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 September 30, 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  x    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 the definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x	Accelerated filer  ¨	Non-accelerated filer  ¨	Smaller reporting company  ¨
		(Do not check if a 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, on November 2, 2009, was 667,582,796.

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED September 30, 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 Statements 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	50
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	84
ITEM 4.	CONTROLS AND PROCEDURES	87
PART II: OTHER INFORMATION		88
ITEM 1.	LEGAL PROCEEDINGS	88
ITEM 1A.	RISK FACTORS	88
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	88
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	88
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	88
ITEM 5.	OTHER INFORMATION	88
ITEM 6.	EXHIBITS	88

2

PART I: FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

THE AES CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in millions, except per share data)
Revenues:
Regulated	$	2,092		$	2,089		$	5,542		$	6,043
Non-regulated		1,746			2,230			5,169			6,483
Total revenues		3,838			4,319			10,711			12,526
Cost of Sales:
Regulated		(1,448	)		(1,446	)		(3,993	)		(4,253	)
Non-regulated		(1,382	)		(1,911	)		(3,980	)		(5,240	)
Total cost of sales		(2,830	)		(3,357	)		(7,973	)		(9,493	)
Gross margin		1,008			962			2,738			3,033
General and administrative expenses		(82	)		(90	)		(255	)		(287	)
Interest expense		(421	)		(458	)		(1,195	)		(1,362	)
Interest income		94			156			282			405
Other expense		(15	)		(18	)		(67	)		(128	)
Other income		35			63			279			258
Gain on sale of investments		17			-			132			912
Impairment expense		(6	)		(22	)		(7	)		(94	)
Foreign currency transaction losses on net monetary position		(1	)		(60	)		(13	)		(123	)
Other non-operating expense		(2	)		-			(12	)		-
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EQUITY IN EARNINGS OF AFFILIATES		627			533			1,882			2,614
Income tax expense		(205	)		(168	)		(485	)		(725	)
Net equity in earnings of affiliates		18			(4	)		75			38
INCOME FROM CONTINUING OPERATIONS		440			361			1,472			1,927
(Loss) income from operations of discontinued businesses, net of income tax expense of $—, $—, $— and $—, respectively		-			(2	)		-			1
Loss from disposal of discontinued businesses, net of income tax expense of $—, $—, $— and $—, respectively		-			-			-			(1	)
NET INCOME		440			359			1,472			1,927
Less: Net income attributable to noncontrolling interests		(255	)		(214	)		(766	)		(646	)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	185		$	145		$	706		$	1,281
BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.28		$	0.22		$	1.06		$	1.91
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		-			-			-			-
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.28		$	0.22		$	1.06		$	1.91
DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.28		$	0.22		$	1.06		$	1.87
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		-			-			-			-
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.28		$	0.22		$	1.06		$	1.87
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	185		$	147		$	706		$	1,281
Discontinued operations, net of tax		-			(2	)		-			-
Net income	$	185		$	145		$	706		$	1,281

See Notes to Condensed Consolidated Financial Statements

3

THE AES CORPORATION

Condensed Consolidated Balance Sheets

	September 30, 2009			December 31, 2008
	(in millions except share and per share data)
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,020		$	903
Restricted cash		510			729
Short-term investments		1,357			1,382
Accounts receivable, net of allowance for doubtful accounts of $275 and $254, respectively		2,387			2,233
Inventory		578			564
Receivable from affiliates		28			31
Deferred income taxes—current		158			180
Prepaid expenses		274			177
Other current assets		1,416			1,117
Total current assets		8,728			7,316
NONCURRENT ASSETS
Property, Plant and Equipment:
Land		1,092			854
Electric generation, distribution assets, and other		27,467			24,654
Accumulated depreciation		(8,799	)		(7,515	)
Construction in progress		4,466			3,410
Property, plant and equipment, net		24,226			21,403
Other assets:
Deferred financing costs, net of accumulated amortization of $292 and $272, respectively		391			366
Investments in and advances to affiliates		1,109			901
Debt service reserves and other deposits		655			636
Goodwill		1,423			1,421
Other intangible assets, net of accumulated amortization of $202 and $185, respectively		487			500
Deferred income taxes—noncurrent		674			567
Other		1,568			1,696
Total other assets		6,307			6,087
TOTAL ASSETS	$	39,261		$	34,806
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	1,223		$	1,042
Accrued interest		358			252
Accrued and other liabilities		3,086			2,660
Non-recourse debt—current		1,357			1,074
Recourse debt—current		214			154
Total current liabilities		6,238			5,182
LONG-TERM LIABILITIES
Non-recourse debt—noncurrent		12,791			11,869
Recourse debt—noncurrent		5,298			4,994
Deferred income taxes—noncurrent		1,316			1,132
Pension and other post-retirement liabilities		1,158			1,017
Other long-term liabilities		3,835			3,525
Total long-term liabilities		24,398			22,537
Contingencies and Commitments (see Note 8)
Cumulative preferred stock of subsidiary		60			60
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 677,017,626 issued and 667,483,036 outstanding at September 30, 2009; 673,478,012 issued and 662,786,745 outstanding at December 31, 2008)		7			7
Additional paid-in capital		6,859			6,832
Retained earnings (accumulated deficit)		698			(8	)
Accumulated other comprehensive loss		(2,855	)		(3,018	)
Treasury stock, at cost (9,534,590 and 10,691,267 shares at September 30, 2009 and December 31, 2008, respectively)		(126	)		(144	)
Total The AES Corporation stockholders’ equity		4,583			3,669
NONCONTROLLING INTERESTS		3,982			3,358
Total equity		8,565			7,027
TOTAL LIABILITIES AND EQUITY	$	39,261		$	34,806

See Notes to Condensed Consolidated Financial Statements

4

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended September 30,
	2009			2008
	(in millions)
OPERATING ACTIVITIES:
Net income	$	1,472		$	1,927
Adjustments to net income:
Depreciation and amortization		767			760
Gain from sale of investments and impairment expense		(115	)		(832	)
Provision for deferred taxes		(24	)		296
Settlement of non-cash contingencies		(14	)		44
(Gain) loss on the extinguishment of debt		(3	)		56
Other		33			(76	)
Changes in operating assets and liabilities:
Increase in accounts receivable		(82	)		(363	)
Increase in inventory		(10	)		(101	)
Decrease (increase) in prepaid expenses and other current assets		114			(35	)
Increase in other assets		(133	)		(246	)
(Decrease) increase in accounts payable and accrued liabilities		(159	)		156
Increase in income tax receivables and payables, net		96			88
Decrease in other long-term liabilities		(43	)		(87	)
Net cash provided by operating activities		1,899			1,587
INVESTING ACTIVITIES:
Capital expenditures		(1,765	)		(1,963	)
Acquisitions—net of cash acquired		-			(1,135	)
Proceeds from the sales of businesses		2			1,093
Proceeds from the sales of assets		16			102
Sale of short-term investments		3,277			4,121
Purchase of short-term investments		(2,774	)		(4,262	)
Decrease (increase) in restricted cash		272			(57	)
Decrease (increase) in debt service reserves and other assets		80			(38	)
Affiliate advances and equity investments		(137	)		(205	)
Loan advances		-			(173	)
Other investing		(15	)		79
Net cash used in investing activities		(1,044	)		(2,438	)
FINANCING ACTIVITIES:
(Repayments) borrowings under the revolving credit facilities, net		(96	)		382
Issuance of recourse debt		503			625
Issuance of non-recourse debt		1,189			1,908
Repayments of recourse debt		(154	)		(1,037	)
Repayments of non-recourse debt		(622	)		(1,037	)
Payments for deferred financing costs		(72	)		(62	)
Distributions to noncontrolling interests		(561	)		(450	)
Contributions from noncontrolling interests		75			407
Financed capital expenditures		(27	)		(52	)
Purchase of treasury stock		-			(143	)
Other financing		8			21
Net cash provided by financing activities		243			562
Effect of exchange rate changes on cash		19			(50	)
Total increase (decrease) in cash and cash equivalents		1,117			(339	)
Cash and cash equivalents, beginning		903			2,043
Cash and cash equivalents, ending	$	2,020		$	1,704
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	971		$	1,141
Cash payments for income taxes, net of refunds	$	389		$	390
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Assets acquired in noncash asset exchange	$	111		$	18
Assets acquired in acquisition of subsidiary	$	-		$	946
Non-recourse debt assumed in acquisition of subsidiary	$	-		$	12
Liabilities assumed in acquisition of subsidiary	$	-		$	7
Assets disposed of in noncash asset exchange	$	-		$	4

See Notes to Condensed Consolidated Financial Statements

5

THE AES CORPORATION

Condensed Consolidated Statements 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
	(in millions)
Balance at January 1, 2009	$	7	$	(144	)	$	6,832	$	(8	)	$	(3,018	)	$	3,358
Comprehensive income
Net income		-		-			-		706			-			766			1,472
Change in fair value of available-for-sale securities, net of income tax		-		-			-		-			6			-			6
Foreign currency translation adjustment, net of income tax		-		-			-		-			117			437			554
Change in derivative fair value (including a reclassification to earnings, net of income tax)		-		-			-		-			38			24			62
Change in unfunded pension obligation, net of income tax		-		-			-		-			2			-			2
Other comprehensive income																		624
Total comprehensive income																	$	2,096
Capital contributions from noncontrolling interests		-		-			-		-			-			79
Dividends declared to noncontrolling interests		-		-			-		-			-			(673	)
Disposition of businesses		-		-			-		-			-			(7	)
Preferred dividends of subsidiary		-		-			-		-			-			(2	)
Issuance of common stock under benefit plans and exercise of stock options		-		18			11		-			-			-
Stock compensation		-		-			16		-			-			-
Balance at September 30, 2009	$	7	$	(126	)	$	6,859	$	698		$	(2,855	)	$	3,982

	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
	(in millions)
Balance at January 1, 2008	$	7	$	-		$	6,776	$	(1,241	)	$	(2,378	)	$	3,181
Comprehensive income
Net income		-		-			-		1,281			-			646			1,927
Income from operations of discontinued businesses		-		-			-		-			-			(1	)
Change in fair value of available-for-sale securities, net of income tax		-		-			-		-			(1	)		-			(1	)
Foreign currency translation adjustment, net of income tax		-		-			-		-			(166	)		(184	)		(350	)
Change in derivative fair value (including a reclassification to earnings, net of income tax)		-		-			-		-			47			(1	)		46
Change in unfunded pension obligation, net of income tax		-		-			-		-			(2	)		-			(2	)
Other comprehensive loss																		(307	)
Total comprehensive income																	$	1,620
Capital contributions from noncontrolling interests		-		-			-		-			-			432
Dividends declared to noncontrolling interests		-		-			-		-			-			(428	)
Acquisition of treasury stock		-		(144	)		-		-			-			-
Issuance of common stock under benefit plans and exercise of stock options		-		-			23		-			-			-
Stock compensation		-		-			27		-			-			-
Balance at September 30, 2008	$	7	$	(144	)	$	6,826	$	40		$	(2,500	)	$	3,645

See Notes to Condensed Consolidated Financial Statements

6

THE AES CORPORATION

Notes to Condensed Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 2009 and 2008

1. FINANCIAL STATEMENT PRESENTATION

The prior period condensed consolidated financial statements in this Quarterly Report on Form 10-Q (“Form 10-Q”) have been reclassified to reflect the financial statement presentation requirements of new accounting guidance related to noncontrolling interests, which became effective for the Company on January 1, 2009, the new reportable segment structure discussed in Note 11 — Segments and businesses held for sale and discontinued operations as discussed in Note 13 — Discontinued Operations. In addition, certain immaterial prior period amounts have been reclassified within the condensed consolidated financial statements to conform to current period presentation.

On September 14, 2009, The AES Corporation filed a Current Report on Form 8-K (“September 2009 Form 8-K”) to recast previously filed financial statements included in the Company’s Form 10-K for the period ended December 31, 2008 (“2008 Form 10-K”) to reflect the effect of changes to the Company’s reportable segments and the adoption of the presentation and disclosure provisions of new accounting guidance for noncontrolling interests, which required retrospective presentation and became effective for the Company on January 1, 2009. The revisions to the 2008 Form 10-K were limited to the Company’s Business Overview, Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and Notes contained in Items 1, 6, 7 and 8. All other information in the 2008 Form 10-K remains unchanged.

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 of accounting. 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”) as contained in the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (the “Codification” or “ASC”) 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, changes in equity and cash flows. The results of operations for the three and nine months ended September 30, 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 September 2009 Form 8-K.

7

Significant New Accounting Policies

Noncontrolling Interests

Effective January 1, 2009, we adopted new accounting guidance which changed the accounting for, and the reporting of, minority interest, now referred to as noncontrolling interests, in the Company’s condensed consolidated financial statements. The adoption of this guidance 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 and statements of changes in equity. Additionally, net income and comprehensive income attributable to noncontrolling interests are reflected separately from consolidated net income and comprehensive income in the accompanying condensed consolidated statements of operations and statements of changes in equity. As required by the authoritative guidance, prior period financial statements have been reclassified to conform to the current year presentation.

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

The new authoritative guidance for noncontrolling interests revised the provisions of previously issued accounting standards regarding consolidation. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests’ basis has been reduced to zero. Previously, losses that otherwise would have been attributed to the noncontrolling interests were allocated to the controlling interest after the associated noncontrolling interests’ basis was reduced to zero. The Company had no material losses that it did not allocate to noncontrolling interests prior to the adoption of the new noncontrolling interests accounting guidance and the adoption did not have a material impact on the Company’s financial position or results of operations.

The noncontrolling interests accounting guidance requires changes in a parent’s ownership interest in a subsidiary, which result in the parent retaining its controlling financial interest to be accounted for as equity transactions. 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. Previous SEC guidance 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 the revised guidance on noncontrolling interests, this option is no longer available.

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. 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 prior accounting standards, the retained noncontrolling interest in the subsidiary was not adjusted to fair value.

FASB Accounting Standards Codification

Effective for financial statements issued for interim and annual periods ended after September 15, 2009, the FASB established the Codification as the single source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. The Codification supersedes all existing non-SEC accounting and reporting standards. All other non-grandfathered, non-SEC accounting literature is no longer considered authoritative if it is not included in the Codification.

8

As a result of the Codification, the FASB no longer issues new accounting standards in the form of FASB Statements, FASB Staff Positions or Emerging Issues Task Force Abstracts. Instead, new standards or changes to existing accounting guidance are issued as Accounting Standards Updates (“ASUs”), which will serve to update the Codification, provide background information about the guidance and the basis for conclusions on the changes to the Codification. U.S. GAAP content was not changed as a result of the FASB’s Codification project. This Form 10-Q has been updated to reflect the new Codification organization and all previous references to specific accounting standards are now replaced by references to the overall subject matter that pertains to the accounting policy, issue or transaction.

ASU No. 2009-06, Implementation Guidance on Accounting for Uncertainty in Income Taxes and Disclosure Amendments for Non-Public Entities (“ASU No. 2009-06”)

In September 2009, the FASB amended the income tax accounting guidance with the issuance of ASU No. 2009-06, which provided additional implementation guidance on accounting for uncertainty in income taxes. ASU No. 2009-06 amended the definition of a tax position to clarify that the term “tax position” encompasses an entity’s status, including its status as a pass-through entity. ASU No. 2009-06 also clarified that entities should attribute income taxes to either the entity or its owners based on how the tax laws and regulations of each jurisdiction attribute income taxes, rather than based on who pays the income taxes. If attributable to the entity, the accounting should be consistent with the guidance for uncertainty in income taxes. If the income taxes are attributable to the owner, the accounting by the entity would be as a transaction with owners. ASU No. 2009-06 also clarified that regardless of the tax status of a reporting entity, all tax positions of each entity in the consolidated or combined group must be considered when preparing financial statements for a group of related entities. ASU No. 2009-06 became effective for financial statements issued for interim and annual periods ended after September 15, 2009, or the quarter ended September 30, 2009 for AES. The adoption of ASU No. 2009-06 did not have a material impact on our financial statements.

New Accounting Pronouncements

The following accounting standards have been issued, but as of September 30, 2009 are not yet effective for and have not been adopted by AES.

FAS No. 167, Amendments to FASB Interpretation No. 46(R) (“FAS No. 167”)

In June 2009, the FASB issued an amendment to the accounting and disclosure requirements for the consolidation of VIEs. The amendment requires an entity to qualitatively, rather than quantitatively, assess the determination of the primary beneficiary of a VIE. This determination should be based on whether the entity has the power to direct the activities that most significantly impact the economic performance of the VIE and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Other key changes include: the requirement for an ongoing reconsideration of the primary beneficiary, the criteria for determining whether service provider or decision maker contracts are variable interests, the consideration of kick-out and removal rights in determining whether an entity is a VIE, the types of events that trigger the reassessment of whether an entity is a VIE and the expansion of the disclosures previously required. The impact of FAS No. 167 may require the Company to consolidate the assets, liabilities and operating results of certain VIEs, including certain entities currently accounted for under the equity method of accounting that AES does not currently consolidate. It may also require the Company to deconsolidate certain VIEs that are currently consolidated. The impact of the adoption may be applied retrospectively with a cumulative-effect adjustment to retained earnings as of the beginning of the first year restated, or through a cumulative-effect adjustment on the date of adoption. FAS No. 167 is effective for fiscal years beginning after November 15, 2009, or January 1, 2010 for AES. Early adoption is prohibited. AES is currently reviewing the potential impact of FAS No. 167 and at this time has determined that the adoption of FAS No. 167 may have a material impact on its consolidated financial statements.

ASU No. 2009-05, Fair Value Measurement and Disclosures (“ASU No. 2009-05”)

In August 2009, the FASB issued ASU No. 2009-05, which amended the fair value measurement and disclosure accounting guidance for the fair value measurement of liabilities. ASU No. 2009-05 provided

9

clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the following techniques:

• A valuation technique that uses the quoted price of the identical liability when traded as an asset or quoted prices for similar liabilities or similar liabilities when traded as assets.

• Another valuation technique that is consistent with the fair value principles of the income approach or market approach.

ASU No. 2009-05 also clarified that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs to reflect the existence of a restriction that prevents the transfer of the liability. It also clarified that Level 1 fair value measurements include a quoted price in an active market for the identical liability at the measurement date and the quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required. ASU No. 2009-05 is effective for interim and annual periods beginning after issuance, or October 1, 2009 for the Company. The adoption of ASU No. 2009-05 is not expected to have a material impact on the Company’s financial statements.

2. INVENTORY

The following table summarizes the Company’s inventory balances as of September 30, 2009 and December 31, 2008:

	September 30, 2009		December 31, 2008
	(in millions)
Coal, fuel oil and other raw materials	$	284	$	311
Spare parts and supplies		294		253
Total	$	578	$	564

3. FAIR VALUE DISCLOSURES

In April 2009, the FASB issued new accounting guidance requiring additional disclosures about the fair value of financial instruments in interim and annual financial statements.

The following table summarizes the carrying and fair value of the Company’s financial assets and liabilities as of September 30, 2009 and December 31, 2008:

	September 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Assets
Marketable securities (1)	$	1,414	$	1,414	$	1,413	$	1,413
Derivatives (2)		147		147		350		350
Total assets	$	1,561	$	1,561	$	1,763	$	1,763
Liabilities
Debt (3)	$	19,660	$	20,470	$	18,091	$	15,588
Derivatives (2)		464		464		534		534
Total liabilities	$	20,124	$	20,934	$	18,625	$	16,122

10

⁽¹⁾ See Note 4 — Investments in Marketable Securities for additional information regarding the classification of marketable securities in the fair value hierarchy.

⁽²⁾ See Note 5 — Derivative Instruments and Hedging Activities for additional information regarding the fair value of derivatives.

⁽³⁾ See Note 7 — Long-Term Debt for additional information regarding the fair value of the Company’s recourse and non-recourse debt.

The Company adopted the revised fair value measurement provisions 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 recognize any material adjustments to nonfinancial assets or liabilities measured at fair value on a nonrecurring basis during the three or nine months ended September 30, 2009. Although the adoption of the new fair value measurement and disclosure accounting guidance did not materially impact our financial condition, results of operations or cash flows, additional disclosures about fair value measurements are included in this Form 10-Q.

The Company’s financial assets and liabilities that are measured at fair value on a recurring basis fall into two broad categories: marketable securities and derivatives. Marketable securities are generally measured at fair value using the market approach. The Company’s investments in marketable securities generally consist of debt and equity securities. Equity securities are adjusted to fair value using quoted market prices. Debt securities primarily consist of unsecured debentures, certificates of deposit, government debt securities and money market funds held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to LIBOR), Selic (overnight borrowing rate) or IGPM (inflation) rates in Brazil and are adjusted based on the banks’ assessment of the specific businesses. Fair value is determined based on comparisons to market data obtained for similar assets and are considered Level 2 inputs. These investments are primarily issued by highly rated institutions and governmental agencies and therefore the consideration of counterparty credit risk does not have a material impact on the determination of fair value. The Company’s 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. The Company’s derivatives are primarily interest rate swaps to establish a fixed rate on non-recourse variable rate debt, foreign exchange instruments to hedge against currency fluctuations and derivatives or embedded derivatives associated with commodity contracts. The fair value of the Company’s 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.

11

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2009. 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. The Company’s 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.

	September 30, 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	$	1,399	$	16	$	1,341	$	42
Trading securities		7		7		-		-
Derivatives		147		-		70		77
Total assets	$	1,553	$	23	$	1,411	$	119
Liabilities
Derivatives	$	464	$	-	$	303	$	161
Total liabilities	$	464	$	-	$	303	$	161

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 and nine months ended September 30, 2009:

	Three Months Ended September 30, 2009					Nine Months Ended September 30, 2009
	Derivatives			Available-For- Sale Securities (5)		Derivatives			Available-For- Sale Securities (5)
	(in millions)					(in millions)
Balance at beginning of period (1)	$	(9	)	$	2	$	(69	)	$	42
Total gains/losses (realized/unrealized) (1)
Included in earnings (2)		(3	)		-		(20	)		-
Included in other comprehensive income		(23	)		-		117			-
Included in regulatory assets		(1	)		-		1			-
Purchases, issuances and settlements (1)		(28	)		40		(36	)		-
Asset transferred in (out) of Level 3		-			-		(187	) (3)		-
Liabilities transferred (in) out of Level 3		(20	) (4)		-		110	(4)		-
Balance at end of period (1)	$	(84	)	$	42	$	(84	)	$	42
Total gains/losses for the period included in earnings attributable to the change in unrealized gains/losses relating to assets and liabilities held at both the beginning and end of the period	$	(7	)	$	-	$	(34	)	$	-

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

⁽²⁾ See Note 5 — Derivative Instruments and Hedging Activities for further information regarding the classification of gains and losses included in earnings in the Condensed Consolidated Statements of Operations.

⁽³⁾ Assets transferred out of Level 3 during the nine months ended September 30, 2009 primarily resulted from the election of the normal purchase normal sale designation as of December 31, 2008 of a power purchase agreement (“PPA”). As such, the agreement was measured at fair value using significant unobservable inputs at December 31, 2008, but is subsequently being amortized and is not reported at fair value.

⁽⁴⁾ Liabilities transferred (in) out of Level 3 were primarily a result of an (increase) decrease in the significance of unobservable inputs to calculate the credit valuation adjustments of these derivative instruments.

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⁽⁵⁾ Available-for-sale securities in Level 3 are auction rate securities and variable rate demand notes which have failed remarketing or are not actively trading and for which there are no longer adequate observable inputs available to measure the fair value.

4. INVESTMENTS IN MARKETABLE SECURITIES

New accounting guidance related to investments in debt and equity securities became effective and was adopted by the Company for the quarter ended June 30, 2009. The new guidance amended existing other-than-temporary impairment guidance for debt securities to change the recognition threshold and to improve the presentation and disclosure of other-than-temporary impairment on debt and equity securities in the financial statements. The new accounting guidance also changed the accounting requirements related to the recognition of other-than-temporary impairment of debt securities. If other-than-temporary impairment is recognized, it is separated into two pieces 1) the amount representing the credit loss is recognized in earnings and 2) the amount related to other factors is recognized in other comprehensive income unless there is a plan to sell the assets in which case it would be recognized in earnings. The amount recognized in other comprehensive income for held-to-maturity debt securities is then amortized over the remaining life of the security. The changes were effective for new and existing securities held by an entity as of the beginning of the period adopted and required a cumulative adjustment to the opening balance of retained earnings in the period of adoption with a corresponding adjustment to accumulated other comprehensive income. The adoption did not have a material impact on the Company’s financial condition, results of operations, or cash flows. AES has incorporated the additional disclosure requirements on this Form 10-Q.

The following table sets forth the Company’s investments in marketable debt and equity securities reported at fair value as of September 30, 2009 and December 31, 2008 by security type and by level within the fair value hierarchy. The security types are determined based on the nature and risk of the security and are consistent with how the Company manages, monitors and measures its securities. These securities have been classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s 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 securities and their placement within the fair value hierarchy levels.

	September 30, 2009								December 31, 2008
	Level 1		Level 2		Level 3		Total (2)		Total (2)
	(in millions)
AVAILABLE-FOR-SALE:
Unsecured debentures (1)	$	-	$	706	$	-	$	706	$	674
Certificates of deposit (1)		-		470		-		470		493
Government debt securities		-		136		-		136		32
Common stock (3)		16		-		-		16		1
Money market funds		-		29		-		29		21
Other		-		-		42		42		42
Subtotal	$	16	$	1,341	$	42	$	1,399	$	1,263
TRADING:
Mutual funds		7		-		-		7		-
Subtotal		7		-		-		7		-
TOTAL	$	23	$	1,341	$	42	$	1,406	$	1,263

⁽¹⁾ Unsecured debentures are instruments similar to certificates of deposit that are held primarily by our subsidiaries in Brazil. The unsecured debentures and certificates of deposit included here do not qualify as cash equivalents and meet the definition of a security under the relevant guidance and are therefore classified as available-for-sale securities.

13

⁽²⁾ The amortized cost approximated fair value of the available-for-sale securities at September 30, 2009 and December 31, 2008, with the exception of the common stock discussed below.

⁽³⁾ During the three months ended September 30, 2009, an investment of the Company with a cost basis of $5 million, previously accounted for under the cost method, underwent an initial public offering (“IPO”). Subsequent to the IPO, the Company’s investment in common stock became marketable. Beginning in the third quarter, the common stock was accounted for as available-for-sale and adjusted to fair value at September 30, 2009. As a result, an unrealized gain of $10 million was recognized in other comprehensive income.

The following table sets forth the stated maturities of the Company’s investments in debt securities classified as available-for-sale as of September 30, 2009:

	Available-for-sale debt securities
	(in millions)
Less than one year	$	546
One to five years		710
Five to ten years		56
After ten years		42
Total	$	1,354

The following table summarizes the pre-tax gains and losses related to available-for-sale and trading securities for the three and nine months ended September 30, 2009 and 2008. There were no realized losses on the sale of available-for-sale securities. Gains and losses on the sale of investments are determined using the specific identification method. There was no other-than-temporary impairment recognized in earnings or other comprehensive income for the three and nine months ended September 30, 2009 and 2008.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(in millions)
Gains included in earnings that relate to trading securities held at the reporting date	$	-	$	-	$	1	$	-
Gain (losses) included in other comprehensive income		10		-		10		(2	)
Gains reclassified out of other comprehensive income into earnings		2		-		2		-
Proceeds from sales		1,712		2,374		2,982		3,957
Gross realized gains on sales		2		-		3		-

During the second quarter of 2009, three of the Company’s generation businesses in the Dominican Republic exchanged $110 million of accounts receivable due from the government-owned distribution companies of the Dominican Republic for sovereign bonds of the same amount. The bonds, which were classified as available-for-sale securities, were adjusted to fair value when acquired. During the second and third quarter of 2009, the Company used a portion of the bonds with a carrying value of $31 million to settle third-party liabilities and sold the remaining bonds. As of September 30, 2009, all of the sovereign bonds had been sold or transferred.

14

The following table sets forth the Company’s investments in marketable securities classified as held-to-maturity as of September 30, 2009 and December 31, 2008:

	September 30, 2009		December 31, 2008
	(in millions)
Government debt securities	$	4	$	93
Certificates of deposit		4		45
Other		-		12
Total	$	8	$	150

The amortized cost approximated fair value of the held-to-maturity securities at September 30, 2009 and December 31, 2008. As of September 30, 2009, all held-to-maturity debt securities had stated maturities within one year.

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Risk Management Objectives

The Company is exposed to market risks associated with its enterprise-wide business activities, namely the purchase and sale of fuels and electricity as well as foreign currency risk and interest rate risk. In order to manage the market risks associated with these business activities, we enter into contracts that incorporate derivatives and financial instruments, including forwards, futures, options, swaps or combinations thereof as appropriate. Derivative transactions are not entered into for trading purposes.

15

Interest Rate Risk

AES and its subsidiaries utilize variable rate debt financing for construction projects and operations, resulting in an exposure to interest rate risk. Interest rate swap, cap and floor agreements are entered into to manage interest rate risk by effectively fixing or limiting the interest rate exposure on the underlying financing. These interest rate contracts range in maturity through 2028. The following table sets forth, by type of interest rate index, the Company’s current and maximum outstanding notional under its interest rate derivative instruments, the weighted average remaining term and the percentage of variable-rate debt hedged that is based on that index as of September 30, 2009 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:

	September 30, 2009
	Current			Maximum (1)			Weighted Average Remaining Term (1)	% of Debt Currently Hedged by Index (2)
Interest Rate Derivatives	Derivative Notional	Derivative Notional Translated to USD		Derivative Notional	Derivative Notional Translated to USD
		(in millions)					(in years)
Bubor (Hungarian Forint)	3,683	$	20	3,683	$	20	<1	83	%
Libor (U.S. Dollar)	2,935		2,935	3,606		3,606	10	72	%
Euribor (Euro)	780		1,142	820		1,201	13	83	%
Treasury Bills (U.S. Dollar) (3)	70		70	70		70	<1	123	%
Libor (British Pound Sterling)	51		82	51		82	10	65	%
City of Petersburg, IN Pollution Control Refunding Revenue Bonds Adjustable Rate (U.S. Dollar)	40		40	40		40	13	100	%

⁽¹⁾ The Company’s interest rate derivative instruments primarily include accreting and amortizing notionals. The maximum derivative notional represents the largest notional at any point between September 30, 2009 and the maturity of the derivative instrument, which includes forward starting derivative instruments. The weighted average remaining term represents the tenor (remaining term) of our interest rate derivatives weighted by the corresponding maximum notional in USD.

⁽²⁾ Excludes variable-rate debt tied to other indices where the Company had no interest rate derivatives.

⁽³⁾ The debt and swap are related to a construction project. This swap does not currently qualify for cash flow hedge accounting.

Cross currency swaps are utilized in certain instances to manage the risk related to fluctuations in both interest rates and certain foreign currencies. These cross currency contracts range in maturity through 2028. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notional of its cross currency derivative instruments as of September 30, 2009, which are all in qualifying cash flow hedging relationships. These swaps are amortized and therefore the notional amount represents the maximum outstanding notional as of September 30, 2009:

	September 30, 2009
Cross Currency Swaps	Notional	Notional Translated to USD		Weighted Average Remaining Term (1)	% of Debt Currently Hedged by Index (2)
	(in millions)			(in years)
Chilean Unidad de Fomento (CLF)	6	$	212	16	82	%
Euro (EUR)	4		6	<1	<1	%

⁽¹⁾ Represent the remaining tenor of our cross currency swaps weighted by the corresponding notional in U.S. Dollar.

⁽²⁾ Represent the proportion of foreign currency denominated debt hedged by the same foreign currency denominated notional of the cross currency swap.

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Foreign Currency Risk

We are exposed to foreign currency risk as a result of our investments in foreign subsidiaries and affiliates. AES operates businesses in many foreign environments and such operations in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. Foreign currency forwards, swaps and options are utilized, where possible, to manage the risk related to fluctuations in certain foreign currencies. These foreign currency contracts range in maturity through 2010. The following tables set forth, by type of foreign currency denomination, the Company’s outstanding notional over the remaining terms of its foreign currency derivative instruments as of September 30, 2009 regardless of whether the derivative instruments are in qualifying hedging relationships:

	September 30, 2009
Foreign Currency Options	Notional	USD Notional (1)		Probability Adjusted Notional (2)			Remaining Term
	(in millions)						(in years)
Hungarian Forint (HUF)	641	$	3	$	-	(3)	<1
Philippine Peso (PHP)	356		7		2		<1
Brazilian Real (BRL)	123		63		5		<1
Argentine Peso (ARS)	82		16		-	(3)	<1
British Pound Sterling (GBP)	8		13		9		<1
Euro (EUR)	3		5		1		<1

⁽¹⁾ Represent contractual notionals at inception of trade.

⁽²⁾ Represents the gross notional amounts times the probability of exercising the option, which is based on the relationship of changes in the option value with respect to changes in the price of the underlying currency.

⁽³⁾ De minimis amount.

	September 30, 2009
Foreign Currency Forwards and Swaps	Notional	Notional Translated to USD		Remaining Term
	(in millions)			(in years)
Colombian Peso (COP)	43,989	$	19	<1
Argentine Peso (ARS)	145		34	<1
U.S. Dollar (USD) (1)	5		5	<1

⁽¹⁾ Related to a U.S. Dollar exposure at one of our subsidiaries in Brazil.

In addition, certain of our subsidiaries have entered into contracts denominated in currencies other than their own functional currencies or the currency of the item being purchased or sold. These contracts range in maturity through 2025. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notional over the remaining terms of its foreign currency embedded derivative instruments as of September 30, 2009:

	September 30, 2009
Embedded Foreign Currency Derivatives	Notional	Notional Translated to USD		Weighted Average Remaining Term (1)
	(in millions)			(in years)
Kazakhstani Tenge (KZT)	55,831	$	370	10
Hungarian Forint (HUF)	107		1	<1
Argentine Peso (ARS)	67		17	2
Philippine Peso (PHP)	27		1	4
Euro (EUR)	2		3	10
Brazilian Real (BRL)	2		1	<1

⁽¹⁾ Represent the remaining tenor of our foreign currency embedded derivatives weighted by the corresponding notional in U.S. Dollar.

17

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 (which provide our distribution businesses with a franchise to serve a specific geographic region), 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 of our businesses hedge certain aspects of their commodity risks using financial hedging 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 used 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 are exposed to commodity price risk. Eastern Energy in New York and Deepwater in Texas, two of our North America generation businesses, sell electricity into power pools managed by the New York Independent System Operator and the Electric Reliability Council of Texas, respectively. In addition, Eastern Energy has hedged a portion of its power exposure for 2010 by entering into hedges of natural gas prices, as movements in natural gas prices affect power prices. While there is a strong relationship between natural gas and power prices, the natural gas hedges do not currently qualify for hedge accounting treatment. All financial transactions at Eastern Energy hedge 80% of the forecasted sales of electricity through the remainder of 2009 and 45% of the forecasted sales of electricity in 2010. All financial transactions at Deepwater hedge 49% of the forecasted sales of electricity through the remainder of 2009 and 18% of the forecasted sales of electricity in 2010.

In addition, certain of our subsidiaries have entered into PPAs and fuel supply agreements that have been assessed as derivatives or contain embedded features that have been assessed as embedded derivatives. These contracts range in maturity through 2024. The following table sets forth by type of commodity, the Company’s outstanding notional for the remaining term of its commodity derivative (excluding Eastern Energy and Deepwater) and embedded derivative instruments as of September 30, 2009:

	September 30, 2009
Commodity Derivatives	Volume	Weighted Average Remaining Term (1)
	(in millions)	(in years)
Natural gas (MMBtu)	106	9
Petcoke (Metric tons)	15	15
Coal (Metric tons)	1	1
Log wood (Tons)	1	3
Electricity (MWhs)	1	1

⁽¹⁾ Represents the remaining tenor of our commodity and embedded derivatives weighted by the corresponding volume.

Accounting and Reporting

In accordance with the accounting standards for derivatives and hedging, we recognize all derivatives, except those designated as “normal purchase normal sale,” 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.

18

The accounting standards for derivatives and hedging enable 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 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 the accounting standards for derivatives and hedging. If AES deems that a derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively. During the first nine months of 2009 no cash flow hedges were discontinued 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.

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 the accounting standards for derivatives and hedging.

The Company has elected not to offset net derivative positions in the financial statements. Accordingly, the Company does not offset such derivative positions against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements. At September 30, 2009, we held $37 million of cash collateral that we received from counterparties to our derivative positions, which is classified as “restricted cash” and “accrued and other liabilities” in the condensed consolidated balance sheets. Also, at September 30, 2009, we had no cash collateral posted with (held by) counterparties to our derivative positions.

As of September 30, 2009, approximately $(130) million, $1 million, $(1) million and $58 million of the pre-tax accumulated other comprehensive (loss) income related to interest rate derivative instruments, cross currency derivative instruments, foreign currency derivative instruments and commodity derivative instruments, respectively, is expected to be recognized as a (decrease) increase to income from continuing operations before income taxes over the next twelve months. 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 and cross currency swaps, as depreciation is recognized for interest rate hedges during construction, as foreign currency transaction and translation gains and losses are recognized for hedges of foreign currency exposure and as electricity sales are recognized for hedges of forecasted electricity transactions. Cash flows associated with settled derivatives have been included in the condensed consolidated statements of cash flows as operating and/or investing activities based on the nature of the underlying transaction.

19

The following table sets forth by type of derivative the financial statement location and fair value of derivative instruments as of September 30, 2009:

	September 30, 2009
	Designated as Hedging Instruments			Not Designated as Hedging Instruments
	(in millions)
Assets
Other current assets
Cross currency derivatives	$	1		$	-
Foreign exchange derivatives		-			2
Commodity derivatives:
Electricity		60			-
Fuel		-			23
Other		-			2
Total other current assets		61			27
Other assets
Interest rate derivatives		54			-
Commodity derivatives:
Electricity		5			-
Total other assets—noncurrent		59			-
Total assets	$	120		$	27
Liabilities
Accrued and other liabilities
Interest rate derivatives	$	(119	)	$	(11	)
Foreign exchange derivatives		(1	)		(14	)
Commodity derivatives:
Electricity		(2	)		-
Fuel		-			(3	)
Other		-			(13	)
Total accrued and other liabilities—current		(122	)		(41	)
Other long-term liabilities
Interest rate derivatives		(249	)		(18	)
Foreign exchange derivatives		-			(4	)
Cross currency derivatives		(24	)		-
Commodity derivatives:
Fuel		-			(2	)
Other		-			(4	)
Total other long-term liabilities		(273	)		(28	)
Total liabilities	$	(395	)	$	(69	)

20

The following tables set forth by type of derivative, the financial statement location and amount of gains (losses) recognized in accumulated other comprehensive loss (“AOCL”) and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging for the three and nine months ended September 30, 2009:

	Three Months Ended September 30, 2009
	Gains (Losses) Recognized in AOCL on Derivatives			Location of Gains (Losses) Reclassified from AOCL into Earnings	Gains (Losses) Reclassified from AOCL
	(in millions)				(in millions)
Interest rate derivatives	$	(94	)	Interest expense	$	(32	) (1)
Cross currency derivatives		3		Interest expense		(1	)
				Foreign currency transaction gains (losses) on net monetary position		(9	)
Foreign currency derivatives		(1	)	Foreign currency transaction gains (losses) on net monetary position		-	(2)
Commodity derivatives - electricity		11		Non-regulated revenue		63
Total	$	(81	)		$	21

	Nine Months Ended September 30, 2009
	Gains (Losses) Recognized in AOCL on Derivatives			Location of Gains (Losses) Reclassified from AOCL into Earnings	Gains (Losses) Reclassified from AOCL
	(in millions)				(in millions)
Interest rate derivatives	$	7		Interest expense	$	(71	) (1)
Cross currency derivatives		37		Interest expense		(1	)
				Foreign currency transaction gains (losses) on net monetary position		23
Foreign currency derivatives		(1	)	Foreign currency transaction gains (losses) on net monetary position		-	(2)
Commodity derivatives - electricity		120		Non-regulated revenue		150
Total	$	163			$	101

⁽¹⁾ Excludes $4 million and $18 million of losses for the three and nine months ended September 30, 2009, respectively, reclassified from accumulated other comprehensive losses related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting.

⁽²⁾ De minimis amount of losses reclassified from AOCL.

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The following tables set 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 in the accounting standards for derivatives and hedging, for the three and nine months ended September 30, 2009:

		Amount of Gains (Losses) Recognized in Earnings
	Location of Gains (Losses) Recognized in Earnings	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
		(in millions)
Interest rate derivatives	Interest expense	$	2		$	12
Cross currency derivatives	Interest expense		-	(1)		2
Commodity derivatives - electricity	Non-regulated revenue		-	(1)		(2	)
Total		$	2		$	12

⁽¹⁾ De minimis 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, as defined in the accounting standards for derivatives and hedging, for the three and nine months ended September 30, 2009:

		Amount of Gains (Losses) Recognized in Earnings
	Location of Gains (Losses) Recognized in Earnings	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
		(in millions)
Interest rate derivatives	Interest expense	$	(23	)	$	(42	)
Foreign exchange derivatives	Non-regulated cost of sales		(1	)		(12	)
Foreign exchange derivatives	Foreign currency transaction gains (losses) on net monetary position		(8	)		(30	)
Commodity derivatives - PPA embedded	Non-regulated revenue		-			(5	)
Commodity derivatives - other	Non-regulated revenue		(17	)		(17	)
Commodity derivatives - fuel	Non-regulated cost of sales		(1	)		(1	)
Total		$	(50	)	$	(107	)

In addition, IPL, the Company’s North American integrated utility, has two derivative instruments for which the gains and losses are accounted for in accordance with accounting standards for regulated operations, as regulatory assets or liabilities. Gains and losses on these derivatives due to changes in fair value are recoverable through future rates and are initially recognized as an adjustment to the regulatory asset or liability and recognized through earnings when the related costs are recovered through IPL’s rates. Therefore, these gains and losses are excluded from the above table. For the three and nine months ended September 30, 2009, there were decreases in the fair values of these derivatives of $2 million and $3 million, respectively, included in regulatory assets and liabilities on the accompanying condensed consolidated balance sheet.

Credit Risk-Related Contingent Features

Certain of our businesses have derivative agreements that contain credit contingent provisions which would permit the counterparties with which we are in a net liability position to require collateral credit support when the

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fair value of the derivatives exceeds the unsecured thresholds established in the agreements. These thresholds vary based on the subsidiaries’ credit ratings and as their credit ratings are lowered the thresholds decrease, requiring more collateral support.

Eastern Energy, our generation business in New York, enters into commodity derivative transactions with several counterparties who have market exposure limits defined in their transaction agreements. Pursuant to the aforementioned credit contingent provisions, if Eastern Energy’s credit rating were to fall below the minimum thresholds established in each of the respective transaction agreements, the counterparties could demand immediate collateralization of the entire mark-to-market value of the derivatives (excluding credit valuation adjustments) if they were in a net liability position. As of September 30, 2009, Eastern Energy had net liability positions of $1 million and had posted a nominal amount of collateral to support these positions based on its current credit rating and the related thresholds in the agreements.

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. Pursuant to the aforementioned credit contingent provisions, 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 net liability position, which was $24 million at September 30, 2009. As of September 30, 2009, Gener had posted $50 million in the form of a letter of credit to support these swaps.

6. INVESTMENTS IN AND ADVANCES TO AFFILIATES

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

AES holds a 71% ownership interest in AES Energia Cartagena (“Cartagena”), a VIE, in which the Company is not the primary beneficiary. The Company’s investment in Cartagena is a combination of common stock and participative loans. As a result of unrealized losses on Cartagena’s interest rate hedges, in December 2008 the investment balance was reduced to zero and the recognition of equity losses was suspended. AES will resume the equity method of accounting and recognize income once Cartagena generates income of which AES’s portion is greater than or equal to the cumulative losses AES has not recognized while the equity method of accounting has been suspended. In June 2009, Cartagena received a cash settlement of $53 million for liquidated damages, including legal costs incurred, related to the construction delay from December 2005 to November 2006 of the 1,200 MW generation plant in Cartagena, Spain. Cartagena used the settlement proceeds to repay a portion of the participative loans outstanding to its investors including AES. The Company received its proportionate share of the settlement, $35 million, which was recognized as “net equity in earnings of affiliates” in the second quarter of 2009 because the distribution was in excess of the Company’s current investment balance of zero and AES does not have an obligation or intent to fund future cash flow requirements of Cartagena.

The following table summarizes financial information of the affiliates 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 accounted for using the equity method of accounting:

	50%-or-less Owned Affiliates (1)									Majority-owned Unconsolidated Subsidiaries (2)
	Three Months Ended September 30,					Nine Months Ended September 30,				Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008		2009		2008			2009		2008
	(in millions)									(in millions)
Revenue	$	343	$	301		$	880	$	889	$	41	$	43		$	120	$	131
Gross margin	$	73	$	14		$	143	$	99	$	21	$	18		$	41	$	49
Net income (loss)	$	58	$	(3	)	$	92	$	80	$	5	$	(5	)	$	27	$	(2	)

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⁽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 of accounting in accordance with its accounting policy regarding equity method investments. In addition, although the Company’s ownership interest in Trinidad Generation Unlimited, (“Trinidad”) is 10%, the Company accounts 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.

⁽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.

7. LONG-TERM DEBT

The Company has two types of debt reported on its condensed consolidated balance sheet: non-recourse and recourse debt. Non-recourse debt is used to fund investments and capital expenditures for the construction and acquisition of electric power plants, wind projects and distribution companies at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. The default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries. Recourse debt is direct borrowings by the Parent Company and is used to fund development, construction or acquisitions, including serving as funding for equity investments or loans to the affiliates. The Parent Company’s debt is among other things, recourse to the Parent Company and is structurally subordinated to the affiliates’ debt.

Recourse and non-recourse debt are carried at amortized cost. The following table summarizes the carrying amount and fair value of the Company’s recourse and non-recourse debt as of September 30, 2009 and December 31, 2008:

	September 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Non-recourse debt	$	14,148	$	14,897	$	12,943	$	11,200
Recourse debt		5,512		5,573		5,148		4,388
Total debt	$	19,660	$	20,470	$	18,091	$	15,588

The fair value of non-recourse debt is estimated differently depending upon the type of loan. The fair value of fixed rate loans is estimated using quoted market prices or a discounted cash flow analysis. For variable rate loans, carrying value typically approximates fair value. At December 31, 2008, credit spreads were significantly above historic levels. For the U.S. Dollar, Euro and British Pound markets where the Company believed the expanded credit spread was material, fair value was estimated using a discounted cash flow analysis. The increase in credit spreads was calculated as the difference between composite fair value curves, published by pricing services for the relevant issuer credit rating, and London Inter-Bank Offered Rate (“LIBOR”). For all other currencies, the Company continued to assume the carrying value was equal to fair value. During the second and third quarters of 2009, credit spreads returned to a typical range for all currencies and the Company concluded that carrying value approximated fair value for all of our variable rate debt as of September 30, 2009.

The fair value was determined using available market information as of September 30, 2009. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to September 30, 2009.

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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 September 30, 2009:

	Primary Nature of Default	September 30, 2009
Subsidiary		Default		Net Assets
		(in millions)
Kelanitissa	Covenant	$	45	$	14
Ebute (1)	Covenant		8		160
Total		$	53

⁽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 was classified as current.

None of the subsidiaries that are currently in default is a material subsidiary under the Parent Company’s corporate debt agreements which 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 the Company’s 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 agreements.

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 are being used to meet Gener’s funding requirements for projects under construction.

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 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 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 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 through June 23, 2010. From June 23, 2010 through 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%.

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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 9.75% senior unsecured notes due 2016 in a private placement. The notes were priced at a discount to yield 11%. Subsequently, the Parent Company allocated a substantial portion of the proceeds to voluntarily reduce the size of its $600 million senior unsecured credit facility among the Parent Company, Merrill Lynch Bank USA and the banks party thereto (the “senior unsecured credit facility”). At September 30, 2009, the remaining commitments under the senior unsecured credit facility were $108 million, which consisted primarily of letters of credit, the majority of which supported a project under construction in Bulgaria. On October 7, 2009, the Parent Company voluntarily reduced all of the remaining commitments available under the senior unsecured credit facility and terminated the facility agreement. The outstanding letters of credit under the senior unsecured credit facility were transferred to the senior secured credit facility.

On June 1, 2009, the Parent Company repaid at maturity all of its outstanding 9.5% senior unsecured notes at par for an aggregate principal amount of $154 million.

8. 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 September 30, 2009, the Company had recorded liabilities of $30 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 September 30, 2009.

The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion by-products), and certain air emissions, such as SO₂, NO_x, particulate matter and mercury. Such risks and uncertainties include risks and uncertainties related to increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations.

To date, the primary regulation of GHG emissions affecting the Company’s U.S. plants has been through the Regional Greenhouse Gas Initiative (“RGGI”). Under RGGI, ten Northeastern States have coordinated to establish rules that require reductions in CO₂ emissions from power plant operations within those states through a cap-and-trade program. States in which our subsidiaries have generating facilities include Connecticut, Maryland, New York and New Jersey. Under RGGI, power plants must acquire one carbon allowance through auction or in the emission trading markets for each ton of CO₂ emitted. As noted in the Company’s 2008 Form 10-K and September 2009 Form 8-K, we have estimated that the costs to the Company of compliance with RGGI could be approximately $29 million per year for 2009 through 2011.

The primary international agreement concerning GHG emissions is the Kyoto Protocol which became effective on February 16, 2005 and requires the industrialized countries that have ratified it to significantly reduce their GHG emissions. The vast majority of the developing countries which have ratified the Kyoto Protocol have no GHG reduction requirements. Many of the countries in which the Company’s subsidiaries operate have no reduction obligations under the Kyoto Protocol. In addition, of the 29 countries that the Company’s subsidiaries operate in, all but two — the United States (including Puerto Rico) and Kazakhstan — have ratified the Kyoto Protocol.

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In July 2003, the European Community “Directive 2003/87/EC on Greenhouse Gas Emission Allowance Trading” was created, which requires member states to limit emissions of CO₂ from large industrial sources within their countries. To do so, member states are required to implement EC-approved national allocation plans (“NAPs”). The European Union has announced that it intends to keep the European Union Emissions Trading System (“EU ETS”) in place after the potential expiration of the Kyoto Protocol in 2012. The Company’s subsidiaries operate seven electric power generation facilities, and another subsidiary has one under construction, within six member states which have adopted NAPs to implement Directive 2003/87/EC. The risk and benefit associated with achieving compliance with applicable NAPs at several facilities of the Company’s subsidiaries are not the responsibility of the Company’s subsidiaries as they are subject to contractual provisions that transfer the costs associated with compliance to contract counterparties. However, one such contract counterparty, GDF-Suez, is currently disputing these provisions with AES Energía Cartagena S.R.L. In connection with this dispute or any similar dispute that might arise with other contract counterparties, there can be no assurance that the Company and/or the relevant subsidiary will prevail, or that the administrative burden associated with any such dispute will not be significant.

In 2009, a key development in the area of GHG legislation has been the passage of H.R. 2454, The American Clean Energy and Security Act of 2009 (“ACESA”) by the U.S. House of Representatives on June 26, 2009. ACESA contemplates a nationwide cap and trade program to reduce U.S. emission of CO₂ and other greenhouse gases starting in 2012. Key features of ACESA include, among other things:

• A planned target to reduce by 2020 GHG emissions by 17% from 2005 levels and to reduce GHG emissions by 83% from 2005 levels by 2050.

• A requirement that certain GHG emitting companies, including most power generators, surrender on an annual basis one ton of CO₂ equivalent allowances or GHG offset credits for each ton of annual CO ₂ equivalent emissions. Such companies will be required to meet allowance surrender requirements via the allocations of free allowances if available from the U.S. Environmental Protection Agency (“EPA”) or purchases in the open market at auctions if free allowances are not allocated, or otherwise.

• A mechanism under which the EPA would initially issue a capped and steadily declining number of tradable free emissions allowances to certain sections of affected industries, including certain generators and utilities in the electricity sector, with such free distribution of allowances to the electricity sector phasing out over a five year period from 2026 through 2030.

• A provision permitting up to two billion tons of GHG offset credits in the aggregate, if available, to be purchased annually by all emitters to satisfy the requirements above.

• A provision precluding the EPA from regulating GHG emissions under the existing provisions of the Clean Air Act (“CAA”).

• A temporary prohibition on the implementation of similar State or regional GHG cap and trade programs, with a six year moratorium (2012 to 2017) on the implementation or enforcement of similar GHG emission caps.

• The establishment of a combined energy efficiency and renewable electricity standard (“RES”) that would require retail electric utilities to receive 6% of their power from renewable sources by 2012, with such requirement increasing to 20% by 2020. In certain circumstances, a portion of this requirement for renewable energy could be satisfied through measures intended to increase energy efficiency.

The Senate has begun to deliberate similar legislation with the introduction on September 30, 2009 of draft bill S. 1733, the Clean Energy Jobs and American Power Act (“CEJAPA”). CEJAPA contemplates a planned target to reduce by 2020 GHG emissions by 20% from 2005 levels and by 83% from 2005 levels by 2050. CEJAPA has not advanced out of the Senate Committee in which it was introduced (the Committee on the Environment and Public Works) and, if it does advance out of the Committee and is ultimately passed by the Senate, it may undergo significant revisions from its current form.

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At this time, if ACESA or CEJAPA were to be enacted into law, or some reconciled version of ACESA or CEJAPA were to be enacted, the impact on the Company’s consolidated results of operations cannot be accurately predicted because of a number of uncertainties with respect to the specific terms and implementation of any such potential legislation, including, among other provisions:

• The number of free allowances that will be allocated to subsidiaries of the Company.

• The cost to purchase allowances in an auction or on the open market, and the cost of purchasing GHG offset credits.

• The extent to which our utility business (IPL) will be able to recover compliance costs from its customers.

• The benefits to our renewables businesses from the RES provision, if any.

• The benefits to our climate solutions projects from the potentially increased demand for GHG offset credits arising from GHG legislation, if any.

• The benefits from the temporary moratorium on state or regional GHG cap and trade programs, if any.

If federal legislation is not enacted that precludes the EPA from regulating GHG emissions under the CAA, the EPA plans to regulate GHG emissions. On September 28, 2009 the EPA proposed a rule to regulate GHG emissions from automobiles, a mobile source of emissions. If such rule is ultimately enacted with respect to a mobile source, one effect would be to subject stationary sources of GHG emissions (including power plants) to regulation under various sections of the CAA. The most important impact on stationary sources would be a requirement that all new sources of GHG emissions of over 250 tons per year, and existing sources planning physical changes that would increase their GHG emissions, obtain new source review permits from the EPA prior to construction. Such sources would be required to apply “best available control technology” to limit the emission of GHGs. On September 30, 2009, the EPA proposed a rule that would limit such regulation of stationary sources to those stationary sources emitting the CO₂ equivalent of over 25,000 tons per year of GHGs. In September of 2009 the EPA also finalized a rule mandating the widespread reporting and tracking of GHG emissions. Although this tracking and reporting rule does not mandate reductions in GHG emissions, data generated from its implementation may facilitate the further development of federal GHG policy, which may include mandatory GHG emissions limits.

Our subsidiaries conduct business in a number of countries that have ratified the Kyoto Protocol, an international agreement concerning GHG emissions. The Kyoto Protocol is currently expected to expire at the end of 2012. A United Nations conference, called COP 15, is planned for December of 2009 in Copenhagen, Denmark. COP 15 is focused primarily on establishing a new international agreement that would succeed the Kyoto Protocol or establishing a framework that will lead to such an international agreement. There are a number of uncertainties and challenges regarding these discussions, including, among other factors, burden-sharing between developing and wealthier nations, the commitments (if any) of the United States under any such agreement, whether large developing countries such as China, India and Brazil will accept emission caps, and the continued availability of international offsets under the Clean Development Mechanism of the Kyoto Protocol.

There is substantial uncertainty with respect to whether U.S. federal GHG legislation will be enacted into law, whether the EPA will regulate GHG emissions, and whether a new international agreement to succeed the Kyoto Protocol will be reached, and there is additional uncertainty regarding the final provisions and implementation of any potential U.S. federal GHG legislation, any EPA rules regulating GHG emissions and any international agreement to succeed the Kyoto Protocol. In light of these uncertainties, the Company cannot accurately predict the impact on its consolidated results of operations from potential U.S. federal GHG legislation, EPA regulation of GHG emissions or any new international agreement on such emissions, or make a reasonable estimate of the potential costs to the Company associated with any such legislation, regulation or international agreement; however, the impact from any such legislation, regulation or international agreement could have a material adverse effect on certain of our U.S. or international subsidiaries and on the Company and its consolidated results of operations.

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As noted in the Company’s 2008 Form 10-K and September 2009 Form 8-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. The EPA is now expected to propose a new rule to address hazardous air pollutants (“HAPs”) from electric generation power plants, including mercury. With respect to the HAPs, the EPA issued a notice of the agency’s intent to collect information so that it can develop a maximum achievable control technology standard for coal-fired power plants which, unlike CAMR, will not provide a market-based compliance option (e.g., cap-and-trade) for power plants subject to the rule. The EPA recently entered into a settlement agreement under which the EPA committed to issue a proposed HAPs rule for coal-fired power plants by March 2011 and a final rule by November 2011. The EPA has indicated that all existing coal-fired power plants will be required to comply with such standards within four years of a final rule. While the exact impact and cost of any such new federal rules 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 September 30, 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 $446 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 September 30, 2009, the Parent Company had $192 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. During the third quarter the Company paid letter of credit fees ranging from 3.17% to 8.36% per annum on the outstanding amounts. See further discussion in Note 7 — Long-Term Debt regarding the termination of the senior unsecured credit facility in October 2009. All remaining commitments under the senior unsecured credit facility were transferred to the senior secured credit facility.

As of September 30, 2009, The AES Corporation had $140 million of commitments to invest in subsidiaries under construction and to purchase related equipment, excluding approximately $136 million of such obligations 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: $45 million in 2009, $39 million in 2010 and $56 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 September 30, 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

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found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$970 million ($543 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. Eletropaulo has consented to the appointment of such an expert, subject to a reservation of rights. 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.

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. After hearings at FERC, AES Placerita was found 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. As FERC investigations and hearings progressed, numerous appeals on related issues were filed with the U.S. Court of Appeals for the Ninth Circuit. Over the past five years, the Ninth Circuit issued several opinions that had the potential to expand the scope of the FERC proceedings and increase refund exposure for AES Placerita and other sellers of electricity. Following remand of one of the Ninth Circuit appeals in March 2009, FERC started a new hearing process involving AES Placerita. In May 2009, AES Placerita entered into a settlement, subject to FERC approval, concerning the claims before FERC against AES Placerita relating to the California energy crisis of 2000-2001, including the California refund proceeding. Pursuant to the settlement, AES Placerita paid $6 million and assigned a receivable of $168,119 due to it from the California Power Exchange in return for a release of all claims against it at FERC by the settling parties and other

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consideration. In July 2009, FERC approved the settlement as submitted. To date, in excess of 97% of the buyers in the market have elected to join the settlement. A small amount of AES Placerita’s settlement payment was placed in escrow for buyers that do not join the settlement (“non-settling parties”). It is unclear whether the escrowed funds will be enough to satisfy any additional sums that might be determined to be owed to non-settling parties at the conclusion of the FERC proceedings concerning the California energy crisis. However, any such additional sums are expected to be immaterial to the Company’s consolidated financial statements. In July 2009, one non-settling party, the Sacramento Municipal Utility District (“SMUD”), requested that the FERC rehear its order approving the settlement. The FERC denied SMUD’s petition for rehearing in September 2009. SMUD has until November 13, 2009 to appeal the FERC’s approval of the settlement.

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 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

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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 the Federal Court of Sao Paulo (“FSCP”) 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 May 2006, the FCSP 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 with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal with the FCA, which was subsequently consolidated with the MPF’s interlocutory appeal, seeking a transfer of venue and to enjoin the FCSP from considering any of the alleged violations. In June 2009, the FCA granted the injunction sought by AES Elpa and AES Transgás and transferred the case to the Federal Court of Rio de Janeiro. MPF likely will appeal. The MPF’s lawsuit before the FCSP has been stayed pending a final decision on the 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 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

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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 ($3.4 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 ($8.2 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 ($2.1 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 ($427 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 ($353 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 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’

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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 subsequently appealed to the U.S. Court of Appeals for the Fifth Circuit, which heard oral arguments in November 2008. In October 2009, the Fifth Circuit affirmed the District Court’s dismissal of the plaintiffs’ unjust enrichment, fraudulent misrepresentation, and civil conspiracy claims. However, the Fifth Circuit reversed the District Court’s dismissal of the plaintiffs’ public and private nuisance, trespass, and negligence claims, and remanded those claims to the District Court for further proceedings. The Company intends to seek en banc review at the Fifth Circuit. 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 July 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan (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. Also, the economic court issued an injunction to secure Nurenergoservice’s alleged liability, freezing Nurenergoservice’s bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. Nurenergoservice’s appeal to the court of appeals (first panel) was rejected in July 2008. In February 2009, the Antimonopoly Agency seized approximately 783 million KZT ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice’s alleged damages liability. However, in October 2009, Nurenergoservice’s appeal to the Kazakhstan Supreme Court was upheld. The Supreme Court annulled the decisions of the lower courts and remanded the case to the economic court for reconsideration. 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. 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. The Compensation Committee’s successor, 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.

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

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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 dismissed in April 2009. In June 2009, UK HPP paid the alleged damages and thus the economic court thereafter canceled the injunction on UK HPP’s assets. UK HPP has filed an appeal with the Kazakhstan Supreme Court, which is pending. Furthermore, the Antimonopoly Agency has initiated administrative proceedings against UK HPP for its alleged antimonopoly violations. In May 2009, the administrative court of first instance ordered UK HPP to pay approximately 99 million KZT ($665,000) in administrative fines, which UK HPP did in June 2009. 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.

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 April 2009, the Antimonopoly Agency initiated an investigation of AES Ust-Kamenogorsk TETS LLP’s (“UKT”) power sales in 2008 through February 2009. With respect to UKT’s 2008 sales, the Antimonopoly Agency has issued an order allegedly quantifying UKT’s revenues from those sales, but the amount of damages and/or fines that UKT will have to pay, if any, for its alleged antimonopoly violations relating to the 2008 sales has not been determined and is the subject of ongoing court proceedings. As for UKT’s sales in January and February 2009, the Antimonopoly Agency’s investigation of those sales is temporarily suspended pending court proceedings concerning UKT’s market share. If UKT fails to prove in those proceedings that it is not a dominant market entity, the Antimonopoly Agency’s investigation will resume. UKT 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.

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

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 requested 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 sought 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 sought an IURC order requiring IPL to resume making annual contributions to the VEBA Trust. IPL filed a motion to dismiss and both parties sought summary judgment in the IURC proceeding. In May 2009, the IURC issued an order granting summary judgment in favor of IPL. In June 2009, the Complainants filed an appeal of the IURC’s May 2009 order with the Indiana Court of Appeals. Briefing on the appeal is now complete and oral argument is scheduled for November 30, 2009. IPL anticipates a decision on the appeal sometime in 2010. IPL believes it has meritorious defenses to the Complainants’ claims and it will continue to assert them vigorously in all proceedings; however, there can be no assurances that it will be successful in its efforts.

In January 2008, the Tioga Preservation Group and two individuals (collectively, “TPG”) filed a land use appeal with the Tioga County Court of Common Pleas of Pennsylvania (“Common Pleas Court”) with respect to the Tioga County Planning Commission’s grant to AES Armenia Mountain Wind, LLC (“Armenia Mountain”)

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of preliminary approval for development of a wind project. Although the appeal is against the Tioga County Planning Commission, Armenia Mountain joined as an interested party. In August 2008, the Common Pleas Court entered an Opinion and Order denying TPG’s land use appeal with prejudice and affirming Armenia Mountain’s preliminary approval. In September 2008, TPG filed a Notice of Appeal with the Commonwealth Court of Pennsylvania. In October 2008, the Planning Commission notified Armenia Mountain that all of the conditions to the preliminary approval had been satisfied and that Armenia Mountain was authorized to start construction of the wind project. In March 2009, the Commonwealth Court denied TPG’s appeal, also affirming Armenia Mountain’s preliminary approval. In April 2009, TPG filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court asking it to review the Commonwealth Court’s order. In October 2009, the Pennsylvania Supreme Court denied the petition and declined to allow the appeal.

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 District Court granted in October 2009. The plaintiffs are expected to 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 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals that the environmental permit for Empresa Eléctrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant has stopped as a consequence of the Supreme Court’s decision. In September 2009, the Municipality of Puchuncaví issued an order to demolish the Plant on the basis of other permitting issues. In October 2009, EEC and AES Gener S.A. (“Gener”) filed a judicial claim against the Municipality of Puchuncaví before the Civil Judge of the City of Quintero, seeking to revoke the demolition order and asking for an immediate stay of said order. At the request of EEC and Gener, the Civil Judge of Quintero agreed to suspend the order until a final decision on the order is issued. EEC is working with Chilean authorities to attempt to find a solution that might allow the Plant’s construction to resume. EEC and the construction contractor are disputing which of them is responsible for the cause and consequences of the environmental and other permitting issues. If EEC is unable to complete the project, AES may be required to record an impairment of the Campiche project proportional to its indirect ownership, which could have a material impact on earnings in the period in which it is recorded. Based on cash investments through September 30, 2009 and potential termination costs, AES could incur an impairment of approximately $186 million. In the event an impairment charge is recognized with regard to the project, the amount of such impairment will depend on a number of factors, including EEC’s ability to recover project costs. In addition, Empresa Electrica Ventanas S.A. (“EEV”), a 270 MW gross coal plant under development in Ventanas, is reviewing the potential effects, if any, that the decision of the Supreme Court could have on the Nueva Ventanas project.

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 by the Appellate Court of the State of Sao Paulo in 2006 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

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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. The Public Attorney’s Office has filed appeals to both Superior Court of Justice (“SCJ”) and the Supreme Court (“SC”) and such appeals are to be answered by Eletropaulo before the end of the fourth quarter. 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 from the EPA regarding production levels and projects implemented at IPL’s generating stations. These types of information requests have been used in the past to assist EPA in determining whether a plant is in compliance with applicable standards under the CAA. The information request generally covered 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. IPL received a previous CAA Section 114 request in November 2000, seeking information about production levels and projects at IPL’s generating stations dating back to January 1, 1975. In October 2009, IPL received a Notice of Violation and Finding of Violation (“NOV”) from EPA pursuant to CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and New Source Review Requirements under the CAA. The letter accompanying the NOV offered IPL an opportunity to meet with EPA representatives to discuss the NOV. IPL will meet with EPA to discuss the NOV in the near future. IPL believes it has meritorious defenses to the allegations described in the NOV and will defend itself in any dispute vigorously; however, there can be no assurances that it will be successful in its efforts. At this time, it is not possible to predict the impact. If IPL’s defense is not successful, however, it is possible that IPL may face fines or be required to make capital expenditures in connection with the alleged violations, which could be material to the Company’s results of operations or financial position.

In November 2007, the U.S. Department of Justice (“DOJ”) notified 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 that occurred in 2006. 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 in a manner that is consistent with AES Thames’ historical method of operation. 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 prevail in the action.

In February 2009, a CAA Section 114 information request regarding Cayuga and Somerset was received. The request seeks various operating and testing data and other information regarding certain types of projects at

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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. Cayuga and Somerset responded to the EPA’s information request in June 2009, and they are awaiting a response from the EPA regarding their submittal. 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.

On February 2, 2009, the Cayuga facility received a Notice of Violation from the New York State Department of Environmental Conservation that the facility had exceeded the permitted volume limit of coal ash that can be disposed of in the on-site landfill. Cayuga has met with and submitted a demonstration plan to the agency and discussions between the parties are ongoing. Cayuga is awaiting a response from the New York State Department of Environmental Conservation. While at this time it is not possible to predict what impact, if any, this matter may have on Cayuga, its results of operation or its financial position, based upon the discussions to date, the Company does not believe the impact will be material.

In June 2009, the Inter-American Commission on Human Rights of the Organization of American States (“IACHR”) requested that the Republic of Panama suspend the construction of AES Changuinola S.A.’s hydroelectric project (“Project”) until the bodies of the Inter-American human rights system can issue a final decision on a petition (286/08) claiming that the construction violates the human rights of alleged indigenous communities. In July 2009, Panama responded by informing the IACHR that it would not suspend construction of the Project and requesting that the IACHR revoke its request. The IACHR will hear arguments by the communities and Panama on the merits of the petition on November 2, 2009. The Company cannot predict Panama’s response to any determination on the merits of the petition by the bodies of the Inter-American human rights system.

On July 30, 2009, AES Energía Cartagena S.R.L. (“AES Cartagena”) received a notice from the Spanish national energy regulator, Comisión Nacional de Energía (“CNE”), stating that it intends to invoice AES Cartagena for CO₂ allowances previously granted to AES Cartagena for 2007, 2008 and the first half of 2009. CNE alleges that generators selling into the electricity pool offered prices that included the costs of purchasing CO₂ allowances to offset their emissions, despite the fact that the generators were allegedly allocated free CO₂ allowances to cover some or all of those emissions. CNE’s notice asserts that AES Cartagena’s revenues should be reduced by roughly the amount of free CO₂ allowances allocated to AES Cartagena for 2007, 2008 and the first half of 2009, which CNE calculates as approximately €20 million ($29.2 million) for 2007-2008 and an amount to be determined for the first half of 2009. On September 17, 2009, AES Cartagena received invoices in an amount equal to €523,548 (approximately $764,000) for 2007 and €19,907,248 ($29 million) for 2008. AES Cartagena filed an administrative appeal against both such invoices with the Spanish Ministry of Industry on October 16, 2009 and has also applied for a stay of its obligation to pay the invoices pending the hearing of that appeal. There can be no assurance that this appeal or the application for a stay will be successful. In addition, AES Cartagena is seeking an indemnity in respect of these CNE invoices and any future such invoices from GDF-Suez under its long-term energy agreement (the “Energy Agreement”) with GDF-Suez, as further described below. AES Cartagena understands that CNE has sent notices to other generators, also alleging that they sold into the electricity pool at prices which reflected the cost of purchasing CO₂ allowances when they allegedly received free allowances. AES Cartagena does not sell electricity into the electricity pool, but instead, it provides electricity directly to GDF-Suez when requested by GFD-Suez to do so, subject to the terms of the Energy Agreement. AES Cartagena receives a fixed capacity payment from GDF-Suez under the Energy Agreement in return for keeping the plant available to run when requested. GDF-Suez then sells the electricity provided by AES Cartagena directly into the electricity pool and GDF-Suez receives all of the revenue associated with such sales into the electricity pool. Accordingly, for these and other reasons, AES Cartagena believes that GDF-Suez is contractually required to bear the costs associated with any invoices from CNE. However, GDF-Suez has disputed that it is liable under the Energy Agreement for the CNE invoices and other CO₂ emissions related costs. Therefore, AES Cartagena is seeking an indemnity in respect of the CNE payments and other CO₂ emissions-related costs from GDF-Suez. Formal dispute resolution proceedings were initiated against GDF-Suez on

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September 2, 2009 relating to, among other things, the CNE invoices and the responsibility for procuring and cost of procuring CO₂ emissions allowances. AES Cartagena believes it has meritorious claims and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 2009, the Public Defender’s Office of the State of Rio Grande do Sul filed a class action against AES Sul in Brazilian state court claiming that AES Sul has been illegally passing PIS and COFINS taxes (taxes based on AES Sul’s income) to consumers. AES Sul has not been officially served with the action. According to ANEEL’s Order No. 93/05, the federal laws of Brazil, and the Brazilian Constitution, energy companies such as AES Sul are entitled to highlight PIS and COFINS taxes in power bills to final consumers, as the cost of those taxes is included in the energy tariffs that are applicable to final consumers. Nevertheless, if AES Sul does not prevail in the litigation and is ordered to cease recovering PIS and COFINS taxes pursuant to its energy tariff, its potential prospective losses could be approximately R$9.6 million ($5.4 million) per month, as estimated by AES Sul. In addition, if AES Sul is ordered to reimburse consumers, its potential retrospective liability could be approximately R$1.2 billion ($672 million), as estimated by AES Sul. AES Sul believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings if it is served with the action; however, there can be no assurances that it would be successful in its efforts. Furthermore, if AES Sul does not prevail in the litigation it will seek to adjust its energy tariff to compensate it for its losses, but there can be no assurances that it would be successful in obtaining an adjusted energy tariff.

In September 2009, IPL received a letter from the staff of the IURC relevant to the IURC’s periodic review of IPL’s basic rates and charges which expressed concerns about IPL’s level of earnings and invited IPL to provide additional information. In response, IPL provided information to the staff of the IURC. It is not possible to predict what impact, if any, the IURC’s review may have on IPL.

9. PENSION PLANS

Total pension cost for the three and nine months ended September 30, 2009 and 2008 included the following components:

	Three Months Ended September 30,												Nine Months Ended September 30,
	2009						2008						2009						2008
	U.S.			Foreign			U.S.			Foreign			U.S.			Foreign			U.S.			Foreign
	(in millions)
Service cost	$	2		$	4		$	1		$	3		$	6		$	10		$	4		$	10
Interest cost		8			123			8			121			25			334			24			365
Expected return on plan assets		(7	)		(100	)		(8	)		(108	)		(20	)		(271	)		(25	)		(328	)
Amortization of initial net asset		-			(1	)		-			-			-			(2	)		-			(2	)
Amortization of prior service cost		1			-			1			-			3			-			2			-
Amortization of net loss		4			2			1			-			12			5			2			2
Total pension cost	$	8		$	28		$	3		$	16		$	26		$	76		$	7		$	47

Total employer contributions for the nine months ended September 30, 2009 for the Company’s U.S. and foreign subsidiaries were $16 million and $133 million, respectively. The expected remaining scheduled annual employer contributions for 2009 are $5 million for U.S. subsidiaries and $21 million for foreign subsidiaries. As of September 30, 2009, the depreciation of the U.S. Dollar compared to the Brazilian Real (“BRL”) resulted in an increase of $18 million in the Company’s estimate of total remaining expected 2009 employer contributions for foreign subsidiaries when translated into the U.S. Dollar. This increase is entirely due to the change in the exchange rate used to translate the BRL, the local currency, to a U.S. Dollar estimate of expected future contributions. The expected contributions, which will be made in BRL, remain unchanged.

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10. COMPREHENSIVE INCOME (LOSS)

The components of comprehensive income (loss) for the three and nine months ended September 30, 2009 and 2008 were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in millions)
Net income	$	440		$	359		$	1,472		$	1,927
Change in fair value of available-for-sale securities, net of income tax (expense) benefit of $(4), $—, $(4) and $1, respectively		6			-			6			(1	)
Foreign currency translation adjustments, net of income tax (expense) benefit of $(19), $33, $(51) and $17, respectively		221			(640	)		554			(350	)
Derivative activity:
Reclassification to earnings, net of income tax benefit of $12, $4, $38 and $14, respectively		10			-			(33	)		-
Change in derivative fair value, net of income tax benefit (expense) of $16, $(139), $(53) and $(45), respectively		(91	)		192			95			46
Total change in fair value of derivatives		(81	)		192			62			46
Change in unfunded pension obligation, net of income tax (expense) benefit of $—, $(11), $(1) and $1, respectively		-			9			2			(2	)
Other comprehensive income (loss)		146			(439	)		624			(307	)
Comprehensive income (loss)		586			(80	)		2,096			1,620
Less: Comprehensive (income) loss attributable to noncontrolling interests (1)		(409	)		157			(1,227	)		(461	)
Comprehensive income attributable to The AES Corporation	$	177		$	77		$	869		$	1,159

(1) Reflects the income (loss) attributed to noncontrolling interests in the form of common securities and dividends on preferred stock of subsidiary.

The components of accumulated other comprehensive loss as of September 30, 2009 were as follows:

	(in millions)
Foreign currency translation adjustment	$	2,466
Unrealized derivative losses		226
Unfunded pension obligation		169
Securities available for sale		(6	)
Accumulated other comprehensive loss as of September 30, 2009	$	2,855

11. SEGMENTS

As further described below, beginning with the Company’s Form 10-Q for the quarterly period ended March 31, 2009 filed with the SEC on May 8, 2009, the Company modified its segment reporting in accordance with the relevant guidance.

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On September 14, 2009, the Company filed the September 2009 Form 8-K to recast previously filed financial statements included in the Company’s 2008 Form 10-K to reflect, among other things, the effect of changes to the Company’s reportable segments for all periods presented therein.

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. The new management reporting structure continues to be organized along our two lines of business, 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 with our North America region while climate solutions projects are now managed in the region in which they are located. Key climate solutions initiatives include investments in GHG initiatives, projects to create emissions offsets for the voluntary U.S. market and projects that produce certified emission reduction credits (“CERs”). Despite the management of these climate solution initiatives within the different geographic regions, these businesses do not meet the aggregation criteria to be combined into the respective region’s Generation or Utilities segments and continue to be reported as part of “Corporate and Other”. AES Solar is accounted for using the equity method of accounting and continues to be reflected in “Corporate and Other.” 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 which is reflected in “Corporate and Other”.

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 segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and the Company concluded that it now has six reportable segments. This new segment structure was reflected in the September 2009 Form 8-K and the Forms 10-Q for the quarterly periods ended March 31 and June 30, 2009. 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 segment reporting accounting guidance. 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 criteria to allow for aggregation with another operating segment or quantitative thresholds for separate disclosure.

Therefore, as a result of this analysis, the Company now reports 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” includes the operations for the Company’s Europe Utilities, Africa Utilities and Africa Generation businesses, AES Wind and climate solutions initiatives. AES Solar is

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accounted for under the equity method of accounting, therefore its operating results are included in “Net Equity in Earnings of Affiliates” on the face of the condensed consolidated statements of operations, not in the revenue and gross margin measures for “Corporate and Other” reflected in this Form 10-Q. None of these operations are currently material to our presentation of reportable segments, individually or in the aggregate. “Corporate and Other” also includes development and operational costs related to the development group and other intercompany charges, such as self-insurance premiums, which are fully eliminated in consolidation.

The Company uses multiple measures to evaluate the performance of its segments. The GAAP measure that most closely aligns with the Company’s internal performance measures is gross margin. Gross margin is defined as total revenue less operating expenses including depreciation and amortization, local fixed operating and other overhead costs. 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. 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.

Information about the Company’s operations by segment for the three and nine months ended September 30, 2009 and 2008 was as follows:

	Total Revenue						Inter-segment						External Revenue
Three Months Ended September 30,	2009			2008			2009			2008			2009		2008
	(in millions)
Latin America–Generation	$	1,008		$	1,195		$	(248	)	$	(285	)	$	760	$	910
Latin America–Utilities		1,672			1,604			-			-			1,672		1,604
North America–Generation		486			616			-			-			486		616
North America–Utilities		266			288			-			-			266		288
Europe–Generation		157			262			-			-			157		262
Asia–Generation		291			372			-			-			291		372
Corporate and Other		(42	)		(18	)		248			285			206		267
Total Revenue	$	3,838		$	4,319		$	-		$	-		$	3,838	$	4,319
	Total Revenue						Inter-segment						External Revenue
Nine Months Ended September 30,	2009			2008			2009			2008			2009		2008
	(in millions)
Latin America–Generation	$	2,794		$	3,578		$	(634	)	$	(795	)	$	2,160	$	2,783
Latin America–Utilities		4,253			4,644			-			-			4,253		4,644
North America–Generation		1,463			1,705			-			-			1,463		1,705
North America–Utilities		817			804			-			-			817		804
Europe–Generation		513			834			-			-			513		834
Asia–Generation		875			985			-			-			875		985
Corporate and Other		(4	)		(24	)		634			795			630		771
Total Revenue	$	10,711		$	12,526		$	-		$	-		$	10,711	$	12,526

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	Total Gross Margin				Inter-segment						External Gross Margin
Three Months Ended September 30,	2009		2008		2009			2008			2009		2008
	(in millions)
Latin America–Generation	$	388	$	385	$	(252	)	$	(281	)	$	136	$	104
Latin America–Utilities		294		246		247			291			541		537
North America–Generation		104		147		(5	)		6			99		153
North America–Utilities		65		81		-			2			65		83
Europe–Generation		34		40		-			3			34		43
Asia–Generation		71		37		(1	)		2			70		39
Corporate and Other		52		26		11			(23	)		63		3
Total Gross Margin	$	1,008	$	962	$	-		$	-		$	1,008	$	962
	Total Gross Margin				Inter-segment						External Gross Margin
Nine Months Ended September 30,	2009		2008		2009			2008			2009		2008
	(in millions)
Latin America–Generation	$	1,095	$	1,103	$	(625	)	$	(781	)	$	470	$	322
Latin America–Utilities		640		725		634			801			1,274		1,526
North America–Generation		346		549		12			17			358		566
North America–Utilities		186		194		2			3			188		197
Europe–Generation		128		219		2			3			130		222
Asia–Generation		195		125		3			4			198		129
Corporate and Other		148		118		(28	)		(47	)		120		71
Total Gross Margin	$	2,738	$	3,033	$	-		$	-		$	2,738	$	3,033

Assets by segment as of September 30, 2009 and December 31, 2008 were as follows:

	Total Assets
	September 30, 2009		December 31, 2008
	(in millions)
Latin America–Generation	$	9,785	$	8,228
Latin America–Utilities		8,912		7,267
North America–Generation		6,328		6,426
North America–Utilities		3,080		3,093
Europe–Generation		2,929		2,656
Asia–Generation		3,090		3,239
Corporate and Other		5,137		3,897
Total Assets	$	39,261	$	34,806

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12. OTHER INCOME (EXPENSE)

The components of other income for the three and nine months ended September 30, 2009 and 2008 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(in millions)
Gain on sale of assets	$	5	$	23	$	13	$	27
Tax credit settlement		-		-		129		-
Management performance incentive		-		-		80		-
Gain on extinguishment of liabilities		-		-		3		124
Other		30		40		54		107
Total other income	$	35	$	63	$	279	$	258

Other income generally includes gains on asset sales and extinguishments of liabilities, favorable judgments on contingencies and other income from miscellaneous transactions.

Other income of $35 million for the three months ended September 30, 2009 included the reversal of contingencies at Sonel in Cameroon and Sul in Brazil, a gain on sale of assets at Placerita, and the reversal of tax liabilities at Altai. Other income of $63 million for the three months ended September 30, 2008 included $29 million of cash proceeds received by AES Southland in California for a settlement, $23 million of gains associated with a sale of land at Eletropaulo in Brazil and the sale of turbines at Itabo in the Dominican Republic.

Other income of $279 million for the nine months ended September 30, 2009 included a favorable court decision in which Eletropaulo had requested reimbursement for excess non-income taxes paid from 1989 to 1992. Eletropaulo received reimbursement in the form of tax credits 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 14 — Acquisitions and Dispositions. Other income also included $9 million of insurance proceeds at Uruguaiana in Brazil and Andres in the Dominican Republic. Other income of $258 million for the nine months ended September 30, 2008 included income from the above mentioned settlement and sales of assets, as well as a $117 million gain related to the extinguishment of a non-income tax liability at Eletropaulo, insurance recoveries of $14 million for damaged turbines at Uruguaiana, and $14 million of compensation received from the local government for the impairment of plant assets and cessation of the power purchase agreement associated with a settlement agreement to shut down the Hefei generation facility in China.

The components of other expense for the three and nine months ended September 30, 2009 and 2008 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(in millions)
Loss on sale and disposal of assets	$	6	$	10	$	20	$	25
Loss on extinguishment of debt		-		1		-		70
Other		9		7		47		33
Total other expense	$	15	$	18	$	67	$	128

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Other expense generally includes losses on asset sales, losses on the extinguishment of debt, legal contingencies and losses from other miscellaneous transactions.

Other expense of $15 million for the three months ended September 30, 2009 included losses on the disposal of assets at Eletropaulo and contingencies at Alicura in Argentina. Other expense of $18 million for the three months ended September 30, 2008 was primarily comprised of losses on disposal of assets.

Other expense of $67 million for the nine months ended September 30, 2009 included a $13 million loss recognized when three of our businesses in the Dominican Republic received $110 million par value bonds issued by the Dominican Republic government to settle existing accounts receivable for the same amount from the government-owned distribution companies. The loss represented an adjustment to reflect the fair value of the bonds on the date received. Other expense also included losses on the disposal of assets at Eletropaulo and Andres and contingencies at Altai and Alicura. Other expense of $128 million for the nine months ended September 30, 2008 included $69 million of losses related to the extinguishment of debt at the Parent Company in connection with a refinancing in June 2008 and the refinancing of $375 million of debt by IPALCO Enterprises, Inc. (“IPALCO”) in April 2008, as well as contingencies and losses on disposal of assets.

13. DISCONTINUED OPERATIONS

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.

The following table summarizes the revenue, income tax expense, income from operations of the discontinued businesses and loss on the disposal of discontinued businesses for the three and nine months ended September 30, 2008:

	Three Months Ended September 30, 2008			Nine Months Ended September 30, 2008
	(in millions)
Revenue	$	26		$	69
Income from operations of discontinued businesses	$	(2	)	$	1
Income tax benefit		-			-
Income from operations of discontinued businesses, net of tax	$	(2	)	$	1
Loss on disposal of discontinued operations	$	-		$	(1	)

14. 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.

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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. This was recognized as “Other Income” in the Company’s condensed consolidated statement of operations during the first quarter of 2009. The cash was received by the Company in April 2009. A $13 million gain was recognized 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 first quarter of 2009.

The 2009 agreement also provided for an additional $102 million payment, primarily related to the termination of the management agreement, payable to AES in January 2010. In May 2009, Kazakhmys provided an irrevocable standby letter of credit from a credit worthy institution to AES of $102 million to secure the final payment. The payment of the final component of the management termination agreement is not contingent upon any future events. As a result, the Company recognized an additional gain on the sale of Ekibastuz and Maikuben of approximately $98.5 million in the second quarter of 2009.

The parties agreed to terminate both the Stock Purchase Agreement and the Management Agreement, and have further agreed to a mutual release of prior claims. As part of the management termination agreement, AES agreed to transition the management of the businesses to Kazakhmys over a period of 100 days from March 13, 2009. The transition period ended June 21, 2009 and at that time the management of Ekibastuz and Maikuben became the responsibility of Kazakhmys. The Company’s involvement with the businesses remained 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 for all periods presented, despite the termination of the management agreement.

Excluding income earned under the three-year management and operation agreement (terminated in March 2009), Ekibastuz and Maikuben generated no revenue in 2009 and the three months ended September 30, 2008, and generated revenue of $103 million for the nine months ended September 30, 2008.

15. 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.

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The following table presents a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation for income from continuing operations for the three and nine months ended September 30, 2009 and 2008. In the table below income represents the numerator and weighted-average shares represent the denominator:

	Three Months Ended September 30,
	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	$	185	667	$	0.28	$	147	669	$	0.22
EFFECT OF DILUTIVE SECURITIES
Convertible securities		-	-		-		-	-		-
Stock options		-	2		-		-	4		-
Restricted stock units		-	2		-		-	2		-
DILUTED EARNINGS PER SHARE	$	185	671	$	0.28	$	147	675	$	0.22
	Nine Months Ended September 30,
	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	$	706	666	$	1.06	$	1,281	671	$	1.91
EFFECT OF DILUTIVE SECURITIES
Convertible securities		-	-		-		16	15		(0.04	)
Stock options		-	2		-		-	5		-
Restricted stock units		-	1		-		-	2		-
DILUTED EARNINGS PER SHARE	$	706	669	$	1.06	$	1,297	693	$	1.87

There were approximately 18,380,626 and 9,221,476 additional options outstanding at September 30, 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 September 30, 2009 and 2008, and the nine months ended September 30, 2009, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. For the nine months ended September 30, 2008, all convertible debentures were included in the earnings per share calculation as their impact was dilutive. During the nine months ended September 30, 2009, 2,096,389 shares of common stock were issued under the Company’s profit sharing plan and 598,871 shares of common stock were issued upon the exercise of stock options.

16. ACCOUNTS RECEIVABLE SECURITIZATION

IPL, a consolidated subsidiary of the Company, formed IPL Funding Corporation (“IPL Funding”) in 1996 as a special purpose entity to purchase, on a revolving basis, the receivables originated by IPL. IPL Funding is a qualified special purpose entity and is consolidated by IPL and IPALCO. IPL Funding entered into a sale facility with unrelated parties (“the Purchasers”) pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, interests in the pool of receivables purchased from IPL up to the lesser of (1) an amount

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determined pursuant to the sale facility that takes into account certain eligibility requirements and reserves relating to the receivables, or (2) $50 million. During the second quarter of 2009, this agreement was extended through May 25, 2010. Accounts receivable on the Company’s condensed consolidated balance sheets are stated net of the $50 million sold and include $63 million and $87 million as of September 30, 2009 and December 31, 2008, respectively, related to IPL Funding’s accounts receivable.

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

The carrying values of the retained interests are determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value. The key assumptions in estimating fair value are credit losses, the selection of discount rates and expected receivables turnover rate. The hypothetical effect on the fair value of the retained interests assuming both a 10% and a 20% unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history.

The losses recognized on the sales of receivables were $0.3 million and $0.5 million for the three months ended September 30, 2009 and 2008, respectively, and $0.9 million and $1.5 million for the nine months ended September 30, 2009 and 2008, respectively. These losses are included in other expense on the condensed consolidated statements of operations. The amount of the losses recognized depends on the previous carrying amount of the financial assets involved in the transfer, allocated between the assets sold and the interests that continue to be held by the transferor based on their relative fair value at the date of transfer, and the proceeds received.

There were no proceeds from new securitizations for each of the three and nine months ended September 30, 2009 and 2008. IPL Funding pays IPL annual service fees totaling $1 million, which is financed by capital contributions from IPL to IPL Funding.

The following table shows the receivables sold and retained interests as of September 30, 2009 and December 31, 2008:

	September 30, 2009		December 31, 2008
	(in millions)
Receivables at IPL Funding	$	113	$	137
Less: Retained interests		63		87
Net receivables sold	$	50	$	50

The following table shows the cash flows for the periods ended September 30, 2009 and 2008:

	Nine Months Ended September 30,
	2009		2008
	(in millions)
Cash proceeds from interest retained	$	450	$	442
Cash proceeds from sold receivables	$	338	$	297

IPL and IPL Funding provide certain indemnities to the Purchasers, including indemnification in the event that there is a breach of representations and warranties made with respect to the purchased receivables. IPL

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Funding and IPL each have agreed to indemnify the Purchasers on an after-tax basis for any and all damages, losses, claims, liabilities, penalties, taxes, costs and expenses at any time imposed on or incurred by the indemnified parties arising out of, or otherwise relating to, the sale facility, subject to certain limitations as defined in the sale facility.

Under the sale facility, if IPL fails to maintain certain financial covenants including, but not limited to interest coverage and debt to capital ratios, it would constitute a “termination event.” As of September 30, 2009, IPL was in compliance with such covenants. In the event that IPL’s credit rating falls below a threshold identified in the sale facility, the facility agent has the ability to replace IPL as the collection agent and declare a “lock-box” event. Under a lock-box event or a termination event, the facility agent has the ability to require all proceeds of purchased receivables of IPL to be directed to lock-box accounts within 45 days of notifying IPL. In addition, a termination event would also give the facility agent the option to take control of the lock-box account, give the Purchasers the option to discontinue the purchase of new receivables, and require all proceeds to be used to reduce the Purchaser’s investment and pay other amounts owed to the Purchasers and the facility agent. This could reduce the operating capital available to IPL by the aggregate amount of any purchased receivables up to $50 million.

17. SUBSEQUENT EVENTS

On October 7, 2009, the Parent Company voluntarily reduced all of the remaining commitments available under the senior unsecured credit facility and terminated the facility agreement. See further discussion in Note 7 — Long-Term Debt — Recourse Debt.

Subsequent events have been evaluated through the date of issuance of this Form 10-Q.

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

In this Quarterly Report on Form 10-Q “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.

On September 14, 2009, The AES Corporation filed a Current Report on Form 8-K (“September 2009 Form 8-K”) to recast previously filed financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 (“2008 Form 10-K”) to reflect the effect of changes to the Company’s reportable segments and the adoption of the presentation and disclosure provisions of new accounting guidance for noncontrolling interests, which required retrospective presentation and became effective for the Company on January 1, 2009. The revisions to the 2008 Form 10-K were limited to the Company’s Business Overview, Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and Notes contained in Items 1, 6, 7 and 8. All other information in the 2008 Form 10-K remained unchanged.

The condensed consolidated financial statements included in Item 1. — Financial Statements of this Form 10-Q and the discussions contained herein should be read in conjunction with our 2008 Form 10-K and the September 2009 Form 8-K.

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 Item 1A. — 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.

OVERVIEW OF OUR BUSINESS

We are a global power company. 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. The Utilities line of business also includes our integrated utilities that both distribute and generate electricity. 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 renewable projects in solar and climate solutions. These initiatives are not material contributors to our operating results, but we believe that they may become material in the future.

Our Company is organized along our two lines of businesses in three regions: (1) Latin America & Africa; (2) North America and AES Wind Generation; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. AES Wind Generation is managed as part of our North America region while

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climate solutions projects are managed in the region in which they are located. With certain exceptions, the Company manages development efforts centrally through a development group.

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, reliability and efficiency, management of fixed and variable operating costs, management of working capital including collection of receivables, 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 current market price of electricity and the marginal costs of production that are not passed through to the off taker. Growth in our Generation business is largely tied to securing new power purchase agreements (“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 including collection of receivables, and in developing countries, reduction of commercial and technical losses. The operating results of our Utilities businesses are sensitive to changes in economic growth and weather conditions in the areas in which they operate. In addition to these drivers as explained below, the Company also has exposure to currency exchange rate fluctuations.

One of the key factors which affects our Generation business is our ability to enter into long-term contracts for the sale of electricity and the costs to purchase fuel used to produce that electricity. Long-term contracts are intended to reduce the exposure to volatility associated with fuel prices in the market and the price of electricity by fixing the revenues and costs for these businesses. The majority of the electricity produced by our Generation businesses is sold under long-term contracts, or PPAs, to wholesale customers. In turn, most of these businesses enter 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. While these long-term contractual agreements reduce exposure to volatility in the market price for electricity and fuel, the predictability of operating results and cash flow vary by business based on the extent to which a facility’s generation capacity and fuel requirements are contracted and the negotiated terms of these agreements.

When fuel costs increase, many of our businesses are able to pass these costs on to their customers. Generation businesses with long-term contracts in place do this by including fuel pass-through or fuel indexing arrangements in their contracts. Utilities businesses can pass costs on to their customers through increases in current or future tariff rates. Therefore, in a rising fuel cost environment, the increased fuel costs for these businesses often result in an increase in revenue to the extent these costs can be passed through (though not necessarily on a one-for-one basis). Conversely, in a declining fuel cost environment, the decreased fuel costs can result in a decrease in revenue. Increases or decreases in revenue at these businesses that have the ability to pass through costs to the customer have a corresponding impact on cost of sales, to the extent the costs can be passed through, resulting in a limited impact on gross margin, if any. Although these circumstances may not have a large impact on gross margin, they can significantly affect gross margin as a percentage of revenue. As a result, gross margin as a percentage of revenue is a less relevant measure when evaluating our operating performance.

Diversification also helps us to mitigate some operational risks. Our portfolio employs a broad range of fuels, including coal, gas, fuel oil and renewable sources such as hydroelectric power, wind and solar, which reduce 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 associated with that debt. However, we only hedge a portion of our currency and 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

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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.” Continued commodity and power price volatility could impact our financial metrics to the extent this volatility is not hedged. For example, as further discussed in Item 3. — Quantitative and Qualitative Disclosure About Market Risk — Commodity Price Risk, we estimate that a 10% decline in power prices at our U.S. operations alone would result in an estimated reduction in gross margin of $2 million.

Due to our global presence, the Company has significant exposure to foreign currency fluctuations. The exposure is primarily associated with the impact of the translation of our foreign subsidiaries operating results from their local currency to U.S. dollars that is required for the preparation of our consolidated financial statements. Additionally, there is risk of transaction exposure when an entity enters into transactions, including debt agreements, in currencies other than their functional currency. These risks are further described in the 2008 Form 10-K, Item 1A. — Risk Factors, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.” To date in 2009, changes in foreign currency exchange rates have had a significant impact on our operating results. In the third quarter of 2009, our gross margin increased $46 million compared to the same period last year. The increase included the unfavorable impact of $79 million due to changes in foreign currency exchange rates. In the first nine months of 2009, our gross margin declined $295 million compared to the same period last year, of which $316 million was due to unfavorable changes in foreign currency exchange rates. If the current foreign currency exchange rate volatility continues, our gross margin and other financial metrics could be adversely affected.

Another key driver of our results is our ability to bring new businesses into commercial operations successfully. We currently have an aggregate of 2,727 MW of projects under construction in nine countries. Our prospects for increases in operating results and cash flows are dependant upon successful completion of these projects on time and within budget. However, as disclosed in the 2008 Form 10-K, Item 1A. — Risk Factors, “Our business is subject to substantial development uncertainties,” construction is subject to a number of risks, including risks associated with siting, financing and permitting and our ability to meet construction deadlines. Delays or the inability to complete projects and commence commercial operations can result in increased costs, impairment of assets and other challenges involving partners and counterparties to our construction agreements, PPAs, and other agreements.

Our gross margin is also impacted by the fact that in each country in which we conduct business, we are subject to extensive and complex governmental regulations such as regulations governing the generation and distribution of electricity, and environmental regulations which affect most aspects of our business. Regulations differ on a country by country basis (and even at the state and local municipality levels) and are based upon the type of business we operate in a particular country, and affect many aspects of our operations and development projects. Our ability to negotiate tariffs, enter into long-term contracts, pass through capital expenditures and otherwise navigate these regulations can have an impact on our revenues, costs and gross margin. While not currently material to our operations, environmental and land use regulations, including proposed regulation of carbon emissions, could substantially increase our capital expenditures or other compliance costs, which could in turn have a material adverse affect on our business and results of operations. For a further discussion of the Regulatory Environment in the condensed consolidated financial statements, see Note 8 — Contingencies and Commitments — Environmental, included in Item 1. — Financial Statements of this Form 10-Q and our 2008 Form 10-K, Item 1. — Business — Regulatory Matters — Environmental and Land Use Regulations and Item 1A. — Risk Factors — Risks Associated with Government Regulation and Laws.

Other factors that can affect our financial results include gains and losses from the sale of businesses, incurrence and release of legal/regulatory/tax reserves and asset impairment.

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Key Drivers of Results in the Third Quarter

For the third quarter of 2009, the Company increased its gross margin, net income attributable to The AES Corporation and net cash provided by operating activities. Our results of operations were impacted by factors including:

• the unfavorable impact of foreign currency translation losses on our international business operations;

• lower fuel prices, which led to lower electricity prices and had a negative impact at our generation plants in New York, but benefited gross margin at our generation plants in Chile; and

• improved operating performance and working capital management at certain of our businesses in Latin America and Asia.

To address and mitigate the challenges faced by the Company this quarter, we were able to partially offset the impact of unfavorable factors on revenue and gross margin through fuel and geographic diversification, operational improvements at certain businesses and asset recoveries. An example of where lower spot electricity prices benefited the Company took place at our generation business operating in the central Chilean market. A decrease in contract and spot market rates contributed to lower revenue. However, gross margin improved as we were able to fulfill our obligations under electricity contracts with purchased energy rather than producing energy from less efficient plants in our portfolio.

During the quarter we also experienced a significant increase in net cash provided by operating activities compared to the third quarter of 2008. Much of the increase was attributable to the Company’s working capital management, which includes among other things, the timing of inventory procurement and usage; collection of accounts receivable and payments to vendors. In the third quarter, working capital management efforts included the recovery of a municipal receivable that had previously been written off at one of our utility businesses in Brazil. The recovery of the receivable was also reflected in gross margin; absent this recovery, gross margin for the Company would have decreased for the quarter.

Although management will continue to seek ways to mitigate the impact of adverse factors on its operations, we expect certain of the unfavorable factors described above may continue to present challenges to maintaining our operating results. Therefore we can provide no assurances regarding management’s ability to mitigate the effect of these adverse factors, or that the quarterly increase in gross margin, net income attributable to The AES Corporation and net cash flow from operating activities as experienced in the quarter ended September 30, 2009 will continue in future periods.

The following briefly describes the key fluctuations in our reported revenues, gross margin, net income attributable to The AES Corporation and net cash provided by operating activities for the three and nine months ended September 30, 2009 compared to 2008 and should be read in conjunction with our Consolidated Results of Operations and Segment Analysis discussion within our Management’s Discussion and Analysis.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009		2008		% Change		2009		2008		% Change
	($’s in millions, except per share amounts)						($’s in millions, except per share amounts)
Revenue	$	3,838	$	4,319	-11	%	$	10,711	$	12,526	-14	%
Gross margin	$	1,008	$	962	5	%	$	2,738	$	3,033	-10	%
Net income attributable to The AES Corporation	$	185	$	145	28	%	$	706	$	1,281	-45	%
Net cash provided by operating activities	$	1,028	$	803	28	%	$	1,899	$	1,587	20	%

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Our third quarter financial results include the following highlights:

Three months ended September 30, 2009:

Revenue decreased $481 million, or 11%, to $3.8 billion for the three months ended September 30, 2009 compared with the same period in 2008. Key drivers of the decrease included:

• the unfavorable impact of foreign currency of $367 million, largely driven by the Brazilian Real;

• decreases in volume at Uruguaiana in Brazil, as a result of a renegotiation of its power sales agreements in 2009 to reduce the energy volume sold, in New York and Hungary and lower dispatch in Northern Ireland due to unfavorable gas prices compared to coal;

• the impact of lower spot and contract prices at our generation business in Chile;

• the unfavorable impact of mark-to-market derivative adjustments on certain commodity contracts in North America and Chile; and

• partially offset by an increase in tariff rates in Brazil primarily reflecting the recovery of energy purchases that were passed through to our customers at our utilities businesses in Latin America.

Gross margin increased $46 million, or 5%, to $1.0 billion for the three months ended September 30, 2009 compared with the same period in 2008. Key drivers of the increase included:

• improved operating performance at our generation businesses in Chile and the Philippines;

• bad debt recoveries in Brazil;

• partially offset by the unfavorable impact of foreign currency of $79 million; and

• lower volume in New York due to lower spot market rates.

Net income attributable to The AES Corporation increased $40 million, or 28%, to $185 million for the three months ended September 30, 2009 compared with the same period in 2008. The increase was primarily attributable to the following:

• improvements in gross margin for the quarter as described above;

• a decrease in foreign currency transaction losses on net monetary positions as a result of strengthening of the Euro, British Pound, Philippine Peso and Chilean Peso;

• partially offset by an increase in income tax expense as a result of higher net income; and

• an increase in net income attributable to noncontrolling interests primarily as a result of increased earnings at certain of our businesses in Brazil and Chile.

Net cash provided by operating activities increased $225 million, or 28% to $1 billion for the three months ended September 30, 2009 compared to the same period in 2008 primarily due to the following:

• an increase of $114 million at our Latin American Generation businesses due to improved working capital;

• an increase of $85 million at IPALCO, which is the holding company for IPL in North America primarily due to improved working capital;

• an increase of $84 million at our Asia Generation businesses due to improved operating performance;

• a $62 million recovery of a municipal receivable at Eletropaulo; and

• partially offset by a decrease of $80 million at our North America Generation businesses, primarily due to reduced operating results.

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Nine months ended September 30, 2009:

Revenue decreased $1.8 billion, or 14%, to $10.7 billion for the nine months ended September 30, 2009 compared with the same period in 2008. The key drivers of the decrease included:

• the unfavorable impact of foreign currency of $1.5 billion, largely driven by the Brazilian Real;

• decreases in volume at Uruguaiana due to the renegotiation of its power sales agreements in 2009 to reduce the energy volume sold, in New York and Hungary and lower dispatch in Northern Ireland due to unfavorable gas prices compared to coal;

• the impact of lower spot and contract energy prices at our generation business in Chile; and

• partially offset by an increase in tariff rates in Latin America primarily reflecting the recovery of energy purchases that were passed through to our customers at our utilities businesses.

Gross margin decreased $295 million, or 10%, to $2.7 billion for the nine months ended September 30, 2009 compared with the same period in 2008. Key drivers of the net decrease included:

• unfavorable impact of foreign currency of $316 million, largely driven by the Brazilian Real;

• the unfavorable impact of mark-to-market derivative adjustments on certain commodity contracts in North America and Chile;

• lower volume in New York due to lower spot market rates;

• partially offset by improved operating performance at our generation businesses in Chile and the Philippines; and

• bad debt recoveries and a reduction in bad debt expense in Brazil.

Net income attributable to The AES Corporation decreased $575 million, or 45%, to $706 million for the nine months ended September 30, 2009 compared with the same period in 2008. This net decrease was primarily attributable to the following:

• a gain recognized in 2008 from the sale of two wholly-owned subsidiaries in Northern Kazakhstan partially offset by a performance incentive bonus recognized in 2009 for management services provided to these subsidiaries and a termination of the management agreement in 2009;

• the reduction in gross margin in 2009 as described above;

• an increase in net income attributable to noncontrolling interests due to higher earnings at our businesses in Chile, Pakistan, the Philippines and Sonel in Cameroon;

• partially offset by a reduction in foreign currency transaction losses on net monetary position as a result of reduced losses at our businesses in Chile and the Philippines;

• a reduction in interest expense due primarily to lower interest rates and debt balances in Brazil and favorable foreign currency translation;

• lower impairment charges in 2009 compared to 2008; and

• lower income tax expenses as a result of lower consolidated net income in 2009.

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In 2008, the $908 million gain recognized on the sale of our two Northern Kazakhstan businesses had a significant impact on net income attributable to The AES Corporation. In 2009, the Company recognized a performance incentive bonus of $80 million in the first quarter for management services provided to these sold businesses, reflected as other income. Additionally, in the second quarter of 2009, the Company recognized an additional gain on the sale of the businesses of $98.5 million upon the termination of the management agreement. However, while the Company engages in the sale of assets and businesses from time to time, the gain or loss recognized in any such sale will depend on a number of factors related to the asset or business that may be sold. The Company does not expect that the decline in net income between 2008 and 2009 will continue in future periods.

Net cash provided by operating activities for the nine months ended September 30, 2009 increased $312 million, or 20%, to $1.9 billion compared with $1.6 billion for the same period in 2008. This increase was primarily due to improvements in working capital and a decrease in net regulatory assets. Please refer to Cash Flows — Operating Activities for further discussion.

Management’s Priorities

Management continues to focus on the following priorities:

• Maintaining sufficient liquidity as further described in Liquidity and Capital Resources described below.

• Improvement of operations in the existing portfolio.

• Completion of more than 2,500 MW construction program on time and within budget. During the second quarter, the Company stopped construction on its Campiche Plant, as further described in Key Trends and Uncertainties — Operational Challenges below.

• Maximizing the use of cash, including establishment of low-cost development options, reducing debt, stock repurchases and increasing cash balances.

• Integration of new projects. During the quarter the following projects commenced commercial operations:

Project	Location	Fuel	Gross MW	AES Equity Interest (Percent, Rounded)
Amman East	Jordan	Gas	380	37	%
Guacolda (1)	Chile	Coal	152	35	%
Huanghua (2)	China	Wind	49.5	49	%

⁽¹⁾ Guacolda is an equity method investment indirectly held by AES through Gener. The AES equity interest reflects the 29% noncontrolling interests in Gener.

⁽²⁾ Huanghua is an equity method investment of AES.

This year we have completed construction of six projects totaling approximately 800 MW. In addition to the projects named above, the 80 MW Kilroot peaker expansion in Northern Ireland, 16 MW of Innovent wind projects in France and the 130 MW Santa Lidia diesel facilities in Chile all entered commercial operation during 2009.

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Key Trends and Uncertainties

Operational Challenges

Our operations continue to face many risks as previously discussed in the Company’s 2008 Form 10-K, Item 1A. — Risk Factors. We continue to monitor our operations and address challenges as they arise.

As previously discussed in the Company’s 2008 Form 10-K, Item 1A. — Risk Factors — Risks Associated with our Operations — Our acquisitions may not perform as expected, the Company continued to evaluate its Masinloc operations, which were acquired in April 2008. The Company completed a goodwill impairment test of the Masinloc reporting unit as of March 31, 2009 and concluded that no impairment existed. In the second and third quarters of 2009 we continued to monitor Masinloc’s operations noting no impairment indicators. The Company will continue to monitor Masinloc’s operating results and business outlook to identify any changes that could indicate a potential impairment. As of September 30, 2009 the book value of Masinloc’s goodwill was approximately $58 million.

In addition, during the past five months, the Company has successfully completed a number of construction projects, totaling approximately 800 MW, on schedule, including Amman East, Guacolda III, Santa Lidia in Chile, Kilroot OCGT in the United Kingdom, Huanghua, and Innovent in France. However, as discussed under the 2008 Form 10-K, Item 1A. — Risk Factors — Risks Associated with our Operations — Our business is subject to substantial development uncertainties, our development projects are subject to uncertainties. The Company also has 670 MW under construction at its Maritza project in Bulgaria. Certain delays have occurred in the project. However, at this time, we believe that Maritza will still be completed by the second half of 2010. In the event of further delays of the project, completion of the project and commencement of commercial operations could be delayed beyond this timeframe. The parties to the construction and other project contracts are disputing which of them is responsible for the cause and consequences of the delays, which could potentially lead to formal dispute resolution proceedings involving the project.

In June 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals that the environmental permit for Empresa Eléctrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant has stopped as a consequence of the Supreme Court’s decision. In September 2009, the Municipality of Puchuncaví issued an order to demolish the Plant on the basis of other permitting issues. In October 2009, EEC and AES Gener S.A. (“Gener”) filed a judicial claim against the Municipality of Puchuncaví before the Civil Judge of the City of Quintero, seeking to revoke the demolition order and asking for an immediate stay of said order. At the request of EEC and Gener, the Civil Judge of Quintero agreed to suspend the order until a final decision on the order is issued. EEC is working with Chilean authorities to attempt to find a solution that might allow the Plant’s construction to resume. EEC and the construction contractor are disputing which of them is responsible for the cause and consequences of the environmental and other permitting issues. If EEC is unable to complete the project, AES may be required to record an impairment of the Campiche project proportional to its indirect ownership, which could have a material impact on earnings in the period in which it is recorded. Based on cash investments through September 30, 2009 and potential termination costs, AES could incur an impairment of approximately $186 million. In the event an impairment charge is recognized with regard to the project, the amount of such impairment will depend on a number of factors, including EEC’s ability to recover project costs. In addition, Empresa Electrica Ventanas S.A. (“EEV”), a 270 MW gross coal plant under development in Ventanas, is reviewing the potential effects, if any, that the decision of the Supreme Court could have on the Nueva Ventanas project.

Global Recession

The global economic slowdown has caused unprecedented market illiquidity, widening credit spreads, volatile currencies, illiquidity, and increased counterparty credit risk. Despite these challenges, management currently believes that it can meet its liquidity requirements through a combination of existing cash balances,

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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 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 deliver contracted commodities or services at the contracted price or to satisfy their financial or other contractual obligations. 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 nine months ended September 30, 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). We continue to monitor our projects and businesses as needed, however, the Company has not recognized material impairment charges in the first nine months of 2009, although we did evaluate one of our businesses for impairment as described under Operational Challenges. In the future, we may be required to adjust to fair value and record an impairment of certain of our assets or businesses 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 because of the credit crisis and deteriorating global macroeconomic conditions.

A decline in asset value could also result in a material increase in our obligations. For instance, certain subsidiaries 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.

In addition, as described in Overview of Our Business, volatility in foreign currency exchange rates has had an impact on the Company’s financial results. If the current volatility in foreign currencies continues, our gross margin and other financial metrics could be adversely affected. It is also possible that commodity or power price volatility could impact our financial metrics as further described in Overview of Our Business and Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.

To date, other than the impacts described above, the global economic slowdown has not significantly impacted the Company. However, in the event that global economic conditions deteriorate further, or continue for a prolonged period, 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. Any of the foregoing 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.

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Regulatory Environment

The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion by-products), and certain air emissions, such as SO₂, NO_x, particulate matter and mercury. Such risks and uncertainties include risks and uncertainties related to increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations.

In 2009, a key development in the area of GHG legislation has been the passage of H.R. 2454, The American Clean Energy and Security Act of 2009 (“ACESA”) by the U.S. House of Representatives on June 26, 2009. ACESA contemplates a nationwide cap and trade program to reduce U.S. emission of CO₂ and other greenhouse gases starting in 2012. Key features of ACESA include, among other things:

• A planned target to reduce by 2020 GHG emissions by 17% from 2005 levels and to reduce GHG emissions by 83% from 2005 levels by 2050.

• A requirement that certain GHG emitting companies, including most power generators, surrender on an annual basis one ton of CO₂ equivalent allowances or GHG offset credits for each ton of annual CO ₂ equivalent emissions. Such companies will be required to meet allowance surrender requirements via the allocations of free allowances if available from the U.S. Environmental Protection Agency (“EPA”) or purchases in the open market at auctions if free allowances are not allocated, or otherwise.

• A mechanism under which the EPA would initially issue a capped and steadily declining number of tradable free emissions allowances to certain sections of affected industries, including certain generators and utilities in the electricity sector, with such free distribution of allowances to the electricity sector phasing out over a five year period from 2026 through 2030.

• A provision permitting up to two billion tons of GHG offset credits in the aggregate, if available, to be purchased annually by all emitters to satisfy the requirements above.

• A provision precluding the EPA from regulating GHG emissions under the existing provisions of the Clean Air Act (“CAA”).

• A temporary prohibition on the implementation of similar State or regional GHG cap and trade programs, with a six year moratorium (2012 to 2017) on the implementation or enforcement of similar GHG emission caps.

• The establishment of a combined energy efficiency and renewable electricity standard (“RES”) that would require retail electric utilities to receive 6% of their power from renewable sources by 2012, with such requirement increasing to 20% by 2020. In certain circumstances, a portion of this requirement for renewable energy could be satisfied through measures intended to increase energy efficiency.

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The Senate has begun to deliberate similar legislation with the introduction on September 30, 2009 of draft bill S. 1733, the Clean Energy Jobs and American Power Act (“CEJAPA”). CEJAPA contemplates a planned target to reduce by 2020 GHG emissions by 20% from 2005 levels and by 83% from 2005 levels by 2050. CEJAPA has not advanced out of the Senate Committee in which it was introduced (the Committee on the Environment and Public Works) and, if it does advance out of the Committee and is ultimately passed by the Senate, it may undergo significant revisions from its current form.

At this time, if ACESA or CEJAPA were to be enacted into law, or some reconciled version of ACESA or CEJAPA were to be enacted, the impact on the Company’s consolidated results of operations cannot be accurately predicted because of a number of uncertainties with respect to the specific terms and implementation of any such potential legislation, including, among other provisions:

• The number of free allowances that will be allocated to subsidiaries of the Company.

• The cost to purchase allowances in an auction or on the open market, and the cost of purchasing GHG offset credits.

• The extent to which our utility business (IPL) will be able to recover compliance costs from its customers.

• The benefits to our renewables businesses from the RES provision, if any.

• The benefits to our climate solutions projects from the potentially increased demand for GHG offset credits arising from GHG legislation, if any.

• The benefits from the temporary moratorium on state or regional GHG cap and trade programs, if any.

If federal legislation is not enacted that precludes the EPA from regulating GHG emissions under the CAA, the EPA plans to regulate GHG emissions. On September 28, 2009 the EPA proposed a rule to regulate GHG emissions from automobiles, a mobile source of emissions. If such rule is ultimately enacted with respect to a mobile source, one effect would be to subject stationary sources of GHG emissions (including power plants) to regulation under various sections of the CAA. The most important impact on stationary sources would be a requirement that all new sources of GHG emissions of over 250 tons per year, and existing sources planning physical changes that would increase their GHG emissions, obtain new source review permits from the EPA prior to construction. Such sources would be required to apply “best available control technology” to limit the emission of GHGs. On September 30, 2009, the EPA proposed a rule that would limit such regulation of stationary sources to those stationary sources emitting the CO₂ equivalent of over 25,000 tons per year of GHGs. In September of 2009 the EPA also finalized a rule mandating the widespread reporting and tracking of GHG emissions. Although this tracking and reporting rule does not mandate reductions in GHG emissions, data generated from its implementation may facilitate the further development of federal GHG policy, which may include mandatory GHG emissions limits.

Our subsidiaries conduct business in a number of countries that have ratified the Kyoto Protocol, an international agreement concerning GHG emissions. The Kyoto Protocol is currently expected to expire at the end of 2012. A United Nations conference, called COP 15, is planned for December of 2009 in Copenhagen, Denmark. COP 15 is focused primarily on establishing a new international agreement that would succeed the Kyoto Protocol or establishing a framework that will lead to such an international agreement. There are a number of uncertainties and challenges regarding these discussions, including, among other factors, burden-sharing between developing and wealthier nations, the commitments (if any) of the United States under any such agreement, whether large developing countries such as China, India and Brazil will accept emission caps, and the continued availability of international offsets under the Clean Development Mechanism of the Kyoto Protocol.

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There is substantial uncertainty with respect to whether U.S. federal GHG legislation will be enacted into law, whether the EPA will regulate GHG emissions, and whether a new international agreement to succeed the Kyoto Protocol will be reached, and there is additional uncertainty regarding the final provisions and implementation of any potential U.S. federal GHG legislation, any EPA rules regulating GHG emissions and any international agreement to succeed the Kyoto Protocol. In light of these uncertainties, the Company cannot accurately predict the impact on its consolidated results of operations from potential U.S. federal GHG legislation, EPA regulation of GHG emissions or any new international agreement on such emissions, or make a reasonable estimate of the potential costs to the Company associated with any such legislation, regulation or international agreement; however, the impact from any such legislation, regulation or international agreement could have a material adverse effect on certain of our U.S. or international subsidiaries and on the Company and its consolidated results of operations.

On August 23, 2009, the Executive Branch of the Panamanian government issued a new resolution that requested that the National Authority for the Environment in Panama (the “Authority”) increase the current rate for the use of water for the generation of hydroelectric energy and that this increase not be transferable to energy consumers. As of today, the Authority has not issued this rate increase. As AES Panama S.A. currently operates hydroelectric plants in Panama, this new resolution will result in a significant increase in costs that can not be passed through to consumers. Additionally, this new resolution resulted in an investment downgrade of AES Panama S.A., which may affect the ability of AES Panama S.A. to declare and distribute dividends in the future to the Company. AES Panama S.A. is currently in discussions with the Panamanian government to suspend this new resolution and identify other means to promote energy development without increasing the current rate for the use of water.

New Accounting Pronouncements

In June 2009, the FASB issued FAS No. 167, Amendments to FASB Interpretation No. 46(R) (“FAS No. 167”), an amendment to the accounting and disclosure requirements for the consolidation of VIEs. The impact of FAS No. 167 may require the Company to consolidate the assets, liabilities and operating results of certain VIEs, including certain entities currently accounted for under the equity method of accounting that AES does not currently consolidate. It may also require the Company to deconsolidate certain VIEs that are currently consolidated. The impact of the adoption may be applied retrospectively with a cumulative-effect adjustment to retained earnings as of the beginning of the first year restated, or through a cumulative-effect adjustment on the date of adoption. FAS No. 167 will be effective January 1, 2010 for AES. Early adoption is prohibited. AES is currently reviewing the potential impact of FAS No. 167 and at this time has determined that the adoption of FAS No. 167 may have a material impact on its consolidated financial statements. See further discussion of the accounting and disclosure changes and transition guidance in Item 1. – Financial Statements – Note 1 – Financial Statement Presentation – New Accounting Pronouncements.

Recent Developments

On October 7, 2009, the Parent Company voluntarily reduced all of the remaining commitments available under the senior unsecured credit facility and terminated the facility agreement. See further discussion in Note 7 — Long-Term Debt — Recourse Debt.

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Consolidated Results of Operations

	Three Months Ended September 30,											Nine Months Ended September 30,
RESULTS OF OPERATIONS	2009			2008			$ change			% change		2009			2008			$ change			% change
	($’s in millions, except per share amounts)											($’s in millions, except per share amounts)
Revenue:
Latin America Generation	$	1,008		$	1,195		$	(187	)	-16	%	$	2,794		$	3,578		$	(784	)	-22	%
Latin America Utilities		1,672			1,604			68		4	%		4,253			4,644			(391	)	-8	%
North America Generation		486			616			(130	)	-21	%		1,463			1,705			(242	)	-14	%
North America Utilities		266			288			(22	)	-8	%		817			804			13		2	%
Europe Generation		157			262			(105	)	-40	%		513			834			(321	)	-38	%
Asia Generation		291			372			(81	)	-22	%		875			985			(110	)	-11	%
Corporate and Other (1)		(42	)		(18	)		(24	)	-133	%		(4	)		(24	)		20		83	%
Total Revenue		3,838			4,319			(481	)	-11	%		10,711			12,526			(1,815	)	-14	%
Gross Margin:
Latin America Generation		388			385			3		1	%		1,095			1,103			(8	)	-1	%
Latin America Utilities		294			246			48		20	%		640			725			(85	)	-12	%
North America Generation		104			147			(43	)	-29	%		346			549			(203	)	-37	%
North America Utilities		65			81			(16	)	-20	%		186			194			(8	)	-4	%
Europe Generation		34			40			(6	)	-15	%		128			219			(91	)	-42	%
Asia Generation		71			37			34		92	%		195			125			70		56	%
Corporate and Other (2)		52			26			26		100	%		148			118			30		25	%
General and administrative expense		(82	)		(90	)		8		9	%		(255	)		(287	)		32		11	%
Interest expense		(421	)		(458	)		37		8	%		(1,195	)		(1,362	)		167		12	%
Interest income		94			156			(62	)	-40	%		282			405			(123	)	-30	%
Other expense		(15	)		(18	)		3		17	%		(67	)		(128	)		61		48	%
Other income		35			63			(28	)	-44	%		279			258			21		8	%
Gain on sale of investments		17			-			17		100	%		132			912			(780	)	-86	%
Impairment expense		(6	)		(22	)		16		73	%		(7	)		(94	)		87		93	%
Foreign currency transaction (losses) gains on net monetary position		(1	)		(60	)		59		98	%		(13	)		(123	)		110		89	%
Other non-operating expense		(2	)		-			(2	)	-100	%		(12	)		-			(12	)	-100	%
Income tax expense		(205	)		(168	)		(37	)	-22	%		(485	)		(725	)		240		33	%
Net equity in earnings of affiliates		18			(4	)		22		550	%		75			38			37		97	%
Income from continuing operations		440			361			79		22	%		1,472			1,927			(455	)	-24	%
Loss (income) from operations of discontinued businesses		-			(2	)		2		100	%		-			1			(1	)	-100	%
Loss from disposal of discontinued businesses		-			-			-		0	%		-			(1	)		1		100	%
Net income		440			359			81		23	%		1,472			1,927			(455	)	-24	%
Noncontrolling interests		(255	)		(214	)		(41	)	-19	%		(766	)		(646	)		(120	)	-19	%
Net income attributable to The AES Corporation	$	185		$	145		$	40		28	%	$	706		$	1,281		$	(575	)	-45	%
PER SHARE DATA:
Basic income per share from continuing operations	$	0.28		$	0.22		$	0.06		27	%	$	1.06		$	1.91		$	(0.85	)	-45	%
Diluted income per share from continuing operations	$	0.28		$	0.22		$	0.06		27	%	$	1.06		$	1.87		$	(0.81	)	-43	%

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

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

Revenue

Revenue decreased $481 million, or 11%, to $3.8 billion for the three months ended September 30, 2009 compared with the same period in 2008. Excluding the unfavorable impact of foreign currency translation of $367 million, largely driven by the Brazilian Real, revenue decreased $114 million or 3%. The decrease was due to a reduction in volume at our generation businesses in Hungary and Northern Ireland of $82 million from the impact of the cancellation of one of our PPAs and reduced demand in Hungary and the unfavorable impact of gas prices compared to coal in Northern Ireland, resulting in lower dispatch. Further contributing to the decrease in revenue was the impact of lower spot and contract energy prices at our generation business in Chile of $74 million, a decrease in volume of $69 million at Uruguaiana in Brazil, as a result of the renegotiation of its power sales agreements in 2009 to reduce the energy volume sold, the unfavorable impact of mark-to-market derivative adjustments on certain commodity contracts of $69 million in North America and Chile and a reduction in the volume of spot electricity sales in New York of $55 million driven by lower spot market rates. These decreases were partially offset by an increase in tariff rates in Latin America primarily reflecting the recovery of energy purchases that were passed through to customers at our utilities businesses in Brazil and El Salvador of $213 million.

Revenue decreased $1.8 billion, or 14%, to $10.7 billion for the nine months ended September 30, 2009 compared with the same period in 2008. Excluding the impact of foreign currency translation of $1.5 billion, largely driven by the Brazilian Real, revenue decreased $349 million or 3%. This decrease was primarily due to the impact of lower spot and contract energy prices at Gener of $308 million, a decrease in volume of $218 million at Uruguaiana, as a result of the renegotiation of its power sales agreements in 2009 to reduce the energy volume sold and lower volume in New York of $109 million due to lower spot market rates. Volume decreased at our Europe generation businesses in Hungary and Northern Ireland by $110 million due to the cancellation of one of our power purchase agreements and reduced demand in Hungary and lower dispatch as a result of the unfavorable impact of gas prices relative to coal at Kilroot. Additionally, our Europe generation segment was unfavorably impacted $111 million by the sale of our Northern Kazakhstan businesses in May 2008. Partially offsetting these decreases were increases in tariff rates in Brazil and El Salvador of $417 million largely from the recovery of energy purchases that were passed through to the customer.

Gross Margin

Gross margin increased $46 million, or 5%, to $1.0 billion for the three months ended September 30, 2009 compared with the same period in 2008. Excluding the unfavorable impact of foreign currency translation of $79 million, gross margin increased $125 million or 13%. This increase was due to improved operating performance of $48 million at Gener and $23 million from Masinloc, our generation business in the Philippines acquired in April 2008, reduced fixed costs primarily driven by bad debt recoveries in Brazil and Cameroon of $65 million, partially offset by lower volume at our generation business in New York of $33 million as a result of lower spot market rates.

Excluding the impact of foreign currency translation, our gross margin for the three months ended September 30, 2009 increased 13% compared to a decrease in revenue of 3%. Contributing to this variance were bad debt recoveries in Brazil and Cameroon and the favorable impact of the Hawaii coal supply contract derivative, all of which had no associated favorable impact on revenue. These were partially offset by the unfavorable impact to revenue of lower volume at our Europe generation businesses largely driven by fuel costs passed through to the customer and had minimal impact on gross margin.

Gross margin decreased $295 million, or 10%, to $2.7 billion for the nine months ended September 30, 2009 compared with the same period in 2008. Excluding the unfavorable impact of foreign currency translation of

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$316 million, gross margin increased $21 million, or 1%. This increase was primarily the result of improved operating results at certain Latin America Generation businesses, largely due to rate and volume at Gener of $93 million and the favorable impact at Uruguaiana of $70 million driven by the renegotiation of its power sales agreements in 2009, which reduced the volume it was required to provide under its contracts, bad debt expense and maintenance costs. Also contributing to the increase was the recovery of a municipality receivable previously written off at Eletropaulo of $57 million and improved operations at Masinloc of $37 million. Offsetting these increases were the unfavorable impact of mark-to-market derivatives adjustments on certain commodity contracts of $107 million in North America and Chile, lower volume at our generation business in New York of $66 million as a result of unfavorable pricing in the spot market, and the absence of the contribution of $41 million from our Northern Kazakhstan businesses which were sold in May 2008.

Please refer to Segment Analysis below for further discussion of revenue and gross margin.

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 September 30,						For the Nine Months Ended September 30,
	2009		2008		% Change		2009		2008		% Change
	(in millions)						(in millions)
Latin America Generation
Revenue	$	1,008	$	1,195	-16	%	$	2,794	$	3,578	-22	%
Gross Margin	$	388	$	385	1	%	$	1,095	$	1,103	-1	%

Excluding the unfavorable impact of foreign currency translation of $77 million in Argentina and Brazil, generation revenue for the three months ended September 30, 2009 decreased $110 million, or 9%, compared to the three months ended September 30, 2008 primarily due to lower spot and contract prices at Gener in Chile of $74 million. Additionally, the decrease was due to lower volume at Uruguaiana in Brazil of $69 million due to the renegotiation of its power sales agreements in 2009, lower contract prices at our businesses in the Dominican Republic of $57 million, lower volume at our businesses in the Dominican Republic, Argentina and Panama of $48 million and a derivative gain recorded in the third quarter of 2008 related to a PPA at Gener in Chile of $27 million. These decreases were partially offset by a net increase in volume at Gener of $74 million driven by the unfavorable impact in 2008 of gas curtailments in Argentina, a decrease in outages in Chile and Argentina of $41 million, increased spot and contract prices of $38 million at our businesses in Argentina and an increase in volume and higher prices of $26 million at Tiete in Brazil.

Excluding the unfavorable impact of foreign currency translation of $34 million in Brazil and Argentina, generation gross margin for the three months ended September 30, 2009 increased $37 million, or 10%, compared to the three months ended September 30, 2008 primarily due to an increase at Gener of $74 million from the combined impact of an increase in the volume of spot sales driven by the unfavorable impact in 2008 of gas curtailments in Argentina, savings from the use of more efficient fuel in 2009 offset by an increase in purchased energy. The increase was also a result of fewer outages at our businesses in Argentina and Gener of $31 million and a reduction in the volume of purchased energy at Uruguaiana of $20 million. These increases were partially offset by a derivative gain recorded in the third quarter of 2008 related to a PPA at Gener in Chile of $27 million, higher purchased energy prices at Uruguaiana of $20 million, a decrease in the volume of spot sales combined with an increase in purchased energy in Panama of $19 million and higher fuel and purchased energy prices in Argentina of $18 million.

Even though generation revenue declined 16%, gross margin increased 1%. This was primarily due to a reduction in outages, the use of more efficient fuel and less purchased energy that had a favorable impact on gross margin, but no corresponding impact on revenue.

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Excluding the unfavorable impact of foreign currency translation of $229 million in Brazil and Argentina, generation revenue for the nine months ended September 30, 2009 decreased $555 million, or 16%, compared to the nine months ended September 30, 2008 primarily due to lower spot and contract prices at Gener of $308 million, lower volume at Uruguaiana of $218 million as a result of the renegotiation of its power sales agreements in 2009 to reduce the energy volume sold, and lower prices and volume at our businesses in the Dominican Republic of $143 million. These decreases were partially offset by higher prices and volume at Tiete of $80 million and fewer outages in 2009 at Gener and Alicura of $78 million.

Excluding the unfavorable impact of foreign currency translation of $125 million in Brazil and Argentina, generation gross margin for the nine months ended September 30, 2009 increased $117 million, or 11%, compared to the nine months ended September 30, 2008, primarily due to increased spot sales and a reduction in fuel purchases at Gener of $145 million driven by the unfavorable impact in 2008 of gas curtailments in Argentina, fewer outages in 2009 at Gener and Alicura of $63 million, higher prices of energy sold at Tiete of $57 million and the favorable impact at Uruguaiana of a decrease in bad debt expense of $46 million, largely a result of the renegotiation of its power sales agreements in 2009 to reduce the energy volume sold. These increases were partially offset by the unfavorable impact of higher fuel and purchased energy prices at our businesses in Argentina of $70 million, the net impact of lower contract and spot prices offset by lower fuel costs and decreased purchased energy prices at Gener of $52 million, and higher purchased energy prices at Uruguaiana of $51 million.

Even though generation revenue declined by 22%, gross margin decreased 1%. This was primarily due to reduced fuel purchases, outages and bad debt expense.

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2009		2008		% Change		2009		2008		% Change
	(in millions)						(in millions)
Latin America Utilities
Revenue	$	1,672	$	1,604	4	%	$	4,253	$	4,644	-8	%
Gross Margin	$	294	$	246	20	%	$	640	$	725	-12	%

Excluding the unfavorable impact of foreign currency translation of $185 million, primarily in Brazil, utilities revenue for the three months ended September 30, 2009 increased $253 million, or 16%, compared to the three months ended September 30, 2008, largely due to an increase in tariff rates primarily reflecting the recovery of energy purchases that were passed through to our customers at our utilities in Brazil and El Salvador of $213 million.

Excluding the unfavorable impact of foreign currency translation of $33 million, primarily in Brazil, utilities gross margin for the three months ended September 30, 2009 increased $81 million, or 33%, compared to the three months ended September 30, 2008, primarily due to the recovery of a municipality receivable previously written off in Brazil of $57 million and higher volume in Brazil of $20 million.

Utilities revenue for the three months ended September 30, 2009 increased 4% while gross margin increased 20% for the period, primarily due to the recovery of the municipal receivable in Brazil which had no impact on revenue.

Excluding the unfavorable impact of foreign currency translation of $828 million, primarily in Brazil, utilities revenue for the nine months ended September 30, 2009 increased $437 million, or 9%, compared to the nine months ended September 30, 2008, primarily due to an increase in tariff rates reflecting the recovery of energy purchases that were passed through to our customers at our utilities in Brazil and El Salvador of $417 million.

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Excluding the unfavorable impact of foreign currency translation of $123 million, utilities gross margin for the nine months ended September 30, 2009 increased $38 million, or 5%, compared to the nine months ended September 30, 2008, primarily due to higher tariffs of $62 million in Brazil, higher volume of $26 million and the recovery of a municipality receivable previously written off in Brazil of $57 million. These decreases were partially offset by an increase in fixed costs of $100 million primarily at Eletropaulo driven by higher pension costs, labor contingencies and bad debt expense.

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 September 30,						For the Nine Months Ended September 30,
	2009		2008		% Change		2009		2008		% Change
	(in millions)						(in millions)
North America Generation
Revenue	$	486	$	616	-21	%	$	1,463	$	1,705	-14	%
Gross Margin	$	104	$	147	-29	%	$	346	$	549	-37	%

Excluding the unfavorable impact of foreign currency translation in Mexico of $13 million, generation revenue for the three months ended September 30, 2009 decreased $117 million, or 19%, compared to the three months ended September 30, 2008 primarily due to a net decrease of $34 million in New York due to a reduction in the volume of electricity sold in the spot market as a result of lower spot rates, partially offset by a rate increase on electricity sold under favorable contracts. Additionally the decrease was due to the impact of a mark-to-market derivative gain at Deepwater in Texas of $24 million in 2008 that did not recur, reduced natural gas prices in 2009 at Merida in Mexico of $23 million, the unfavorable impact of commodity derivatives in New York of $17 million and an increase in outages at Warrior Run in Maryland of $11 million and TEG/TEP in Mexico of $6 million.

Generation gross margin for the three months ended September 30, 2009 decreased $43 million, or 29%, compared to the three months ended September 30, 2008 primarily due to a mark-to-market derivative gain at Deepwater of $24 million in 2008 that did not recur, the unfavorable impact of commodity derivatives in New York of $17 million, an increase in outages at TEG/TEP of $16 million and Warrior Run of $11 million, and a net decrease of $12 million in New York due to a reduction in the volume of electricity sold in the spot market as a result of lower spot rates, partially offset by favorable contracted rates. These decreases were partially offset by a $52 million mark-to-market derivative loss on a coal supply contract at Hawaii in 2008 that did not recur.

Excluding the unfavorable impact of foreign currency translation in Mexico of $40 million, generation revenue for the nine months ended September 30, 2009 decreased $202 million, or 12%, compared to the nine months ended September 30, 2008 primarily due to a decrease of $74 million in New York due to a reduction in the volume of electricity sold in the spot market as a result of lower spot rates partially offset by a rate increase on electricity sold under favorable contracts and fewer outages. Additionally, revenue decreased $41 million due to a reduction in natural gas prices at Merida, an increase in outages at Warrior Run and TEG/TEP of $25 million and $21 million, respectively, lower rates at Deepwater of $17 million and the unfavorable impact of commodity derivatives in New York of $21 million. These decreases were partially offset by a $17 million revenue adjustment at Merida in 2008.

Excluding the unfavorable impact of foreign currency translation of $4 million in Mexico, generation gross margin for the nine months ended September 30, 2009 decreased $199 million, or 36%, compared to the nine months ended September 30, 2008 primarily due to a $55 million mark-to-market derivative gain on a coal supply contract at Hawaii in 2008 compared to a $7 million loss recognized in the first nine months of 2009, an

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increase in outages at Warrior Run and TEG/TEP of $25 million and $16 million, respectively, a net of $37 million in New York due to a reduction in the volume of electricity sold in the spot market as a result of lower spot rates partially offset by favorable contracted rates and fewer outages. Additionally, gross margin decreased due to the unfavorable impact of commodity derivatives and lower contracted sales of $21 million, higher purchases of emission allowances of $14 million and higher property taxes of $8 million at New York. These decreases were partially offset by a $17 million revenue adjustment at Merida in 2008.

For the comparable nine month period, generation revenue declined 14% while gross margin declined 37%. This was primarily due to $62 million mark-to-market derivative gain on a coal supply contract at Hawaii included as an increase to cost of sales in 2008, and an increase in outages at Warrior Run of $25 million and TEG/TEP of $16 million which had a greater impact on gross margin than revenue.

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 September 30,						For the Nine Months Ended September 30,
	2009		2008		% Change		2009		2008		% Change
	(in millions)						(in millions)
North America Utilities
Revenue	$	266	$	288	-8	%	$	817	$	804	2	%
Gross Margin	$	65	$	81	-20	%	$	186	$	194	-4	%

Utilities revenue for the three months ended September 30, 2009 decreased $22 million, or 8%, compared to the three months ended September 30, 2008 primarily due to lower retail volume of $14 million. The decrease in retail volume is mainly attributable to the economic recession and milder weather.

Utilities gross margin for the three months ended September 30, 2009 decreased $16 million, or 20%, compared to the three months ended September 30, 2008 primarily due to lower retail margin of $8 million mainly attributable to increased capacity costs of $3 million, the impact of milder weather and the economic recession. Additionally, gross margin decreased due to increased pension expense of $6 million largely attributable to the decline in market value of IPL’s pension assets during 2008. Utilities revenue declined 8% while gross margin declined 20% primarily due to the increase in pension expense which did not have an impact on revenue.

Utilities revenue for the nine months ended September 30, 2009 increased $13 million, or 2%, compared to the nine months ended September 30, 2008 primarily due to $32 million of credits to retail customers established during the first nine months of 2008 and higher pass-through fuel costs of $17 million. These increases were partially offset by lower retail volume of $27 million due primarily to milder weather and the economic recession, and a decrease in wholesale revenue of $9 million, primarily driven by lower prices.

Utilities gross margin for the nine months ended September 30, 2009 decreased $8 million, or 4%, compared to the nine months ended September 30, 2008 primarily due to a decrease in wholesale margin of $15 million due to unfavorable prices and increased pension expense of $18 million largely due to the decline in market value of IPL’s pension assets during 2008. These decreases were partially offset by an increase in retail margin of $25 million primarily due to $32 million of credits to retail customers established during the first six months of 2008 and a decrease in property tax expense of $5 million.

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Europe

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2009		2008		% Change		2009		2008		% Change
	(in millions)						(in millions)
Europe Generation
Revenue	$	157	$	262	-40	%	$	513	$	834	-38	%
Gross Margin	$	34	$	40	-15	%	$	128	$	219	-42	%

Excluding the unfavorable impact of foreign currency translation of $29 million, driven mainly by our businesses in Hungary, generation revenue for the three months ended September 30, 2009 decreased $76 million, or 29%, compared to the three months ended September 30, 2008. This decrease was primarily the result of lower volume at our businesses in Hungary of $50 million due to the combined impact of the cancellation of one of our PPAs and reduced demand and $26 million at Kilroot in Northern Ireland mainly driven by lower dispatch due to favorable gas prices compared to coal.

Excluding the unfavorable impact of foreign currency translation of $5 million, generation gross margin for the three months ended September 30, 2009 decreased $1 million, or 3%, compared to the three months ended September 30, 2008. This decrease was primarily the result of lower demand in Hungary and higher fixed costs at Kilroot.

Generation revenue for the three months declined 40% while gross margin declined 15% primarily due to the decrease in dispatch at Kilroot. This had a negligible impact on gross margin because the decreased dispatch was driven by fuel costs which are passed through to the customer.

Excluding the unfavorable impact of foreign currency translation of $130 million, driven mainly by our businesses in Hungary and at Kilroot, generation revenue for the nine months ended September 30, 2009 decreased $191 million, or 23%, compared to the nine months ended September 30, 2008. This decrease was primarily due to lower revenue of $111 million in Kazakhstan as a result of the sale of Ekibastuz and Maikuben in May 2008, lower volume at our businesses in Hungary of $70 million due to the combined impact of the cancellation of one our PPAs and reduced demand and $34 million at Kilroot mainly driven by lower dispatch due to favorable gas prices compared to coal. These decreases were partially offset by higher rates of $16 million at Altai in Kazakhstan and Bohemia in the Czech Republic.

Excluding the unfavorable impact of foreign currency translation of $33 million across the region, generation gross margin for the nine months ended September 30, 2009 decreased $58 million, or 26%, compared to the nine months ended September 30, 2008. This decrease was primarily due to lower gross margin of $41 million from our businesses in Kazakhstan as result of the sale of Ekibastuz and Maikuben in May 2008, lower demand in Hungary of $19 million and higher fixed costs across the region of $21 million, partially offset by higher capacity revenue rates at Kilroot and Altai.

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Asia

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2009		2008		% Change		2009		2008		% Change
	(in millions)						(in millions)
Asia Generation
Revenue	$	291	$	372	-22	%	$	875	$	985	-11	%
Gross Margin	$	71	$	37	92	%	$	195	$	125	56	%

Excluding the unfavorable impact of foreign currency translation of $18 million, primarily in Pakistan, generation revenue for the three months ended September 30, 2009 decreased $63 million, or 17%, compared to the three months ended September 30, 2008. This decrease was primarily due to a decrease in generation volume and rates of $64 million in Sri Lanka and Pakistan, largely due to lower fuel costs which are largely passed through to the customer, decreased demand from offtakers, in addition to a $20 million decrease at Lal Pir in Pakistan due to a planned outage in August 2009. These decreases were offset by an increase of $10 million at Masinloc in the Philippines, due to increased capacity and an increase of $7 million at our business, Amman East in Jordan, due to an incremental volume increase driven by fuel costs passed through and the impact of new business. Amman East began single cycle production in July 25, 2008 and additionally commenced operations as a combined cycle plant in August 2009.

Excluding the unfavorable impact of foreign currency translation of $2 million, generation gross margin for the three months ended September 30, 2009 increased $36 million, or 97%, compared to the three months ended September 30, 2008. This increase was primarily due to improved operations at Masinloc of $23 million, largely driven by increased rates and capacity and reduced coal prices; favorable margins in Pakistan of $7 million driven by lower fuel costs, and a higher capacity charge of $5 million at Kelanitissa in Sri Lanka.

Generation revenue for the three months declined 22% while gross margin increased 92%. The significant increase in gross margin compared to the decrease in revenue, was mainly the result of decreased revenue in Pakistan and Sri Lanka driven by fuel costs that are largely passed through to the customer and had a minimal impact on gross margin, accompanied by improved operations at Masinloc.

Excluding the unfavorable impact of foreign currency translation of $91 million, primarily in Pakistan and the Philippines, generation revenue for the nine months ended September 30, 2009 decreased $19 million, or 2%, compared to the nine months ended September 30, 2008. This decrease was primarily due to a decrease in rate and volume of $193 million in Pakistan and Sri Lanka, attributed primarily to a decline in fuel costs which are largely passed through to the customer, lower dispatch from the offtaker and fewer outages. These decreases were partially offset by improved operations and availability of $74 million at Masinloc in the second and third quarters of 2009 and the benefit of new business of $46 million at Masinloc, which was acquired in April 2008, and $50 million at Amman East which commenced single cycle operations in July 2008.

Excluding the unfavorable impact of foreign currency translation of $13 million, primarily in Pakistan and the Philippines, generation gross margin for the nine months ended September 30, 2009 increased $83 million, or 66%, compared to the nine months ended September 30, 2008. This increase was mainly a result of improved operations in the second and third quarters of 2009 at Masinloc of $37 million and the impact of our new businesses, Masinloc and Amman East, of $40 million.

Generation revenue for the nine months declined 11% while gross margin increased 56%. The increase in gross margin compared to the decrease in revenue, was mainly the result of decreased revenue in Pakistan and Sri Lanka driven by fuel costs that are largely passed through to the customer and had a minimal impact on gross margin, accompanied by improved operations at Masinloc.

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Corporate and Other

Corporate and Other includes the net operating results from our generation and utilities businesses in Africa, utilities businesses in Europe, AES Wind Generation and other climate solutions and renewables projects which are immaterial for the purposes of separate segment disclosure. The following table excludes the elimination of inter-segment activity and summarizes revenue and gross margin for Corporate and Other entities for the periods indicated:

	Revenue								Gross Margin
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,						Nine Months Ended September 30,
	2009		2008		2009		2008		2009			2008			2009		2008
	(in millions)								(in millions)
Corp/Other	$	7	$	17	$	11	$	35	$	20		$	(30	)	$	-	$	(34	)
Europe Utilities		61		101		205		297		4			10			15		28
Africa Utilities		93		96		267		298		33			13			71		39
Africa Generation		17		17		50		49		10			7			29		21
Wind		28		36		97		92		(4	)		3			5		17
Total Corporate and Other	$	206	$	267	$	630	$	771	$	63		$	3		$	120	$	71

Corporate and Other revenue decreased $61 million, or 23%, to $206 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to the unfavorable impact of foreign currency translation of $41 million at our utilities businesses in the Ukraine.

Corporate and Other revenue decreased $141 million, or 18%, to $630 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. The decrease was primarily due to the unfavorable impact of foreign currency translation of $117 million at our utilities businesses in the Ukraine.

Corporate and Other gross margin increased $60 million to $63 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to an increase of $20 million at Sonel, our utility business in Cameroon, mainly related to decreased bad debt expense, and improvements at our climate solutions projects.

Corporate and Other gross margin increased $49 million, or 69%, to $120 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. The increase was primarily due to decreased fixed costs of $41 million at Sonel mainly related to decreased bad debt expense of $24 million.

General and Administrative Expense

General and administrative expense includes those 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.

General and administrative expense decreased $8 million, or 9%, to $82 million for the three months ended September 30, 2009 from $90 million for the three months ended September 30, 2008. The decrease was primarily related to a current year decrease in corporate overhead and business development costs.

General and administrative expense decreased $32 million, or 11%, to $255 million for the nine months ended September 30, 2009 from $287 million for the nine months ended September 30, 2008. The decrease was primarily related to 2008 professional fees associated with remediation efforts of our 2007 material weaknesses and a current year decrease in corporate overhead and business development costs, partially offset by an increase in current year costs associated with the worldwide implementation of SAP.

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Interest expense

Interest expense decreased $37 million, or 8%, to $421 million for the three months ended September 30, 2009 compared to the same period in 2008 primarily due to lower interest rates in Brazil as a result of inflationary adjustments to the General Market Price Index (“IGP-M”), favorable foreign currency translation and lower outstanding indebtedness.

Interest expense decreased $167 million, or 12%, to $1.2 billion for the nine months ended September 30, 2009 compared to the same period in 2008. In addition to the items mentioned above, the decrease was also due to lower interest rates at Gener in Chile and Southland in North America. These decreases were partially offset by interest expense at our Masinloc plant in the Philippines which began operations during April 2008, and interest expense at Infovias in Brazil where a fee on a non-exercised credit line was written off.

Interest income

Interest income decreased $62 million, or 40%, to $94 million for the three months ended September 30, 2009 and decreased $123 million, or 30%, to $282 million for the nine months ended September 30, 2009 primarily due to lower interest rates in Brazil, unfavorable foreign currency translation on the Brazilian Real, lower cash balances at Uruguaiana, and the impact of inflationary adjustments on accounts receivables in 2008 at Gener in Chile.

Other expense

Other expense of $15 million for the three months ended September 30, 2009 included losses on disposal of assets at Eletropaulo and contingencies at Alicura in Argentina. Other expense of $18 million for the three months ended September 30, 2008 was primarily comprised of losses on disposal of assets.

Other expense of $67 million for the nine months ended September 30, 2009 primarily consisted of a $13 million loss recognized when three of our businesses in the Dominican Republic received $110 million par value bonds issued by the Dominican Republic government to settle existing accounts receivable for the same amount from the government-owned distribution companies. The loss represented an adjustment to reflect the fair value of the bonds on the date received. Other expense also included losses on the disposal of assets at Eletropaulo and Andres and contingencies at Altai and Alicura. Other expense of $128 million for the nine months ended September 30, 2008 included $69 million of losses related to the extinguishment of debt at the Parent Company in connection with a refinancing in June 2008 and the refinancing of $375 million of debt by IPALCO in April 2008, as well as contingencies and losses on disposal of assets.

Other income

Other income of $35 million for the three months ended September 30, 2009 included the reversal of contingencies at Sonel in Cameroon and Sul in Brazil, a gain on sale of assets at Placerita, and the reversal of tax liabilities at Altai. Other income of $63 million for the three months ended September 30, 2008 included $29 million of cash proceeds received by AES Southland in California for a settlement and $23 million of gains associated with a sale of land at Eletropaulo in Brazil and the sale of turbines at Itabo in the Dominican Republic.

Other income of $279 million for the nine months ended September 30, 2009 included a favorable court decision in which Eletropaulo had requested reimbursement for excess non-income taxes paid from 1989 to 1992. Eletropaulo received reimbursement in the form of tax credits 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

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the sale of these businesses in Kazakhstan in May 2008; see further discussion of this transaction in Note 14 — Acquisitions and Dispositions of our condensed consolidated financial statements included in this Quarterly Report. Other income also included $9 million of insurance proceeds at Uruguaiana in Brazil and Andres in the Dominican Republic. Other income of $258 million for the nine months ended September 30, 2008 included income from the above mentioned settlement and sales of assets, as well as a $117 million gain related to the extinguishment of a non-income tax liability at Eletropaulo, insurance recoveries of $14 million for damaged turbines at Uruguaiana, and $14 million of compensation received from the local government for the impairment of plant assets and cessation of the PPA associated with a settlement agreement to shut down the Hefei generation facility in China recorded during the first quarter of 2008.

Gain on sale of investments

Gain on sale of investments for the three months ended September 30, 2009 was $17 million which included a $15 million gain related to the shutdown of the Company’s Hefei plant in China. The final payment on the remaining property, plant and equipment was received and the Company’s obligations under the settlement agreement were satisfied in September 2009 and the deferred gain on the shutdown and termination of the PPA was recognized. There was no gain on the sale of investments in the three months ended September 30, 2008.

The gain on the sale of investments for the nine months ended September 30, 2009 was $132 million and primarily consisted of $98 million recognized in May 2009 related to the termination of the management agreement between the Company and Kazakhmys PLC for Ekibastuz and Maikuben; see further discussion of this transaction in Note 14 — Acquisitions and Dispositions to the condensed consolidated financial statements included in this Quarterly Report. In addition, the gain for the nine months ended September 30, 2009 included a $13 million reversal of a contingent liability in March 2009 related to the sale of Ekibastuz and Maikuben in May 2008 and the $15 million gain on Hefei discussed above. The gain on sale of investments for the nine months ended September 30, 2008 was $912 million and primarily consisted of a $908 million net gain on the sale of two of the Company’s wholly-owned subsidiaries in Kazakhstan, Ekibastuz and Maikuben in May 2008.

Impairment expense

Impairment expense for the three months ended September 30, 2009 and 2008 was $6 million and $22 million, respectively. Impairment expense for the three months ended September 30, 2009 consisted primarily of a $5 million impairment of long-lived assets at Borsod in Hungary. Impairment expense for the three months ended September 30, 2008 included an impairment charge of $11 million, in addition to the impairment recognized during the first half of 2008 related to turbine deposits for the South African peakers projects, as further discussed below, and a $5 million impairment recognized upon our withdrawal from a project in Israel.

Impairment expense for the nine months ended September 30, 2009 and 2008 was $7 million and $94 million, respectively. Impairment expense for the nine months ended September 30, 2009 consisted primarily of the long-lived asset impairment recognized at Borsod in the third quarter of 2009 as discussed above. Impairment expense in 2008 consisted primarily of impairment charges of $36 million at Uruguaiana, a thermoelectric plant. This charge resulted from the analysis of its long-lived assets, which was triggered by the combination of gas curtailments and increases in the spot market price of energy in 2007. Additionally, impairment of $31 million was recognized in the first nine months of 2008 related to project development costs written off upon the Company’s withdrawal from a South African peakers project and $14 million associated with a settlement agreement to shut down the Hefei plant in China.

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Foreign currency transaction (losses) gains on net monetary position

Foreign currency transaction (losses) gains were as follows:

	Three months ended September 30,						Nine months ended September 30,
	2009			2008			2009			2008
	(in millions)						(in millions)
The AES Corporation	$	16		$	(14	)	$	4		$	2
Philippines		7			(20	)		2			(47	)
Chile		(16	)		(12	)		39			(44	)
Colombia		(10	)		6			(15	)		4
Argentina		(2	)		(8	)		(13	)		(1	)
Brazil		(1	)		(7	)		(5	)		(29	)
Kazakhstan		(1	)		(1	)		(27	)		(5	)
Other		6			(4	)		2			(3	)
Total (1)	$	(1	)	$	(60	)	$	(13	)	$	(123	)

⁽¹⁾ Includes $8 million and $6 million losses on foreign currency derivative contracts for the three months ended September 30, 2009 and 2008, respectively, and includes $42 million and $18 million losses on foreign currency derivative contracts for the nine months ended September 30, 2009 and 2008, respectively.

The Company recognized foreign currency transaction losses of $1 million for the three months ended September 30, 2009. These consisted primarily of losses in Chile, Colombia and Argentina partially offset by gains at The AES Corporation and in the Philippines.

• Losses of $16 million in Chile were primarily due to the devaluation of the Chilean Peso by 3%, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with net working capital denominated in Chilean Peso, mainly cash and accounts receivables.

• Gains of $16 million at The AES Corporation were primarily due to the strengthening of the Euro and the weakening of the British Pound during the quarter, resulting in gains on outstanding notes receivables denominated in Euro and on third party debt denominated in the British Pound, partially offset by losses on foreign exchange options.

• Losses of $10 million in Colombia were primarily due to appreciation of the Colombian Peso by 11%, resulting in losses at Chivor (a U.S. Dollar functional currency subsidiary) associated with its Colombian Peso denominated debt and $4 million in losses on foreign currency derivatives.

• Gains of $7 million in the Philippines were primarily due to the appreciation of the Philippine Peso, resulting in gains on translation of U.S. Dollar denominated debt.

The Company recognized foreign currency transaction losses of $60 million for the three months ended September 30, 2008. These consisted primarily of losses at The AES Corporation and in Chile, the Philippines and Brazil.

• Losses of $14 million at The AES Corporation were primarily due to losses of $15 million from unfavorable exchange rates associated with a convertible loan receivable, notes receivable and cash accounts denominated in Euros, offset by gains from favorable exchange rates for outstanding notes denominated in British Pounds.

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• Losses of $20 million in the Philippines were primarily due to the weakening of the Philippine Peso to the U.S. Dollar on remeasurement of external and intercompany loans at Masinloc in the Philippines.

• Losses of $12 million in Chile were primarily due to the devaluation of the Chilean Peso by 5%, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with its net working capital denominated in Chilean Pesos, primarily cash, accounts receivables and VAT receivables.

• Losses of $7 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 $11 million.

The Company recognized foreign currency transaction losses of $13 million for the nine months ended September 30, 2009. These consisted primarily of losses in Kazakhstan, Colombia, Argentina and Brazil, partially offset by gains in Chile and at The AES Corporation.

• Gains of $39 million at Chile were primarily due to the appreciation of the Chilean Peso by 14%, resulting in gains at Gener (a U.S. Dollar functional currency subsidiary) associated with its net working capital denominated in Chilean Peso, mainly cash and accounts receivables. This gain was partially offset by $13 million in losses on foreign currency derivatives.

• Losses of $27 million in Kazakhstan were primarily due to net foreign currency transaction losses of $14 million related to energy sales denominated and fixed in the U.S. Dollar and $13 million of foreign currency transaction losses on debt denominated in other than functional currencies.

• Losses of $15 million in Colombia were primarily due to appreciation of the Colombian Peso by 14%, resulting in losses at Chivor (a U.S. Dollar functional currency subsidiary) associated with its Colombian Peso denominated debt and $7 million in losses on foreign currency derivatives.

• Losses of $13 million in Argentina were primarily due to the devaluation of the Argentine Peso by 11%, resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt.

• Losses of $5 million in Brazil were primarily due to energy purchases made by Eletropaulo denominated in U.S. Dollar, resulting in foreign currency transaction losses of $11 million, partially offset by gains of $6 million due to the appreciation of the Brazilian Real by 24%, resulting in gains in Sul and Uruguaiana in Brazil associated with U.S. Dollar denominated liabilities.

• Gains of $4 million at The AES Corporation were primarily due to the strengthening of the Euro and the British Pound, resulting in gains on outstanding notes receivable, which were partially offset by losses on third party debt denominated in the British Pound and losses on foreign exchange options.

The Company recognized foreign currency transaction losses of $123 million for the nine months ended September 30, 2008. These consisted primarily of losses in Chile, the Philippines, Brazil and Kazakhstan.

• Losses of $47 million in the Philippines were primarily due to the weakening of the Philippine Peso to the U.S. Dollar on remeasurement of debt at Masinloc in the Philippines.

• Losses of $44 million in Chile were primarily due to the devaluation of the Chilean Peso by 11%, resulting in losses 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.

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• Losses of $29 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 $32 million.

• Losses of $5 million in Kazakhstan were primarily due to losses of $19 million associated with third-party debt and intercompany liabilities denominated in currencies other than the Kazakh Tenge, the functional currency. These increased losses were offset by gains of $5 million related to energy sales denominated and fixed in USD.

Other non-operating expense

Other non-operating expense was $2 million and $12 million for the three and nine months ended September 30, 2009, consisting primarily of other-than-temporary impairments of cost method investments. 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 market and management concluded that the $10 million decline was other-than-temporary.

There was no non-operating expense for the three and nine months ended September 30, 2008.

Income taxes

Income tax expense increased $37 million, or 22%, to $205 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. The Company’s effective tax rates were 33% and 32% for the three months ended September 30, 2009 and 2008, respectively.

Income tax expense decreased $240 million, or 33%, to $485 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. The Company’s effective tax rates were 26% and 28% for the nine months ended September 30, 2009 and 2008, respectively.

The net increase in the effective tax rate for the three months ended September 30, 2009 compared to the same period in 2008 was primarily due to tax benefit recorded in 2008 on the treatment of unrealized foreign currency losses on U.S. Dollar denominated debt held by certain of our Brazilian subsidiaries.

The net decrease in the effective tax rate for the nine months ended September 30, 2009 compared to the same period in 2008 was primarily due to a tax benefit recorded in 2009 upon the release of valuation allowance at a U.S. and a Brazilian subsidiary and the increase in U.S. taxes on distributions from the Company’s primary holding company to facilitate early retirement of Parent Company debt in the second quarter of 2008, offset by the impact of the non-taxable Kazakhstan transactions in 2008 and 2009. See further discussion about the Kazakhstan transactions in Item 1. — Financial Statements, Note 14 — Acquisitions and Dispositions in the condensed consolidated financial statements included in this Form 10-Q.

Net equity in earnings of affiliates

Net equity in earnings of affiliates increased $22 million to $18 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. The increase was primarily due to increased earnings of equity investees at Gener and Chigen due to decreased cost of coal, increased tariff at Chigen affiliates, and a reduction of net losses at our affiliates in Turkey.

Net equity in earnings of affiliates increased $37 million, or 97%, to $75 million for the nine months ended September 30, 2009. The increase was primarily due to a cash settlement received by Cartagena, in Spain, in June 2009 for liquidated damages, including legal costs incurred, related to a construction delay from December 2005 to November 2006, increased earnings of equity investees at Chigen and Gener, and a reduction of net losses at our affiliates in Turkey, as mentioned above. These increases were partially offset by decreased earnings at OPGC in India, mainly due to lower tariff and lower earnings at AES Barry Ltd due to a settlement payment received in 2008.

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Net income attributable to noncontrolling interests

Net income attributable to noncontrolling interests increased $41 million, or 19%, to $255 million for the three months ended September 30, 2009 compared to the same period in 2008 primarily due to increased earnings at our businesses in Brazil, Gener, and Sonel in Cameroon, as well as the impact of an increase in noncontrolling interests from 20% to 29% as a result of the sale of shares at Gener in November 2008. These increases were partially offset by decreased earnings at Itabo in the Dominican Republic.

Net income attributable to noncontrolling interests increased $120 million, or 19%, to $766 million for the nine months ended September 30, 2009 compared to the same period in 2008. In addition to the items mentioned above, the increase was primarily due to increased earnings at Pak Gen in Pakistan, Merida in Mexico and our businesses in the Philippines and Jordan. These increases were partially offset by decreased earnings at Ras Laffan, Itabo and our businesses in Panama, and depreciation of the Brazilian Real.

Liquidity and Capital Resources

Overview

The AES Corporation is a holding company whose operations are conducted through its subsidiaries. As of September 30, 2009, the Company had unrestricted cash and cash equivalents of $2.0 billion and short term investments of $1.4 billion. In addition, we had restricted cash and debt service reserves of $1.2 billion. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $14.2 billion and $5.5 billion, respectively. Of the total $1.4 billion of our short-term non-recourse debt currently outstanding, $1.3 billion is presented as current because it is due in the next twelve months and $53 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 $214 million of our recourse debt matures within the next twelve months, which we expect to repay primarily using liquidity of the Company or cash provided by operating activities.

The Company has two types of debt reported on its balance sheet: non-recourse and recourse debt. Non-recourse debt is used to fund investments and capital expenditures for construction and acquisition of our electric power plants, wind projects and distribution facilities at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. The default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries. Recourse debt is direct borrowings by the Parent Company and is used to fund development, construction or acquisition, including funding for equity investments or provide loans to the Parent Company’s subsidiaries or affiliates. This Parent Company debt is with recourse to the Parent Company and is structurally subordinated to the debt of the Parent Company’s subsidiaries or affiliates, except to the extent such subsidiaries or affiliates guarantee the Parent Company’s debt.

We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. 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 of the revenue expected to be 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 7 — Long-term Debt of the condensed consolidated financial statements included in Item 1. — Financial Statements, of this Form 10-Q.

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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 and senior unsecured credit facilities. On a consolidated basis, of the Company’s $19.7 billion of total debt outstanding as of September 30, 2009, approximately $3.7 billion bore interest at variable rates that were not subject to derivative instruments 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 September 30, 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 $446 million in aggregate (excluding investment commitments and those collateralized by letters of credit).

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 September 30, 2009, the Parent Company had $192 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 senior secured and senior unsecured credit facilities. During the third quarter, the Company paid letter of credit fees ranging from 3.17% to 8.36% 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 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 Global Recession 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

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and other commitments during the 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.

As of September 30, 2009, the Company has approximately $299 million of trade accounts receivable related to some of its generation businesses in Latin America classified as other long-term assets. These consist primarily of trade accounts receivable that pursuant to amended agreements or government resolutions have collection periods that extend beyond September 30, 2010, or one year past the balance sheet date. All payments are being received as scheduled and the Company expects all of these receivables to be fully collectible. Additionally, the current portion of these trade accounts receivable was $136 million at September 30, 2009.

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.

On September 15, 2009, the Company filed a registration statement on Form S-3 with the SEC which will allow the Company to quickly access the capital markets to sell any of a variety of debt and/or equity securities in order to fund refinancings, new investments such as development projects and/or acquisitions, working capital or general corporate purposes. The Form S-3 may also be used to register the resale of securities offered in a private offering of securities.

Cash Flows

At September 30, 2009, cash and cash equivalents increased $1.1 billion from December 31, 2008 to $2.0 billion. The increase in cash and cash equivalents was due to $1.9 billion of cash provided by operating activities, $1.0 billion of cash used for investing activities, $243 million of cash provided by financing activities and the favorable effect of foreign currency exchange rates on cash of $19 million.

At September 30, 2008, cash and cash equivalents decreased by $339 million from December 31, 2007 to $1.7 billion. The decrease in cash and cash equivalents was due to $1.6 billion of cash provided by operating activities, $2.4 billion of cash used for investing activities, $562 million of cash provided by financing activities and the unfavorable effect of foreign currency exchange rates on cash of $50 million.

Operating Activities

Net cash provided by operating activities increased $312 million, or 20%, to $1.9 billion for the nine months ended September 30, 2009 from $1.6 billion for the same period in 2008. This increase was partially due to an increase of approximately $243 million at our Latin America Generation businesses primarily due to reduced working capital requirements, $215 million at our Asia Generation businesses primarily due to improved working capital management and improved operating performance of $92 million at IPALCO in North America primarily due to a decrease in regulatory assets and $66 million in our Europe Generation segment primarily due to the collection of the $80 million Kazakhstan management performance incentive bonus in the first quarter 2009. These increases were partially offset by a decrease in net cash provided by operating activities at our Latin America Utilities businesses of approximately $314 million primarily due to lower cash earnings, increased working capital requirements including the payment on the settlement of a swap agreement and increased payments related to the settlement of contingencies and energy purchases, offset by the $62 million recovery of a municipal receivable at our Brazil business.

Investing Activities

Net cash used in investing activities decreased $1.4 billion to net cash used of $1.0 billion for the nine months ended September 30, 2009 from net cash used of $2.4 billion for nine months ended September 30, 2008. This decrease was primarily attributable to the following:

Capital expenditures decreased $198 million, or 10% to $1.8 billion for the nine months ended September 30, 2009 from $2.0 billion for the nine months ended September 30, 2008. This was mainly due to an

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overall decrease in expenditures of $179 million for our U.S. wind generation projects, $156 million at Maritza in Bulgaria, $113 million in Brazil, and $94 million in Panama. These decreases were partially offset by increased expenditures of $234 million related to wind generation projects in Europe and $105 million for plant construction at Gener.

Acquisitions, net of cash acquired were $1.1 billion for the nine months ended September 30, 2008, due to the purchase of a coal-fired thermal power generation facility at Masinloc in the Philippines and the purchase of Mountain View, a wind generation facility in the U.S. No acquisitions were completed for the nine months ended September 30, 2009.

Proceeds from the sales of businesses decreased $1.1 billion to $2 million for the nine months ended September 30, 2009 from $1.1 billion for the same period in 2008. The 2008 activity was primarily attributable to the sale of Ekibastuz and Maikuben in Kazakhstan in May 2008.

The sale of short-term investments, net of purchases, increased $644 million to $503 million net sales of short-term investments for the nine months ended September 30, 2009 from $141 million net purchase of short-term investments for the nine months ended September 30, 2008. The activity included increases in net sales of $238 million, $175 million and $46 million at Brasiliana Energia, Tiete, and Eletropaulo respectively, all located in Brazil, to fund interest and dividend payments. In addition, there was an increase in net sales of $130 million at Alicura in Argentina due to maturities of investments and an increase in net sales of $74 million at IPALCO as a result of IPL’s variable rate demand notes being successfully remarketed.

Restricted cash balances decreased $272 million for the nine months ended September 30, 2009, primarily due to decreases of $216 million at Gener from the use of the proceeds raised in the fourth quarter of 2008 that were restricted to use only for the purchase of additional shares in the first quarter of 2009 to fund future construction, $72 million at Chigen used for debt repayment, and $41 million at New York.

Debt service reserves and other assets decreased $80 million for the nine months ended September 30, 2009 primarily due to decreases of $84 million at wind generation projects in Europe and $37 million at Eletropaulo. These decreases were offset by an increase of $43 million at Gener.

Cash used in advances to affiliate and equity investments was $137 million for the nine months ended September 30, 2009, primarily driven by contributions made to AES Solar. Loan advances were $173 million for the nine months ended September 30, 2008 and represented amounts paid for a convertible loan from a Brazilian wind development business. There were no loan advances made in the nine months ended September 30, 2009.

Financing Activities

Net cash provided by financing activities decreased $319 million to $243 million for the nine months ended September 30, 2009 compared to net cash provided of $562 million for the nine months ended September 30, 2008. As discussed below, this decrease was primarily attributable to a decrease in contributions from noncontrolling interests of $332 million, an increase in distributions to noncontrolling interests of $111 million, a net decrease in debt balances, net of repayments of $21 million, offset by a decrease in purchases of treasury stock of $143 million.

Net repayments under revolving credit facilities were $96 million for the nine months ended September 30, 2009, compared to net borrowings of $382 million for the nine months ended September 30, 2008. The increase in net repayments of $478 million was primarily due to increased net repayments of $205 million at the Parent Company, $197 million at Lal Pir/Pak Gen in Pakistan due to off-taker collections, and $71 million at Panama for project financing.

Issuances of recourse and non-recourse debt for the nine months ended September 30, 2009 were $1.7 billion compared to $2.5 billion for the nine months ended September 30, 2008. This decrease in debt issuances

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of $841 million was primarily due to a decrease of $602 million at Masinloc where the 2008 activity was for acquisition and improvement related costs, $296 million at IPALCO due to refinancing of debt, $219 million at Buffalo Gap 3 in Texas due to completion of construction, and $122 million at the Parent Company from decreased bond issuances. These decreases were offset by an increase of $183 million at Gener due to bond issuances and construction financing.

Repayments of recourse and non-recourse debt for the nine months ended September 30, 2009 were $776 million compared to $2.1 billion for the nine months ended September 30, 2008. This decrease of $1.3 billion was predominately due to decreases in repayments of recourse debt of $883 million at the Parent Company and $257 million at IPL due to debt refinancing.

Distributions to noncontrolling interests increased $111 million to $561 million for the nine months ended September 30, 2009 from $450 million for the nine months ended September 30, 2008. The increase was primarily due to increased distributions of $129 million at Brasiliana Energia, $13 million at Tiete and $12 million at Gener. These increases were partially offset by a decrease in distributions of $26 million at Panama.

Contributions from noncontrolling interests decreased $332 million to $75 million for the nine months ended September 30, 2009 from $407 million for the nine months ended September 30, 2008. The decrease was primarily due to decreases of $240 million at Buffalo Gap 3, $78 million at Mountain View and $22 million at Masinloc. These decreases were offset by an increase of $19 million at Gener.

Financed capital expenditures decreased $25 million to $27 million for the nine months ended September 30, 2009 from $52 million for the nine months ended September 30, 2008, predominately due to a decrease of $36 million at Gener, partially offset by an increase of $6 million at Kilroot.

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.

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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 September 30, 2009 and December 31, 2008 as follows:

Parent Company Liquidity	September 30, 2009		December 31, 2008
	(in millions)
Consolidated cash and cash equivalents	$	2,020	$	903
Less: Cash and cash equivalents at subsidiaries		1,313		656
Cash and cash equivalents at Parent and qualified holding companies		707		247
Borrowing available under senior secured credit facility		700		720
Borrowing available under senior unsecured credit facility (1)		1		423
Liquidity	$	1,408	$	1,390

⁽¹⁾ During the second and third quarters of 2009, the Parent Company voluntarily reduced the size of its senior unsecured credit facility by $492 million. On October 7, 2009, the Parent Company further voluntarily reduced all of the remaining commitments available under the senior unsecured credit facility and terminated the facility agreement. The outstanding letters of credit under the senior unsecured credit facility were transferred to the senior secured credit facility. Please refer to “Recourse Debt” below for further description.

The following table summarizes our Parent Company contingent contractual obligations as of September 30, 2009:

Contingent Contractual Obligations	Amount		Number of Agreements	Exposure Range for Each Agreement
	(in millions)			(in millions)
Guarantees	$	446	32	< $1 -$53
Letters of credit under the revolving credit facility		85	19	< $1 -$29
Letters of credit under the senior unsecured credit facility		107	2	< $1 -$107
Total	$	638	53

As of September 30, 2009, the Parent Company had $140 million of commitments to invest in subsidiaries with projects under construction and to purchase related equipment, excluding approximately $136 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: $45 million in 2009, $39 million in 2010 and $56 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 flows.

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

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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 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 senior secured and senior unsecured credit facilities. 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. On September 15, 2009, we filed a shelf registration statement on Form S-3 with the SEC which may be used for such transactions, or to raise funds for other transactions, such as refinancings. 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 was 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 through June 23, 2010. From June 23, 2010 through 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.

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On April 2, 2009, the Parent Company issued $535 million aggregate principal amount of 9.75% senior unsecured notes due 2016 in a private placement. The notes were priced at a discount to yield 11%. Subsequently, the Parent Company allocated a substantial portion of the proceeds to voluntarily reduce the size of its $600 million senior unsecured credit facility. At September 30, 2009, the remaining commitments under the senior unsecured credit facility were $108 million which consisted primarily of letters of credit, the majority of which supported a project under construction in Bulgaria. On October 7, 2009, the Parent Company further voluntarily reduced all of the remaining commitments available under the senior unsecured credit facility and terminated the facility agreement. The outstanding letters of credit under the senior unsecured credit facility were transferred to the senior secured credit facility.

On June 1, 2009, the Parent Company repaid at maturity all of its outstanding 9.5% senior unsecured notes at par for an aggregate principal amount of $154 million. Recourse debt as of September 30, 2009 is scheduled to reach maturity as set forth in the table below:

	Annual Maturities
	(in millions)
October 1 – December 31, 2009	$	-
2010		214
2011		466
2012		-
2013		690
Thereafter		4,142
Total recourse debt	$	5,512

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 $53 million at September 30, 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 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 of its non-recourse debt, trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities.

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On April 8, 2009, 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 are being used to meet Gener’s funding requirements for projects under construction.

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 — General and Summary of Significant Accounting Policies to the consolidated financial statements included in the Company’s 2008 Form 10-K and the September 2009 Form 8-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 Form 10-K and the September 2009 Form 8-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 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 September 30, 2009. The only significant change to our critical accounting policies and estimates is the adoption of accounting guidance for Fair value measurements and disclosures, 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.

Interest Rate Risks

We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable-rate debt and fixed-rate debt, 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 September 30, 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 $5 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

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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, Mexican Peso, Kazakhstani Tenge, British Pound, Euro, Hungarian Forint, 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.

During the third quarter, we entered into hedges to partially mitigate the exposure of earnings translated into U.S. Dollar to foreign exchange volatility. Given a 10% U.S. Dollar appreciation, AES pre-tax earnings for the balance of 2009 would be reduced by approximately $14 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 is not exhibiting the characteristics of a peg or managed float relative to the U.S. Dollar, net of impact of outstanding hedges 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 and physical hedging 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 IPALCO, a 10% decline in the price of electricity as of September 30, 2009 would produce an estimated decrease in gross margin of $2 million for the balance of 2009. An increase of 10% in petroleum coke prices at Deepwater would result in a decline in projected gross margin of less than $1 million for the remainder of 2009.

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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 and 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 Item 7A. — Quantitative and Qualitative Disclosures about Market Risk — Risk Management in Part II, 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 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 VaR calculation within the commodity transaction management system, and is reported for financially settled derivative products at our Eastern Energy business in New York State and Deepwater in Texas as these are the only businesses with commodity transactions that are deemed derivatives. These commodity transactions are marked to market on a daily basis. Collateral is then posted or recalled for any changes in exposures at Eastern Energy but is not required at Deepwater. However, not every transaction requires Eastern Energy to post collateral, as several counterparties have caps defined in their transaction agreements. For those counterparties that do require Eastern Energy 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 September 30, 2009, $19 million and $77 million have been utilized under these facilities.

The VaR as of September 30, 2009 for foreign exchange rate-sensitive instruments was $58 million compared with $78 million as of June 30, 2009. These amounts include foreign currency denominated debt and hedge instruments. The decrease in VaR is primarily due to lower volatilities particularly for the Euro, British Pound and Brazilian Real.

The VaR as of September 30, 2009 for interest rate-sensitive instruments was $129 million compared with $155 million as of June 30, 2009. These amounts include the financial instruments that serve as hedges and the underlying hedged items. The decrease in VaR relative to the second quarter is attributable to the decrease in volatility in interest rates.

The VaR as of September 30, 2009 for commodity price-sensitive instruments was $7 million compared with $4 million as of June 30, 2009. For Eastern Energy, 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 VaR for Eastern Energy was $7 million compared to $4 million for the second quarter. This

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increase in VaR is driven by the higher volume hedged in the portfolio. For Deepwater, the reported VaR includes the physically settled derivative products that serve as hedges. Third quarter VaR was $590,000 compared to $800,000 in the second quarter. This decrease is mainly due to a lower volume of hedged MWhs.

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 September 30, 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

The evaluation discussed above identified a material change in the Company’s internal control over financial reporting as of September 30, 2009. The Company completed the implementation of a new financial reporting consolidation system that enhanced the integration and reporting of our consolidated financial information. The Company will continue to monitor the internal control structure over financial reporting ensuring that the design is proper and operating effectively. To date, the Company has not experienced any negative impact on our internal control structure over financial reporting. There were no other changes in the Company’s internal controls over financial reporting that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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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 8 — Contingencies and Commitments of the condensed consolidated financial statements included in Item 1. — Financial Statements 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 September 30, 2009. See Note 8 — Contingencies and Commitments of the condensed consolidated financial statements included in Item 1. — Financial Statements, 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

None.

ITEM 5.    OTHER INFORMATION

None

ITEM 6.    EXHIBITS

3.1	Amended and Restated By-Laws of The AES Corporation is incorporated herein by reference to Exhibit 3.1 of the Company’s Form 8-K filed on August 11, 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)/15d-14(b) of the Exchange Act.
32.2	Certification of principal financial officer required by Rule 13a-14(b)/15d-14(b) of the Exchange Act.
101	The following materials from The AES Corporation’s Quarterly Report on Form 10-Q for the interim period ended September 30, 2009 formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Balance Sheets, (iii) the Condensed Consolidated Statements of Cash Flows, (iv) the Condensed Consolidated Statements of Changes in Equity, (v) the Notes to the Condensed Consolidated Financial Statements, tagged as block text.

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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: November 5, 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)

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