3,554
Long-term liabilities of held for sale and discontinued businesses		62				—				370				2				434
Total long-term liabilities		19,998				251				—				10				20,259
Minority Interest (including discontinued businesses of $175		3,100				(152		)		—				—				2,948
Commitments and Contingent Liabilities (see Notes 10 and 11)
STOCKHOLDERS’ EQUITY
Common stock ($.01 par value, 1,200,000,000 shares authorized; 665,126,309 issued and outstanding at December 31, 2006		7				—				—				—				7
Additional paid-in capital		6,654				—				—				—				6,654
Accumulated deficit		(1,025		)		(71		)		—				—				(1,096		)
Accumulated other comprehensive loss		(2,600		)		—				—				—				(2,600		)
Total stockholders’ equity		3,036				(71		)		—				—				2,965
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY		$	31,163			$	28			$	—			$	10			$	31,201

The following table details the impact of both the May 2007 and the August 2007 Restatements on the Company’s Consolidated Balance Sheet as of December 31, 2005:

	As of December 31, 2005
	As Previously				May 2007								Aug 2007				Discontinued Operations							2006 Form
	Reported				Restatement				2006 Form 10-K				Restatement				EDC			Central Valley				10-K/A
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	1,390			$	(69	)		$	1,321			$	—		$	(144	)		$	(1	)		$	1,176
Restricted cash		420				57				477				—			(40		)		—				437
Short-term investments		203				(4		)		199				—			—				—				199
Accounts receivable, net of reserves of $260		1,615				33				1,648				—			(127		)		(4		)		1,517
Inventory		460				(3		)		457				—			(34		)		(2		)		421
Receivable from affiliates		2				71				73				—			(2		)		—				71
Deferred income taxes—current		267				3				270				—			(12		)		—				258
Prepaid expenses		119				—				119				—			(6		)		—				113
Other current assets		756				(68		)		688				—			(18		)		—				670
Current assets of held for sale and discontinued businesses		—				35				35				—			383				7				425
Total current assets		5,232				55				5,287				—			—				—				5,287
NONCURRENT ASSETS
Property, Plant and Equipment:
Land		860				—				860				—			(20		)		(3		)		837
Electric generation and distribution assets		22,440				(139		)		22,301				—			(2,014		)		(21		)		20,266
Accumulated depreciation		(6,087		)		112				(5,975		)		—			338				5				(5,632		)
Construction in progress		1,441				(594		)		847				—			(166		)		—				681
Property, plant and equipment, net		18,654				(621		)		18,033				—			(1,862		)		(19		)		16,152
Other assets:
Deferred financing costs, net of accumulated amortization of $217		294				(19		)		275				—			(7		)		—				268
Investments in and advances to affiliates		670				(5		)		665				—			(1		)		—				664
Debt service reserves and other deposits		611				(65		)		546				—			—				—				546
Goodwill, net		1,428				(15		)		1,413				—			—				(3		)		1,410
Other intangible assets, net of accumulated amortization of $127		—				284				284				—			(7		)		(1		)		276
Deferred income taxes—noncurrent		807				(24		)		783				—			(85		)		—				698
Other assets		1,736				(327		)		1,409				21			(16		)		(7		)		1,407
Noncurrent assets of held for sale and discontinued businesses		—				265				265				—			1,978				44				2,287
Total other assets		5,546				94				5,640				21			1,862				33				7,556
TOTAL ASSETS		$	29,432			$	(472	)		$	28,960			$	21		$	—			$	14			$	28,995
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	1,104			$	(13	)		$	1,091			—			$	(90	)		$	(3	)		$	998
Accrued interest		382				(2		)		380				—			(7		)		—				373
Accrued and other liabilities		2,122				(15		)		2,107				—			(67		)		(3		)		2,037
Recourse debt-current portion		200				—				200				—			—				—				200
Non-recourse debt-current portion		1,598				(151		)		1,447				—			(79		)		(1		)		1,367
Current liabilities of held for sale and discontinued businesses		—				51				51				—			243				7				301
Total current liabilities		5,406				(130		)		5,276				—			—				—				5,276
LONG-TERM LIABILITIES
Non-recourse debt		11,226				(588		)		10,638				—			(320		)		—				10,318
Recourse debt		4,682				—				4,682				—			—				—				4,682
Deferred income taxes-noncurrent		721				56				777				6			(8		)		14				789
Pension liabilities and other post-retirement liabilities		857				8				865				—			(36		)		—				829
Other long-term liabilities		3,280				54				3,334				48			(43		)		(2		)		3,337
Long-term liabilities of held for sale and discontinued businesses		—				136				136				—			407				2				545
Total long-term liabilities		20,766				(334		)		20,432				54			—				14				20,500
Minority Interest (including discontinued businesses of $122		1,611				15				1,626				(19		)	—				—				1,607
Commitments and Contingent Liabilities (see Notes 10 and 11)
STOCKHOLDERS’ EQUITY
Common stock ($.01 par value, 1,200,000,000 655,882,836 shares issued and outstanding at December 31, 2005		7				—				7				—			—				—				7
Additional paid-in capital		6,517				44				6,561				—			—				—				6,561
Accumulated deficit		(1,214		)		(72		)		(1,286		)		(14		)	—				—				(1,300		)
Accumulated other comprehensive loss		(3,661		)		5				(3,656		)		—			—				—				(3,656		)
Total stockholders’ equity		1,649				(23		)		1,626				(14		)	—				—				1,612
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY		$	29,432			$	(472	)		$	28,960			$	21		$	—			$	14			$	28,995

B. Narrative Discussion of Adjustments and Reclassifications

1. Adjustments contained in the May 2007 Restatement Background

· 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.

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 remediate 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.

The May 2007 Restatement adjustments included several key categories as described below:

Brazil Adjustments

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

· other errors identified through account reconciliation or review procedures.

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, included 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.

Capitalization of Certain Costs

Derivatives

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

· the evaluation of hedge effectiveness; and

· the identification and evaluation of derivatives.

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 affiliates 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.

Income Tax Adjustments

Income tax adjustments related primarily to the following:

Other Adjustments

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. These receipts called “special obligations” were previously offset against property, plant and equipment. 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. See further discussion regarding special obligations in August 2007 Restatement.

Cartagena Deconsolidation

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.

Share-based Compensation

Background of the LTC Review

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.

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.

The Company’s Accounting Adjustments

Fiscal Year Ended	Pre-Tax Expense			After-Tax Expense
	(in millions)
2000		$	8		$	6
2001		$	15		$	11
2002		$	8		$	5
2003		$	4		$	3
2004		$	—		$	—
2005		$	1		$	1

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.

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 recorded a $3 million charge to account for this error for the year 2003.

Summary of Significant Charges By Grant Year

For grants made in 2001, the total charge resulting from the LTC Review was approximately $9 million. Of that amount, approximately $7 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 million resulted from 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 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 noted 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.

2. Adjustments presented in the August 2007 Restatement

Special Obligations in Brazil Subsidiaries

liabilities should begin. In June 2007, ANEEL issued another resolution, Circular 1314, stating that two February 2007 resolutions (236 and 296) were no longer in force.

Special Obligations represent consumers’ contributions to the cost of expanding the electric power supply system. Property plant and equipment assets, regardless of the source of funds to acquire them, are depreciated based on the respective assets’ useful lives, as established by ANEEL. The Special Obligation liability was not previously amortized as a reduction of allowable costs for tariff or Brazilian Accounting Principles. The purpose of the Resolution is to adjust the tariff prospectively to offset the allowable cost for depreciation on these assets with amortization of the special obligation liability.

The Company considered “the pre-acquisition liability” that was determined to have a fair value of zero at the time of acquisition to determine whether the Resolution was a triggering event that would now make this liability probable as a reduction of allowable cost under tariff. The Company consulted with the Brazilian affiliate of its external audit firm regarding the pre-acquisition liability and determined that as of May 23, 2007, the date of the filing of our 2006 Form 10-K, no industry positions or any other consensus had been reached regarding how ANEEL guidance should be applied at that date and no adjustments to the financial statements were made relating to Special Obligations in Brazil. Subsequent to May 23, 2007, industry discussions occurred and other Brazilian companies filed Forms 20-F with the SEC reflecting the impact of the Resolution in their December 31, 2006 financial statements. In the absence of any significant regulatory developments between May 23, 2007 and the date of these other filings, we now believe that the October 2006 resolution issued by ANEEL required us to record an adjustment to our Special Obligations liability as of December 31, 2006.

Lease Accounting

In connection with the Company’s continued remediation efforts related to internal controls over financial reporting, the Company discovered certain errors relating to its accounting for leases at its AES Southland subsidiary, a wholly-owned North American Generations business and its Pakistan subsidiary, a majority-owned Asia Generation business.

In accordance with EITF 01-08, “Determining Whether an Arrangement Contains a Lease” (“EITF 01-08”), an entity must reassess whether an arrangement requires lease accounting when certain changes including contractual terms; renewal or extension or changes in fulfillment of the arrangement exist. Upon reassessment of the arrangement and the subsequent modifications, the Company determined that the PPA with the third party offtakers in both cases qualified as a lease under the provisions of EITF 01-08. As a result, the revenue generated from the capacity payments should be accounted for on a straight-line basis. The impact on net income as a result of the correction of these errors is a decrease of $26 million and $18 million and in 2006 and 2005, respectively and an increase of $4 million in 2004.

For these restatements items, the Company determined that the remediation efforts relative to its previously reported material weakness related to accounting for certain derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, was in fact viewed more broadly by the Company in the context of controls related to the accounting for contracts in general; specifically, the material weakness was viewed as a lack of sufficient controls designed to ensure the adequate analysis and documentation at inception and on an ongoing basis of whether or not certain contracts were adequately accounted for in accordance with U.S. GAAP. As such, the Company revised the title and description of the previously disclosed “Derivative Accounting” material weakness to reflect the above described broader view. Accordingly, the Company determined that no revision to the related remediation plan, as previously disclosed in the Company 2006 Form 10-K, was needed.

3. Reclassifications into Discontinued Operations presented in this Form 10-K/A

“Income (Loss) from Operations of Discontinued Businesses” in the Consolidated Statement of Operations. Correspondingly, the assets and liabilities of these businesses are reclassified to assets and liabilities ‘held for sale” in the Consolidated Balance Sheets. In accordance with SEC guidelines, when a company files or amends its annual financial statements as of a date on or after the date the company reports discontinued operations, the company must present the financial information in those prior period financial statements to reflect the discontinued operations. Accordingly, certain financial information presented in this Form 10-K/A has been conformed to the presentation of the discontinued operations in our first quarter 2007 Form 10-Q.

Sale of EDC

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 has 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 and 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 was 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 recorded a pre-tax, non-cash impairment charge of $638 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 approximately $101 million from EDC in 2006. EDC’s five generation plants represented approximately 7% of AES’ approximate 35 gigawatts of capacity installed.

Business Overview

Our Businesses

We operate two 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 13 distribution companies in seven countries with over 10 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—Indianapolis Power & Light (“IPL”),

· Cameroon—AES SONEL.

· 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.

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,

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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 over 35 gigawatts of capacity installed in 21 countries.

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.

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Recent Initiatives

We are developing an Alternative Energy business. Alternative Energy includes strategic initiatives such as wind generation and other renewable energy sources, liquefied natural gas regasification (“LNG”), greenhouse gas emissions offset projects and new technologies. Of these initiatives, we currently only have wind generation facilities that are operational. Our Buffalo Gap wind project, which is located in Texas, began full commercial operations in April 2006. An expansion of Buffalo Gap, called Buffalo Gap 2, is currently under construction. We also acquired wind generation assets in California from Enron Wind Systems. In Europe, we have acquired stakes in wind development businesses in Scotland, France, and Bulgaria.

We currently have three LNG projects that are in pre-construction phases of development. We are also pursuing projects which will allow us to develop greenhouse gas emission offsets. To that end, we have developed a joint venture with AgCert International called AES AgriVerde, which will deploy greenhouse gas emissions reduction technology in selected countries in Asia, Europe and North Africa. Although, Alternative Energy represents a very small portion of our business compared to Utilities and Generation, Alternative Energy is an important initiative in our long-term strategy because we believe it may represent a significant growth opportunity for us.

Some of the important drivers of performance for us 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. While this initiative represents a growth opportunity for us, alternative energy is not material to our financial statements at this time.

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.

Earnings per share—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 totaling $512 million, or

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$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.

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. In 2006, we saw continuing improvements in the number of lost time accidents (LTAs) at our businesses.

Material Weaknesses

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 related to:

· US GAAP accounting expertise in Brazil;

· Income tax accounting;

· Derivative accounting; and

· Foreign currency implications of certain intercompany loans.

This effort involved a continuing review of current processes, implementation of remediation plans and a focus on staffing with the right level and quality of technical accounting resources. We have focused our internal audit resources on performing additional targeted financial statement audits and have brought in outside expertise in the areas of derivatives and tax to help us expedite our improvement plans. In addition to this specific focus, the Company embarked upon a program to assess the capabilities of its financial staff on a worldwide basis and develop related hiring and training programs. We have approved a program to accelerate our implementation of integrated financial systems for our generation plants, which will allow for further automation of currently manual processes and more timely submission and review of financial statements.

As a result of these continued efforts, we did identify certain prior year errors which caused the Company to restate prior year results again. Even so, we feel confident that the financial and control organizations are taking the right steps, with full management support, to help us ensure that we are able to produce accurate and timely financial statements in the future.

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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.

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 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.

We continued to build a robust business development pipeline and extend that pipeline into new areas such as greenhouse gas emission reduction projects and electricity transmission. 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 included in Europe & Africa generation, 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.

The Company’s growth project backlog (growth projects under construction) as of December 31, 2006 totaled over 1,500 gross MW of new generation capacity with total expected investment of approximately $3.2 billion through 2011. This includes fossil-fueled projects in Chile and Bulgaria, a hydroelectric project in Panama, and a wind project in the US. We also secured early-stage memorandums of understanding to develop power projects in countries such as Vietnam, Indonesia, and India.

In addition to the wind project mentioned above, significant 2006 developments in the Company’s Alternative Energy business included acquisition of 73 MW of wind generation assets in California and interests in wind project development pipelines totaling approximately 1,360 MW in Scotland (U.K.), France, and Bulgaria. The Company made its first significant strides in the greenhouse gas emission area, acquiring a 9.9% ownership interest in AgCert International (“AgCert”) for $52 million. AgCert is an Ireland-based company which uses agricultural sources to produce greenhouse gas emission offsets under the Kyoto protocol. AES and AgCert also formed a joint venture, AES AgriVerde, to produce greenhouse gas emission offsets in selected countries in Asia, Europe and North Africa.

The Company expects to fund growth investments from available cash, net cash from operating activities and/or the proceeds from the issuance of debt, common stock, other securities, asset sales, and partner equity contributions. Certain of the Alternative Energy businesses may be considered start-up businesses that will need to be funded internally through cash equity contributions, and may have limited debt financing opportunities initially. We see 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 Consolidated Financial Statements included in Item 8 of this Form 10-K/A.

An accounting estimate is considered critical if:

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

· different estimates reasonably could have been used; or

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

Management believes that the accounting estimates employed are appropriate and the resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. 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

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Company and certain of its subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the taxing jurisdictions when determining the adequacy of the provision for income taxes. 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 Consolidated Financial Statements included in Item 8 of this Form 10-K/A, 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 Item 8 of this Form 10-K/A. 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

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method. In applying this methodology, we rely on a number of factors, including actual operating results, future business plans, economic projections and market data.

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:

· Discount rates;

· Salary growth;

· Retirement rates;

· Inflation;

· Expected return on plan assets; and

· Mortality rates.

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

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be incurred or included in future rate initiatives. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, 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.

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Consolidated Results of Operations

Overview

	Year Ended December 31,
Results of operations	2006 (Restated)				2005 (Restated)				2004 (Restated)				$ change 2006 vs. 2005				$ change 2005 vs. 2004
	(in millions, except per share data)
Revenue:
Latin America Generation		$	2,616			$	2,145			$	1,584			$	471			$	561
Latin America Utilities		4,595				4,161				3,205				434				956
North America Generation		1,871				1,785				1,676				86				109
North America Utilities		1,032				951				885				81				66
Europe & Africa Generation		852				735				697				117				38
Europe & Africa Utilities		571				505				463				66				42
Middle East & Asia Generation		785				600				570				185				30
Corporate and Other(1)		(758		)		(562		)		(335		)		(196		)		(227		)
Total Revenue		$	11,564			$	10,320			$	8,745			$	1,244			$	1,575
Gross Margin:
Latin America Generation		$	1,054			$	857			$	616			$	197			$	241
Latin America Utilities		884				596				517				288				79
North America Generation		565				599				594				(34		)		5
North America Utilities		277				301				303				(24		)		(2		)
Europe & Africa Generation		249				186				182				63				4
Europe & Africa Utilities		112				112				60				—				52
Middle East & Asia Generation		200				242				252				(42		)		(10		)
Total Corporate and Other(2)		(248		)		(190		)		(147		)		(58		)		(43		)
Interest expense		(1,763		)		(1,826		)		(1,816		)		63				(10		)
Interest income		426				375				254				51				121
Other expense		(449		)		(110		)		(113		)		(339		)		3
Other income		106				157				150				(51		)		7
Gain (loss) on sale of investments		98				—				(1		)		98				1
Loss on sale of subsidiary stock		(539		)		—				(24		)		(539		)		24
Asset impairment expense		(28		)		(16		)		(49		)		(12		)		33
Foreign currency transaction losses on net monetary position		(88		)		(145		)		(109		)		57				(36		)
Equity in earnings of affiliates		72				71				63				1				8
Income tax expense		(334		)		(483		)		(365		)		149				(118		)
Minority interest expense		(459		)		(324		)		(195		)		(135		)		(129		)
Income from continuing operations		135				402				172				(267		)		230
Income from operations of discontinued businesses		105				188				41				(83		)		147
(Loss) gain from disposal of discontinued businesses		(57		)		—				91				(57		)		(91		)
Extraordinary items		21				—				—				21				—
Cumulative effect of accounting change		—				(3		)		—				3				(3		)
Net income		$	204			$	587			$	304			$	(383	)		$	283

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	December 31,
Per share data:	2006 Restated			2005 Restated			2004 Restated			$ change 2006 vs. 2005				$ change 2005 vs. 2004
Basic income per share from continuing operations		$	0.21		$	0.62		$	0.27		$	(0.41	)		$	0.35
Diluted income per share from continuing operations		$	0.20		$	0.61		$	0.27		$	(0.41	)		$	0.34

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

(2) Total Corporate and Other expenses include corporate general and administrative expenses as well as certain inter-segment eliminations, primarily corporate charges for management fees and self insurance premiums.

Segment Analysis

Latin America

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

Latin America	For the Years Ended December 31,
	2006						2005						2004
				% of Total						% of Total						% of Total
Revenue	Revenue			Revenue			Revenue			Revenue			Revenue			Revenue
Latin America Generation		$	2,616		23	%		$	2,145		21	%		$	1,584		18	%
Latin America Utilities		4,595			40	%		4,161			40	%		3,205			37	%

Fiscal Year 2006 versus 2005 Revenue

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.

Fiscal Year 2005 versus 2004 Revenue

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.

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Fiscal Year 2006 versus 2005 Gross Margin

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

Latin America	For the Years Ended December 31,
	2006						2005						2004
				% of Total						% of Total						% of Total
				Gross						Gross						Gross
Gross Margin	Gross Margin			Margin			Gross Margin			Margin			Gross Margin			Margin
Latin America Generation		$	1,054		31	%		$	857		29	%		$	616		24	%
Latin America Utilities		884			26	%		596			20	%		517			20	%

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.

Fiscal Year 2005 versus 2004 Gross Margin

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.

North America

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

North America	For the Years Ended December 31,
	2006						2005						2004
				% of Total						% of Total						% of Total
Revenue	Revenue			Revenue			Revenue			Revenue			Revenue			Revenue
North America Generation		$	1,871		16	%		$	1,785		17	%		$	1,676		19	%
North America Utilities		1,032			9	%		951			9	%		885			10	%

Fiscal Year 2006 versus 2005 Revenue

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

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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.

Fiscal Year 2005 versus 2004 Revenue

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.

Fiscal Year 2006 versus 2005 Gross Margin

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

North America	For the Years Ended December 31,
	2006						2005						2004
				% of Total						% of Total						% of Total
				Gross						Gross						Gross
Gross Margin	Gross Margin			Margin			Gross Margin			Margin			Gross Margin			Margin
North America Generation		$	565		17	%		$	599		20	%		$	594		23	%
North America Utilities		277			8	%		301			10	%		303			12	%

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.

Fiscal Year 2005 versus 2004 Gross Margin

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.

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

Other expense

	Years Ended December 31,
	2006			2005			2004
	(in millions)
Loss on extinguishment of liabilities	$	(181	)	$	(3	)	$	(33	)
Regulatory special obligations	(139		)	—			—
Write-down of disallowed regulatory assets	(36		)	—			—
Legal/dispute settlement	(31		)	(30		)	(5		)
Loss on sale and disposal of assets	(28		)	(47		)	(22		)
Marked-to-market loss on commodity derivatives	—			—			(5		)
Other	(34		)	(30		)	(48		)
Total other expense	$	(449	)	$	(110	)	$	(113	)

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

As discussed in Note 17 to the 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-

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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 was $98 million in 2006 and was primarily comprised of the following:

· In March 2006, we sold our equity investment in a power project in Canada (Kingston) for a net gain of $87 million.

· In September 2006, we transferred Infoenergy, a wholly owned AES subsidiary, to Brasiliana for a net gain of $10 million. 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.

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 14 to the 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 $80 million. For the twelve months ended December 31, 2006, AES recognized a pre-tax loss of $539 million 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.

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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.

	Years Ended December 31,
	2006			2005			2004
	(in millions)
AES Corporation	$	(17	)	$	10		$	(8	)
Argentina	(3		)	(5		)	(6		)
Brazil	(56		)	(96		)	(58		)
Venezuela	—			—			2
Dominican Republic	—			1			(28		)
Pakistan	(18		)	(22		)	(17		)
Chile	—			(20		)	(3		)
Kazakhstan	1			(4		)	14
Colombia	(1		)	(5		)	(8		)
Cameroon	2			(4		)	5
Other	4			—			(2		)
Total(1)	$	(88	)	$	(145	)	$	(109	)

(1) Includes $(58) million, $(119) million and $(89) million of losses on foreign currency derivative contracts for December 31, 2006, 2005 and 2004, respectively.

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 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.

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Equity in earnings of affiliates

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.

Income taxes

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, 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 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.

Discontinued operations

As discussed in Note 20 to the consolidated financial statements included in Item 8 of this Form 10-K/A; on February 22, 2007, the Company entered into a definitive agreement with PDVSA dated February 15, 2007, to sell all of its 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. Also, during 2006 we discontinued certain of our operations including Eden, a regulated utility located in Argentina, AES Indian Queens Power Limited and AES Indian Queens Operations Limited, collectively “IQP”, which is an Open Cycle Gas

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Turbine, located in the U.K. Income from operations of discontinued businesses, net of tax, was $105 million in 2006.

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 wholly-owned subsidiary of AES, has been classified as “held for sale” and reflected as such on the financial statements. In addition to the results of its operations, Eden has also recognized a $2 million favorable adjustment in the first quarter of 2007, to the originally recorded net loss on the sale as a result of the finalization of the sale transaction.

In September 2006, the Company completed the sale of IQP. Proceeds from the sale were $28 million in cash and the buyer’s assumption of debt of $30 million. The Company recognized a gain on disposal of discontinued businesses of $5 million. The results of operations of IQP and the associated gain on disposal are reflected in the discontinued operations line items on the financial statements.

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 Consolidated Financial Statements included in Item 8 of this Form 10-K/A, 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 December 31, 2006, we had $4.8 billion of recourse debt and $11.2 billion of non-recourse debt outstanding. For more information on our long-term debt see Note 8 to the Consolidated Financial Statements included in Item 8 of this Form 10-K/A.

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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. For example in March 2006, AES sold its interest in Kingston for $110 million. 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 intend 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 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.

As a result of AES parent’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 December 31, 2006, 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 $995 million (including those collateralized by letters of credit and other obligations discussed below). 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.

At December 31, 2006, we had $461 million in letters of credit outstanding, which operate to guarantee performance relating to certain project construction and development activities and subsidiary operations. All of these letters of credit were provided under our revolving credit facility and senior unsecured credit facility. We pay letter of credit fees ranging from 1.63% to 2.64% per annum on the outstanding amounts. In addition, we had $1 million in surety bonds outstanding at December 31, 2006.

Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may adversely affect those subsidiaries’ financial condition and results of operations. 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 in our regulated utility businesses.

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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 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.

Financing Activities

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.

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

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$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

(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

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other consolidated debt of the subsidiaries. Recourse debt borrowings are the borrowings of AES, the parent company. Note 8 to the Consolidated Financial Statements included in Item 8 of this Form 10-K/A 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 Consolidated Financial Statements included in Item 8 of this Form 10-K/A).

(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

Because of the non-recourse nature of most of our indebtedness, The AES Corporation believes that unconsolidated parent company liquidity is an important measure of liquidity. Our principal sources of liquidity at the parent company level are:

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

· proceeds from debt and equity financings at the parent company level, including borrowings under our credit facilities; and

· proceeds from asset sales

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Our cash requirements at the parent company level are primarily to fund:

· interest and preferred dividends;

· principal repayments of debt;

· acquisitions;

· construction commitments;

· other equity commitments;

· taxes; and

· parent company overhead and development costs.

Since 2002, The AES Corporation has undertaken various initiatives to improve the credit and risk profile of both the parent and the consolidated company while continuing to pursue disciplined growth.

On March 3, 2006, The AES Corporation redeemed all of its outstanding 8.875% Senior Subordinated Debentures due 2027 (approximately $115 million aggregate principal amount). The redemption was made pursuant to the optional redemption provisions of the indenture governing the Debentures. The Debentures were redeemed at a redemption price equal to 100% of the principal amount thereof, plus a make-whole premium determined in accordance with the terms of the indenture, plus accrued and unpaid interest up to the redemption date.

In December 2006, The AES Corporation exercised its right to increase the revolving credit facility by $100 million to a total of $750 million. As of December 31, 2006, there were no outstanding borrowings against the revolving credit facility. We had $88 million of letters of credit outstanding against the revolving credit facility and $662 million available under the revolving credit facility as of December 31, 2006.

The AES Corporation entered into a $500 million senior unsecured credit facility agreement effective March 31, 2006. On May 1, 2006, The AES Corporation 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 December 31, 2006, the Company had no outstanding borrowings under the senior unsecured credit facility. The AES Corporation had $373 million of letters of credit outstanding against the senior unsecured credit facility as of December 31, 2006. The credit facility is being used to support our ongoing share of construction obligations for AES Maritza East 1 and for general corporate purposes.

The following table sets forth parent company liquidity as of December 31, for the periods indicated.

Parent Company Liquidity	2006		2005		2004
	(in millions)
Cash and cash equivalents	$	1,379	$	1,176	$	931
Less: Cash and cash equivalents at subsidiaries	1,142		914		644
Parent cash and cash equivalents	237		262		287
Borrowing available under revolving credit facility	662		356		352
Borrowing available under senior unsecured credit facility	227		—		—
Cash at qualified holding companies	20		6		4
Total parent liquidity	$	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.

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The following table sets forth our parent company contingent contractual obligations as of December 31, 2006:

						Exposure Range
				Number of		for Each
Contingent Contractual obligations	Amount			Agreements		Agreement
	(in millions)
Guarantees		$	533		32		<$1 - $10	0
Letters of credit under the revolving credit facility		88			12		<$1 - $2	6
Letters of credit under the senior unsecured credit facility		373			8		<$1 - $33	3
Surety bonds		1			1		<$	1
Total		$	995		53

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, construction cost overruns, subsidiary default, political risk, tax indemnities, spot market power prices, supplies support and liquidated damages under power sales agreements for projects in development, under construction and operating. 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 there under.

While we believe that our sources of liquidity will be adequate to meet our needs through the end of 2007, 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 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. See Item 1A. “Risk Factors—The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise”

Various debt instruments at the parent company level, including our senior secured credit facilities, contain certain restrictive covenants. The covenants provide for, among other items:

· limitations on other indebtedness, liens, investments and guarantees;

· restrictions on dividends and redemptions and payments of unsecured and subordinated debt and the use of proceeds;

· restrictions on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off balance sheet and derivative arrangements;

· maintenance of certain financial ratios; and

· financial and other reporting requirements.

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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:

· reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the parent level during the time period of any default;

· triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;

· causing us to record a loss in the event the lender forecloses on the assets; and

· triggering defaults in our outstanding debt at the parent level.

For example, our senior secured credit facilities and outstanding debt securities at the parent level include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the parent level includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total debt classified as current in the accompanying consolidated balance sheets related to such defaults was $245 million at December 31, 2006, 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 AES’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 AES parent company’s outstanding debt securities.

Off-Balance Sheet Arrangements

In May 1999, one of our subsidiaries acquired six electric generating plants from New York State Electric and Gas. Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. 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 Consolidated Financial Statements included in Item 8 of this Form 10-K/A 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

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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 have 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% 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).

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks

We are exposed to market risks associated with interest rates, foreign exchange rates and commodity prices. We often utilize financial instruments and other contracts to hedge against such fluctuations. We also utilize financial 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.

Foreign Exchange Rate Risk

We are exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk 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

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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 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	2006			2005		2004
	(in millions)
Foreign Exchange		$	36	$	34	$	27
Interest Rate		$	76	$	114	$	110
Commodity		$	24	$	19	$	9

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.

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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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THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2006, 2005, AND 2004

	2006				2005				2004
	(Restated)(1)				Restated)(1)				(Restated)(1)
	(in millions)
OPERATING ACTIVITIES:
Net income		$	204			$	587			$	304
Adjustments to net income:
Depreciation and amortization of intangible assets		933				864				777
Loss from sale of investments and goodwill and asset impairment expense		491				49				74
Loss (gain) on disposal and impairment write-down associated with discontinued operations		62				—				(98		)
Provision for deferred taxes		(34		)		138				211
Minority interest expense		478				354				211
Contingencies		173				(10		)		28
Loss (gain) on the extinguishment of debt		148				1				(59		)
Other		58				132				297
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		93				—				(110		)
Increase in inventory		(13		)		(58		)		(23		)
(Increase) decrease in prepaid expenses and other current assets		(55		)		124				(82		)
Decrease (increase) in other assets		151				83				(62		)
(Decrease) increase in accounts payable and accrued liabilities		(382		)		(134		)		74
Increase (decrease) in other liabilities		53				102				(45		)
Net cash provided by operating activities		2,360				2,232				1,497
INVESTING ACTIVITIES:
Capital Expenditures		(1,460		)		(826		)		(706		)
Acquisitions—net of cash acquired		(19		)		(85		)		(20		)
Proceeds from the sales of businesses		898				22				35
Proceeds from the sales of assets		24				26				28
Sale of short-term investments		2,011				1,499				1,402
Purchase of short-term investments		(2,359		)		(1,345		)		(1,388		)
(Increase) decrease in restricted cash		(8		)		94				(43		)
Purchase of emission allowances		(77		)		(19		)		(5		)
Proceeds from the sales of emission allowances		82				42				3
Decrease (increase) in debt service reserves and other assets		46				(100		)		(63		)
Purchase of long-term available-for-sale securities		(52		)		—				—
Other investing		12				31				14
Net cash used in investing activities		(902		)		(661		)		(743		)
FINANCING ACTIVITIES:
Borrowings under the revolving credit facilities, net		72				53				—
Issuance of recourse debt		—				5				491
Issuance of non-recourse debt		3,097				1,710				2,110
Repayments of recourse debt		(150		)		(259		)		(1,140		)
Repayments of non-recourse debt		(4,059		)		(2,651		)		(2,534		)
Payments for deferred financing costs		(86		)		(21		)		(109		)
Distributions to minority interests		(335		)		(186		)		(139		)
Contributions from minority interests		125				1				24
Issuance of common stock		78				26				16
Financed capital expenditures		(52		)		(1		)		(6		)
Other financing		(7		)		(16		)		2
Net cash used in financing activities		(1,317		)		(1,339		)		(1,285		)
Effect of exchange rate changes on cash		62				13				6
Total increase (decrease) in cash and cash equivalents		203				245				(525		)
Cash and cash equivalents, beginning		1,176				931				1,456
Cash and cash equivalents, ending		$	1,379			$	1,176			$	931
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized		$	1,718			$	1,674			$	1,759
Cash payments for income taxes, net of refunds		$	479			$	268			$	197
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Common stock issued for debt retirement		$	—			$	—			$	168
Brasiliana Energia debt exchange (See Note 14)		$	—			$	—			$	773
Transfer of Infoenergy to Brasiliana		$	13			$	—			$	—
IQP—Buyer’s assumption of debt (See Note 20)		$	30			$	—			$	—

(1) See Note 1 related to the restated consolidated financial statements

See notes to consolidated financial statements.

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THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)
YEARS ENDED DECEMBER 31, 2006, 2005, AND 2004

	Common Stock					Additional Paid-In				Retained Earnings (Accumulated				Accumulated Other Comprehensive				Comprehensive
	Shares		Amount			Capital				Deficit)				Loss				Income
	(in millions)
Balance at January 1, 2004 (As Restated)(1)		625.6		6			5,774				(2,191		)		(3,710		)
Net income (Restated)(1)		—		—			—				304				—				304
Subsidiary sale of stock		—		—			482				—				—				—
Foreign currency translation adjustment (net of reclassification to earnings of $(46) for the sale or write off of investments in foreign entities, net of income tax expense of $15) (Restated)(1)		—		—			—				—				85				85
Minimum pension liability adjustment (net of income tax expense of $4)		—		—			—				—				18				18
Change in derivative fair value (including a reclassification to earnings of $88 million, net of tax, and an income tax benefit of $23) (Restated)(1)		—		—			—				—				(34		)		(34		)
Comprehensive income (Restated)(1)																			$	373
Issuance of common stock in exchange for cancellation of debt		19.7		—			168				—				—
Issuance of common stock under benefit plans and exercise of stock options and warrants (net of income tax benefit of $5 million)		4.8		1			34				—				—
Stock compensation (Restated)(1)		—		—			20				—				—
Balance at December 31, 2004 (Restated)(1)		650.1		$	7		$	6,478			$	(1,887	)		$	(3,641	)
Net income (Restated)(1)		—		—			—				587				—				587
Foreign currency translation adjustment (net of reclassification to earnings of $1 for the sale or write off of investments in foreign entities, net of income tax expense of $11) (Restated)(1)		—		—			—				—				72				72
Minimum pension liability adjustment (net of income tax benefit of $10) (Restated)(1)		—		—			—				—				(12		)		(12		)
Change in derivative fair value (including a reclassification to earnings of $153 million, net of income tax benefit of $105) (Restated)(1)		—		—			—				—				(75		)		(75		)
Comprehensive income (Restated)(1)																			$	572
Issuance of common stock under benefit plans and exercise of stock options and warrants (net of income tax benefit of $14 million)		5.8		—			62				—				—
Stock compensation (Restated)(1)		—		—			21				—				—
Balance at December 31, 2005 (Restated)(1)		655.9		$	7		$	6,561			$	(1,300	)		$	(3,656	)
Net income (Restated)(1)		—		—			—				204				—				204
Subsidiary sale of stock		—		—			(35		)		—				—				—
Change in fair value of available for sale securities (net of income tax benefit of $2)															(3		)		(3		)
Foreign currency translation adjustment (net of income tax expense of $9)		—		—			—				—				691				691
Minimum pension liability adjustment (net of income tax expense of $2)		—		—			—				—				—				—
Change in derivative fair value (including a reclassification to earnings of $(6) million, net of an income tax expense of $194)		—		—			—				—				274				274
Effect of SFAS No. 158 (net of income tax expense of $60)															94				—
Comprehensive income (Restated)(1)																			$	1,166
Issuance of common stock under benefit plans and exercise of stock options and warrants		9.2		—			97				—				—
Stock compensation		—		—			31				—				—
Balance at December 31, 2006 (Restated)(1)		665.1		$	7		$	6,654			$	(1,096	)		$	(2,600	)

(1) See Note 1 related to the restated consolidated financial statements

See notes to consolidated financial statements.

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THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2006, 2005, AND 2004

1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The AES Corporation is a holding company that through its subsidiaries and affiliates, (collectively, “AES” or “the Company”) operates a geographically diversified portfolio of electricity generation and distribution businesses.

PRINCIPLES OF CONSOLIDATION—The consolidated financial statements of the Company include the accounts of The AES Corporation, its subsidiaries, and controlled affiliates. Furthermore, variable interest entities in which the Company has an interest have been consolidated where the Company is identified as the primary beneficiary. Investments in which the Company has the ability to exercise significant influence but not control are accounted for using the equity method. All significant intercompany transactions and balances have been eliminated in consolidation.

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

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

RESTRICTED CASH—Restricted cash includes cash and cash equivalents which are restricted as to withdrawal or usage. The nature of restrictions includes restrictions imposed by the financing agreements such as security deposits kept as collateral, debt service reserves, maintenance reserves, and others; as well as restrictions imposed by long-term power purchase agreements.

ALLOWANCE FOR DOUBTFUL ACCOUNTS—The Company maintains an allowance for doubtful accounts for estimated uncollectible accounts receivable. The allowance is based on the Company’s assessment of known delinquent accounts, historical experience, and other currently available evidence of the collectibility and the aging of accounts receivable.

INVESTMENTS—Short-term investments consist of investments with original maturities in excess of three months but less than one year.

Securities that the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at historical cost. Other investments that the Company does not intend to hold to maturity are classified as available-for-sale or trading. Unrealized gains or losses on available-for-sale investments are recorded as a separate component of stockholders’ equity. Investments classified as trading are marked to market on a periodic basis through the statement of operations. Interest and dividends on investments are reported in interest income. Gains and losses on sales of investments are recorded using the specific identification method.

EQUITY INVESTMENTS—Investments in which the Company has the ability to exercise significant influence but not control are accounted for using the equity method. The Company evaluates its equity

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method investments for impairment whenever events or changes in circumstances indicate that the carrying amounts of such investments may not be recoverable. The difference between the carrying value of the equity method investment and its estimated fair value is recognized as an impairment when the loss in value is deemed other than temporary.

In accordance with Accounting Principles Board Opinion No. 18, the Company discontinues the application of the equity method when an investment is reduced to zero and does not provide for additional losses when the Company does not guarantee the obligations of the investee or is not otherwise committed to provide further financial support for the investee. The Company resumes the application of the equity method if the investee subsequently reports net income to the extent that the Company’s share of such net income equals the share of net losses not recognized during the period the equity method was suspended.

PROPERTY, PLANT, AND EQUIPMENT—Property, plant, and equipment is stated at cost. The cost of renewals and betterments that extend the useful life of property, plant and equipment are capitalized.

Construction progress payments, engineering costs, insurance costs, salaries, interest, and other costs relating to construction in progress are capitalized during the construction period, or expensed at the time the Company determines that development of a particular project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, siting, financing, construction, permitting, and contract compliance. Construction in progress balances are transferred to electric generation and distribution assets when each asset is ready for its intended use.

Depreciation, after consideration of salvage value and asset retirement obligations, is computed using the straight-line method over the estimated composite useful lives of the assets. Maintenance and repairs are charged to expense as incurred. Emergency and rotable spare parts inventories are included in electric generation and distribution assets when placed in service and are depreciated over the useful life of the related components.

DEFERRED FINANCING COSTS—Financing costs are deferred and amortized over the related financing period using the effective interest method or the straight-line method when it does not differ materially from the effective interest method.

GOODWILL AND OTHER INTANGIBLES—In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, the Company recognizes goodwill for the excess of the cost of an acquired entity over the net amount assigned to assets acquired and liabilities assumed. The Company evaluates goodwill for impairment on an annual basis and whenever events or changes in circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company’s annual impairment testing date is October 1st. The Company accounts for emission allowance as intangible assets.

LONG-LIVED ASSETS—In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company evaluates the impairment of long-lived assets based on the projection of undiscounted cash flows when circumstances indicate that the carrying amount of such assets may not be recoverable or the assets meet the held for sale criteria under SFAS No. 144. These events or circumstances may include the relative pricing of wholesale electricity by region, anticipated demand and cost of fuel. If the carrying amount is not recoverable, an impairment charge is 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.

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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, we made our best estimate of fair value using valuation methods based on the most current information at that time. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions, and management’s analysis of the benefits of the transaction.

ASSET RETIREMENT OBLIGATIONS—The Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations in 2003. SFAS No. 143 requires the Company to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. When a new liability is recorded the Company will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss.

The Company’s retirement obligations covered by SFAS No. 143 primarily include active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. As of December 31, 2006 and 2005, the Company had recorded liabilities of approximately $51 million and $46 million, respectively, related to asset retirement obligations. There are no assets that are legally restricted for purposes of settling asset retirement obligations.

The following table summarizes the amounts recorded, which were related to asset retirement obligations, during the years ended December 31, 2006 and 2005:

	2006			2005
	(in millions)
Balance at January 1		$	46		$	23
Additional liability recorded from cumulative effect of accounting change		—			18
Additional liabilities incurred in the current period		—			5
Accretion expense		3			2
Change in estimated cash flows		1			(1		)
Translation adjustments		1			(1		)
Balance at December 31		$	51		$	46

CONDITIONAL ASSET RETIREMENT OBLIGATIONS—In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47 Accounting for Conditional Asset Retirement Obligations which requires the Company to record the estimated fair value of conditional asset retirement obligations. The Company’s asset retirement obligations covered by FIN No. 47 primarily include conditional obligations to demolish assets or return assets in good working condition at the end of the contractual or concession term, and for the removal of equipment containing asbestos and other contaminants. The Company recognized a cumulative effect adjustment in the statement of operations in 2005 of $2 million related to the adoption of FIN No. 47.

GUARANTOR ACCOUNTING—Pursuant to FIN No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others, at the inception of a guarantee, the Company records the fair value of a guarantee as a liability, with the offset dependent on the circumstances under which the guarantee was issued.

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INCOME TAXES—Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Contingent liabilities related to income taxes are recorded when the criteria for loss recognition under SFAS No. 5 Accounting for Contingencies, as amended, have been met.

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

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 during which the sale occurs. The calculation of revenues earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. 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.

GENERAL AND ADMINISTRATIVE 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.

DEFERRED 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. 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 due to the probability of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income.

DERIVATIVES—The Company enters into various derivative transactions in order to hedge its exposure to certain market risks. AES primarily uses derivative instruments to manage its interest rate, commodity, and foreign currency exposures. The Company does not enter into derivative transactions for trading purposes.

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Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, the Company recognizes all derivatives as either assets or liabilities in the balance sheet and measures 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 as, and is designated and qualifies as, a fair value hedge are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as, a cash flow hedge are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions 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. If AES deems that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

For cash flow hedges of forecasted transactions, AES estimates the future cash flows represented by the forecasted transactions, as well as evaluates the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing for the reclassification of gains or losses on cash flow hedges from accumulated other comprehensive loss into earnings.

STOCK OPTIONS—The Company accounts for stock-based compensation plans under the fair value recognition provision of SFAS No. 123, as amended by SFAS No. 148, prospectively to all employee awards granted, modified or settled after January 1, 2003.

The new standard requires companies to recognize compensation cost relating to share-based payment transactions in their financial statements. That cost is to be measured based on the fair value of the equity or liability instruments issued. Starting January 1, 2003, we accounted for our share-based compensation awards under the fair value method prescribed under SFAS No. 123 and accounted for forfeitures on an actual basis, and therefore had reversed compensation expense in the period an award was forfeited. The method was applied prospectively for all employee awards granted, modified or settled after January 1, 2003. Currently, we use a Black-Scholes Option pricing model to estimate the fair value of stock options granted to employees.

In April 2005, the SEC amended the compliance dates for SFAS No. 123(R), to allow companies to implement the standard at the beginning of their next fiscal year, instead of the next reporting period beginning after June 15, 2005. Accordingly, AES adopted SFAS No. 123(R) effective January 1, 2006. For transition purposes, AES elected the modified prospective application method. Under this application method, SFAS No. 123(R) applies to new awards and to awards modified, repurchased, or cancelled after the required effective date.

On November 10, 2005, the FASB released the final FASB Staff Position No. SFAS 123(R)-3, Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards (“FSP SFAS 123(R)-3”). Effective January 1, 2006, AES adopted FSP SFAS 123(R)-3, which provides the Company the option to use the “short-cut method” for calculating the historical pool of windfall tax benefits upon adopting FAS 123(R).

SALES OF STOCK BY A SUBSIDIARY—Sales of stock by a subsidiary of the Company are accounted for as capital transactions pursuant to the SEC’s Staff Accounting Bulletin No. 51 Accounting for Sales of Stock by a Subsidiary (“SAB 51”).

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PENSION AND OTHER POSTRETIREMENT PLANS—The Company adopted SFAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, effective December 31, 2006, which requires recognition of an asset or liability in the balance sheet reflecting the funded status of pension and other postretirement benefits plans with current-year changes in the funded status recognized in stockholders equity. The Company recorded a cumulative adjustment to adopt the recognition provisions of SFAS No. 158 as of December 31, 2006. See Note 12 to these consolidated financial statements for the impact of the adoption of SFAS No. 158. AES will adopt the measurement date provisions of the standard for the fiscal year ending December 31, 2008.

NEW ACCOUNTING PRONOUNCEMENTS

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157 Fair Value Measurement, (“SFAS No. 157”). SFAS No. 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 No. 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.

Under SFAS No. 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 No. 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 No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are currently evaluating the effect of this new standard on our consolidated financial statements.

Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109

FASB Interpretation 48, Accounting for Uncertainty in Income Taxes (“FIN No. 48”) clarifies the accounting for uncertainty in income taxes recognized in our financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes (“SFAS No. 109”). FIN No. 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

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The evaluation of a tax position is a two-step process.

The first step is recognition: The enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that would have full knowledge of all relevant information.

The second step is measurement: A tax position that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

Differences between tax positions taken in a tax return and amounts recognized in the financial statements will generally result in one or a combination of the following:

· An increase in a liability for income taxes payable or a reduction of an income tax refund receivable

· A reduction in a deferred tax asset or an increase in a deferred tax liability

A liability for unrecognized tax benefits will be classified as current to the extent that we anticipate making a payment within one year or the operating cycle, if longer. An income tax liability should not be classified as a deferred tax liability unless it results from a taxable temporary difference (that is, a difference between the tax basis of an asset or a liability as calculated using this Interpretation and its reported amount in the statement of financial position). FIN No. 48 does not change the classification requirements for deferred taxes.

Tax positions that previously failed to meet the more-likely-than-not recognition threshold will be recognized in the first subsequent financial reporting period in which that threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not recognition threshold will be derecognized in the first subsequent financial reporting period in which that threshold is no longer met. Use of a valuation allowance as described in SFAS No. 109 is not an appropriate substitute for the derecognition of a tax position. The requirement to assess the need for a valuation allowance for deferred tax assets based on the sufficiency of future taxable income is unchanged by FIN No. 48.

The Company adopted FIN No. 48 on January 1, 2007 and estimates the cumulative effect of the change in accounting principle to result in a decrease to retained earnings of approximately $50 to $100 million.

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

In February 2007, the FASB issued 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 have not assessed the impact of SFAS 159 on our consolidated results of operations, cash flows or financial position.

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EITF 06-6: Application of Issue No. 05-7 Debtor’s Accounting for a Modification (or Exchange) of Convertible Debt Instruments

In June 2006 the FASB Emerging Issue Task Force (EITF) issued EITF 06-6 Application of Issue No. 05-7 Debtor’s Accounting for a Modification (or Exchange) of Convertible Debt Instruments. This guidance that addresses the treatment of a) whether a change in the fair value of an embedded conversion option resulting from a modification of a convertible debt instrument should be included in the analysis of whether there has been a substantial change in the debt instrument terms for determination if a debt extinguishment has occurred and b) how an issuer should account for modifications that do not result in a debt extinguishment. The consensus was made by the EITF that the change in the fair value of an embedded conversion option resulting from an exchange of or modification in the terms of debt instruments should not be included in the cash flow test to determine whether debt extinguishment accounting should be applied. It was also determined that when a convertible debt instrument is modified or exchanged in a transaction that is not accounted for as an extinguishment, an increase in the fair value of the embedded conversion option should reduce the carrying amount of the debt instrument with a corresponding increase in additional paid in capital.

The consensus in this Issue should be applied to modifications or exchanges of debt instruments occurring in interim or annual reporting periods beginning after Board ratification on November 29, 2006. We are currently evaluating the effect of this Issue on our consolidated financial statements.

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

In September 2006 the FASB Emerging Issue Task Force (EITF)issued 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 that addresses the ability for an entity to issue convertible debt with an embedded conversion option that is required to be bifurcated under SFAS 133 Accounting for Derivative Instruments and Hedging Activities (SFAS 133) if all conditions are met. The EITF reached a consensus that when an embedded conversion option in a convertible debt instrument no longer meets the bifurcation criteria in SFAS 133, an issuer should account for the previously bifurcated conversion option by reclassifying the carrying amount of the liability for the conversion option to shareholder’s equity. Any debt discount recognized when the conversion option was bifurcated from convertible debt should continue to be amortized. It was also determined that if a holder exercises a conversion option for which the carrying amount has previously been reclassified to shareholders’ equity, the issuer should recognize any unamortized discount remaining at the date of conversion immediately as interest expense. All relevant information pertaining to the period in which an embedded conversion option previously accounting under SFAS 133 no longer meets the separation criteria addressed in the pronouncement should be disclosed in the footnotes to the financial statements.

The consensus in this Issue should be applied to previously bifurcated conversion options in convertible debt instruments that cease to meet the bifurcation criteria in SFAS 133 in interim or annual reporting periods beginning after December 15, 2006. We are currently evaluating the effect of this Issue on our consolidated financial statements.

EITF 06-11: Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards

In November 2006 the FASB Emerging Issue Task Force (EITF) issued EITF 06-11 Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards that addresses how a company should recognize the income tax benefit related to the payment of dividends on equity-classified employee share-based payment awards that are charged to retained earnings pursuant to SFAS 123(R) Share Based Payment. The EITF reached a consensus that the appropriate treatment of the income tax benefit should

146

be recognized as an increase in additional paid-in capital. The realized income tax benefit recognized in additional paid-in capital should be included in the pool of excess tax benefits available to absorb future tax deficiencies on share-based payment awards. The tax benefit incurred for dividends paid to employees for non-vested equity-classified employee share-based payment awards shall not be recognized until the respective deduction reduces income taxes payable.

The consensus in this Issue should be applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning after September 15, 2007. We are currently evaluating the effect of this Issue on our consolidated financial statements.

RESTATEMENT

The Company previously identified certain material weaknesses related to its system of interal control over financial reporting which required us to restate our financial statements for the years ended December 31 2005 and prior as disclosed in our Form 10-K filed on May 23, 2007. Subsequent to the filing of our 2006 Form 10-K, certain other errors were found related to Brazil “special obligations” and accounting for leases at our Pakistan and Southland subsidiaries. As a result of these errors we are restating our financial statements for the years ended December 31, 2006 and prior.

The term “August 2007 Restatement” refers collectively to the errors related to special obligations liabilities at the AES Eletropaulo and AES Sul subsidiaries and the errors related to accounting for leases at the AES Southland and Pakistan subsidiaries and the reclassification of EDC and Central Valley into discontinued operations. The term “May 2007 Restatement” refers collectively to the errors that were previously discussed in our 2006 Annual Report on Form 10-K that was filed on May 23, 2007.

147

The following table details the impact of the August 2007 Restatement on the Company’s Consolidated Statement of Operations for the year ended December 31, 2006:

	Year Ended December 31, 2006
				Aug-2007			Discontinued Operations						2006 Form
	2006 Form 10-K			Restatement			EDC			Central Valley			10-K/A
Revenues:
Regulated		$ 6,849			$ —			$ (651	)		$ —			6,198
Non-Regulated		5,450			(48	)		—			(36	)		5,366
Total revenues		12,299			(48	)		(651	)		(36	)		11,564
Cost of Sales:
Regulated		(4,578	)		—			465			—			(4,114	)
Non-Regulated		(4,090	)		(1	)		—			38			(4,052	)
Total cost of sales		(8,668	)		(1	)		465			38			(8,166	)
Gross margin		3,631			(49	)		(186	)		2			3,398
General and administrative expenses		(305	)		—			—			—			(305	)
Interest expense		(1,802	)		—			39			—			(1,763	)
Interest income		443			—			(17	)		—			426
Other expense		(308	)		(139	)		(2	)		—			(449	)
Other income		115			—			(9	)		—			106
Gain (loss) on sale of investments		98			—			—			—			98
Loss on sale of subsidiary stock		(539	)		—			—			—			(539	)
Asset impairment expense		(29	)		—			1			—			(28	)
Foreign currency transaction losses on net monetary position		(77	)		—			(11	)		—			(88	)
Equity in earnings of affiliates		72			—			—			—			72
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST		1,299			(188	)		(185	)		2			928
Income tax expense		(403	)		(1	)		72			(2	)		(334	)
Minority interest expense		(610	)		132			19			—			(459	)
INCOME FROM CONTINUING OPERATIONS		286			(57	)		(94	)		—			135
Income (loss) from operations of discontinued businesses net of income tax		11			—			94			—			105
(Loss) gain from disposal of discontinued businesses net of income tax		(57	)		—			—			—			(57	)
INCOME BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		240			(57	)		—			—

Delaware		54 1163725
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
4300 Wilson Boulevard Arlington, Virginia		22203
(Address of principal executive offices)		(Zip Code)

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share		New York Stock Exchange
AES Trust III, $3.375 Trust Convertible		New York Stock Exchange
Preferred Securities

	2006				2005
Price Range of Common Stock	High		Low		High		Low
First Quarter	$	17.71	$	16.20	$	17.65	$	12.84
Second Quarter	18.76		16.40		17.36		13.72
Third Quarter	21.24		18.25		16.67		14.67
Fourth Quarter	23.72		20.21		17.10		14.94

	Year Ended December 31,
	2006		2005			2004		2003			2002
	(Restated)(1) (Dollars and shares in millions, except per share amounts)
Statement of Operations Data
Revenues	$	11,564	$	10,320		$	8,745	$	7,708		$	6,653
Income (loss) from continuing operations	135		402			172		183			(1,845		)
Discontinued operations, net of tax	48		188			132		(681		)	(1,821		)
Extraordinary item, net of tax	21		—			—		—			—
Cumulative effect of change in accounting principle, net of tax	—		(3		)	—		41			(376		)
Net income available to common stockholders	$	204	$	587		$	304	$	(457	)	$	(4,042	)
Basic earnings (loss) earnings per share:
Income (loss) from continuing operations	$	0.21	$	0.62		$	0.27	$	0.32		$	(3.42	)
Discontinued operations	0.07		0.29			0.20		(1.16		)	(3.38		)
Extraordinary item, net of tax	0.03		—			—		—			—
Cumulative effect of change in accounting principle	—		(0.01		)	—		0.07			(0.70		)
Basic earnings (loss) per share	$	0.31	$	0.90		$	0.47	$	(0.77	)	$	(7.50	)
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	0.20	$	0.61		$	0.27	$	0.32		$	(3.42	)
Discontinued operations	0.07		0.28			0.20		(1.16		)	(3.38		)
Extraordinary item, net of tax	0.03		—			—		—			—
Cumulative effect of change in accounting principle	—		(0.01		)	—		0.07			(0.70		)
Diluted earnings (loss) per share	$	0.30	$	0.88		$	0.47	$	(0.77	)	$	(7.50	)

	December 31,
	2006		2005		2004			2003			2002
	(Restated) (Dollars in millions)
Balance Sheet Data:
Total assets	$	31,201	$	28,995	$	28,417		$	29,133		$	34,516
Non-recourse debt (long-term)	$	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)	$	4,790	$	4,682	$	5,010		$	5,862		$	6,755
Stockholders’ equity (deficit)	$	2,965	$	1,612	$	957	(3)	$	(121	)(3)	$	(823	)(2)(3)

PART I		1
ITEM 1. BUSINESS		19
Overview		19
Subsequent Events		22
Segments		23
Facilities		26
Customers		31
Employees		31
How to Contact AES and Sources of Other Information		31
Executive Officers of the Registrant		32
Regulatory Matters		33
ITEM 1A. RISK FACTORS		54
ITEM 1B. UNRESOLVED STAFF COMMENTS		69
ITEM 2. PROPERTIES		69
ITEM 3. LEGAL PROCEEDINGS		70
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS		78
PART II		79
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS		79
Recent Sales Of Unregistered Securities		79
Market Information		79
Holders		81
Dividends		81
ITEM 6. SELECTED FINANCIAL DATA		81
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.		83
Restatement Of Consolidated Financial Statements		83
Sale of EDC		99
Critical Accounting Estimates		105
Consolidated Results of Operations		109
Capital Resources And Liquidity		120
Off-Balance Sheet Arrangements		129
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		131
Overview Regarding Market Risks		131
Interest Rate Risks		131
Foreign Exchange Rate Risk		131
Commodity Price Risk		131
Value at Risk		131
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		134
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		217
ITEM 9A. CONTROLS AND PROCEDURES		217
ITEM 9B. OTHER INFORMATION.		232

PART III		232
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		232
ITEM 11. EXECUTIVE COMPENSATION		237
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS		275
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		277
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES		279
PART IV		280
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES		280
SIGNATURES		284

Europe & Africa	For the Years Ended December 31,
	2006						2005						2004
Revenue	Revenue			% of Total Revenue			Revenue			% of Total Revenue			Revenue			% of Total Revenue
Europe/Africa Generation		$	852		7	%		$	735		7	%		$	697		8	%
Europe/Africa Utilities		571			5	%		505			5	%		463			5	%

Asia/Middlle East	For the Years Ended December 31,
	2006						2005						2004
Revenue	Revenue			% of Total Revenue			Revenue			% of Total Revenue			Revenue			% of Total Revenue
Asia/Middle East Generation		$	785		7	%		$	600		6	%		$	570		7	%

Asia/Middle East	For the Years Ended December 31,
	2006						2005						2004
Gross Margin	Gross Margin			% of Total Gross Margin			Gross Margin			% of Total Gross Margin			Gross Margin			% of Total Gross Margin
Asia/Middle East Generation		$	200		6	%		$	242		8	%		$	252		10	%

										Favorable/(Unfavorable)
Years Ended December 31,	2006			2005			2004			06 vs. 05				05 vs. 04
(in millions)
Operating	$	2,360		$	2,232		$	1,497			$	128			$	735
Investing	(902		)	(661		)	(743		)		(241		)		82
Financing	(1,317		)	(1,339		)	(1,285		)		22				(54		)

	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	)