UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended March 31, 2009

or

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

Commission file number 1-12291

THE AES CORPORATION

(Exact name of registrant as specified in its charter)

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

(703) 522-1315

Registrant’s telephone number, including area code:

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  ¨    No  ¨

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

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

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

The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, at May 4, 2009, was 666,664,430.

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED March 31, 2009

TABLE OF CONTENTS

PART I: FINANCIAL INFORMATION		3
ITEM 1.	FINANCIAL STATEMENTS	3
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Cash Flows	5
	Condensed Consolidated Statement of Changes in Equity	6
	Notes to Condensed Consolidated Financial Statements	7
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	34
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57
ITEM 4.	CONTROLS AND PROCEDURES	59
PART II: OTHER INFORMATION		60
ITEM 1.	LEGAL PROCEEDINGS	60
ITEM 1A.	RISK FACTORS	60
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	60
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	60
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	60
ITEM 5.	OTHER INFORMATION	61
ITEM 6.	EXHIBITS	61
SIGNATURES		62

2

PART I: FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

THE AES CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(in millions, except per share data)
Revenues:
Regulated	$	1,668		$	1,915
Non-regulated		1,710			2,166
Total revenues		3,378			4,081
Cost of Sales:
Regulated		(1,228	)		(1,356	)
Non-regulated		(1,267	)		(1,683	)
Total cost of sales		(2,495	)		(3,039	)
Gross margin		883			1,042
General and administrative expenses		(85	)		(98	)
Interest expense		(391	)		(435	)
Interest income		98			116
Other expense		(22	)		(25	)
Other income		222			45
Gain on sale of investments		13			4
Impairment expense		-			(47	)
Foreign currency transaction (losses) gains on net monetary position		(39	)		22
Other non-operating expense		(10	)		-
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EQUITY IN EARNINGS OF AFFILIATES		669			624
Income tax expense		(175	)		(239	)
Net equity in earnings of affiliates		7			22
INCOME FROM CONTINUING OPERATIONS		501			407
Income from operations of discontinued businesses, net of income tax expense of $— and $1, respectively		-			2
Loss from disposal of discontinued businesses, net of income tax expense of $— and $—, respectively		-			(1	)
NET INCOME		501			408
Less: Net income attributable to noncontrolling interests		(283	)		(175	)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	218		$	233
BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.33		$	0.35
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		-			-
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.33		$	0.35
DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.33		$	0.34
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		-			-
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.33		$	0.34
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	218		$	232
Discontinued operations, net of tax		-			1
Net income	$	218		$	233

See Notes to Condensed Consolidated Financial Statements

3

THE AES CORPORATION

Condensed Consolidated Balance Sheets

	March 31, 2009			December 31, 2008
	(in millions except share and per share data)
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,267		$	903
Restricted cash		435			729
Short-term investments		1,134			1,382
Accounts receivable, net of allowance for doubtful accounts of $225 and $254, respectively		2,180			2,233
Inventory		502			564
Receivable from affiliates		22			31
Deferred income taxes—current		174			180
Prepaid expenses		347			177
Other current assets		1,152			1,117
Total current assets		7,213			7,316
NONCURRENT ASSETS
Property, plant and equipment:
Land		871			854
Electric generation and distribution assets, and other		24,888			24,654
Accumulated depreciation		(7,685	)		(7,515	)
Construction in progress		3,631			3,410
Property, plant and equipment, net		21,705			21,403
Other assets:
Deferred financing costs, net of accumulated amortization of $268 and $272, respectively		371			366
Investments in and advances to affiliates		949			901
Debt service reserves and other deposits		571			636
Goodwill		1,417			1,421
Other intangible assets, net of accumulated amortization of $185 and $185, respectively		484			500
Deferred income taxes—noncurrent		553			567
Other assets		1,575			1,696
Total other assets		5,920			6,087
TOTAL ASSETS	$	34,838		$	34,806
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	1,087		$	1,042
Accrued interest		334			252
Accrued and other liabilities		2,161			2,660
Non-recourse debt—current		789			1,074
Recourse debt—current		154			154
Total current liabilities		4,525			5,182
LONG-TERM LIABILITIES
Non-recourse debt—noncurrent		12,021			11,869
Recourse debt—noncurrent		4,993			4,994
Deferred income taxes—noncurrent		1,135			1,132
Pension and other post-retirement liabilities		997			1,017
Other long-term liabilities		3,470			3,525
Total long-term liabilities		22,616			22,537
Commitments and contingent liabilities (see Note 7)
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($.01 par value, 1,200,000,000 shares authorized; 675,926,976 issued and 666,399,854 outstanding at March 31, 2009; 673,478,012 issued and 662,786,745 outstanding at December 31, 2008)		7			7
Additional paid-in capital		6,834			6,832
Retained earnings (accumulated deficit)		210			(8	)
Accumulated other comprehensive loss		(3,009	)		(3,018	)
Treasury stock, at cost (9,527,122 and 10,691,267 shares at March 31, 2009 and December 31, 2008, respectively)		(127	)		(144	)
Total The AES Corporation stockholders’ equity		3,915			3,669
NONCONTROLLING INTERESTS		3,782			3,418
Total equity		7,697			7,087
TOTAL LIABILITIES AND EQUITY	$	34,838		$	34,806

See Notes to Condensed Consolidated Financial Statements

4

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(in millions)
OPERATING ACTIVITIES:
Net income	$	501		$	408
Adjustments to net income:
Depreciation and amortization		245			244
(Loss) gain from sale of investments and impairment expense		(12	)		45
Provision for deferred taxes		(25	)		52
(Settlement) accrual of non-cash contingencies		(102	)		41
Loss on the extinguishment of debt		14			-
Other		41			(57	)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		80			(235	)
Decrease (increase) in inventory		47			(21	)
Increase in prepaid expenses and other current assets		(105	)		(126	)
Increase in other assets		(73	)		(35	)
(Decrease) increase in accounts payable and accrued liabilities		(192	)		75
(Decrease) increase in income taxes receivables and payables, net		(9	)		106
Decrease in other liabilities		(34	)		(27	)
Net cash provided by operating activities		376			470
INVESTING ACTIVITIES:
Capital expenditures		(574	)		(633	)
Acquisitions—net of cash acquired		-			(186	)
Proceeds from the sales of assets		5			8
Sale of short-term investments		999			1,281
Purchase of short-term investments		(686	)		(1,373	)
Decrease in restricted cash		293			54
Decrease (increase) in debt service reserves and other assets		73			(13	)
Affiliate advances and equity investments		(30	)		(97	)
Loan advances		-			(172	)
Other investing		(3	)		21
Net cash provided by (used in) investing activities		77			(1,110	)
FINANCING ACTIVITIES:
(Repayments) borrowings under the revolving credit facilities, net		(153	)		178
Issuance of non-recourse debt		244			259
Repayments of non-recourse debt		(169	)		(98	)
Payments for deferred financing costs		(22	)		(5	)
Distributions to noncontrolling interests		(12	)		(4	)
Contributions from noncontrolling interests		73			4
Financed capital expenditures		(49	)		(9	)
Other financing		1			4
Net cash (used in) provided by financing activities		(87	)		329
Effect of exchange rate changes on cash		(2	)		18
Total increase (decrease) in cash and cash equivalents		364			(293	)
Cash and cash equivalents, beginning		903			2,043
Cash and cash equivalents, ending	$	1,267		$	1,750
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	271		$	301
Cash payments for income taxes, net of refunds	$	200		$	63
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Assets acquired in acquisition of subsidiary	$	-		$	60
Non-recourse debt assumed in acquisition of subsidiary	$	-		$	12
Liabilities assumed in acquisition of subsidiary	$	-		$	7

See Notes to Condensed Consolidated Financial Statements

5

THE AES CORPORATION

Condensed Consolidated Statement of Changes in Equity

(Unaudited)

	THE AES CORPORATION STOCKHOLDERS										Noncontrolling Interests		Consolidated Comprehensive Income
	Common Stock		Treasury Stock		Additional Paid-In Capital		(Accumulated Deficit) /Retained Earnings		Accumulated Other Comprehensive Loss
Balance at January 1, 2009	$	7	$	(144)	$	6,832	$	(8)	$	(3,018)	$	3,418	$	-
Comprehensive income
Net income		-		-		-		218		-		283		501
Foreign currency translation adjustment (net of income tax)		-		-		-		-		(72)		3		(69)
Change in derivative fair value (including a reclassification to earnings of $(6), net of income tax)		-		-		-		-		80		14		94
Change in unfunded pension obligation (net of income tax)		-		-		-		-		1		-		1
Other comprehensive income														26
Total comprehensive income													$	527
Capital contributions from noncontrolling interests		-		-		-		-		-		73
Dividends declared to noncontrolling interests		-		-		-		-		-		(9)
Issuance of common stock under benefit plans and exercise of stock options and warrants		-		17		-		-		-		-
Stock compensation		-		-		2		-		-		-
Balance at March 31, 2009	$	7	$	(127)	$	6,834	$	210	$	(3,009)	$	3,782

	THE AES CORPORATION STOCKHOLDERS
	Common Stock		Additional Paid-In Capital		(Accumulated Deficit) /Retained Earnings		Accumulated Other Comprehensive Loss		Noncontrolling Interests		Consolidated Comprehensive Income
Balance at January 1, 2008	$	7	$	6,776	$	(1,241)	$	(2,378)	$	3,241
Comprehensive income
Net income		-		-		233		-		175		408
Change in fair value of available for sale securities (net of income tax)		-		-		-		(1)		-		(1)
Foreign currency translation adjustment (net of income tax)		-		-		-		54		26		80
Change in derivative fair value (including a reclassification to earnings of $(1) million, net of income tax)		-		-		-		(149)		(9)		(158)
Change in unfunded pension obligation (net of income tax)		-		-		-		-		-		-
Other comprehensive income												(79)
Total comprehensive income											$	329
Capital contributions from noncontrolling interests		-		-		-		-		8
Dividends declared to noncontrolling interests		-		-		-		-		(2)
Issuance of common stock under benefit plans and exercise of stock options and warrants		-		13		-		-		-
Stock compensation		-		7		-		-		-
Balance at March 31, 2008	$	7	$	6,796	$	(1,008)	$	(2,474)	$	3,439

See Notes to Condensed Consolidated Financial Statements

6

THE AES CORPORATION

Notes to Condensed Consolidated Financial Statements

For the Three Months Ended March 31, 2009 and 2008

1. FINANCIAL STATEMENT PRESENTATION

The prior period condensed consolidated financial statements in this Quarterly Report have been reclassified to reflect the financial statement presentation requirements of Statement of Financial Accounting Standard (“FAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (“FAS No. 160”), the new reportable segment structure discussed in Note 10 — Segments and businesses held for sale and discontinued operations as discussed in Note 12 — Discontinued Operations of these condensed consolidated financial statements. In addition, certain immaterial prior period amounts have been reclassified within the condensed consolidated financial statements to conform to current period presentation.

Consolidation

In this Quarterly Report the terms “AES”, “the Company”, “us” or “we” refer to the consolidated entity including its subsidiaries and affiliates. The terms “The AES Corporation”, “the Parent” or “the Parent Company” refer only to the publicly-held holding company, The AES Corporation, excluding its subsidiaries and affiliates. Furthermore, variable interest entities (“VIEs”) in which the Company has an interest have been consolidated where the Company is 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 intercompany transactions and balances have been eliminated in consolidation.

Interim Financial Presentation

The accompanying unaudited condensed consolidated financial statements and footnotes have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and Article 10 of Regulation S-X issued by the Securities and Exchange Commission (“SEC”). Accordingly, they do not include all the information and footnotes required by U.S. GAAP for annual fiscal reporting periods. In the opinion of management, the interim financial information includes all adjustments of a normal recurring nature necessary for a fair presentation of the results of operations, financial position and cash flows. The results of operations for the three months ended March 31, 2009, are not necessarily indicative of results that may be expected for the year ending December 31, 2009. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2008 audited consolidated financial statements and notes thereto, which are included in the 2008 Form 10-K, as filed with the SEC on February 26, 2009.

Significant New Accounting Policies

Noncontrolling Interests

Effective January 1, 2009, the Company adopted FAS No. 160, which changed the accounting for and the reporting of minority interest, now referred to as noncontrolling interests, in our condensed consolidated financial statements. The adoption of FAS No. 160 resulted in the reclassification of amounts previously attributable to minority interest to a separate component of stockholders’ equity titled “Noncontrolling Interests” in the accompanying condensed consolidated balance sheets. Additionally, net income and comprehensive income attributable to noncontrolling interests are shown separately from consolidated net income and comprehensive income in the accompanying condensed consolidated statements of operations and statement of equity. Prior period financial statements have been reclassified to conform to the current year presentation as required by FAS No. 160.

7

The following summarizes significant changes in the Company’s accounting policies related to the allocation of losses to noncontrolling interests, sales of stock of a subsidiary and the deconsolidation of a subsidiary:

FAS No. 160 significantly revises the provisions of Accounting Research Bulletin (“ARB”) 51, Consolidated Financial Statements. Under FAS No. 160, losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests’ basis has been reduced to zero. Prior to the implementation of FAS No. 160, losses that otherwise would have been attributed to the noncontrolling interests were allocated to the controlling interests after the balance in the noncontrolling interests was reduced to zero. The Company had no material losses that it did not allocate to the noncontrolling interests prior to the adoption of FAS No. 160 and the adoption did not have a material impact.

FAS No. 160 requires a change in a parent’s ownership interest in a subsidiary when the parent retains its controlling financial interest to be accounted for as an equity transaction. Gains or losses from such transactions are no longer recognized in net income and the carrying values of the subsidiary’s assets (including goodwill) and liabilities are not adjusted. SEC Staff Accounting Bulletin (“SAB”) No. 51, Accounting for Sales of Stock by a Subsidiary (“SAB 51”), had previously provided an option in certain circumstances for a parent to recognize a gain or loss on the sale of stock by a subsidiary or account for the sale as an equity transaction. In certain transactions, AES had previously elected the option to recognize a gain or loss under SAB 51. This option is no longer available under FAS No. 160.

A parent company deconsolidates a subsidiary when that parent company no longer controls the subsidiary. When control is lost, the parent-subsidiary relationship no longer exists and the parent derecognizes the assets and liabilities of the subsidiary. In accordance with FAS No. 160, if the parent company retains a noncontrolling interest, the remaining noncontrolling investment in the subsidiary is remeasured at fair value and is included in the gain or loss recognized upon the deconsolidation of the subsidiary. Under SAB 51, the retained noncontrolling interest in the subsidiary was not adjusted to fair value.

New Accounting Pronouncements

The following accounting standards have been issued, but as of March 31, 2009 are not yet effective and have not been adopted by AES:

FASB Staff Position (“FSP”) FAS No. 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That are Not Orderly (“FSP FAS 157-4”)

In April 2009, the FASB issued FSP FAS 157-4, which provides additional guidance for estimating fair value under FAS No. 157, Fair Value Measurements (“FAS No. 157”), when the volume and level of activity for the asset or liability have significantly decreased. The FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009, or the quarter ending June 30, 2009 for AES. AES is currently evaluating the future impact of FSP FAS 157-4 but at this time does not believe the impact will be material.

FSP FAS No. 115-2 and FAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (“FSP FAS 115-2 and FAS 124-2”)

In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, which amends existing guidance to make the other-than-temporary impairment guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on the debt and equity securities in the financial statements. FSP FAS 115-2 and FAS 124-2 is effective for interim and annual reporting periods ending after June 15, 2009, or the quarter ending June 30, 2009 for AES. AES is currently evaluating the future impact of FSP FAS 115-2 and FAS 124-2 but at this time does not believe the impact will be material.

8

FSP FAS No. 107-1 and APB 28-1: Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”)

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which amends FAS No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements. FSP FAS 107-1 and APB 28-1 also amends APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in all interim financial statements. FSP FAS 107-1 and APB 28-1 is effective for interim and annual reporting periods ending after June 15, 2009, or the quarter ending June 30, 2009 for AES. AES will incorporate the required disclosures into its Form 10-Q for the quarter ending June 30, 2009.

2. INVENTORY

The following table summarizes our inventory balances as of March 31, 2009 and December 31, 2008:

	March 31, 2009		December 31, 2008
	(in millions)
Coal, fuel oil and other raw materials	$	255	$	311
Spare parts and supplies		247		253
Total	$	502	$	564

3. DERIVATIVE INSTRUMENTS

The Company enters into various derivative transactions in order to hedge our exposure to certain market risks. We primarily use derivative instruments to manage interest rate, commodity price and foreign currency exchange rate risk exposures. Derivative transactions are not entered into for trading purposes. Interest rate swap, cap and floor agreements are entered into to manage interest rate risk associated with the Company’s floating-rate borrowings. Electricity and fuel derivative instruments (“commodity derivatives”) are utilized to hedge the risk related to electricity sales and fuel purchases (primarily coal, natural gas and petcoke), respectively. Foreign currency forwards, swaps and options are utilized, where possible, to manage the risk related to fluctuations in certain foreign currencies. Cross currency swaps are utilized, where possible, to manage the risk related to fluctuations in both interest rates and certain foreign currencies.

Under FAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“FAS No. 133”), as amended, we recognize all derivatives, except those designated as “normal purchase normal sale” at inception as either assets or liabilities on the balance sheet at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Gains or losses on derivatives that do not qualify for hedge accounting are recognized as interest expense for interest rate derivatives, foreign currency gains or losses on foreign currency derivatives, and non-regulated revenue or non-regulated cost of sales for commodity derivatives.

FAS No. 133 enables companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as, a cash flow hedge are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions affect earnings. Any ineffectiveness is immediately recognized in earnings. The ineffective portion is recognized as interest expense for interest rate hedges, foreign currency gains or losses on foreign currency hedges, and non-regulated revenue or non-regulated cost of sales for commodity hedges. For all hedge contracts, the Company maintains formal documentation of the hedge and effectiveness testing in accordance with FAS No. 133. If AES deems that a derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

9

Certain derivatives are not designated as hedging instruments. While these instruments economically hedge interest rate risk, foreign exchange risk or commodity price risk, they do not qualify for hedge accounting treatment as defined by FAS No. 133.

The following table sets forth by type of derivative the financial statement location and fair value of our investments in derivative instruments as of March 31, 2009:

	March 31, 2009
	Designated as Hedging Instruments		Not Designated as Hedging Instruments
	(in millions)
Assets
Other current assets
Interest rate derivatives	$	-	$	1
Cross currency derivatives		1		-
Foreign currency derivatives		-		1
Commodity derivatives:
Electricity		129		-
Fuel		-		18
Other		-		1
Total other current assets		130		21
Other assets
Interest rate derivatives		19		-
Cross currency derivatives		1		-
Foreign currency derivatives		-		10
Commodity derivatives:
Electricity		14		-
Fuel		-		7
Total other assets—noncurrent		34		17
Total assets	$	164	$	38
Liabilities
Accrued and other liabilities
Interest rate derivatives	$	61	$	38
Foreign currency derivatives		-		11
Commodity derivatives:
Fuel		-		6
Total accrued and other liabilities—current		61		55
Other long-term liabilities
Interest rate derivatives		279		41
Cross currency derivatives		27		-
Foreign currency derivatives		-		2
Commodity derivatives:
Fuel		-		2
Total other long-term liabilities		306		45
Total liabilities	$	367	$	100

10

The following table sets forth by type of derivative, the financial statement location and amount of gains (losses) recognized in accumulated other comprehensive loss and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships, as defined under FAS No. 133, for the three months ended March 31, 2009:

	Three Months Ended March 31, 2009
	Gain/(Loss) Recognized in OCI on Derivatives		Location of Gain/(Loss) Reclassified from Accumulated OCI into Earnings	Gain/(Loss) Reclassified from Accumulated OCI
	(in millions)			(in millions)
Interest rate derivatives	$	50	Interest expense	$	(1	)(1)
Cross currency derivatives		6	Foreign currency transaction (losses) gains on net monetary position		-
Commodity derivatives - electricity		81	Non-regulated revenue		30
Total	$	137		$	29

⁽¹⁾ Excludes $14 millions of losses reclassified from accumulated other comprehensive income related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting

The following table sets forth by type of derivative the financial statement location and amount of gains (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined under FAS No. 133, for the three months ended March 31, 2009:

	Three Months Ended March 31, 2009
	Location of Gain (Loss) Recognized in Earnings	Amount of Gain (Loss) Recognized in Earnings
		(in millions)
Interest rate derivatives	Interest expense	$	-	(1)
Cross currency derivatives	Foreign currency transaction (losses) gains on net monetary position		2
Commodity derivatives - electricity	Non-regulated revenue		(2	)
Total		$	-

⁽¹⁾ De minimus amount of ineffectiveness recognized

The following table sets forth by type of derivative the financial statement location and amount of gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under FAS No. 133 for the three months ended March 31, 2009:

	Three Months Ended March 31, 2009
	Location of Gain (Loss) Recognized in Earnings	Amount of Gain (Loss) Recognized in Earnings
		(in millions)
Interest rate derivatives	Interest expense	$	(5	)
Foreign currency derivatives	Foreign currency transaction (losses) gains on net monetary position		7
Commodity derivatives - PPA embedded	Non-regulated revenue		(5	)
Commodity derivatives - fuel	Non-regulated cost of sales		(13	)
Total		$	(16	)

Gains and losses on derivative instruments at Indiana Power & Light Company (“IPL”), our North American regulated utility, are accounted for in accordance with FAS No. 71, Accounting for the Effects of

11

Certain Types of Regulation, as regulatory assets or liabilities. Gains and losses due to changes in the fair value of these derivatives are recoverable through future rates and are recognized as an adjustment to the regulatory asset or liability instead of being recognized through earnings, so they are excluded from the above table. For the three months ended March 31, 2009, there was a decrease in the fair value of these derivatives of $1 million and $4 million included in regulatory assets and liabilities, respectively, in the condensed consolidated balance sheet.

The maximum length of time remaining for qualifying cash flow hedge of forecasted interest, cross currency and commodity transactions is 18 years, 20 years and 2 years, respectively. There were no discontinuances of cash flow hedges because it was probable that the forecasted transaction would not occur by the end of the originally specified time period (as documented at the inception of the hedging relationship) or within an additional two-month time period thereafter.

Approximately $8 million of the pre-tax accumulated other comprehensive loss related to derivative instruments as of March 31, 2009 is expected to be recognized as a decrease to income from continuing operations before income taxes over the next twelve months, which relate primarily to interest rate derivatives. The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for interest rate hedges, as depreciation is recognized for hedges of capitalized interest, as foreign currency transaction and translation gains and losses are recognized for hedges of foreign currency exposure, and as electric sales and fuel purchases are recognized for hedges of forecasted electric and fuel transactions. These balances are included in the condensed consolidated statements of cash flows as operating and/or investing activities based on the nature of the underlying transaction.

The following table sets forth, by type of interest rate index, the Company’s outstanding exposures under its interest rate derivative instruments as of March 31, 2009:

	March 31, 2009
	Notional	Notional Translated to USD		Weighted Average Remaining Term
	(in millions)	(in millions)		(in years)
Libor (U.S. Dollar)	2,742	$	2,742	5
Libor (British Pound Sterling)	46		66	2
Treasury Bills (U.S. Dollar)	53		53	1
Euribor (Euro)	681		902	1
Bubor (Hungarian Forint)	5,524		24	1
City of Petersburg, IN Pollution Control Refunding
Revenue Bonds Adjustable Rate (U.S. Dollar)	29		29	14
Securities Industry and Financial Markets Association
(SIFMA) Municipal Swap Index (U.S. Dollar)	11		11	14

The following table sets forth, by type of interest rate index and foreign currency, the Company’s outstanding exposures under its cross currency derivative instruments as of March 31, 2009:

	March 31, 2009
	Notional	Notional Translated to USD		Weighted Average Remaining Term
	(in millions)	(in millions)		(in years)
Chilean Unidad de Fomento (CLF)	6	$	201	17
Euribor (EUR)	6		8	1

12

The following table sets forth, by type of foreign currency denomination, the Company’s outstanding exposures over the remaining term of its foreign currency derivative and embedded derivative instruments as of March 31, 2009:

	March 31, 2009
	Notional	Notional Translated to USD		Weighted Average Remaining Term
	(in millions)	(in millions)		(in years)
Kazakhstani Tenge (KZT)	43,503	$	288	10
Hungarian Forint (HUF)	58		-(1)	1
Argentine Peso (ARS)	22		6	9
U.S. Dollar (USD)	9		9	<1
Euro (EUR)	2		3	10
Brazilian Real (BRL)	4		2	1
British Pound Sterling (GBP)	2		3	<1

⁽¹⁾ De minimus amount

The following table sets forth by type of commodity, the Company’s outstanding exposures over the remaining term of its commodity derivative and embedded derivative instruments as of March 31, 2009:

	March 31, 2009
	Volume	Weighted Average Remaining Term
	(in millions)	(in years)
Coal (Metric tons)	2	2
Natural gas (MMBtu)	110	9
Petcoke (Metric tons)	16	15
Log wood (Tons)	1	4
Electricity (MWhs)	1	1

Eastern Energy, one of our North America generation businesses, sells electricity into the power pool managed by the New York Independent System Operator (“NYISO”). Our commodity transactions at Eastern Energy hedge 73% of the forecasted sales of this electricity through the remainder of 2009 and 9% of the forecasted sales of this electricity through 2010. Eastern Energy is required to post collateral for several counterparties who have market exposure limits defined in their transaction agreements. However, most have maximum collateral posting limits. For those counterparties that require Eastern Energy to post collateral the Company has established two letter of credit facilities in the amounts of $75 million and $350 million that are non-recourse to the Parent Company. As of March 31, 2009, approximately $20 million and $71 million have been utilized under these facilities, respectively.

In December 2007, Gener, our generation business in Chile, entered into cross currency swap agreements with a counterparty to swap the Chilean inflation indexed bonds issued in December 2007 into U.S. Dollars. The cross currency swap agreements require Gener to provide collateral credit support when the fair value of the swaps exceeds the thresholds established in the agreements. These thresholds vary based on Gener’s credit rating. As Gener’s credit rating drops the threshold drops, requiring more collateral support. As of March 31, 2009, Gener had posted $25 million in the form of a letter of credit to support these swaps. If Gener’s credit rating were to fall below the minimum threshold established in the swap agreements, the counterparty could demand immediate collateralization of the entire mark-to-market value of the swaps (excluding credit valuation adjustments) if they were in a liability position, which would have been $38 million at March 31, 2009.

13

4. FAIR VALUE DISCLOSURES

The Company adopted the provisions of FAS No. 157 as of January 1, 2008 for financial assets and liabilities and January 1, 2009 for all nonrecurring fair value measurements of nonfinancial assets. In general the Company’s nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis include goodwill; intangible assets, such as sales concessions, land rights and emissions allowances; and long-lived tangible assets including property, plant and equipment. The Company did not adjust any nonfinancial assets or liabilities measured at fair value on a nonrecurring basis to fair value during the three months ended March 31, 2009. Although the adoption of FAS No. 157 did not materially impact our financial condition, results of operations or cash flows, additional disclosures about fair value measurements are discussed below. Our financial assets and liabilities that are measured at fair value on a recurring basis fall into two broad categories: investments and derivatives. Investments are generally measured at fair value using the market approach. The Company’s investments generally consist of debt and equity securities. Equity securities are adjusted to fair value using quoted market prices. Debt securities primarily consist of certificates of deposit, government debt securities and money market funds held by our Brazilian subsidiaries. Our derivatives are valued using the income approach. When deemed appropriate, the Company minimizes its risk from interest and foreign currency exchange rate and commodity price fluctuations through the use of derivative financial instruments. Our derivatives are primarily interest rate swaps on non-recourse debt to establish a fixed rate on variable rate debt, foreign exchange instruments to hedge against currency fluctuations and derivatives or embedded derivatives associated with commodity contracts. The fair value of our derivative portfolio was determined using internal valuation models, most of which are based on observable market inputs including interest rate curves and forward and spot prices for currencies and commodities.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were measured at fair value on a recurring basis as of March 31, 2009 in accordance with FAS No. 157. Financial assets and liabilities have been classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the determination of the fair value of the assets and liabilities and their placement within the fair value hierarchy levels.

	March 31, 2009			Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(in millions)
Assets
Available-for-sale securities	$	1,037		$	1	$	1,023		$	13
Trading securities		5			5		-			-
Derivatives		202			-		147			55
Total assets	$	1,244		$	6	$	1,170		$	68
Liabilities
Derivatives	$	(467	)	$	-	$	(195	)	$	(272	)
Total liabilities	$	(467	)	$	-	$	(195	)	$	(272	)

14

The following table presents a reconciliation of all assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three months ended March 31, 2009:

	Derivatives			Available-For- Sale Securities
	(in millions)
Balance at December 31, 2008 (1)	$	(69	)	$	42	(4)
Total gains/losses (realized/unrealized) (1)
Included in earnings (2)		(19	)		-
Included in other comprehensive income		63			-
Included in regulatory assets (liabilities) (1)		1
Purchases, issuances and settlements (1)		(10	)		(29	)
Asset transferred in (out) of Level 3		(187	) (3)		-
Liabilities transferred (in) out of Level 3		4			-
Balance at March 31, 2009 (1)	$	(217	)	$	13
Total gains/losses for the period included in earnings attributable to the change in unrealized gains/losses relating to assets and liabilities held at March 31, 2009 and December 31, 2008	$	(19	)	$	-

⁽¹⁾ Derivative assets and (liabilities) are presented on a net basis.

⁽²⁾ See Note 3 — Derivative Instruments for further information regarding where gains and losses included in earnings are reported in the Condensed Consolidated Statements of Operations.

⁽³⁾ Assets transferred out of Level 3 primarily resulted from the election of the normal purchase normal sale designation as of December 31, 2008 for a power purchase agreement. As such, the agreement was measured at fair value using significant unobservable inputs of December 31, 2008, but is subsequently being amortized and not measured at fair value.

⁽⁴⁾ Available-for-sale securities in Level 3 are auction rate securities and variable rate demand notes which have failed remarketing and are not actively trading and for which there are no longer adequate observable inputs available to measure the fair value.

5. SUMMARIZED INCOME STATEMENT INFORMATION OF AFFILIATES

50%-or-less Owned Affiliates and Majority-owned Unconsolidated Subsidiaries

During the first quarter of 2009, the Company amended its July 2008 shareholder agreement with the Government of the Republic of Trinidad and Tobago (“GORTT”) related to the Trinidad development project, Trinidad Generation Unlimited, (“Trinidad”). Based on the terms of the revised agreement, the Company will no longer fund development and as a result its ownership interest was reduced from 60% to 10%. Although the Company’s ownership interest has dropped to 10%, the Company will continue to account for its investment in Trinidad as an equity method investment because AES continues to exercise significant influence through the supermajority vote requirement for any significant future project development activities.

The following table summarizes financial information of the affiliates accounted for using the equity method in which we own 50% or less and have the ability to exercise significant influence but do not control and our majority-owned unconsolidated subsidiaries.

	50%-or-less Owned Affiliates (1) Three Months Ended March 31,				Majority-owned Unconsolidated Subsidiaries (2) Three Months Ended March 31,
	2009		2008		2009			2008
	(in millions)
Revenue	$	248	$	288	$	2		$	46
Gross margin	$	18	$	48	$	-		$	18
Net income	$	11	$	42	$	(2	)	$	4

15

⁽¹⁾ The 50%-or-less Owned Affiliates portion of the table excludes information related to the Companhia Energetica de Minas Gerais (“CEMIG”) business because the Company discontinued the application of the equity method in accordance with its accounting policy regarding equity method investments.

⁽²⁾ The Majority-owned Unconsolidated Subsidiaries portion of the table includes information related to Barry, Cartagena, Cili and IC Ictas Energy Group. Although we continue to maintain 100% ownership of Barry, as a result of an amended credit agreement, no material financial or operating decisions can be made without the banks’ consent, and the Company no longer controls Barry. Consequently, the Company discontinued consolidating the business’s results and began using the equity method to account for this unconsolidated majority-owned subsidiary. In December 2008, the Company’s basis in its investment in Cartagena was reduced to zero and the equity method accounting was suspended. As VIEs, Cartagena, Cili and IC Ictas Energy Group were precluded from consolidation under the provisions of FASB Interpretation Number (“FIN”) No. 46(R), Variable Interest Entities, as the Company determined that it was not the primary beneficiary of the respective VIE’s.

6. LONG-TERM DEBT

Non-Recourse Debt

Subsidiary non-recourse debt in default, or accelerated, including any temporarily waived default, is classified as current debt, in the accompanying condensed consolidated balance sheets. The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of March 31, 2009:

Subsidiary	Primary Nature of Default	March 31, 2009
		Default		Net Assets
		(in millions)
Aixi	Payment	$	2	$	8
Ebute (1)	Covenant		6		168
Kelanitissa	Covenant		50		3
Total		$	58

⁽¹⁾ Ebute, our subsidiary in Nigeria, received a waiver of default on September 18, 2008. The waiver gives Ebute until December 31, 2009 to cure the breached covenants; however, as this waiver does not extend beyond the company’s current reporting cycle and the probability of curing the default cannot be determined, the debt is classified as current.

None of the subsidiaries that are currently in default is a material subsidiary under The AES Corporation’s corporate debt agreements whose defaults would 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 of its non-recourse debt, trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities.

On April 8, 2009, AES Gener, S.A. (“Gener”) issued $196 million aggregate principal amount of unsecured notes in the Chilean market. See further discussion in Note 15 — Subsequent Events.

Recourse Debt

On March 26, 2009, the Parent Company and certain subsidiary guarantors amended the Parent Company’s existing senior secured credit facility pursuant to the terms of Amendment No. 1 (“Amendment No. 1”) to the Fourth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2008 (the “senior

16

secured credit facility”). The senior secured credit facility previously included a $200 million term loan facility maturing on August 10, 2011 and a $750 million revolving credit facility maturing on June 23, 2010 (the “revolving credit facility”).

The principal modification set forth in Amendment No. 1 is a one-year extension of $570 million of revolving credit facility commitments from an original maturity date of June 23, 2010 to July 5, 2011. In addition, certain lenders determined that they would increase their commitment under the revolving credit facility by $35 million from March 26, 2009 through July 5, 2011. Accordingly, Amendment No. 1 increased the size of the revolving credit facility from $750 million to $785 million for the period between the dates of Amendment No. 1 and June 23, 2010. Between June 23, 2010 and July 5, 2011, the revolving credit facility size will be $605 million. No modifications were made to the amount or maturity date of the $200 million term loan facility.

The extended commitments from this amendment were subject to new pricing that included an upfront fee of 1.25% for participating in the extensions and an increase in undrawn commitment fees ranging from 50 to 100 basis points. The annual interest rate on the drawn loans was also increased by 200 basis points to London Inter-Bank Offered Rate (“LIBOR”) plus 3.50%. Pricing and all other material terms remain unchanged for the revolving credit facility commitments which have not been extended.

On April 2, 2009 the Parent Company issued $535 million aggregate principal amount of senior unsecured notes in a private placement. Subsequently, the Parent Company allocated a substantial portion of the proceeds to voluntarily reduce its commitments available under the $600 million senior unsecured credit facility among the Parent Company, Merrill Lynch Bank USA and the banks party thereto, (the “senior unsecured credit facility”) by $425 million. See further discussion in Note 15 — Subsequent Events.

7. CONTINGENCIES AND COMMITMENTS

Environmental

The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of March 31, 2009, the Company had recorded liabilities of $27 million for projected environmental remediation costs. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Based on currently available information and analysis, the Company believes that it is reasonably possible that costs associated with such liabilities, or as yet unknown liabilities, may exceed current reserves in amounts that could be material but cannot be estimated as of March 31, 2009.

As noted in the Company’s 2008 Form 10-K, on April 2, 2007, the U.S. Supreme Court issued a decision in a case involving the regulation of CO₂ emissions from motor vehicles under the Clean Air Act (“CAA”). The Court ruled that CO₂ is a pollutant which potentially could be subject to regulation under Section 202 of the CAA and that the U.S. Environmental Protection Agency (“EPA”) had a duty to determine whether CO₂ emissions contribute to climate change or to provide some reasonable explanation why it would not exercise its authority. In response to the Court’s decision, on July 11, 2008, the U.S. EPA issued an Advanced Notice of Public Rulemaking soliciting public input on whether CO₂ emissions should be regulated from both mobile and stationary sources under Section 202 the CAA. In order for the EPA to regulate CO₂ and other greenhouse emissions under Section 202 of the CAA, such emissions must be “endangering public health and welfare” under the CAA. On April 17, 2009, EPA released proposed findings for comment which included a proposed finding that atmospheric concentrations of six greenhouse gases, including CO₂, “endanger public health and welfare within the meaning of Section 202(a) of the CAA.” While the document did not include proposed regulations, it could be viewed as signaling EPA’s willingness to regulate greenhouse gas emissions under the CAA.

This response to the Court’s decision, coupled with stimulus from the new administration, regulators, members of Congress, states, non-governmental organizations, private parties, the courts and other factors could result in a determination by the EPA to regulate CO₂ emissions from both mobile and stationary sources,

17

including electric power generation facilities. Such a determination by the EPA could result in CO₂ emission limits on stationary sources that do not include market-based compliance mechanisms (e.g., carbon tax, CO₂ emission limits, etc.), which could increase our costs directly and indirectly and have a material adverse effect on our business and/or results of operations. For additional information regarding the risks associated with carbon emissions, see the following items in the Company’s 2008 Form 10-K: Item 1 — Business — Regulatory Matters — Environmental and Land Use Regulations and Item 1A: Risk Factors — Risks Associated with Governmental Regulations and Laws.

As noted in the Company’s 2008 Form 10-K, 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 (“CWA”) Section 316(b) rule regarding existing power plant cooling water intake structures issued by the EPA in 2005 and the subsequent Circuit Court of Appeals decision and the recent Supreme Court decision regarding the rule.

The rule as originally issued would affect 12 of the Company’s U.S. power plants and the rule’s requirements would be implemented via each plant’s national Pollutant Discharge Elimination System water quality renewal process. Since each facility’s design, location, existing control equipment and results of impact assessments must be taken into consideration, costs would likely vary from site to site.

On January 25, 2007, a United States Court of Appeals for the Second Circuit decision vacated and remanded major parts of the rule back to the EPA. In November 2007, three industry petitioners sought review of the Second Circuit’s decision by the U.S. Supreme Court and this review was granted by the U.S. Supreme Court in April 2008. Oral arguments were held in December 2008 an in an April 2009 decision, the U.S. Supreme Court granted the EPA authority to use a cost-benefit analysis when setting technology-based requirements under Section 316(b) of the CWA. The Company is currently unable to predict the final requirements under Section 316(b), but expect that capital investments and/or modifications resulting from such requirements could be significant.

As noted in the Company’s 2008 Form 10-K, on February 6, 2009, the Acting Solicitor General of the United States filed a motion in the U.S. Supreme Court to dismiss the EPA’s request for review of the D.C. Circuit Court’s February 2008 decision vacating the Clean Air Mercury Rule (“CAMR”). On February 23, 2009, the U.S. Supreme Court declined to review the lower court’s CAMR decision. EPA is now expected to propose a new rule to address hazardous air emissions from electric generation power plants. While the exact impact and cost of any such new federal rules or related state proposals cannot be established until they are promulgated, there can be no assurance that the Company’s business, financial conditions or results of operations would not be materially and adversely affected by such rules.

Guarantees, Letters of Credit and Commitments

As of March 31, 2009, The AES Corporation had provided outstanding financial and performance related guarantees or other credit support commitments for the benefit of its subsidiaries, which were limited by the terms of the agreements to an aggregate of approximately $408 million (excluding investment commitments and those collateralized by letters of credit discussed below). The term of these credit support arrangements generally parallels the length of the related financing arrangements or transactions.

As of March 31, 2009, the Parent Company had $203 million in letters of credit outstanding under the revolving credit facility and under the senior unsecured credit facility that operate to guarantee performance of certain project development activities and subsidiary operations. The Company pays letter of credit fees ranging from 1.63% to 13.34% per annum on the outstanding amounts.

As of March 31, 2009, The AES Corporation had $212 million of commitments to invest in subsidiaries under construction and to purchase related equipment excluding approximately $150 million of such obligations

18

already included in the letters of credit discussed above. The Company expects to fund these net investment commitments over time according to the following schedule: $133 million in 2009, $25 million in 2010 and $54 million in 2011. The exact payment schedule will be dictated by construction milestones.

Litigation

The Company is involved in certain claims, suits and legal proceedings in the normal course of business, some of which are described below. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information currently available and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be reasonably estimated as of March 31, 2009.

In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the Fifth District Court found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$959 million ($415 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the Fifth District Court rejected Eletropaulo’s defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro ruled that Eletropaulo was not a proper party to the litigation because any alleged liability was transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the Fifth District Court. Eletropaulo’s subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil have been dismissed. Eletrobrás has requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. After the amount of the alleged debt is determined, Eletrobrás may resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo will be required to provide security in the amount of its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the Fifth District Court grants such request, Eletropaulo’s results of operations may be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the Fifth District Court against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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

19

In August 2000, the Federal Energy Regulation Commission (“FERC”) announced an investigation into the organized California wholesale power markets in order to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. FERC requested documents from each of the AES Southland, LLC plants and AES Placerita, Inc. AES Southland and AES Placerita have cooperated fully with the FERC investigations. AES Southland was not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. AES Placerita is currently subject to refund liability of $588,000 plus interest for spot sales to the California Power Exchange from October 2, 2000 to June 20, 2001 (“Refund Period”). In September 2004, the U.S. Court of Appeals for the Ninth Circuit issued an order addressing FERC’s decision not to impose refunds for the alleged failure to file rates, including transaction specific data, for sales in 2000 and 2001 (“September 2004 Decision”). Although it did not order refunds, the Ninth Circuit remanded the case to FERC for a refund proceeding to consider remedial options. In March 2008, FERC issued its order on remand from the September 2004 decision, requiring the parties to engage in settlement discussions before a settlement judge and establishing procedures for an evidentiary hearing if the settlement process failed. The settlement process has concluded and the hearing process is beginning for AES Placerita and other parties who have not settled. In August 2006 in a separate case, the Ninth Circuit confirmed the Refund Period, expanded the transactions subject to refunds to include multi-day transactions, expanded the potential liability of sellers to include any pre-Refund Period tariff violations, and remanded the matter to FERC (“August 2006 Decision”). In April 2009, the Ninth Circuit denied petitions for rehearing and issued its mandate concerning its August 2006 Decision. FERC has yet to act on the remand. The August 2006 Decision may allow FERC to reopen closed investigations and order relief. AES Placerita made sales during the periods at issue in the September 2004 and August 2006 Decisions. Further FERC proceedings are required to determine potential liability, if any, and judicial review may follow any FERC decision. Prior to the August 2006 Decision, AES Placerita’s potential liability for the Refund and pre-Refund Periods could have approximated $23 million plus interest. However, given the September 2004 and August 2006 Decisions, it is unclear whether AES Placerita’s potential liability is less than or exceeds that amount. AES Placerita believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In August 2001, the Grid Corporation of Orissa, India, now Gridco Ltd (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and

20

holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. The Company subsequently filed an application to recover its costs of the arbitration, which is under consideration by the tribunal. In addition, in September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in Orissa Power Generation Corporation Ltd’s (“OPGC”), and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco’s challenge to the arbitration award is resolved. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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

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

AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took

21

the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney’s Office then requested an injunction which the judge rejected on September 26, 2008. The Public Attorney’s office has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a “Technical Cooperation Protocol” pursuant to which they requested a new deadline from FEPAM in order to present a proposal. In March 2008, the State Prosecution office filed a Public Class Action against AES Florestal, AES Sul and CEEE, requiring an injunction for the removal of the alleged sources of contamination and the payment of an indemnity in the amount of R$6 million ($2.6 million). The injunction was rejected and the case is in the evidentiary stage awaiting the judge’s determination concerning the production of expert evidence. The above referenced proposal was delivered on April 8, 2008. FEPAM responding by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE’s operations. It is estimated that remediation could cost approximately R$14.7 million ($6.4 million). Discussions between Sul and CEEE are ongoing.

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

In April 2004, BNDES filed a collection suit against SEB, a subsidiary of the Company, to obtain the payment of R$3.8 billion ($1.6 billion), which includes principal, interest and penalties under the loan agreement between BNDES and SEB, the proceeds of which were used by SEB to acquire shares of CEMIG. In May 2004, the 15th Federal Circuit Court (“Circuit Court”) ordered the attachment of SEB’s CEMIG shares, which were given as collateral for the loan, as well as dividends paid by CEMIG to SEB. At the time of the attachment, the shares were worth approximately R$762 million ($330 million). In December 2006, SEB’s defense was ruled groundless by the Circuit Court. The Federal Court of Appeals affirmed that decision in February 2009. SEB intends to file further appeals. BNDES has seized a total of approximately R$630 million ($273 million) in attached dividends to date, with the approval of the Circuit Court, and is seeking to recover additional attached dividends. Also, BNDES has filed a plea to seize the attached CEMIG shares. The Circuit Court will consider BNDES’s request to seize the attached CEMIG shares after the net value of the alleged debt is recalculated in

22

light of BNDES’s seizure of dividends. SEB believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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

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

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

In June 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan ordered AES Ust-Kamenogorsk TETS LLP (“UKT”) to pay approximately 835 million KZT ($6 million) to the state for alleged antimonopoly violations in 2005 through January 2007. The Competition Committee also ordered UKT to pay approximately 235 million KZT ($2 million), as estimated by the Company, to certain customers that allegedly had paid unreasonably high power prices since January 2007. In November 2007, the economic court of first instance upheld the Competition Committee’s order in part, finding that UKT had violated Kazakhstan’s antimonopoly laws, but reduced the damages to be paid to the state to 833 million KZT ($6 million) and rejected the damages to be paid to customers. The court of appeals (first panel) later affirmed the economic court’s decision and, therefore, in June 2008, UKT paid the damages. UKT’s subsequent

23

appeals have also been rejected, including by the Supreme Court of Kazakhstan in March 2009. In April 2009, the Competition Committee’s successor (the Antimonopoly Agency) initiated an investigation of UKT’s power sales in 2008 through February 2009. The investigation is ongoing and no order has been issued relating to it. UKT believes it has meritorious defenses and will assert them vigorously in any formal proceeding concerning the investigation; however, there can be no assurances that it will be successful in its efforts.

In July 2007, the Competition Committee ordered Nurenergoservice, an AES subsidiary, to pay approximately 18 billion KZT ($121 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. The Competition Committee’s order was affirmed by the economic court in April 2008. Nurenergoservice’s subsequent appeals have been unsuccessful to date, including at the court of appeals (first panel), which rejected Nurenergoservice’s appeal in July 2008. Also, the economic court has issued an injunction to secure Nurenergoservice’s alleged liability, freezing Nurenergoservice’s bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. In separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately 1.8 billion KZT (approximately $12 million) in administrative fines for its alleged antimonopoly violations. Nurenergoservice’s appeal to the administrative court of first instance was rejected in February 2009. The Antimonopoly Agency has not indicated whether it intends to assert claims against Nurenergoservice for alleged antimonopoly violations post first quarter 2007. Nurenergoservice believes it has meritorious claims and defenses; however, there can be no assurances that it will prevail in these proceedings. As Nurenergoservice did not prevail in the economic court or the court of appeals (first panel) with respect to the alleged damages, it will have to pay the alleged damages or risk seizure of its assets. In February 2009, the Antimonopoly Agency seized approximately 783 million KZT ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice alleged damages liability. Furthermore, as Nurenergoservice did not prevail in the administrative court with respect to the fines, it will have to pay the fines or risk seizure of its assets.

In December 2008, the Antimonopoly Agency ordered Ust-Kamenogorsk HPP (“UK HPP”), a hydroelectric plant under AES concession, to pay approximately 1.1 billion KZT ($7 million) for alleged antimonopoly violations in February through November 2007. The economic court of first instance has issued an injunction to secure UK HPP’s alleged liability, among other things freezing UK HPP’s bank accounts. Also, in March 2009, the economic court affirmed the Antimonopoly Agency’s order. UK HPP’s subsequent appeal to the court of appeals (first panel) was rejected in April 2009. Furthermore, the Antimonopoly Agency has initiated administrative proceedings against UK HPP seeking an unspecified amount of administrative fines for the alleged antimonopoly violations. UK HPP believes it has meritorious defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts. As UK HPP did not prevail in economic court or the court of appeals (first panel) with respect to the alleged damages, it will have to pay the alleged damages or risk seizure of its assets. Furthermore, if UK HPP does not prevail in the administrative court of first instance with respect to the fines, it will have to pay the fines or risk seizure of its assets.

In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of UK HPP and Shulbinsk HPP, another hydroelectric plant under AES concession (collectively, the “Hydros”), in 2008 through February 2009. The investigation is ongoing and no order has been issued relating to it. The Hydros believe they have meritorious defenses and will assert them vigorously in any formal proceeding concerning the investigation; however, there can be no assurances that they will be successful in their efforts.

In July 2007, AES Energia Cartagena SRL, (“AESEC”) initiated arbitration against Initec Energia SA, Mitsubishi Corporation, and MC Power Project Management, SL (“Contractor”) to recover damages from the Contractor for its delay in completing the construction of AESEC’s majority-owned power facility in Murcia, Spain. In October 2007, the Contractor denied AESEC’s claims and asserted counterclaims to recover approximately €12 million ($16 million) for alleged unpaid milestone and scope change order payments, among other things, and an unspecified amount for an alleged early completion bonus. The final hearing is scheduled to begin in June 2009. AESEC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

24

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

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

In October 2007, the Ekibastuz Tax Committee issued a notice for the assessment of certain taxes against AES Ekibastuz LLP. A portion of the assessment, approximately $1.7 million, relates to alleged environmental pollution. The review by the Ekibastuz Tax Committee is ongoing and their decision on any assessment, including the portion related to alleged environmental pollution, is not yet final. In addition, as the result of a subsequent tax audit which was completed on January 24, 2008, an additional amount of approximately 36 million KZT in principal, 20 million KZT in interest and 13 million KZT in penalty (collectively, approximately $500,000), was assessed as underpayment of taxes for the 2004 calendar year and VAT for January 2004. AES Ekibastuz appealed these assessments. However, this position was rejected by the Regional Tax Committee in a decision dated January 30, 2008. On February 29, 2008, AES Ekibastuz appealed to the Ministry of Finance of the Republic of Kazakhstan and is currently awaiting a decision.

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

In June 2008, Ricardo Correa Dubri, by himself and on behalf of Consejo Ecológico Puchuncaví Quintero and Grupo de Acción Ecológica Chinchimen, filed a constitutional protection action with the Valparaiso Court of Appeals (“VCA”) against the Comisión Regional del Medio Ambiente, V Region (Chile) (“COREMA”) and other authorities that participated in the environmental assessment of the Campiche Thermal Power Plant (“Plant”), seeking to revoke the environmental permit for the Plant. In January 2009, the VCA held that the permit was not properly granted and was thus illegal and that the Plant was in an allegedly unsafe area and thus affected the rights of the plaintiffs to live in an unpolluted environment. Later in January 2009, Empresa Eléctrica Campiche S.A. (“EEC”), an affiliate of the Company, and COREMA filed separate appeals with the Supreme Court of Chile against the VCA’s decision. The Supreme Court heard arguments on the appeals in April 2009 and later requested information about the location of the Plant and related issues from the Ministry of Housing and Urbanism and the Municipality of Puchuncaví. The appeals remain pending at the Supreme Court. The VCA’s decision will not become enforceable unless it is affirmed by the Supreme Court. EEC believes that its appeal is meritorious and will pursue it vigorously; however, if EEC fails to prevail in the Supreme Court the construction of the Plant could be delayed.

25

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

In 2007, a lower court issued a decision related to a 1993 claim that was filed by the Public Attorney’s office against Eletropaulo, the São Paulo State Government, SABESP (a state owned company), CETESB (a state owned company) and DAEE (the municipal Water and Electric Energy Department), alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from Pinheiros River into Billings Reservoir. The events in question occurred while Eletropaulo was a state owned company. An initial lower court decision in 2007 found the parties liable for the payment of approximately $230 million for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo which reversed the lower court decision. It is not yet know whether this appellate decision will be appealed by the Public Attorney’s office. If so, Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 2008, IPL received a CAA Section 114 information request. The request seeks various information regarding production levels and projects implemented at IPL’s generating stations, generally for the time period from January 1, 2001 to the date of the information request. A subsequent related request extended the time period to cover certain operational data for the year 2000. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. At this time it is not possible to predict what impact, if any, this request may have on IPL, its results of operation or its financial position.

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

In December 2008, the National Electricity Regulatory Entity of Argentina (“ENRE”) filed a criminal action in the National Criminal and Correctional Court of Argentina against the board of directors and administrators of EDELAP. ENRE’s action concerns certain bank cancellations of EDELAP debt in 2006 and 2007, which were accomplished through transactions between the banks and related AES companies. ENRE claims that EDELAP should have reflected in its accounts the alleged benefits of the transactions that were allegedly obtained by the related companies. EDELAP believes that the allegations lack merit; however, there can be no assurances that its board and administrators will be successful in any formal proceedings concerning the allegations.

In January 2009, an alleged shareholder of the Company filed a putative derivative and class action in Delaware state court against the Company and certain members of its board of directors. The plaintiff claims that Section 2.17(B) of the Company’s bylaws, concerning shareholder action by written consent, is illegal under Delaware law. The plaintiff does not seek damages but declarations that Section 2.17(B) is unlawful and void and

26

that the board member defendants breached their respective fiduciary duties of loyalty by adopting that bylaw in October 2008. The plaintiff further seeks to recover his litigation costs. In April 2009, the parties executed a stipulation of settlement and filed it with the court for approval.

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

In March 2009, Glencore International AG initiated arbitration against Itabo in the International Chamber of Commerce concerning the parties’ coal supply agreement. Glencore claims that Itabo has repudiated and breached the agreement by allegedly failing to purchase coal pursuant to the terms of the agreement. Glencore seeks approximately $75 million in damages, plus interest, among other relief. Itabo believes it has meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

8. PENSION PLANS

Total pension cost for the three months ended March 31, 2009 and 2008 included the following components:

	Three Months Ended March 31,
	2009						2008
	U.S.			Foreign			U.S.			Foreign
	(in millions)
Service cost	$	2		$	3		$	1		$	3
Interest cost		8			100			8			121
Expected return on plan assets		(7	)		(81	)		(8	)		(109	)
Amortization of initial net asset		-			(1	)		-			(2	)
Amortization of prior service cost		1			-			1			-
Amortization of net loss		4			1			-			1
Total pension cost	$	8		$	22		$	2		$	14

Total employer contributions for the three months ended March 31, 2009 for our U.S. and foreign subsidiaries were $6 million and $38 million, respectively. The expected remaining scheduled annual employer contributions for 2009 are $16 million for U.S. subsidiaries and $102 million for foreign subsidiaries.

27

9. COMPREHENSIVE INCOME

The components of comprehensive income for the three months ended March 31, 2009 and 2008 were as follows:

	Three Months Ended March 31,
	2009			2008
	(in millions)
Net income	$	501		$	408
Change in fair value of available-for-sale securities (net of income tax benefit of $— and $1, respectively)		-			(1	)
Foreign currency translation adjustments (net of income tax expense of $1 and $3, respectively)		(69	)		80
Derivative activity:
Reclassification to earnings (net of income tax benefit of $11 and $4, respectively)		(6	)		(1	)
Change in derivative fair value (net of income tax (expense) benefit of $(40) and $86, respectively)		100			(157	)
Total change in fair value of derivatives		94			(158	)
Change in unfunded pension obligation (net of income tax expense of $— and $—, respectively)		1			-
Other comprehensive income		26			(79	)
Comprehensive income		527			329
Less: Comprehensive income attributable to noncontrolling interest		(300	)		(192	)
Comprehensive income attributable to The AES Corporation	$	227		$	137

The components of accumulated other comprehensive loss (net of income tax benefit or expense) as of March 31, 2009 were as follows:

	(in millions)
Foreign currency translation adjustment	$	2,656
Unrealized derivative losses		183
Unfunded pension obligation		170
Accumulated other comprehensive loss March 31, 2009	$	3,009

10. SEGMENTS

As further described below, beginning with this Quarterly Report on Form 10-Q, the Company has modified its segment reporting in accordance with FAS No. 131, Disclosures about Segments of an Enterprise and Related Information (“FAS No. 131”)

Background

Through the end of 2008, the Company organized its operations for management reporting purposes along two primary lines of business – the generation of electricity (“Generation”) and the distribution of electricity (“Utilities”) within four geographic regions: Latin America; North America; Europe & Africa; and Asia & the Middle East (“Asia”). Three regions, North America, Latin America and Europe & Africa, are engaged in both Generation and Utility businesses. Our Asia region only has Generation businesses. This regional management structure resulted in the Company reporting seven segments, as defined in FAS No. 131 in the 2008 Form 10-K.

28

These reportable segments included Latin America – Generation, Latin America – Utilities, North America – Generation, North America – Utilities, Europe & Africa – Generation, Europe & Africa – Utilities and Asia – Generation. In addition, the Company reports certain activities in “Corporate and Other” including corporate overhead costs which are not directly associated with the operations of our primary operating segments; and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation. Our alternative energy business which included AES Wind Generation, climate solutions, and certain other initiatives, was managed by our alternative energy group. The associated revenue, development and operational costs were reported under “Corporate and Other” since its results were not material to the presentation of our operation segments.

2009 Segment Reporting

Management Reporting Structure – In early 2009, we implemented certain internal organizational changes in an effort to streamline the organization. These changes affected how results are reported internally for management review, but did not change any of the chief operating decision makers. The new management reporting structure continues to be organized along our two lines of businesses, but there are now three regions: (1) Latin America & Africa; (2) North America and AES Wind; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The Company no longer has an alternative energy group. Instead, AES Wind Generation is managed as part of our North America region while climate solutions projects are now managed in the region in which they are located. In addition to the change in regional management structure, with the exception of AES Wind Development, the Company now manages all development efforts centrally through a development group.

Segment Reporting Structure – The new segment reporting structure uses the management reporting structure as its foundation. The Company’s segment reporting structure continues to be organized along our two lines of business and three regions to reflect how the Company manages the business internally. The Company applied the guidance in FAS No. 131, which provides certain quantitative thresholds and aggregation criteria, and the Company concluded that it now has six reportable segments. The operating segments comprising the former Europe & Africa Generation and Utilities reportable segments are no longer managed together. Under the new management structure Africa is managed with the Latin America region and Europe is managed with the Asia region. Only Europe – Generation was determined to be a reportable segment based on the Company’s application of FAS No. 131. As described below, our Europe Utilities, Africa Utilities and Africa Generation operating segments are now reported within “Corporate and Other” because they do not meet the quantitative thresholds for separate disclosure under FAS No. 131.

Therefore as a result of this analysis, the Company will now report six segments, which include:

• Latin America – Generation;

• Latin America – Utilities;

• North America – Generation;

• North America – Utilities;

• Europe – Generation;

• Asia – Generation.

29

Corporate and Other – Corporate and Other now includes corporate overhead costs which are not directly associated with the operations of our six primary reportable segments; and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation, the operations for the Company’s Europe and Africa Utilities and Africa Generation businesses, the operations of AES Wind and the development and operational costs related to the development group. None of these operations is currently material to our presentation of reportable segments, individually or in the aggregate.

The Company uses both revenue and gross margin as key measures to evaluate the performance of its segments. Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within the Latin America region. No inter-segment revenue relationships exist between other segments. Gross margin is defined as total revenue less operating expenses including depreciation and amortization, local fixed operating and other overhead costs. Corporate allocations include certain management fees and self insurance activity which are reflected within segment gross margin. All intra-segment activity has been eliminated with respect to revenue and gross margin within the segment; inter-segment activity has been eliminated within the total consolidated results.

As required by FAS No. 131, all prior period information has been recast to reflect the realignment of reportable segments.

Information about the Company’s operations by segment for the three months ended March 31, 2009 and 2008, respectively, was as follows:

	Total Revenue					Inter-segment						External Revenue
Three Months Ended March 31,	2009		2008			2009			2008			2009		2008
						(in millions)
Latin America–Generation	$	891	$	1,206		$	(183	)	$	(258	)	$	708	$	948
Latin America–Utilities		1,214		1,463			-			-			1,214		1,463
North America–Generation		502		551			-			-			502		551
North America–Utilities		290		249			-			-			290		249
Europe–Generation		204		304			-			-			204		304
Asia–Generation		247		312			-			-			247		312
Corporate and Other		30		(4	)		183			258			213		254
Total Revenue	$	3,378	$	4,081		$	-		$	-		$	3,378	$	4,081
	Total Gross Margin					Inter-segment						External Gross Margin
Three Months Ended March 31,	2009		2008			2009			2008			2009		2008
						(in millions)
Latin America–Generation	$	372	$	399		$	(180	)	$	(253	)	$	192	$	146
Latin America–Utilities		171		225			184			258			355		483
North America–Generation		120		160			4			5			124		165
North America–Utilities		70		52			1			1			71		53
Europe–Generation		68		115			1			-			69		115
Asia–Generation		47		48			1			1			48		49
Corporate and Other		35		43			(11	)		(12	)		24		31
Total Gross Margin	$	883	$	1,042		$	-		$	-		$	883	$	1,042

30

Assets by segment as of March 31, 2009 and December 31, 2008, respectively, were as follows:

	Total Assets
	March 31, 2009		December 31, 2008
	(in millions)
Latin America–Generation	$	8,568	$	8,228
Latin America–Utilities		7,230		7,267
North America–Generation		6,423		6,426
North America–Utilities		3,056		3,093
Europe–Generation		2,658		2,656
Asia–Generation		3,050		3,239
Corporate and Other		3,853		3,897
Total Assets	$	34,838	$	34,806

11. OTHER INCOME (EXPENSE)

The components of other income were summarized as follows:

	Three Months Ended March 31,
	2009		2008
	(in millions)
Tax credit settlement	$	129	$	-
Performance incentive fee		80		-
Other		13		45
Total other income	$	222	$	45

Other income generally includes gains on asset sales and extinguishments of liabilities, favorable judgments on legal settlements and other income from miscellaneous transactions. Other income of $222 million for the three months ended March 31, 2009 primarily consisted of a favorable court decision on a legal dispute in which Eletropaulo, the Company’s utility business in Brazil, had requested reimbursement for excess non-income taxes paid from 1989 to 1992. Eletropaulo received reimbursement in the form of tax credit to be applied against future tax liabilities resulting in a $129 million gain. The net impact to the Company after noncontrolling interests was $21 million. In addition, the Company recognized income of $80 million from a performance incentive bonus for management services provided to Ekibastuz and Maikuben in 2008. The management agreement was related to the sale of these businesses in Kazakhstan in May 2008; see further discussion of this transaction in Note 13 — Acquisitions and Dispositions. Other income of $45 million for the three months ended March 31, 2008 primarily consisted of $14 million of compensation for the impairment of plant assets and cessation of the PPA associated with a settlement agreement with the local government to shut down the Hefei generation facility in China and a $6 million insurance recovery at one of our North American businesses.

Other expense generally includes losses on asset sales, losses on the extinguishment of debt, charges from legal disputes and losses from other miscellaneous transactions. Other expense of $22 million for the three months ended March 31, 2009 was primarily comprised of losses on disposal of assets at Eletropaulo and Andres. Other expense of $25 million for the three months ended March 31, 2008 primarily consisted of losses on the disposals of assets at one of our subsidiaries in Brazil and legal reserves.

12. DISCONTINUED OPERATIONS

The Company did not have discontinued operations for the three months ended March 31, 2009.

31

In December 2008, the Company completed the sale of its 70% equity interest in Jiaozuo AES Wanfang Power Co., Ltd. (“Jiaozuo”), which was reported in the Asia Generation segment, for approximately $73 million, net of any withholding taxes. For the three months ended March 31, 2008, income from operations of discontinued businesses, net of tax, was $2 million and reflected the operations of Jiaozuo.

The following table summarizes the revenue, income tax expense and income from operations of the discontinued operation for the three months ended March 31, 2008:

	Three Months Ended March 31, 2008
	(in millions)
Revenue	$	23
Income from operations of discontinued businesses	$	3
Income tax expense		(1	)
Income from operations of discontinued businesses, net of tax	$	2
Loss on disposal of discontinued operations	$	(1	)

13. ACQUISITIONS AND DISPOSITIONS

Dispositions

On May 30, 2008 the Company completed the sale of two of its wholly-owned subsidiaries in Kazakhstan, AES Ekibastuz LLP (“Ekibastuz”), a coal-fired generation plant, and Maikuben West LLP (“Maikuben”), a coal mine. Total consideration received in the transaction was approximately $1.1 billion plus additional potential earn-out provisions, a three-year management and operation agreement and a capital expenditures program bonus. Due to the fact that AES was to have significant continuing involvement in the management and operations of the businesses through its three-year management and operation agreement, the results of operations from Ekibastuz and Maikuben were included in income from continuing operations through the date of the disposition. Income earned as a result of the three-year management and operation agreement has been recognized as management fee income for all periods subsequent to the disposition.

On March 23, 2009, the Company and Kazakhmys PLC (“Kazakhmys”), which purchased the subsidiaries, mutually agreed to terminate the original sale agreement and the three-year management and operation agreement. In connection with the termination of these agreements, the Company and Kazakhmys entered into a new agreement (the “2009 Agreement”). Under the 2009 Agreement, Kazakhmys agreed to pay the Company an $80 million performance incentive bonus in April 2009 for management services provided in 2008, and $102 million in January 2010 to terminate the management agreement. The $80 million performance incentive bonus was recognized as “Other Income” in the Company’s condensed consolidated statement of operations during the first quarter of 2009. Kazakhmys agreed to post collateral in the form of letters of credit as security for the January 2010 payment.

Excluding income earned under the three-year management and operation agreement, Ekibastuz and Maikuben generated no revenue for the three months ended March 31, 2009 and generated revenue of $63 million for the three months ended March 31, 2008. A $13 million gain was also recorded related to a reversal of a tax contingency for a contractual obligation, under which the Company provided indemnification to Kazakhmys, which expired in January 2009. This was recorded as an adjustment to the gain on the sale of Ekibastuz and Maikuben during the three months ended March 31, 2009.

In addition to the $80 million, received in April 2009, and $102 million, payable in January 2010, payments noted above, under the terms of the 2009 Agreement, the parties have agreed to terminate both the Stock

32

Purchase Agreement and the Management Agreement, and have further agreed to a mutual release of prior claims. The 2009 Agreement also provides for a 100 day disengagement period during which the Company will provide continued assistance to Kazakhmys in connection with the transition of management of the operations of the previously sold entities from the Company to Kazakhmys. Despite the termination of the management agreement, the Company’s involvement with the business will remain in place for more than one year from the date of the sale; therefore, the Company has continued to include the businesses as part of continuing operations in the condensed consolidated financial statements.

14. EARNINGS PER SHARE

Basic and diluted earnings per share are based on the weighted average number of shares of common stock and potential common stock outstanding during the period, after giving effect to stock splits. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units and stock options. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable. The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for income from continuing operations. In the table below, income represents the numerator and weighted-average shares represent the denominator:

	Three Months Ended March 31,
	2009					2008
	Income		Shares	$ per Share		Income		Shares	$ per Share
			(in millions except per share data)
BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders	$	218	665	$	0.33	$	232	671	$	0.35
EFFECT OF DILUTIVE SECURITIES
Stock options		-	1		-		-	6		(0.01	)
Restricted stock units		-	-		-		-	2		-
DILUTED EARNINGS PER SHARE	$	218	666	$	0.33	$	232	679	$	0.34

There were approximately 20,849,485 and 7,820,538 additional options outstanding at March 31, 2009 and 2008, respectively, that could potentially dilute basic earnings per share in the future. Those options were not included in the computation of diluted earnings per share because the exercise price exceeded the average market price during the related periods. For the three months ended March 31, 2009 and 2008, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. During the three months ended March 31, 2009, 2,096,389 shares of common stock were issued under the Company’s profit sharing plan and 59,825 shares of common stock were issued upon the exercise of stock options.

15. SUBSEQUENT EVENTS

On April 2, 2009, the Parent Company issued $535 million aggregate principal amount of 9.75% senior unsecured notes due 2016. The notes were priced at a discount to yield 11%. Subsequently, the Parent Company allocated a substantial portion of the proceeds to voluntarily reduce its commitment under the $600 million senior unsecured credit facility by $425 million. The remaining $175 million under the senior unsecured credit facility consists of letters of credit, the majority of which support several projects currently under construction.

On April 8, 2009, AES Gener S.A. (“Gener”) issued $196 million aggregate principal amount of 8% unsecured notes due in 2019. The unsecured notes were priced at a discount to par resulting in an 8.5% yield. The proceeds from this issuance will be used to provide Gener’s funding requirements for projects under construction.

33

ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In this Quarterly Report on Form 10-Q, 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” or “the Parent Company” refers only to the parent, publicly-held holding company, The AES Corporation, excluding its subsidiaries and affiliates.

Forward-Looking Information

The following discussion may contain forward-looking statements regarding us, our business, prospects and our results of operations that are subject to certain risks and uncertainties posed by many factors and events that could cause our actual business, prospects and results of operations to differ materially from those that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those described in the “Risk Factors” section of our 2008 Form 10-K filed on February 26, 2009. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We undertake no obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise interested parties of the risks and factors that may affect our business.

The interim financial statements filed on this Form 10-Q and the discussions contained herein should be read in conjunction with our 2008 Form 10-K.

Overview of Our Business

We are a global power company. We own a portfolio of electricity generation and distribution businesses with generation capacity totaling approximately 43,000 Megawatts (“MW”) and distribution networks serving more than 11 million people. In addition, we have more than 3,400 MW under construction in ten countries. Our global workforce of approximately 25,000 people provides electricity to people in diverse markets ranging from urban centers in the United States to remote villages in India. Our global footprint includes operations in 29 countries on five continents with 80% of our revenue for the first quarter of 2009 generated outside the United States.

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

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

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

The majority of the electricity produced by our Generation businesses is sold under long-term contracts, or PPAs, to wholesale customers. Approximately 56% of the revenues from our Generation businesses during the first quarter of 2009 was derived from plants that operate under PPAs of three years or longer for 75% or more of

34

their output capacity. These businesses often reduce their exposure to fuel supply risks by entering into long-term fuel supply contracts or fuel tolling contracts where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. These long-term contractual agreements result in relatively predictable cash flow and earnings and reduce exposure to volatility in the market price for electricity and fuel; however, the amount of earnings and cash flow predictability varies from business to business based on the degree to which its exposure is limited by the contracts that it has negotiated.

The balance of our Generation businesses sells power through competitive markets under short-term contracts or directly in the spot market. As a result, the cash flows and earnings associated with these businesses are more sensitive to fluctuations in the market price for electricity, natural gas, coal and other fuels.

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

Renewables and Other Initiatives.     In recent years, as demand for renewable sources of energy has grown, we have placed increasing emphasis on developing projects in our renewables business including wind, solar and climate solutions. Climate solutions is our business that develops projects that produce greenhouse gas emission offset credits (“GHG credits”).

Our wind generation business (“AES Wind Generation”) currently has 20 plants in operation in three countries totaling more than 1,200 MW and is one of the largest producers of wind power in the U.S. In addition, more than 400 MW are under construction in four countries outside the U.S. In the area of climate solutions, we have operating projects in Latin America to produce GHG credits and are currently developing projects in Asia. While none of these renewable and other initiatives are currently material to our operations, we believe that in the future, they may become a material contributor to our revenue and gross margin. However, there are risks associated with these initiatives, which are further disclosed in the 2008 Form 10-K. As further described in “Our Organization and Segments” below, some of these projects will be managed within the region where they are located, while others are managed as business units.

Our solar business, AES Solar Energy LLC (“AES Solar”), was formed in March 2008 as a joint venture with Riverstone Holdings, LLC (“Riverstone”), a private equity firm. AES Solar has since commenced commercial operations of eight plants totaling 24 MW of solar projects in Spain and has development potential in three other countries. We account for our investment in AES Solar under the equity method of accounting.

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

One of the key factors which affect both our revenue and costs of sales is change in the cost of fuel. When fuel costs increase, many of our Generation businesses with long-term contracts and our Utilities businesses are

35

able to pass these costs on to the customer through fuel pass-through or fuel indexing arrangements in their contracts or through increases in tariff rates. Therefore, in a rising fuel cost environment increases in fuel costs for these businesses often result in increases in revenue (though not necessarily on a one-for-one basis). In addition, where fuel is a pass-through cost, increased fuel costs could result in counterparties electing to purchase less energy from our Generation businesses. This would result in a decrease in generation volume and an unfavorable impact on revenue with no corresponding impact to gross margin. While these circumstances may not have a large impact on gross margin, they can significantly affect gross margin as a percentage of revenue. Other factors that can affect gross margin include our ability to expand the number of facilities we own and our existing plants, our ability to sign up new customers and/or purchasing parties, collect receivables from existing customers and operate our plants more efficiently.

Another key driver of our results is the management of risk. Our assets are diverse with respect to fuel source and type of market, which helps reduce certain types of operating risk. Our portfolio employs a broad range of fuels, including coal, gas, fuel oil and renewable sources such as hydroelectric power, wind and solar, which reduces the risks associated with dependence on any one fuel source. Our presence in mature markets helps reduce the volatility associated with our businesses in faster-growing emerging markets. In addition, as noted above, our Generation portfolio is largely contracted, which reduces the risk related to the market prices of electricity and fuel. We also attempt to limit risk by hedging certain currency and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the business that issued that debt. However, we do not fully hedge currency or commodity risks and our businesses are still subject to these risks, as further described in the 2008 Form 10-K, Item 1A – Risk Factors, “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.” and “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.”

In each country where we conduct business, we are subject to extensive and complex governmental regulations which affect most aspects of our business, such as regulations governing the generation and distribution of electricity, and environmental regulations. Regulations differ on a country by country basis and are based upon the type of business we operate in a particular country, but affect the operation, development, capital expenditures, growth and ownership of our businesses. While not currently material to our operations, environmental and land use regulations, including proposed regulation of carbon emissions, could substantially increase our capital expenditures, which could in turn have a material adverse affect on our business and results of operations. As noted in Note 7 – Contingencies and Commitments – Environmental, recent actions by the EPA could be interpreted as signaling willingness to regulate GHG emissions under the CAA. For additional discussion regarding the potential risks to the Company relating to carbon emissions, see the following sections in our 2008 Form 10-K: Item 1: Business – Regulatory Matters – Environmental and Land Use Regulations; Item 1A: Risk Factors – Risks Associated with Government Regulation and Laws – Our businesses are subject to stringent environmental laws and regulation; and. Item 1A: Risk Factors – Risks Associated with Government Regulation and Laws – Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and are taking actions which, in addition to the potential physical risks associated with climate change, could have a material adverse impact on our consolidated results of operations, financial condition and cash.

Credit Crisis and the Macroeconomic Environment

In the second half of 2007, conditions in the credit markets began to deteriorate in the United States and abroad. In the third quarter of 2008, this crisis and associated market conditions worsened dramatically, with unprecedented market volatility, widening credit spreads, volatile currencies, illiquidity, and increased counterparty credit risk. The crisis continued through the quarter ended March 31, 2009 and beyond.

Beginning in the second half of 2007 and through the second quarter of 2008, the Company began a series of debt-related initiatives including the refinancing of approximately $2 billion of recourse debt which enabled it to reduce the 2009 maturities of its recourse debt from $467 million as of June 30, 2007 to $154 million as of December 31, 2008. Recourse debt maturing in 2009 as of March 31, 2009 was $154 million. In addition, in the

36

second quarter of 2008, the Parent Company was also able to eliminate many of the restrictive covenants in its 8.75% Second Priority Senior Secured Notes due 2013 and modified certain covenants in its senior secured credit facility. The amendments made the financial covenants less restrictive and made certain other changes, such as expanding the Parent Company’s ability to repurchase its own common stock. In March and April 2009, the Parent Company furthered these initiatives by amending and extending the maturity date of its existing revolving credit facility; issuing $535 million of 9.75% senior unsecured notes due 2016 and reducing the commitment under its $600 million senior unsecured credit facility to $175 million, each of which is more fully discussed under “Recourse Debt”.

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

The Company is also subject to credit risk, which includes risk related to the ability of counterparties (such as parties to our power purchase agreements, fuel supply agreements, our hedging agreements, and other contractual arrangements) to meet their contractual payment obligations or the potential nonperformance of counterparties to deliver contracted commodities or services at the contracted price. While counterparty credit risk has increased in the current crisis and there can be no assurances regarding the future, the Company has not suffered any material effects related to its counterparties for the quarter ended March 31, 2009.

The global economic slowdown could also result in a decline in the value of our assets including the businesses we operate, equity investments and projects under development, which could result in impairments that could be material to our operations. For example, during the fourth quarter of 2008, and in response to the financial market crisis, the Company reviewed and prioritized the projects in its development pipeline and consequently recognized an impairment charge of approximately $75 million ($34 million, net of noncontrolling interests and income taxes). The Company did not realize material impairment charges during the first quarter of 2009. However in the future, we may be required to adjust to fair value and record an impairment of certain of our assets if any of the following events occur: a significant adverse change in business climate or legal factors, an adverse action or assessment by a regulator, sale of assets at below book value, unanticipated competition, a loss of key personnel or our acquisitions do not perform as expected. The likelihood of the occurrence of these events may increase as a result of the credit crisis and deteriorating global macroeconomic conditions, such as a loss of key personnel, asset sales or a change in business climate.

As previously discussed in the Company’s 2008 Form 10-K within Item 1A: Risk Factors – Risks Associated with our Operations – Our acquisitions may not perform as expected, the Company continued to evaluate its Masinloc operations, acquired in April 2008, and completed a goodwill impairment test of the Masinloc reporting unit as of March 31, 2009 and concluded that no impairment existed. The Company will continue to monitor Masinloc’s operating results and business outlook to identify any changes that could indicate a potential impairment of the business’s goodwill, whose balance was approximately $60 million as of March 31, 2009.

A decline in asset value could result in a material increase in our obligations as a result of the deterioration in the financial markets. For instance, certain subsidiaries of the Company have defined benefit pension plans. The Company periodically evaluates the value of the pension plan assets to ensure that they will be sufficient to fund their respective pension obligations. Given the declines in worldwide asset values, we are expecting an increase in pension expense and funding requirements in future periods, which may be material. Total employer contributions for the three months ended March 31, 2009 for our U.S. and foreign subsidiaries were $6 million and $38 million, respectively. The expected remaining scheduled annual employer contributions for 2009 are $16 million for U.S. subsidiaries, and $102 million for foreign subsidiaries.

Furthermore, volatility in foreign currency exchange rates has had an impact on the Company’s financial results. For example, in the first quarter of 2009, our gross margin declined by $159 million compared to the same

37

period last year. During the same period the Company experienced foreign currency translation losses of $130 million. If the current volatility in foreign currencies continues, our gross margin and other financial metrics could be impacted at the same or more severe levels than those noted above. It is also possible that commodity or power price volatility could impact our financial metrics. As further discussed in Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk, we estimate that a 10% decline in power prices will result in an estimated reduction in gross margin of $12 million for our U.S.-based assets.

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

Our Organization and Segments

As further described below, beginning with this Quarterly Report on Form 10-Q, the Company has modified its segment reporting in accordance with FAS No. 131, Disclosures about Segments of an Enterprise and Related Information (“FAS No. 131”)

Background

Through the end of 2008, the Company organized its operations for management reporting purposes along two primary lines of business – Generation and Utilities, within four geographic regions: Latin America; North America; Europe & Africa; and Asia & the Middle East (“Asia”). Three regions, North America, Latin America and Europe & Africa, are engaged in both Generation and Utility businesses. Our Asia region only has Generation businesses. This regional management structure resulted in the Company reporting seven segments, as defined in FAS No. 131 in the 2008 Form 10-K. These reportable segments included Latin America – Generation, Latin America – Utilities, North America – Generation, North America – Utilities, Europe & Africa – Generation, Europe & Africa – Utilities and Asia – Generation. In addition, the Company reports certain activities in “Corporate and Other” including corporate overhead costs which are not directly associated with the operations of our primary operating segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation. Our alternative energy business which included AES Wind Generation, climate solutions, and certain other initiatives, was managed by our alternative energy group. The associated revenue, development and operational costs were reported under “Corporate and Other” since its results were not material to the presentation of our operation segments.

2009 Segment Reporting

Management Reporting Structure – In early 2009, we implemented certain internal organizational changes in an effort to streamline the organization. These changes affected how results are reported internally for management review, but did not change any of the chief operating decision makers. The new management

38

reporting structure continues to be organized along our two lines of businesses, but there are now three regions: (1) Latin America & Africa; (2) North America and AES Wind; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The Company no longer has an alternative energy group. Instead, AES Wind Generation is managed as part of our North America region while climate solutions projects are now managed in the region in which they are located. In addition to the change in regional management structure, with the exception of AES Wind Development, the Company now manages all development efforts centrally through a development group.

Segment Reporting Structure – The new segment reporting structure uses the management reporting structure as its foundation. The Company’s segment reporting structure continues to be organized along our two lines of business and three regions to reflect how the Company manages the business internally. The Company applied the guidance in FAS No. 131, which provides certain quantitative thresholds and aggregation criteria, and the Company concluded that it now has six reportable segments. The operating segments comprising the former Europe & Africa Generation and Utilities reportable segments are no longer managed together. Under the new management structure Africa is managed with the Latin America region and Europe is managed with the Asia region. Only Europe – Generation was determined to be a reportable segment based on the Company’s application of FAS No. 131. As described below, our Europe Utilities, Africa Utilities and Africa Generation operating segments are now reported within “Corporate and Other” because they do not meet the quantitative thresholds for separate disclosure under FAS No. 131.

Therefore as a result of this analysis, the Company will now report six segments, which include:

• Latin America – Generation;

• Latin America – Utilities;

• North America – Generation;

• North America – Utilities;

• Europe – Generation;

• Asia – Generation.

Corporate and Other – Corporate and Other now includes corporate overhead costs which are not directly associated with the operations of our six primary reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation; the operations for the Company’s Europe and Africa Utilities and Africa Generation businesses; the operations of AES Wind and the development and operational costs related to the development group. None of these operations is currently material to our presentation of reportable segments, individually or in the aggregate.

As required by FAS No. 131, all prior period information within this Form 10-Q has been recast to reflect the realignment of reportable segments.

First Quarter 2009 Highlights

First Quarter Events

During the first quarter we reached an agreement with Kazakhmys PLC (“Kazakhmys”) to terminate the management agreement signed at the time AES Ekibastuz LLP (“Ekibastuz”) and AES Maikuben LLP

39

(“Maikuben”) were sold to Kazakhmys in May 2008 for $1.1 billion. Under the original terms of the management agreement, we would have continued to manage and operate Ekibastuz and Maikuben through 2010. The termination agreement provided for an $80 million management performance incentive bonus as compensation for the management services provided by AES in 2008. This was recognized as other income in the first quarter of 2009. In addition, AES will also receive $102 million in early 2010 to terminate the management agreement. Kazakhmys agreed to post collateral in the form of letters of credit as security for this payment. AES will transition the management of the businesses to Kazakhmys over the next several months.

Local Chilean regulators approved the issuance of 954 million shares of AES Gener (“Gener”) in late December 2008. Gener anticipates using these proceeds for future expansion plans, working capital and other operating needs. During the first quarter of 2009, one of our wholly-owned subsidiaries, Cachagua, paid $175 million to purchase 681 million shares using the proceeds from Gener’s November 2008 share sale to maintain its ownership percentage of 71%. This is further discussed in the Notes to our Financial Statements included in our 2008 Form 10-K Note 27 — Subsequent Events.

In March 2009, the Parent Company amended its existing senior secured credit facility that included a $200 million term loan facility and a revolving credit facility. The principal modification was a one year extension of $570 million of revolving credit facility commitments from an original maturity date of June 23, 2010 to July 5, 2011. In addition, certain lenders determined that they would increase their commitments under the revolving credit facility by $35 million from March 26, 2009 through July 5, 2011 increasing the availability under the revolving credit facility from $750 million to $785 million for the period March 26, 2009 until June 23, 2010. Between June 23, 2010 and July 5, 2011, the revolving credit facility will be $605 million. No modifications were made to the amount or maturity date of the $200 million term loan facility.

Recent Developments

On April 2, 2009, the Parent Company issued $535 million aggregate principal amount of 9.75% senior unsecured notes (“the Senior Notes”) due 2016. The notes were priced at a discount to yield 11%. The Parent Company intends to use the net proceeds from the sale of the notes for general corporate purposes, including, but not limited to, refinancing debt or providing working capital. Subsequently, the Parent Company allocated a substantial portion of the proceeds to voluntarily reduce its commitment under the $600 million senior unsecured credit facility by $425 million. The remaining $175 million committed under the senior unsecured credit facility consists of letters of credit, the majority of which continues to support several projects currently under construction.

On April 8, 2009, Gener issued $196 million aggregate principal amount of 8% unsecured notes in the Chilean market. The unsecured notes were issued in the Chilean market at a discount resulting in a yield of 8.5%. The proceeds from this issuance will be used to provide Gener’s funding requirements for projects currently under construction.

First Quarter Performance Highlights

	Three Months Ended March 31,
	2009		2008		% Change
	($’s in millions, except per share amounts)
Revenue	$	3,378	$	4,081	-17%
Gross margin	$	883	$	1,042	-15%
Gross margin as a % of revenue		26%		26%
Diluted earnings per share from continuing operations	$	0.33	$	0.34	-3%
Net cash provided by operating activities	$	376	$	470	-20%

40

Revenue

Revenue decreased $703 million, or 17%, to $3.4 billion for the three months ended March 31, 2009 compared with the same period in 2008 primarily due to the unfavorable impact of foreign currency of $578 million primarily in Latin America and lower power prices, particularly in Chile. These were partially offset by the impact of new businesses.

Gross Margin

Gross margin decreased $159 million, or 15%, to $883 million for the three months ended March 31, 2009 compared with the same period in 2008 primarily due to the unfavorable impact of foreign currency translation of $130 million and the impact of lower electricity prices and decreased volumes at our existing generation businesses of $63 million. These decreases were partially offset by the favorable impact of higher rates at our utilities businesses, contributions from new businesses and fewer outages. We believe that it is reasonably possible that the year-over-year declining trend in gross margin will continue. The Company’s future gross margin trends may continue to be significantly impacted by currency exchange rates, commodity prices and the impact of any significant regulatory developments in each country where the Company conducts its business. The Company is subject to extensive and complex governmental regulations which affect most aspects of our business, such as regulations governing the generation and distribution of electricity and environmental regulations.

Diluted Earnings Per Share From Continuing Operations

Diluted earnings per share from continuing operations attributable to The AES Corporation decreased $0.01 per diluted share to $0.33 per diluted share for the three months ended March 31, 2009, compared with $0.34 per diluted share for the three months ended March 31, 2008. The decrease was primarily driven by the unfavorable impact of foreign currency. This was partially offset by an $80 million, or $0.12 per diluted share performance incentive bonus received for management services provided in Kazakhstan.

Net Cash Provided By Operating Activities

Net cash provided by operating activities decreased 20% to $376 million for the three months ended March 31, 2009 compared with $470 million for the same period in 2008. This decrease was primarily due to lower cash earnings, increased cash payments on interest rate swap agreements and increased cash payments for taxes in Latin America. This decrease was partially offset by improved working capital in Asia and improved operating performance in Europe. For further discussion see Consolidated Cash Flows – Operating Activities.

Significant New Accounting Policies and Recently Issued Accounting Pronouncements

Please refer to the discussion of Significant New Accounting Policies and Recently Issued Accounting Pronouncements in Note 1 — Financial Statement Presentation in the condensed consolidated financial statements included in Item 1 of this Form 10-Q.

41

Consolidated Results of Operations

	Three Months Ended March 31,
RESULTS OF OPERATIONS	2009			2008			$ change			% change
	($’s in millions, except per share amounts)
Revenue:
Latin America Generation	$	891		$	1,206			$    (315	)	-26	%
Latin America Utilities		1,214			1,463			(249	)	-17	%
North America Generation		502			551			(49	)	-9	%
North America Utilities		290			249			41		16	%
Europe Generation		204			304			(100	)	-33	%
Asia Generation		247			312			(65	)	-21	%
Corporate and Other (1)		30			(4	)		34		850	%
Total Revenue		3,378			4,081			(703	)	-17	%
Gross Margin:
Latin America Generation		372			399			(27	)	-7	%
Latin America Utilities		171			225			(54	)	-24	%
North America Generation		120			160			(40	)	-25	%
North America Utilities		70			52			18		35	%
Europe Generation		68			115			(47	)	-41	%
Asia Generation		47			48			(1	)	-2	%
Corporate and Other (2)		(50	)		(55	)		5		9	%
Interest expense		(391	)		(435	)		44		10	%
Interest income		98			116			(18	)	-16	%
Other expense		(22	)		(25	)		3		12	%
Other income		222			45			177		393	%
Gain on sale of investments		13			4			9		225	%
Impairment expense		-			(47	)		47		100	%
Foreign currency transaction (losses) gains on net monetary position		(39	)		22			(61	)	-277	%
Other non-operating expense		(10	)		-			(10	)	-100	%
Income tax expense		(175	)		(239	)		64		27	%
Net equity in earnings of affiliates		7			22			(15	)	-68	%
Income from continuing operations		501			407			94		23	%
Income from operations of discontinued businesses		-			2			(2	)	-100	%
Loss from disposal of discontinued businesses		-			(1	)		1		100	%
Net income		501			408			93		23	%
Noncontrolling interest		(283	)		(175	)		(108	)	-62	%
Net income attributable to The AES Corporation	$	218		$	233		$	(15	)	-6	%
PER SHARE DATA:
Basic income per share from continuing operations	$	0.33		$	0.35		$	(0.02	)	-6	%
Diluted income per share from continuing operations	$	0.33		$	0.34		$	(0.01	)	-3	%

⁽¹⁾ Corporate and Other includes revenue from our generation and utilities businesses in Africa, utilities businesses in Europe, AES Wind and other renewables projects and inter-segment eliminations of revenue related to transfers of electricity from Tietê (generation) to Eletropaulo (utility).

⁽²⁾ Total Corporate and Other includes the gross margin from our generation and utilities businesses in Africa, utilities businesses in Europe and AES Wind and other renewables projects, development costs, corporate general and administrative expenses as well as certain inter-segment eliminations, primarily corporate charges for self insurance premiums.

Revenue

Revenue decreased $703 million, or 17%, to $3.4 billion for the three months ended March 31, 2009 compared with the same period in 2008 primarily due to the unfavorable impact of foreign currency of $578

42

million primarily in Latin America and lower power prices, particularly in Chile. These were partially offset by the impact of new businesses. In addition, first quarter revenue declined due to reduced volume at our generation businesses where fuel costs are passed through to the customers.

Gross Margin

Gross margin decreased $159 million, or 15%, to $883 million for the three months ended March 31, 2009 compared with the same period in 2008 primarily due to the unfavorable impact of foreign currency translation of $130 million and the impact of unfavorable generation rates and volumes at our existing generation businesses of $63 million. These decreases were partially offset by the favorable impact of higher rates at our utilities, contributions from new businesses and a decrease in outages.

Segment Analysis

Latin America

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

	For the Three Months Ended March 31,
	2009		2008		% Change
	(in millions)
Latin America Generation
Revenue	$	891	$	1,206	-26%
Gross Margin	$	372	$	399	-7%
Gross Margin as a % of Segment Revenue		42%		33%

Generation revenue for the three months ended March 31, 2009 decreased $315 million, or 26%, compared to the three months ended March 31, 2008 primarily due to lower contract, spot prices and volume at Gener in Chile of $161 million and in the Dominican Republic of $23 million. This decrease was also due to the unfavorable impact of foreign currency translation of $76 million, and lower contract prices and volume at Uruguaiana in Brazil of $53 million as a result of the renegotiation of one of its power sales agreements.

Generation gross margin for the three months ended March 31, 2009 decreased $27 million, or 7%, compared to the three months ended March 31, 2008 primarily due to lower contract and spot prices at Gener of $110 million, the unfavorable impact of foreign currency translation of $47 million and lower contract and spot prices, higher fuel prices and lower volume in Argentina of $27 million. These decreases were partially offset by a reduction in purchased energy as a result of lower fuel costs at Gener of $71 million, a reduction in purchased energy at Uruguaiana of $48 million, and the favorable impact at Uruguaiana of $34 million as a result of the renegotiation of one of its power sales agreements. These favorable impacts to gross margin combined with the decrease in generation revenue, in particular at Gener and Uruguaiana, resulted in an increase in gross margin as a percentage of segment revenue from 33% for the three months ended March 31, 2008 to 42% for the three months ended March 31, 2009.

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

	For the Three Months Ended March 31,
	2009		2008		% Change
	(in millions)
Latin America Utilities
Revenue	$	1,214	$	1,463	-17%
Gross Margin	$	171	$	225	-24%
Gross Margin as a % of Segment Revenue		14%		15%

43

Utilities revenue for the three months ended March 31, 2009 decreased $249 million, or 17%, compared to the three months ended March 31, 2008 primarily due to the unfavorable impact of foreign currency translation of $345 million. This decrease was partially offset by higher tariffs in Brazil and El Salvador of $100 million.

Utilities gross margin for the three months ended March 31, 2009 decreased $54 million, or 24%, compared to the three months ended March 31, 2008 primarily due to the unfavorable impact of foreign currency translation of $52 million and $25 million of higher operating costs at Eletropaulo in Brazil mainly due to pension costs and costs associated with the successful resolution of legal cases. These decreases were partially offset by an increase of $29 million from lower energy prices primarily driven by a reduction in volume due to the renegotiation of the PPA between Uruguaiana and Sul.

North America

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

	For the Three Months Ended March 31,
	2009		2008		% Change
	(in millions)
North America Generation
Revenue	$	502	$	551	-9	%
Gross Margin	$	120	$	160	-25	%
Gross Margin as a % of Segment Revenue		24%		29%

Generation revenue for the three months ended March 31, 2009 decreased $49 million, or 9% compared to the three months ended March 31, 2008 primarily due to lower rates and volume in New York of $28 million, the unfavorable impact of foreign currency translation of $15 million at our businesses in Mexico and a reduction in back-up power recoveries due to fewer planned outages of $13 million at TEG/TEP in Mexico. Additionally, revenue decreased due to an increase in planned outages at Thames in Connecticut and Hawaii of $10 million. These decreases were partially offset by a net increase of $12 million, excluding the unfavorable impact of foreign currency translation discussed above, at Merida in Mexico due to a revenue adjustment in 2008 partially offset by a decrease in natural gas prices in 2009.

Generation gross margin for the three months ended March 31, 2009 decreased $40 million, or 25% compared to the three months ended March 31, 2008 primarily due to lower rates and volume of $28 million in New York, a decrease of $22 million in Hawaii which included an $8 million mark-to-market derivative loss on a coal supply contract, an increase in planned outages and an increase in coal prices. Additionally, gross margin decreased due to an increase in planned outages of $7 million at Thames and the unfavorable impact of foreign currency translation of $2 million at our businesses in Mexico. These decreases were partially offset by an $18 million revenue adjustment in 2008 at Merida and a decrease of $5 million at TEG/TEP from higher volume and a reduction in back-up power recoveries due to fewer planned outages. Gross margin as a percentage of revenue decreased in 2009 primarily due to lower rates in New York and the unfavorable impact of a mark-to-market derivative loss in Hawaii.

The Utilities segment in North America consists solely of our integrated utility business in Indiana, IPL. The following table summarizes revenue and gross margin for our Utilities segment in North America for the periods indicated:

	For the Three Months Ended March 31,
	2009		2008		% Change
	(in millions)
North America Utilities
Revenue	$	290	$	249	16	%
Gross Margin	$	70	$	52	35	%
Gross Margin as a % of Segment Revenue		24%		21%

44

Utilities revenue for the three months ended March 31, 2009 increased $41 million, or 16%, compared to the three months ended March 31, 2008 primarily due to $30 million of credits to retail customers established during the first quarter of 2008 and higher fuel prices of $19 million in 2009. The increase was partially offset by a decrease in retail revenue of $7 million, primarily due to lower volume, and a decrease in wholesale revenue of $4 million, primarily driven by prices.

Utilities gross margin for the three months ended March 31, 2009 increased $18 million, or 35%, compared to the three months ended March 31, 2008 primarily due to a higher retail margin of $31 million due to $30 million of credits to retail customers established during the first quarter of 2008. The increase was partially offset by increased pension expense of $6 million largely due to the decline in market value of IPL’s pension assets during 2008, a decrease in wholesale margin of $4 million due to unfavorable prices and an increase in the amortization of regulatory assets and depreciation of $3 million.

Europe

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

	For the Three Months Ended March 31,
	2009		2008		% Change
	(in millions)
Europe Generation
Revenue	$	204	$	304	-33	%
Gross Margin	$	68	$	115	-41	%
Gross Margin as a % of Segment Revenue		33%		38%

Generation revenue for the three months ended March 31, 2009 decreased $100 million or 33%, compared to the three months ended March 31, 2008 primarily due to the unfavorable impact of foreign currency translation of $62 million across the region, mainly driven by Kilroot in the U.K. and our businesses in Hungary and a decrease in revenue of $60 million in Kazakhstan as a result of the sale of two subsidiaries in May 2008. These decreases were partially offset by higher rates in Hungary, at Kilroot and the remaining businesses in Kazakhstan of $32 million.

Generation gross margin for the three months ended March 31, 2009 decreased $47 million or 41% compared to the three months ended March 31, 2008 primarily due to a decrease of $26 million in Kazakhstan as a result of the sale of two subsidiaries in May 2008, the unfavorable impact of foreign currency translation of $21 million across the region and lower volume across the region of $13 million. These decreases were partially offset by higher rates at Kilroot, in Bohemia and at Tisza II in Hungary of $20 million. Gross margin as a percentage of revenue decreased primarily due to lower margins at Borsod due to higher fuel costs, the sale of two profitable subsidiaries in Kazakhstan in the first quarter of 2008 and the unfavorable impact of foreign currency translation on gross margin at Kilroot.

Asia

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

	For the Three Months Ended March 31,
	2009		2008		% Change
	(in millions)
Asia Generation
Revenue	$	247	$	312	-21%
Gross Margin	$	47	$	48	-2%
Gross Margin as a % of Segment Revenue		19%		15%

45

Generation revenue for the three months ended March 31, 2009 decreased $65 million, or 21%, compared to the three months ended March 31, 2008 primarily due to lower generation volume of $58 million as a result of fuel supply constraints, lower generation rates of $31 million due to a decline in pass through fuel costs and the unfavorable impact of foreign currency translation of $23 million at Lal Pir and Pak Gen in Pakistan. Additionally, revenue decreased at Kelanitissa in Sri Lanka from reduced rates and volume of $8 million and $9 million, respectively. These decreases were partially offset by our new businesses, Masinloc in the Philippines, acquired in April 2008 and Amman East in Jordan which began production in 2008 of $46 million and $26 million, respectively.

Generation gross margin for the three months ended March 31, 2009 remained relatively flat at $47 million, compared to $48 million for the three months ended March 31, 2008. A decrease in gross margin from a planned outage at Ras Laffan in Qatar was offset by our new businesses. Gross margin as a percentage of revenue increased primarily due to the reduction of revenue, discussed above, that was primarily a result of lower generation rate due to lower pass through fuel costs.

Corporate and Other

Corporate and other include general and administrative expenses related to corporate staff functions and/or initiatives, executive management, finance, legal, human resources, information systems, and certain development costs which are not allocable to our business segments. In addition, this category includes the net operating results from our generation and utilities businesses in Africa, utilities businesses in Europe and AES Wind and other renewables projects and costs associated with our development group which are immaterial for the purposes of separate segment disclosure and the effects of eliminating transactions such as self-insurance charges, between the operating segments and corporate. For the three months ended March 31, 2009 and 2008, Corporate and other was approximately 1% of total revenue.

Corporate and other decreased $5 million, or 9%, to $50 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008. The decrease was primarily due to an $8 million decrease in corporate expenses driven by remediation costs incurred in 2008 and a current year decrease in development efforts, travel and staffing, partially offset by an increase in SAP implementation costs. The decrease in corporate expenses was partially offset by favorable operating results from our generation and utilities businesses in Africa and our utilities businesses in Europe.

Interest expense

Interest expense decreased $44 million, or 10%, to $391 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008 primarily due to the favorable impact of foreign currency translation and lower interest rates in Brazil, the repayment of debt at the Parent Company, and lower interest expense related to derivatives at Southland, one of our North America Generation businesses. These decreases were partially offset by line of credit extension fees written off at one of our Brazilian subsidiaries, and additional interest expense at our Masinloc plant in the Philippines which was acquired in April 2008.

Interest income

Interest income decreased $18 million, or 16%, to $98 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008 primarily due to the unfavorable impact of foreign currency translation in Brazil, and lower interest rates at the Parent Company.

Other expense

Other expense decreased $3 million, or 12%, to $22 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008. The 2009 expense is primarily losses on disposal of assets at Eletropaulo and Andres.

46

Other income

Other income increased $177 million to $222 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008. Other income in 2009 included a favorable court decision on a legal dispute in which Eletropaulo had requested reimbursement for excess non-income taxes paid from 1989 to 1992. Eletropaulo received reimbursement in the form of a tax credit to be applied against future tax liabilities resulting in a $129 million gain. The net impact to the Company after noncontrolling interests was $21 million. In addition, the Company recognized income of $80 million in the first quarter of 2009 from a performance incentive bonus for management services provided to Ekibastuz and Maikuben in 2008. See further discussion of this transaction in Note 13 — Acquisitions and Dispositions.

Gain on sale of investments

Gain on sale of investments increased $9 million to $13 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008. This gain primarily consisted of a reversal of a contingent liability related to the sale of two wholly-owned subsidiaries in Kazakhstan in May 2008. At the time of sale, we provided indemnification to the buyer for a withholding tax liability which expired in January 2009, and accordingly, the liability was reversed.

Impairment expense

There was no impairment expense for the three months ended March 31, 2009. Impairment expense for the three months ended March 31, 2008 was $47 million, consisting primarily of an impairment charge of $19 million related to South African peakers project development costs that were written off due to withdrawal from the project, as well as an impairment charge of $14 million associated with a settlement agreement to shut down the Hefei plant in China. Additionally, there was $14 million of impairment at Uruguaiana, a thermoelectric plant located in Brazil, as a result of an analysis of Uruguaiana’s long-lived assets, which was triggered by the combination of gas curtailments and increases in the spot market price of energy in 2007.

Foreign currency transaction (losses) gains on net monetary position

Foreign currency transaction (losses) gains were as follows:

	Three months ended March 31,
	2009			2008
	(in millions)
The AES Corporation	$	(26	)	$	26
Chile		26			14
Kazakhstan		(15	)		-
Argentina		(9	)		(2	)
Brazil		(7	)		(10	)
Philippines		(7	)		-
Colombia		6			(7	)
Other		(7	)		1
Total (1)	$	(39	)	$	22

⁽¹⁾ Includes $11 million losses and $5 million gains on foreign currency derivative contracts for the three months ended March 31, 2009 and 2008, respectively.

The Company recognized foreign currency transaction losses of $39 million for the three months ended March 31, 2009. These consisted primarily of losses at The AES Corporation, Kazakhstan, Argentina, the Philippines and Brazil partially offset by gains in Chile and Colombia.

¡ Losses of $26 million at The AES Corporation were primarily due to the devaluation of the Euro during the quarter, resulting in losses associated with notes receivable.

47

¡ Gains of $26 million in Chile were primarily due to an 8% appreciation of the Chilean Peso in the first quarter of 2009, resulting in gains at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos, primarily cash, accounts receivable and value added tax (“VAT”) receivables. These gains were partially offset by a $6 million loss on foreign currency derivatives.

¡ Losses of $15 million in Kazakhstan were primarily due to net foreign currency transaction losses of $2 million related to energy sales denominated and fixed in the U.S. Dollar and $13 million of foreign currency transaction losses on external and intercompany debt denominated in other than functional currencies.

¡ Losses of $9 million in Argentina were driven by an 8% devaluation of the Argentine Peso in the first quarter of 2009, mainly resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar – denominated debt partially offset by a $3 million gain on derivative instruments; and losses at Termoandes (a U.S. Dollar functional currency subsidiary) associated with trade and tax receivables denominated in Argentinean Peso.

¡ Losses of $7 million in Brazil were primarily due to the realization of deferred exchange variances on past energy purchases made by Eletropaulo denominated in U.S. Dollar, resulting in foreign currency transaction losses.

¡ Losses of $7 million in the Philippines were primarily due to remeasurement losses at Masinloc (a Philippine Peso functional currency subsidiary) on U.S. Dollar – denominated debt and other monetary assets and liabilities resulting from depreciation of the Philippine Peso.

¡ Gains of $6 million in Colombia were primarily due to a 14% devaluation of the Colombian Peso in the first quarter of 2009, resulting in gains at Chivor (a U.S. Dollar functional currency subsidiary) associated with its Colombian Peso – denominated debt.

The Company recognized foreign currency transaction gains of $22 million for the three months ended March 31, 2008. These consisted primarily of gains at The AES Corporation and Chile partially offset by losses at Brazil and Colombia.

¡ Gains of $26 million at The AES Corporation were primarily the result of favorable exchange rates for cash accounts and notes denominated in Euros.

¡ Gains of $14 million in Chile were primarily due to a 14% appreciation of the Chilean Peso in the first quarter 2008, resulting in gains at Gener (a U.S. Dollar functional currency subsidiary) associated with its net working capital denominated in Chilean Pesos, mainly cash, accounts receivables and VAT receivables.

¡ Losses of $10 million in Brazil were primarily due to energy purchases made by Eletropaulo that were denominated in U.S. Dollar, resulting in foreign currency transaction losses of $12 million.

¡ Losses of $7 million in Colombia were primarily due to 11% appreciation of the Colombia Peso in the first quarter of 2008, resulting in losses of $4 million at Chivor (a U.S. Dollar functional currency subsidiary) associated with its Colombian Peso – denominated debt.

Other non-operating expense

Other non-operating expense was $10 million for the three months ended March 31, 2009, consisting primarily of an other-than-temporary impairment of a cost method investment. During the first quarter of 2009, the market value of the investee’s shares continued to decline due to the downward trends in the capital markets and management concluded that the decline was other-than-temporary. There was no other non-operating expense for the three months ended March 31, 2008.

48

Income taxes

Income tax expense on continuing operations decreased $64 million to $175 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008. The Company’s effective tax rates were 26% and 38% for the three months ended March 31, 2009 and 2008, respectively.

The net decrease in the effective tax rate for the three months ended March 31, 2009 compared to the same period in 2008 was, in part, due to an income tax benefit generated by a release of a FIN 48 liability for an uncertain tax position at one of our UK subsidiaries and a non-taxable performance incentive bonus for management services provided to Ekibastuz and Maikuben in 2008 and recognized in the first quarter of 2009. See further discussion about the Kazakhstan transaction in Note 13 — Acquisitions and Dispositions.

Net equity in earnings of affiliates

Net equity in earnings of affiliates decreased $15 million, or 68%, to $7 million for the three months ended March 31, 2009. The decrease was primarily due to the exclusion of earnings at Cartagena in 2009 because the equity method of accounting was suspended when the investment was reduced to zero in December 2008, decreased earnings at Chigen due to increased prices and lower supplies of coal, a decrease as a result of increased development costs related to AES Solar which was formed in March 2008, and decreased earnings at OPGC, in India, due to lower tariff revenue. These decreases were partially offset by a reduction in net losses of our affiliates in Turkey.

Discontinued operations

There were no discontinued operations in 2009. For the three months ended March 31, 2008, income from operations of discontinued businesses, net of tax, was $2 million and reflected the operations of Jiaozuo, a coal-fired generation facility in China sold in December 2008.

Net income attributable to noncontrolling interests

Net income attributable to noncontrolling interests increased $108 million, or 62%, to $283 million for the three months ended March 31, 2009 compared to the same period in 2008 primarily due to increased earnings at Eletropaulo and Uruguaiana in Brazil, Itabo in the Dominican Republic and Gener in Chile, as well as an increase in noncontrolling interests from approximately 20% to approximately 29% as a result of the sale of shares at Gener in November 2008. These increases were partially offset by the depreciation of the Brazilian Real.

Capital Resources and Liquidity

Overview

As of March 31, 2009, the Company had unrestricted cash and cash equivalents of $1.3 billion and short term investments of $1.1 billion. In addition, we had restricted cash and debt service reserves of $1 billion. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $12.8 billion and $5.2 billion, respectively. Of the total $789 million of our short-term non-recourse debt currently outstanding, $731 million is presented as current because it is due in the next twelve months and $58 million relates to debt currently in default. We expect such maturities will be repaid from cash on hand or cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. Approximately $154 million of our recourse debt matures within the next twelve months which we expect to repay primarily using liquidity of the Parent Company, or cash provided by operating activities or funds raised through our April 2009 senior notes issuance.

We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent achievable, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments

49

required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates and is generally secured by the capital stock, physical assets, contracts and cash flow of the related subsidiary or affiliate. Generally our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency expected to be received for revenue generated from the benefiting project thereby reducing currency risk. In certain cases the currency is matched through the use of derivative instruments. These derivatives can require that the Company post collateral to support the currency match. The majority of our non-recourse debt is funded by international commercial banks with debt capacity supplemented by multilaterals and local regional banks. For more information on our long-term debt, see Note 6 — Long-term Debt to the condensed consolidated financial statements included in Item 1 of this Form 10-Q.

Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. While the Company believes that this represents an economic hedge, the Company may be required to mark-to-market all or a portion of these interest rate swaps and other derivatives. Presently, the Parent Company’s only exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility. On a consolidated basis, of the Company’s $18 billion of total debt outstanding as of March 31, 2009, approximately $3.2 billion bore interest at variable rates of interest that were not subject to an interest rate swap which fixed the interest rate.

In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany 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, proceeds from the sales of assets and/or the proceeds from our debt issuances, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity with our subsidiaries or lenders. In such circumstances, if a subsidiary defaults on its payment or supply obligation, the Parent Company will be responsible for the subsidiary’s obligations up to the amount provided for in the relevant guarantee or other credit support. At March 31, 2009, the Parent Company 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, of approximately $408 million in aggregate (excluding investment commitments and those collateralized by letters of credit and other obligations discussed below).

As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. 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 March 31, 2009, the Parent Company had $203 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations. These letters of credit were provided under our revolver and senior unsecured credit facility. The Company pays letter of credit fees ranging from 1.63% to 13.34% per annum on the outstanding amounts.

We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. However, depending on local and global

50

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

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

AES Solar, one of our equity investments, was formed in March 2008 as a joint venture with Riverstone. Under the terms of the AES Solar joint venture agreement, the Company and Riverstone may each provide up to $500 million of capital through 2013. The joint venture has commitments to purchase solar panels for use in their business and, while the Company is not required to fund AES Solar’s obligations, it is possible that if we decide not to fund the joint venture in the future it could impact AES Solar’s development plans or operations.

Cash Flows

At March 31, 2009, cash and cash equivalents increased by $364 million from December 31, 2008 to $1.3 billion. The change in cash was due to $376 million of cash provided by operating activities, $77 million of cash provided by investing activities, $87 million of cash used for financing activities and the unfavorable effect of foreign currency exchange rates on cash of $2 million.

Operating Activities

Net cash provided by operating activities decreased $94 million, or 20%, to $376 million for the three months ended March 31, 2009 from $470 million for the same period in 2008. This decrease was partially due to a decrease of approximately $221 million at our Latin America Utilities businesses primarily due to lower cash earnings and payments on interest rate swap agreements made by two of our subsidiaries in Brazil; $89 million at our Latin America Generation businesses primarily due to an increase in cash used by one of our Brazilian subsidiaries to pay income taxes during the first three months of 2009 compared to the same period in the prior year, where tax credits were the primary payment method; and additional working capital requirements at our renewables businesses. These decreases were partially offset by an increase in net cash provided by operating activities at our Asia Generation businesses of approximately $193 million primarily due to improved working capital. In addition, our Europe Generation businesses experienced an increase in net cash provided by operating activities of approximately $39 million due to improved performance, partially offset by an increase in net working capital requirements.

Significant non-cash income recognized for the three months ended March 31, 2009 included an $80 million performance incentive bonus recognized for management services performed in Kazakhstan, for which a cash payment was received in April 2009, and the settlement of contingencies at Eletropaulo for $129 million of non-income tax credits as a result of the favorable court decision. These are described further in Other Income within Consolidated Operating Results.

51

Investing Activities

Net cash provided by investing activities increased $1,187 million to net cash provided of $77 million for the three months ended March 31, 2009 from net cash used of $1,110 million for the three months ended March 31, 2008. This increase was primarily attributable to the following:

Capital expenditures decreased $59 million, or 9% to $574 million for the three months ended March 31, 2009 from $633 million for the three months ended March 31, 2008. This was mainly due to reduction in capital expenditures of $182 million for wind development projects in the U.S.-based businesses and $45 million at Maritza in Bulgaria. These decreases were offset by net increased capital expenditures of $119 million for plant construction at Gener and $52 million for Europe-based wind development projects at our European businesses.

Acquisitions, net of cash acquired were $186 million for the three months ended March 31, 2008, due to the purchase of the Mountain View wind project and a deposit for the Nejapa acquisition. There were no acquisitions in the three months ended March 31, 2009.

The sale of short-term investments, net of purchases, increased $405 million to $313 million for the three months ended March 31, 2009 from $92 million net purchases of short-term investments for the three months ended March 31, 2008. The increase was primarily due to a decrease in net purchases of $213 million and $123 million at Eletropaulo and Tiete, respectively, as a result of a change in investment strategy to acquire public debt and government securities. This was offset by a $21 million decrease in net sales at Gener.

Debt service reserves and other assets decreased $73 million for the three months ended March 31, 2009 primarily due to decreases of $37 million at Kavarna, $30 million at K2 Wind Energy Ltd, and $9 million at Merida. These decreases were offset by an increase of $4 million at Kelanitissa and $4 million at our businesses in Puerto Rico.

Restricted cash balances decreased $293 million for the three months ended March 31, 2009, primarily due to decreases of $224 million at Gener and $72 million at Chigen.

Affiliate advances and equity investments decreased $67 million for the three months ended March 31, 2009 to $30 million compared to $97 million for the three months ended March 31, 2008 due to lower investment activity in the current year. For the three months ended March 31, 2009, the $30 million primarily consisted of an additional investment in AES Solar. For the three months ended March 31, 2008, the $97 million primarily consisted of our initial investment in AES Solar, and additional investments made to the Turkish Hydros and the Huanghua joint venture.

Loan advances were $172 million for the three months ended March 31, 2008, due to the Company’s advance of a convertible loan to a Brazilian wind development business. There were no loan advances made in the three months ended March 31, 2009.

Financing Activities

Net cash used in financing activities increased $416 million to $87 million for the three months ended March 31, 2009 compared to net cash provided of $329 million for the three months ended March 31, 2008. As discussed below, this change was primarily attributable to a decrease in debt, net of borrowings, of $417 million.

Net repayments under revolving credit facilities were $153 million for the three months ended March 31, 2009, compared to net borrowings of $178 million for the three months ended March 31, 2008. The increase in net repayments was primarily due to $107 million at Lal Pir and $106 million at Pak Gen in Pakistan, $60 million at the Parent Company, $41 million at IPL and $8 million at Caess.

Issuances of non-recourse debt for the three months ended March 31, 2009 were $244 million compared to $259 million for the three months ended March 31, 2008. This decrease of $15 million was primarily due to a

52

decrease at Buffalo Gap 3 of $136 million and at Jordan of $22 million. These decreases were offset by increases of $106 million at Sonel and $33 million at Gener for construction projects.

Repayments of non-recourse debt for the three months ended March 31, 2009 were $169 million compared to $98 million for the three months ended March 31, 2008. This increase of $71 million was predominately due to an increase in repayments at Chigen of $72 million from proceeds received from the Jiaozuo sale.

Payments made for deferred financing costs for the three months ended March 31, 2009 were $22 million compared to $5 million for the three months ended March 31, 2008. This increase of $17 million was primarily due to increases of $10 million at the Parent Company and $6 million at a Brazilian subsidiary.

Contributions from noncontrolling interests increased $69 million to $73 million for the three months ended March 31, 2009 from $4 million for the three months ended March 31, 2008. The increase was primarily a result of additional contributions of $71 million at Gener.

Financed capital expenditures increased $40 million to $49 million for the three months ended March 31, 2009 from $9 million for the three months ended March 31, 2008, predominately due to an increase of $39 million for financing of certain construction at Kavarna in Bulgaria.

Parent Company Liquidity

The following discussion of “Parent Company Liquidity” has been included because we believe it is a useful measure of the liquidity available to the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company Liquidity as outlined below is not a measure under U.S. GAAP and should not be construed as an alternative to cash and cash equivalents, which are determined in accordance with U.S. GAAP, as a measure of liquidity. Cash and cash equivalents are disclosed in the condensed consolidated statement of cash flows. Parent Company Liquidity may differ from that of similarly titled measures used by other companies. Our principal sources of liquidity at the Parent Company level are:

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

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

• proceeds from asset sales.

Our cash requirements at the Parent Company level are primarily to fund:

• interest and preferred dividend payments;

• principal repayments of debt;

• acquisitions;

• construction commitments;

• other equity commitments;

• taxes; and

• Parent Company overhead and development costs.

53

The Company defines Parent Company Liquidity as cash available to the Parent Company and qualified holding companies plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents” at March 31, 2009 and December 31, 2008 as follows:

Parent Company Liquidity	March 31, 2009		December 31, 2008
	(in millions)
Consolidated cash and cash equivalents	$	1,267	$	903
Less: Cash and cash equivalents at subsidiaries		1,099		656
Cash and cash equivalents at Parent and qualified holding companies		168		247
Borrowing available under senior secured credit facility		757		720
Borrowing available under senior unsecured credit facility		425		423
Total Parent Company Liquidity	$	1,350	$	1,390

The following table summarizes our Parent Company contingent contractual obligations as of March 31, 2009:

Contingent Contractual Obligations	Amount	Number of Agreements	Exposure Range for Each Agreement
	(in millions)		(in millions)
Guarantees	$        408	33	< $1 - $53
Letters of credit under the revolving credit facility	28	3	< $1 - $27
Letters of credit under the senior unsecured credit facility	175	16	< $1 - $129
Total	$        611	52

As of March 31, 2009, the Parent Company had $212 million of commitments to invest in subsidiaries with projects under construction and to purchase related equipment, excluding approximately $150 million of such obligations already included in the letters of credit discussed above. The Parent Company expects to fund these net investment commitments over time according to the following schedule: $133 million in 2009, $25 million in 2010 and $54 million in 2011. The exact payment schedule will be dictated by construction milestones. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.

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, buyer and tax indemnities, equity subscription, spot market power prices, supplier support and liquidated damages under power sales agreements for projects in development, under construction and in operation. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations during 2009 or beyond, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.

While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets, 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 project

54

subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in project loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that our actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our revolving credit facility and senior unsecured credit facility. If, due to new corporate opportunities or otherwise, our capital requirements exceed amounts available from cash on hand or borrowings under our credit facilities, we may need to access the capital markets to raise additional debt or equity financing. Various debt instruments at the Parent Company level 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.

Recourse Debt:

On March 26, 2009, the Parent Company and certain subsidiary guarantors amended the Parent Company’s existing senior secured credit facility pursuant to the terms of Amendment No. 1 to the senior secured credit facility. The senior secured credit facility previously included a $200 million term loan facility maturing on August 10, 2011 and a $750 million revolving credit facility maturing on June 23, 2010.

The principal modification set forth in Amendment No. 1 is a one year extension of the $570 million of revolving credit facility commitments from an original maturity date of June 23, 2010 to July 5, 2011. In addition, certain lenders determined that they would increase their commitments under the revolving credit facility by $35 million from March 26, 2009 through July 5, 2011. Accordingly, Amendment No. 1 also increased the size of the revolving credit facility from $750 million to $785 million for the period between the date of Amendment No. 1 and June 23, 2010. Between June 23, 2010 and July 5, 2011, the revolving credit facility size will be $605 million. No modifications were made to the amount or maturity date of the $200 million term loan facility.

The extended commitments from this amendment were subject to new pricing that included an upfront fee of 1.25% for participating in the extensions and an increase in undrawn commitment fees from 50 to 100 basis points. The annual interest rate on the drawn loans was also increased by 200 basis points to LIBOR plus 3.50%. Pricing and all other terms remained unchanged for the revolving credit facility commitments which have not been extended.

On April 2, 2009, the Parent Company issued $535 million aggregate principal amount of 9.75% senior secured notes due 2016. The notes were priced at a discount to yield 11%. Subsequently, the Parent Company announced its intention to allocate a substantial portion of the proceeds to voluntarily reduce its commitment under the $600 million senior unsecured credit facility by $425 million. The remaining $175 million of the senior unsecured credit facility consists of letters of credit, the majority of which continues to support several projects currently under construction.

55

Future principal payments on recourse debt as of March 31, 2009 are set forth in the table below:

March 31,	Annual Maturities
	(in millions)
2009		154
2010		214
2011		451
2012		-
2013		690
Thereafter		3,638
Total recourse debt	$	5,147

Non-Recourse Debt:

While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can potentially 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 Company 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 may 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.

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total debt classified as current in the accompanying condensed consolidated balance sheet related to such defaults was $58 million at March 31, 2009, all of which is non-recourse debt.

None of the subsidiaries that are currently in default meet the applicable definition of materiality in The AES Corporation’s corporate debt agreements in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary,” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities.

Critical Accounting Policies and 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. The Company’s significant accounting policies are described in Note 1 — Financial Statement Presentation to the consolidated financial statements included in the Company’s 2008 Annual Report on Form 10-K. The Company’s critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s 2008 Annual Report on Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the

56

estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods.

The Company has reviewed and determined that those policies remain the Company’s critical accounting policies as of and for the three months ended March 31, 2009. The only significant change to our critical accounting policies and estimates is the adoption of FAS No. 157 for nonfinancial assets and liabilities as of January 1, 2009. See further discussion of the Company’s policy in Item 1. Financial Statements, Notes to Condensed Consolidated Financial Statements, Note 1—Financial Statement Presentation in this Form 10-Q.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks

We are exposed to market risks associated with interest rates, foreign exchange rates and commodity prices. We often utilize financial instruments and other contracts to hedge against such fluctuations. We also utilize financial derivatives for the purpose of hedging exposures to market risk. We do not enter into derivative transactions for trading purposes. Set forth below are certain factors considered by the Company in assessing market risk, including statements about the impact of changes in interest rates, commodity prices and currencies. These statements are based upon a number of assumptions and actual impacts to the Company may not follow the assumptions made by the Company. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 3.

Interest Rate Risks

We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable-rate debt, fixed-rate debt and trust preferred securities, as well as interest rate swap, cap and floor and option agreements. Decisions on the fixed-floating debt ratio are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing.

As of March 31, 2009, the portfolio’s interest expense exposure (adjusted to reflect noncontrolling interests) to a 100 basis point increase in U.S. Dollar and Brazilian Real interest rates is approximately $13 million. These numbers assume a one-time, 100 basis point increase in interest rates and calculating its impact on interest expense for U.S. Dollar and Brazilian Real-denominated debt for the remainder of 2009, which together account for more than 90% of the portfolio’s floating-rate debt which are primarily non-recourse financing. The numbers do not take into account the historical correlation between U.S. Dollar and Brazilian Real interest rates and do not include other currencies which account for less than 10% of the portfolio floating-rate debt.

Foreign Exchange Rate Risk

In the normal course of business, we are exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in U.S. Dollar or currencies other than their own functional currencies. Primarily, we are exposed to changes in the exchange rate between the U.S. Dollar and the following currencies: Brazilian Real, Argentine Peso, Kazakhstani Tenge, British Pound, Euro, Colombian Peso, Chilean Peso and Philippine Peso. 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.

57

Given a 10% U.S. Dollar appreciation, AES pre-tax earnings for the balance of 2009 would be reduced by approximately $51 million on a correlated basis. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to pre-tax earnings for the balance of 2009 coming from subsidiaries where the local currency is either not the U.S. Dollar or it is not exhibiting the characteristics of a peg or managed float relative to the U.S. Dollar and holding all other variables constant. The numbers presented above are net of any transactional gains/losses and the correlation effect is based on historical foreign exchange rate movement over a period equal in length to the period over which the simulated move occurs.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the price of electricity, fuels and environmental credits. Although we primarily consist of businesses with long-term contracts or retail sales concessions, a portion of our current and expected future revenues are derived from businesses without significant long-term revenue or supply contracts. These businesses subject our results of operations to the volatility of prices for electricity, fuels and environmental credits in competitive markets. 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. Some businesses hedge certain aspects of their commodity risks using financial hedge instruments. We also enter into short-term contracts for the supply of electricity and fuel in other competitive markets in which we operate.

When hedging the output of our generation assets, we have power purchase agreements or other hedging instruments that lock in the spread in dollars per MWh between the cost of fuel to generate a unit of electricity and the price at which the electricity can be sold. The portion of our sales and fuel purchases that are not subject to such agreements will be exposed to commodity price risk. For our U.S.-based assets including Eastern Energy, Deepwater, and wholesale sales for Indianapolis Power & Light, a 10% decline in the price of electricity as of March 31, 2009 would produce an estimated decrease in gross margin of $12 million for the balance of 2009. We limited our analysis to the U.S. markets as they have quoted forward electricity curves. We shifted the forward electricity curves for Western New York, Houston, Texas, and the Cinergy hub down by 10%. We applied the change in electricity prices to our un-hedged sales volumes. An increase of 10% in petroleum coke prices at Deepwater would result in a decline in gross margin of $1 million. Our other U.S.-based assets’ fuel prices are either fully hedged or regulated and thus have no major impact on gross margin to be included in the sensitivity analysis.

Value at Risk

We have performed a company wide value at risk analysis (“VaR”) of all of our material financial assets, liabilities and derivative instruments. 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. This is calculated based on volatilities and correlations of the different risk exposures of the portfolio. The quantification of market risk using VaR provides a consistent measure of risk across diverse markets and instruments. VaR is not necessarily indicative of actual results that may occur. Additionally, VaR represents changes in fair value of financial instruments and not the economic exposure to AES and its affiliates. Because of the inherent limitations of VaR, including those specific to Analytic VaR, in particular the assumption that values or returns are normally distributed, we rely on VaR as only one component in our risk assessment process. In addition to using VaR measures, we perform sensitivity 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. For a further discussion of the Company’s VaR methodology and its limitations, see Quantitative and Qualitative Disclosures about Market Risk — Risk Management in Part II, Item 7A of the 2008 Form 10-K

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

58

correlation within and across these variables. 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 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 a Monte Carlo VaR within the commodity transaction management system, and is reported for financially settled derivative products at the AES Eastern Energy, L.P. business in New York State as this is the only business with commodity transactions that are deemed derivatives. These commodity transactions are marked to market on a daily basis and collateral is then posted or recalled for any changes in exposures. However, not every transaction requires AES Eastern Energy, L.P. to post collateral, as several counterparties have caps defined in their transaction agreements. For those counterparties that do require AES Eastern Energy, L.P. to post collateral, two facilities that are non-recourse to The AES Corporation in the amounts of $75 million and $350 million are used to issue letters of credit. As of March 31, 2009, $20 million and $71 million have been utilized under these facilities.

The VaR as of March 31, 2009 for foreign exchange rate-sensitive instruments was $78 million compared with $125 million as of December 31, 2008. These amounts include foreign currency denominated debt and hedge instruments. The decrease in VaR relative to the fourth quarter is primarily attributable to the decrease in volatility of the Brazilian Real, Euro and British Pound.

The VaR as of March 31, 2009 for interest rate-sensitive instruments was $176 million compared with $188 million as of December 31, 2008. These amounts include the financial instruments that serve as hedges and the underlying hedged items. The decrease in VaR relative to the fourth quarter is attributable to the decrease in volatility in interest rates.

The VaR as of March 31, 2009 for commodity price-sensitive instruments was $4 million compared with $7 million as of December 31, 2008. 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. The decrease in VaR relative to the fourth quarter 2008 is attributable to a lower volume of hedged MWhs and a decrease in Western New York power prices of approximately 28% during the period.

ITEM 4.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective as of March 31, 2009 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls Over Financial Reporting

There were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

59

PART II: OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

The Company is involved in certain claims, suits and legal proceedings in the normal course of business, some of which are described Note 7 — Contingencies and Commitments in Item 1 of this Form 10-Q. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of March 31, 2009. See Note 7 — Contingencies and Commitments in Item 1 of this Form 10-Q for additional information regarding these claims and proceedings.

ITEM 1A.    RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2008 Form 10-K.

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

None.

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

The Company held its Annual Meeting of Stockholders on April 23, 2009. The slate of directors set forth in the Company’s proxy statement filed on March 2, 2009 were elected by the stockholders as follows:

Nominee	Vote Type	Vote
SAMUEL W. BODMAN, III	FOR	571,296,020
	AGAINST	4,123,527
	ABSTAIN	0
PAUL T. HANRAHAN	FOR	503,640,528
	AGAINST	71,779,018
	ABSTAIN	0
KRISTINA M. JOHNSON 1	FOR	481,373,611
	AGAINST	94,045,936
	ABSTAIN	0
TARUN KHANNA	FOR	571,482,283
	AGAINST	3,937,264
	ABSTAIN	0

¹ On March 12, 2009, Dr. Kristina M. Johnson was nominated for the office of Under Secretary of the Department of Energy of the United States. Dr. Johnson has served on the Board of Directors of The AES Corporation since April, 2004. As a result of her nomination, on April 19, 2009, Dr. Johnson advised AES that she would not stand for re-election at the Annual Meeting of Stockholders. Therefore, while Dr. Johnson was listed as a Director nominee in the Company’s 2009 Proxy Statement, she will not serve on the AES Board during the 2009-2010 Board year.

60

JOHN A. KOSKINEN	FOR	483,849,274
	AGAINST	91,570,273
	ABSTAIN	0
PHILIP LADER	FOR	500,614,281
	AGAINST	74,805,266
	ABSTAIN	0
SANDRA O. MOOSE	FOR	500,470,498
	AGAINST	74,949,048
	ABSTAIN	0
JOHN B. MORSE, JR.	FOR	571,378,182
	AGAINST	4,041,365
	ABSTAIN	0
PHILIP A. ODEEN	FOR	483,860,430
	AGAINST	91,559,117
	ABSTAIN	0
CHARLES O. ROSSOTTI	FOR	499,468,531
	AGAINST	75,951,016
	ABSTAIN	0
SVEN SANDSTROM	FOR	503,782,397
	AGAINST	71,637,150
	ABSTAIN	0

Ratification of Ernst & Young LLP as the independent auditors of the Company for the year 2009: 574,285,978 votes for, 720,974 votes against, 412,594 votes abstained and no non-votes.

ITEM 5.    OTHER INFORMATION

None.

ITEM 6.    EXHIBITS

4	There are numerous instruments defining the rights of holders of long-term indebtedness of the Registrant and its consolidated subsidiaries, none of which exceeds ten percent of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any such agreements to the Commission upon request. Since these documents are not required filings under Item 601 of Regulation S-K, the Company has elected to file the following document as Exhibit 4(a).
4 (a)	Fourteenth Supplemental Indenture, dated April 2, 2009 is incorporated by reference to Exhibit 99.1 of the Company’s Form 8-K filed on April 2, 2009.
10.1	Amendment No. 1 to the Fourth Amended and Restated Credit and Reimbursement Agreement dated March 26, 2009 among the Company, the subsidiary guarantors, Citicorp USA Inc., as Administrative Agent, Citibank, N.A., as Collateral Agent and various lenders named therein is incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on March 26, 2009.
31.1	Certification of principal executive officer required by Rule 13a-14(a)/15d-14(a) of the Exchange Act.
31.2	Certification of principal financial officer required by Rule 13a-14(a)/15d-14(a) of the Exchange Act.
32.1	Certification of principal executive officer required by Rule 13a-14(b) or 15d-14(b) of the Exchange Act.
32.2	Certification of principal financial officer required by Rule 13a-14(b) or 15d-14(b) of the Exchange Act.

61

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	THE AES CORPORATION (Registrant)
Date: May 7, 2009	By:	/s/ VICTORIA D. HARKER
		Name:	Victoria D. Harker
		Title:	Executive Vice President and Chief Financial Officer (Principal Financial Officer)
	By:	/s/ MARY E. WOOD
		Name:	Mary E. Wood
		Title:	Vice President and Controller (Principal Accounting Officer)

62