10-Q

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, 2011

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 October 28, 2011 was 767,548,237.

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011

TABLE OF CONTENTS

PART I: FINANCIAL INFORMATION		1
ITEM 1.	FINANCIAL STATEMENTS	1
	Condensed Consolidated Statements of Operations	1
	Condensed Consolidated Balance Sheets	2
	Condensed Consolidated Statements of Cash Flows	3
	Condensed Consolidated Statements of Changes in Equity	4
	Notes to Condensed Consolidated Financial Statements	5
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	51
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	101
ITEM 4.	CONTROLS AND PROCEDURES	103
PART II: OTHER INFORMATION		104
ITEM 1.	LEGAL PROCEEDINGS	104
ITEM 1A.	RISK FACTORS	113
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	113
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	113
ITEM 4.	REMOVED AND RESERVED	113
ITEM 5.	OTHER INFORMATION	113
ITEM 6.	EXHIBITS	114

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,
	2011			2010			2011			2010
	(in millions, except per share amounts)
Revenue:
Regulated	$	2,405		$	2,244		$	7,228		$	6,642
Non-Regulated		1,976			1,746			5,889			5,135
Total revenue		4,381			3,990			13,117			11,777
Cost of Sales:
Regulated		(1,743	)		(1,638	)		(5,435	)		(4,918	)
Non-Regulated		(1,618	)		(1,385	)		(4,663	)		(3,958	)
Total cost of sales		(3,361	)		(3,023	)		(10,098	)		(8,876	)
Gross margin		1,020			967			3,019			2,901
General and administrative expenses		(91	)		(98	)		(283	)		(279	)
Interest expense		(432	)		(381	)		(1,178	)		(1,151	)
Interest income		103			96			293			304
Other expense		(76	)		(23	)		(131	)		(83	)
Other income		58			17			108			94
Gain on sale of investments		-			-			7			-
Goodwill impairment		(17	)		(18	)		(17	)		(18	)
Asset impairment expense		(163	)		(296	)		(196	)		(297	)
Foreign currency transaction (losses) gains on net monetary position		(92	)		103			(21	)		(19	)
Other non-operating expense		(82	)		(2	)		(82	)		(7	)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES		228			365			1,519			1,445
Income tax expense		(84	)		(102	)		(469	)		(540	)
Net equity in earnings of affiliates		6			26			12			174
INCOME FROM CONTINUING OPERATIONS		150			289			1,062			1,079
Income from operations of discontinued businesses, net of income tax (benefit) expense of $(31), $8, $(33) and $23, respectively		25			29			23			92
Gain from disposal of discontinued businesses, net of income tax expense of $0, $38, $0 and $38, respectively		-			79			-			57
NET INCOME		175			397			1,085			1,228
Noncontrolling interests:
Less: Income from continuing operations attributable to noncontrolling interests		(269	)		(248	)		(766	)		(725	)
Less: Income from discontinued operations attributable to noncontrolling interests		(37	)		(35	)		(52	)		(58	)
Total net income attributable to noncontrolling interests		(306	)		(283	)		(818	)		(783	)
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	$	(131	)	$	114		$	267		$	445
BASIC EARNINGS PER SHARE:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	(0.15	)	$	0.05		$	0.38		$	0.46
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		(0.02	)		0.09			(0.04	)		0.12
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	(0.17	)	$	0.14		$	0.34		$	0.58
DILUTED EARNINGS PER SHARE:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	(0.15	)	$	0.05		$	0.38		$	0.46
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		(0.02	)		0.09			(0.04	)		0.12
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	(0.17	)	$	0.14		$	0.34		$	0.58
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income (loss) from continuing operations, net of tax	$	(119	)	$	41		$	296		$	354
Discontinued operations, net of tax		(12	)		73			(29	)		91
Net income (loss)	$	(131	)	$	114		$	267		$	445

See Notes to Condensed Consolidated Financial Statements

1

THE AES CORPORATION

Condensed Consolidated Balance Sheets

	September 30, 2011			December 31, 2010
	(in millions, except share and per share data)
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,392		$	2,550
Restricted cash		795			502
Short-term investments		1,053			1,718
Accounts receivable, net of allowance for doubtful accounts of $293 and $304, respectively		2,364			2,301
Inventory		668			561
Receivable from affiliates		28			27
Deferred income taxes — current		278			305
Prepaid expenses		190			223
Other current assets		1,128			1,036
Current assets of discontinued and held for sale businesses		171			223
Total current assets		10,067			9,446
NONCURRENT ASSETS
Property, Plant and Equipment:
Land		1,029			1,126
Electric generation, distribution assets and other		29,945			27,929
Accumulated depreciation		(9,257	)		(9,048	)
Construction in progress		2,096			4,454
Property, plant and equipment, net		23,813			24,461
Other Assets:
Investments in and advances to affiliates		1,401			1,320
Debt service reserves and other deposits		909			653
Goodwill		1,246			1,271
Other intangible assets, net of accumulated amortization of $153 and $157, respectively		493			511
Deferred income taxes — noncurrent		585			646
Other		2,133			1,958
Noncurrent assets of discontinued and held for sale businesses		236			245
Total other assets		7,003			6,604
TOTAL ASSETS	$	40,883		$	40,511
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	1,792		$	2,048
Accrued interest		395			257
Accrued and other liabilities		2,619			2,633
Non-recourse debt — current, including $269 and $1,150, respectively, related to variable interest entities		2,163			2,567
Recourse debt — current		11			463
Current liabilities of discontinued and held for sale businesses		261			97
Total current liabilities		7,241			8,065
LONG-TERM LIABILITIES
Non-recourse debt — noncurrent, including $2,168 and $2,199, respectively, related to variable interest entities		12,523			12,371
Recourse debt — noncurrent		6,181			4,149
Deferred income taxes — noncurrent		621			895
Pension and other post-retirement liabilities		1,310			1,511
Other long-term liabilities		2,978			2,812
Long-term liabilities of discontinued and held for sale businesses		112			235
Total long-term liabilities		23,725			21,973
Contingencies and Commitments (see Note 9)
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; 807,093,084 issued and 770,260,308 outstanding at September 30, 2011 and 804,894,313 issued and 787,607,240 outstanding at December 31, 2010		8			8
Additional paid-in capital		8,499			8,444
Retained earnings		887			620
Accumulated other comprehensive loss		(2,727	)		(2,383	)
Treasury stock, at cost (36,832,776 shares at September 30, 2011 and 17,287,073 shares at December 31, 2010, respectively)		(434	)		(216	)
Total The AES Corporation stockholders’ equity		6,233			6,473
NONCONTROLLING INTERESTS		3,624			3,940
Total equity		9,857			10,413
TOTAL LIABILITIES AND EQUITY	$	40,883		$	40,511

See Notes to Condensed Consolidated Financial Statements

2

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(in millions)
OPERATING ACTIVITIES:
Net income	$	1,085		$	1,228
Adjustments to net income:
Depreciation and amortization		947			876
Loss from sale of investments and impairment expense		321			350
(Gain) loss on disposal and impairment write-down — discontinued operations		1			(102	)
Provision for deferred taxes		(67	)		31
Contingencies		36			75
Loss on the extinguishment of debt		52			9
Undistributed gain from sale of equity method investment		-			(118	)
Other		65			(81	)
Changes in operating assets and liabilities:
Increase in accounts receivable		(185	)		(136	)
(Increase) decrease in inventory		(118	)		9
Decrease in prepaid expenses and other current assets		62			194
Increase in other assets		(167	)		(51	)
Increase in accounts payable and accrued liabilities		200			4
Increase (decrease) in income taxes and other income tax payables, net		(151	)		20
Increase in other liabilities		227			108
Net cash provided by operating activities		2,308			2,416
INVESTING ACTIVITIES:
Capital expenditures		(1,832	)		(1,528	)
Acquisitions — net of cash acquired		(158	)		(237	)
Proceeds from the sale of businesses		47			369
Proceeds from the sale of assets		89			11
Sale of short-term investments		4,191			4,583
Purchase of short-term investments		(3,632	)		(4,540	)
Increase in restricted cash		(164	)		(82	)
Increase in debt service reserves and other assets		(379	)		(9	)
Affiliate advances and equity investments		(91	)		(77	)
Proceeds from loan repayments		-			132
Proceeds from performance bond		199			-
Other investing		(4	)		31
Net cash used in investing activities		(1,734	)		(1,347	)
FINANCING ACTIVITIES:
Issuance of common stock		-			1,566
Borrowings under the revolving credit facilities, net		126			74
Issuance of recourse debt		2,050			-
Issuance of non-recourse debt		1,516			1,497
Repayments of recourse debt		(474	)		(619	)
Repayments of non-recourse debt		(1,489	)		(1,441	)
Payments for financing fees		(153	)		(50	)
Distributions to noncontrolling interests		(990	)		(951	)
Contributions from noncontrolling interests		6			-
Financed capital expenditures		(13	)		(21	)
Purchase of treasury stock		(225	)		(15	)
Other financing		(7	)		(18	)
Net cash provided by financing activities		347			22
Effect of exchange rate changes on cash		(79	)		(21	)
Total increase in cash and cash equivalents		842			1,070
Cash and cash equivalents, beginning		2,550			1,775
Cash and cash equivalents, ending	$	3,392		$	2,845
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	982		$	1,003
Cash payments for income taxes, net of refunds	$	647		$	589

See Notes to Condensed Consolidated Financial Statements

3

THE AES CORPORATION

Condensed Consolidated Statements of Changes in Equity

(Unaudited)

	THE AES CORPORATION STOCKHOLDERS
	Common Stock		Treasury Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Consolidated Comprehensive Income
	(in millions)
Balance at January 1, 2011	$	8	$	(216	)	$	8,444	$	620		$	(2,383	)	$	3,940
Net income		-		-			-		267			-			818		$	1,085
Change in fair value of available-for-sale securities, net of income tax		-		-			-		-			(3	)		-			(3	)
Foreign currency translation adjustment, net of income tax		-		-			-		-			(178	)		(149	)		(327	)
Change in unfunded pensions obligation, net of income tax		-		-			-		-			4			8			12
Change in derivative fair value, including a reclassification to earnings, net of income tax		-		-			-		-			(167	)		(26	)		(193	)
Other comprehensive income																		(511	)
Total comprehensive income																	$	574
Capital contributions from noncontrolling interests		-		-			-		-			-			9
Distributions to noncontrolling interests		-		-			-		-			-			(990	)
Disposition of businesses		-		-			-		-			-			(2	)
Acquisition of treasury stock		-		(225	)		-		-			-			-
Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax		-		7			20		-			-			-
Stock compensation		-		-			16		-			-			-
Net gain on sale of subsidiary shares to noncontrolling interests		-		-			19		-			-			-
Sale of subsidiary shares to noncontrolling interests		-		-			-		-			-			16
Balance at September 30, 2011	$	8	$	(434	)	$	8,499	$	887		$	(2,727	)	$	3,624
	THE AES CORPORATION STOCKHOLDERS
	Common Stock		Treasury Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Consolidated Comprehensive Income
	(in millions)
Balance at January 1, 2010	$	7	$	(126	)	$	6,868	$	650		$	(2,724	)	$	4,205
Net income		-		-			-		445			-			783		$	1,228
Change in fair value of available-for-sale securities, net of income tax		-		-			-		-			(6	)		-			(6	)
Foreign currency translation adjustment, net of income tax		-		-			-		-			465			54			519
Change in unfunded pensions obligation, net of income tax		-		-			-		-			3			3			6
Change in derivative fair value, including a reclassification to earnings, net of income tax		-		-			-		-			(204	)		(51	)		(255	)
Other comprehensive income																		264
Total comprehensive income																	$	1,492
Cumulative effect of consolidation of entities under variable interest entity accounting guidance		-		-			-		(47	)		(38	)		15
Cumulative effect of deconsolidation of entities under variable interest entity accounting guidance		-		-			-		1			-			-
Capital contributions from noncontrolling interests		-		-			-		-			-			30
Distributions to noncontrolling interests		-		-			-		-			-			(1,068	)
Disposition of businesses		-		-			-		-			-			(78	)
Acquisition of treasury stock		-		(15	)		-		-			-			-
Issuance of common stock		1		-			1,566		-			-			-
Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax		-		9			10		-			-			-
Stock compensation		-		-			18		-			-			-
Changes in the carrying amount of redeemable stock of subsidiaries		-		-			-		7			-			-
Balance at September 30, 2010	$	8	$	(132	)	$	8,462	$	1,056		$	(2,504	)	$	3,893

See Notes to Condensed Consolidated Financial Statements

4

THE AES CORPORATION

Notes to Condensed Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 2011 and 2010

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 businesses held for sale and discontinued operations as discussed in Note 16 — Discontinued Operations and Held for Sale Businesses.

On June 1, 2011, The AES Corporation filed a Current Report on Form 8-K (“June 2011 Form 8-K”) to recast previously filed financial statements and other information included in the Company’s Form 10-K for the year ended December 31, 2010 (“2010 Form 10-K”) to reclassify certain businesses held for sale as discussed in Note 16 — Discontinued Operations and Held for Sale Businesses. The updates to the 2010 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, respectively. All other information in the 2010 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 a variable 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.

AES Thames, LLC (“Thames”), a 208 MW coal–fired plant in Connecticut, filed petitions for bankruptcy protection under Chapter 11 in the U.S. Bankruptcy Court on February 1, 2011. Effective that date, the Company lost control of the business and is no longer able to exercise significant influence over its operating and financial policies. In accordance with the accounting guidance on consolidations, Thames was deconsolidated in February 2011 and is now accounted for as a cost method investment. At the time of deconsolidation, Thames had total assets and total liabilities of $158 million and $170 million, respectively. Subsequently, the Company paid $5 million in satisfaction of a pre-existing guarantee. A net gain of $7 million has been deferred pending the completion of the bankruptcy proceedings.

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, for interim financial information and Article 10 of Regulation S-X issued by the U.S. 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, 2011 are not necessarily indicative of results that may be expected for the year ending December 31, 2011. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2010 audited consolidated financial statements and notes thereto, which are included in the June 2011 Form 8-K.

5

Change in Estimate

On January 1, 2011, the Company changed its estimates related to depreciation of property, plant and equipment at its Brazilian concessionary utility and generation businesses. Based on recent information received from regulators, the depreciation rates and salvage values for its concession assets were adjusted on a prospective basis to reflect a remuneration basis, which equates to the reimbursement expected by the Company at the end of the respective concession periods. For the three months ended September 30, 2011, the impact to the condensed consolidated statement of operations was an increase in depreciation expense of $17 million and a decrease in net income attributable to The AES Corporation of $5 million, or $0.01 per share. For the nine months ended September 30, 2011, the impact to the condensed consolidated statement of operations was an increase in depreciation expense of $52 million and a decrease in net income attributable to The AES Corporation of $14 million, or $0.02 per share.

New Accounting Policies Adopted

Accounting Standards Update (“ASU”) No. 2009-13, Revenue Recognition (Topic 605), “Multiple-Deliverable Revenue Arrangements”

In October 2009, the FASB issued ASU No. 2009-13, which amended the accounting guidance related to revenue recognition. The amended guidance provides primarily two changes to the prior guidance for multiple-element revenue arrangements. The first eliminated the requirement that there be “objective and reliable evidence” of fair value for any undelivered items in order for a delivered item to be treated as a separate unit of accounting. The second required that the consideration from multiple-element revenue arrangements be allocated to all the deliverables based on their relative selling price at the inception of the arrangement. AES adopted the standard on January 1, 2011. AES elected prospective adoption and applied the revised guidance to all revenue arrangements entered into or materially modified after the date of adoption. The adoption of ASU No. 2009-13 did not have a material impact on the financial position and results of operations of AES and is not expected to have a material impact in future periods.

ASU No. 2010-28, Intangibles — Goodwill and Other (Topic 350), “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”

In December 2010, the FASB issued ASU No. 2010-28, which amended the accounting guidance related to goodwill. The amendment modified Step One of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step Two of the goodwill impairment test if it is more likely than not that a goodwill impairment exists, eliminating an entity’s ability to assert that a reporting unit is not required to perform Step Two because the carrying amount of the reporting unit is zero or negative, despite the existence of qualitative factors that indicate the goodwill is more likely than not impaired. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. The Company adopted ASU No. 2010-28 on January 1, 2011. The adoption did not have any impact on the Company as none of its reporting units with goodwill has a zero or negative carrying amount.

ASU No. 2011-2, Receivables (Topic 310), “A Creditor’s Determination of Whether a Restructuring Is a Troubled Debt Restructuring”

In April 2011, the FASB issued ASU No. 2011-2, which provides additional guidance and clarification to help creditors determine whether a creditor has granted a concession and whether a debtor is experiencing financial difficulties for purposes of determining whether a restructuring constitutes a troubled debt restructuring. The Company adopted ASU No. 2011-2 on July 1, 2011. The adoption did not have any impact on the Company’s financial position, results of operations or cash flows.

6

ASU No. 2011-8, Intangibles — Goodwill and Other (Topic 350), “Testing Goodwill for Impairment”

In September 2011, the FASB issued ASU No. 2011-8, which amends the existing guidance for goodwill impairment testing. Under the amendments in ASU No. 2011-8, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after this qualitative assessment, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. Also, an entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. The amendments do not change the existing accounting guidance on how Step 1 and Step 2 of the goodwill impairment test are performed. In addition, an entity is no longer permitted to carry forward its detailed calculation of a reporting unit’s fair value from a prior year as previously permitted under the existing guidance. ASU No. 2011-8 is effective for annual and interim goodwill impairment tests performed for fiscal periods beginning on or after December 15, 2011 and early adoption is permitted. AES elected to early adopt ASU No. 2011-8 for its annual goodwill impairment evaluations, which are performed at October 1 each year. The adoption is not expected to have a material impact on the Company’s financial position, results of operations or cash flows in current or future periods.

Accounting Pronouncements Issued But Not Yet Effective

As of September 30, 2011, the following accounting standards have been issued, but are not yet effective for, and have not been adopted by AES.

ASU No. 2011-4, Fair Value Measurements (Topic 820), “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS”

In May 2011, the FASB issued ASU No. 2011-4, which among other requirements, prohibits the use of the block discount factor for all fair value level hierarchies; permits an entity to measure the fair value of its financial instruments on a net basis when the related market risks are managed on a net basis; states the highest and best use concept is no longer relevant in the measurement of financial assets and liabilities; clarifies that a reporting entity should disclose quantitative information about the unobservable inputs used in Level 3 measurements and that the application of premiums and discounts is related to the unit of account for the asset or liability being measured at fair value; and requires expanded disclosures to describe the valuation process used for Level 3 measurements and the sensitivity of Level 3 measurements to changes in unobservable inputs. In addition, entities are required to disclose the hierarchy level for items which are not measured at fair value in the statement of financial position, but for which fair value is required to be disclosed. ASU No. 2011-4 is effective for the first interim or annual period beginning on or after December 15, 2011, or January 1, 2012 for AES. The adoption is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

2. INVENTORY

The following table summarizes the Company’s inventory balances as of September 30, 2011 and December 31, 2010:

	September 30, 2011		December 31, 2010
	(in millions)
Coal, fuel oil and other raw materials	$	377	$	276
Spare parts and supplies		291		285
Total	$	668	$	561

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3. FAIR VALUE

The fair value of current financial assets and liabilities, debt service reserves and other deposits approximates their reported carrying amounts. The fair value of non-recourse debt is estimated based upon the type of loan. The fair value of variable rate loans generally approximates their carrying amounts. For fixed rate loans, fair value is estimated using quoted market prices or discounted cash flow analyses. See Note 8 — Debt for additional information on the fair value and carrying value of debt. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards, swaps and options and energy derivatives is the estimated net amount that the Company would receive or pay to sell or transfer the agreements as of the balance sheet date.

The estimated fair values of the Company’s assets and liabilities have been determined using available market information. By virtue of these amounts being estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

The following table summarizes the carrying amount and fair value of certain of the Company’s financial assets and liabilities as of September 30, 2011 and December 31, 2010:

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Assets
Marketable securities	$	1,093	$	1,093	$	1,767	$	1,767
Derivatives		117		117		124		124
Total assets	$	1,210	$	1,210	$	1,891	$	1,891
Liabilities
Debt	$	20,878	$	21,101	$	19,550	$	20,137
Derivatives		688		688		423		423
Total liabilities	$	21,566	$	21,789	$	19,973	$	20,560

Valuation Techniques:

The fair value measurement accounting guidance describes three main approaches to measuring the fair value of assets and liabilities: (1) market approach; (2) income approach and (3) cost approach. The market approach uses prices and other relevant information generated from market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future amounts to a single present value amount. The measurement is based on current market expectations of the return on those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company measures its investments and derivatives at fair value on a recurring basis. Additionally, in connection with annual or event-driven impairment evaluations, certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis. These include long-lived tangible assets (i.e., property, plant and equipment), goodwill and intangible assets (e.g., sales concessions, land use rights and emissions allowances, etc.). In general, the Company determines the fair value of investments and derivatives using the market approach and the income approach, respectively. In the nonrecurring measurements of nonfinancial assets and liabilities, all three approaches are considered; however, fair value estimated under the income approach is often selected.

Investments

The Company’s investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are measured at fair value using quoted market prices. Debt securities primarily

8

consist of unsecured debentures, certificates of deposit and government debt securities held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to London Inter-Bank Offered Rate, or LIBOR, a benchmark interest rate widely used by banks in the interbank lending market) or Selic (overnight borrowing rate) rates in Brazil. Fair value is determined from comparisons to market data obtained for similar assets and are considered Level 2 in the fair value hierarchy. For more detail regarding the fair value of investments see Note 4 — Investments in Marketable Securities.

Derivatives

When deemed appropriate, the Company manages its risk from interest and foreign currency exchange rate and commodity price fluctuations through the use of over-the-counter financial and physical derivative instruments. The derivatives are primarily interest rate swaps to hedge non-recourse debt to establish a fixed rate on variable rate debt, foreign exchange instruments to hedge against currency fluctuations, commodity derivatives to hedge against commodity price fluctuations and embedded derivatives associated with commodity contracts. The Company’s subsidiaries are counterparties to various over-the-counter derivatives, which include interest rate swaps and options, foreign currency options and forwards and commodity swaps. In addition, the Company’s subsidiaries are counterparties to certain power purchase agreements (“PPAs”) and fuel supply agreements that are derivatives or include embedded derivatives.

For the derivatives where there is a standard industry valuation model, the Company uses that model to estimate the fair value. For the derivatives (such PPAs and fuel supply agreements that are derivatives or include embedded derivatives) where there is not a standard industry valuation model, the Company has created internal valuation models to estimate the fair value, using observable data to the extent available. For all derivatives, the income approach is used, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The following are among the most common market data inputs used in the income approach: volatilities, spot and forward benchmark interest rates (such as LIBOR and Euro Inter Bank Offered Rate (“EURIBOR”)), foreign exchange rates and commodity prices. Forward rates and prices are generally obtained from published information provided by pricing services for an instrument with the same duration as the derivative instrument being valued. In situations where significant inputs are not observable, the Company uses relevant techniques to best estimate the inputs, such as regression analysis, Monte Carlo simulation or prices for similarly traded instruments available in the market.

For each derivative, the income approach is used to estimate the cash flows over the remaining term of the contract. Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR or EURIBOR) plus a spread that reflects the credit or nonperformance risk. This risk is estimated by the Company using credit spreads and risk premiums that are observable in the market, whenever possible, or estimated borrowing costs based on bank quotes, industry publications and/or information on financing closed on similar projects. To the extent that management can estimate the fair value of these assets or liabilities without the use of significant unobservable inputs, these derivatives are classified as Level 2.

In certain instances, the published forward rates or prices may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable inputs, such as proxy commodity prices or historical settlements to forecast forward prices. In addition, in certain instances, there may not be third party data readily available, which requires the use of unobservable inputs. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable. The fair value hierarchy of an asset or a liability is based on the level of significance of the input assumptions. An input assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are transferred to Level 3 when the use of unobservable inputs becomes significant. Similarly, when the use of unobservable input becomes insignificant for Level 3 assets and liabilities, they are transferred to Level 2.

Transfers in and out of Level 3 are from and to Level 2 and are determined as of the end of the reporting period. The Company has not had any Level 1 derivatives so there have not been any transfers between Levels 1 and 2.

9

Nonfinancial Assets and Liabilities

For nonrecurring measurements derived using the income approach, fair value is determined using valuation models based on the principles of discounted cash flows (“DCF”). The income approach is most often used in the impairment evaluation of long-lived tangible assets, goodwill and intangible assets. The Company has developed internal valuation models for such valuations; however, an independent valuation firm may be engaged in certain situations. In such situations, the independent valuation firm largely uses DCF valuation models as the primary measure of fair value though other valuation approaches are also considered. A few examples of input assumptions to such valuations include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates and power and commodity prices. Whenever possible, the Company attempts to obtain market observable data to develop input assumptions. Where the use of market observable data is limited or not possible for certain input assumptions, the Company develops its own estimates using a variety of techniques such as regression analysis and extrapolations.

For nonrecurring measurements derived using the market approach, recent market transactions involving the sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to find sale transactions of identical or similar assets. This approach is used in the impairment evaluations of certain intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.

For nonrecurring measurements derived using the cost approach, fair value is typically determined using the replacement cost approach. Under this approach, the depreciated replacement cost of assets is determined by first determining the current replacement cost of assets and then applying the remaining useful life percentages to such cost. Further adjustments for economic and functional obsolescence are made to the depreciated replacement cost. This approach involves a considerable amount of judgment, which is why its use is limited to the measurement of a few long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach. For the nine months ended September 30, 2011, the Company did not measure any nonfinancial assets under the cost approach.

Fair Value Considerations:

In determining fair value, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk of the counterparty and the risk of the Company’s or its counterparty’s nonperformance. The conditions and criteria used to assess these factors are:

Sources of market assumptions

The Company derives most of its market assumptions from market efficient data sources (e.g., Bloomberg and Platt’s). To determine fair value, where market data is not readily available, management uses comparable market sources and empirical evidence to develop its own estimates of market assumptions.

Market liquidity

The Company evaluates market liquidity based on whether the financial or physical instrument, or the underlying asset, is traded in an active or inactive market. An active market exists if the prices are fully transparent to market participants, can be measured by market bid and ask quotes, the market has a relatively large proportion of trading volume as compared to the Company’s current trading volume and the market has a significant number of market participants that will allow the market to rapidly absorb the quantity of the assets traded without significantly affecting the market price. Another factor the Company considers when determining whether a market is active or inactive is the presence of government or regulatory controls over pricing that could make it difficult to establish a market based price when entering into a transaction.

10

Nonperformance risk

Nonperformance risk refers to the risk that the obligation will not be fulfilled and affects the value at which a liability is transferred or an asset is sold. Nonperformance risk includes, but may not be limited to, the Company or counterparty’s credit and settlement risk. Nonperformance risk adjustments are dependent on credit spreads, letters of credit, collateral, other arrangements available and the nature of master netting arrangements. The Company and its subsidiaries are parties to various interest rate swaps and options; foreign currency options and forwards; and derivatives and embedded derivatives which subject the Company to nonperformance risk. The financial and physical instruments held at the subsidiary level are generally non-recourse to the Parent Company.

Nonperformance risk on the investments held by the Company is incorporated in the fair value derived from quoted market data to mark the investments to fair value.

The Company adjusts for nonperformance or credit risk on its derivative instruments by deducting a credit valuation adjustment (“CVA”). The CVA is based on the margin or debt spread of the Company’s subsidiary or counterparty and the tenor of the respective derivative instrument. The counterparty for a derivative asset position is considered to be the bank or government sponsored banking entity or counterparty to the PPA or commodity contract. The CVA for asset positions is based on the counterparty’s credit ratings and debt spreads or, in the absence of readily obtainable credit information, the respective country debt spreads are used as a proxy. The CVA for liability positions is based on the Parent Company’s or the subsidiary’s current debt spread, the margin on indicative financing arrangements, or in the absence of readily obtainable credit information, the respective country debt spreads are used as a proxy. All derivative instruments are analyzed individually and are subject to unique risk exposures.

Recurring Measurements

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, 2011 and December 31, 2010. 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.

	Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total September  30, 2011
	(in millions)
Assets
Available-for-sale securities	$	2	$	1,041	$	40	$	1,083
Trading securities		10		-		-		10
Derivatives		-		57		60		117
Total assets	$	12	$	1,098	$	100	$	1,210
Liabilities
Derivatives	$	-	$	419	$	269	$	688
Total liabilities	$	-	$	419	$	269	$	688

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	Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total December 31, 2010
	(in millions)
Assets
Available-for-sale securities	$	8	$	1,707	$	42	$	1,757
Trading securities		10		-		-		10
Derivatives		-		63		61		124
Total assets	$	18	$	1,770	$	103	$	1,891
Liabilities
Derivatives	$	-	$	411	$	12	$	423
Total liabilities	$	-	$	411	$	12	$	423

The following tables present a reconciliation of net derivative 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, 2011 and 2010 (presented net by type of derivative):

	Three Months Ended September 30, 2011
	Interest Rate			Cross Currency			Foreign Currency			Commodity and Other			Total
	(in millions)
Balance at July 1	$	(60	)	$	15		$	38		$	17		$	10
Total gains (losses) (realized and unrealized):
Included in earnings(1)		-			(3	)		4			(44	)		(43	)
Included in other comprehensive income		(36	)		(37	)		-			-			(73	)
Included in regulatory (assets) liabilities		-			-			-			(3	)		(3	)
Settlements		4			4			(1	)		(8	)		(1	)
Transfers of assets (liabilities) into Level 3(2)		(101	)		-			-			-			(101	)
Transfers of (assets) liabilities out of Level 3(2)		2			-			-			-			2
Balance at September 30	$	(191	)	$	(21	)	$	41		$	(38	)	$	(209	)
Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/(losses) relating to assets and liabilities held at the end of the period	$	-		$	(2	)	$	2		$	(52	)	$	(52	)
	Three Months Ended September 30, 2010
	Interest Rate			Cross Currency			Foreign Currency			Commodity and Other			Total
	(in millions)
Balance at July 1	$	(226	)	$	(34	)	$	18		$	19		$	(223	)
Total gains (losses) (realized and unrealized):
Included in earnings(1)		(2	)		-			-			(3	)		(5	)
Included in other comprehensive income		(63	)		24			(1	)		-			(40	)
Included in regulatory (assets) liabilities		(3	)		-			-			(2	)		(5	)
Settlements		15			1			-			(3	)		13
Transfers of assets (liabilities) into Level 3(2)		(3	)		-			-			-			(3	)
Transfers of (assets) liabilities out of Level 3(2)		26			-			-			-			26
Balance at September 30	$	(256	)	$	(9	)	$	17		$	11		$	(237	)
Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/(losses) relating to assets and liabilities held at the end of the period	$	(1	)	$	-		$	-		$	-		$	(1	)

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	Nine Months Ended September 30, 2011
	Interest Rate			Cross Currency			Foreign Currency			Commodity and Other			Total
	(in millions)
Balance at January 1	$	(1	)	$	10		$	22		$	18		$	49
Total gains (losses) (realized and unrealized):
Included in earnings(1)		-			(5	)		21			(50	)		(34	)
Included in other comprehensive income		(3	)		(34	)		-			-			(37	)
Included in regulatory (assets) liabilities		-			-			-			3			3
Settlements		-			8			(2	)		(9	)		(3	)
Transfers of assets (liabilities) into Level 3(2)		(189	)		-			-			-			(189	)
Transfers of (assets) liabilities out of Level 3(2)		2			-			-			-			2
Balance at September 30	$	(191	)	$	(21	)	$	41		$	(38	)	$	(209	)
Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/(losses) relating to assets and liabilities held at the end of the period	$	-		$	(2	)	$	18		$	(56	)	$	(40	)
	Nine Months Ended September 30, 2010
	Interest Rate			Cross Currency			Foreign Currency			Commodity and Other			Total
	(in millions)
Balance at January 1	$	(12	)	$	(12	)	$	-		$	24		$	-
Total gains (losses) (realized and unrealized):
Included in earnings(1)		1			4			19			1			25
Included in other comprehensive income		(20	)		(5	)		-			-			(25	)
Included in regulatory (assets) liabilities		(6	)		-			-			2			(4	)
Settlements		6			4			(1	)		(16	)		(7	)
Transfers of assets (liabilities) into Level 3(2)		(251	)		-			(1	)		-			(252	)
Transfers of (assets) liabilities out of Level 3(2)		26			-			-			-			26
Balance at September 30	$	(256	)	$	(9	)	$	17		$	11		$	(237	)
Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/(losses) relating to assets and liabilities held at the end of the period	$	(2	)	$	5		$	20		$	(10	)	$	13

⁽¹⁾  The gains (losses) included in earnings for these Level 3 derivatives are classified as follows: interest rate and cross currency derivatives as interest expense, foreign currency derivatives as foreign currency transaction gains (losses) and commodity and other derivatives as either non-regulated revenue, non-regulated cost of sales, or other expense. 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.

⁽²⁾  Transfers in and out of Level 3 are determined as of the end of the reporting period and are from and to Level 2, as the Company has no Level 1 derivative assets or liabilities. The (assets) liabilities transferred out of Level 3 are primarily the result of a decrease in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments. Similarly, the assets (liabilities) transferred into Level 3 are primarily the result of an increase in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments.

13

The following table presents a reconciliation of available-for-sale securities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011			2010
	(in millions)
Balance at beginning of period(1)	$	40	$	42	$	42		$	42
Settlements		-		-		(2	)		-
Balance at September 30	$	40	$	42	$	40		$	42
Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets held at the end of the period	$	-	$	-	$	-		$	-

⁽¹⁾  Available-for-sale securities in Level 3 are variable rate demand notes which have failed remarketing and for which there are no longer adequate observable inputs available to measure the fair value.

Nonrecurring Measurements:

For purposes of impairment evaluation, the Company measured the fair value of long-lived assets and equity method investments under the fair value measurement accounting guidance. For purposes of the measurement of impairment expense, the Company compares the fair value of assets and liabilities at the evaluation date to the carrying amount at the end of the month prior to the evaluation date. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:

			Nine Months Ended September 30, 2011
	Carrying Amount		Fair Value						Gross Loss
			Level 1		Level 2		Level 3
	(in millions)
Long-lived assets held and used:
Wind turbines and deposits	$	161	$	-	$	45	$	-	$	116
Kelanitissa		66		-		-		29		37
Carbon Reduction Projects		49		-		-		11		33	(1)
Bohemia		14		-		5		-		9
Equity method affiliates:
YangCheng		100		-		-		26		74
Goodwill:
Chigen		17		-		-		-		17
			Nine Months Ended September 30, 2010
	Carrying Amount		Fair Value						Gross Loss
			Level 1		Level 2		Level 3
	(in millions)
Long-lived assets held and used:
Southland (Huntington Beach)	$	288	$	-	$	-	$	88	$	200
Tisza II		160		-		-		75		85
Goodwill:
Deepwater		18		-		-		-		18

⁽¹⁾  The carrying amounts and fair value of the asset groups also include other assets and liabilities; however, impairment expense recognized was limited to the carrying amounts of long-lived assets.

14

Long-lived Assets Held and Used

Wind Turbines and Deposits.    During the third quarter of 2011, the Company determined that certain wind turbines and deposits held by our Wind Generation business were impaired. The long-lived assets with a carrying amount of $161 million were written down to their estimated fair value of $45 million under the market approach. This resulted in the recognition of asset impairment expense of $116 million for the three and nine months ended September 30, 2011.

Kelanitissa.    During the second quarter of 2011, the Company determined the long-lived assets at Kelanitissa, our diesel-fired plant in Sri Lanka, were impaired. The long-lived assets with a carrying amount of $66 million were written down to their estimated fair value of $33 million based on a discounted cash flow analysis. An additional impairment of $4 million was recognized in the three months ended September 30, 2011. This resulted in the recognition of asset impairment expense of $37 million for the nine months ended September 30, 2011.

Carbon Reduction Projects.    During the third quarter of 2011, the Company determined there were impairment indicators for the long-lived asset groups at Carbon Reduction projects, our emission reduction credit projects in Asia and Latin America. The long-lived asset groups with an aggregate carrying amount of $49 million were written down as their estimated fair value was $11 million based on discounted cash flows analysis. This resulted in the recognition of asset impairment expense of $33 million for the three and nine months ended September 30, 2011.

Tisza II and Southland (Huntington Beach).    During the third quarter of 2010, the Company determined there were impairment indicators for the long-lived assets at Tisza II, our gas-fired generation plant in Hungary, and Southland, our gas-fired generation plants in California. These long-lived assets had carrying amounts of $160 million and $288 million, respectively and were written down to their fair value of $75 million and $88 million, respectively. These resulted in the recognition of asset impairment expense of $85 million and $200 million, respectively during the three and nine months ended September 30, 2010.

For further discussion of these impairments, see Note 14 — Impairments.

Equity Method Affiliate

YangCheng.    During the third quarter of 2011, the Company determined that the carrying amount of YangCheng, a 2,100 MW venture in China in which AES owns a 25% interest, had incurred an other-than-temporary impairment. YangCheng’s carrying amount of $100 million was written down to its estimated fair value of $26 million determined under the income approach. This resulted in the recognition of other non-operating expense of $74 million for the three and nine months ended September 30, 2011. See Note 15 — Other Non-Operating Expense for further information.

Goodwill

During the third quarter of 2011, the Company determined there were impairment indicators for the goodwill at Chigen, our holding company in China that holds AES’ interests in Chinese ventures. Goodwill of $17 million was written down to its implied fair value of zero during an interim impairment evaluation, resulting in the recognition of goodwill impairment of $17 million for the three and nine months ended September 30, 2011.

During the third quarter of 2010, the Company determined there were impairment indicators for the long-lived assets and goodwill at Deepwater, our pet coke-fired generation plant in Texas. Goodwill with an aggregate carrying amount of $18 million was written down to its implied fair value of zero, resulting in the recognition of goodwill impairment of $18 million for the nine months ended September 30, 2010.

For further discussion, see Note 14 — Impairments.

15

Discontinued Operations and Held for Sale Businesses

The Company determined the fair value of nonfinancial assets and liabilities of our held for sale businesses during the nine months ended September 30, 2010. These included the Company’s operations in Pakistan, Oman and Qatar. See Note 16 — Discontinued Operations and Held for Sale Businesses for further information.

4. INVESTMENTS IN MARKETABLE SECURITIES

The following table sets forth the Company’s investments in marketable debt and equity securities as of September 30, 2011 and December 31, 2010 by security class and by level within the fair value hierarchy. The security classes are determined based on the nature and risk of a security and are consistent with how the Company manages, monitors and measures its marketable securities.

	September 30, 2011								December 31, 2010
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)
AVAILABLE-FOR-SALE:(1)
Debt securities:
Unsecured debentures(2)	$	-	$	498	$	-	$	498	$	-	$	723	$	-	$	723
Certificates of deposit(2)		-		447		-		447		-		876		-		876
Government debt securities		-		40		-		40		-		47		-		47
Other debt securities		-		-		40		40		-		-		42		42
Subtotal		-		985		40		1,025		-		1,646		42		1,688
Equity securities:
Mutual funds		-		56		-		56		1		61		-		62
Common stock		2		-		-		2		7		-		-		7
Subtotal		2		56		-		58		8		61		-		69
Total available-for-sale		2		1,041		40		1,083		8		1,707		42	$	1,757
TRADING:
Equity securities:
Mutual funds		10		-		-		10		10		-		-		10
Total trading		10		-		-		10		10		-		-		10
TOTAL	$	12	$	1,041	$	40	$	1,093	$	18	$	1,707	$	42	$	1,767

⁽¹⁾  Cost/amortized cost approximated fair value at September 30, 2011 and December 31, 2010, with the exception of certain common stock investments with a cost basis and fair value of $4 million and $2 million, respectively, at September 30, 2011, and a cost basis and fair value of $6 million and $7 million, respectively, at December 31, 2010.

⁽²⁾  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, but meet the definition of a security under the relevant guidance and are therefore classified as available-for-sale securities.

As of September 30, 2011, all available-for-sale debt securities had stated maturities within one year, with the exception of $40 million of variable rate demand notes held by IPL. These securities, classified as other debt securities in the table above, had stated maturities of greater than ten years.

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, 2011 and 2010. Gains and losses on the sale of investments are determined using the specific identification method. For the three and nine months ended

16

September 30, 2011 and 2010, there were no realized losses on the sale of available-for-sale securities and no other-than-temporary impairment of marketable securities recognized in earnings or other comprehensive income.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions)						(in millions)
Losses included in earnings that relate to trading securities held at the reporting date	$	(2	)	$	(1	)	$	(1	)	$	-
Unrealized losses on available-for-sale securities included in other comprehensive income	$	(1	)	$	-		$	(4	)	$	(10	)
Proceeds from sales of available-for-sale securities	$	1,134		$	1,420		$	4,218		$	4,644
Gross realized gains on sales	$	1		$	-		$	5		$	2

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 fuel 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. The Company generally applies hedge accounting to contracts as long as they are eligible under the accounting standards for derivatives and hedging. While derivative transactions are not entered into for trading purposes, some contracts are not eligible for hedge accounting.

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 2030, and are typically designated as cash flow hedges. The following table sets forth, by underlying 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 the related index as of September 30, 2011 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:

	September 30, 2011
	Current				Maximum(1)
Interest Rate Derivatives	Derivative Notional		Derivative Notional Translated to USD		Derivative Notional		Derivative Notional Translated to USD		Weighted Average Remaining Term(1)		% of Debt Currently Hedged by Index(2)
			(in millions)						(in years)
Libor (U.S. Dollar)		3,511	$	3,511		3,585	$	3,585		9		75	%
Euribor (Euro)		1,072		1,435		1,072		1,435		13		66	%
Libor (British Pound Sterling)		63		98		72		112		12		87	%
Securities Industry and Financial
Markets Association Municipal
Swap Index (U.S. Dollar)		40		40		40		40		11		N/A	(3)

⁽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, 2011 and the maturity of the derivative instrument, which includes forward starting derivative instruments. The weighted average remaining term represents the remaining tenor of our interest rate derivatives weighted by the corresponding maximum notional.

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

⁽³⁾  The debt that was being hedged is no longer exposed to variable interest payments because it is now held on IPL’s behalf and no longer bears interest.

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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 amount under its cross currency derivative instruments as of September 30, 2011, which are all in qualifying cash flow hedge relationships. These swaps are amortizing and therefore the notional amount represents the maximum outstanding notional amount as of September 30, 2011:

	September 30, 2011
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	$	237		14		83	%

⁽¹⁾  Represents the remaining tenor of our cross currency swaps weighted by the corresponding notional.

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

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 countries and such operations may be impacted by significant fluctuations in foreign currency exchange rates. Foreign currency options and forwards are utilized, where deemed appropriate, to manage the risk related to fluctuations in certain foreign currencies. These foreign currency contracts range in maturity through 2015. The following tables set forth, by type of foreign currency denomination, the Company’s outstanding notional amounts over the remaining terms of its foreign currency derivative instruments as of September 30, 2011 regardless of whether the derivative instruments are in qualifying hedging relationships:

	September 30, 2011
Foreign Currency Options	Notional		Notional Translated to USD(1)		Probability Adjusted Notional(2)		Weighted Average Remaining Term(3)
	(in millions)						(in years)
Brazilian Real (BRL)		173	$	105	$	96		<1
Euro (EUR)		67		96		82		<1
British Pound (GBP)		29		47		40		<1
Argentine Peso (ARS)		88		20		8		<1

⁽¹⁾  Represents 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⁾  Represents the remaining tenor of our foreign currency options weighted by the corresponding notional.

	September 30, 2011
Foreign Currency Forwards	Notional		Notional Translated to USD		Weighted Average Remaining Term(1)
	(in millions)				(in years)
Chilean Peso (CLP)		98,944	$	201		<1
Euro (EUR)		123		169		2
Colombian Peso (COP)		80,376		44		<1
British Pound (GBP)		11		17		1
Argentine Peso (ARS)		61		13		1

⁽¹⁾  Represents the remaining tenor of our foreign currency forwards weighted by the corresponding notional.

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In addition, certain of our subsidiaries have entered into contracts which contain embedded derivatives that require separate valuation and accounting due to the fact that the item being purchased or sold is denominated in a currency other than the functional currency of that subsidiary or the currency of the item. 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, 2011:

	September 30, 2011
Embedded Foreign Currency Derivatives	Notional		Notional Translated to USD		Weighted Average Remaining Term(1)
	(in millions)				(in years)
Philippine Peso (PHP)		15,973	$	363		2
Argentine Peso (ARS)		904		215		11
Kazakhstani Tenge (KZT)		30,606		207		9
Hungarian Forint (HUF)		10,114		46		<1
Euro (EUR)		20		27		2
Brazilian Real (BRL)		4		2		1

⁽¹⁾  Represents the remaining tenor of our foreign currency embedded derivatives weighted by the corresponding notional.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the price of electricity, fuel 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 purchase or sales contracts. These businesses subject our results of operations to the volatility of prices for electricity, fuel 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 PPAs, fuel supply agreements, commodity forward contracts, futures, swaps and options. Some of our businesses hedge certain aspects of their commodity risks using financial hedging instruments.

The PPAs and fuel supply agreements entered into by the Company are evaluated to determine if they meet the definition of a derivative or contain embedded derivatives, either of which requires separate valuation and accounting. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Generally, these agreements do not meet the definition of a derivative, often due to the inability to be net settled. On a quarterly basis, we evaluate the markets for the commodities to be delivered under these agreements to determine if facts and circumstances have changed such that the agreements could then be net settled and meet the definition of a derivative.

Nonetheless, certain of the PPAs and fuel supply agreements entered into by certain of the Company’s subsidiaries are derivatives or contain embedded derivatives requiring separate valuation and accounting. These contracts range in maturity through 2024. The following table sets forth, by type of commodity, the Company’s outstanding notionals for the remaining term of its commodity derivatives and embedded derivative instruments as of September 30, 2011:

	September 30, 2011
Commodity Derivatives	Notional			Weighted Average Remaining Term(1)
	(in millions)			(in years)
Natural gas (MMBTU)		33			11
Aluminum (MWh)		16	(2)		8
Petcoke (Metric tons)		13			13

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

⁽²⁾  Sonel’s PPA with its primary offtaker, an aluminum smelter, contains an embedded derivative which reflects the linkage of our energy contract pricing, in part, to the price of aluminum as quoted on the London Metals Exchange, a global metals market maker (as required by contract). While the linkage between the contract price of power based on forecasted forward aluminum price curves and the Cameroon market price for power provides for economic alignment between Sonel’s financial results under the PPA and the offtaker’s financial performance, to the extent there are fluctuations in the price of aluminum as compared to the market price for power under our PPA, we may be exposed to significant swings in earnings through mark-to-market adjustments of the embedded derivative as the market price for aluminum has proven to be volatile.

Accounting and Reporting

The following table sets forth the Company’s derivative instruments as of September 30, 2011 and December 31, 2010 by type of derivative and by level within the fair value hierarchy. Derivative assets and liabilities are recognized at their fair value. Derivative assets and liabilities are combined with other balances and included in the following captions in our condensed consolidated balance sheets: current derivative assets in other current assets, noncurrent derivative assets in other noncurrent assets, current derivative liabilities in accrued and other liabilities and long-term derivative liabilities in other long-term liabilities.

	September 30, 2011								December 31, 2010
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)								(in millions)
Assets
Current assets:
Foreign currency derivatives	$	-	$	48	$	4	$	52	$	-	$	4	$	3	$	7
Commodity and other derivatives		-		-		5		5		-		2		3		5
Total current assets		-		48		9		57		-		6		6		12
Noncurrent assets:
Interest rate derivatives		-		-		-		-		-		49		-		49
Cross currency derivatives		-		-		1		1		-		-		12		12
Foreign currency derivatives		-		5		49		54		-		4		27		31
Commodity and other derivatives		-		4		1		5		-		4		16		20
Total noncurrent assets		-		9		51		60		-		57		55		112
Total assets	$	-	$	57	$	60	$	117	$	-	$	63	$	61	$	124
Liabilities
Current liabilities:
Interest rate derivatives	$	-	$	102	$	29	$	131	$	-	$	137	$	-	$	137
Cross currency derivatives		-		-		5		5		-		-		2		2
Foreign currency derivatives		-		6		1		7		-		13		-		13
Commodity and other derivatives		-		5		3		8		-		-		-		-
Total current liabilities		-		113		38		151		-		150		2		152
Long-term liabilities:
Interest rate derivatives		-		294		162		456		-		246		1		247
Cross currency derivatives		-		-		17		17		-		-		-		-
Foreign currency derivatives		-		11		11		22		-		15		8		23
Commodity and other derivatives		-		1		41		42		-		-		1		1
Total long-term liabilities		-		306		231		537		-		261		10		271
Total liabilities	$	-	$	419	$	269	$	688	$	-	$	411	$	12	$	423

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The following table sets forth the fair value and balance sheet classification of derivative instruments as of September 30, 2011 and December 31, 2010:

	September 30, 2011						December 31, 2010
	Designated as Hedging Instruments		Not Designated as Hedging Instruments		Total		Designated as Hedging Instruments		Not Designated as Hedging Instruments		Total
	(in millions)						(in millions)
Assets
Current assets:
Foreign currency derivatives	$	17	$	35	$	52	$	-	$	7	$	7
Commodity and other derivatives		-		5		5		-		5		5
Total current assets		17		40		57		-		12		12
Noncurrent assets:
Interest rate derivatives		-		-		-		49		-		49
Cross currency derivatives		1		-		1		12		-		12
Foreign currency derivatives		2		52		54		-		31		31
Commodity and other derivatives		-		5		5		-		20		20
Total noncurrent assets		3		57		60		61		51		112
Total assets	$	20	$	97	$	117	$	61	$	63	$	124
Liabilities
Current liabilities:
Interest rate derivatives	$	126	$	5	$	131	$	126	$	11	$	137
Cross currency derivatives		5		-		5		2		-		2
Foreign currency derivatives		1		6		7		8		5		13
Commodity and other derivatives		-		8		8		-		-		-
Total current liabilities		132		19		151		136		16		152
Long-term liabilities:
Interest rate derivatives		437		19		456		232		15		247
Cross currency derivatives		17		-		17		-		-		-
Foreign currency derivatives		-		22		22		-		23		23
Commodity and other derivatives		-		42		42		-		1		1
Total long-term liabilities		454		83		537		232		39		271
Total liabilities	$	586	$	102	$	688	$	368	$	55	$	423

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, 2011 and December 31, 2010, we held no cash collateral that we received from counterparties to our derivative positions. As we have not received collateral, our derivative assets are exposed to the credit risk of the respective counterparty and, due to this credit risk, the fair values of our derivative assets (as shown in the above two tables) have been reduced by a credit valuation adjustment. Also, at September 30, 2011 and December 31, 2010, we had no cash collateral posted with (held by) counterparties to our derivative positions.

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The table below sets forth the pre-tax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes over the next twelve months as of September 30, 2011 for the following types of derivatives:

	Accumulated
	Other Comprehensive Income (Loss)
	(in millions)
Interest rate derivatives	$	(116	)
Cross currency derivatives	$	(1	)
Foreign currency derivatives	$	16

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, and as foreign currency gains and losses are recognized for hedges of foreign currency exposure. These balances are included in the condensed consolidated statements of cash flows as operating and/or investing activities based on the nature of the underlying transaction.

The following tables set forth the 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, 2011 and 2010:

	Gains (Losses) Recognized in AOCL							Gains (Losses) Reclassified from AOCL into Earnings(1)
	Three Months   Ended September 30,						Classification in Condensed Consolidated Statements of Operations	Three Months Ended September 30,
	2011			2010				2011			2010
	(in millions)							(in millions)
Interest rate derivatives	$	(297	)	$	(138	)	Interest expense	$	(35	)(2)	$	(24	)(2)
							Non-regulated cost of sales		(1	)(2)		(3	)(2)
							Net equity in earnings of affiliates		(1	)		(1	)
Cross currency derivatives		(37	)		24		Interest expense		(3	)		-
							Foreign currency transaction gains (losses)		(26	)		30
Foreign currency derivatives		29			(12	)	Foreign currency transaction gains (losses)		3			1
Commodity and other derivatives		-			(4	)	Non-regulated cost of sales		(2	)		-
Total	$	(305	)	$	(130	)		$	(65	)	$	3
	Gains (Losses) Recognized in AOCL							Gains (Losses) Reclassified from AOCL into Earnings(1)
	Nine Months  Ended September 30,						Classification in Condensed Consolidated Statements of Operations	Nine Months Ended September 30,
	2011			2010				2011			2010
	(in millions)							(in millions)
Interest rate derivatives	$	(389	)	$	(388	)	Interest expense	$	(88	)(2)	$	(81	)(2)
							Non-regulated cost of sales		(3	)(2)		(3	)(2)
							Net equity in earnings of affiliates		(3	)		(3	)
Cross currency derivatives		(34	)		(5	)	Interest expense		(7	)		(1	)
							Foreign currency transaction gains (losses)		(20	)		16
Foreign currency derivatives		27			(5	)	Foreign currency transaction gains (losses)		(1	)		1
Commodity and other derivatives		-			(4	)	Non-regulated cost of sales		(2	)		-
Total	$	(396	)	$	(402	)		$	(124	)	$	(71	)

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⁽¹⁾  Excludes $0 million and $20 million related to discontinued operations for the three months ended September 30, 2011 and 2010, respectively, and $0 million and $30 million related to discontinued operations for the nine months ended September 30, 2011 and 2010, respectively.

⁽²⁾  Includes amounts that were reclassified from AOCL related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting.

The following table sets forth the pre-tax 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, 2011 and 2010:

	Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Recognized in Earnings						Gains (Losses) Recognized in Earnings
		Three Months Ended September 30,						Nine Months Ended September 30,
		2011			2010			2011			2010
		(in millions)						(in millions)
Interest rate derivatives	Interest expense	$	1		$	(10	)	$	(6	)	$	(18	)
	Net equity in earnings of affiliates		(1	)		-	(1)		(2	)		(1	)
Cross currency derivatives	Interest expense		(3	)		-	(1)		(5	)		4
Foreign currency derivatives	Foreign currency transaction gains (losses)		-	(1)		-	(1)		-	(1)		-	(1)
Total		$	(3	)	$	(10	)	$	(13	)	$	(15	)

⁽¹⁾  De minimis amount.

The following table sets forth the gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging, for the three and nine months ended September 30, 2011 and 2010:

	Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Recognized in Earnings						Gains (Losses) Recognized in Earnings
		Three Months Ended September 30,						Nine Months Ended September 30,
		2011			2010			2011			2010
		(in millions)						(in millions)
Interest rate derivatives	Interest expense	$	(1	)	$	(3	)	$	(2	)	$	(8	)
Foreign exchange derivatives	Foreign currency transaction gains (losses)		27			(7	)		54			(32	)
	Net equity in earnings of affiliates		-			-			-			2
Commodity and other derivatives	Non-regulated revenue		(54	)		1			(63	)		5
	Non-regulated cost of sales		3			(3	)		2			2
Total		$	(25	)	$	(12	)	$	(9	)	$	(31	)

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In addition, IPL 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 the fair value of these derivatives are probable of recovery 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. The following table sets forth the change in regulatory assets and liabilities resulting from the change in the fair value of these derivatives for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions)
(Increase) decrease in regulatory assets	$	(4	)	$	(3	)	$	(6	)	$	(6	)
Increase (decrease) in regulatory liabilities	$	(3	)	$	(2	)	$	3		$	2

Credit Risk-Related Contingent Features

Gener, our business in Chile, has cross currency swap agreements with counterparties to swap Chilean inflation indexed bonds issued in December 2007 into U.S. Dollars. The derivative agreements contain credit contingent provisions which would permit the counterparties with which Gener is in a net liability position to require collateral credit support when the fair value of the derivatives exceeds the unsecured thresholds established in the agreement. These thresholds vary based on Gener’s credit rating. If Gener’s credit rating were to fall below the minimum threshold established in the swap agreements, the counterparties can demand immediate collateralization of the entire mark-to-market value of the swaps (excluding credit valuation adjustments) if Gener is in a net liability position, which was $21 million at September 30, 2011. The swaps were in a net asset position at December 31, 2010. As of September 30, 2011 and December 31, 2010, Gener had not posted collateral to support these swaps.

6. INVESTMENTS IN AND ADVANCES TO AFFILIATES

In February 2011, the Company acquired a 49.6% interest in Entek Elektrik Uretim A.S. (“Entek”) for approximately $136 million. Additional purchase consideration of $13 million was paid in May 2011, increasing the total purchase consideration to $149 million. Entek owns and operates two gas-fired generation facilities in Turkey with an aggregate capacity of 312 MW, and is also engaged in an energy trading business. The Company has significant influence, but not control, of Entek and accordingly the investment has been accounted for under the equity method of accounting.

7. FINANCING RECEIVABLES

Accounts and notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable by considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other available evidence of the collectability, and records an allowance for doubtful accounts for the estimated uncollectable amount as appropriate. Certain of our businesses charge interest on accounts receivable under contractual terms or where charging interest is a customary business practice. In such cases, interest income is recognized on an accrual basis. In situations where the collection of interest is uncertain, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectable.

Included in “Noncurrent other assets” on the condensed consolidated balance sheets as of September 30, 2011 and December 31, 2010 are long-term financing receivables of $282 million and $151 million, respectively,

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primarily with certain Latin American governmental bodies. These receivables have contractual maturities of greater than one year and are being collected in installments as scheduled. Of the total $282 million as of September 30, 2011, $220 million and $50 million, respectively, relate to our businesses in Argentina and the Dominican Republic. The remaining amounts relate to our distribution businesses in Brazil.

8. 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, distribution companies and other project-related investments at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. Absent guarantees, intercompany loans or other credit support, the default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries, though the Company’s equity investments and/or subordinated loans to projects (if any) are at risk. 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.

The following table summarizes the carrying amount and estimated fair values of the Company’s recourse and non-recourse debt as of September 30, 2011 and December 31, 2010:

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Non-recourse debt	$	14,686	$	14,885	$	14,938	$	15,269
Recourse debt		6,192		6,216		4,612		4,868
Total debt	$	20,878	$	21,101	$	19,550	$	20,137

Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated differently based upon the type of loan. The fair value of fixed rate loans is estimated using quoted market prices, if available, or a discounted cash flow analysis. In the discounted cash flow analysis, the discount rate is based on the credit rating of the individual debt instruments if available, or the credit rating of the subsidiary. If the subsidiary’s credit rating is not available, a synthetic credit rating is determined using certain key metrics, including cash flow ratios and interest coverage, as well as other industry specific factors. For subsidiaries located outside the U.S., in the event that the country rating is lower than the credit rating previously determined, the country rating is used for the purposes of the discounted cash flow analysis. The fair value of recourse and non-recourse debt excludes accrued interest at the valuation date.

The fair value was determined using available market information as of September 30, 2011. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to September 30, 2011.

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Non-Recourse Debt

The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of September 30, 2011 and is in the current portion of non-recourse debt unless otherwise indicated:

Subsidiary	Primary Nature of  Default	September 30, 2011
		Default Amount		Net Assets
		(in millions)
Maritza	Covenant	$	935	$	216
Sonel	Covenant		342		306
Kelanitissa	Covenant		22		6
Total		$	1,299

Included in “Current liabilities of discontinued and held for sale businesses” in the condensed consolidated balance sheet as of September 30, 2011 is approximately $203 million of non-recourse debt relating to our businesses in New York, which has been classified as current due to certain facts and circumstances that create significant uncertainty about the business’s ability to generate sufficient cash flows and remain in compliance with the terms of its contractual obligations in the next twelve months.

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’ corporate debt agreements as of September 30, 2011 in order to trigger an event of default or permit acceleration under such indebtedness. The bankruptcy or acceleration of material amounts of debt at such entities would cause a cross default under the recourse senior secured credit facility. 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 or the financial position or results of operations of an individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby a bankruptcy or an acceleration of its non-recourse debt trigger an event of default and possible acceleration of the indebtedness under the AES Parent Company’s outstanding debt securities.

On October 3, 2011, Dolphin Subsidiary II, Inc. (“Dolphin II”), a newly formed, wholly owned special purpose indirect subsidiary of AES, entered into an indenture (the “Indenture”) with Wells Fargo Bank, N.A. (the “Trustee”) as part of its issuance of $450 million aggregate principal amount of 6.50% senior notes due 2016 (the “2016 Notes”) and $800 million aggregate principal amount of 7.25% senior notes due 2021 (the “7.25% 2021 Notes”, together with the 2016 Notes, the “notes”) to finance the pending acquisition (the “Acquisition”) by AES of DPL Inc. (“DPL”). See Note 17 — Acquisitions for further information.

Interest on the 2016 Notes and the 7.25% 2021 Notes accrues at a rate of 6.50% and 7.25% per year, respectively, and is payable on April 15 and October 15 of each year, beginning April 15, 2012. Prior to September 15, 2016 with respect to the 2016 Notes or July 15, 2021 with respect to the 7.25% 2021 Notes, Dolphin II may redeem some or all of the 2016 Notes or 7.25% 2021 Notes at par, plus a “make-whole” amount set forth in the Indenture and accrued and unpaid interest. At any time on or after September 15, 2016 or July 15, 2021 with respect to the 2016 Notes and 7.25% 2021 Notes, respectively, Dolphin II may redeem some or all of the 2016 Notes or 7.25% 2021 Notes at par plus accrued and unpaid interest.

The proceeds from issuance of the notes were deposited into an escrow account pledged for the benefit of the Trustee pending the consummation of the Acquisition. The notes are subject to a special mandatory redemption at a price of 101% of the offering price of the notes plus accrued and unpaid interest in the event that the Acquisition is not consummated on or before September 30, 2012. If the acquisition closes on or before such date, Dolphin II will concurrently merge with and into DPL, with DPL being the surviving company and obligor under the notes.

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On September 28, 2011, the Company provided a letter of credit for approximately $115 million in favor of the escrow agent for the benefit of the Trustee pending the consummation of the Acquisition to cover payment of the interest expense from October 3, 2011 to September 30, 2012, the discount paid to the initial purchasers of the notes and special mandatory redemption price of 1% of the offering price of the notes. On September 29, 2011, at the instructions of the Dolphin II, escrow agent drew the entire amount of the letter of credit and deposited into the same escrow account for the benefit of the Trustee pending the consummation of the Acquisition. At the Acquisition consummation, any excess amount in the escrow account will be returned to Dolphin II.

Recourse Debt

During the nine months ended September 30, 2011, the Company secured recourse debt of $2.05 billion. The proceeds of the debt may, among other things, be used to partially finance the Company’s contemplated acquisition of DPL Inc, as discussed further in Note 17 — Acquisitions.

On May 27, 2011, the Company secured a $1.05 billion term loan under a senior secured credit facility (the “senior secured term loan”). The senior secured term loan will bear annual interest, at the Company’s option, at a variable rate of LIBOR plus 3.25% or Base Rate plus 2.25%, and will mature on the seventh anniversary of the closing date. The senior secured term loan is subject to certain customary representations, covenants and events of default.

On June 15, 2011, the Company issued $1 billion aggregate principal amount of 7.375% senior unsecured notes maturing July 1, 2021 (the “7.375% 2021 Notes”). Upon a change of control, the Company must offer to repurchase the 7.375% 2021 Notes at a price equal to 101% of principal, plus accrued and unpaid interest. The 7.375% 2021 Notes are also subject to certain covenants restricting the ability of the Company to incur additional secured debt; to enter into sale-lease back transactions; to consolidate, merge, convey or transfer substantially all of its assets; as well as other covenants and events of default that are customary for debt securities similar to the 7.375% 2021 Notes. The Company entered into interest rate locks in May 2011 to hedge the risk of changes in LIBOR until the issuance of the 7.375% 2021 Notes. The Company paid $24 million to settle those interest rate locks as of June 15, 2011. The payment was recognized in accumulated other comprehensive loss and is being amortized over the life of the 7.375% 2021 Notes.

9. 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, 2011, the Company had recorded liabilities of $22 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, 2011.

The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and 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 byproducts), and certain air emissions, such as SO₂, NO_x, particulate matter and mercury. Such risks and uncertainties could result in 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.

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Legislation and Regulation of GHG Emissions

Currently, in the United States there is no federal legislation establishing mandatory GHG emissions reduction programs (including CO₂) affecting the electric power generation facilities of the Company’s subsidiaries. There are numerous state programs regulating GHG emissions from electric power generation facilities and there is a possibility that federal GHG legislation will be enacted within the next several years. Further, the United States Environmental Protection Agency (“EPA”) has adopted regulations pertaining to GHG emissions and has announced its intention to propose new regulations for electric generating units under Section 111 of the United States Clean Air Act (“CAA”).

Potential U.S. Federal GHG Legislation    Federal legislation passed the U.S. House of Representatives in 2009 that, if adopted, would have imposed a nationwide cap-and-trade program to reduce GHG emissions. This legislation was never signed into law, and is no longer under consideration. In the U.S. Senate, several different draft bills pertaining to GHG legislation have been considered, including comprehensive GHG legislation similar to the legislation that passed the U.S. House of Representatives and more limited legislation focusing only on the utility and electric generation industry. It is uncertain whether any legislation pertaining to GHG emissions will be voted on and passed by the U.S. Senate and House of Representatives. If any such legislation is enacted into law, the impact could be material to the Company.

EPA GHG Regulation    The EPA has promulgated regulations governing GHG emissions from automobiles under the CAA. The effect of the EPA’s regulation of GHG emissions from mobile sources is that certain provisions of the CAA will also apply to GHG emissions from existing stationary sources, including many U.S. power plants. In particular, beginning January 2, 2011, construction of new stationary sources and modifications to existing stationary sources that result in increased GHG emissions became subject to permitting requirements under the prevention of significant deterioration (“PSD”) program of the CAA. The PSD program, as currently applicable to GHG emissions, requires sources that emit above a certain threshold of GHGs to obtain PSD permits prior to commencement of new construction or modifications to existing facilities. In addition, major sources of GHG emissions may be required to amend, or obtain new, Title V air permits under the CAA to reflect any new applicable GHG emissions requirements for new construction or for modifications to existing facilities.

The EPA promulgated a final rule on June 3, 2010 (the “Tailoring Rule”) that sets thresholds for GHG emissions that would trigger PSD permitting requirements. The Tailoring Rule, which became effective in January of 2011, provides that sources already subject to PSD permitting requirements need to install Best Available Control Technology (“BACT”) for greenhouse gases if a proposed modification would result in the increase of more than 75,000 tons per year of GHG emissions. Also, under the Tailoring Rule, any new sources of GHG emissions that would emit over 100,000 tons per year of GHG emissions, in addition to any modification that would result in GHG emissions exceeding 75,000 tons per year, require PSD review and are subject to related permitting requirements. The EPA anticipates that it will adjust downward the permitting thresholds of 100,000 tons and 75,000 tons for new sources and modifications, respectively, in future rulemaking actions. The Tailoring Rule substantially reduces the number of sources subject to PSD requirements for GHG emissions and the number of sources required to obtain Title V air permits, although new thermal power plants may still be subject to PSD and Title V requirements because annual GHG emissions from such plants typically far exceed the 100,000 ton threshold noted above. The 75,000 ton threshold for increased GHG emissions from modifications to existing sources may reduce the likelihood that future modifications to plants owned by some of our United States subsidiaries would trigger PSD requirements, although some projects that would expand capacity or electric output are likely to exceed this threshold, and in any such cases the capital expenditures necessary to comply with the PSD requirements could be significant.

In December 2010, the EPA entered into a settlement agreement with several states and environmental groups to resolve a petition for review challenging the EPA’s new source performance standards (“NSPS”) rulemaking for electric utility steam generating units (“EUSGUs”) based on the NSPS’s failure to address GHG emissions. Under the settlement agreement, the EPA had committed to propose GHG emissions standards for

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EUSGUs by July 26, 2011. The EPA previously announced that it would delay the proposal of such standards until September 30, 2011, and it subsequently announced a further delay without specifying a deadline for the proposal of such standards. The EPA has also committed to finalize GHG NSPS for EUSGUs by May 26, 2012. The NSPS will establish GHG emission standards for newly constructed and reconstructed EUSGUs. The NSPS also will establish guidelines regarding the best system for achieving further GHG emissions reductions from existing EUSGUs. Based on the guidelines, individual states will be required to develop regulations establishing GHG performance standards for existing EUSGUs within their states. It is impossible to estimate the impact and compliance cost associated with any future NSPS applicable to EUSGUs until such regulations are finalized. However, the compliance costs could have a material and adverse impact on our consolidated financial condition or results of operations.

Regional Greenhouse Gas Initiative    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 participating in RGGI 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 2010 Form 10-K, we have estimated the costs to the Company of compliance with RGGI to be approximately $15 million for 2011.

International GHG Regulation    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 emissions reduction requirements. Many of the countries in which the Company’s subsidiaries operate have no emissions reduction obligations under the Kyoto Protocol. In addition, of the 27 countries in which the Company’s subsidiaries operate, all but one — the United States (including Puerto Rico) — have ratified the Kyoto Protocol. The first commitment period under the Kyoto Protocol is currently expected to expire at the end of 2012, and countries have been unable to agree on a successor commitment period. The next annual United Nations conference to develop a successor international agreement is scheduled for November 2011 in South Africa. It currently appears unlikely that a successor agreement will be reached at such conference; however, if a successor agreement is reached the impact could be material to the Company.

There is substantial uncertainty with respect to whether U.S. federal GHG legislation will be enacted into law, whether new country-specific GHG legislation will be adopted in countries in which our subsidiaries conduct business, and whether a new international agreement to succeed the Kyoto Protocol will be reached. There is additional uncertainty regarding the final provisions or implementation of any potential U.S. federal or foreign country GHG legislation, the EPA’s 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 or financial condition from potential U.S. federal or foreign country GHG legislation, the EPA’s 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.

Other U.S. Air Emissions Regulations and Legislation

The Company’s subsidiaries in the United States are subject to the Clean Air Act (“CAA”) and various state laws and regulations that regulate emissions of air pollutants, including SO₂, NO_X, particulate matter (“PM”), mercury and other hazardous air pollutants (“HAPs”).

The EPA promulgated the Clean Air Interstate Rule (“CAIR”) on March 10, 2005, which required allowance surrender for SO₂ and NO_X emissions from existing power plants located in 28 eastern states and the

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District of Columbia. CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the EPA. In response to the D.C. Circuit’s opinion, on July 7, 2011, the EPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, the CSAPR requires significant reductions in SO₂ and NOx emissions from covered sources, such as power plants, in many states in which subsidiaries of the Company operate. Once fully implemented in 2014, the rule requires additional SO₂ emission reductions of 73% and additional NO_x reductions of 54% from 2005 levels. The CSAPR will be implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of new emissions allowances that the EPA will create. The CSAPR contemplates limited interstate and intra-state trading of emissions allowances by covered sources. Initially, at least through 2012, the EPA will issue emissions allowances to affected power plants based on state emissions budgets established by the EPA under the CSAPR. The availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time. The CSAPR was published in the Federal Register on August 8, 2011 and on October 6, 2011, the EPA proposed some technical revisions to the CSAPR, including allowing for additional allowances for certain states. The EPA will be taking public comments on the proposed revisions for thirty days, and such public comments will be considered by the EPA prior to promulgating a final rule. Many states, utilities and other affected parties have filed lawsuits in the U.S. Court of Appeals for the District of Columbia seeking to stay the implementation of the CSAPR and challenging the validity of the CSAPR. We cannot predict the outcome of such litigation or the effect it might have on the possible implementation of the CSAPR. To comply with the CSAPR, additional pollution control technology may be required by some of our subsidiaries, and the cost of implementing any such technology could affect the financial condition or results of operations of these subsidiaries or the Company. Additionally, compliance with the CSAPR could require the purchase of newly issued allowances, the switch to higher priced, lower sulfur coal or the retirement of existing generating units. While the capital costs, other expenditures or operational restrictions necessary to comply with the CSAPR cannot be specified at this time, and the outcome of litigation pertaining to CSAPR is uncertain, the Company anticipates that the CSAPR may have a material impact on the Company’s business and results of operations.

As a result of prior EPA determinations and the D.C. Circuit Court ruling, the EPA is obligated under Section 112 of the CAA to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, hydrogen chloride, hydrogen fluoride, and other metal species from coal and oil-fired power plants. The EPA has entered into a consent decree under which it is obligated to finalize the rule by November 2011, and it has subsequently requested an extension of this deadline until December 16, 2011. In connection with such rule, the CAA requires the EPA to establish maximum achievable control technology (“MACT”) standards for each pollutant regulated under the rule. MACT is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. The EPA published a proposed rule on May 3, 2011 that would establish national emissions standards for hazardous air pollutants (“NESHAP”) from coal and oil-fired electric utility steam generating units. The rule, as currently proposed, may require all coal-fired power plants to retire operations or install acid gas control technology, upgrade particulate control devices and/or install some other type of mercury control technology, such as sorbent injection. The public comment period for this proposed rule has expired, and the public comments will be considered by the EPA prior to promulgating a final rule. Most of the United States coal-fired plants operated by the Company’s subsidiaries have acid gas scrubbers or comparable control technologies, but as proposed there are other improvements to such control technologies that may be needed at some of the Company’s plants. Under the CAA, compliance is required within three years of the effective date of the rule; however, the compliance period for a unit, or group of units, may be extended by state permitting authorities (for one additional year) or through a determination by the President (for up to two additional years). At this time, the Company cannot predict the extent of the final regulations for hazardous air pollutants, but the cost of compliance with any such regulations could be material.

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Other International Air Emissions Regulations and Legislation

On January 18, 2011, the President of Chile approved a new air emissions regulation submitted to him by the national environmental regulatory agency (“CONAMA”). The new regulation establishes limits on emissions of NO_X, SO₂, metals and particulate matter for both existing and new thermal power plants, with more stringent limitations on new facilities. The regulation became effective on June 23, 2011. The regulation will require AES Gener, the Company’s Chilean subsidiary, to install emissions reduction equipment at its existing thermal plants from late 2011 through 2015. The costs of compliance with such regulation have not yet been determined and the Company believes some of the compliance costs are contractually passed through to counterparties. However, the compliance costs could be material.

Cooling Water Intake Regulations

The Company’s U.S. facilities are subject to the U.S. Clean Water Act Section 316(b) rule issued by the EPA which seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the “best technology available” for cooling water intake structures. The EPA published a proposed rule establishing requirements under 316(b) regulations on April 20, 2011. The proposal, based on Section 316(b) of the U.S. Clean Water Act, establishes Best Technology Available (“BTA”) requirements regarding impingement standards with respect to aquatic organisms for all facilities that withdraw above 2 million gallons per day of water from certain water bodies and utilize at least 25% of the withdrawn water for cooling purposes. To meet these BTA requirements, as currently proposed, cooling water intake structures associated with once through cooling processes will need modifications of existing traveling screens that protect aquatic organisms and will need to add a fish return and handling system for each cooling system. Existing closed cycle cooling facilities may require upgrades to water intake structure systems. The proposal would also require comprehensive site-specific studies during the permitting process and may require closed-cycle cooling systems in order to meet BTA entrainment standards.

The public comment period for this proposed rule has expired, and the EPA will consider the public comments with a view to issuing a final rule by July of 2012. Until such regulations are final, the EPA has instructed state regulatory agencies to use their best professional judgment in determining how to evaluate what constitutes “best technology available” for protecting fish and other aquatic organisms from cooling water intake structures. Certain states in which the Company operates power generation facilities, such as New York, have been delegated authority and are moving forward with best technology available determinations in the absence of any final rule from the EPA. On September 27, 2010, the California Office of Administrative Law approved a policy adopted by the California Water Resources Control Board with respect to power plant cooling water intake structures. This policy became effective on October 1, 2010, and establishes technology-based standards to implement Section 316(b) of the U.S. Clean Water Act. At this time, it is contemplated that the Company’s Redondo Beach, Huntington Beach and Alamitos power plants in California will need to have in place best technology available by December 31, 2020, or repower the facilities. At present, the Company cannot predict the final requirements under Section 316(b) or whether compliance with the anticipated new 316(b) rule will have a material impact on our operations or results, but the Company expects that capital investments and/or modifications resulting from such requirements could be significant.

Waste Management

In the course of operations, many of the Company’s facilities generate coal combustion byproducts (“CCB”), including fly ash, requiring disposal or processing. On June 21, 2010 the EPA published in the Federal Register a proposed rule to regulate CCB under the Resource Conservation and Recovery Act (“RCRA”). The proposed rule provides two possible options for CCB regulation, and both options contemplate heightened structural integrity requirements for surface impoundments of CCB. The first option contemplates regulation of CCB as a hazardous waste subject to regulation under Subtitle C of the RCRA. Under this option, existing surface impoundments containing CCB would be required to be retrofitted with composite liners and these

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impoundments would likely be phased out over several years. State and/or federal permit programs would be developed for storage, transport and disposal of CCB. States could bring enforcement actions for non-compliance with permitting requirements, and the EPA would have oversight responsibilities as well as the authority to bring lawsuits for non-compliance. The second option contemplates regulation of CCB under Subtitle D of the RCRA. Under this option, the EPA would create national criteria applicable to CCB landfills and surface impoundments. Existing impoundments would also be required to be retrofitted with composite liners and would likely be phased out over several years. This option would not contain federal or state permitting requirements. The primary enforcement mechanism under regulation pursuant to Subtitle D would be private lawsuits.

The public comment period for this proposed regulation has expired, and the EPA is required to consider the public comments prior to promulgating a final rule. Requirements under a final rule are expected to become effective by January 2012, with a compliance schedule of five years. While the exact impact and compliance cost associated with future regulations of CCB cannot be established until such regulations are finalized, there can be no assurance that the Company’s businesses, financial condition or results of operations would not be materially and adversely affected by such regulations.

Indiana Senate Bill 251

In May 2011, Senate Bill 251 became a law in the State of Indiana. Senate Bill 251 is a comprehensive bill which, among other things, provides Indiana utilities, including IPL, with a means for recovering 80% of costs incurred to comply with federal mandates through a periodic retail rate adjustment mechanism, and additional cost recovery is possible through a subsequent general rate case. This includes costs to comply with regulations from the EPA, FERC, NERC, the Department of Energy, etc., including capital intensive requirements and/or proposals such as those relating to cooling water intake regulations, waste management and coal combustion byproducts, wastewater effluent, MISO transmission expansion costs and polychlorinated biphenyls. It does not change existing legislation that allows for 100% recovery of clean coal technology designed to reduce air pollutants (Indiana Senate Bill 29).

Some of the most important features of Senate Bill 251 to IPL are as follows: any energy utility in Indiana seeking to recover federally mandated costs incurred in connection with a compliance project shall apply to the Indiana Utility Regulatory Commission (“IURC”) for a certificate of public convenience and necessity (“CPCN”) for the compliance project. It sets forth certain factors that the IURC must consider in determining whether to grant a CPCN. It further specifies that if the IURC approves a proposed compliance project and the projected federally mandated costs associated with the project, the following apply: (i) 80% of the approved costs shall be recovered by the energy utility through a periodic retail rate adjustment mechanism; (ii) 20% of the approved costs shall be deferred and recovered by the energy utility as part of the next general rate case filed by the energy utility with the IURC; and (iii) actual costs exceeding the projected federally mandated costs of the approved compliance project by more than 25% shall require specific justification and approval by the IURC before being authorized in the energy utility’s next general rate case.

Guarantees, Letters of Credit and Commitments

In connection with certain project financing, acquisition, power purchase, and other agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, AES has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations primarily relate to future performance commitments which the Company or its businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 15 years.

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The following table summarizes the Parent Company’s contingent contractual obligations as of September 30, 2011. Amounts presented in the table below represent the Parent Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of businesses of $26 million.

Contingent contractual obligations	Amount		Number of Agreements		Maximum Exposure Range for Each Agreement
	(in millions)				(in millions)
Guarantees	$	357		23	<$1 - $53
Letters of credit under the senior secured credit facility		12		11	<$1 - $7
Cash collateralized letters of credit		260		13	<$1 - $223
Total	$	629		47

As of September 30, 2011, the Company had $16 million of commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit discussed above. The Company expects to fund these net investment commitments in 2011. The exact payment schedules will be dictated by the construction milestones. Additionally, subject to regulatory approvals, the Company is committed to purchase DPL for $3.5 billion, see Note 17 — Acquisitions for further information. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.

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 has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims of approximately $372 million and $448 million as of September 30, 2011 and December 31, 2010, respectively. These reserves are reported on the condensed consolidated balance sheets within “accrued and other liabilities” and “other long-term liabilities.” A significant portion of the reserves relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company’s subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that these reserves will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

The Company believes, based upon information it currently possesses and taking into account established reserves for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company’s financial statements. However, even where no reserve has been recognized, it is reasonably possible 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 could not be estimated as of September 30, 2011. The material contingencies where a loss is reasonably possible are described below. In aggregate, the Company estimates that the range of potential losses related to these material contingences to be up to $1.2 billion. The amounts considered reasonably possible do not include amounts reserved, as discussed above. Where a loss or range of loss cannot be estimated, a statement to this effect has been included in the applicable case descriptions presented below.

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$1.2 billion ($656 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 (“AC”) ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been 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 were dismissed. Eletrobrás later requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo consented to the appointment of such an expert, subject to a reservation of rights. In February 2010, the Fifth District Court appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization, in accordance with the methodology proposed by Eletrobrás. Pursuant to its reservation of rights, Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo’s arguments and directing the Fifth District Court to proceed accordingly. Eletrobrás has restarted the accounting proceedings at the Fifth District Court, which will proceed in accordance with the AC’s April 2010 decision. The parties are briefing the issues. In the Fifth District Court proceedings, the expert’s conclusions will be subject to the Fifth District Court’s review and approval. If Eletropaulo is determined to be responsible for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to 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 and, in turn the Company’s results of operations could 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. The parties are disputing the proper venue for the CTEEP lawsuit. 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 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 seeking 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

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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. 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. (“OPGC”), an equity method investment of the Company, 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. In June 2010, a 2-to-1 majority of the arbitral tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. 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 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 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 São 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. 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. In May 2010, the MPF filed an appeal with the Superior Court of Justice challenging the transfer. The MPF’s lawsuit before the FCSP has been stayed pending a final decision on the interlocutory appeals. AES Elpa and AES Brasiliana (the successor of 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.

In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”), for the period from January through February 2009. The investigation of both Hydros has now been completed. The Antimonopoly Agency determined that the Hydros abused their market position and charged monopolistically high prices for power from January through February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($3 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of the Hydros. In the course of criminal proceedings, the financial police have expanded the periods at issue to the entirety of 2009 in the case of UK HPP and from January through October 2009 in the case

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of Shulbinsk HPP, and sought increased damages of KZT 1.2 billion ($8 million) in the case of UK HPP and KZT 1.3 billion ($9 million) in the case of Shulbinsk HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

In July 1993, the Public Attorney’s office filed a claim against Eletropaulo, the Sao Paulo State Government, SABESP (a state-owned company), CETESB (the Environmental Agency of Sao Paulo State) and DAEE (the Municipal Water and Electric Energy Department) alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from the Pinheiros River into the 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 R$760 million ($415 million) for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo, which reversed the lower court decision. In 2009, the Public Attorney’s Office filed appeals to both the Superior Court of Justice and the Supreme Court and such appeals were answered by Eletropaulo in the fourth quarter of 2009. 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 February 2009, a CAA Section 114 information request from the EPA regarding Cayuga and Somerset was received. The request seeks various operating and testing data and other information regarding certain types of projects at the Cayuga and Somerset facilities, generally for the time period from January 1, 2000 through the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. 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 the Company, its results of operations or its financial position.

On February 2, 2009, the Cayuga facility received a Notice of Violation from the New York State Department of Environmental Conservation (“NYSDEC”) 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 NYSDEC and submitted a Landfill Liner Demonstration Report to them. Such report found that the landfill has adequate engineering integrity to support the additional coal ash and there is no inherent environmental threat. NYSDEC has indicated they accept the finding of the report. A permit modification was approved by the NYSDEC on May 14, 2010 and such permit modification allows for closure of this approximately 10-acre portion of the landfill. The construction in accordance with the approved permit modification was completed in November 2010 and the certification report for this construction project was submitted to the NYSDEC in the second quarter of 2011. While at this time it is not possible to predict what impact, if any, this matter may have on the Company, its results of operations or its financial position, based upon the discussions to date, the Company does not believe the impact will be material.

In July 2009, AES Energía Cartagena S.R.L. (“AES Cartagena”) received notices from the Spanish national energy regulator, Comisión Nacional de Energía (“CNE”), stating that the proceeds of the sale of electricity from AES Cartagena’s plant should be reduced by roughly the value of the CO₂ allowances that were granted to AES Cartagena for free for the years 2007, 2008, and the first half of 2009. In particular, the notices stated that CNE intended to invoice AES Cartagena to recover that value, which CNE calculated as approximately €20 million ($27 million) for 2007-2008 and an amount to be determined for the first half of 2009. In September 2009, AES Cartagena received invoices for €523,548 (approximately $712,000) for the allowances granted for free for 2007 and €19,907,248 (approximately $27 million) for 2008. In July 2010, AES Cartagena received an invoice for approximately €5 million ($7 million) for the allowances granted for free for the first half of 2009. AES Cartagena does not expect to be charged for CO₂ allowances issued free of charge for subsequent periods. AES Cartagena has paid the amounts invoiced and has filed challenges to the CNE’s demands in the Spanish judicial system. There can be no assurances that the challenges will be successful. AES Cartagena has demanded indemnification from its fuel supply and electricity toller, GDF Suez S.A. (“GDFS”), in relation to the CNE

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invoices under the long-term energy agreement (the “Energy Agreement”) with GDFS. However, GDFS has disputed that it is responsible for the CNE invoices under the Energy Agreement. Therefore, in September 2009, AES Cartagena initiated arbitration against GDFS, seeking to recover the payments made to CNE. In the arbitration, AES Cartagena also seeks a determination that GDFS is responsible for procuring and bearing the cost of CO₂ allowances that are required to offset the CO₂ emissions of AES Cartagena’s power plant, which is also in dispute between the parties. To date, AES Cartagena has paid approximately €25 million ($34 million) for the CO₂ allowances that have been required to offset 2008, 2009 and 2010 CO₂ emissions. AES Cartagena expects that allowances will need to be purchased to offset emissions for subsequent years. The evidentiary hearing in the arbitration took place from May 31-June 4, 2010, and closing arguments were heard on September 1, 2010. In February 2011, the arbitral tribunal requested further briefing on certain issues in the arbitration, which was later submitted by the parties. The tribunal has the matter under consideration. If AES Cartagena does not prevail in the arbitration and is required to bear the cost of carbon compliance, its results of operations could be materially adversely affected and, in turn, there could be a material adverse effect on the Company and its results of operations. 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. The parties have agreed to settle the dispute subject to the closing of a share sale agreement, which is subject to regulatory and lender approvals. See Note 20 — Subsequent Events for further information. If the transaction does not close, the arbitration will continue, including the risks described above.

In November 2009, April 2010, December 2010, April 2011, June 2011, and August 2011, substantially similar personal injury lawsuits were filed by a total of 47 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The AES defendants moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. The AES defendants will respond to those amended complaints by October 31, 2011. The AES defendants will also respond to the December 2010, April 2011, June 2011 and August 2011 lawsuits after the relevant plaintiffs file amended complaints. The AES defendants believe they have meritorious defenses to the claims asserted against them and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.

On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns an unfinished 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million ($211 million). The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. The Contractor may attempt to seek relief relating to the bond dispute in the French or English courts. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units because of the alleged characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor’s claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the

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EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately €240 million ($326 million) in the arbitration, unspecified damages for alleged injury to reputation, and other relief. The arbitral hearing on the merits is in September 2012. Maritza 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.

10. PENSION PLANS

Total pension cost for the three and nine months ended September 30, 2011 and 2010 included the following components:

	Three Months Ended September 30,												Nine Months Ended September 30,
	2011						2010						2011						2010
	U.S.			Foreign			U.S.			Foreign			U.S.			Foreign			U.S.			Foreign
	(in millions)												(in millions)
Service cost	$	1		$	6		$	1		$	3		$	5		$	16		$	4		$	12
Interest cost		8			145			8			129			24			436			24			380
Expected return on plan assets		(8	)		(130	)		(7	)		(108	)		(24	)		(391	)		(22	)		(318	)
Amortization of prior service cost		1			-			1			-			3			-			3			-
Amortization of net loss		3			6			3			4			10			18			9			11
Loss on curtailment		-			-			-			-			-			4			-			-
Total pension cost	$	5		$	27		$	6		$	28		$	18		$	83		$	18		$	85

Total employer contributions for the nine months ended September 30, 2011 for the Company’s U.S. and foreign subsidiaries were $30 million and $132 million, respectively. The expected remaining scheduled employer contributions for 2011 are $7 million for U.S. subsidiaries and $39 million for foreign subsidiaries.

11. EQUITY

STOCK REPURCHASE PROGRAM

In July 2010, the Company’s Board of Directors approved a stock repurchase program (the “Program”) under which the Company can repurchase up to $500 million of AES common stock. The Board authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The Program does not have an expiration date and it can be modified or terminated by the Board of Directors at any time. During the nine months ended September 30, 2011, shares of common stock repurchased under this plan totaled 19,987,795 at a total cost of $224 million plus a nominal amount of commissions (average of $11.24 per share including commissions), bringing the cumulative total purchases under the program to 28,370,620 shares at a total cost of $324 million plus a nominal amount of commissions (average of $11.42 per share including commissions).

The shares of stock repurchased have been classified as treasury stock and accounted for using the cost method. A total of 36,832,776 and 17,287,073 shares were held as treasury stock at September 30, 2011 and December 31, 2010, respectively. The Company has not retired any shares held in treasury during the nine months ended September 30, 2011.

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COMPREHENSIVE INCOME

The components of comprehensive income (loss) for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions)						(in millions)
Net income	$	175		$	397		$	1,085		$	1,228
Change in fair value of available-for-sale securities, net of income tax benefit of $0, $0, $1 and $4, respectively		(1	)		-			(3	)		(6	)
Foreign currency translation adjustments, net of income tax benefit (expense) of $42, $(15), $28 and $(7), respectively		(589	)		285			(327	)		519
Derivative activity:
Reclassification to earnings, net of income tax (expense) of $(13), $(3), $(15) and $(22), respectively		53			13			112			81
Change in derivative fair value, net of income tax benefit of $68, $23, $93 and $82, respectively		(236	)		(99	)		(305	)		(336	)
Total net change in fair value of derivatives		(183	)		(86	)		(193	)		(255	)
Change in unfunded pension obligation, net of income tax (expense) of $(2), $(1), $(6) and $(3), respectively		5			1			12			6
Other comprehensive income (loss)		(768	)		200			(511	)		264
Comprehensive income (loss)		(593	)		597			574			1,492
Less: Comprehensive (income) loss attributable to noncontrolling interests(1)		12			(385	)		(651	)		(789	)
Comprehensive income (loss) attributable to The AES Corporation	$	(581	)	$	212		$	(77	)	$	703

⁽¹⁾  Includes the income 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, 2011 and December 31, 2010 were as follows:

	September 30, 2011		December 31, 2010
	(in millions)
Foreign currency translation adjustment	$	2,002	$	1,824
Unrealized derivative losses, net		511		344
Unfunded pension obligation		212		216
Securities available-for-sale		2		(1	)
Accumulated other comprehensive loss	$	2,727	$	2,383

EQUITY TRANSACTIONS WITH NONCONTROLLING INTERESTS

On July 7, 2011, a subsidiary of the Company completed the acquisition of an additional 10% equity interest in AES-VCM Mong Duong Power Company Limited (“Mong Duong”), a 1,200 MW coal-fired power plant in development in the Quang Ninh province in Vietnam, from Vietnam National Coal and Mineral Industries Group, its minority shareholder. On July 8, 2011, through a subsidiary, the Company sold 30% and 19% equity interests in Mong Duong to PSC Energy Global Co., Ltd. (a wholly owned subsidiary of POSCO Corporation) and Stable Investment Corporation (a wholly owned subsidiary of China Investment Corporation, a related party)

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respectively, resulting in the Company retaining a 51% indirect equity interest in Mong Duong. As a result of these transactions, the Company did not lose control of Mong Duong, which continues to be accounted for as a consolidated subsidiary. A net gain of $19 million resulting from these transactions was recorded as an equity transaction in additional paid-in capital.

The following table summarizes the net income attributable to The AES Corporation and transfers (to) from noncontrolling interests for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2010		2011		2010
	(in millions)
Net (loss) income attributable to The AES Corporation	$	(131	)	$	114	$	267	$	445
Transfers (to) from the noncontrolling interests:
Net increase in The AES Corporation’s paid-in capital for sale of subsidiary shares		19			-		19		-
Net transfers (to) from noncontrolling interest		19			-		19		-
Change from net income attributable to The AES Corporation and transfers (to) from noncontrolling interests	$	(112	)	$	114	$	286	$	445

12. SEGMENTS

The Company’s current management reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally. On September 6, 2011, the Company announced the appointment of Andrés Gluski as its President and Chief Executive Officer. Subsequently, on October 18, 2011, the Company announced a plan to redefine its operational management and organizational structure. The planned reporting structure will remain organized along two lines of business — Generation and Utilities, however, we are continuing to evaluate both the timing and impact, if any, that the realignment will have on our reportable segments. For the three and nine months ended September 30, 2011 the Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and concluded it has the following six reportable segments:

• Latin America — Generation;

• Latin America — Utilities;

• North America — Generation;

• North America — Utilities;

• Europe — Generation; and

• Asia — Generation.

Corporate and Other — The Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation operating segments and other climate solutions and renewables projects are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our presentation of reportable segments, individually or in the aggregate. AES Solar and certain other unconsolidated businesses are accounted for using the equity method of accounting;

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therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Consolidated Statements of Operations, not in revenue or gross margin. “Corporate and Other” also includes costs related to corporate overhead costs which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

The Company uses Adjusted Gross Margin, a non-GAAP measure, to evaluate the performance of its segments. Adjusted Gross Margin is defined by the Company as: Gross Margin plus depreciation and amortization less general and administrative expenses.

Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain self insurance activities which are reflected within segment Adjusted Gross Margin. All intra-segment activity has been eliminated with respect to revenue and Adjusted Gross Margin within the segment. Inter-segment activity has been eliminated within the total consolidated results. All balance sheet information for businesses that were discontinued or classified as held for sale as of September 30, 2011 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.

Information about the Company’s operations by segment for the three and nine months ended September 30, 2011 and 2010 was as follows:

Three Months Ended September 30,	Total Revenue						Intersegment						External Revenue
	2011			2010			2011			2010			2011		2010
	(in millions)
Latin America — Generation	$	1,302		$	1,111		$	(328	)	$	(267	)	$	974	$	844
Latin America — Utilities		1,930			1,757			-			-			1,930		1,757
North America — Generation		372			413			-			-			372		413
North America — Utilities		321			306			-			-			321		306
Europe — Generation		397			282			-			-			397		282
Asia — Generation		172			136			-			-			172		136
Corp/Other & eliminations		(113	)		(15	)		328			267			215		252
Total Revenue	$	4,381		$	3,990		$	-		$	-		$	4,381	$	3,990

Nine Months Ended September 30,	Total Revenue						Intersegment						External Revenue
	2011			2010			2011			2010			2011		2010
	(in millions)
Latin America — Generation	$	3,810		$	3,178		$	(842	)	$	(778	)	$	2,968	$	2,400
Latin America — Utilities		5,774			5,236			-			-			5,774		5,236
North America — Generation		1,116			1,173			(4	)		-			1,112		1,173
North America — Utilities		890			869			-			-			890		869
Europe — Generation		1,125			864			(1	)		-			1,124		864
Asia — Generation		449			491			-			-			449		491
Corp/Other & eliminations		(47	)		(34	)		847			778			800		744
Total Revenue	$	13,117		$	11,777		$	-		$	-		$	13,117	$	11,777

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Three Months Ended September 30,	Total Adjusted Gross Margin					Intersegment						External Adjusted Gross Margin
	2011			2010		2011			2010			2011			2010
	(in millions)
Latin America — Generation	$	505		$	436	$	(313	)	$	(262	)	$	192		$	174
Latin America — Utilities		378			306		322			267			700			573
North America — Generation		145			146		3			5			148			151
North America — Utilities		113			118		-			-			113			118
Europe — Generation		128			71		2			2			130			73
Asia — Generation		35			51		-			1			35			52
Corp/Other & eliminations		(62	)		12		(14	)		(13	)		(76	)		(1	)
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization													(313	)		(271	)
Interest expense													(432	)		(381	)
Interest income													103			96
Other expense													(76	)		(23	)
Other income													58			17
Goodwill impairment													(17	)		(18	)
Asset impairment expense													(163	)		(296	)
Foreign currency transaction (losses) gains on net monetary position													(92	)		103
Other non-operating expense													(82	)		(2	)
Income from continuing operations before taxes and equity in earnings of affiliates												$	228		$	365

Nine Months Ended September 30,	Total Adjusted Gross Margin					Intersegment						External Adjusted Gross Margin
	2011			2010		2011			2010			2011			2010
	(in millions)
Latin America — Generation	$	1,493		$	1,296	$	(800	)	$	(766	)	$	693		$	530
Latin America — Utilities		1,035			888		820			778			1,855			1,666
North America — Generation		402			406		6			12			408			418
North America — Utilities		292			324		1			1			293			325
Europe — Generation		327			287		4			5			331			292
Asia — Generation		133			204		1			3			134			207
Corp/Other & eliminations		(37	)		19		(32	)		(33	)		(69	)		(14	)
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization													(909	)		(802	)
Interest expense													(1,178	)		(1,151	)
Interest income													293			304
Other expense													(131	)		(83	)
Other income													108			94
Gain on sale of investments													7			-
Goodwill impairment													(17	)		(18	)
Asset impairment expense													(196	)		(297	)
Foreign currency transaction (losses) gains on net monetary position													(21	)		(19	)
Other non-operating expense													(82	)		(7	)
Income from continuing operations before taxes and equity in earnings of affiliates												$	1,519		$	1,445

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Assets by segment as of September 30, 2011 and December 31, 2010 were as follows:

	Total Assets
	September 30, 2011		December 31, 2010
	(in millions)
Assets
Latin America — Generation	$	10,545	$	10,373
Latin America — Utilities		8,938		9,872
North America — Generation		4,403		4,681
North America — Utilities		3,218		3,139
Europe — Generation		4,264		4,178
Asia — Generation		1,725		1,762
Discontinued businesses		407		468
Corp/Other & eliminations		7,383		6,038
Total Assets	$	40,883	$	40,511

13. OTHER INCOME (EXPENSE)

The components of other income for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in millions)
Tax credit settlement	$	31	$	-	$	31	$	-
Tax dispute settlement		14		-		14		-
Extinguishment of liability		-		-		-		62
Gain on sale of assets		9		5		25		7
Other		4		12		38		25
Total other income	$	58	$	17	$	108	$	94

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

Other income of $58 million for the three months ended September 30, 2011 was primarily due to an additional tax credit settlement from a favorable court decision in 2011 concerning reimbursement of excess non-income taxes paid from 1989 to 1992 at Eletropaulo and the reimbursement of income tax expense recognized during the quarter related to an indemnity agreement between Los Mina and the Dominican Republic government. Other income of $17 million for the three months ended September 30, 2010 was primarily related to the gain on sale of assets at Eletropaulo.

Other income of $108 million for the nine months ended September 30, 2011 was primarily related to the items described above, in addition to the gain on sale of mineral rights and land at IPL. Other income of $94 million for the nine months ended September 30, 2010 was primarily related to the extinguishment of a swap liability owed by two of our Brazilian subsidiaries, resulting in the recognition of a $62 million gain. The net impact to the Company after taxes and non-controlling interest was $9 million.

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The components of other expense for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in millions)
Loss on sale and disposal of assets	$	31	$	17	$	60	$	36
Loss on extinguishment of debt		36		-		52		9
Wind Generation transaction costs		-		-		-		22
Other		9		6		19		16
Total other expense	$	76	$	23	$	131	$	83

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

Other expense of $76 million for the three months ended September 30, 2011 was primarily due to the premium paid on the early retirement of debt at Gener and losses on the disposal of assets at TermoAndes and Eletropaulo. Other expense of $23 million for the three months ended September 30, 2010 was primarily comprised of losses on the disposal of assets at Eletropaulo and Gener.

Other expense of $131 million for the nine months ended September 30, 2011 was primarily due to the premium paid on early retirement of debt at Gener, a loss related to the early retirement of senior notes due in 2011 at IPL, and loss on disposal of assets at Eletropaulo and TermoAndes. Other expense of $83 million for the nine months ended September 30, 2010 included the previously capitalized transaction costs of $22 million that were incurred in connection with the preparation for the sale of a noncontrolling interest in our Wind Generation business. These costs were written off upon the expiration of the letter of intent (“LOI”) on June 30, 2010. Also, there was a $9 million loss on debt extinguishment at the Parent Company from the retirement of senior notes, and losses on disposal of assets at Eletropaulo and Gener.

14. IMPAIRMENTS

Asset Impairment

Asset impairment expense for the three and nine months ended September 30, 2011 and 2010 consisted of:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in millions)
Wind turbines & deposits	$	116	$	-	$	116	$	-
Carbon reduction projects		33		-		33		-
Kelanitissa		4		-		37		-
Southland (Huntington Beach)		-		200		-		200
Tisza II		-		85		-		85
Other		10		11		10		12
Total asset impairment expense	$	163	$	296	$	196	$	297

During the third quarter of 2011, the Company evaluated the future use of certain wind turbines held in storage pending their installation. Due to reduced wind turbine market pricing and advances in turbine technology, the Company determined it was more likely than not that the turbines would be sold significantly

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before the end of their previously estimated useful lives. In addition, the Company has concluded that more likely than not non-refundable deposits it had made in prior years to a turbine manufacturer for the purchase of wind turbines are not recoverable. The Company determined it was more likely than not that it would not proceed with the purchase of turbines due to the availability of more advanced and lower cost turbines in the market. These developments were more likely than not as of September 30, 2011 and as a result were considered impairment indicators. In October 2011, the Company determined that an impairment had occured as of September 30, 2011 as the aggregate carrying amount of $161 million of these assets was not recoverable and was reduced to their estimated fair value of $45 million determined under the market approach. This resulted in asset impairment expense of $116 million for the three and nine months ended September 30, 2011. Wind Generation is reported in the Corporate and Other segment

During the third quarter of 2011, the markets for emission reduction offsets, including Certified Emission Reductions (CERs) and European Allowance Units (EUAs), experienced a significant adverse change, as the global economic conditions contributed to unforeseen deterioration in the market prices of CERs and EUAs. This decline in the market prices of emission reduction offsets adversely impacted the Company’s Carbon Reduction Projects in Asia and Latin America. The Latin American project also incurred current period operating losses and is projecting continuing operating and cash flow losses for future periods. Consequently, we determined that indicators of impairment existed as of September 30, 2011 and the carrying amounts of these projects were not recoverable based on undiscounted cash flows. The fair value of the projects was then determined using discounted cash flow analysis. The aggregate carrying amount of $49 million of these projects was written down as their estimated fair value was $11 million, resulting in asset impairment expense of $33 million, which was limited to the carrying amounts of long-lived assets. Carbon Reduction Projects are reported in the Corporate and Other segment.

During the second quarter of 2011, the Company recognized asset impairment expense of $33 million for the long-lived assets of Kelanitissa, our diesel-fired generation plant in Sri Lanka. We have continued to evaluate the recoverability of our long-lived assets at Kelanitissa as a result of both the existing government regulation which may require the government to acquire an ownership interest and the current expectation of future losses. Our evaluation during the quarter indicated that the long-lived assets were no longer recoverable and accordingly they were written down to their estimated fair value of $33 million based on a discounted cash flow analysis. The long-lived assets had a carrying amount of $66 million prior to the recognition of asset impairment expense. An additional impairment of $4 million was recognized in the three months ended September 30, 2011. Kelanitissa is a Build-operate-transfer (BOT) generation facility and payments under its PPA are scheduled to decline over the PPA term. It is possible that further impairment charges may be required in the future as Kelanitissa gets closer to the BOT date. Kelanitissa is reported in the Asia Generation reportable segment.

During the third quarter of 2011, the Company concluded it was more likely than not that it would sell its interest in two distribution companies and a small generation plant in Argentina. This was considered an impairment indicator. An evaluation of the recoverability of their carrying amount concluded that using probability-weighted undiscounted cash flows, the carrying amounts of the asset groups were recoverable and no impairment charge was recognized for the three months ended September 30, 2011. However, it is reasonably possible that the estimate of undiscounted cash flows at September 30, 2011 could change in the near term. For example, sales negotiations may be finalized in the near term resulting in the need to recognize an impairment charge, which may be material. The aggregate carrying amount of the entities at September 30, 2011 was approximately $317 million, which includes cumulative translation losses of $208 million currently classified as accumulated other comprehensive loss in equity. As the proceeds from a possible sale are likely to be minimal, we would be required to write down substantially all of the carrying amount of these entities.

During the third quarter of 2010, the Company entered into annual negotiations with the offtaker of its Tisza II generation plant in Hungary. As a result of these preliminary negotiations, as well as the further deterioration of the economic environment in Hungary, the Company determined that an indicator of impairment existed at September 30, 2010. Thus, the Company performed an asset impairment test in accordance with the accounting guidance on property, plant and equipment and determined that based on the undiscounted cash flow analysis, the carrying amount of the Tisza II asset group was not recoverable. The fair value of the asset group was then

45

determined using a discounted cash flow analysis. The carrying value of the Tisza II asset group of $160 million exceeded the fair value of $75 million resulting in the recognition of asset impairment expense of $85 million during the three and nine months ended September 30, 2010. Tisza II is reported in the Europe Generation reportable segment.

In September 2010, the Office of Administrative Law in California approved the policy that will require the Company to change the process through which it uses ocean water to cool the generation turbines at its Alamitos, Huntington Beach and Redondo Beach (collectively “Southland”) gas-fired generation facilities in California. The policy requires compliance with the new regulations by December 31, 2020. The change in the water cooling process will result in significant future capital expenditures to ensure compliance with the new regulations or a shut down of the plants and the Company determined that an indicator of impairment existed at September 30, 2010. The Company performed an asset impairment test and the asset group was determined to be at the individual plant level and based on the undiscounted cash flow analysis, the Company determined that the Huntington Beach asset group was not recoverable. The fair value of the Huntington Beach asset group was then determined using a discounted cash flow analysis. The carrying value of the Huntington Beach plant of $288 million exceeded the fair value of $88 million resulting in the recognition of asset impairment expense of $200 million for the three and nine months ended September 30, 2010. The undiscounted cash flows of the Alamitos and Redondo Beach asset groups exceeded their respective carrying values and resulted in no impairment. Huntington Beach is reported in the North America Generation reportable segment.

Goodwill Impairment

Goodwill impairment was $17 million for the three and nine months ended September 30, 2011. During the third quarter of 2011, the Company identified higher coal prices and the resulting reduced operating margins in China as an impairment indicator for the goodwill at Chigen, our holding company that holds equity interests in Chinese ventures. A significant downward revision of cash flow forecasts indicated that the fair value of Chigen reporting unit was lower than its carrying amount. See Note 15 — Other Non-operating Expense for further information. As of September 30, 2011, Chigen had goodwill of $17 million. The Company performed an interim impairment evaluation of Chigen’s goodwill and determined that goodwill had no implied fair value. As a result, the entire carrying amount of $17 million was recognized as goodwill impairment.

Goodwill impairment was $18 million for the three and nine months ended September 30, 2010. During the third quarter of 2010, the Company determined that there was an indicator that the carrying value of goodwill related to Deepwater, our pet coke-fired merchant generation facility in Texas, was not recoverable. This determination was based primarily on the fact that Deepwater did not operate for more than 30 days in the three months ended September 30, 2010, had incurred operating and cash flow losses and was forecasting operating and cash flow losses for the remainder of 2010 through 2014 as a result of decreases in future power price expectations and an increase in pet coke prices affecting the market. Deepwater is reported in the North America Generation segment.

15. OTHER NON-OPERATING EXPENSE

Other non-operating expense of $82 million for the three and nine months ended September 30, 2011 primarily consisted of other-than-temporary impairments of equity method investments in China.

During the third quarter of 2011 as part of the quarterly close process, the Company evaluated YangCheng International Power Generating Co Ltd (“YangCheng”), a 2,100 MW coal-fired plant in China, for other-than-temporary-impairment. AES owns a 25% interest in YangCheng and the remaining equity interest in the venture is held by Chinese partners. During the nine months ended September 30, 2011, coal prices continued an upward trend in China, thereby, reducing the operating margin of coal generation facilities. During this time, there was no corresponding increase in tariffs to compensate for higher coal prices. Power prices in China are tightly regulated by the national and provincial governments, which often limit power generators’ ability to pass through

46

increases in fuel costs to customers. In addition, under the YangCheng venture agreement, AES will surrender its equity interest to the venture partners in 2016 without additional compensation. During the nine months ended September 30, 2011, management continued to monitor the situation and in the third quarter determined that it was unlikely that there would be a reversal in the trends in coal prices during the remaining term of the venture. Accordingly, during September 2011, management revised downward its forecasts of earning and cash flows over the remaining term of the venture. The revised forecasts were significantly lower than management’s earlier estimates such that the carrying amount of the investment in YangCheng was considered to have incurred an other-than-temporary-impairment. In determining the fair value of our investment, management used a discounted cash flow analysis based on probability-weighted revised cash distribution forecasts under multiple scenarios. As of September 30, 2011, YangCheng had a carrying amount of $100 million which was written down to the estimated fair value of $26 million, and the difference was recognized as other non-operating expense.

Other non-operating expense of $2 million and $7 million, respectively, for the three and nine months ended September 30, 2010 primarily consisted of an other-than-temporary impairment of an equity method investment.

16. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

Discontinued operations includes the results of the following generation businesses:

• Eletropaulo Telecomunicacões Ltda. and AES Communications Rio de Janeiro S.A (collectively “Brazil Telecom”), our Brazil telecommunication businesses (held for sale in September 2011);

• Eastern Energy, including Cayuga, Greenidge, Somerset and Westover, in New York (held for sale in March 2011);

• Borsod and Tiszapalkonya, in Hungary (held for sale in March 2011);

• Ras Laffan, in Qatar (sold in October 2010);

• Barka, in Oman (sold in August 2010); and

• Lal Pir and Pak Gen, in Pakistan (sold in June 2010).

For the nine months ended September 30, 2010, the Company recognized a gain on disposal and impairment losses totaling $57 million. The Company incurred a loss of $14 million, net of tax and noncontrolling interests on Lal Pir and Pak Gen as a result of an increase in net assets carrying value compared to the agreed upon sale proceeds. Additionally, the Company completed the sale of its interest in Barka in August 2010 and recognized a gain on disposal of $63 million, net of noncontrolling interests and $38 million of tax expense associated with the sale.

The following table summarizes the revenue, income from operations, income tax expense, impairment and gain on sale of discontinued operations for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions)
Revenue	$	107		$	218		$	327		$	948
(Loss) income from operations of discontinued businesses	$	(6	)	$	37		$	(10	)	$	115
Income tax benefit (expense)		31			(8	)		33			(23	)
Income from operations of discontinued businesses, net of tax	$	25		$	29		$	23		$	92
Gain on sale of discontinued operations	$	-		$	79		$	-		$	57

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17. ACQUISITIONS

In the second quarter of 2011, the Company finalized the purchase price allocation related to the acquisition of Ballylumford. There were no significant adjustments made to the preliminary purchase price allocation recorded in the third quarter of 2010 when the acquisition was completed.

On April 20, 2011, the Company announced the execution of a definitive agreement (the “Merger Agreement”) with DPL, the parent company of Dayton Power & Light Company, a utility company based in Ohio. Under the terms of the Merger Agreement, AES agreed to acquire DPL for an enterprise value of $4.7 billion, consisting of cash of $3.5 billion and the assumption of net debt of approximately $1.2 billion. Through its operating subsidiaries DP&L and DPL Energy Resources, DPL serves over 500,000 customers in West Central Ohio. Additionally, DPL operates over 3,800 MW of power generation facilities and provides competitive retail energy services to industrial and commercial customers. Upon closing of the transaction, DPL will become a wholly-owned subsidiary of AES.

The consummation of the transaction is subject to approval of the Public Utilities Commission of Ohio and FERC. By September 30, 2011, the transaction had been approved by DPL shareholders and had satisfied the antitrust review under the Hart-Scott-Rodino Act. Remaining approvals are expected to be obtained during the fourth quarter of 2011 or the first quarter of 2012, although there can be no assurance that such approvals will be obtained, or that they will be obtained on reasonable terms. The transaction is also subject to certain other closing conditions. After the announcement of the transaction, certain lawsuits were filed seeking to enjoin the merger and/or seek unspecified monetary damages, some of which name AES as a defendant. The Company believes it has meritorious defenses to the lawsuits and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.

18. 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. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units, stock options and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.

The following tables present 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, 2011 and 2010. In the table below, income represents the numerator and weighted-average shares represent the denominator:

	Three Months Ended September 30,
	2011								2010
	Loss			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	$	(119	)		778	$	(0.15	)	$	41		794	$	0.05
EFFECT OF DILUTIVE SECURITIES
Stock options		-			-		-			-		2		-
Restricted stock units		-			-		-			-		3		-
DILUTED EARNINGS PER SHARE	$	(119)			778	$	(0.15)		$	41		799	$	0.05

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	Nine Months Ended September 30,
	2011						2010
	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	$	296		783	$	0.38	$	354		762	$	0.46
EFFECT OF DILUTIVE SECURITIES
Stock options		-		1		-		-		2		-
Restricted stock units		-		3		-		-		3		-
DILUTED EARNINGS PER SHARE	$	296		787	$	0.38	$	354		767	$	0.46

There were approximately 15,564,118 and 16,951,804 additional options outstanding at September 30, 2011 and 2010, 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, 2011 and 2010, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. During the three months ended September 30, 2011, 115,597 shares of common stock were issued upon the exercise of stock options. For the nine months ended September 30, 2011 and 2010, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. During the nine months ended September 30, 2011, 1,073,539 shares of common stock were issued under the Company’s profit sharing plan and 589,948 shares of common stock were issued upon the exercise of stock options.

19. REGULATORY ASSETS AND LIABILITIES

Regulatory liabilities generally represent obligations to make refunds to customers for previous collections of revenue and for costs that are not likely to be incurred or included in future rate events. For example, in July 2011, the Brazilian energy regulator (the “Regulator”) postponed the periodic review and reset of a component of Eletropaulo’s regulated tariff, which determines the margin to be earned by Eletropaulo. The review and reset of this tariff component is performed every four years. From July 2011 through September 2011, Eletropaulo continued to invoice customers under the existing tariff rate, as required by the Regulator. Management believes that it is probable that the new tariff rate will be lower than the existing tariff rate, resulting in future refunds to customers, and has estimated the amount of this liability. Accordingly, as of September 30, 2011, Eletropaulo recognized a regulatory liability and corresponding reduction in revenue of approximately $104 million. It is at least reasonably possible that future events confirming the final amount of the regulatory liability or a change in the estimated amount of the liability will occur in the near term as the periodic review and tariff reset process progresses with the Regulator through the remainder of 2011 and into 2012. The primary factors in the ongoing discussions between the Brazilian distribution companies, including Eletropaulo, and the Regulator that cause the estimate to be sensitive to change include the regulatory asset base and the investment return rate assumptions used in the determination of the margin. The final amount of the regulatory liability may differ from the estimated amount recognized as of September 30, 2011.

20. SUBSEQUENT EVENTS

On October 3, 2011, the Company completed the placement of $1.25 billion aggregate principal amount senior notes with Wells Fargo Bank N.A. See Note 8 — Debt, Non-Recourse Debt for further information.

In July 2011, a subsidiary of the Company entered into an agreement to sell its ownership interest in two telecommunication companies in Brazil. The Company held approximately 46% ownership interest in these companies through the subsidiary. The transaction closed on October 31, 2011 and the subsidiary received

49

approximately R$1,522 million ($901million), subject to customary purchase price adjustments. The estimated gain on the sale before noncontrolling interests and taxes is approximately R$1,333 million ($789 million), subject to final purchase price adjustments.

On October 20, 2011, a subsidiary of the Company signed a share sale agreement with Electrabel International Holdings B.V. (“EIH”), a subsidiary of GDF SUEZ S.A. (“GDFS”) for the sale of 80% of its interest in the wholly-owned holding company that holds the Company’s interest in AES Energia Cartagena S.R.L. (“AES Cartagena”), a 1,199 MW gas-fired generation business in Spain, for €172 million ($234 million), subject to customary purchase price adjustments. AES owns approximately 70.81% of AES Cartagena through this holding company structure. Under the terms of the sale agreement, EIH has an option to purchase AES’ remaining 20% interest in the holding company for a fixed price of €28 million ($38 million) during a five month period beginning 13 months from the date the sale closes. Subject to regulatory and lenders’ approvals, the sale is expected to close by the end of 2011. Concurrent with the sale, GDFS agreed to settle the outstanding arbitration between the parties regarding certain emissions costs and other taxes that AES Cartagena sought to recover from GDFS as energy manager under the existing commercial arrangements and to pay €58 million ($79 million) to AES Cartagena for such costs incurred by AES Cartagena during the period up to December 31, 2010 and additional amounts for such costs incurred by AES Cartagena during the period from January 1, 2011 until closing of the sale. However, the settlement of the arbitration is contingent on consummation of the sale. See Note 9 — Contingencies and Commitments for further information.

Subsequent to September 30, 2011, the Company continued to repurchase stock under the stock repurchase program announced on July 7, 2010. The Company has repurchased 5,554,185 shares at a cost of $54 million subsequent to September 30, 2011, bringing the cumulative total through November 3, 2011 to 33,924,805 shares at a total cost of $378 million (average price of $11.16 per share including commissions). For additional information, see Note 11 — Equity.

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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 consolidated entity 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 June 1, 2011, The AES Corporation filed a Current Report on Form 8-K (“June 2011 Form 8-K”) to recast previously filed financial statements included in the Company’s Form 10-K for the year ended December 31, 2010 (“2010 Form 10-K”) to reclassify certain businesses held for sale as discussed in Note 16 — Discontinued Operations and Held for Sale Businesses to item 1. — Financial Statements. 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 2010 Form 10-K and the June 2011 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 of our 2010 Form 10-K filed on February 25, 2011, the Form 10-Q for the first quarter of 2011 filed on May 6, 2011 and this Form 10-Q for the period ended September 30, 2011. 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. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements. 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 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, other intermediaries and certain end-users. The second is our Utilities business, where we own and/or operate utilities which distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area and in certain circumstances, sell electricity on the wholesale market. For the nine months ended September 30, 2011 our Generation and Utilities businesses comprised approximately 45% and 55% of our consolidated revenue, respectively. For additional information regarding our business, see Item 1. — Business of the June 2011 Form 8-K.

We are also continuing to expand our wind and solar businesses. These initiatives are not material contributors to our operating results, but we believe that certain of these initiatives may become material in the future. For additional information regarding our business, see Item 1. — Business of the June 2011 Form 8-K.

Our Organization and Segments.    The Company’s current management reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The financial reporting segment structure uses the Company’s management reporting structure as its foundation and reflects how the Company manages the business internally. On September 6, 2011, the Company announced the appointment of Andrés Gluski as its President and Chief Executive Officer. Subsequently, on October 18, 2011, the Company announced a plan to redefine its operational management and organizational

51

structure. The planned reporting structure will remain organized along two lines of business — Generation and Utilities, however, we are continuing to evaluate both the timing and impact, if any, that the realignment will have on our reportable segments. For the three and nine months ended September 30, 2011, the Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and concluded that it has the following six reportable segments:

• Latin America — Generation;

• Latin America — Utilities;

• North America — Generation;

• North America — Utilities;

• Europe — Generation; and

• Asia — Generation.

Corporate and Other.    The Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation operating segments and climate solutions and other renewables projects are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our financial statement presentation of reportable segments, individually or in the aggregate. “Corporate and Other” also includes costs related to corporate overhead which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

Components of Revenue and Cost of Sales.    Revenue includes revenue earned from the sale of energy from our utilities and the production of energy from our generation plants, which are classified as regulated and unregulated on the condensed consolidated statements of operations, respectively. Revenue also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the sale of electricity. Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, maintenance, operations, non-income taxes and bad debt expense and recoveries as well as depreciation and general and administrative and support costs, including employee-related costs, that are directly associated with the operations of a particular business. Cost of sales also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.

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 reliability and efficiency, power prices, volume, 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. Growth in our Generation business is largely tied to securing new PPAs, expanding capacity in our existing facilities and building or acquiring new power plants. Performance drivers for our Utilities businesses include, but are not limited to, reliability of service; management of working capital, including collection of receivables; negotiation of tariff adjustments; compliance with extensive regulatory requirements; management of pension assets; and in developing countries, reduction of commercial and technical losses. The operating results of our Utilities

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businesses are sensitive to changes in inflation, economic growth and weather conditions in 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 affect our Generation business is our ability to enter into contracts for the sale of electricity and the purchase of 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 revenue 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 arrangements 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 flows 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. Entering into these contracts exposes us to counterparty credit risk. For further discussion of these risks, see “Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks.” in Item 1A. — Risk Factors of the 2010 Form 10-K.

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. To the extent our businesses are unable to pass through fuel cost increases to their customers, gross margin may be adversely affected.

Global diversification also helps us to mitigate risk. Our presence in mature markets helps mitigate the exposure associated with our businesses in emerging markets. Additionally, our portfolio employs a broad range of fuels, including coal, gas, fuel oil, water (hydroelectric power), wind and solar, which reduces the risks associated with dependence on any one fuel source. However, to the extent the mix of fuel sources enabling our generation capabilities in any one market is not diversified, the spread in costs of different fuels may also influence the operating performance and the ability of our subsidiaries to compete within that market. For example, in a market where gas prices fall to a low level compared to coal prices, power prices may be set by low gas prices which can affect the profitability of our coal plants in that market. In certain cases, we may attempt to hedge fuel prices to manage this risk, but there can be no assurance that these strategies will be effective.

We also attempt to limit risk by hedging much of our interest rate and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the underlying business. 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 Item 1A. — Risk Factors of the 2010 Form 10-K, “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.” Commodity and power price volatility could continue to impact our financial metrics to the extent this volatility is not hedged. For a discussion of our sensitivities to commodity, currency and interest rate risk, see Item 3. — Quantitative and Qualitative Disclosures About Market Risk in this Form 10-Q.

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

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statements. Additionally, there is a 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 Item 1A. — Risk Factors of the 2010 Form 10-K, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.” In the three and nine months ended September 30, 2011, changes in foreign currency exchange rates have had a significant impact on our operating results. If the current foreign currency exchange rate volatility continues, our gross margin and other financial metrics could be affected.

Another key driver of our results is our ability to bring new businesses into commercial operations successfully. We currently have approximately 2,294 MW of projects under construction in eleven countries. Our prospects for increases in operating results and cash flows are dependent upon successful completion of these projects on time and within budget. However, as disclosed in Item 1A. — Risk Factors of the 2010 Form 10-K, “Our business is subject to substantial development uncertainties,” construction is subject to a number of risks, including risks associated with site identification, 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 costs related to capital expenditures and otherwise navigate these regulations can have an impact on our revenue, costs and gross margin. Environmental and land use regulations, including existing and proposed regulation of GHG 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, see Note 9 — Contingencies and Commitments — Environmental, included in Item 1. — Financial Statements of this Form 10-Q and Item 1. — Business — Regulatory Matters — Environmental and Land Use Regulations and Item 1A. — Risk Factors — Risks Associated with Government Regulation and Laws of the 2010 Form 10-K.

Key Drivers of Results in the Three Months Ended September 30, 2011

During the three months ended September 30, 2011, the Company’s gross margin increased $53 million and net income attributable to The AES Corporation decreased $245 million, while net cash from operating activities increased $127 million compared to the same period in 2010.

During the three months ended September 30, 2011, the Company benefited from new businesses including Ballylumford, in Northern Ireland, acquired in August 2010, and Angamos I, in Chile, and Maritza, in Bulgaria, which commenced commercial operations in April and June 2011, respectively. Gener, our generation business in Chile, saw improvements over the prior year due to higher generation at the Electrica Santiago plant running on liquefied natural gas and higher contract and spot sales. These favorable results were offset by the unfavorable impacts of outages in Panama and an unfavorable adjustment to regulatory liabilities at Eletropaulo related to the estimated impact of the July 2011 tariff reset as discussed below. Absent the favorable impact of foreign currency, gross margin for the Company would have remained flat for the quarter. During the three months ended September 30, 2011, gross margin did not increase at the same rate as revenue primarily due to the pass-through of fuel costs and purchased energy that increase revenue but do not have a corresponding impact on gross margin as well as a forced outage in Panama.

For the remainder of 2011 and into 2012, we expect to face continued challenges at certain of our businesses. The determination of the 2011 tariff reset in Brazil has been postponed until late 2011. Although we expect the tariff to decrease, its components and their potential impact on our Brazilian utility, Eletropaulo,

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remain uncertain at this time. Additionally, the Company identified damage to a tunnel at a hydroelectric plant in Panama in late 2010, which will cause the plant to be offline through mid-2012. Until the ultimate disposition of Eastern Energy in New York, which is classified as held for sale, the Company will continue to see the effects of relatively lower gas prices and a decline in power prices relative to coal. These conditions are not hedged for the remainder of 2011. In addition, as further described in Key Trends and Uncertainties — Sale of Eastern Energy below, we placed Eastern Energy into discontinued operations based on our intention to sell our interest in the business. While we are continuing our efforts to sell our interest in the business and believe that the sale is probable of being consummated by March 31, 2012 for the assets to continue to be presented as discontinued operations, there can be no assurance that we will be successful in these efforts. In addition, we currently anticipate a benefit to our 2011 results if we close the sale of 80% of our interest in AES Cartagena. However, there can be no assurance that we will close the transaction or if we do, that it will close by year-end. Additional items that could impact our 2011 or 2012 results are discussed in Key Trends and Uncertainties below, along with the risk factors included in our 2010 Form 10-K and Forms 10-Q for the periods ended March 31, 2011 and September 30, 2011. However, management expects that improved operating performance at certain businesses and growth from newly acquired businesses and businesses expected to commence operations in 2011 may lessen or offset the impact of the challenges described above. If these favorable effects do not occur, or if the challenges described above and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move unfavorably, then these adverse factors (or other adverse factors unknown to us) may impact our gross margin, net income attributable to The AES Corporation and cash flows.

The following briefly describes the key changes in our reported revenue, gross margin, net income attributable to The AES Corporation, diluted earnings per share from continuing operations, Adjusted Earnings per Share (a non-GAAP measure) and net cash provided by operating activities for the three and nine months ended September 30, 2011 compared to the three and nine months ended September 30, 2010 and should be read in conjunction with our Consolidated Results of Operations discussion below.

Performance Highlights

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011			2010		% Change			2011		2010		% Change
	($’s in millions, except per share amounts)
Revenue	$	4,381		$	3,990		10	%	$	13,117	$	11,777		11	%
Gross Margin	$	1,020		$	967		5	%	$	3,019	$	2,901		4	%
Net (Loss) Income Attributable to The AES Corporation	$	(131	)	$	114		-215	%	$	267	$	445		-40	%
Net Cash Provided by Operating Activities	$	1,127		$	1,000		13	%	$	2,308	$	2,416		-4	%
Diluted (Loss) Earnings per Share from Continuing Operations	$	(0.15	)	$	0.05		-400	%	$	0.38	$	0.46		-17	%
Adjusted Earnings Per Share (a non-GAAP measure)(1)	$	0.27		$	0.20		35	%	$	0.76	$	0.70		9	%

⁽¹⁾ See reconciliation and definition below under Non-GAAP Measure.

Our third quarter and year-to-date financial results include the following highlights:

Three months ended September 30, 2011:

Revenue increased $391 million, or 10%, to $4.4 billion in the three months ended September 30, 2011 compared with $4.0 billion in the three months ended September 30, 2010. Key drivers of the increase included:

• the favorable impact of foreign currency of $173 million;

• the impact of new businesses including Ballylumford, in Northern Ireland, acquired in August 2010 and Angamos I, in Chile, and Maritza, in Bulgaria, that commenced commercial operation in April and June 2011, respectively;

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• increased prices at our generation businesses in Argentina and at Gener, in Chile; and

• increased volume at our Brazilian utilities, driven by increased market demand.

These increases were partially offset by:

• lower prices at Eletropaulo, our utility in Brazil, primarily related to the estimated impact of the July 2011 tariff reset which has been postponed by the Brazilian energy regulatory agency; and

• the unfavorable impact of an unrealized mark-to-market derivative loss at Sonel.

Gross margin increased $53 million, or 5%, to $1.0 billion in the three months ended September 30, 2011 compared with $967 million in the three months ended September 30, 2010. Key drivers of the increase included:

• the favorable impact of foreign currency of $51 million;

• the impact of new businesses including Ballylumford, acquired in August 2010 and Angamos and Maritza that commenced commercial operation in April and June 2011, respectively;

• increased volume at Gener; and

• decreased fixed costs primarily due to a non-recurring reduction in bad debt expense and lower contingencies at Eletropaulo.

These increases were partially offset by:

• the unfavorable impact of an unrealized mark-to-market derivative loss at Sonel;

• lower prices at our Brazilian utilities, primarily due to the estimated impact of the July 2011 tariff reset as discussed above;

• the unfavorable impact of outages in Panama; and

• higher fuel prices at Gener in Chile.

Net income attributable to The AES Corporation decreased $245 million to a loss of $131 million in the three months ended September 30, 2011 compared with income of $114 million in the three months ended September 30, 2010. Key drivers of the decrease included:

• foreign currency losses at The AES Corporation due to the decrease in valuation of cash, note receivables and trade receivables related to the weakening of the Euro and British Pound and losses in Chile associated with the net working capital denominated in Chilean Pesos due to the devaluation of the Chilean Peso;

• other-than-temporary impairment losses related to two of our equity investments in China; and

• the gain on sale of discontinued operations related to the sale of Barka which occurred in August 2010.

These decreases were partially offset by:

• a decrease in asset impairment losses due to higher impairment losses in the prior year related to Southland and Tisza II generation facilities offset primarily by the current year asset impairment for Wind.

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Net cash provided by operating activities increased $127 million, or 13%, to $1.1 billion in the three months ended September 30, 2011 compared with $1.0 billion in the three months ended September 30, 2010. Key drivers of the increase included:

• an increase at our Latin American generation businesses primarily due to higher collection of account receivables in Chile;

• an increase at our Europe generation businesses as a result of commenced commercial operations at Maritza in Bulgaria and a full quarter of operations at Ballylumford in Northern Ireland; offset by

• a decrease at our Latin American utilities businesses primarily due to higher energy purchases and regulatory charges at Eletropaulo and higher working capital needs in El Salvador;

• a decrease at our Asia generation businesses primarily due to lower operating income at Masinloc in the Philippines as well as from the sale of Ras Laffan in 2010.

Nine months ended September 30, 2011:

Revenue increased $1.3 billion, or 11%, to $13.1 billion in the nine months ended September 30, 2011 compared with $11.8 billion in the nine months ended September 30, 2010. Key drivers of the increase included:

• the favorable impact of foreign currency of $600 million;

• the impact of new businesses including Ballylumford, acquired in August 2010 and Angamos and Maritza, which commenced commercial operations in April and June 2011, respectively;

• increased price and volume in Chile;

• increased price at our generation businesses in Argentina; and

• increased volume at our Brazilian utilities, driven by increased market demand.

These increases were partially offset by:

• lower prices at our utility businesses in Brazil primarily due to the estimated impact of the July 2011 tariff reset which has been postponed by the Brazilian energy regulatory agency;

• lower volume at Cartagena and Tisza II; and

• the unfavorable impact of an unrealized mark-to-market derivative loss at Sonel.

Gross margin increased $118 million, or 4%, to $3.0 billion in the nine months ended September 30, 2011 compared with $2.9 billion in the nine months ended September 30, 2010. Key drivers of the increase included:

• the favorable impact of foreign currency of $148 million;

• the impact of new businesses including Ballylumford, acquired in August 2010, and Angamos and Maritza, which commenced commercial operation in April and June 2011, respectively;

• increased price and volume at Gener; and

• increased volume at our Brazilian utilities, driven by increased market demand.

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These increases were partially offset by:

• lower prices at our Brazilian utility business, primarily related to the estimated impact of the July 2011 tariff reset which has been postponed by the Brazilian energy regulatory agency;

• the unfavorable impact of outages in Panama;

• the unfavorable impact of an unrealized mark-to-market derivative loss at Sonel;

• lower volume at IPL in Indiana;

• an increase in global fixed costs, particularly at our Latin American generation businesses;

• lower spot prices and volume at Masinloc; and

• lower prices at Kilroot.

Net income attributable to The AES Corporation decreased $178 million, or 40%, to $267 million in the nine months ended September 30, 2011 compared with $445 million in the nine months ended September 30, 2010. Key drivers of the decrease included:

• a decrease in net equity in earnings of affiliates partially offset by income tax expense related to the sale of the Company’s indirect investment in CEMIG in 2010;

• a decrease in discontinued operations related to the sale of Barka which occurred in August 2010 and lower net income related to discontinued businesses in 2011; and

• other-than-temporary impairment losses related to our equity investments in China.

These decreases were partially offset by:

• a decrease in asset impairment losses as described above;

• a decrease in income tax expense primarily due to the extension of a favorable U.S. tax law in the fourth quarter of 2010 impacting distributions from certain non-U.S. subsidiaries; and

• an increase in gross margin as described above.

Net cash provided by operating activities decreased $108 million, or 4%, to $2.3 billion in the nine months ended September 30, 2011 compared with $2.4 billion in the nine months ended September 30, 2010. Please refer to Consolidated Cash Flows — Operating Activities for further discussion.

Non-GAAP Measure

We define adjusted earnings per share (“Adjusted EPS”) as diluted earnings per share from continuing operations excluding gains or losses of the consolidated entity due to (a) mark-to-market amounts related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) significant gains or losses due to dispositions and acquisitions of business interests, (d) significant losses due to impairments, and (e) costs due to the early retirement of debt. The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. AES believes that Adjusted EPS better reflects the underlying business performance of the Company and is considered in the Company’s internal evaluation of financial performance. Factors in this determination include the variability due to mark-to-market gains or losses related to derivative transactions, currency gains or losses, losses due to impairments and strategic decisions to dispose or acquire business interests or retire debt, which affect results in a given period or periods. Adjusted EPS should not be construed as an alternative to diluted earnings per share from continuing operations, which is determined in accordance with GAAP.

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For the three months ended September 30, 2011, the Company reported a loss from continuing operations of $0.15 per share. For purposes of measuring diluted loss per share under GAAP, common stock equivalents were excluded from weighted average shares as their inclusion would be antidilutive. However, for purposes of computing Adjusted EPS (a non-GAAP measure), the Company has included the impact of dilutive common stock equivalents as the inclusion of the defined adjustments result in income for Adjusted EPS. The table below reconciles the weighted average shares used in GAAP diluted earnings per share to the weighted average shares used in calculating the non-GAAP measure of Adjusted EPS:

	Three Months Ended September 30, 2011
	Loss			Shares		$ per Share
Reconciliation of Denominator Used For Adjusted Earnings Per Share
GAAP DILUTED EARNINGS PER SHARE
Loss from continuing operations attributable to The AES Corporation common stockholders	$	(119	)		778	$	(0.15	)
EFFECT OF DILUTIVE SECURITIES
Stock options		-			1		-
Restricted stock units		-			3		-
NON-GAAP DILUTED EARNINGS (LOSS) PER SHARE	$	(119	)		782	$	(0.15	)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Reconciliation of Adjusted Earnings Per Share
Diluted earnings per share from continuing operations	$	(0.15	)	$	0.05		$	0.38		$	0.46
Derivative mark-to-market (gains)/losses(1)		0.02			0.02			0.01			0.01
Currency transaction (gains)/losses(2)		0.10			(0.13	)		0.02			(0.04	)
Disposition/acquisition (gains)/losses		-			-			-			-	(3)
Impairment losses		0.27	(4)		0.26	(5)		0.31	(6)		0.26	(5)
Debt retirement (gains)/losses		0.03	(7)		-			0.04	(8)		0.01	(9)
Adjusted earnings per share	$	0.27		$	0.20		$	0.76		$	0.70

⁽¹⁾ Derivative mark-to-market (gains)/losses were net of income tax per share of $0.01 in the three months ended September 30, 2011 and 2010, and of $0.00 in the nine months ended September 30, 2011 and 2010.

⁽²⁾ Unrealized foreign currency transaction (gains)/losses were net of income tax per share of $0.01 and $0.00 in the three months ended September 30, 2011 and 2010, respectively, and of $0.00 and $(0.01) in the nine months ended September 30, 2011 and 2010, respectively.

⁽³⁾ The Company did not adjust for the gain or the related tax effect from the sale of its indirect investment in CEMIG in its determination of Adjusted EPS because the gain was recognized by an equity method investee. The Company does not adjust for transactions of its equity method investees in its determination of Adjusted EPS.

⁽⁴⁾ Amount includes equity method investment impairment at Chigen, including YangCheng, of $79 million or $0.10 per share, asset impairments at Wind of $116 million ($76 million, and $0.10 per share, net of income tax), Carbon Reduction Projects of $33 million or $0.04 per share, and Bohemia of $9 million ($6 million, and $0.01 per share, net of income tax), and goodwill impairment at Chigen of $17 million or $0.02 per share.

⁽⁵⁾ Amount includes asset impairments at Southland (Huntington Beach) of $200 million and Tisza of $85 million ($130 million, or $0.17 per share, and $55 million, or $0.07 per share, net of income tax, respectively) and goodwill impairment at Deepwater of $18 million ($12 million, or $0.02 per share, net of income tax).

⁽⁶⁾ Amount includes asset impairments described in footnote (4) above, in addition to $37 million at Kelanitissa ($34 million, or $0.04 per share, net of noncontrolling interests).

⁽⁷⁾ Amount includes loss on retirement of debt at Gener of $38 million ($22 million, or $0.03 per share, net of noncontrolling interests and income tax).

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⁽⁸⁾ Amount includes loss on retirement of debt described in footnote (7) above, in addition to IPL of $15 million ($10 million, or $0.01 per share, net of income tax).

⁽⁹⁾  Amount includes loss on retirement of Parent Company debt of $9 million ($6 million, or $0.01 per share, net of income tax).

Management’s Priorities

Management has re-evaluated its priorities following the recent appointment of its new CEO. Management is focused on the following priorities:

• To resolve the remaining conditions precedent to allow us to close the acquisition of DPL, Inc. For a discussion of risks related to the DPL transaction, see Item 1A. — Risk Factors in our Form 10-Q for the quarter ended March 31, 2011;

• Execution of our geographic concentration strategy to maximize shareholder value through a disciplined capital allocation inclusive of: strategic portfolio management, corporate debt reduction, and return of capital to shareholders;

• Completing the restructuring/sale of certain businesses such as Eastern Energy and closing the sales of businesses for which we have signed agreements with counterparties such as AES Cartagena;

• Implementing a management realignment of our businesses under two business lines: Utilities and Generation and achieving cost savings through the alignment of overhead costs with business requirements, systems automation and optimal allocation of business development spending;

• Continued improvement of operations in the existing portfolio;

• Repairing the Esti hydro tunnel in Panama, as further described in Key Trends and Uncertainties — Operations below;

• Achieving full commercial operation at Maritza in Bulgaria. The plant has started partial operations with commercial production now at 620 MW and has passed capacity tests at 670 MW. Final regulatory approval for full production at 670 MW is pending as further described in Key Trends and Uncertainties — Development below; and

• Completion of an approximately 2,294 MW (including the remaining capacity at Maritza) construction program; and the integration of new projects into existing businesses. During the three months ended September 30, 2011, the following projects commenced commercial operations:

Project	Location	Fuel	Gross MW		AES Equity Interest (Percent, Rounded)
Trinidad I(1)	Trinidad	Gas		394		10	%
Changuinola I	Panama	Hydro		111		100	%
Laurel Mountain	US-WV	Wind		98		100	%
AES Solar	Italy	Solar		18		50	%
Sao Joaquim	Brazil	Hydro		3		24	%

⁽¹⁾  Trinidad is an equity method investment held by AES.

Key Trends and Uncertainties

Our operations continue to face many risks as discussed in Item 1A. — Risk Factors of the 2010 Form 10-K. Some of these challenges are also described above in “Key Drivers of Results in the Three Months Ended September 30, 2011”. We continue to monitor our operations and address challenges as they arise.

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Development

During the quarter, the Company successfully completed construction and commenced commercial operations at projects totaling approximately 624 MW. In addition, engineering efforts were completed to increase capacity at Maritza, a 670 MW coal-fired project in Bulgaria. After certain delays, Maritza began commercial operations on June 3, 2011 at a reduced capacity level of 494 MW. During the quarter, engineering efforts increased capacity to its full design of 670 MW. As noted above, Maritza is currently operating at 620 MW and efforts continue to obtain regulatory approval to operate at the full design capacity of 670 MW. As a result of delays in reaching commercial operations, the project debt is in default and the Company is working with its lenders to resolve the default. In addition, the Company is in litigation with the contractor regarding the cause of delays. The EPC contract was terminated for cause by the Company during the first quarter of 2011. At this time, we believe that Maritza will receive regulatory approval to operate at full capacity by the end of 2011. However, due to the inherent uncertainties, there could be further delays in obtaining regulatory approval to operate at the full design capacity. There can be no assurance that Maritza will resolve the default with the lenders or prevail in the litigation referenced above, which could result in loss in the value of some or all of our investment or require additional funding for the project. Any of these events could have a material adverse effect on the Company’s operating results or financial position.

In addition, the Company has a number of additional projects under construction which are expected to commence commercial operations in 2011, including Changuinola II in Panama, and a number of wind and solar projects. While we expect these projects will be completed on time, there can be no assurance that these projects will commence commercial operations on time and on budget, due to the inherent uncertainties associated with the development process. For further discussion of the risks associated with development, see Item 1A. — Risk Factors — Our business is subject to substantial development uncertainties of the 2010 Form 10-K.

Operations

Beginning in August 2010 the Esti power plant, a 120 MW run-of-river hydroelectric power plant in Panama, experienced a reduction in power generation. Following an inspection of its tunnel infrastructure in October 2010, which indicated damage, the plant was taken offline. A significant repair of the Esti tunnel and additional surrounding support structures was deemed necessary to allow the plant to continue operation and to prevent future potential damage to the tunnel. AES Panama is partially covered for business interruption losses and property damage under existing insurance programs. In June 2011, AES Panama entered into a contract for the repair of the Esti tunnel and the surrounding support structures and on July 15, 2011 the Notice to Proceed was executed. Under the contract, the repairs will be performed over an 11-month period. The Esti power plant is projected to resume operations by the second quarter of 2012. However, due to the inherent uncertainties associated with construction, it is possible that commercial operations may resume after this timeframe.

Our utility businesses are subject to significant government laws and regulations. Changes in these regulations are often uncertain and difficult to predict. In particular, our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including the inability to obtain expected or contracted increases in electricity tariff rates or tariff adjustments for increased expenses, could have an unfavorable impact on the results of operations of these businesses. For example, since 2005, one of our distribution companies in Argentina has only received partial increases in its tariff associated with operational costs and cost of capital. Operating deficits and unfunded capital investments have been subsidized by the Company. A decision to sell or dispose of the distribution company (which we believe is more likely than not) or further delays in receiving the remaining portion of the tariff could adversely affect the carrying amount of the distribution company, which could be material. The carrying amount of the distribution company at September 30, 2011 was approximately $189 million, which includes cumulative translation losses of $140 million currently classified as accumulated other comprehensive loss in equity. As the proceeds from a possible sale are likely to be minimal, we would be required to write down substantially all of the carrying amount of the distribution company.

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Other regulatory changes that have a potential to adversely impact the results of our utility businesses include regulatory tariff revisions. For example, Eletropaulo, our utility business in Brazil, is currently billing its customers under the current tariff as required by the regulator. In July 2011, the regulator postponed the review and reset of Eletropaulo’s regulated tariff, which includes a tariff component that determines the margin Eletropaulo is allowed to earn. The review and reset of the regulated tariff is performed every four years. Management believes that it is probable that the new tariff rate will be lower than the current tariff rate, resulting in future refunds to customers, and based on its best estimate continues to record the amount of future refunds as a reduction of revenue and a regulatory liability. The estimate is sensitive to the key assumptions that determine Eletropaulo’s margin such as the regulatory asset base and the investment return rate. These assumptions are subject to ongoing discussions with the regulator. As the periodic review and reset process progresses with the regulator through the remainder of 2011 and into 2012, it is at least reasonably possible that the estimated amount of refunds will change in amounts that could require more refunds than we currently expect, in amounts that could be material.

Indiana Tree Trimming Regulation

In February 2009, an IPL customer filed a formal complaint claiming IPL’s tree trimming practices were unreasonable and expressed concerns with language contained in IPL’s tariff that addressed IPL’s tree trimming and tree removal rights. Subsequently, the Indiana Utility Regulatory Commission (“IURC”) initiated a generic investigation into electric utility tree trimming practices and tariffs in Indiana. In November 2010, the IURC issued an order in the investigation, which imposed additional requirements on the conduct of tree trimming. The order included requirements on utilities to provide advance customer notice and obtain customer consent or additional easements if existing easements and rights of way are insufficient to permit pruning in accordance with the required industry standards or in the event that a tree would need to have more than 25% of its canopy removed. The order also directed that a rulemaking would be initiated to further address vegetation management practices. In December 2010, notices of appeal and petitions for reconsideration, clarification and/or rehearing were filed by multiple parties, including IPL.

On July 7, 2011, the IURC issued an additional tree trimming order which did not provide the relief IPL was seeking, but clarified utility customer notice requirements and the relationship of the order to property rights and tariff requirements. It also clarified that in cases of emergency or public safety, utilities may, without customer consent, remove more than 25% of a tree or trim beyond existing easement or right of way boundaries to remedy the situation. The IURC is currently in the process of promulgating formal rules to implement the order. IPL and other interested parties will participate in this rulemaking process. It is not possible to predict the outcome of this matter, but these proceedings could significantly increase IPL’s vegetation management costs and the costs of defending IPL’s vegetation management program in litigation, which could have a material impact on our consolidated financial statements.

Sale of Eastern Energy

As disclosed in the Company’s Form 10-K for the year ended December 31, 2010 filed on February 28, 2011 and our Form 8-K dated June 1, 2011, the Company’s North American businesses continue to face pressure as a result of high coal prices relative to natural gas, which has affected the results of certain of our coal plants in the region, particularly those which are merchant plants that are exposed to market risk, such as Eastern Energy. The Company has also previously disclosed that it is seeking a sale or restructuring of its interest in Eastern Energy and if these efforts are not successful, Eastern Energy may not be able to continue operations. As a result of the continued pressure on energy prices and negative forecasted operating cash flow and losses, management does not believe that cash flow from operations, together with available liquidity, will be sufficient to cover expected capital requirements or Eastern Energy’s obligations, including, without limitation, its debt and certain lease obligations. For example, in July 2011, Eastern Energy made payments on certain lease obligations utilizing funds from a reserve account. The reserve account does not have sufficient funds to make the next payment which is due in January 2012. In addition, one of the holding companies has outstanding debt that came

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due as of July 6, 2011, which was used to cover normal operating activities. The holding company entered into an agreement with its lenders which provides forbearance for the past due payment, which expires on November 7, 2011. While discussions are continuing regarding an extension of the forbearance period there can be no assurance that an extension will be obtained. In the event that an extension is not granted, the holding company’s lenders could foreclose on the holding company, including the shares of those subsidiaries which it owns, which could result in the loss of AES’ majority interest in those subsidiaries, which would result in a cross default on other debt and lease obligations. If Eastern Energy defaults on its debt or lease obligations, Eastern Energy could be subject to full payment of the outstanding principal or lease payments, accrued interest, termination costs under its lease arrangements and debt obligations, and other costs. In addition, as of March 31, 2011, we placed Eastern Energy into discontinued operations based on our intention to sell our interest in the business. We believe that the sale is probable of being consummated by March 31, 2012 for the business to continue to be presented as discontinued operations. However, while efforts to sell Eastern Energy continue, there can be no assurance that we will be able to sell our interest in Eastern Energy. If the Company’s efforts to sell its interest in Eastern Energy fail, or the attempts to restructure Eastern Energy’s obligations fail, Eastern Energy defaults on its debt, or it otherwise becomes clear that Eastern Energy cannot meet its future obligations, or Eastern Energy determines to file for bankruptcy and there could be a material impact on the Company and its results of operations. For example, it is possible that in prior periods, Eastern Energy may no longer be classified as discontinued operations and that the Company may be required to include Eastern Energy’s losses in the Company’s results of operations, which could have a material impact on those periods.

Global Economic Considerations.    During the past few years, economic conditions in some countries where our subsidiaries conduct business have deteriorated. Global economic conditions remain volatile and could have an adverse impact on our businesses in the event these recent trends continue.

Our business or results of operations could be impacted if we or our subsidiaries are unable to access the capital markets on favorable terms or at all, are unable to raise funds through the sale of assets or are otherwise unable to finance or refinance our activities. At this time, the Euro Zone continues to face a sovereign debt crisis, the impacts of which are described below. The Company could also be adversely affected if capital market disruptions result in increased borrowing costs (including with respect to interest payments on the Company’s or our subsidiaries’ variable rate debt) or if commodity prices affect the profitability of our plants or their ability to continue operations.

In addition, in recent months, global economic sentiment has indicated that there is a possibility of global economic slowdown in the coming months. The Company could be adversely affected if general economic or political conditions in the markets where our subsidiaries operate deteriorate, resulting in a reduction in cash flow from operations, a reduction in the availability and/or an increase in the cost of capital, or if the value of our 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.

Our subsidiaries are subject to credit risk, which includes risk related to the ability of counterparties (such as parties to our PPAs, fuel supply agreements, 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. The Company has not suffered any material effects related to its counterparties during the nine months ended September 30, 2011. However, if macroeconomic conditions impact our counterparties, they may be unable to meet their commitments which could result in the loss of favorable contractual positions, which could have a material impact on our business.

In addition, during the past year, certain European Union countries have continually faced a sovereign debt crisis and it is possible that this crisis could spread to other countries. This crisis has resulted in an increased risk of default by governments and the implementation of austerity measures in certain countries. If the crisis continues, worsens, or spreads, there could be a material adverse impact on the Company. Our businesses may be impacted if they are unable to access the capital markets, face increased taxes or labor costs, or if governments

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fail to fulfill their obligations to us or adopt austerity measures which adversely impact our projects. In addition, as discussed in Item 1A. — Risk Factors — Our renewable energy projects and other initiatives face considerable uncertainties including development, operational and regulatory challenges of the 2010 Form 10-K, our renewables businesses are dependent on favorable regulatory incentives, including subsidies, which are provided by sovereign governments, including European governments. If these subsidies or other incentives are reduced or repealed, or sovereign governments are unable or unwilling to fulfill their commitments or maintain favorable regulatory incentives for renewables, in whole or in part, this could impact the ability of the affected businesses to continue to sustain and/or grow their operations. For example, in May 2011, the Spanish government issued a decree, which limits the feed-in-tariff and number of photovoltaic hours eligible for the feed-in-tariff. Similarly, the Italian government also published a decree in May 2011, which restricts the size of projects on agricultural land and replaced the old feed-in-tariff for projects not interconnected by May 31, 2011 with a new feed-in-tariff, resulting in an approximate 30% reduction to the current tariff. These decrees may have an adverse impact in Spain and Italy on AES Solar Energy Ltd., our international solar joint venture. For further information on the Spain decree, see Item 1. — Regulatory — Spain of the 2010 Form 10-K. In addition, any of the foregoing could also impact contractual counterparties of our subsidiaries in core power or renewables. If such counterparties are adversely impacted, then they may be unable to meet their commitments to our subsidiaries. For further information on the importance of long-term contracts and our counterparty credit risk, see Item 1A. — Risk Factors — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations…” of the 2010 Form 10-K. As a result of any of the foregoing events, we may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. The Company’s investment in AES Solar Energy Ltd., whose primary operations are in Europe, was $243 million at September 30, 2011. During the nine months ended September 30, 2011, in connection with the Italian decree noted above, AES Solar Energy Ltd. recognized an impairment of $20 million on its assets, of which AES’s share was $10 million.

As noted in Item 7 — Management’s Discussion and Analysis, Key Drivers of Results in 2010, and Item 7A. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk of the 2010 Form 10-K, the Company’s North American businesses continue to face pressure as a result of high coal prices relative to natural gas, which has affected the results of certain of our coal plants in the region, particularly those which are merchant plants that are exposed to market risk and those that have hybrid merchant risk, meaning those businesses that have a PPA in place, but purchase fuel at market prices or under short term contracts. On February 1, 2011, AES Thames, LLC (“Thames”), our 208 MW coal-fired plant in Connecticut, filed petitions for bankruptcy protection under Chapter 11 in the U. S. Bankruptcy Court. In addition, as disclosed in Key Trends and Uncertainties, Sale of Eastern Energy, while our efforts to sell Eastern Energy continue, there can be no assurance that we will be successful in those efforts. At this time, AES Deepwater has been idled to mitigate operating risks caused by high fuel costs and other competitive pressures. If the conditions describe above continue or worsen, our North American businesses with market or hybrid merchant exposure may need to restructure their obligations or seek additional funding (including from the Parent) or face the possibility that they may be unable to meet their obligations and continue operations, which could result in the loss of earnings or cash flow or result in a write down in the value of these assets, any of which could have a material impact on the Company. For further discussion of the risks associated with commodity prices, see “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” in Item 1A. — Risk Factors of the 2010 Form 10-K.

If global economic conditions worsen, it could also affect the prices we receive for the electricity we generate or transmit. Utility regulators or parties to our generation contracts may seek to lower our prices based on prevailing market conditions as PPAs, concession agreements or other contracts come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual price or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses.

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Impairments.

Long-lived assets.    The global economic conditions and other adverse factors discussed above heighten the risk of a significant asset impairment. Examples of conditions that could be indicative of impairment which would require us to evaluate the recovery of a long-lived asset or asset group include:

• current period operating or cash flow losses combined with a history of operating or cash flow losses or a projection that demonstrates continuing losses associated with the use of a long-lived asset group;

• a significant adverse change in legal factors, including changes in environmental or other regulations or in the business climate that could affect the value of a long-lived asset group, including an adverse action or assessment by a regulator;

• a significant adverse change in the extent or manner in which a long-lived asset group is being used or in its physical condition; and

• a current expectation that, more likely than not, a long-lived asset (asset group) will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

During the third quarter of 2011, the Company evaluated the future use of certain wind turbines held in storage pending their installation. Due to reduced wind turbine market pricing and advances in turbine technology, the Company determined that it was more likely that not the turbines would be sold significantly before the end of their previously estimated useful lives. At the same time, the Company also concluded that more likely than not non-refundable deposits that it had made in prior years to a turbine manufacturer for the purchase of wind turbines were not recoverable. The Company determined it was more likely than not that it would not proceed with the purchase of turbines due to the availability of more advanced and lower cost turbines in the market. In October 2011, the Company determined that an impairment had occured as of September 30, 2011 and wrote down the aggregate carrying amount of $161 million of these assets to their estimated fair value of $45 million by recognizing asset impairment expense of $116 million. It is reasonably possible that the turbines could incur further loss in value due to changing marketing conditions and advances in technology.

The prices for emission reduction offsets, including Certified Emission Reductions (CERs) and European Allowance Units (EUAs), have trended downward during 2011. This decline adversely impacted the Company’s Carbon Reduction Projects in Asia and Latin America. The Latin American project also incurred current period operating losses and is projecting continuing operating and cash flow losses for future periods. The aggregate carrying amount of $49 million of these projects was written down as their estimated fair value was $11 million, resulting in asset impairment expense of $33 million, which was limited to the carrying amount of long-lived assets. It is reasonably possible that the prices of CERs and EUAs could decrease further and require the Company to record additional impairment expense.

We have continued to evaluate the recoverability of our long-lived assets at Kelanitissa, our diesel-fired generation plant in Sri Lanka, as a result of both the existing government regulation which may require the government to acquire an ownership interest and the current expectation of future losses. Our evaluation during the second quarter of 2011 indicated that the long-lived assets were not recoverable and accordingly, they were written down to their estimated fair value of $33 million based on a discounted cash flow analysis. An additional impairment of $4 million was recognized in the three months ended September 30, 2011. Kelanitissa is a Build-operate-transfer (BOT) generation facility and payments under its PPA are scheduled to decline over the PPA term. It is possible that further impairment charges may be required in the future as Kelanitissa gets closer to the BOT date.

Equity method investments.    Adverse changes in economic and business conditions could also impact the value of our equity method investments. For example, YangCheng, our 2100 MW coal-fired plant in China, continues to experience lower operating margin due to higher coal prices. The coal prices have trended upward during the nine months ended September 30, 2011 and it is unlikely that the trend will reverse in the next several

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years. Due to the tight governmental control on tariff, it is also difficult to pass through the increase in fuel costs to customers. At the end of the venture in 2016, AES is required to surrender its interest to other venture partners without additional compensation. During the third quarter of 2011, an other-than-temporary-impairment of $74 million was recorded to write down YangCheng to its estimated fair value of $26 million. It is reasonably possible that further impairment expense may be required on YangCheng or any other equity method investments if adverse changes occur in economic or business environments.

Goodwill.    The Company seeks business acquisitions as one of its growth strategies. We have achieved significant growth in the past as a result of several business acquisitions, which also resulted in the recognition of goodwill. As noted in Item 1A. — Risk Factors of the 2010 Form 10-K, there is always a risk that “Our acquisitions may not perform as expected.” The benefits of goodwill are typically realized through the future operating results of an acquired business. Management believes that the recoverability of goodwill is positively correlated with the economic environments in which our acquired businesses operate and a severe economic downturn could negatively impact the recoverability of goodwill. Also, the evolving environmental regulations, including GHG regulations, around the globe continue to increase the operating costs of our generation businesses. In extreme situations, the environmental regulations could even make a once profitable business uneconomical. In addition, most of our generation businesses have a finite life and as the acquired businesses reach the end of their finite lives, the carrying amount of goodwill is gradually recovered through their periodic operating results. The accounting guidance, however, prohibits the systematic amortization of goodwill and rather requires an annual impairment evaluation. Thus, as some of our acquired businesses approach the end of their finite lives, they may incur goodwill impairment charges even if there are no discrete adverse changes in the economic environment.

In the fourth quarter of 2010, the Company completed its annual goodwill impairment evaluation and did not have any reporting units that were considered “at risk.” A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. While there were no potential impairment indicators at that time that could result in the recognition of goodwill impairment at our reporting units, it is possible we may incur goodwill impairment at our reporting units in future periods 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, a sale of assets at less than carrying amount, unanticipated competition, a loss of key personnel, an acquisition not performing as expected, changing environmental regulations that significantly increase the cost of doing business, or a business reaches the end of its finite life. The likelihood of the occurrence of these events may increase if global economic conditions remain volatile or deteriorate further. For example, during the third quarter of 2011, the Company identified higher coal prices and the resulting reduced operating margins in China as an impairment indicator of goodwill at Chigen, our holding company that holds AES’ interests in Chinese joint ventures. An interim evaluation of goodwill was performed at September 30, 2011 and its entire carrying amount of $17 million was recognized as a goodwill impairment. See Note 14 — Impairment Expense to Item 1. — Financial Statements for further information.

Regulatory — Environment.    The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and 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 byproducts), and certain air emissions, such as SO₂, NO_x, particulate matter and mercury. Such risks and uncertainties could result in 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. For further information about these risks, see Item 1A. — Risk Factors, “Our businesses are subject to stringent environmental laws and regulations,” “Our businesses are subject to enforcement initiatives from environmental regulatory agencies,” and “Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with

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climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows” set forth in the Company’s Form 10-K for the year ended December 31, 2010.

Legislation and Regulation of GHG Emissions

Currently, in the United States there is no federal legislation establishing mandatory GHG emissions reduction programs (including CO₂) affecting the electric power generation facilities of the Company’s subsidiaries. There are numerous state programs regulating GHG emissions from electric power generation facilities and there is a possibility that federal GHG legislation will be enacted within the next several years. Further, the United States Environmental Protection Agency (“EPA”) has adopted regulations pertaining to GHG emissions and has announced its intention to propose new regulations for electric generating units under Section 111 of the United States Clean Air Act (“CAA”).

Potential U.S. Federal GHG Legislation    Federal legislation passed the U.S. House of Representatives in 2009 that, if adopted, would have imposed a nationwide cap-and-trade program to reduce GHG emissions. This legislation was never signed into law, and is no longer under consideration. In the U.S. Senate, several different draft bills pertaining to GHG legislation have been considered, including comprehensive GHG legislation similar to the legislation that passed the U.S. House of Representatives and more limited legislation focusing only on the utility and electric generation industry. It is uncertain whether any legislation pertaining to GHG emissions will be voted on and passed by the U.S. Senate and House of Representatives. If any such legislation is enacted into law, the impact could be material to the Company.

EPA GHG Regulation    The EPA has promulgated regulations governing GHG emissions from automobiles under the CAA. The effect of the EPA’s regulation of GHG emissions from mobile sources is that certain provisions of the CAA will also apply to GHG emissions from existing stationary sources, including many U.S. power plants. In particular, beginning January 2, 2011, construction of new stationary sources and modifications to existing stationary sources that result in increased GHG emissions became subject to permitting requirements under the prevention of significant deterioration (“PSD”) program of the CAA. The PSD program, as currently applicable to GHG emissions, requires sources that emit above a certain threshold of GHGs to obtain PSD permits prior to commencement of new construction or modifications to existing facilities. In addition, major sources of GHG emissions may be required to amend, or obtain new, Title V air permits under the CAA to reflect any new applicable GHG emissions requirements for new construction or for modifications to existing facilities.

The EPA promulgated a final rule on June 3, 2010 (the “Tailoring Rule”) that sets thresholds for GHG emissions that would trigger PSD permitting requirements. The Tailoring Rule, which became effective in January of 2011, provides that sources already subject to PSD permitting requirements need to install Best Available Control Technology (“BACT”) for greenhouse gases if a proposed modification would result in the increase of more than 75,000 tons per year of GHG emissions. Also, under the Tailoring Rule, any new sources of GHG emissions that would emit over 100,000 tons per year of GHG emissions, in addition to any modification that would result in GHG emissions exceeding 75,000 tons per year, require PSD review and are subject to related permitting requirements. The EPA anticipates that it will adjust downward the permitting thresholds of 100,000 tons and 75,000 tons for new sources and modifications, respectively, in future rulemaking actions. The Tailoring Rule substantially reduces the number of sources subject to PSD requirements for GHG emissions and the number of sources required to obtain Title V air permits, although new thermal power plants may still be subject to PSD and Title V requirements because annual GHG emissions from such plants typically far exceed the 100,000 ton threshold noted above. The 75,000 ton threshold for increased GHG emissions from modifications to existing sources may reduce the likelihood that future modifications to plants owned by some of our United States subsidiaries would trigger PSD requirements, although some projects that would expand capacity or electric output are likely to exceed this threshold, and in any such cases the capital expenditures necessary to comply with the PSD requirements could be significant.

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In December 2010, the EPA entered into a settlement agreement with several states and environmental groups to resolve a petition for review challenging the EPA’s new source performance standards (“NSPS”) rulemaking for electric utility steam generating units (“EUSGUs”) based on the NSPS’s failure to address GHG emissions. Under the settlement agreement, the EPA had committed to propose GHG emissions standards for EUSGUs by July 26, 2011. The EPA previously announced that it would delay the proposal of such standards until September 30, 2011, and it subsequently announced a further delay without specifying a deadline for the proposal of such standards. The EPA has also committed to finalize GHG NSPS for EUSGUs by May 26, 2012. The NSPS will establish GHG emission standards for newly constructed and reconstructed EUSGUs. The NSPS also will establish guidelines regarding the best system for achieving further GHG emissions reductions from existing EUSGUs. Based on the guidelines, individual states will be required to develop regulations establishing GHG performance standards for existing EUSGUs within their states. It is impossible to estimate the impact and compliance cost associated with any future NSPS applicable to EUSGUs until such regulations are finalized. However, the compliance costs could have a material and adverse impact on our consolidated financial condition or results of operations.

Regional Greenhouse Gas Initiative    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 participating in RGGI 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 most recent Form 10-Q, we have estimated the costs to the Company of compliance with RGGI to be approximately $15 million for 2011.

International GHG Regulation    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 emissions reduction requirements. Many of the countries in which the Company’s subsidiaries operate have no emissions reduction obligations under the Kyoto Protocol. In addition, of the 27 countries in which the Company’s subsidiaries operate, all but one — the United States (including Puerto Rico) — have ratified the Kyoto Protocol. The first commitment period under the Kyoto Protocol is currently expected to expire at the end of 2012, and countries have been unable to agree on a successor commitment period. The next annual United Nations conference to develop a successor international agreement is scheduled for November 2011 in South Africa. It currently appears unlikely that a successor agreement will be reached at such conference; however, if a successor agreement is reached the impact could be material to the Company.

There is substantial uncertainty with respect to whether U.S. federal GHG legislation will be enacted into law, whether new country-specific GHG legislation will be adopted in countries in which our subsidiaries conduct business, and whether a new international agreement to succeed the Kyoto Protocol will be reached. There is additional uncertainty regarding the final provisions or implementation of any potential U.S. federal or foreign country GHG legislation, the EPA’s 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 or financial condition from potential U.S. federal or foreign country GHG legislation, the EPA’s 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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Other U.S. Air Emissions Regulations and Legislation

The Company’s subsidiaries in the United States are subject to the Clean Air Act (“CAA”) and various state laws and regulations that regulate emissions of air pollutants, including SO₂, NO_X, particulate matter (“PM”), mercury and other hazardous air pollutants (“HAPs”).

The EPA promulgated the “Clean Air Interstate Rule” (“CAIR”) on March 10, 2005, which required allowance surrender for SO₂ and NO_X emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the EPA. In response to the D.C. Circuit’s opinion, on July 7, 2011, the EPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, the CSAPR requires significant reductions in SO₂ and NO_x emissions from covered sources, such as power plants, in many states in which subsidiaries of the Company operate. Once fully implemented in 2014, the rule requires additional SO₂ emission reductions of 73% and additional NO_x reductions of 54% from 2005 levels. The CSAPR will be implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of new emissions allowances that the EPA will create. The CSAPR contemplates limited interstate and intra-state trading of emissions allowances by covered sources. Initially, at least through 2012, the EPA will issue emissions allowances to affected power plants based on state emissions budgets established by the EPA under the CSAPR. The availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time. The CSAPR was published in the Federal Register on August 8, 2011 and on October 6, 2011, the EPA proposed some technical revisions to the CSAPR, including allowing for additional allowances for certain states. The EPA will be taking public comments on the proposed revisions for thirty days, and such public comments will be considered by the EPA prior to promulgating a final rule. Many states, utilities and other affected parties have filed lawsuits in the U.S. Court of Appeals for the District of Columbia seeking to stay the implementation of the CSAPR and challenging the validity of the CSAPR. We cannot predict the outcome of such litigation or the effect it might have on the possible implementation of the CSAPR. To comply with the CSAPR, additional pollution control technology may be required by some of our subsidiaries, and the cost of implementing any such technology could affect the financial condition or results of operations of these subsidiaries or the Company. Additionally, compliance with the CSAPR could require the purchase of newly issued allowances, the switch to higher priced, lower sulfur coal or the retirement of existing generating units. While the capital costs, other expenditures or operational restrictions necessary to comply with the CSAPR cannot be specified at this time, and the outcome of litigation pertaining to CSAPR is uncertain, the Company anticipates that the CSAPR may have a material impact on the Company’s business and results of operations.

As a result of prior EPA determinations and the D.C. Circuit Court ruling, the EPA is obligated under Section 112 of the CAA to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, hydrogen chloride, hydrogen fluoride, and other metal species from coal and oil-fired power plants. The EPA has entered into a consent decree under which it is obligated to finalize the rule by November 2011, and it has subsequently requested an extension of this deadline until December 16, 2011. In connection with such rule, the CAA requires the EPA to establish maximum achievable control technology (“MACT”) standards for each pollutant regulated under the rule. MACT is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. The EPA published a proposed rule on May 3, 2011 that would establish national emissions standards for hazardous air pollutants (“NESHAP”) from coal- and oil-fired electric utility steam generating units. The rule, as currently proposed, may require all coal-fired power plants to retire operations or install acid gas control technology, upgrade particulate control devices and/or install some other type of mercury control technology, such as sorbent injection. The public comment period for this proposed rule has expired, and the public comments will be considered by the EPA prior to promulgating a final rule. Most of the United States coal-fired plants operated by the Company’s subsidiaries have acid gas scrubbers or comparable control technologies, but as proposed there are other improvements to such control technologies that may be needed at some of the Company’s plants. Under the CAA, compliance is required within three years of

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the effective date of the rule; however, the compliance period for a unit, or group of units, may be extended by state permitting authorities (for one additional year) or through a determination by the President (for up to two additional years). At this time, the Company cannot predict the extent of the final regulations for hazardous air pollutants, but the cost of compliance with any such regulations could be material.

Other International Air Emissions Regulations and Legislation

On January 18, 2011, the President of Chile approved a new air emissions regulation submitted to him by the national environmental regulatory agency (“CONAMA”). The new regulation establishes limits on emissions of NO_X, SO₂, metals and particulate matter for both existing and new thermal power plants, with more stringent limitations on new facilities. The regulation became effective on June 23, 2011. The regulation will require AES Gener, the Company’s Chilean subsidiary, to install emissions reduction equipment at its existing thermal plants from late 2011 through 2015. The costs of compliance with such regulation have not yet been determined and the Company believes some of the compliance costs are contractually passed through to counterparties. However, the compliance costs could be material.

Cooling Water Intake Regulations

The Company’s U.S. facilities are subject to the U.S. Clean Water Act Section 316(b) rule issued by the EPA which seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the “best technology available” for cooling water intake structures. The EPA published a proposed rule establishing requirements under 316(b) regulations on April 20, 2011. The proposal, based on Section 316(b) of the U.S. Clean Water Act, establishes Best Technology Available (“BTA”) requirements regarding impingement standards with respect to aquatic organisms for all facilities that withdraw above 2 million gallons per day of water from certain water bodies and utilize at least 25% of the withdrawn water for cooling purposes. To meet these BTA requirements, as currently proposed, cooling water intake structures associated with once through cooling processes will need modifications of existing traveling screens that protect aquatic organisms and will need to add a fish return and handling system for each cooling system. Existing closed cycle cooling facilities may require upgrades to water intake structure systems. The proposal would also require comprehensive site-specific studies during the permitting process and may require closed-cycle cooling systems in order to meet BTA entrainment standards.

The public comment period for this proposed rule has expired, and the EPA will consider the public comments with a view to issuing a final rule by July of 2012. Until such regulations are final, the EPA has instructed state regulatory agencies to use their best professional judgment in determining how to evaluate what constitutes “best technology available” for protecting fish and other aquatic organisms from cooling water intake structures. Certain states in which the Company operates power generation facilities, such as New York, have been delegated authority and are moving forward with best technology available determinations in the absence of any final rule from the EPA. On September 27, 2010, the California Office of Administrative Law approved a policy adopted by the California Water Resources Control Board with respect to power plant cooling water intake structures. This policy became effective on October 1, 2010, and establishes technology-based standards to implement Section 316(b) of the U.S. Clean Water Act. At this time, it is contemplated that the Company’s Redondo Beach, Huntington Beach and Alamitos power plants in California will need to have in place best technology available by December 31, 2020, or repower the facilities. At present, the Company cannot predict the final requirements under Section 316(b) or whether compliance with the anticipated new 316(b) rule will have a material impact on our operations or results, but the Company expects that capital investments and/or modifications resulting from such requirements could be significant.

Waste Management

In the course of operations, many of the Company’s facilities generate coal combustion byproducts (“CCB”), including fly ash, requiring disposal or processing. On June 21, 2010 the EPA published in the Federal Register a proposed rule to regulate CCB under the Resource Conservation and Recovery Act (“RCRA”). The

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proposed rule provides two possible options for CCB regulation, and both options contemplate heightened structural integrity requirements for surface impoundments of CCB. The first option contemplates regulation of CCB as a hazardous waste subject to regulation under Subtitle C of the RCRA. Under this option, existing surface impoundments containing CCB would be required to be retrofitted with composite liners and these impoundments would likely be phased out over several years. State and/or federal permit programs would be developed for storage, transport and disposal of CCB. States could bring enforcement actions for non-compliance with permitting requirements, and the EPA would have oversight responsibilities as well as the authority to bring lawsuits for non-compliance. The second option contemplates regulation of CCB under Subtitle D of the RCRA. Under this option, the EPA would create national criteria applicable to CCB landfills and surface impoundments. Existing impoundments would also be required to be retrofitted with composite liners and would likely be phased out over several years. This option would not contain federal or state permitting requirements. The primary enforcement mechanism under regulation pursuant to Subtitle D would be private lawsuits.

The public comment period for this proposed regulation has expired, and the EPA is required to consider the public comments prior to promulgating a final rule. Requirements under a final rule are expected to become effective by January 2012, with a compliance schedule of five years. While the exact impact and compliance cost associated with future regulations of CCB cannot be established until such regulations are finalized, there can be no assurance that the Company’s businesses, financial condition or results of operations would not be materially and adversely affected by such regulations.

Indiana Senate Bill 251

In May 2011, Senate Bill 251 became a law in the State of Indiana. Senate Bill 251 is a comprehensive bill which, among other things, provides Indiana utilities, including IPL, with a means for recovering 80% of costs incurred to comply with federal mandates through a periodic retail rate adjustment mechanism, and additional cost recovery is possible through a subsequent general rate case. This includes costs to comply with regulations from the EPA, FERC, NERC, the Department of Energy, etc., including capital intensive requirements and/or proposals such as those relating to cooling water intake regulations, waste management and coal combustion byproducts, wastewater effluent, MISO transmission expansion costs and polychlorinated biphenyls. It does not change existing legislation that allows for 100% recovery of clean coal technology designed to reduce air pollutants (Indiana Senate Bill 29).

Some of the most important features of Senate Bill 251 to IPL are as follows: any energy utility in Indiana seeking to recover federally mandated costs incurred in connection with a compliance project shall apply to the Indiana Utility Regulatory Commission (“IURC”) for a certificate of public convenience and necessity (“CPCN”) for the compliance project. It sets forth certain factors that the IURC must consider in determining whether to grant a CPCN. It further specifies that if the IURC approves a proposed compliance project and the projected federally mandated costs associated with the project, the following apply: (i) 80% of the approved costs shall be recovered by the energy utility through a periodic retail rate adjustment mechanism; (ii) 20% of the approved costs shall be deferred and recovered by the energy utility as part of the next general rate case filed by the energy utility with the IURC; and (iii) actual costs exceeding the projected federally mandated costs of the approved compliance project by more than 25% shall require specific justification and approval by the IURC before being authorized in the energy utility’s next general rate case.

Recent Events

On October 20, 2011, a subsidiary of the Company signed a share sale agreement with Electrabel International Holdings B.V. (“EIH”), a subsidiary of GDF SUEZ S.A. (“GDFS”) for the sale of 80% of its interest in the wholly-owned holding company that holds the Company’s interest in AES Energia Cartagena S.R.L. (“AES Cartagena”), a 1,199 MW gas-fired generation business in Spain, for €172 million ($234 million), subject to customary purchase price adjustments. AES owns approximately 70.81% of AES Cartagena through this holding company structure. Under the terms of the sale agreement, EIH has an option to purchase AES’

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remaining 20% interest in the holding company for a fixed price of €28 million ($38 million) during a five month period beginning 13 months from the date the sale closes. Subject to regulatory and lenders’ approvals, the sale is expected to close by the end of 2011. Concurrent with the sale, GDFS agreed to settle the outstanding arbitration between the parties regarding certain emissions costs and other taxes that AES Cartagena sought to recover from GDFS as energy manager under the existing commercial arrangements and to pay €58 million ($79 million) to AES Cartagena for such costs incurred by AES Cartagena during the period up to December 31, 2010 and additional amounts for such costs incurred by AES Cartagena during the period from January 1, 2011 until closing of the sale. However, the settlement of the arbitration is contingent on consummation of the sale. See Note 9 — Contingencies and Commitments for further information.

In July 2011, a subsidiary of the Company entered into an agreement to sell its ownership interest in two telecommunication companies in Brazil. The Company held approximately 46% ownership interest in these companies through the subsidiary. The transaction closed on October 31, 2011 and the subsidiary received approximately R$1,522 million ($901 million), subject to customary purchase price adjustments. The estimated gain on the sale before noncontrolling interests and taxes is approximately R$1,333 million ($789 million), subject to final purchase price adjustments.

On October 3, 2011, the Company completed the placement of $1.25 billion aggregate principal amount senior notes with Wells Fargo Bank N.A. See Note 8 — Debt, Non-Recourse Debt for further information.

Subsequent to September 30, 2011, the Company continued to repurchase stock under the stock repurchase program announced on July 7, 2010. The Company has repurchased 5,554,185 shares at a cost of $54 million subsequent to September 30, 2011, bringing the cumulative total through November 3, 2011 to 33,924,805 shares at a total cost of $378 million (average price of $11.16 per share including commissions). For additional information, see Note 11 — Equity.

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Consolidated Results of Operations

	Three Months Ended September 30,												Nine Months Ended September 30,
							$			%									$			%
	2011			2010			change			change			2011			2010			change			change
	(in millions, except per share amounts)												(in millions, except per share amounts)
Revenue:
Latin America Generation	$	1,302		$	1,111		$	191			17	%	$	3,810		$	3,178		$	632			20	%
Latin America Utilities		1,930			1,757			173			10	%		5,774			5,236			538			10	%
North America Generation		372			413			(41	)		-10	%		1,116			1,173			(57	)		-5	%
North America Utilities		321			306			15			5	%		890			869			21			2	%
Europe Generation		397			282			115			41	%		1,125			864			261			30	%
Asia Generation		172			136			36			26	%		449			491			(42	)		-9	%
Corporate and Other(1)		215			252			(37	)		-15	%		800			744			56			8	%
Eliminations(2)		(328	)		(267	)		(61	)		-23	%		(847	)		(778	)		(69	)		-9	%
Total Revenue	$	4,381		$	3,990		$	391			10	%	$	13,117		$	11,777		$	1,340			11	%
Gross Margin:
Latin America Generation	$	440		$	386		$	54			14	%	$	1,308		$	1,145		$	163			14	%
Latin America Utilities		305			247			58			23	%		810			714			96			13	%
North America Generation		110			111			(1	)		-1	%		301			300			1			-	%
North America Utilities		71			78			(7	)		-9	%		170			206			(36	)		-17	%
Europe Generation		95			47			48			102	%		240			221			19			9	%
Asia Generation		38			52			(14	)		-27	%		136			197			(61	)		-31	%
Corporate and Other(3)		(37	)		33			(70	)		-212	%		37			85			(48	)		-56	%
Eliminations(4)		(2	)		13			(15	)		-115	%		17			33			(16	)		-48	%
General and administrative		(91	)		(98	)		7			7	%		(283	)		(279	)		(4	)		-1	%
Interest expense		(432	)		(381	)		(51	)		-13	%		(1,178	)		(1,151	)		(27	)		-2	%
Interest income		103			96			7			7	%		293			304			(11	)		-4	%
Other expense		(76	)		(23	)		(53	)		-230	%		(131	)		(83	)		(48	)		-58	%
Other income		58			17			41			241	%		108			94			14			15	%
Gain on sale of investments		-			-			-			-	%		7			-			7			100	%
Goodwill impairment		(17	)		(18	)		1			-6	%		(17	)		(18	)		1			6	%
Asset impairment expense		(163	)		(296	)		133			45	%		(196	)		(297	)		101			34	%
Foreign currency transaction gains (losses) on net monetary position		(92	)		103			(195	)		-189	%		(21	)		(19	)		(2	)		-11	%
Other non-operating expense		(82	)		(2	)		(80	)		-4000	%		(82	)		(7	)		(75	)		-1071	%
Income tax expense		(84	)		(102	)		18			18	%		(469	)		(540	)		71			13	%
Net equity in earnings of affiliates		6			26			(20	)		-77	%		12			174			(162	)		-93	%
Income from continuing operations		150			289			(139	)		-48	%		1,062			1,079			(17	)		-2	%
Income from operations of discontinued businesses		25			29			(4	)		-14	%		23			92			(69	)		-75	%
Gain from disposal of discontinued businesses		-			79			(79	)		-100	%		-			57			(57	)		-100	%
Net income		175			397			(222	)		-56	%		1,085			1,228			(143	)		-12	%
Noncontrolling interests:
Income from continuing operations attributable to noncontrolling interests		(269	)		(248	)		(21	)		-8	%		(766	)		(725	)		(41	)		-6	%
Income from discontinued operations attributable to noncontrolling interests		(37	)		(35	)		(2	)		-6	%		(52	)		(58	)		6			10	%
Net (loss) income attributable to The AES Corporation	$	(131	)	$	114		$	(245	)		-215	%	$	267		$	445		$	(178	)		-40	%
Per Share Data:
Basic (loss) income per share from continuing operations	$	(0.15	)	$	0.05		$	(0.20	)		-400	%	$	0.38		$	0.46		$	(0.08	)		-17	%
Diluted (loss) income per share from continuing operations	$	(0.15	)	$	0.05		$	(0.20	)		-400	%	$	0.38		$	0.46		$	(0.08	)		-17	%

⁽¹⁾  Corporate and Other includes revenue from our generation and utilities businesses in Africa, utilities businesses in Europe, Wind Generation and other renewables initiatives.

⁽²⁾  Represents inter-segment eliminations of revenue primarily related to transfers of electricity from Tietê (generation) to Eletropaulo (utility).

⁽³⁾  Corporate and Other gross margin includes gross margin from our generation and utilities businesses in Africa, utilities businesses in Europe, Wind Generation and other renewables initiatives.

⁽⁴⁾  Represents inter-segment eliminations of gross margin related to corporate charges for self insurance premiums.

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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,
	2011		2010		% Change			2011		2010		% Change
	($’s in millions)							($’s in millions)
Latin America Generation
Revenue	$	1,302	$	1,111		17	%	$	3,810	$	3,178		20	%
Gross Margin	$	440	$	386		14	%	$	1,308	$	1,145		14	%

Excluding the favorable impact of foreign currency translation and remeasurement of $8 million, generation revenue for the three months ended September 30, 2011 increased $183 million, or 16%, compared to the three months ended September 30, 2010 primarily due to:

• higher energy prices of $54 million attributable to a price adjustment for consuming an alternate fuel and $9 million associated with higher availability in Argentina;

• new business of $37 million at Angamos, Gener’s 264 MW coal-fired plant in Chile, which commenced commercial operations in April 2011;

• higher revenue of $29 million at Tietê in Brazil due to the combined effect of higher contract prices associated with CPI indexation in the second half of 2011 and higher volume due to an increase in energy demand in Brazil;

• higher contract prices of $26 million at Gener in Chile as a result of price indexation mainly driven by higher fuel costs;

• higher ancillary services and third party gas sales of $17 million, and higher energy prices of $13 million primarily from PPAs in the Dominican Republic; and

• higher volume of $16 million in Colombia and Panama driven by higher generation mainly due to higher water inflows in the system.

These increases were partially offset by:

• lower generation volume of $25 million in Argentina due to reduced capacity of the plant to operate on alternate fuel; and

• lower spot prices of $13 million in Colombia and Panama due to higher water inflows in the system.

Excluding the favorable impact of foreign currency translation and remeasurement of $15 million, primarily in Brazil, generation gross margin for the three months ended September 30, 2011 increased $39 million, or 10%, compared to the three months ended September 30, 2010 primarily due to:

• higher volume of $44 million at Gener — Electrica Santiago primarily associated with higher spot sales and improved fuel availability;

• higher volume and contract energy prices at Tietê of $32 million as result of higher energy demand and CPI indexation in the second half of 2011;

• higher volume of $24 million in Colombia and Panama as a result of higher generation;

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• higher ancillary services and gas sales of $12 million and higher energy prices of $7 million in the Dominican Republic as mentioned above;

• higher energy prices of $7 million at a coal generation business in Argentina as a result of higher thermal generation with alternate fuel; and

• new business of $4 million at Angamos as described above.

These increases were partially offset by:

• higher fuel costs at Gener in Chile of $21 million;

• a net decrease of $22 million related to higher spot purchases and the forced outage in Panama;

• lower generation volume of $13 million in Argentina due to reduced capacity of the plant to operate on alternate fuel;

• lower spot prices of $13 million in Colombia and Panama due to higher water inflows in the system; and

• higher fixed and operating costs of $20 million across the region, primarily attributable to higher maintenance costs as well as higher depreciation at Tietê due to the change in useful lives and salvage values of property, plant and equipment, as a result of new regulatory information.

For the three months ended September 30, 2011, revenue increased 17%, while gross margin increased by 14%. This was primarily due to the higher spot purchases in Panama resulting from the forced outage, and the price adjustment in Argentina for consuming an alternate fuel that had no corresponding impact on gross margin and higher fixed costs.

Excluding the favorable impact of foreign currency translation and remeasurement of $44 million, generation revenue for the nine months ended September 30, 2011 increased $588 million, or 19%, compared to the nine months ended September 30, 2010 primarily due to:

• higher energy prices of $200 million in Argentina attributable to a price adjustment for consuming an alternate fuel;

• higher contract and spot prices of $164 million at Gener as a result of low water inflows in the Central Interconnected System and PPA price indexation;

• new business of $109 million at Angamos;

• higher volume of $99 million in Colombia and Panama due to higher water inflows in the system during the first six months of 2011;

• higher volume of $70 million at Gener — Electrica Santiago primarily associated with higher spot sales and improved fuel availability;

• higher contract prices of $40 million at Tietê due to CPI indexation in the second half of 2011; and

• higher contract prices of $34 million primarily from PPAs indexed to coal, higher ancillary services and higher third party gas sales of $38 million in the Dominican Republic.

These increases were partially offset by:

• lower spot prices of $123 million in Colombia and Panama due to higher water inflows in the system during the first six months of 2011;

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• lower volume of $32 million at Tietê mainly driven by reduced requirements per PPA settlement terms during the first six months of 2011;

• $32 million related to the final settlement of the power sales agreement between Uruguaiana and Sul in the second quarter of 2010; and

• a net decrease of $26 million related to the forced outage in Panama.

Excluding the favorable impact of foreign currency translation and remeasurement of $51 million, primarily in Brazil, generation gross margin for the nine months ended September 30, 2011 increased $112 million, or 10%, compared to the nine months ended September 30, 2010 primarily due to:

• higher volume of $127 million at Gener — Electrica Santiago primarily associated with higher spot sales and improved fuel availability;

• higher volume of $115 million in Colombia and Panama as a result of higher water inflows in the system during the first six months of 2011;

• higher contract prices of $43 million at Tietê, as discussed above;

• higher contract and spot prices of $42 million at Gener as a result of low water inflows in the Central Interconnected System;

• new business of $41 million at Angamos, as described above;

• higher energy prices of $28 million and higher ancillary services and gas sales of $20 million in the Dominican Republic, as described above; and

• higher volume of $13 million at coal generation businesses in Argentina as a result of low hydrology.

These increases were partially offset by:

• lower spot prices of $110 million in Colombia and Panama due to higher water inflows in the system during the first six months of 2011;

• a net decrease of $82 million related to higher spot purchases and the forced outage in Panama;

• lower volume of $40 million at Tietê, as discussed above;

• $32 million related to the final settlement of the power sales agreement between Uruguaiana and Sul; and

• higher fixed and operating costs of $71 million across the region, primarily attributable to higher employee costs, maintenance costs, increase in non-income taxes in Argentina and Colombia, and higher depreciation at Tietê due to the change in useful lives and salvage values of property, plant and equipment, as a result of new regulatory information.

For the nine months ended September 30, 2011, revenue increased 20%, while gross margin increased by 14%. This was primarily due to the higher spot purchases in Panama resulting from the forced outage, the price adjustment in Argentina for consuming an alternate fuel that had no corresponding impact on gross margin and higher fixed costs.

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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,
	2011		2010		% Change			2011		2010		% Change
	($’s in millions)							($’s in millions)
Latin America Utilities
Revenue	$	1,930	$	1,757		10	%	$	5,774	$	5,236		10	%
Gross Margin	$	305	$	247		23	%	$	810	$	714		13	%

Excluding the favorable impact of foreign currency translation of $122 million, primarily in Brazil, utilities revenue for the three months ended September 30, 2011 increased $51 million, or 3%, compared to the three months ended September 30, 2010 primarily due to:

• higher volume of $63 million, primarily in Brazil, due to increased market demand; and

• higher tariffs of $45 million at Sul in Brazil and our utility businesses in El Salvador primarily due to higher energy prices associated with energy purchases and pass-through transmission costs.

These increases were partially offset by:

• expected lower tariffs of $55 million at Eletropaulo in Brazil, primarily related to the estimated impact of the July 2011 tariff reset which has been postponed by the Brazilian energy regulatory agency.

Excluding the favorable impact of foreign currency translation of $27 million, primarily in Brazil, utilities gross margin for the three months ended September 30, 2011 increased $31 million, or 13%, compared to the three months ended September 30, 2010 primarily due to:

• lower fixed costs of $64 million primarily due to contingency reversals and a non-recurring reduction in bad debt expense in Brazil; and

• higher volume of $23 million, primarily in Brazil, due to increased market demand.

These increases were partially offset by:

• expected lower tariffs of $35 million at Eletropaulo in Brazil, primarily related to the estimated impact of the July 2011 tariff reset which has been postponed by the Brazilian energy regulatory agency; and

• higher depreciation of $11 million at our businesses in Brazil, mainly due to the change in useful lives and salvage values of property, plant and equipment, as a result of new regulatory information.

For the three months ended September 30, 2011, revenue increased 10%, while gross margin increased by 23%. This was primarily due to non-recurring lower fixed costs in Brazil.

Excluding the favorable impact of foreign currency translation of $446 million, primarily in Brazil, utilities revenue for the nine months ended September 30, 2011 increased $92 million, or 2%, compared to the nine months ended September 30, 2010 primarily due to:

• higher volume of $223 million, primarily in Brazil, due to increased market demand; and

• higher tariffs of $53 million at our utility businesses in El Salvador primarily due to higher energy prices associated with energy purchases and pass-through transmission costs.

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These increases were partially offset by:

• lower tariffs of $153 million at Eletropaulo in Brazil, primarily related to the estimated impact of the July 2011 tariff reset which has been postponed by the Brazilian energy regulatory agency and lower energy prices associated with energy purchases and pass-through transmission costs.

Excluding the favorable impact of foreign currency translation of $76 million, primarily in Brazil, utilities gross margin for the nine months ended September 30, 2011 increased $20 million, or 3%, compared to the nine months ended September 30, 2010 primarily due to:

• higher volume of $118 million, primarily in Brazil, due to increased market demand;

• $32 million related to the final settlement of a power sales agreement between Sul and Uruguaiana in the second quarter of 2010; and

• lower fixed costs of $12 million, primarily in Brazil, due to contingency reversals and a non-recurring reduction in bad debt expense, partially offset by higher employee costs, regulatory penalties and maintenance costs.

These increases were partially offset by:

• lower tariffs of $94 million primarily related to the estimated impact of the July 2011 tariff reset at Eletropaulo which has been postponed by the Brazilian energy regulatory agency; and

• higher depreciation of $37 million at our businesses in Brazil, mainly due to the change in useful lives and salvage values of property, plant and equipment, as a result of new regulatory information.

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,
	2011		2010		% Change			2011		2010		% Change
	($’s in millions)							($’s in millions)
North America Generation
Revenue	$	372	$	413		-10	%	$	1,116	$	1,173		-5	%
Gross Margin	$	110	$	111		-1	%	$	301	$	300		0	%

Excluding the favorable impact of foreign currency translation of $4 million in Mexico, generation revenue for the three months ended September 30, 2011 decreased $45 million, or 11%, compared to the three months ended September 30, 2010 primarily due to:

• a decrease of $27 million at Thames in Connecticut due to the plant shutdown in January 2011 and its deconsolidation as of February 2011 as a result of loss of control to the U.S. Bankruptcy Court for the District of Delaware when it filed for bankruptcy protection;

• a decrease of $8 million at Merida in Mexico due to a combination of forced and scheduled outages; and

• a decrease in volume of $8 million at Deepwater in Texas due to the layup of the plant caused by high fuel costs and diminishing power prices.

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Excluding the favorable impact of foreign currency translation of $1 million in Mexico, generation gross margin for the three months ended September 30, 2011 decreased $2 million, or 2%, compared to the three months ended September 30, 2010 primarily due to:

• a decrease of $8 million at TEG/TEP in Mexico due to management fee adjustments; and

• a decrease of $6 million at Merida due to a combination of forced and scheduled outages.

These decreases were partially offset by:

• an increase of $8 million in Hawaii due to a favorable impact of prior year mark-to-market derivative adjustments.

For the three months ended September 30, 2011, revenue decreased 10%, while gross margin decreased by 1%. This was primarily due to outages at Merida and Puerto Rico, which had a greater impact on revenue than gross margin.

Excluding the favorable impact of foreign currency translation of $15 million in Mexico, generation revenue for the nine months ended September 30, 2011 decreased $72 million, or 6%, compared to the nine months ended September 30, 2010 primarily due to:

• a net decrease of $69 million at Thames as discussed above;

• a decrease in volume of $21 million at Deepwater as discussed above; and

• decreases at Merida of $16 million due to lower rates, and volume and $8 million due to a combination of forced and scheduled outages.

These decreases were partially offset by:

• increases at Puerto Rico of $21 million primarily due to a prior year forced outage and related penalty and $13 million due to higher rates.

Excluding the favorable impact of foreign currency translation of $2 million in Mexico, generation gross margin for the nine months ended September 30, 2011 decreased $1 million, or 0%, compared to the nine months ended September 30, 2010 primarily due to:

• decreases of $14 million at TEG/TEP due to a combination of forced and scheduled outages and higher fuel costs and $8 million due to management fee adjustments;

• a decrease of $8 million at Shady Point in Oklahoma due to higher fuel costs;

• a decrease in volume of $7 million at Deepwater as discussed above; and

• a decrease of $7 million at Merida due to a combination of forced and scheduled outages.

These decreases were partially offset by:

• an increase in Puerto Rico of $15 million primarily due to a prior year forced outage and related penalty;

• an increase of $15 million in Hawaii due to a favorable impact of prior year mark-to-market derivative adjustments; and

• lower fixed costs at Deepwater of $7 million as discussed above.

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For the nine months ended September 30, 2011, revenue decreased 5%, while gross margin remained flat. This was primarily due to the favorable impact of the mark-to-market derivative gain in Hawaii as discussed above.

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,
	2011		2010		% Change			2011		2010		% Change
	($’s in millions)							($’s in millions)
North America Utilities
Revenue	$	321	$	306		5	%	$	890	$	869		2	%
Gross Margin	$	71	$	78		-9	%	$	170	$	206		-17	%

Utilities revenue for the three months ended September 30, 2011 increased $15 million, or 5%, compared to the three months ended September 30, 2010 primarily due to:

• higher prices of $19 million primarily due to higher fuel adjustment charges of $17 million.

This increase was partially offset by:

• lower retail volume of $4 million primarily due to unfavorable weather.

Utilities gross margin for the three months ended September 30, 2011 decreased $7 million, or 9%, compared to the three months ended September 30, 2010 primarily due to:

• higher outage costs of $4 million for repairs and maintenance on generating units.

For the three months ended September 30, 2011, revenue increased 5%, while gross margin decreased by 9% primarily due to the positive impact of higher pass-through fuel costs on revenue, which had no corresponding impact on gross margin.

Utilities revenue for the nine months ended September 30, 2011 increased $21 million, or 2%, compared to the nine months ended September 30, 2010 primarily due to:

• higher prices of $51 million, primarily due to higher fuel adjustment charges of $45 million.

This increase was partially offset by:

• lower wholesale volume of $17 million, primarily due to increased generating unit outages; and

• lower retail volume of $12 million, primarily due to unfavorable weather.

Utilities gross margin for the nine months ended September 30, 2011 decreased $36 million, or 17%, compared to the nine months ended September 30, 2010 primarily due to:

• lower wholesale margin of $11 million, primarily due to increased generating unit outages;

• higher outage costs of $9 million for repairs and maintenance on generating units;

• lower retail margin of $6 million, primarily due to a non-recurring charge to retail revenue in the first quarter of 2011 and unfavorable weather; and

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• higher non-outage salaries, wages and benefits of $5 million, primarily due to increases in pension and health insurance expenses, as well as higher pay rates in 2011.

For the nine months ended September 30, 2011, revenue increased 2%, while gross margin decreased by 17% primarily due to the positive impact of higher pass-through fuel costs on revenue, which had no corresponding impact on gross margin, and increased maintenance costs due to outages.

Europe

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

	For the Three Months Ended September 30,							For the Nine Months Ended September 30,
	2011		2010		% Change			2011		2010		% Change
	($’s in millions)							($’s in millions)
Europe Generation
Revenue	$	397	$	282		41	%	$	1,125	$	864		30	%
Gross Margin	$	95	$	47		102	%	$	240	$	221		9	%

Excluding the favorable impact of foreign currency translation of $24 million, generation revenue for the three months ended September 30, 2011 increased $91 million, or 32%, compared to the three months ended September 30, 2010 primarily due to:

• new business of $77 million at Maritza, in Bulgaria, which commenced commercial operations in June 2011; and

• a net increase of $49 million from the operations of Ballylumford, in Northern Ireland, which was acquired in August 2010.

These increases were partially offset by:

• lower revenue of $27 million at Cartagena, primarily due to lower pass-through energy; and

• lower revenue of $7 million at Kilroot, in Northern Ireland, primarily driven by the cancellation of the long-term PPA and related supplementary agreements in November 2010 and a subsidy for flue gas desulphurization (“FGD”) investment that ended in 2010, partially offset by increased energy prices and CO₂ contributions passed through in the market price.

Excluding the favorable impact of foreign currency translation of $6 million, generation gross margin for the three months ended September 30, 2011 increased $42 million, or 89%, compared to the three months ended September 30, 2010 primarily due to:

• new business of $26 million at Maritza, which commenced commercial operations in June 2011, and $12 million from the reversal of fixed costs as a result of liquidated damages received from a subcontractor; and

• a net increase of $16 million from the operations at Ballylumford, which was acquired in August 2010.

These increases were partially offset by:

• a net decrease of $10 million at Kilroot primarily driven by the cancellation of the long-term PPA and related supplementary agreements in November 2010, lower volumes, and an increase in maintenance expense, partially offset by CO₂ contributions passed through in the market price; and

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• $9 million in Hungary, primarily from lower contract sales and lower volume on ancillary services, partially offset by higher capacity prices.

For the three months ended September 30, 2011, revenue increased 41%, while gross margin increased by 102% primarily due to the recovery of liquidated damages received from a subcontractor at Maritza, lower maintenance expense at Ballylumford, as the plant was under an outage in September 2010, lower pass-through revenue at Cartagena that had no corresponding impact on gross margin, and the reversal of bad debt in Kazakhstan.

Excluding the favorable impact of foreign currency translation of $58 million, generation revenue for the nine months ended September 30, 2011 increased $203 million, or 23%, compared to the nine months ended September 30, 2010 primarily due to:

• a net increase of $237 million from the operations of Ballylumford, which was acquired in August 2010; and

• new business of $107 million at Maritza, which commenced commercial operations in June 2011.

These increases were partially offset by:

• lower revenue of $76 million at Cartagena, primarily due to lower pass-through energy;

• lower revenue of $39 million at Kilroot, primarily driven by the cancellation of the long-term PPA and related supplementary agreements in November 2010; and

• a net decrease of $35 million in Hungary primarily from lower contract sales and lower volume on ancillary services, partially offset by higher capacity prices.

Excluding the favorable impact of foreign currency translation of $14 million, generation gross margin for the nine months ended September 30, 2011 increased $5 million, or 2%, compared to the nine months ended September 30, 2010 primarily due to:

• gross margin of $70 million from the operations at Ballylumford, which was acquired in August 2010; and

• gross margin of $27 million at Maritza, which commenced commercial operations in June 2011.

These increases were partially offset by:

• decreased gross margin of $60 million at Kilroot primarily driven by the cancellation of the long-term PPA and related supplementary agreements in November 2010, partially offset by CO₂ contributions passed through in the market price; and

• lower gross margin of $36 million in Hungary primarily due to a decline in contract energy prices and negative dark spread.

For the nine months ended September 30, 2011, revenue increased 30% while gross margin increased by 9% primarily due to the acquisition of Ballylumford, which had a larger positive impact on revenue than gross margin, higher energy revenues at Kilroot, which as a pass-through had no corresponding impact on gross margin, and increased fixed costs at Maritza due to delays in the commencement of commercial operations, partially offset by the reversal of liquidated damages at Maritza in July 2011 and the reversal of bad debt in Kazakhstan.

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Asia

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

	For the Three Months Ended September 30,							For the Nine Months Ended September 30,
	2011		2010		% Change			2011		2010		% Change
	($’s in millions)							($’s in millions)
Asia Generation
Revenue	$	172	$	136		26	%	$	449	$	491		-9	%
Gross Margin	$	38	$	52		-27	%	$	136	$	197		-31	%

Excluding the favorable impact of foreign currency translation of $8 million, generation revenue for the three months ended September 30, 2011 increased $28 million, or 21%, compared to the three months ended September 30, 2010 primarily due to:

• higher generation volume of $27 million at Kelanitissa in Sri Lanka due to higher offtaker demand as a result of lower hydrology and higher prices of $12 million at Kelanitissa due to higher pass-through fuel prices; and

• offset by outages of $6 million in Kelanitissa during the three months ended in September 30, 2011.

Excluding the favorable impact of foreign currency translation of $4 million, generation gross margin for the three months ended September 30, 2011 decreased $18 million, or 35%, compared to the three months ended September 30, 2010 primarily due to:

• a net decrease of $8 million at Masinloc attributable to lower spot prices offset in part by higher contract volume;

• a negative impact on gross margin of approximately $4 million at Kelanitissa due primarily to the planned plant outage.

For the three months ended September 30, 2011, revenue increased 26%, while gross margin decreased by 27%. This was primarily due to the negative influence on gross margin arising from lower rates at Masinloc and the outage at Kelanitissa.

Excluding the favorable impact of foreign currency translation of $20 million, generation revenue for the nine months ended September 30, 2011 decreased $62 million, or 13%, compared to the nine months ended September 30, 2010 primarily due to:

• a decrease of $55 million at Masinloc in the Philippines primarily due to lower generation prices and volume. Spot volume and prices were lower due to flat electricity demand and higher available capacity in the grid.

Excluding the favorable impact of foreign currency translation of $9 million, generation gross margin for the nine months ended September 30, 2011 decreased $70 million, or 36%, compared to the nine months ended September 30, 2010 primarily due to:

• a decrease of $64 million at Masinloc primarily attributable to lower generation prices and volume driven by a combination of flat market demand and lower spot prices, and higher coal prices.

For the nine months ended September 30, 2011, revenue decreased 9%, while gross margin decreased by 31%. This was primarily due to higher coal prices at Masinloc and pass-through revenue at Kelanitissa.

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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, Wind Generation and other climate solutions and renewables projects which are immaterial for the purposes of separate segment disclosure. The following table excludes inter-segment activity and summarizes revenue and gross margin for Corporate and Other entities for the periods indicated:

	For the Three Months Ended September 30,									For the Nine Months Ended September 30,
	2011			2010			% Change			2011			2010			% Change
	($’s in millions)									($’s in millions)
Revenue
Europe Utilities	$	93		$	90			3	%	$	293		$	258			14	%
Africa Utilities		61			91			-33	%		271			279			-3	%
Africa Generation		23			22			5	%		67			66			2	%
Wind Generation		42			44			-5	%		172			139			24	%
Corp/Other		5			11			-55	%		21			22			-5	%
Eliminations		(9	)		(6	)		-50	%		(24	)		(20	)		-20	%
Total Corporate and Other	$	215		$	252			-15	%	$	800		$	744			8	%
Gross Margin
Europe Utilities	$	5		$	6			-17	%	$	15		$	14			7	%
Africa Utilities		(49	)		7			-800	%		(47	)		10			-570	%
Africa Generation		11			12			-8	%		36			35			3	%
Wind Generation		1			-			100	%		49			20			145	%
Corp/Other		(5	)		5			-200	%		(19	)		1			-2000	%
Eliminations		-			3			-100	%		3			5			-40	%
Total Corporate and Other	$	(37	)	$	33			-212	%	$	37		$	85			-56	%

Excluding the favorable impact of foreign currency translation of $7 million, revenue for the three months ended September 30, 2011 decreased $44 million, or 17%, compared to the three months ended September 30, 2010 primarily due to:

• a decrease of $38 million at Sonel, in Cameroon, from the unfavorable impact of an unrealized mark-to-market derivative adjustment, partially offset by higher tariff and volume.

Excluding the unfavorable impact of foreign currency translation of $2 million, gross margin for the three months ended September 30, 2011 decreased $68 million, or 206%, compared to the three months ended September 30, 2010 primarily due to:

• a decrease of $55 million at Sonel from the unfavorable impact of an unrealized mark-to-market derivative adjustment, the recognition of service disruption penalties and increased fixed costs, partially offset by higher tariff and volume.

For the three months ended September 30, 2011, revenue decreased 15%, while gross margin decreased by 212%. This was primarily due to the recognition of service disruption penalties at Sonel.

Excluding the favorable impact of foreign currency translation of $17 million, revenue for the nine months ended September 30, 2011 increased $39 million, or 5%, compared to the nine months ended September 30, 2010 primarily due to:

• higher tariff, partially offset by lower volume, of $35 million at our utility businesses in the Ukraine; and

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• the additional revenue of $15 million from a wind generation project in Bulgaria that commenced operations in March 2010.

These increases were partially offset by:

• a decrease of $25 million at Sonel from the unfavorable impact of an unrealized mark-to-market derivative adjustment, partially offset by higher tariff and volume.

Excluding the unfavorable impact of foreign currency translation of $4 million, gross margin for the nine months ended September 30, 2011 decreased $44 million, or 52%, compared to the nine months ended September 30, 2010 primarily due to:

• a decrease of $53 million at Sonel from the unfavorable impact of an unrealized mark-to-market derivative adjustment, the recognition of service disruption penalties and increased fixed costs, partially offset by higher tariff and volume.

This decrease was partially offset by:

• gross margin of $12 million from a wind generation project in Bulgaria that commenced operations in March 2010.

For the nine months ended September 30, 2011, revenue increased 8%, while gross margin decreased by 56%. This was primarily due to higher tariffs at our utility businesses in Ukraine, which only had a marginal impact on gross margin, and higher fixed costs and the recognition of service disruption penalties at Sonel.

General and Administrative Expense

General and administrative expense decreased $7 million, or 7%, to $91 million for the three months ended September 30, 2011. The decrease was primarily due to a reduction of SAP implementation costs and business development costs, partially offset by DPL transaction costs.

General and administrative expense increased $4 million, or 1%, to $283 million for the nine months ended September 30, 2011. The increase was primarily due to DPL transaction costs, partially offset by a reduction of SAP implementation and business development costs.

Interest expense

Interest expense increased $51 million, or 13%, to $432 million for the three months ended September 30, 2011. The increase was primarily due to increased average outstanding indebtedness at the Parent Company and less interest capitalization at Maritza due to the commencement of power plant operations.

Interest expense increased $27 million, or 2%, to $1.2 billion for the nine months ended September 30, 2011. The increase was primarily due to higher interest rates offset by lower average outstanding indebtedness, an unfavorable impact of foreign currency translation in Brazil, a monetary correction related to VAT over commercial losses at Eletropaulo, and additional bridge loan fees at the Parent Company.

Interest income

Interest income increased $7 million, or 7%, to $103 million for the three months ended September 30, 2011. The increase is primarily due to favorable foreign currency translation.

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Interest income decreased $11 million, or 4%, to $293 million for the nine months ended September 30, 2011. The decrease was primarily due to the settlement of a dispute related to inflation adjustments for energy sales in Tiete in 2010 and a settlement of a loan receivable at a wind development project in Brazil in 2010. The decreases were partially offset by the favorable impact on foreign currency translation in Brazil.

Other expense

Other expense of $76 million for the three months ended September 30, 2011 was primarily due to the premium paid on the early retirement of debt at Gener, and losses on the disposal of assets at TermoAndes and Eletropaulo. Other expense of $23 million for the three months ended September 30, 2010 was primarily comprised of losses on disposal of assets at Eletropaulo and Gener.

Other expense of $131 million for the nine months ended September 30, 2011 was primarily due to the premium paid on early retirement of debt at Gener, a loss related to the early retirement of senior notes due in 2011 at IPL, and loss on disposal of assets at Eletropaulo and TermoAndes. Other expense of $83 million for the nine months ended September 30, 2010 included the previously capitalized transaction costs of $22 million that were incurred in connection with the preparation for the sale of a noncontrolling interest in our Wind Generation business. These costs were written off upon the expiration of the letter of intent (“LOI”) on June 30, 2010. Also, there was a $9 million loss on debt extinguishment at the Parent Company from the retirement of senior notes, and losses on disposal of assets at Eletropaulo and Gener.

Other income

Other income of $58 million for the three months ended September 30, 2011 was primarily due to an additional tax credit settlement from a favorable court decision in 2011 concerning reimbursement of excess non-income taxes paid from 1989 to 1992 at Eletropaulo, and the reimbursement of income tax expense recognized during the quarter related to an indemnity agreement between Los Mina and the Dominican Republic government. Other income of $17 million for the three months ended September 30, 2010 was primarily related to gain on sale of assets at Eletropaulo.

Other income of $108 million for the nine months ended September 30, 2011 was primarily related to the items described above, in addition to the gain on sale of mineral rights and land at IPL. Other income of $94 million for the nine months ended September 30, 2010 was primarily related to the extinguishment of a swap liability owed by two of our Brazilian subsidiaries, resulting in the recognition of a $62 million gain. The net impact to the Company after taxes and noncontrolling interest was $9 million. Other income also included a gain on sale of assets at Eletropaulo.

Goodwill impairment

Goodwill impairment was $17 million for the three and nine months ended September 30, 2011.

During the third quarter of 2011, the Company identified higher coal prices and the resulting reduced operating margins in China as a goodwill impairment indicator for Chigen, our holding company that holds AES’ interests in Chinese joint ventures. A significant downward revision of cash flow forecasts indicated that the fair value of Chigen reporting unit was lower than its carrying amount. See Note 15 — Other Non-operating Expense to Item 1. — Financial Statements for further information. As of September 30, 2011, Chigen had goodwill of $17 million. The Company performed an interim impairment evaluation of Chigen’s goodwill and determined that goodwill had no implied fair value. As a result, the entire carrying amount of $17 million was recognized as goodwill impairment.

Goodwill impairment was $18 million for the three and nine months ended September 30, 2010.

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During the third quarter of 2010, the Company determined there was an indicator that the carrying value of goodwill related to Deepwater, our pet coke-fired merchant generation facility in Texas, was not recoverable. This determination was based primarily on the fact that Deepwater did not operate for more than 30 days in the three months ended September 30, 2010, had incurred current operating and cash flow losses, and was forecasting operating and cash flow losses for the remainder of 2010 through 2014 as a result of decreases in future power price expectations and an increase in pet coke prices. Deepwater is reported in the North America Generation segment.

Asset impairment expense

Asset impairment expense was $163 million and $196 million for the three and nine months ended September 30, 2011, respectively.

During the third quarter of 2011, the Company evaluated the future use of certain wind turbines held in storage pending their installation. Due to reduced wind turbine market pricing and advances in turbine technology, the Company determined it was more likely than not that the turbines would be sold significantly before the end of their previously estimated useful lives. In addition, the Company has concluded that more likely than not non-refundable deposits it had made in prior years to a turbine manufacturer for the purchase of wind turbines are not recoverable. The Company determined it was more likely than not that it would not proceed with the purchase of turbines due to the availability of more advanced and lower cost turbines in the market. These developments were more likely than not as of September 30, 2011 and as a result were considered impairment indicators. In October 2011, the Company determined that an impairment had occurred as of September 30, 2011 as the aggregate carrying amount of $161 million of these assets was not recoverable and was reduced to their estimated fair value of $45 million determined under the market approach. This resulted in asset impairment expense of $116 million for the three and nine months ended September 30, 2011. Wind Generation is reported in the Corporate and Other segment.

During the third quarter of 2011, the markets for emission reduction offsets, including Certified Emission Reductions (CERs) and European Allowance Units (EUAs), experienced a significant adverse change, as the global economic conditions contributed to unforeseen deterioration in the market prices of CERs and EUAs. This decline in the market prices of emission reduction offsets adversely impacted the Company’s Carbon Reduction Projects in Asia and Latin America. The Latin American project also incurred current period operating losses and is projecting continuing operating and cash flow losses for future periods. Consequently, we determined that indicators of impairment existed as of September 30, 2011 and the carrying amounts of these projects were not recoverable based on undiscounted cash flows. The fair value of the projects was then determined using discounted cash flow analysis. The aggregate carrying amount of $49 million of these projects was written down as their estimated fair value was $11 million, resulting in asset impairment expense of $33 million, which was limited to the carrying amounts of long-lived assets. Carbon Reduction Projects are reported in the Corporate and Other segment.

During the second quarter of 2011, the Company recognized asset impairment expense of $33 million for the long-lived assets of Kelanitissa, our diesel-fired generation plant in Sri Lanka. We have continued to evaluate the recoverability of our long-lived assets at Kelanitissa as a result of both the existing government regulation which may require the government to acquire an ownership interest and the current expectation of future losses. Our evaluation during the quarter indicated that the long-lived assets were no longer recoverable and accordingly they were written down to their estimated fair value of $33 million based on a discounted cash flow analysis. The long-lived assets had a carrying amount of $66 million prior to the recognition of asset impairment expense. An additional impairment of $4 million was recognized in the three months ended September 30, 2011. Kelanitissa is a Build-operate-transfer (BOT) generation facility and payments under its PPA are scheduled to decline over the PPA term. It is possible that further impairment charges may be required in the future as Kelanitissa gets closer to the BOT date. Kelanitissa is reported in the Asia Generation reportable segment.

Asset impairment expense was $296 million and $297 million for the three and nine months ended September 30, 2010, respectively.

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During the third quarter of 2010, the Company entered into annual negotiations with the offtaker of its Tisza II generation plant in Hungary. As a result of these preliminary negotiations, as well as the further deterioration of the economic environment in Hungary, the Company determined that an indicator of impairment existed at September 30, 2010. Thus, the Company performed an asset impairment test and determined that based on the undiscounted cash flow analysis, the carrying amount of the Tisza II asset group was not recoverable. The fair value of the asset group was then determined using a discounted cash flow analysis. The carrying value of the Tisza II asset group of $160 million exceeded the fair value of $75 million resulting in the recognition of asset impairment expense of $85 million during the three and nine months ended September 30, 2010. Tisza II is reported in the Europe Generation reportable segment.

In September 2010, the Office of Administrative Law in California approved the policy that would require the Company to change the process through which it uses ocean water to cool the generation turbines at its Alamitos, Huntington Beach and Redondo Beach (collectively “Southland”) gas-fired generation facilities in California. The policy requires compliance with the new regulations by December 31, 2020. The change in the water cooling process will result in significant future capital expenditures to ensure compliance with the new regulations or a shut down of the plants and, therefore, the Company determined that an indicator of impairment existed at September 30, 2010. The Company performed an asset impairment test and the asset group was determined to be at the individual plant level and based on the undiscounted cash flow analysis, the Company determined that the Huntington Beach asset group was not recoverable. The fair value of the Huntington Beach asset group was then determined using a discounted cash flow analysis. The carrying value of the Huntington Beach plant of $288 million exceeded the fair value of $88 million resulting in the recognition of asset impairment expense of $200 million for the three and nine months ended September 30, 2010. The undiscounted cash flows of the Alamitos and Redondo Beach asset groups exceeded their respective carrying values and resulted in no impairment. Huntington Beach is reported in the North America Generation reportable segment.

Gain on sale of investments

There was no gain on sale of investments for the three months ended September 30, 2011 and 2010.

Gain on sale of investments for the nine months ended September 30, 2011 was $7 million, primarily related to our sale of Wuhu, an equity investment in China that was accounted for under the equity method of accounting. There was no gain on sale of investments for the nine months ended September 30, 2010.

Foreign currency transaction gains (losses) on net monetary position

Foreign currency transaction gains (losses) were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions)						(in millions)
AES Corporation	$	(37	)	$	53		$	10		$	(33	)
Chile		(22	)		27			(24	)		7
Philippines		-			18			8			18
Brazil		(15	)		5			(11	)		(8	)
Argentina		(1	)		(2	)		11			11
Colombia		3			(7	)		(1	)		(13	)
Other		(20	)		9			(14	)		(1	)
Total(1)	$	(92	)	$	103		$	(21	)	$	(19	)

⁽¹⁾  Includes $16 million in gains and $16 million in losses on foreign currency derivative contracts for the three months ended September 30, 2011 and 2010, respectively, and $35 million and $1 million in gains on foreign currency derivative contracts for the nine months ended September 30, 2011 and 2010, respectively.

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The Company recognized foreign currency transaction losses of $92 million for the three months ended September 30, 2011. These consisted primarily of losses at The AES Corporation, in Chile and in Brazil.

• Losses of $37 million at The AES Corporation were primarily due to a decrease in the valuation of notes and trade receivables, primarily resulting from the weakening of the Euro and British Pound during the quarter.

• Losses of $22 million in Chile were primarily due to an 11% devaluation of the Chilean Peso, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with net working capital denominated in Chilean Pesos, primarily cash, accounts receivable and tax receivables as well as a $2 million loss on foreign currency derivatives.

• Losses of $15 million in Brazil were primarily due to a 19% devaluation of the Brazilian Real, resulting in losses associated with U.S. Dollar denominated debt at the Company’s subsidiaries in Brazil.

The Company recognized foreign currency transaction gains of $103 million for the three months ended September 30, 2010. These consisted primarily of gains at The AES Corporation, in Chile and in the Philippines.

• Gains of $53 million at The AES Corporation were primarily due to the strengthening of the Euro and British Pound during the quarter, resulting in gains on notes receivables and cash balances denominated in Euros, which were partially offset by losses on debt denominated in British Pounds.

• Gains of $27 million in Chile were primarily due to a 12% appreciation of the Chilean Peso resulting in gains at Gener associated with working capital denominated in Chilean Pesos, primarily cash, accounts receivable and tax receivables. These gains were partially offset by a $3 million loss on foreign currency derivatives.

• Gains of $18 million in the Philippines were primarily due to appreciation of the Philippine Peso of 5% during the quarter, resulting in gains at Masinloc (a Philippine Peso functional currency subsidiary) on the remeasurement of U.S. Dollar denominated debt.

The Company recognized foreign currency transaction losses of $21 million for the nine months ended September 30, 2011. These consisted primarily of losses in Chile and Brazil, partially offset by gains in Argentina.

• Losses of $24 million in Chile were primarily due to an 11% devaluation of the Chilean Peso, resulting in losses at Gener associated with net working capital denominated in Chilean Pesos, primarily cash, accounts receivable and tax receivables as well as an $8 million loss on foreign currency derivatives.

• Losses of $11 million in Brazil were primarily due to a 11% devaluation of the Brazilian Real, resulting in losses associated with U.S. Dollar denominated debt at the Company’s subsidiaries in Brazil.

• Gains of $11 million in Argentina were primarily due to a gain on a foreign currency embedded derivative related to government receivables, partially offset by losses due to the devaluation of the Argentine Peso by 6%, resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt.

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The Company recognized foreign currency transaction losses of $19 million for the nine months ended September 30, 2010. These consisted primarily of losses at The AES Corporation and in Colombia, partially offset by gains in the Philippines and Argentina.

• Losses of $33 million at The AES Corporation were primarily due to the weakening of the Euro during the nine months ended September 30, 2010, resulting in the devaluation of notes receivable and cash balances denominated in Euros.

• Losses of $13 million in Colombia were primarily due to the appreciation of the Colombian Peso by 12%, resulting in losses at Chivor associated with its Colombian Peso denominated debt. In addition, there was a loss of $5 million from foreign currency derivatives.

• Gains of $18 million in the Philippines were primarily due to appreciation of the Philippine Peso of 5% during the third quarter, resulting in gains at Masinloc on the remeasurement of U.S. Dollar denominated debt.

• Gains of $11 million in Argentina were primarily due to a gain on a foreign currency embedded derivative related to government receivables, partially offset by losses due to the devaluation of the Argentine Peso by 4%, resulting in losses at Alicura with its U.S. Dollar denominated debt.

Other non-operating expense

Other non-operating expense of $82 million for the three and nine months ended September 30, 2011 primarily consisted of other-than-temporary impairments of equity method investments in China.

During the third quarter of 2011 as part of the quarterly close process, the Company evaluated YangCheng International Power Generating Co Ltd (“YangCheng”), a 2,100 MW coal-fired plant in China, for other-than-temporary-impairment. AES owns a 25% interest in YangCheng and the remaining equity interest in the venture is held by Chinese partners. During the nine months ended September 30, 2011, coal prices continued an upward trend in China, thereby, reducing the operating margin of coal generation facilities. During this time, there was no corresponding increase in tariffs to compensate for higher coal prices. Power prices in China are tightly regulated by the national and provincial governments, which often limit power generators’ ability to pass through increases in fuel costs to customers. In addition, under the YangCheng venture agreement, AES will surrender its equity interest to the JV partners in 2016 without additional compensation. During the nine months ended September 30, 2011, management continued to monitor the situation and in the third quarter determined that it was unlikely that there would be a reversal in the trends in coal prices during the remaining term of the venture. Accordingly, during September 2011, management revised downward its forecasts of earning and cash flows over the remaining term of the venture. The revised forecasts were significantly lower than management’s earlier estimates such that the carrying amount of the investment in YangCheng was considered to have incurred an other-than-temporary-impairment. In determining the fair value of our investment, management used a discounted cash flow analysis based on probability-weighted revised cash distribution forecasts under multiple scenarios. As of September 30, 2011, YangCheng had a carrying amount of $100 million which was written down to the estimated fair value of $26 million, and the difference was recognized as other non-operating expense.

Other non-operating expense of $2 million and $7 million, respectively, for the three and nine months ended September 30, 2010 primarily consisted of an other-than-temporary impairment of an equity method investment.

Income tax expense

Income tax expense on continuing operations decreased $18 million, or 18%, to $84 million for the three months ended September 30, 2011 compared to $102 million for the three months ended September 30, 2010. The Company’s effective tax rates were 37% and 28% for the three months ended September 30, 2011 and 2010, respectively.

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The net increase in the effective tax rate for the three months ended September 30, 2011 compared to the same period in 2010 was primarily due to a valuation allowance recorded at one of our Argentinean subsidiaries, the impact of the impairments recorded in the current period, and tax benefit related to a reversal of a Chilean withholding tax liability recorded in the third quarter of 2010. See Note 14 — Impairments for additional information regarding the current period impairments. These items were offset by the extension of a favorable U.S. tax law in the fourth quarter of 2010 impacting distributions from certain non-U.S. subsidiaries and the impact of a depreciating Peso in certain of our Mexican subsidiaries.

Income tax expense on continuing operations decreased $71 million, or 13%, to $469 million for the nine months ended September 30, 2011 compared to $540 million for the nine months ended September 30, 2010. The Company’s effective tax rates were 31% and 37% for the nine months ended September 30, 2011 and 2010, respectively.

The net decrease in the effective tax rate for the nine months ended September 30, 2011 compared to the same period in 2010 was primarily due to the extension of a favorable U.S. tax law in the fourth quarter of 2010 impacting distributions from certain non-U.S. subsidiaries and expense recorded in the second quarter of 2010 relating to the CEMIG sale transaction. These items were offset by a tax benefit related to a reversal of a Chilean withholding tax liability recorded in the third quarter of 2010. Included in the net 2010 tax expense relating to the CEMIG sale is tax expense on the equity earnings associated with the reversal of the net long-term liability and tax benefit upon the release of a valuation allowance against deferred tax assets.

Net equity in earnings of affiliates

Net equity in earnings of affiliates decreased $20 million, or 77%, to $6 million for the three months ended September 30, 2011. The decrease was primarily due to decreased earnings at Guacolda in Chile due to lower spot sales as well as foreign currency losses recognized at our affiliates in Turkey and our equity affiliate Cayman Energy Traders in Brazil.

Net equity in earnings of affiliates decreased $162 million, or 93%, to $12 million for the nine months ended September 30, 2011. The decrease was primarily due to the sale of our interest in CEMIG during the second quarter of 2010, higher coal prices at Yangcheng in China in 2011, and $30 million in impairments at AES Solar in 2011 of which our share was $15 million.

Income from continuing operations attributable to noncontrolling interests

Income from continuing operations attributable to noncontrolling interests increased $21 million, or 8%, to $269 million for the three months ended September 30, 2011. The increase was primarily due to increased volume at Eletropaulo driven by market demand as well as the appreciation of the Brazilian Real. These increases were partially offset by the devaluation of the Chilean Peso, losses on the extinguishment of debt at Gener and lower gross margin at Sonel due mainly to the unfavorable impact of an unrealized mark to market adjustment.

Income from continuing operations attributable to noncontrolling interests increased $41 million, or 6%, to $766 million for the nine months ended September 30, 2011. The increase was primarily due to the appreciation of the Brazilian Real and increased gross margin at Gener, partially offset by lower gross margin at Sonel due mainly to the unfavorable impact of an unrealized mark to market adjustment.

Discontinued operations

As further discussed in Note 16 — Discontinued Operations and Held for Sale Businesses, discontinued operations include the results of the following businesses:

• Brazil Telecom, 46% owned telecommunication businesses in Brazil (held for sale as of September 2011);

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• Eastern Energy, including Cayuga, Greenidge, Somerset and Westover, 100% owned coal-fired power plants in New York (held for sale since March 2011);

• Borsod and Tiszapalkonya, 100% owned biomass and coal-fired facility and multi-fuel facility, respectively, in Hungary (held for sale since March 2011);

• Ras Laffan, 55% owned combined cycle gas facility and water desalination plant in Qatar (sold in October 2010);

• Barka, 35% owned combined cycle gas facility and water desalination plant in Oman (sold in August 2010); and

• Lal Pir and Pak Gen, 55% owned oil-fired facilities in Pakistan (sold in June 2010).

Prior periods have been restated to reflect these businesses within Discontinued Operations for all periods presented.

For the three months and nine months ended September 30, 2011, operations of discontinued businesses, net of tax and income attributable to noncontrolling interests, incurred a net loss of $12 million and $29 million, respectively. Discontinued operations reflected the operations of Brazil Telecom, Eastern Energy, Borsod and Tiszapalkonya.

For the three months and nine months ended September 30, 2010, income from operations of discontinued businesses, net of tax and income attributable to noncontrolling interests, was $12 million and $42 million, respectively. Discontinued operations reflected the operations of all generation facilities mentioned above. During the three months ended September 30, 2010, the Barka plant was sold resulting in a gain on sale of $63 million, net of tax and income attributable to noncontrolling interests. During the nine months ended September 30, 2010, the Company recognized impairment and a loss on the sale of Lal Pir and Pak Gen of $14 million, net of tax and noncontrolling interests, consisting of $7 million impairment in the first quarter and $7 million loss on sale. Including the Barka sale, total impairments and gains on sales were $49 million for the nine months ended September 30, 2010, net of tax and noncontrolling interests.

Capital Resources and Liquidity

Overview

As of September 30, 2011, the Company had unrestricted cash and cash equivalents of $3.4 billion, of which approximately $2.1 billion was held at the Parent Company and qualified holding companies, and short term investments of $1.1 billion. In addition, we had restricted cash and debt service reserves of $1.7 billion. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $14.7 billion and $6.2 billion, respectively. Of the approximately $2.2 billion of our short-term non-recourse debt, $864 million was presented as current because it is due in the next twelve months and $1.3 billion relates to defaulted debt. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. Approximately $11 million of our recourse debt matures within the next twelve months, which we expect to repay using cash on hand at the Parent Company or through net cash provided by operating activities. See further discussion of Parent Company Liquidity below.

During 2011, the Company issued $2.05 billion of recourse debt, which, among other things, may be used to partially finance the contemplated DPL acquisition, see Note 8 — Debt and Note 17 — Acquisitions in Notes to Condensed Consolidated Financial Statements in Item 1.

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The Company has two types of debt reported on its consolidated 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 acquisitions, including funding for equity investments or to 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. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks.

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. Presently, the Parent Company’s only material un-hedged exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility. On a consolidated basis, of the Company’s $14.7 billion of total non-recourse debt outstanding as of September 30, 2011, approximately $4.5 billion bore interest at variable rates that were not subject to a derivative instrument 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 issuances of debt, 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, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At September 30, 2011, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $357 million in aggregate (excluding investment commitments and those collateralized by letters of credit and other obligations discussed below).

As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or

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other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At September 30, 2011, we had $12 million in letters of credit outstanding, provided under the senior secured credit facility, and $260 million in cash collateralized letters of credit outstanding outside of the senior secured credit facility. These letters of credit operate to guarantee performance relating to certain project development activities and business operations. During the quarter ended September 30, 2011, the Company paid letter of credit fees ranging from 0.25% to 3.25% 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 we or our affiliates 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 on economically attractive terms or at all. See Global Economic Conditions 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 choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.

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

As of September 30, 2011, the Company had approximately $365 million of trade accounts receivable related to certain of its generation and utility 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, 2012, or one year past the balance sheet date. The Company is actively collecting these receivables and believes such amounts are collectible based on collection history and performance under agreements. Additionally, the current portion of these trade accounts receivable was $36 million at September 30, 2011.

Consolidated Cash Flows.    During the nine months ended September 30, 2011, cash and cash equivalents increased $842 million to $3.4 billion. The increase in cash and cash equivalents was due to $2.3 billion of cash provided by operating activities, $1.7 billion of cash used for investing activities, $347 million of cash provided by financing activities and the unfavorable effect of foreign currency exchange rates on cash of $79 million.

Operating Activities

Net cash provided by operating activities decreased $108 million to $2.3 billion during the nine months ended September 30, 2011 compared to $2.4 billion during the nine months ended September 30, 2010. This net decrease was primarily the result of the following:

• a decrease of $138 million at our Asia generation businesses primarily due to lower operating income and higher working capital requirements at Masinloc in the Philippines as well as from the sale of Lal Pir, Pak Gen, Barka and Ras Laffan in 2010;

• a decrease of $128 million at our North America generation businesses primarily due to reduced operations at our New York Plants and higher working capital requirements at Puerto Rico; offset by

• an increase of $83 million at our Latin American generation businesses primarily due to higher gross margin at our businesses in Chile and the Dominican Republic partially offset by lower margin in Panama and higher tax payments at Gener.

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Investing Activities

Net cash used for investing activities increased $387 million to $1.7 billion during the nine months ended September 30, 2011 compared to net cash used of $1.3 billion during the nine months ended September 30, 2010. This net increase was primarily due to the following:

• an increase of $370 million in debt service reserves and other assets during the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. During the nine months ended September 30, 2011, $379 million of funds were transferred to debt service reserves and other assets primarily related to the collateralization for a letter of credit of $223 million at the Parent Company for the Mong Duong project, escrowed cash reserves of $115 million to cover certain expenses associated with the DPL acquisition financing at Dolphin II, lender imposed restrictions on funds of $25 million at Sonel and funds requested to pay a construction retainage at Panama of $24 million. These increases were partially offset by a transfer out of debt service reserves and other assets for payment of rent of $33 million at New York;

• a decrease of $322 million in proceeds from the sale of businesses for the nine months ended September 30, 2011. The decrease was primarily due to proceeds of $170 million related to the sale in August 2010 of Barka in Oman, the final settlement proceeds of $99 million received in January 2010 from the termination of a management agreement with Kazakhmys PLC in Kazakhstan related to Ekibastuz and Maikuben which were sold in May 2008 and the net proceeds from the sale of Lal Pir and Pak Gen in Pakistan in June 2010 of $100 million. These decreases were partially offset by an increase in proceeds of $36 million at Vietnam due to the sale of a 49% interest in Mong Duong;

• an increase of $304 million in capital expenditures to $1.8 billion primarily due to net increases in capital expenditures of $173 million at our Brazilian subsidiaries, $134 million at Vietnam, $80 million at Kribi and $71 million at Ipalco. These increases were partially offset by net decreases in capital expenditures of $96 million at Gener and $66 million at Maritza in Bulgaria;

• a decrease of $132 million in proceeds from loan repayments for the nine months ended September 30, 2011. In 2010, we received $132 million in proceeds related to the repayment of the loan receivable from a wind development project in Brazil; partially offset by

• an increase of $516 million to $559 million from the sale of short-term investments, net of purchases, for the nine months ended September 30, 2011 from $43 million from the sale of short-term investments, net of purchases for the nine months ended September 30, 2010. The increase was primarily due to increases in net sales of $437 million and $97 million at our Brazilian subsidiaries and Gener, respectively, due to the use of investment proceeds for dividend distributions. Net sales were partially offset by an increase in net purchases of $29 million at Chivor; and

• an increase of $199 million in proceeds related to a performance bond received at Maritza in Bulgaria to compensate for construction delays. There were no proceeds from performance bonds in 2010.

Financing Activities

Net cash provided by financing activities increased $325 million to $347 million during the nine months ended September 30, 2011 compared to $22 million during the nine months ended September 30, 2010. This net increase was primarily due to the following:

• a $2 billion increase in proceeds from the issuance of recourse debt at the Parent Company which is expected to be used to partially fund the acquisition of DPL;

• a $145 million decrease in repayments of recourse debt due to higher repayments of maturing debt at the Parent Company in 2010; partially offset by

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• a $1.6 billion decrease in the issuance of common stock, net of transaction costs due to the China Investment Corporation transaction in 2010;

• a $210 million increase in the purchase of treasury stock under the company’s common stock repurchase plan; and

• a $103 million increase in payments for financing fees primarily due to the issuance of debt at the Parent Company, Vietnam and Gener.

Parent Company Liquidity

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

Cash requirements at the Parent Company level are primarily to fund:

• interest;

• principal repayments of debt;

• acquisitions;

• construction commitments;

• other equity commitments;

• equity repurchases;

• 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 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, 2011 and December 31, 2010 as follows:

Parent Company Liquidity	September 30, 2011			December 31, 2010
	(in millions)
Consolidated cash and cash equivalents	$	3,392		$	2,550
Less: Cash and cash equivalents at subsidiaries		(1,303	)		(1,428	)
Parent and qualified holding companies cash and cash equivalents		2,089			1,122
Commitments under Parent credit facilities		800			800
Less: Borrowings and letters of credit under the credit facilities		(12	)		(85	)
Borrowings available under Parent credit facilities		788			715
Total Parent Company Liquidity	$	2,877		$	1,837

The following table summarizes our Parent Company contingent contractual obligations as of September 30, 2011:

Contingent contractual obligations	Amount		Number of Agreements		Maximum Exposure Range for Each Agreement
	(in millions)				(in millions)
Guarantees	$	357		23	<$1 - $53
Letters of credit under the senior secured credit facility		12		11	<$1 - $7
Cash collateralized letters of credit		260		13	<$1 - $223
Total	$	629		47

As of September 30, 2011, the Company had $16 million of commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit discussed above. The Company expects to fund these net investment commitments in 2011. The exact payment schedules will be dictated by the construction milestones. Additionally, subject to regulatory approvals, the Company is committed to purchase DPL for $3.5 billion, see Note 17 — Acquisitions for further information. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.

As of September 30, 2011, Parent Company Liquidity included the proceeds from the senior secured term loan and the 7.375% 2021 Notes, which may, among other things, be used to partially finance the Company’s contemplated acquisition of DPL Inc., as discussed further in Note 17 — Acquisitions.

We have a diverse portfolio of performance related contingent contractual obligations. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, subsidiary default, political risk, tax indemnities, spot market power prices, sponsor support and liquidated damages under power sales agreements for projects in development, in operation and under construction. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations during 2012 or beyond, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.

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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 (see Key Trends and Uncertainties and Global Economic Conditions), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the 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 credit facility. See Item 1A. — Risk Factors, “The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.” of the Company’s 2010 Form 10-K.

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

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

• limitations on dividends, stock repurchases and other equity transactions;

• restrictions and limitations 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.

As of September 30, 2011, we were in compliance with these covenants at the Parent Company level.

Recourse Debt

During the nine months ended September 30, 2011, the Company secured recourse debt of $2.05 billion. The proceeds of the debt may, among other things, be used to partially finance the Company’s contemplated acquisition of DPL Inc, as discussed further in Note 17 — Acquisitions.

On May 27, 2011, the Company secured a $1.05 billion term loan under a senior secured credit facility (the “senior secured term loan”). The senior secured term loan will bear annual interest, at the Company’s option, at a variable rate of LIBOR plus 3.25% or Base Rate plus 2.25%, and will mature on the seventh anniversary of the closing date. The senior secured term loan is subject to certain customary representations, covenants and events of default.

On June 15, 2011, the Company issued $1 billion aggregate principal amount of 7.375% senior unsecured notes maturing July 1, 2021 (the “7.375% 2021 Notes”). Upon a change of control, the Company must offer to repurchase the 7.375% 2021 Notes at a price equal to 101% of principal, plus accrued and unpaid interest. The 7.375% 2021 Notes are also subject to certain covenants restricting the ability of the Company to incur additional secured debt; to enter into sale-lease back transactions; to consolidate, merge, convey or transfer substantially all of its assets; as well as other covenants and events of default that are customary for debt securities similar to the 7.375% 2021 Notes. The Company entered into interest rate locks in May 2011 to hedge the risk of changes in LIBOR until the issuance of the 7.375% 2021 Notes. The Company paid $24 million to settle those interest rate locks as of June 15, 2011. The payment was recognized in accumulated other comprehensive loss and is being amortized over the life of the 7.375% 2021 Notes.

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Recourse debt as of September 30, 2011 is scheduled to reach maturity as set forth in the table below:

	Annual Maturities
	(in millions)
October 1 - December 31, 2011	$	3
2012 .		11
2013 .		11
2014 .		509
2015 .		511
Thereafter		5,147
Total recourse debt	$	6,192

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 still have important consequences for our results of operations and liquidity, including, without limitation:

• reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent 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 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 Company.

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

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying condensed consolidated balance sheet amounts to $2.2 billion. The portion of current debt related to such defaults was $1.3 billion at September 30, 2011, all of which was non-recourse debt related to three subsidiaries — Maritza, Sonel and Kelanitissa.

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’ corporate debt agreements as of September 30, 2011 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 or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the AES Parent Company’s outstanding debt securities.

On October 3, 2011, Dolphin Subsidiary II, Inc. (“Dolphin II”), a newly formed, wholly owned special purpose indirect subsidiary of AES, entered into an indenture (the “Indenture”) with Wells Fargo Bank, N.A. (the “Trustee”) as part of its issuance of $450 million aggregate principal amount of 6.50% senior notes due 2016

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(the “2016 Notes”) and $800 million aggregate principal amount of 7.25% senior notes due 2021 (the “7.25% 2021 Notes”, together with the 2016 Notes, the “notes”) to finance the pending acquisition (the “Acquisition”) by AES of DPL Inc. (“DPL”). See Note 17 — Acquisitions for further information.

Interest on the 2016 Notes and the 7.25% 2021 Notes accrues at a rate of 6.50% and 7.25% per year, respectively, and is payable on April 15 and October 15 of each year, beginning April 15, 2012. Prior to September 15, 2016 with respect to the 2016 Notes or July 15, 2021 with respect to the 7.25% 2021 Notes, Dolphin II may redeem some or all of the 2016 Notes or 7.25% 2021 Notes at par, plus a “make-whole” amount set forth in the Indenture and accrued and unpaid interest. At any time on or after September 15, 2016 or July 15, 2021 with respect to the 2016 Notes and 7.25% 2021 Notes, respectively, Dolphin II may redeem some or all of the 2016 Notes or 7.25% 2021 Notes at par plus accrued and unpaid interest.

The proceeds from issuance of the notes were deposited into an escrow account pledged for the benefit of the Trustee pending the consummation of the Acquisition. The notes are subject to a special mandatory redemption at a price of 101% of the offering price of the notes plus accrued and unpaid interest in the event that the Acquisition is not consummated on or before September 30, 2012. If the acquisition closes on or before such date, Dolphin II will concurrently merge with and into DPL, with DPL being the surviving company and obligor under the notes.

On September 28, 2011, the Company provided a letter of credit for approximately $115 million in favor of the escrow agent for the benefit of the Trustee pending the consummation of the Acquisition to cover payment of the interest expense from October 3, 2011 to September 30, 2012, the discount paid to the initial purchasers of the notes and special mandatory redemption price of 1% of the offering price of the notes. On September 29, 2011, at the instructions of the Dolphin II, escrow agent drew the entire amount of the letter of credit and deposited into the same escrow account for the benefit of the Trustee pending the consummation of the Acquisition. At the Acquisition consummation, any excess amount in the escrow account will be returned to Dolphin II.

Critical Accounting Policies and Estimates

The condensed 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 June 2011 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 June 2011 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 nine months ended September 30, 2011.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks

We are a global company in the power generation and distribution businesses. We own and/or operate power plants to generate and sell power to wholesale customers. We also own and/or operate utilities to distribute, transmit and sell electricity to end-user customers. Our primary market risk exposure is to the price of commodities particularly electricity, oil, natural gas, coal and environmental credits. We operate in multiple countries and as such are subject to volatility in exchange rates at the subsidiary level and between our functional currency, the U.S. Dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments.

These disclosures set forth in this Item 3 are based upon a number of assumptions, and actual impacts to the Company may not follow the assumptions made by the Company. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 3. For further information regarding market risk, see 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”, “Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance” and “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” in the Company’s 2010 Form 10-K.

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 operational results to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options.

When hedging the output of our generation assets, we have PPAs or other hedging instruments that lock in the spread per MWh between variable costs, such as fuel, to generate a unit of electricity and the price at which the electricity can be sold. The portion of our sales and purchases that are not subject to such agreements will be exposed to commodity price risk.

AES businesses will see variance in variable margin performance as global commodity prices shift. For the remainder of 2011, excluding operations from the Company’s merchant generation assets in New York, we project pre-tax earnings exposure would be approximately $5 million for a $10/barrel move in oil and $5 million for a $1/MMBTU move in natural gas. Exposure to coal for the remainder of the year is not considered significant. AES’s merchant generation assets in New York, which are reflected in discontinued operations, are estimated to have pre-tax earnings exposure of $10 million for a $1/MMBTU move in natural gas and $5 million for a $10/ton move in coal. Exposure to coal and oil for the remainder of the year is not considered significant. Our estimates exclude correlation. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed.

Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Generation costs can be directly affected by movements in the price of natural gas, oil

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and coal. Spot power prices and contract indexation provisions are affected by the same commodity price movements. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. Offsets are not perfectly linear or symmetric. The sensitivities are affected by a number of non-market, or indirect market factors. Examples of these factors include hydrology, energy market supply/demand balances, regional fuel supply issues, and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, power plants may reduce dispatch in low market environments limiting downside exposure. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices.

In North America, IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Given that natural gas-fired generators set power prices for many markets, higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during peak periods.

In Chile, we own assets and have associated contracts in both the central and northern regions of the country. Contracts tend to be long-term and indexed to fuel limiting commodity risk. Oil-fired generators set power prices for some markets impacting spot power margins. While Gener has been adding coal-fired generation to its portfolio under long-term power purchase agreements, a small amount of efficient generation is sold into the spot market. Gener also owns natural gas/diesel, hydropower and biomass generation facilities.

In other Latin American markets, the businesses have commodity exposure on un-hedged volumes. In Panama and Colombia, we own hydropower assets, so contracts are not indexed to fuel. In the Dominican Republic, we own natural gas-fired and coal-fired assets, and both contract and spot prices may move with commodity prices. In Argentina, prices are set according to government rules that result in commodity exposure based on the spread between cost of coal-fired generation and oil-fired generation and other factors.

In Europe, our Kilroot facility’s long term PPA was terminated during the fourth quarter of 2010. The commodity risk at our Kilroot business is due to dark spread to the extent sales are un-hedged. Natural gas-fired generators set power prices for many periods, so higher natural gas prices expand margins and higher coal prices cause a decline. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods.

Our Masinloc business in Asia is a coal-fired generation facility, which hedges its output through medium-term contracts that are indexed to fuel prices. Low oil prices may be a driver of margin compression since oil affects spot power sale prices.

Foreign Exchange Rate Risk

In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks 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 the 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: Argentine Peso, Brazilian Real, British Pound, Cameroonian Franc, Chilean Peso, Colombian Peso, Euro, Kazakhstani Tenge, 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.

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During the third quarter of 2011, we entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. As of September 30, 2011, assuming a 10% U.S. Dollar appreciation, pre-tax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Brazilian Real relative to the U.S. Dollar is projected to be approximately $5 million for the remainder of 2011 while exposure to the Argentine Peso, Euro, and Philippine Peso for the remainder of the year is not considered significant. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pre-tax earnings for the remainder of 2011 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 the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges unwound. Additionally, updates to the forecasted pre-tax earnings exposed to foreign exchange risk may result in further modification.

Interest Rate Risks

We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable 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, 2011, the portfolio’s pre-tax earnings exposure for the remainder of 2011 (adjusted to reflect noncontrolling interests) to a 100 basis point increase in Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro, Indian Rupee, Philippine Peso, and U.S. Dollar interest rates would be approximately $5 million. This number is based on the impact of a one-time, 100 basis point increase in interest rates on interest expense for Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro, Indian Rupee, Philippine Peso and U.S. Dollar-denominated debt, which is primarily non-recourse financing. The numbers do not take into account the historical correlation between these interest rates.

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, 2011 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Controls Over Financial Reporting

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

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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 in Note 9 — 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, 2011.

In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the Fifth District Court found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$1.2 billion ($656 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 (“AC”) ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been 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 were dismissed. Eletrobrás later requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo consented to the appointment of such an expert, subject to a reservation of rights. In February 2010, the Fifth District Court appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization, in accordance with the methodology proposed by Eletrobrás. Pursuant to its reservation of rights, Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo’s arguments and directing the Fifth District Court to proceed accordingly. Eletrobrás has restarted the accounting proceedings at the Fifth District Court, which will proceed in accordance with the AC’s April 2010 decision. The parties are briefing the issues. In the Fifth District Court proceedings, the expert’s conclusions will be subject to the Fifth District Court’s review and approval. If Eletropaulo is determined to be responsible for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to 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 and, in turn the Company’s results of operations could 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. The parties are disputing the proper venue for the CTEEP lawsuit. 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 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

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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 seeking 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. 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. (“OPGC”), an equity method investment of the Company, 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. In June 2010, a 2-to-1 majority of the arbitral tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. 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 PPA with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC’s jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court’s decision to the Supreme Court and sought stays of both the High Court’s decision and the underlying OERC proceedings regarding the PPA’s terms. In April 2005, the Supreme Court granted OPGC’s requests and ordered stays of the High Court’s decision and the OERC proceedings with respect to the PPA’s terms. The matter is awaiting further hearing. Unless the Supreme Court finds in favor of OPGC’s appeal or otherwise prevents the OERC’s proceedings regarding the PPA’s terms, the OERC will likely lower the tariff payable to OPGC under the PPA, which would have an adverse impact on OPGC’s financial condition and results of operations. 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 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

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in the Federal Court of São 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. 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. In May 2010, the MPF filed an appeal with the Superior Court of Justice challenging the transfer. The MPF’s lawsuit before the FCSP has been stayed pending a final decision on the interlocutory appeals. AES Elpa and AES Brasiliana (the successor of 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, and the Public Attorney’s office no longer has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a “Technical Cooperation Protocol” pursuant to which they requested a new deadline from FEPAM in order to present a proposal. In March 2008, the State Prosecution office filed a 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 million). The injunction was rejected and the case is in the evidentiary state awaiting the production of the court’s expert opinion. However, in October 2011, the State Prosecution Office presented a new request to the court of Triunfo for an injunction against Florestal, Sul and CEEE for the removal of the alleged sources of contamination and remediation, and the court granted the injunction against CEEE but did not grant injunctive relief against Florestal or Sul. The above-referenced proposal to FEPAM with respect to containing and remediating the contamination was delivered on April 8, 2008. FEPAM responded 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

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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 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 July 2004, the Corporación Dominicana de Empresas Eléctricas Estatales (“CDEEE”) filed lawsuits against Itabo, an affiliate of the Company, in the First and Fifth Chambers of the Civil and Commercial Court of First Instance for the National District. CDEEE alleges in both lawsuits that Itabo spent more than was necessary to rehabilitate two generation units of an Itabo power plant and, in the Fifth Chamber lawsuit, that those funds were paid to affiliates and subsidiaries of AES Gener and Coastal Itabo, Ltd. (“Coastal”), a former shareholder of Itabo, without the required approval of Itabo’s board of administration. In the First Chamber lawsuit, CDEEE seeks an accounting of Itabo’s transactions relating to the rehabilitation. In November 2004, the First Chamber dismissed the case for lack of legal basis. On appeal, in October 2005 the Court of Appeals of Santo Domingo ruled in Itabo’s favor, reasoning that it lacked jurisdiction over the dispute because the parties’ contracts mandated arbitration. The Supreme Court of Justice is considering CDEEE’s appeal of the Court of Appeals’ decision. In the Fifth Chamber lawsuit, which also names Itabo’s former president as a defendant, CDEEE seeks $15 million in damages and the seizure of Itabo’s assets. In October 2005, the Fifth Chamber held that it lacked jurisdiction to adjudicate the dispute given the arbitration provisions in the parties’ contracts. The First Chamber of the Court of Appeal ratified that decision in September 2006. In a related proceeding, in May 2005, Itabo filed a lawsuit in the U.S. District Court for the Southern District of New York seeking to compel CDEEE to arbitrate its claims. The petition was denied in July 2005. Itabo’s appeal of that decision to the U.S. Court of Appeals for the Second Circuit has been stayed since September 2006. Further, in September 2006, in an International Chamber of Commerce arbitration, an arbitral tribunal determined that it lacked jurisdiction to decide arbitration claims concerning these disputes. In September 2011, Itabo and CDEEE dismissed their respective claims in these proceedings.

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 KZT 18 billion ($120 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 (“April 2008 Decision”). The economic court also 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 subsequent appeals to the court of appeals were rejected. In February 2009, the Antimonopoly Agency (the Competition Committee’s successor) seized approximately KZT 778 million ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice’s alleged damages liability. However, on appeal to the Kazakhstan Supreme Court, in October 2009, the Supreme Court annulled the decisions of the lower courts because of procedural irregularities and remanded the case to the

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economic court for reconsideration. On remand, in January 2010, the economic court reaffirmed its April 2008 Decision. Nurenergoservice’s appeals in the court of appeals (first panel) and the court of appeals (second panel) were unsuccessful. Nurenergoservice has appealed to the Kazakhstan Supreme Court. In separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately KZT 1.8 billion ($12 million) in administrative fines for its alleged antimonopoly violations. Nurenergoservice’s appeal to the administrative court was rejected in February 2009. Given the adverse court decisions against Nurenergoservice, the Antimonopoly Agency may attempt to seize Nurenergoservice’s remaining assets, which are immaterial to the Company’s consolidated financial statements. 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 defenses to the claims asserted against it; however, there can be no assurances that it will prevail in these proceedings.

In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”), for the period from January through February 2009. The investigation of both Hydros has now been completed. The Antimonopoly Agency determined that the Hydros abused their market position and charged monopolistically high prices for power from January through February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($3 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of the Hydros. In the course of criminal proceedings, the financial police have expanded the periods at issue to the entirety of 2009 in the case of UK HPP and from January through October 2009 in the case of Shulbinsk HPP, and sought increased damages of KZT 1.2 billion ($8 million) in the case of UK HPP and KZT 1.3 billion ($9 million) in the case of Shulbinsk HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

In April 2009, the Antimonopoly Agency initiated an investigation of Ust-Kamenogorsk TETS LLP’s (“UKT”) power sales from 2008 through February 2009. The Antimonopoly Agency subsequently concluded that UKT abused its market position and charged monopolistically high prices for power and should pay an administrative fine of approximately KZT 136 million ($1 million). The Antimonopoly Agency later sought an order from the administrative court requiring UKT to pay the fine, which was granted by the administrative court in July 2011.

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 have contributed to alleged global warming which, in turn, allegedly has led to the erosion of 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 unspecified damages from the defendants. The Company filed a motion to dismiss the case, which the District Court granted in October 2009. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit. The parties have briefed the appeal. Oral argument will be heard on November 28, 2011. 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 1993, the Public Attorney’s office filed a claim against Eletropaulo, the Sao Paulo State Government, SABESP (a state-owned company), CETESB (the Environmental Agency of Sao Paulo State) and DAEE (the Municipal Water and Electric Energy Department) alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from the Pinheiros River into the Billings Reservoir. The events in question occurred while Eletropaulo was a state-owned company. An initial lower court decision in 2007

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found the parties liable for the payment of approximately R$760 million ($415 million) for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo, which reversed the lower court decision. In 2009, the Public Attorney’s Office filed appeals to both the Superior Court of Justice and the Supreme Court and such appeals were answered by Eletropaulo in the fourth quarter of 2009. 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 1996, a public civil action was 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 repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1 million ($546 thousand) as of June 30, 2011, or pay an indemnification amount of approximately R$11 million ($6 million). Eletropaulo has appealed this decision to the Supreme Court and is awaiting a decision.

In February 2009, a CAA Section 114 information request from the EPA regarding Cayuga and Somerset was received. The request seeks various operating and testing data and other information regarding certain types of projects at the Cayuga and Somerset facilities, generally for the time period from January 1, 2000 through the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. 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 the Company, its results of operations or its financial position.

On February 2, 2009, the Cayuga facility received a Notice of Violation from the New York State Department of Environmental Conservation (“NYSDEC”) 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 NYSDEC and submitted a Landfill Liner Demonstration Report to them. Such report found that the landfill has adequate engineering integrity to support the additional coal ash and there is no inherent environmental threat. NYSDEC has indicated they accept the finding of the report. A permit modification was approved by the NYSDEC on May 14, 2010 and such permit modification allows for closure of this approximately 10-acre portion of the landfill. The construction in accordance with the approved permit modification was completed in November 2010 and the certification report for this construction project was submitted to the NYSDEC in the second quarter of 2011. While at this time it is not possible to predict what impact, if any, this matter may have on the Company, its results of operations or its financial position, based upon the discussions to date, the Company does not believe the impact will be material.

In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Esado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF seeks an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserts that if it is determined that AESU is responsible for the termination of the GSA, AESU is liable for TGM’s alleged losses, including losses under the TA. In April 2011, the arbitrations were consolidated into a single proceeding, and a new procedural schedule was established for the consolidated proceeding. The hearing on liability issues will take place in December 2011. AESU believes it has meritorious claims and defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.

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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. In June 2010, the Inter-American Court of Human Rights vacated the IACHR’s request. With respect to the merits of the underlying petition, the IACHR heard arguments by the communities and Panama in November 2009, but has not issued a decision to date. 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.

In July 2009, AES Energía Cartagena S.R.L. (“AES Cartagena”) received notices from the Spanish national energy regulator, Comisión Nacional de Energía (“CNE”), stating that the proceeds of the sale of electricity from AES Cartagena’s plant should be reduced by roughly the value of the CO₂ allowances that were granted to AES Cartagena for free for the years 2007, 2008, and the first half of 2009. In particular, the notices stated that CNE intended to invoice AES Cartagena to recover that value, which CNE calculated as approximately €20 million ($27 million) for 2007-2008 and an amount to be determined for the first half of 2009. In September 2009, AES Cartagena received invoices for €523,548 (approximately $712,000) for the allowances granted for free for 2007 and €19,907,248 (approximately $27 million) for 2008. In July 2010, AES Cartagena received an invoice for approximately €5 million ($7 million) for the allowances granted for free for the first half of 2009. AES Cartagena does not expect to be charged for CO₂ allowances issued free of charge for subsequent periods. AES Cartagena has paid the amounts invoiced and has filed challenges to the CNE’s demands in the Spanish judicial system. There can be no assurances that the challenges will be successful. AES Cartagena has demanded indemnification from its fuel supply and electricity toller, GDF Suez S.A. (“GDFS”), in relation to the CNE invoices under the long-term energy agreement (the “Energy Agreement”) with GDFS. However, GDFS has disputed that it is responsible for the CNE invoices under the Energy Agreement. Therefore, in September 2009, AES Cartagena initiated arbitration against GDFS, seeking to recover the payments made to CNE. In the arbitration, AES Cartagena also seeks a determination that GDFS is responsible for procuring and bearing the cost of CO₂ allowances that are required to offset the CO₂ emissions of AES Cartagena’s power plant, which is also in dispute between the parties. To date, AES Cartagena has paid approximately €25 million ($34 million) for the CO₂ allowances that have been required to offset 2008, 2009 and 2010 CO₂ emissions. AES Cartagena expects that allowances will need to be purchased to offset emissions for subsequent years. The evidentiary hearing in the arbitration took place from May 31-June 4, 2010, and closing arguments were heard on September 1, 2010. In February 2011, the arbitral tribunal requested further briefing on certain issues in the arbitration, which was later submitted by the parties. The tribunal has the matter under consideration. If AES Cartagena does not prevail in the arbitration and is required to bear the cost of carbon compliance, its results of operations could be materially adversely affected and, in turn, there could be a material adverse effect on the Company and its results of operations. 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. The parties have agreed to settle the dispute subject to the closing of a share sale agreement, which is subject to regulatory and lender approvals. See Note 20 — Subsequent Events for further information. If the transaction does not close, the arbitration will continue, including the risks described above.

In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review (“NSR”) requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material

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impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.

In November 2009, April 2010, December 2010, April 2011, June 2011, and August 2011, substantially similar personal injury lawsuits were filed by a total of 47 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The AES defendants moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. The AES defendants will respond to those amended complaints by October 31, 2011. The AES defendants will also respond to the December 2010, April 2011, June 2011 and August 2011 lawsuits after the relevant plaintiffs file amended complaints. The AES defendants believe they have meritorious defenses to the claims asserted against them and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.

On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns an unfinished 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million ($211 million). The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. The Contractor may attempt to seek relief relating to the bond dispute in the French or English courts. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units because of the alleged characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor’s claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately €240 million ($326 million) in the arbitration, unspecified damages for alleged injury to reputation, and other relief. The arbitral hearing on the merits is in September 2012. Maritza 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.

On February 11, 2011 AES Eletropaulo received a notice of violation from São Paulo State’s Environmental Authorities for allegedly destroying 0.32119 hectares of native vegetation at the Conservation Park of Serra do Mar (“Park”), without previous authorization or license. The notice of violation asserted a fine of approximately R$1 million ($571,542) and the suspension of AES Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities, AES Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the notice of violation or reduce the fine. A decision in this administrative procedure is expected to be issued during the second half of 2011.

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In April 2011, Empresa Distribuidora de Electricidad del Este, S.A. (“EDE Este”), a distribution company of the Government of the Dominican Republic, initiated arbitration proceedings in the Centro de Resolución Alternativa de Controversias de la Cámara de Comercio y Producción de Santo Domingo (“Dominican Arbitral Center”) against AES Andrés, B.V. (“AES Andrés”), seeking a declaration that AES Andrés must deliver an additional 250 MWs under the parties’ long-term power purchase agreement (“PPA”) and damages relating to AES Andrés’ alleged refusal to supply the additional capacity. EDE Este also sought and obtained an ex parte injunction from the Dominican courts requiring AES Andrés to deliver the additional 250 MWs and preventing AES Andrés from providing such additional capacity to any other third party. AES Andrés thereafter initiated arbitration against EDE Este in the ICC seeking, among other things, a declaratory judgment confirming that EDE Este is not entitled to the additional capacity, an order suspending the PPA given EDE Este’s continued failure to pay AES Andrés’ invoices on time for the 50 MWs of capacity contracted under the PPA, and damages resulting from EDE Este’s breach of the PPA. In May 2011, the Dominican Arbitral Center determined that it lacked jurisdiction to decide EDE Este’s arbitration demand. EDE Este thereafter asserted counterclaims against AES Andrés in the ICC arbitration, and sought to add the Company as a party. EDE Este also filed a complaint with the Superintendencia de Electricidad alleging that AES Andrés and its affiliates had engaged in anticompetitive practices. EDE Este voluntarily dismissed the ex parte injunction. In September 2011, the parties settled their dispute, dismissing their respective claims and granting EDE Este the right to purchase certain additional capacity at fixed prices for approximately six years.

Purported stockholders of DPL filed nine putative derivative and/or class actions in Ohio state court and three such suits in Ohio federal court against DPL and its board of directors relating to DPL’s agreement to merge with the Company. Most of those lawsuits name the Company as a defendant. The lawsuits are substantially similar and allege that the price offered in the merger is unfair, DPL’s directors breached their fiduciary duty by agreeing to the merger at an unfair price, and the Company aided and abetted that breach by offering an unfair price. The lawsuits seek to enjoin the merger and some suits also seek unspecified damages. Five of the state lawsuits have been voluntarily dismissed without prejudice. The defendants’ motions to dismiss the remaining four state lawsuits are pending. The three federal lawsuits were consolidated, and the plaintiffs in those suits filed a consolidated amended complaint asserting state and federal disclosure claims and moved to enjoin the merger prior to the vote of DPL’s shareholders on the merger. The defendants filed motions to dismiss the consolidated amended complaint. The federal court established a briefing schedule on those motions and ordered limited discovery on certain disclosure claims. Subsequently, in July 2011, the defendants and the federal plaintiffs executed a memorandum of understanding providing for the settlement of the litigation, subject to certain confirmatory discovery and court approval, pursuant to which DPL would make certain additional disclosures to stockholders in its final proxy statement prior to the shareholder vote on the merger. After execution of the MOU, the federal court suspended briefing on the motions pending before it. DPL made the additional disclosures required under the MOU. The shareholders of DPL later approved the merger in September 2011. The parties to the federal litigation are drafting a stipulation of settlement that, if filed with and ultimately approved by the federal court, would dismiss the federal litigation with prejudice and release all claims by DPL stockholders concerning the merger. The Company believes it has meritorious defenses and will assert them vigorously if the potential settlement is not consummated; however, there can be no assurances that it will be successful in its efforts.

In May 2011, a putative class action was filed in the Mississippi federal court against the Company and numerous unrelated companies. The lawsuit alleges that greenhouse gas emissions contributed to alleged global warming which, in turn, allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert claims for public and private nuisance, trespass, negligence, and declaratory judgment. 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. These and other plaintiffs previously brought a substantially similar lawsuit in the federal court but failed to obtain relief. The Company moved to dismiss the lawsuit in October 2011. The Company believes it has meritorious defenses and will defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.

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In June 2011, the São Paulo Municipal Tax Authority filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking approximately R$1.2 billion ($656 million) in services tax (“ISS”) that allegedly had not been collected on revenues from services rendered by Eletropaulo. Eletropaulo has defended on the ground that the revenues at issue were not subject to ISS. Eletropaulo believes it has meritorious defenses to the assessments and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

ITEM 1A.    RISK FACTORS

Other than the risk factor described below, there have been no material changes to the risk factors as previously disclosed in our 2010 Form 10-K and our Form 10-Q for the period ended March 31, 2011.

Information security breaches could harm our business.

A security breach of our information systems could impact the reliability of our generation fleets and/or the reliability of our transmission and distribution systems. A security breach that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our transmission and distribution assets, access customer information and limit our communications with third parties. Our security measures may not prevent such security breaches. Any loss of confidential or proprietary data through a breach could impair our reputation, expose us to legal claims and materially adversely affect our business and results of operations.

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

In July 2010, the Company’s Board of Directors approved a stock repurchase program (the “Program”) under which the Company can repurchase up to $500 million of AES common stock. The Board authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The Program does not have an expiration date and it can be modified or terminated by the Board of Directors at any time. During the nine months ended September 30, 2011, shares of common stock repurchased under this plan totaled 19,987,795 at a total cost of $224 million plus a nominal amount of commissions (average of $11.24 per share including commissions), bringing the cumulative total purchases under the program to 28,370,620 shares at a total cost of $324 million plus a nominal amount of commissions (average of $11.42 per share including commissions).

The following table presents information regarding purchases made by The AES Corporation of its common stock:

Repurchase Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Repurchased as Part of a Publicly Announced Repurchase Plan		Dollar Value of Maximum Number of Shares To Be Purchased Under the Plan
7/1/11 - 7/30/11		-	$	-		-	$	302,394,766
8/1/11 - 8/30/11		8,816,300	$	10.40		8,816,300	$	210,705,246
9/1/11 - 9/30/11		3,453,784	$	9.91		3,453,784	$	176,478,247
Total		12,270,084	$	10.26		12,270,084

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.    REMOVED AND RESERVED

ITEM 5.    OTHER INFORMATION

None.

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ITEM 6.    EXHIBITS

4.1	Indenture, dated October 3, 2011, between Dolphin Subsidiary II, Inc. and Wells Fargo Bank, National Association is incorporated herein by reference to Exhibit 4.1 of the Company’s Form 8-K filed on October 5, 2011
10.1	Separation Agreement, between Paul T. Hanrahan and The AES Corporation dated September 4, 2011 (filed herewith)
10.2	Mutual Agreement, between Andrés Gluski and The AES Corporation dated October 7, 2011 (filed herewith)
10.3	The AES Corporation Executive Severance Plan, dated October 6, 2011 (filed herewith)
31.1	Rule13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith)
31.2	Rule 13a-14(a)/15d-14(a) Certification of Victoria D. Harker (filed herewith)
32.1	Section 1350 Certification of Andrés Gluski (filed herewith)
32.2	Section 1350 Certification of Victoria D. Harker (filed herewith)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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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 3, 2011		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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EX-10.1

Exhibit 10.1

SEPARATION AGREEMENT

This SEPARATION AGREEMENT (this “Agreement”), dated as of September 4, 2011, is entered into by and between Paul T. Hanrahan (“Employee”) and The AES Corporation (the “Company”).

W I T N E S S E T H

WHEREAS, Employee’s terms and conditions of employment with the Company and its subsidiaries are governed by an employment agreement, dated as of December 29, 2008, between Employee and the Company (the “Employment Agreement”);

WHEREAS, effective as of September 30, 2011 (the “Resignation Date”), Employee will resign from the position of Chief Executive Officer of the Company, resign from all other officer positions that he has with or through the Company and its subsidiaries, and resign from the Board of Directors of the Company and from the boards of directors of any subsidiaries of the Company on which he serves; and

WHEREAS, Employee will terminate his employment with the Company and all of its subsidiaries, effective as of November 30, 2011 (the “Separation Date”):

NOW, THEREFORE, in consideration of the premises, representations, covenants and obligations herein contained, the Company and Employee hereby agree as follows:

1. Resignation/Separation.

(a) Effective as of the Resignation Date, Employee shall no longer serve as the Chief Executive Officer of the Company or otherwise as an officer of the Company, as a member of the Board of Directors of the Company or as an officer or director of any of the Company’s subsidiaries. During the period between the date of this Agreement and the Resignation Date, Employee shall continue to perform his duties as directed by the Board of Directors.

(b) Effective as of the Separation Date, Employee shall resign as an employee of the Company or any of its subsidiaries if his employment was not earlier terminated by the Company or by reason of his death or Disability (within the meaning of the Employment Agreement (“Disability”)) During the period between the Resignation Date and the Separation Date, Employee will not be expected to report to any AES facility but will assist the Company as may be reasonably requested by the Board, the Company’s Chief Executive Officer or the Company’s General Counsel.

(c) Employee shall not hold himself out in any manner inconsistent with the foregoing provisions of this Section 1.

2. Status of Employment Agreement. Except as provided in Section 1 above and Section 3 below, the Employment Agreement shall remain in full force and effect, including without limitation Sections 9,10, 11, 12, 17 and 18 thereof, which are incorporated by reference herein.

3. Separation Payments and Benefits. Provided that (a) Employee does not resign his employment, before the Separation Date, and (b) adheres to the terms of this Agreement including, during the period beginning on the date of his separation from service and ending twenty-one (21) days thereafter, Employee (or his duly authorized representative in the event of his death or Disability) executes and does not revoke the release of claims attached hereto as Exhibit A (the “Release”) and (c) on or before the Separation Date or his earlier death or Disability Employee commits no action that would justify the termination of his employment for Cause within the meaning of Section 7(c)(ii)(B) of the Employment Agreement Employee’s separation from service on the Separation Date or upon his earlier death or Disability shall be treated as a separation from service described in Section 8(e) of the Employment Agreement without any requirement for a Notice of Termination as otherwise provided in the Employment Agreement, and upon such separation from service, Employee shall be entitled to payments and benefits in accordance with Section 8(a) and Section 8(e) of the Employment Agreement, taking into account the provisions of Section 8(i) of the Employment Agreement.

4. Consultation with Attorney/Voluntary Agreement. Employee acknowledges that (a) the Company has advised Employee of his right to consult with an attorney of Employee’s own choosing prior to executing this Agreement, (b) Employee has carefully read and fully understands all of the provisions of this Agreement, and (c) Employee is entering into this Agreement knowingly, freely and voluntarily in exchange for good and valuable consideration, including without limitation the obligations of the Company under this Agreement.

5. Assignment. This Agreement is personal to Employee and may not be assigned by Employee, but any benefit conveyed to Employee pursuant to this Agreement shall inure to the benefit of Employee and Employee’s heirs or beneficiaries. This Agreement is binding on. and will inure to the benefit of, the Company, the Released Parties (within the meaning of the Release) and their respective successors and assigns.

6. Counterparts. This Agreement may be executed simultaneously in counterparts, each of which shall be an original, but all of which shall constitute but one and the same agreement. A faxed signature shall operate the same as an original signature.

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7. Enforceability. In the event that any one or more of the provisions of this Agreement are held to be invalid, illegal or unenforceable, the remainder hereof shall be equitably interpreted to give the fullest effect to the intent of the parties.

8. No Oral Modification; No Waivers. This Agreement may not be changed orally, but may be changed only in a writing signed by a duly authorized representative of the Company and Employee. The failure of the Company or Employee to enforce any of the terms, provisions or covenants of this Agreement will not be construed as a waiver of the same or of the right of the Company or Employee to enforce the same. Waiver by the Company or Employee of any breach or default by another party to this Agreement of any term or provision of this Agreement will not operate as a waiver of any other breach or default.

9. Entire Agreement and Third-Party Beneficiaries. This Agreement together with the Employment Agreement sets forth the entire understanding between the Company and Employee, and supersedes all prior agreements, representations, discussions, negotiations and understandings, concerning the subject matter addressed herein. The Company and Employee represent that, in executing this Agreement, each party has not relied upon any representation or statement made by the other party, other than those set forth herein and in the Employment Agreement, with regard to the subject matter, basis or effect of this Agreement. Each subsidiary of the Company is an intended third-party beneficiary of this Agreement.

10. Governing Law. The validity, interpretation, construction and performance of this Agreement shall be governed by the laws of the State of Virginia without regard to its conflicts of law principles.

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IN WITNESS WHEREOF, the Company and Employee have executed this Agreement as of the date first set forth above.

EMPLOYEE

THE AES CORPORATION

By:

Name:	Brian A. Miller
Title
Dated:	September 4, 2011:

4

Exhibit A

FORM OF RELEASE

RELEASE OF CLAIMS

In exchange for the payments and benefits to be provided pursuant to Section 3 of the Separation Agreement between Paul T. Hanrahan (“you) and The AES Corporation (the “Company”), dated as of September 4, 2011 (the “Separation Agreement”), you hereby agree as follows:

1. You hereby release the Company and all of its past, present and/or future related entities, including but not limited to parents, divisions, affiliates, subsidiaries, officers, directors, stockholders, trustees, employees, agents, representatives, administrators, attorneys, insurers, fiduciaries, predecessors, successors and assigns of the Company, in their individual and/or representative capacities (hereinafter collectively referred to as the “Released Parties”) from any and all causes of action, suits, agreements, promises, damages, disputes, controversies, contentions, differences, judgments, claims and demands of any kind whatsoever (“Claims”) which you or your heirs, executors, administrators, successors and assigns ever had, now have or may have against the Released Parties, whether known or unknown to you, and whether asserted or unasserted, by reason of your employment and/or cessation of employment with the Company, that involve facts which occurred on or prior to the date that you sign this Release of Claims. Such released Claims include, without limitation, any and all Claims under the Age Discrimination in Employment Act of 1967, as amended by the Older Workers’ Benefit Protection Act of 1990, Title VII of the Civil Rights Act of 1964, the Civil Rights Act of 1871, the Civil Rights Act of 1991, the Fair Labor Standards Act, the Family and Medical Leave Act of 1993, the Americans With Disabilities Act, the Employee Retirement Income Security Act of 1974 (including, without limitation, any claim for severance pay), the Virginia Human Rights Law and any and all other federal, state or local laws, statutes, rules and regulations pertaining to employment (each as amended) including but not limited to the laws of the United States and any other country to the extent applicable; any and all Claims under state contract or tort law; any and all Claims based on the design or administration of any Company employee benefit plan (other than claims for welfare benefit payments with respect to events occurring or expenses incurred prior to the date you execute this Release of Claims) or program or arising under any Company policy, procedure, or employee benefit plan, including, but not limited to, the Employment Agreement between you and the Company dated December 29, 2008 (your “Employment Agreement”); any and all Claims for wages, commissions, bonuses, continued employment with the Company in any position, and compensatory, punitive or liquidated damages; and any and all Claims for attorneys’ fees and costs. Notwithstanding the foregoing, nothing contained herein shall interfere with or waive: (i) your right to enforce the Separation Agreement; (ii) your

right to any amounts or any benefits (including, without limitation, payments pursuant to the indemnification rights provided for under Section 5(g) of your Employment Agreement, that either are intended to survive your termination of employment or that arise or are payable after the date that you execute this Release of Claims (together with any claims for welfare benefit payments with respect to events occurring or expenses incurred prior to the date you execute this Release of Claims your “Preserved Rights”)); or (iii) any rights that cannot be waived under applicable law.

2. Except for the payments and benefits set forth in Section 3 of the Separation Agreement and your Preserved Rights, you (a) are not entitled to any other payments or benefits from the Company or any of the other Released Parties, and (b) will not seek or be entitled to obtain any personal recovery in any action against the Company.

3. You have had twenty-one (21) days to execute this Release of Claims from the date you first received it. You then have seven (7) days following its execution to revoke your consent to it.

4. You (a) have been advised by the Company of your right to consult with an attorney of your own choosing prior to executing this Release of Claims, (b) have carefully read and fully understands all of the provisions of this Release of Claims, and (c) are entering into this Release of Claims knowingly, freely and voluntarily in exchange for good and valuable consideration, including without limitation the obligations of the Company under the Separation Agreement.

5. The validity, interpretation, construction and performance of this Release of Claims shall be governed by the laws of the State of Virginia without regard to its conflicts of law principles.

Paul T. Hanrahan

DATE:

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EX-10.2

Exhibit 10.2

MUTUAL AGREEMENT

AGREEMENT made as of this 7th day of October, 2011 (the “Effective Date”), by and between The AES Corporation, a Delaware corporation (the “Company”), and Andres Gluski (the “Executive”).

WHEREAS, the Company and the Executive entered into an Employment Agreement dated as of December 29, 2008; and

WHEREAS, the Company and the Executive now mutually agree and deem it desirable to terminate the Employment Agreement without further obligations under the Employment Agreement on the part of either the Company or the Executive.

NOW THEREFORE, the Company and the Executive, in consideration of their respective covenants and agreements herein contained and intending to be legally bound thereby, agree as follows:

1. As of the Effective Date, the Employment Agreement shall be void and without effect, notwithstanding any contrary terms, conditions, or requirements set out within the Employment Agreement. Accordingly, the Company and the Executive mutually discharge each other from any additional or future obligations under the terms of the Employment Agreement.

2. This Agreement sets forth the entire agreement of the Company and the Executive in respect of the subject matter contained herein and supersedes all prior agreements, promises, covenants, arrangements, communications, representations or warranties, whether oral or written, by any officer, employee or representative of either party hereto; and any prior agreement of the Company and the Executive, in respect of the subject matter contained herein, is hereby terminated and cancelled.

IN WITNESS WHEREOF, the parties have executed this Agreement as of the Effective Date.

EXECUTIVE	THE AES CORPORATION
	By:
Andres Gluski		Name: Rita Trehan
		Title: Vice President, Human Resources & Internal Communications

EX-10.3

Exhibit 10.3

THE AES CORPORATION

EXECUTIVE SEVERANCE PLAN

(Effective October 6, 2011)

ARTICLE I

GENERAL PROVISIONS

1.1 Establishment and Purpose.

The purpose of the AES Corporation Executive Severance Plan, as amended (the “Plan”), is to provide eligible executives of AES Corporation (the “Company”) who (i) are designated to participate in the Plan by the Board and/or Administrator, (ii) agree to the Plan terms, and (iii) are involuntarily terminated from employment in certain limited circumstances, with severance and welfare benefits as set forth in this Plan. Benefits payable under this Plan are generally intended for Eligible Employees who are involuntarily terminated without Cause.

The Plan is not intended to be an “employee pension benefit plan” or “pension plan” within the meaning of Section 3(2) of ERISA. Rather, this Plan is intended to be a “welfare benefit plan” within the meaning of Section 3(1) of ERISA and to meet the descriptive requirements of a plan constituting a “severance pay plan” within the meaning of regulations published by the Secretary of Labor at Title 29, Code of Federal Regulations, Section 2510.3-2(b). Accordingly, the benefits paid by the Plan are not deferred compensation and no employee shall have a vested right to such benefits.

1.2 Term.

The Plan shall generally be effective on the Effective Date. This Plan supersedes any prior severance plans, policies, guidelines, arrangements, agreements, letters and/or other communication, whether formal or informal, written or oral sponsored by the Employer and/or entered into by any representative of the Employer. This Plan represents exclusive severance benefits provided to Eligible Employees and such individuals shall not be eligible for other benefits provided in other severance plans, policies, programs, guidelines, arrangements, letters, etc. of the Company.

1.3 Definitions.

Except as may otherwise be specified or as the context may otherwise require, for purposes of the Plan, the following terms shall have the respective meanings ascribed thereto, or as set forth on a Benefit Schedule to the Plan.

“Administrator” means the Compensation Committee of the Board or such other committee or persons designated by the Board and/or Compensation Committee to assume duties of the Administrator.

“Affiliated Employer” means any corporation which is a member of a controlled group of corporations (as defined in Section 414(b) of the Code) which includes the Company; any trade or business (whether or not incorporated) which is under common control (as defined in Section 414(c) of the Code) with the Company; any organization (whether or not incorporated) which is a member of an affiliated service group (as defined in Section 414(m) of the Code) which includes the Company; and any other entity required to be aggregated with the Company pursuant to regulations under Section 414(o) of the Code.

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“Annual Compensation” means an Eligible Employee’s annualized base salary as in effect as of the Eligible Employee’s Termination Date. Unless otherwise provided on a Benefit Schedule, Annual Compensation shall: (i) include: pre-tax employee contributions under any qualified defined contribution retirement plan, salary deferrals under any unfunded nonqualified deferred compensation plan, and amounts deferred (to include employee premiums) under a flexible spending account established pursuant to Section 125 of the Code; and (ii) exclude: any amounts contributed by the Employer to any plan established pursuant to Section 125 of the Code, bonuses, annual incentive payments, long-term incentive awards (including, but not limited to, stock options, restricted stock and performance unit awards), and any other form of supplemental compensation.

“Benefit Schedule” means any schedule attached to the Plan which sets forth the benefits of specified groups of Eligible Employees, as approved by the Company and updated by the Administrator from time to time.

“Board” means the Board of Directors of the Company.

“Bonus” means an Eligible Employee’s annual target bonus compensation as established by the Employer and in effect on the Eligible Employee’s Termination Date.

“Cause” means, except as otherwise provided in a Benefit Schedule, Separation From Service by action of the Employer, or resignation in lieu of such Separation From Service, on account of the Eligible Employee’s dishonesty; insubordination; continued and repeated failure to perform the Eligible Employee’s assigned duties or willful misconduct in the performance of such duties; intentionally engaging in unsatisfactory job performance; failing to make a good faith effort to bring unsatisfactory job performance to an acceptable level; violation of the Employer’s policies, procedures, work rules or recognized standards of behavior; misconduct related to the Eligible Employee’s employment; or a charge, indictment or conviction of, or a plea of guilty or nolo contendere to, a felony, whether or not in connection with the performance by the Eligible Employee of his or her duties or obligations to the Employer.

“Change in Control” means the occurrence of one or more of the following events: (i) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of the assets of the Company to any Person or group (as that term is used in Section 13(d)(3) of the Securities Exchange Act of 1934) of Persons, (ii) a Person or “group” (as defined under Section 13(d)(3) of the Securities Exchange Act of 1934) of Persons (other than management of the Company on the date of the adoption of this Plan or their Affiliates) shall have become the beneficial owner of more than 35% of the outstanding voting stock of the Company, or (iii) during any one-year period, individuals who at the beginning of such period constitute the Board (together with any new director whose election or nomination was approved by a majority of the directors then in office who were either directors at the beginning of such period or who were previously so approved, but excluding under all circumstances any such new director whose initial assumption of office occurs as a result of an actual or threatened election contest or other actual or threatened solicitation of proxies or consents by or on behalf of any individual, corporation, partnership or other entity or group) cease to constitute a majority of the Board. For purposes of this definition, “Affiliate” means: (i) any Subsidiary of the Company; (ii) any entity or Person or group of Persons that, directly or

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through one or more intermediaries, is controlled by the Company; and (iii) any entity or Person or group of Persons in which the Company has a significant equity interest, as determined by the Company.

“Chief Executive Officer” means an Eligible Employee or Participant, as the context requires, who is the Chief Executive Officer of the Company.

“COBRA Coverage” means medical, dental and vision coverage which is required to be offered to terminated employees under Section 4980B of the Code and Section 606 of ERISA; provided, however, that no provision of this Plan shall be construed to require the Employer to contribute on behalf of an Eligible Employee towards continuation coverage for a health spending account.

“Code” means the Internal Revenue Code of 1986, as amended.

“Company” or “AES” means The AES Corporation, a Delaware corporation, or any successor thereto.

“Compensation Committee” means the Compensation Committee of the Board.

“Disability” or “Disability Termination” means, except as otherwise provided in a Benefit Schedule, a Separation From Service: (a) on account of the Eligible Employee’s failure to return to full-time employment following exhaustion of short-term disability benefits provided by the Employer; (b) following the date the Eligible Employee is determined to be eligible for: (i) long-term disability benefits under any long-term disability insurance policy or plan maintained by the Employer; or (ii) disability pension or retirement benefits under any qualified retirement plan maintained by the Employer; or (c) due to a physical or mental condition that substantially restricts the Eligible Employee’s ability to perform his or her usual duties, as determined by the Employer.

“Effective Date” means October 6, 2011.

“Eligible Employee” means any Employee of the Employer who: (i) is not an Ineligible Employee (within the meaning of Section 2.2); (ii) has completed one Year-of-Service as a full-time Employee (except as otherwise approved by the Administrator or the Board); (iii) has been designated by the Board as a participant in the Plan; and (iv) has executed the document set forth on Exhibit A, thereby understanding and agreeing to be bound by all of the terms and conditions set forth in the Plan and Benefit Schedule. “Eligible Employee” shall include Executive Officers and the Chief Executive Officer.

“Employee” means any person who is employed by the Company or a Subsidiary as a common law employee and is listed as an employee on the U.S. payroll records of the Employer as a full-time employee. Any person hired by the Employer as a consultant or independent contractor and any other individual whom the Employer does not treat as its employee for federal income tax purposes shall not be an Employee for purposes of this Plan, even if it is subsequently determined by a court or administrative agency that such individual should be, or should have been, properly classified as a common law employee of the Employer.

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“Employer” means the Company and any Affiliated Employer that participates in the Plan with the consent of the Company. The Administrator shall maintain a list of participating Employers.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

“Executive” or “Executive Officer” means an Eligible Employee or Participant, as the context requires (other than the Chief Executive Officer), who is an executive officer of the Company as defined under Rule 3b-7 of the Securities Exchange Act of 1934, as amended, or was otherwise approved as an officer by the Board and/or Compensation Committee.

“Good Reason” or “Good Reason Termination” has the meaning set forth in any applicable Benefit Schedule.

“Ineligible Termination” means, except as otherwise provided in a Benefit Schedule, an Eligible Employee’s Separation From Service on account of:

• The Eligible Employee’s voluntary resignation, including but not limited to the Eligible Employee’s unilateral Separation From Service at any time prior to the Termination Date established by the Employer;

• Any Separation From Service that the Employer determines (either before or after the Separation From Service and whether or not any notice is given to the employee) the payment of benefits under the Plan in connection with such Separation From Service would be inconsistent with the intent and purposes of the Plan;

• A Separation From Service in connection with an Eligible Employee’s failure to return to work immediately following the conclusion of an approved leave-of-absence.

• A Separation From Service for, or on account of, Cause;

• A Disability Termination;

• The Eligible Employee’s death;

• The Eligible Employee declines to accept a New Job Position offered by the Employer that is located within 50 miles of the Eligible Employee’s then assigned work site of the Employer;

• The Sale of Business Rule set forth in Section 2.3 herein; or

• The voluntary transfer of employment from Eligible Employee’s Employer to another AES related entity, irrespective of whether the Eligible Employee is required to relocate or whether the AES related entity qualifies as an Affiliated Employer.

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“Involuntary Termination” means an Executive’s involuntary Separation From Service that is (i) not an Ineligible Termination and (ii) by action of the Employer on account of:

• Reduction-in-force that eliminates the Executive’s existing job position;

• Permanent job elimination of the Executive;

• The restructuring or reorganization of a business unit, division, department or other segment, which directly affects the Executive;

• Termination by Mutual Consent; or

• Executive declines to accept a New Job Position offered by the Employer that requires the Executive to relocate to a work site location that is located greater than 50 miles from the Executive’s then assigned work site of the Employer; provided, however, that except as provided in Section 2.3 or in connection with a Separation From Service following a Change in Control, an Executive who functions at or above a Group Manager position (or its equivalent) shall not incur an Involuntary Termination if such Executive declines a New Job Position (regardless of its location) at a time when the Executive’s existing job position is being eliminated.

“New Job Position” means: (i) with respect to an Eligible Employee who has demonstrated inadequate or unsatisfactory performance, as determined by the Employer, any job position offered by the Employer; or (ii) with respect to all other Eligible Employees, a full-time job position offered by the Employer that does not result in a reduction of the Employee’s Annual Compensation.

“Participant” has the meaning set forth in Section 2.1.

“Person” means any individual, corporation, joint venture, association, joint stock company, trust, unincorporated organization or government or any agency or political subdivision thereof.

“Plan” means The AES Corporation Executive Severance Plan as set forth herein, and as the same may from time to time be amended.

“Section 409A” shall mean Section 409A of the Code, the regulations and other binding guidance promulgated thereunder.

“Separation From Service” shall mean an Eligible Employee’s termination of employment with the Company and all of its controlled group members within the meaning of Section 409A of the Code. For purposes hereof, the determination of controlled group members shall be made pursuant to the provisions of Section 414(b) and 414(c) of the Code; provided that the language “at least 50 percent” shall be used instead of “at least 80 percent” in each place it appears in Section 1563(a)(1), (2) and (3) of the Code and Treas. Reg. § 1.414(c)-2; provided, further, where legitimate business reasons exist (within the meaning of Treas. Reg. § 1.409A-1(h)(3)), the language “at least 20 percent” shall be used instead of “at least 80 percent” in each

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place it appears. Whether an Employee has a Separation From Service will be determined based on all of the facts and circumstances and in accordance with the guidance issued under Section 409A.

“Specified Employee” means a key employee (as defined in Section 416(i) of the Code without regard to paragraph (5) thereof) of the Company as determined in accordance with the regulations issued under Code Section 409A and the procedures established by the Company.

“Subsidiary” means any entity in which the Company owns or otherwise controls, directly or indirectly, stock or other ownership interests having the voting power to elect a majority of the board of directors, or other governing group having functions similar to a board of directors, as determined by the Company.

“Termination by Mutual Consent” means an involuntary Separation From Service pursuant to which the Company agrees, in its sole discretion, that benefits are payable under this Plan.

“Termination Date” means the date of the Eligible Employee’s Separation From Service (or scheduled date of Separation From Service, as applicable).

“Year-of-Service” means each twelve-month period measured from the Eligible Employee’s first day of employment with an Employer, as reduced to reflect breaks in service and/or services performed during such period the Eligible Employee was otherwise ineligible to participate in the Plan, as determined under the rules promulgated by the Administrator. Service with a predecessor employer (that was not an Affiliated Employer) shall be recognized to the extent such service is recognized under The AES Corporation Retirement Savings Plan. Service shall also include services performed prior to the effective date of the Plan. In the event an Eligible Employee’s Separation From Service and the Eligible Employee is subsequently reemployed by the Employer, the Eligible Employee’s service for calculation of any severance benefits under Article IV of the Plan shall be based only upon the Eligible Employee’s service credited since the most recent date of employment with the Employer.

ARTICLE II

PARTICIPATION

2.1 Eligibility.

An Eligible Employee shall, upon execution of the release in the form specified in Article III of this Plan in the time and manner set forth in Section 3.1 of the Plan, be eligible for the severance benefits provided under Article IV of this Plan if the Eligible Employee’s Separation From Service is by reason of an Involuntary Termination or Good Reason Termination, as applicable. An Eligible Employee who fails to execute the release in the time and manner set forth in Section 3.1 or who subsequently revokes execution of the release in accordance with its terms shall not be entitled to receive benefits under this Plan. An Eligible Employee who satisfies all of the terms and conditions specified in this Plan and who becomes entitled to receive benefits hereunder shall be referred to herein as a “Participant.”

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2.2 Ineligible Employees. Notwithstanding any provision of this Plan to the contrary, no Employees shall be eligible to participate in the Plan unless so designated by the Board and/or the Administrator.

2.3 Sale of Business Rule.

An Eligible Employee shall not be eligible for benefits under the Plan if the Eligible Employee’s Separation From Service is in connection with the sale of the stock or other ownership interests of the Employer or other related entity, or the sale, lease, or other transfer of the assets, products, services or operations of the Employer or other related entity to another organization if either of the following occurs:

• The Eligible Employee is employed by the new organization immediately following the sale, transfer or lease or is so employed within a time period specified in an agreement between the Employer and the new organizations; or

• The Employer terminates the employment of an Eligible Employee who did not accept an offer of employment from the new organization when the new organization offered a compensation and benefits package that was, in the aggregate, generally comparable to the compensation and benefits provided by the Employer; provided that such Eligible Employee was not required to relocate to a work site location that is located greater than 50 miles from the Employee’s then assigned work site of the Employer.

Notwithstanding the foregoing, this Section 2.3 shall not apply if an Eligible Employee’s Separation From Service occurs in connection with a Change of Control and, as such, any such Separation From Service will not be an Ineligible Termination solely on the basis of the Sale of Business Rule.

ARTICLE III

RELEASES

3.1 Release.

Notwithstanding anything in this Plan to the contrary, no benefits of any sort or nature (other than as provided in Section 3.3) shall be due or paid under this Plan to any Eligible Employee unless the Eligible Employee executes a written release and covenant not to sue, in form and substance satisfactory to the Employer, in its sole discretion, within the time stated in the release; provided, however, that in all cases such release must become final, binding and irrevocable within sixty (60) days following the Eligible Employee’s Termination Date. The written release shall waive any and all claims against the Employer and all related parties including, but not limited to, claims arising out of the Eligible Employee’s employment by the Employer, the Eligible Employee’s Separation From Service and claims relating to the benefits paid under this Plan. At the sole discretion of the Employer, the release shall also include such noncompetition, nonsolicitation and nondisclosure provisions as the Employer considers necessary or appropriate.

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3.2 Revocation.

The release described in Section 3.1 must be executed and binding on the Eligible Employee within the timeframe specified by the Company before benefits are due or paid. An Eligible Employee who revokes execution of the release in accordance with the terms of the release shall not be entitled to receive benefits under the Plan.

3.3 Outplacement Services.

Notwithstanding the foregoing provisions of this Article III, the Outplacement Services set forth under Section 4.3 herein may or may not be provided, at the discretion of the Employer, to an Eligible Employee prior to the execution of a release under this Plan.

ARTICLE IV

SEVERANCE BENEFITS

4.1 Separation Payment.

4.1.1 A Participant shall be entitled to receive a separation payment as set forth on the applicable Benefit Schedule. Except as otherwise provided in a Benefit Schedule, the separation payment shall be paid at least monthly in substantially equal installments as salary continuation in accordance with the Employer’s established payroll policies and practices over the same time period upon which the separation payment is based, which shall be set forth in the Benefit Schedule. The separation payments will commence on the Employer’s next normal pay date occurring after the date the Eligible Employee’s release becomes final, binding and irrevocable.

4.1.2 For purposes of Section 409A: (i) the right to salary continuation installment payments under Section 4.1.1 shall be treated as the right to a series of separate payments; and (ii) a payment shall be treated as made on the scheduled payment date if such payment is made at such date or a later date in the same calendar year or, if later, by the 15th day of the third calendar month following the scheduled payment date. A Participant shall have no right to designate the date of any payment under the Plan. For purposes of the Plan, each salary continuation installment payment in Section 4.1.1 is intended to be excepted from Section 409A to the maximum extent provided under Section 409A as follows: (i) each salary continuation installment payment that is scheduled to be made on or before March 15th of the calendar year following the calendar year containing the Termination Date is intended to be excepted under the short-term deferral exception as specified in Treas. Reg. § 1.409A- 1(b)(4); and (ii) each salary continuation installment payment that is not otherwise excepted under the short-term deferral exception is intended to be excepted under the involuntary pay exception as specified in Treas. Reg. § 1.409A-1(b)(9)(iii).

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4.2 Continuation of Certain Welfare Benefits.

4.2.1 Medical/Dental/Vision. For the period set forth below in Section 4.2.3 and beginning in the calendar month following the calendar month in which the Termination Date occurs, the Participant shall be eligible to participate in the Employer’s medical, dental and vision employee welfare benefit plans applicable to the Participant on his Termination Date. To receive such benefits, the Participant must properly enroll in COBRA coverage, and must also pay such premiums and other costs for such coverage as generally applicable to the Employer’s active employees. The Employer will continue to pay its share of the applicable premiums under the medical, dental and vision plans for the same level and type of coverage in which the Participant is enrolled as of the Termination Date.

Except as provided in a Benefit Schedule to the Plan, if a Participant has elected the “no benefit coverage” option under the medical, dental or vision plans as of his actual Termination Date, the Participant shall not be entitled to continuation coverage or cash in lieu thereof. Following expiration of coverage under this Section 4.2.1, a Participant may, to the extent eligible, continue to participate in such plans for the remainder of the COBRA continuation period, if any.

4.2.2 Concurrent COBRA Period. The continuation period for medical, dental and vision coverage under this Plan shall be deemed to run concurrent with the continuation period federally mandated by COBRA (generally 18 months), or any other legally mandated and applicable federal, state, or local coverage period for benefits provided to terminated employees under the health care plan. The continuation period will be deemed to commence on the first day of the calendar month following the month in which the Termination Date falls. Notwithstanding the foregoing, COBRA Coverage will only be available if the Participant is eligible for and timely elects COBRA Coverage, and timely remits payment of the premiums for COBRA Coverage.

4.2.3 Length of Benefits. Except as provided in a Benefit Schedule, benefits under this Section 4.2 shall be for the same time period upon which the separation payment was based; provided, however that in no event will the time period exceed 18 months.

4.2.4 Implications of Section 409A. Post-termination medical benefits are intended to be excepted from Section 409A under the medical benefits exceptions as specified in Treas. Reg. § 1.409A-l(b)(9)(v)(B).

4.3 Outplacement Services.

As set forth on the applicable Benefit Schedule, a Participant shall be eligible for such outplacement services typically provided to employees of the same job classification or level. Outplacement services may be provided by an independent agency or by the Employer. Notwithstanding the foregoing, the availability, duration, and appropriateness of outplacement services shall be determined by the Administrator in its sole discretion; provided, however, that outplacement expenses must be reasonable, must be actually incurred by the Participant and may not extend beyond the December 31 of the second calendar year following the calendar year in which the Termination Date occurred (or such shorter period as specified by the Employer). Any

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such reimbursement shall be as soon as administratively feasible, but in no event later than December 31st of the third calendar year following the calendar year in which the Termination Date occurred. Post-termination outplacement benefits are intended to be excepted from Section 409A under the separation payment benefits exceptions as specified in Treas. Reg. § 1.409A-l(b)(9)(v)(A).

4.4 Bonus Compensation.

As set forth on the applicable Benefit Schedule and subject to any deferral election that the Participant has made with respect to such amounts, a Participant will be eligible for (i) a prorated Bonus; and (ii) any accrued but unpaid bonus compensation for completed performance periods. The prorated Bonus specified in Section 4.4(i) will be prorated based on the amount of time the Participant was actively at work on a full-time basis in the calendar year in which the Participant’s Termination Date falls, and will be paid within the applicable 2 ¹/2 month period specified in Treas. Reg. § 1.409A- 1(b)(4). The bonus compensation specified in Section 4.4(ii) shall be paid no later than the time that such amounts are paid to similarly situated employees in accordance with the applicable plan terms. Notwithstanding the foregoing, with respect to bonuses paid in accordance with the terms of The AES Corporation Performance Incentive Plan (or any successor plan, the “Performance Incentive Plan”), any such bonus compensation shall be paid only to the extent earned in accordance with the terms of the Performance Incentive Plan and on the payment date specified therein.

4.5 Enhanced Benefits.

In the event a Participant is Involuntarily Terminated or terminates for Good Reason within two years following a Change in Control, a Participant shall receive a separation payment under Section 4.1 and medical/dental/vision benefits under Section 4.2 as set forth in a Benefit Schedule. Notwithstanding the foregoing, unless otherwise specifically provided in the Benefit Schedule, the time period for medical/dental/vision benefits set forth in Section 4.2 will never exceed eighteen (18) months, as described in Section 4.2.3.

4.6 Delay in Payment.

Notwithstanding any provision of this Plan to the contrary, to the extent that a payment hereunder is subject to Section 409A (and not excepted therefrom), such payment shall be delayed for a period of six months after the Termination Date (or, if earlier, the death of the Participant) for any Participant that is a Specified Employee. Any payment that would otherwise have been due or owing during such six-month period will be paid on the first business day of the seventh month following the Separation From Service.

ARTICLE V

CONFIDENTIALITY, COVENANT NOT TO COMPETE, NON-SOLICITATION AND NON-DISPARAGEMENT PROVISIONS

5.1 General Provisions.

As a condition of participation in the Plan, the Eligible Employee agrees that restrictions on his or her activities during and after employment are necessary to protect the

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goodwill, Confidential Information (as defined below) and other legitimate interests of the Company and its Subsidiaries, and that the agreed restrictions set forth below will not deprive the Eligible Employee of the ability to earn a livelihood.

5.2 Confidential Information.

The Eligible Employee acknowledges that the Company and its Subsidiaries continually develop Confidential Information (as defined in Section 5.5(d), below), that the Eligible Employee may develop Confidential Information for the Company or its Subsidiaries and that the Eligible Employee may learn of Confidential Information during the course of his or her employment. The Eligible Employee will comply with the policies and procedures of the Company and its Subsidiaries for protecting Confidential Information and shall not disclose to any person (except as required by applicable law or legal process or for the proper performance of his or her duties and responsibilities to the Company and its Subsidiaries, or in connection with any litigation between the Company and the Eligible Employee (provided that the Company shall be afforded a reasonable opportunity in each case to obtain a protective order)), or use for his or her own benefit or gain, any Confidential Information obtained by the Eligible Employee incident to his or her employment or other association with the Company or any of its Subsidiaries. The Eligible Employee understands that this restriction shall continue to apply after his or her employment terminates, regardless of the reason for such termination. All documents, records, tapes and other media of every kind and description relating to the business, present or otherwise, of the Company or its Subsidiaries and any copies, in whole or in part, thereof (the “Documents”), whether or not prepared by the Eligible Employee, shall be the sole and exclusive property of the Company and its Subsidiaries. The Eligible Employee shall safeguard all Documents and shall surrender to the Company at the time employment terminates, or at such earlier time or times as the Board or its designee may specify, all Documents then in the Eligible Employee’s possession or control.

5.3 Noncompete/Nonsolicit Provisions.

Except in the event of a Change in Control, while the Eligible Employee is in the employment of the Company and for a period of twelve months, or such other period specified in the Benefit Schedule for the Eligible Employee, after a termination of Eligible Employee’s employment with the Company (the “Non-Competition Period”), the Eligible Employee shall not, directly or indirectly, whether as owner, partner, investor, consultant, agent, employee, co venturer or otherwise, engage in Competitive Activity (as defined below). For purposes of this Plan, “Competitive Activity” means any activity that is (i) directly or indirectly competitive with the business of the Company or any of its Subsidiaries, as conducted or which has been proposed by management to be conducted within six (6) months prior to termination of the Eligible Employee’s employment and (ii) conducted in the geographic areas in which the Company or any of its Subsidiaries operate upon the Eligible Employee’s Separation From Service date. Competitive Activity also includes, without limitation, accepting employment or a consulting position with any person who is, or at any time within twelve (12) months prior to termination of the Eligible Employee’s employment has been, a licensee of the Company or any of its Subsidiaries. For the purposes of this Article, the business of the Company and its Subsidiaries, as currently conducted, consists of the generation, sale, supply or distribution of electricity.

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The Eligible Employee agrees that during the Non-Competition Period, the Eligible Employee will not, either directly or through any agent or employee, Solicit (as defined in Section 5.5(d), below) any employee of the Company or any of its Subsidiaries to terminate his or her relationship with the Company or any of its Subsidiaries or to apply for or accept employment with any enterprise engaged in Competitive Activity with the Company, or Solicit any customer, supplier, licensee or vendor of the Company or any of its Subsidiaries to terminate or materially modify its relationship with them, or, in the case of a customer, to conduct with any Person any business or activity which such customer conducts or could conduct with the Company or any of its Subsidiaries.

5.4 Nondisparagement.

Following any termination of the Eligible Employee’s employment, (i) the Eligible Employee shall not make statements or representations, otherwise communicate, directly or indirectly, in writing, orally, or otherwise, or take any action which may, directly or indirectly, disparage or be damaging to the Company or any if its Subsidiaries or affiliates or their respective former or current officers, directors, employees, advisors, businesses or reputations, (ii) the Company shall instruct its Board members and senior management to not make statements or representations, otherwise communicate, directly or indirectly, in writing, orally or otherwise, or take any action which may, directly or indirectly, disparage or be damaging to the Eligible Employee or his reputation. Nothing in this paragraph is intended to undermine any obligations the Eligible Employee or the Company may have to comply with applicable law, or prohibit the Eligible Employee or the Company from providing truthful testimony or information pursuant to subpoena, court order, discovery demand or similar legal process, or truthfully responding to lawful inquiries by any governmental or regulatory entity.

5.5 Miscellaneous.

(a) Nothing in this Article V shall prevent the Eligible Employee, during the Non-Competition Period and following Separation From Service, from acquiring or holding, solely as an investment, publicly traded securities of any competitor corporation so long as such securities do not, in the aggregate, constitute more than 3% of the outstanding voting securities of such corporation.

(b) The Eligible Employee agrees that all inventions, improvements, discoveries, patents, trade concepts and copyrightable materials made, conceived or developed by Eligible Employee, in respect of the business of the Company, either singly or in collaboration with others, shall be the sole and exclusive property of the Company.

(c) Without limiting the foregoing, it is understood that the Company shall not be obligated to make any of the payments or to provide for any of the benefits specified in Article IV or on a Benefit Schedule hereof in connection with the termination of an Eligible Employee’s employment, and shall be entitled to recoup the pro rata portion of any such payments and of the value of any such benefits previously provided to the Eligible Employee in the event of a material breach by the Eligible Employee of the provisions of this Article (such pro ration to be determined as a fraction, the numerator of which is the number of days from such breach to the first anniversary of the date on which the Eligible Employee terminates

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employment and the denominator of which is 365), which breach continues without having been cured within fifteen (15) days after written notice to the Eligible Employee specifying the breach in reasonable detail.

(d) Definitions. For purposes of this Article, the following definitions shall apply:

(i) “Confidential Information” means any and all information of the Company and its Subsidiaries that is not generally known by others with whom they compete or do business, or with whom they plan to compete or do business and any and all information not readily available to the public, which, if disclosed by the Company or its Subsidiaries could reasonably be of benefit to such person or business in competing with or doing business with the Company. Confidential Information includes, without limitation, such information relating to (A) the development, research, testing, manufacturing, store operational processes, marketing and financial activities, including costs, profits and sales, of the Company and its Subsidiaries, (B) the costs, sources of supply, financial performance and strategic plans of the Company and its Subsidiaries, (C) the identity and special needs of the customers and suppliers of the Company and its Subsidiaries and (D) the people and organizations with whom the Company and its Subsidiaries have business relationships and those relationships. Confidential Information also includes comparable information that the Company or any of its Subsidiaries have received belonging to others or which was received by the Company or any of its Subsidiaries with an agreement by the Company that it would not be disclosed. Confidential Information does not include information which (1) is or becomes available to the public generally (other than as a result of a disclosure by the Eligible Employee), (2) was within the Eligible Employee’s possession prior to its being furnished to the Eligible Employee by or on behalf of the Company, provided that the source of such information was not bound by a confidentiality agreement with or other contractual, legal or fiduciary obligation of confidentiality to the Company or any other party with respect to such information, (3) becomes available to the Eligible Employee on a non confidential basis from a source other than the Company, provided that such source is not bound by a confidentiality agreement with or other contractual, legal or fiduciary obligation of confidentiality to the Company or any other party with respect to such information, or (4) was independently developed the Eligible Employee without reference to the Confidential Information.

(ii) “Solicit” means any direct or indirect communication of any kind whatsoever, regardless of by whom initiated, inviting, advising, encouraging or requesting any person or entity, in any manner, with respect to any action.

ARTICLE VI

PLAN ADMINISTRATION

6.1 Operation of the Plan.

The Administrator shall be the named fiduciary responsible for carrying out the provisions of the Plan. The Administrator may delegate any and all of its powers and responsibilities hereunder or appoint agents to carry out such responsibilities, and any such delegation or appointment may be rescinded at any time. The Administrator shall establish the

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terms and conditions under which any such agents serve. The Administrator shall have the full and absolute authority to employ and rely on such legal counsel, actuaries and accountants (which may also be those of the Employer) as it may deem advisable to assist in the administration of the Plan.

6.2 Administration of the Plan.

To the extent that the Administrator in its sole discretion deems necessary or desirable, the Administrator may establish rules for the administration of the Plan, prescribe appropriate forms, and adopt procedures for handling claims and the denial of claims. The Administrator shall have the exclusive authority and discretion to interpret, construe, and administer the provisions of the Plan and to decide all questions concerning the Plan and its administration. Without limiting the foregoing, the Administrator shall have the authority to determine the level of an Employee, to determine eligibility for and the amount of any benefits due in accordance with the applicable Benefit Schedule, to make factual determinations, to correct deficiencies, and to supply omissions, including resolving any ambiguity or uncertainty arising under or existing in the terms and provisions of the Plan or any Benefit Schedule. Any and all such determinations of the Administrator shall be final, conclusive, and binding on the Employer, the Employee and any and all interested parties.

6.3 Funding.

The Plan shall be unfunded and all payments hereunder and expenses incurred in connection with this Plan shall be paid from the general assets of the Employer. Benefits will be paid directly by the Employer employing the Participant, and no other Employer or Affiliated Employer will be responsible for any benefits hereunder.

6.4 Code Section 4Q9A.

Notwithstanding any provision of the Plan to the contrary, if any benefit provided under this Plan is subject to the provisions of Section 409A of the Code and the regulations issued thereunder, the provisions of the Plan will be administered, interpreted and construed in a manner necessary to comply with Section 409A or an exception thereto (or disregarded to the extent such provision cannot be so administered, interpreted, or construed). With respect to payments subject to Section 409A of the Code: (i) it is intended that distribution events authorized under the Plan qualify as permissible distribution events for purposes of Section 409A of the Code; and (ii) the Company and each Employer reserve the right to accelerate and/or defer any payment to the extent permitted and consistent with Section 409A. Notwithstanding any provision of the Plan to the contrary, in no event shall the Administrator, the Company, an Affiliated Employer or Subsidiary (or their employees, officers, directors or affiliates) have any liability to any Participant (or any other person) due to the failure of the Plan to satisfy the requirements of Section 409A or any other applicable law.

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ARTICLE VII

CLAIMS

7.1 General.

Except as otherwise provided in a Benefit Schedule relating to notice periods, if an Employee believes that he or she is eligible for benefits under the Plan and has not been so notified, an Employee should submit a written request for benefits to the Administrator. Any claim for benefits must be made within six months of an Employee’s Termination Date, or the Employee will be forever barred from pursuing a claim. For purposes of this Article VI, an Employee making a claim for benefits under the Plan shall be referred to as a “claimant”. The claimant shall file the claim with and in the manner prescribed by the Administrator. The Administrator shall make the initial determination concerning rights to and amount of benefits payable under this Plan.

7.2 Claim Evaluation.

A properly filed claim will be evaluated and the claimant will be notified of the approval or the denial of the claim within ninety (90) days after the receipt of the claim, unless special circumstances require an extension of time for processing. Written notice of the extension will be furnished to the claimant prior to the expiration of the initial ninety-day (90-day) period, and will specify the special circumstances requiring an extension and the date by which a decision will be reached (provided the claim evaluation will be completed within one hundred and twenty (120) days after the date the claim was filed).

7.3 Notice of Disposition.

A claimant will be given a written notice in which the claimant will be advised as to whether the claim is granted or denied, in whole or in part. If a claim is denied, in whole or in part the notice will contain: (i) the specific reasons for the denial; (ii) references to pertinent Plan provisions upon which the denial is based; (iii) a description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and (iv) the claimant’s rights to seek review of the denial.

7.4 Appeals.

If a claim is denied, in whole or in part, the claimant, or his duly authorized representative, has the right to (i) request that the Administrator review the denial, (ii) review pertinent documents, and (iii) submit issues and comments in writing, provided that the claimant files a written appeal with the Administrator within sixty (60) days after the date the claimant received written notice of the denial. Within sixty (60) days after an appeal is received, the review will be made and the claimant will be advised in writing of the decision, unless special circumstances require an extension of time for reviewing the appeal, in which case the claimant will be given written notice within the initial sixty-day (60-day) period specifying the reasons for the extension and when the review will be completed (provided the review will be completed within one hundred and twenty (120) days after the date the appeal was filed). The decision on appeal will be forwarded to the claimant in writing and will include specific reasons for the decision and references to the Plan provisions upon which the decision is based. A decision on appeal will be final and binding on all persons for all purposes. If a claimant’s claim for benefits is denied in whole or in part, the claimant may file suit in a state or federal court.

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Notwithstanding the aforementioned, before the claimant may file suit in a state or federal court, the claimant must exhaust the Plan’s administrative claims procedure set forth in this Article VI. If any such state or federal judicial or administrative proceeding is undertaken, the evidence presented will be strictly limited to the evidence timely presented to the Administrator. In addition, any such state or federal judicial or administrative proceeding must be filed within six (6) months after the Administrator’s final decision. Any such state or federal judicial or administrative proceeding relating to this Plan shall only be brought in the Circuit Court for Arlington County, Virginia or in the United States District Court for the Eastern District of Virginia, Alexandria Division. If any such action or proceeding is brought in any other location, then the filing party expressly consents to the transfer of such action to the Circuit Court for Arlington County, Virginia or the United States District Court for the Eastern District of Virginia, Alexandria Division. Nothing in this clause shall be deemed to prevent any party from removing an action or proceeding to enforce or interpret this Plan from the Circuit Court for Arlington County, Virginia to the United States District Court for the Eastern District of Virginia, Alexandria Division.

ARTICLE VIII

PLAN AMENDMENTS

8.1 Amendment Authority.

The Board may, at any time and in its sole discretion, amend, modify or terminate the Plan, including any Benefit Schedule, as the Board, in its judgment shall deem necessary or advisable. The Board may delegate its amendment authority to the Administrator or such other persons as the Board considers appropriate. Notwithstanding the foregoing or any provision of the Plan to the contrary, the Board (or its designee) may at any time (in its sole discretion and without the consent of any Participant) modify, amend or terminate any or all of the provisions of this Plan or take any other action, to the extent necessary or advisable to conform the provisions of the Plan with Section 409A of the Code, the regulations issued thereunder or an exception thereto, regardless of whether such modification, amendment or termination of this Plan or other action shall adversely affect the rights of an Eligible Employee or Participant under the Plan. Termination of this Plan shall not be a distribution event under the Plan unless otherwise permitted under Section 409A.

ARTICLE IX

MISCELLANEOUS

9.1 Summary Plan Description.

To the extent the summary plan description or any other writing communication to an Eligible Employee conflicts with this Plan, the Plan document shall control.

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9.2 Impact on Other Benefits.

Except as otherwise provided herein, any amounts paid to a Participant under this Plan shall have no effect on the Participant’s rights or benefits under any other employee benefit plan sponsored by the Employer; provided, however, that in no event shall any Participant be entitled to any payment or benefit under the Plan which duplicates a payment or benefit received or receivable by the Participant under any severance plan, policy, guideline, arrangement, agreement, letter and/or other communication, whether formal or informal, written or oral sponsored by the Employer or an affiliate thereof and/or entered into by any representative of the Employer and/or any affiliate thereof. Further, any such amounts shall not be used to determine eligibility for or the amount of any benefit under any employee benefit plan, policy, or arrangement sponsored by the Employer or any affiliate thereof.

9.3 Tax Withholding.

The Employer shall have the right to withhold from any benefits payable under the Plan or any other wages payable to a Participant an amount sufficient to satisfy federal, state and local tax withholding requirements, if any, arising from or in connection with the Participant’s receipt of benefits under the Plan.

9.4 No Employment or Service Rights.

Nothing contained in the Plan shall confer upon any Employee any right with respect to continued employment with the Employer, nor shall the Plan interfere in any way with the right of the Employer to at any time reassign an Employee to a different job, change the compensation of the Employee or terminate the Employee’s employment for any reason.

9.5 Nontransferability.

Notwithstanding any other provision of this Plan to the contrary, the benefits payable under the Plan may not be subject to voluntary or involuntary anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, attachment or garnishment by creditors of the Participant or such other person, other than pursuant to the laws of descent and distribution, without the consent of the Company.

9.6 Successors.

The Company and its affiliates shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Company and its affiliates (taken as a whole) expressly to assume and agree to perform under the terms of the Plan in the same manner and to the same extent that the Company and its affiliates would be required to perform if no such succession had taken place (provided that such a requirement to perform which arises by operation of law shall be deemed to satisfy the requirements for such an express assumption and agreement), and in such event the Company and its affiliates (as constituted prior to such succession) shall have no further obligation under or with respect to the Plan.

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9.7 Headings and Captions.

The headings and captions herein are provided for reference and convenience only. They shall not be considered as part of the Plan and shall not be employed in the construction of the Plan.

9.8 Gender and Number.

Where the context admits, words in any gender shall include any other gender, and, except where clearly indicated by the context, the singular shall include the plural and vice-versa.

9.9 Nonalienation of Benefits.

None of the payments, benefits or rights of any Participant shall be subject to any claim of any creditor of any Participant and, in particular, to the fullest extent permitted by law, all such payments, benefits and rights shall be free from attachment, garnishment (if permitted under applicable law), trustee’s process, or any other legal or equitable process available to any creditor of such Participant. No Participant shall have the right to alienate, anticipate, commute, plead, encumber or assign any of the benefits or payments that he or she may expect to receive under this Plan.

9.10 Governing Law.

Except as otherwise preempted by the laws of the United States, this Plan shall be governed by and construed in accordance with the laws of the State of Delaware, without giving effect to its conflict of law provisions. If any provision of this Plan shall be held illegal or invalid for any reason, such determination shall not affect the remaining provisions of this Plan.

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The AES Corporation Executive Severance Plan has been duly executed by the undersigned and is effective this 6th day of October, 2011.

The AES Corporation
By:
	Rita Trehan, Vice President
	Human Resources & Internal Communications

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CHIEF EXECUTIVE OFFICER

BENEFIT SCHEDULE

The Chief Executive Officer shall receive the severance benefits outlined in the Plan document, except as otherwise modified or provided in this Benefit Schedule.

A. Definitions. The following definitions apply to this Benefit Schedule and override any contrary (or duplicative) terms of the Plan as they relate to the Chief Executive Officer.

“Cause” means (a) the willful and continued failure by the Chief Executive Officer to substantially perform his duties with the Company (other than any such failure resulting from the Chief Executive Officer’s incapability due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination by the Chief Executive Officer for Good Reason), after demand for substantial performance is delivered by the Company that specifically identifies the manner in which the Company believes that the Chief Executive Officer has not substantially performed his duties, or (b) the willful engaging by the Chief Executive Officer in misconduct which is demonstrably and materially injurious to the Company, monetarily or otherwise (including, but not limited to, conduct that constitutes a violation of Article V of the Plan). No act, or failure to act, on the Chief Executive Officer’s part shall be considered “willful” unless done, or omitted to be done, by him not in good faith and without reasonable belief that his action or omission was in the best interest of the Company. Notwithstanding the foregoing, the Chief Executive Officer shall not be deemed to have been terminated for Cause without (1) reasonable notice from the Board to the Chief Executive Officer setting forth the reasons for the Company’s intention to terminate for Cause and (2) delivery to the Chief Executive Officer of a Notice of Termination, which shall include a resolution duly adopted by the affirmative vote of two-thirds or more of the Board then in office (excluding the Chief Executive Officer) at a meeting of the Board called and held for such purpose, and at which the Chief Executive Officer, together with his counsel, is given an opportunity to be heard, finding that in the good faith opinion of the Board, the Chief Executive Officer was guilty of the conduct and specifying the particulars thereof in detail. “Notice of Termination” shall mean a notice which shall indicate the specific termination provision relied upon in the Plan and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Chief Executive Officer’s employment.

“Disability” means that the Chief Executive Officer is unable, due to physical or mental incapacity, to substantially perform his full time duties and responsibilities for a period of six (6) consecutive months (as determined by a medical doctor selected by the Company and the Chief Executive Officer). If the parties cannot agree on a medical doctor for purposes of such determination, each party shall select a medical doctor and the two doctors shall select a third who shall be the approved doctor for this purpose.

“Good Reason” or “Good Reason Termination” means, without the Chief Executive Officer’s written consent, the involuntary Separation From Service of the Chief Executive Officer due to any of the following events: (a) the failure of the Company to have any successor to all or substantially all of the business and/or assets of the Company expressly

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assume and agree to perform the Plan in accordance with Section 9.6 of the Plan; (b) following a Change in Control, the relocation of the Chief Executive Officer’s principal place of employment to a site outside of the metropolitan area of the Chief Executive Officer’s principal place of employment; (c) following a Change in Control, any material adverse change in the Chief Executive Officer’s overall responsibilities, duties and authorities from those then in place immediately prior to such Change in Control; and (d) following a Change in Control, the failure by the Company to continue the Chief Executive Officer’s participation in a long-term cash or equity award or equity-based grant program (or in a comparable substitute program) on a basis not materially less favorable than that provided to the Chief Executive Officer immediately prior to such Change in Control.

For purposes of any determination regarding the existence of Good Reason following a Change in Control, any good faith claim by the Chief Executive Officer that Good Reason exists shall be presumed to be correct unless the Company establishes by clear and convincing evidence that Good Reason does not exist. In order for the Chief Executive Officer to terminate for Good Reason, (i) the Chief Executive Officer must notify the Board, in writing, within ninety (90) days of the event constituting Good Reason of the Chief Executive Officer’s intent to terminate employment for Good Reason, that specifically identifies in reasonable detail the manner of the Good Reason event, (ii) the event must remain uncorrected for thirty (30) days following the date that the Chief Executive Officer notifies the Board in writing of the Chief Executive Officer’s intent to terminate employment for Good Reason (the “Notice Period”), and (iii) the termination date must occur within sixty (60) days after expiration of the Notice Period.

B. Separation Payments.

(1) Termination by Executive for Good Reason or by the Company (other than Disability, Cause or due to Death). If the Chief Executive Officer Separates from Service on account of an involuntary termination by the Company (other than for Disability or for Cause or due to death), or the Executive Separates from Service for Good Reason, the Chief Executive Officer shall be entitled to (i) Annual Compensation through the Termination Date, (ii) Pro Rata Bonus (as defined below), and (iii) receive a severance payment within ten (10) days following the Chief Executive Officer’s Termination Date (or, if later, the date the Chief Executive Officer has provided a release in accordance with Section 3.1 of the Plan), a cash lump sum payment equal to the product of (A) two (2) and (B) the sum of (1) the Chief Executive Officer’s Annual Compensation, and (2) the Chief Executive Officer’s Bonus.

(2) Upon Termination due to Disability. If the Chief Executive Officer Separates from Service on account of Disability, and subject to the execution of a release in accordance with Section 3.1 of the Plan, the Chief Executive Officer shall receive the following: (i) disability benefits in accordance with the terms of the long-term disability program then in effect for senior executives of the Company, (ii) Annual Compensation through the Termination Date or, if earlier, the end of the month immediately preceding the month in which such disability benefits commence, and (iii) to the extent earned and at the time bonuses are customarily paid to senior executive officers in accordance with the terms of the Performance Incentive Plan (or any successor plan), a bonus for the year in which the Separation From Service occurs equal to the Chief Executive Officer’s annual bonus for such year, multiplied by a faction, the numerator of which is the number of days during such year that the Executive was employed by the Company and the denominator which is 365 (the “Pro Rata Bonus”).

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(3) Upon Termination due to Death. If the Chief Executive Officer Separates from Service on account of death, the Chief Executive Officer shall receive (i) Annual Compensation through the Termination Date and (ii) the Pro Rata Bonus.

C. Continuation of Certain Welfare Benefits.

(1) If the Chief Executive Officer Separates from Service on account of an involuntary termination by the Company (other than for Disability or for Cause or due to death), or the Chief Executive Officer Separates from Service for Good Reason, the Chief Executive Officer shall be entitled to participate in the following welfare and other benefits for the twenty-four (24) month period immediately following the Chief Executive Officer’s Termination Date as follows:

(a) Medical/Dental/Vision Benefits. If the Chief Executive Officer elects COBRA Continuation Coverage, he shall continue to participate in all medical, dental and vision insurance plans he was participating in on his Termination Date. If, however, any such plan does not permit his continued participation following the end of the COBRA Continuation Period (as defined below), then the Company will reimburse the Chief Executive Officer for the actual cost to the Chief Executive Officer of any individual health insurance policy obtained by the Chief Executive Officer. To the extent such benefits are available under the above-referenced plans and the Chief Executive Officer had coverage immediately prior to the Separation From Service, such continuation of benefits for the Chief Executive Officer shall also cover the Executive’s dependents for so long as the Chief Executive Officer is receiving benefits under this subsection (a). The provisions of Section 4.2.2 and 4.2.4 of the Plan shall also apply. “COBRA Continuation Period” means the continuation period for medical, dental and vision insurance to be provided under the terms of the Plan and herein which shall commence on the first day of the calendar month following the month in which the Termination Date falls and generally shall continue for an 18-month period.

(b) Outplacement Services. The Chief Executive Officer shall be eligible to receive outplacement services, as set forth in Section 4.3 of the Plan.

(c) Reimbursement Limitations. Reimbursement under subsections (a) and (b) above will be available only to the extent that (1) such expense is actually incurred for any particular calendar year and is reasonably substantiated; (2) reimbursement shall be made no later than the end of the calendar year following the year in which such expense is incurred by the Chief Executive Officer; and (3) no reimbursement will be provided for any expense incurred following the twenty-four (24) month anniversary of the Separation From Service or for any expense which relates to insurance coverage after such date.

(d) Offset. Benefits or payments otherwise received under Sections B or C hereof shall be reduced to the extent benefits of the same type are received or made available to the Chief Executive Officer by a subsequent employer during the twenty-four (24) month period following the Termination Date (and any such benefits received or made available to the Chief Executive Officer shall be reported to the Company by the Chief Executive Officer).

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D. Change in Control Payments.

(a) If the Chief Executive Officer has a Separation From Service on account of an involuntary termination by the Company (other than for Cause or Disability or due to death), or if the Chief Executive Officer has a Separation From Service for Good Reason, in either case within two (2) years following a Change in Control, then (i) the Chief Executive Officer shall receive the payments set forth in Section B(l) above, except that the two (2) times multiplier shall be increased to three (3) and (ii) the Chief Executive Officer shall receive the benefits set forth in Section C above except the twenty-four (24) month benefit continuation period set forth in Section C(l)(a) and C(l)(c) above shall be increased to thirty-six (36) months.

E. Miscellaneous. For purposes of clarity:

(1) The Chief Executive Officer shall not be entitled to any benefits and payments associated with an Involuntary Termination (as defined and provided for in the Plan) and the definition of Ineligible Termination shall not apply.

(2) Section 2.3 of the Plan shall not apply to the Chief Executive Officer.

(3) Section 4.2.1 and Section 4.2.3 of the Plan shall not apply to the Chief Executive Officer.

(4) For the Chief Executive Officer, the Non-Competition Period under Article V of the Plan applies while the Chief Executive Officer is employed with the Company and for a period of twenty-four months after the Termination Date.

The number “365” in Section 5.5(c) of the Plan, in the case of the Chief Executive Officer, shall be replaced with “730”.

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EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Andrés Gluski, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of The AES Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 3, 2011

/s/ ANDRÉS GLUSKI

Name: Andrés Gluski

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Victoria D. Harker, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of The AES Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 3, 2011

/s/ VICTORIA D. HARKER

Name: Victoria D. Harker

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF PERIODIC FINANCIAL REPORTS

I, Andrés Gluski, President and Chief Executive Officer of The AES Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, (the “Periodic Report”) which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of The AES Corporation.

November 3, 2011

/s/ ANDRÉS GLUSKI

Andrés Gluski

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF PERIODIC FINANCIAL REPORTS

I, Victoria D. Harker, Executive Vice President and Chief Financial Officer of The AES Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of The Sarbanes-Oxley Act of 2002, that:

(1) the Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 (the “Periodic Report”) which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of The AES Corporation.

November 3, 2011

/s/ VICTORIA D. HARKER

Name: Victoria D. Harker

Executive Vice President and Chief Financial Officer

XML

Contingencies and Commitments (Details)	3 Months Ended			3 Months Ended						6 Months Ended		12 Months Ended
	Sep. 30, 2011 USD ($) integer	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Sep. 30, 2011 Guarantees USD ($)	Sep. 30, 2011 Letters of credit under secured credit facility USD ($)	Sep. 30, 2011 Cash Collateralized Letters Of Credit [Member] USD ($)	Sep. 30, 2011 Eletropaulo [Member] USD ($)	Sep. 30, 2011 Eletropaulo [Member] BRL	Sep. 30, 2011 CESCO [Member] USD ($)	Jun. 30, 2009 Cartagena Affiliate [Member] USD ($)	Jun. 30, 2009 Cartagena Affiliate [Member] EUR (€)	Dec. 31, 2008 Cartagena Affiliate [Member] USD ($)	Dec. 31, 2008 Cartagena Affiliate [Member] EUR (€)	Dec. 31, 2007 Cartagena Affiliate [Member] USD ($)	Dec. 31, 2007 Cartagena Affiliate [Member] EUR (€)	Sep. 30, 2011 Cartagena Affiliate [Member] USD ($)	Sep. 30, 2011 Cartagena Affiliate [Member] EUR (€)	Sep. 30, 2011 UKHPP [Member] USD ($)	Sep. 30, 2011 UKHPP [Member] KZT	Sep. 30, 2011 Maritza [Member] USD ($)	Sep. 30, 2011 Maritza [Member] EUR (€)	Sep. 30, 2011 Shulbinsk [Member] USD ($)	Sep. 30, 2011 Shulbinsk [Member] KZT
Environmental Contingencies Disclosure [Abstract]
Liability recorded for projected environmental remediation costs	$ 22,000,000
Number Of Countries In Which Entity Operates	27
Estimated Annual Cost Of Environmental Compliance		15,000,000
Guarantees Letters Of Credit [Abstract]
The range of expiration dates of guarantees made by the Parent Company	less than one year to more than 15 years
Obligations made by the Parent Company associated with non-recourse debt	26,000,000
Contingent Contractual Obligations [Line Items]
Amount	629,000,000			357,000,000	12,000,000	260,000,000
Number of Agreements	47			23	11	13
Maximum Exposure Range for Each Agreement				<$1 - $53	<$1 - $7	<$1 - $223
Commitments to invest in subsidiaries, excluding letters of credit	16,000,000
Commitment to purchase DPL	3,500,000,000
Litigation Contingency Disclosure [Abstract]
Aggregate reserves for claims deemed both probable and reasonably estimable	372,000,000		448,000,000
Loss Contingency Range Of Possible Loss Maximum	1,200,000,000
Litigation Details [Line Items]
Litigation Collection Suit Alleged Amount							656,000,000	1,200,000,000
Arbitration Alleged Damages Amount									189,000,000
Litigation Alleged Fines																		1,000,000	120,000,000
Litigation Disgorge Of Profits																		3,000,000	440,000,000
Litigation Additional Damages																		8,000,000	1,200,000,000			9,000,000	1,300,000,000
Litigation Pollution Liability Amount							415,000,000	760,000,000
Litigation Notified Invoice Amount																27,000,000	20,000,000
Litigation Invoiced Amount										7,000,000	5,000,000	27,000,000	19,907,248	712,000	523,548
Litigation Allowances Paid To Date																34,000,000	25,000,000
Amount Demanded Under Performance Bond																				211,000,000	155,000,000
Damages Sought By Counterparty																				$ 326,000,000	€ 240,000,000

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Condensed Consolidated Statements Of Operations (Parenthetical) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income (loss) from operations of discontinued businesses, income tax expense	$ (31)	$ 8	$ (33)	$ 23
Loss from disposal of discontinued businesses, income tax expense	$ 0	$ 38	$ 0	$ 38

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Condensed Consolidated Balance Sheets (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
CURRENT ASSETS
Cash and cash equivalents	$ 3,392	$ 2,550
Restricted cash	795	502
Short-term investments	1,053	1,718
Accounts receivable, net of allowance for doubtful accounts of $293 and $304, respectively	2,364	2,301
Inventory	668	561
Receivable from affiliates	28	27
Deferred income taxes - current	278	305
Prepaid expenses	190	223
Other current assets	1,128	1,036
Current assets of discontinued and held for sale businesses	171	223
Total current assets	10,067	9,446
Property, Plant and Equipment:
Land	1,029	1,126
Electric generation, distribution assets and other	29,945	27,929
Accumulated depreciation	(9,257)	(9,048)
Construction in progress	2,096	4,454
Property, plant and equipment, net	23,813	24,461
Other Assets:
Investments in and advances to affiliates	1,401	1,320
Debt service reserves and other deposits	909	653
Goodwill	1,246	1,271
Other intangible assets, net of accumulated amortization of $153 and $157, respectively	493	511
Deferred income taxes - noncurrent	585	646
Other	2,133	1,958
Noncurrent assets of discontinued and held for sale businesses	236	245
Total other assets	7,003	6,604
TOTAL ASSETS	40,883	40,511
CURRENT LIABILITIES
Accounts payable	1,792	2,048
Accrued interest	395	257
Accrued and other liabilities	2,619	2,633
Non-recourse debt - current, including $269 and $1,150, respectively, related to variable interest entities	2,163	2,567
Recourse debt - current	11	463
Current liabilities of discontinued and held for sale businesses	261	97
Total current liabilities	7,241	8,065
LONG-TERM LIABILITIES
Non-recourse debt - noncurrent, including $2,168 and $2,199, respectively, related to variable interest entities	12,523	12,371
Recourse debt - noncurrent	6,181	4,149
Deferred income taxes - noncurrent	621	895
Pension and other post-retirement liabilities	1,310	1,511
Other long-term liabilities	2,978	2,812
Long-term liabilities of discontinued and held for sale businesses	112	235
Total long-term liabilities	23,725	21,973
Contingencies and Commitments (see Note ##CONTINGENCIES)	0	0
Cumulative preferred stock of subsidiary	60	60
THE AES CORPORATION STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 807,093,084 issued and 770,260,308 outstanding at September 30, 2011 and 804,894,313 issued and 787,607,240 outstanding at December 31, 2010	8	8
Additional paid-in capital	8,499	8,444
Retained earnings	887	620
Accumulated other comprehensive loss	(2,727)	(2,383)
Treasury stock, at cost (36,832,776 shares at September 30, 2011 and 17,287,073 shares at December 31, 2010, respectively)	(434)	(216)
Total The AES Corporation stockholders' equity	6,233	6,473
NONCONTROLLING INTERESTS	3,624	3,940
Total equity	9,857	10,413
TOTAL LIABILITIES AND EQUITY	$ 40,883	$ 40,511

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Segments (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Revenue
Total Revenue	$ 4,381	$ 3,990	$ 13,117	$ 11,777
Intersegment	0	0	0	0
External Revenue	4,381	3,990	13,117	11,777
Reconciliation To Income From Continuing Operations Before Taxes
Depreciation and amortization	313	271	909	802
Interest expense	(432)	(381)	(1,178)	(1,151)
Interest income	103	96	293	304
Other expense	(76)	(23)	(131)	(83)
Other income	58	17	108	94
Gain on sale of investments	0	0	7	0
Goodwill impairment	(17)	(18)	(17)	(18)
Asset impairment expense	(163)	(296)	(196)	(297)
Foreign currency transaction (losses) gains on net monetary position	(92)	103	(21)	(19)
Other non-operating expense	(82)	(2)	(82)	(7)
Income from continuing operations before taxes and equity in earnings of affiliates	228	365	1,519	1,445
Assets
Total Assets	40,883		40,883		40,511
Latin America Generation [Member]
Revenue
Total Revenue	1,302	1,111	3,810	3,178
Intersegment	(328)	(267)	(842)	(778)
External Revenue	974	844	2,968	2,400
Adjusted Gross Margin
Adjusted Gross Margin	505	436	1,493	1,296
Intersegment	(313)	(262)	(800)	(766)
External Adjusted Gross Margin	192	174	693	530
Assets
Total Assets	10,545		10,545		10,373
Latin America Utilities [Member]
Revenue
Total Revenue	1,930	1,757	5,774	5,236
Intersegment	0	0	0	0
External Revenue	1,930	1,757	5,774	5,236
Adjusted Gross Margin
Adjusted Gross Margin	378	306	1,035	888
Intersegment	322	267	820	778
External Adjusted Gross Margin	700	573	1,855	1,666
Assets
Total Assets	8,938		8,938		9,872
North America Generation [Member]
Revenue
Total Revenue	372	413	1,116	1,173
Intersegment	0	0	(4)	0
External Revenue	372	413	1,112	1,173
Adjusted Gross Margin
Adjusted Gross Margin	145	146	402	406
Intersegment	3	5	6	12
External Adjusted Gross Margin	148	151	408	418
Assets
Total Assets	4,403		4,403		4,681
North America Utilities [Member]
Revenue
Total Revenue	321	306	890	869
Intersegment	0	0	0	0
External Revenue	321	306	890	869
Adjusted Gross Margin
Adjusted Gross Margin	113	118	292	324
Intersegment	0	0	1	1
External Adjusted Gross Margin	113	118	293	325
Assets
Total Assets	3,218		3,218		3,139
Europe Generation [Member]
Revenue
Total Revenue	397	282	1,125	864
Intersegment	0	0	(1)	0
External Revenue	397	282	1,124	864
Adjusted Gross Margin
Adjusted Gross Margin	128	71	327	287
Intersegment	2	2	4	5
External Adjusted Gross Margin	130	73	331	292
Assets
Total Assets	4,264		4,264		4,178
Asia Generation [Member]
Revenue
Total Revenue	172	136	449	491
Intersegment	0	0	0	0
External Revenue	172	136	449	491
Adjusted Gross Margin
Adjusted Gross Margin	35	51	133	204
Intersegment	0	1	1	3
External Adjusted Gross Margin	35	52	134	207
Assets
Total Assets	1,725		1,725		1,762
Segment Discontinued Operations [Member]
Assets
Total Assets	407		407		468
Corporate Other And Other Eliminations [Member]
Revenue
Total Revenue	(113)	(15)	(47)	(34)
Intersegment	328	267	847	778
External Revenue	215	252	800	744
Adjusted Gross Margin
Adjusted Gross Margin	(62)	12	(37)	19
Intersegment	(14)	(13)	(32)	(33)
External Adjusted Gross Margin	(76)	(1)	(69)	(14)
Assets
Total Assets	$ 7,383		$ 7,383		$ 6,038

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Discontinued Operations and Held For Sale Businesses

3 Months Ended

Sep. 30, 2011

DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

16. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

Discontinued operations includes the results of the following generation businesses:

• Eletropaulo Telecomunicacões Ltda. and AES Communications Rio de Janeiro S.A (collectively “Brazil Telecom”), our Braziltelecommunication businesses (held for sale in September 2011);
• Eastern Energy, including Cayuga, Greenidge, Somerset and Westover, in New York(held for sale in March 2011);
• Borsod and Tiszapalkonya, in Hungary(held for sale in March 2011);
• Ras Laffan, in Qatar (sold in October 2010);
• Barka, in Oman (sold in August 2010); and
• Lal Pir and Pak Gen, in Pakistan (sold in June 2010).

For thenine months ended September 30, 2010, the Company recognized a gain on disposal and impairment losses totaling $57 million. TheCompany incurred a loss of $14 million, net of tax and noncontrolling interests on Lal Pir and Pak Gen as a result ofanincrease in net assets carrying value compared to the agreed upon sale proceeds.Additionally, the Company completed the sale of its interest in Barka in August 2010 and recognized a gain on disposal of $63 million, net of noncontrolling interests and $38 million of tax expense associated with the sale.

The following table summarizes the revenue, income from operations,income tax expense,impairmentand gain on sale of discontinued operationsfor the three and nine months ended September 30, 2011 and 2010:

		Three Months				Nine Months
		Ended September 30,				Ended September 30,
		2011		2010		2011		2010
		(in millions)
Revenue		$	107	$	218	$	327	$	948
(Loss) income from operations of discontinued businesses		$	(6)	$	37	$	(10)	$	115
Income tax benefit (expense)			31		(8)		33		(23)
Income from operations of discontinued
	businesses, net of tax	$	25	$	29	$	23	$	92
Gain on sale of discontinued operations		$	-	$	79	$	-	$	57

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Document And Entity Information	3 Months Ended
	Sep. 30, 2011	Oct. 28, 2011
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Trading Symbol	AES
Entity Registrant Name	AES CORP
Entity Central Index Key	0000874761
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		767,548,237
Entity current reporting status	Yes
Entity voluntary filers	No
Entity Well Known Seasoned Issuer	Yes

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Financing Receivables (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Financing Receivable Recorded Investment [Line Items]
Financing Receivable	$ 282	$ 151
Dominican Republic [Member]
Financing Receivable Recorded Investment [Line Items]
Financing Receivable	50
Argentina [Member]
Financing Receivable Recorded Investment [Line Items]
Financing Receivable	$ 220

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Regulatory Assets and Liabilities

3 Months Ended

Sep. 30, 2011

REGULATORY ASSETS & LIABILITIES

19. REGULATORY ASSETS AND LIABILITIES

Regulatory liabilities generally represent obligations to make refunds to customers for previous collections of revenue and for costs that are not likely to be incurred or included in future rate events. For example, in July 2011, the Brazilian energy regulator (the “Regulator”) postponed the periodic review and reset of a component of Eletropaulo's regulated tariff, which determines the margin to be earned by Eletropaulo. The review and reset of this tariff component is performed every four years. From July 2011 through September 2011, Eletropaulo continued to invoice customers under the existing tariff rate, as required by the Regulator. Management believes that it is probable that the new tariff rate will be lower than the existing tariff rate, resulting in future refunds to customers, and has estimated the amount of this liability. Accordingly, as of September 30, 2011, Eletropaulo recognized a regulatory liability and corresponding reduction in revenue of approximately $104 million. It is at least reasonably possible that future events confirming the final amount of the regulatory liability or a change in the estimated amount of the liability will occur in the near term as the periodic review and tariff reset process progresses with the Regulator through the remainder of 2011 and into 2012. The primary factors in the ongoing discussions between the Brazilian distribution companies, including Eletropaulo, and the Regulator that cause the estimate to be sensitive to change include the regulatory asset base and the investment return rate assumptions used in the determination of the margin. The final amount of the regulatory liability may differ from the estimated amount recognized as of September 30, 2011.

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Investments In and Advances To Affiliates (Details) (Entek [Member], USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2011	Mar. 31, 2011	Sep. 30, 2011 mw
Entek [Member]
Investments In And Advances To Affiliates General Disclosure [Abstract]
Effective Ownership %			49.60%
Generation Capacity (MW)			312
Cash paid for acquisition	$ 13	$ 136	$ 149

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Derivative Instruments and Hedging Activities

3 Months Ended

Sep. 30, 2011

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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 fuel 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. The Company generally applies hedge accounting to contracts as long as they are eligible under the accounting standards for derivatives and hedging. While derivative transactions are not entered into for trading purposes, some contracts are not eligible for hedge accounting.

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 2030, and are typically designated as cash flow hedges. The following table sets forth, by underlying 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 the related index as of September 30, 2011 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:

		September 30, 2011
		Current			Maximum(1)
			Derivative			Derivative		Weighted	% of Debt
			Notional			Notional		Average	Currently
		Derivative	Translated		Derivative	Translated		Remaining	Hedged
Interest Rate Derivatives		Notional	to USD		Notional	to USD		Term(1)	by Index(2)
		(in millions)						(in years)
Libor (U.S. Dollar)		3,511	$	3,511	3,585	$	3,585	9	75%
Euribor (Euro)		1,072		1,435	1,072		1,435	13	66%
Libor (British Pound Sterling)		63		98	72		112	12	87%
Securities Industry and Financial
	Markets Association Municipal
	Swap Index (U.S. Dollar)	40		40	40		40	11	N/A(3)

(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, 2011 and the maturity of the derivative instrument, which includes forward starting derivative instruments. The weighted average remaining term represents the remaining tenor of our interest rate derivatives weighted by the corresponding maximum notional.

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

(3)       The debt that was being hedged is no longer exposed to variable interest payments because it is now held on IPL's behalf and no longer bears interest.

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 notionalamount under its cross currency derivative instruments as of September 30, 2011, which are all in qualifying cash flow hedge relationships. These swaps are amortizing and therefore the notional amount represents the maximum outstanding notional amount as of September 30, 2011:

	September 30, 2011
				Weighted	% of Debt
		Notional		Average	Currently
		Translated		Remaining	Hedged
Cross Currency Swaps	Notional	to USD		Term(1)	by Index(2)
	(in millions)			(in years)
Chilean Unidad de Fomento (CLF)	6	$	237	14	83%

(1)        Represents the remaining tenor of our cross currency swaps weighted by the corresponding notional.

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

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 countries and such operations may be impacted by significant fluctuations in foreign currency exchange rates. Foreign currency options and forwards are utilized, where deemed appropriate, to manage the risk related to fluctuations in certain foreign currencies. These foreign currency contracts range in maturity through 2015. The following tables set forth, by type of foreign currency denomination, the Company's outstanding notional amounts over the remaining terms of its foreign currency derivative instruments as of September 30, 2011 regardless of whether the derivative instruments are in qualifying hedging relationships:

	September 30, 2011
						Weighted
		Notional		Probability		Average
		Translated		Adjusted		Remaining
Foreign Currency Options	Notional	to USD(1)		Notional(2)		Term(3)
	(in millions)					(in years)
Brazilian Real (BRL)	173	$	105	$	96	<1
Euro (EUR)	67		96		82	<1
British Pound (GBP)	29		47		40	<1
Argentine Peso (ARS)	88		20		8	<1

(1)       Represents 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)       Represents the remaining tenor of our foreign currency options weighted by the corresponding notional.

	September 30, 2011
		Notional		Weighted Average
Foreign Currency Forwards	Notional	Translated to USD		Remaining Term(1)
	(in millions)			(in years)
Chilean Peso (CLP)	98,944	$	201	<1
Euro (EUR)	123		169	2
Colombian Peso (COP)	80,376		44	<1
British Pound (GBP)	11		17	1
Argentine Peso (ARS)	61		13	1

(1)       Represents the remaining tenor of our foreign currency forwards weighted by the corresponding notional.

In addition, certain of our subsidiaries have entered into contracts which contain embedded derivatives that require separate valuation and accounting due to the fact that the item being purchased or sold is denominated in a currency other than the functional currency of that subsidiary or the currency of the item. 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, 2011:

	September 30, 2011
		Notional		Weighted Average
Embedded Foreign Currency Derivatives	Notional	Translated to USD		Remaining Term(1)
	(in millions)			(in years)
Philippine Peso (PHP)	15,973	$	363	2
Argentine Peso (ARS)	904		215	11
Kazakhstani Tenge (KZT)	30,606		207	9
Hungarian Forint (HUF)	10,114		46	<1
Euro (EUR)	20		27	2
Brazilian Real (BRL)	4		2	1

(1)        Represents the remaining tenor of our foreign currency embedded derivatives weighted by the corresponding notional.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the price of electricity, fuel 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 purchase or sales contracts. These businesses subject our results of operations to the volatility of prices for electricity, fuel 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 PPAs, fuel supply agreements, commodity forward contracts, futures, swaps and options. Some of our businesses hedge certain aspects of their commodity risks using financial hedging instruments.

The PPAs and fuel supply agreements entered into by the Company are evaluated to determine if they meet the definition of a derivative or contain embedded derivatives, either of which requires separate valuation and accounting. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Generally, these agreements do not meet the definition of a derivative, often due to the inability to be net settled. On a quarterly basis, we evaluate the markets for the commodities to be delivered under these agreements to determine if facts and circumstances have changed such that the agreements could then be net settled and meet the definition of a derivative.

Nonetheless, certain of the PPAs and fuel supply agreements entered into by certain of the Company's subsidiaries are derivatives or contain embedded derivatives requiring separate valuation and accounting. These contracts range in maturity through 2024. The following table sets forth, by type of commodity, the Company's outstanding notionals for the remaining term of its commodity derivatives and embedded derivative instruments as of September 30, 2011:

	September 30, 2011
		Weighted Average
Commodity Derivatives	Notional	Remaining Term(1)
	(in millions)	(in years)
Natural gas (MMBTU)	33	11
Aluminum (MWh)	16(2)	8
Petcoke (Metric tons)	13	13

• Represents the remaining tenor of our commodity and embedded derivatives weighted by the corresponding volume.
• Sonel's PPA with its primary offtaker, an aluminum smelter, contains an embedded derivative which reflects the linkage of our energy contract pricing, in part, to the price of aluminum as quoted on the London Metals Exchange, a global metals market maker (as required by contract).While the linkage between the contract price of power based on forecasted forward aluminum price curves and the Cameroon market price for power provides for economic alignment between Sonel's financial results under the PPA and the offtaker's financial performance, to the extent there are fluctuations in the price of aluminum as compared to the market price for power under our PPA, we may be exposed to significant swings in earnings through mark-to-market adjustments of the embedded derivative as the market price for aluminum has proven to be volatile.

Accounting and Reporting

The following table sets forth the Company's derivative instruments as of September 30, 2011 and December 31, 2010 by type of derivative and by level within the fair value hierarchy. Derivative assets and liabilities are recognized at their fair value. Derivative assets and liabilities are combined with other balances and included in the following captions in our condensed consolidated balance sheets: current derivative assets in other current assets, noncurrent derivative assets in other noncurrent assets, current derivative liabilities in accrued and other liabilities and long-term derivative liabilities in other long-term liabilities.

				September 30, 2011								December 31, 2010
				Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
				(in millions)								(in millions)
Assets
Current assets:
	Foreign currency derivatives			$	-	$	48	$	4	$	52	$	-	$	4	$	3	$	7
	Commodity and other derivatives				-		-		5		5		-		2		3		5
		Total current assets			-		48		9		57		-		6		6		12
Noncurrent assets:
	Interest rate derivatives				-		-		-		-		-		49		-		49
	Cross currency derivatives				-		-		1		1		-		-		12		12
	Foreign currency derivatives				-		5		49		54		-		4		27		31
	Commodity and other derivatives				-		4		1		5		-		4		16		20
		Total noncurrent assets			-		9		51		60		-		57		55		112
			Total assets	$	-	$	57	$	60	$	117	$	-	$	63	$	61	$	124
Liabilities
Current liabilities:
	Interest rate derivatives			$	-	$	102	$	29	$	131	$	-	$	137	$	-	$	137
	Cross currency derivatives				-		-		5		5		-		-		2		2
	Foreign currency derivatives				-		6		1		7		-		13		-		13
	Commodity and other derivatives				-		5		3		8		-		-		-		-
		Total current liabilities			-		113		38		151		-		150		2		152
Long-term liabilities:
	Interest rate derivatives				-		294		162		456		-		246		1		247
	Cross currency derivatives				-		-		17		17		-		-		-		-
	Foreign currency derivatives				-		11		11		22		-		15		8		23
	Commodity and other derivatives				-		1		41		42		-		-		1		1
		Total long-term liabilities			-		306		231		537		-		261		10		271
			Total liabilities	$	-	$	419	$	269	$	688	$	-	$	411	$	12	$	423

The following table sets forth the fair value and balance sheet classification of derivative instruments as of September 30, 2011 and December 31, 2010:

		September 30, 2011						December 31, 2010
				Not						Not
		Designated		Designated				Designated		Designated
		as Hedging		as Hedging				as Hedging		as Hedging
		Instruments		Instruments		Total		Instruments		Instruments		Total
		(in millions)						(in millions)
Assets
Current assets:
	Foreign currency derivatives	$	17	$	35	$	52	$	-	$	7	$	7
	Commodity and other derivatives		-		5		5		-		5		5
	Total current assets		17		40		57		-		12		12
Noncurrent assets:
	Interest rate derivatives		-		-		-		49		-		49
	Cross currency derivatives		1		-		1		12		-		12
	Foreign currency derivatives		2		52		54		-		31		31
	Commodity and other derivatives		-		5		5		-		20		20
	Total noncurrent assets		3		57		60		61		51		112
Total assets		$	20	$	97	$	117	$	61	$	63	$	124
Liabilities
Current liabilities:
	Interest rate derivatives	$	126	$	5	$	131	$	126	$	11	$	137
	Cross currency derivatives		5		-		5		2		-		2
	Foreign currency derivatives		1		6		7		8		5		13
	Commodity and other derivatives		-		8		8		-		-		-
	Total current liabilities		132		19		151		136		16		152
Long-term liabilities:
	Interest rate derivatives		437		19		456		232		15		247
	Cross currency derivatives		17		-		17		-		-		-
	Foreign currency derivatives		-		22		22		-		23		23
	Commodity and other derivatives		-		42		42		-		1		1
	Total long-term liabilities		454		83		537		232		39		271
Total liabilities		$	586	$	102	$	688	$	368	$	55	$	423

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, 2011 and December 31, 2010, we held no cash collateral that we received from counterparties to our derivative positions. As we have not received collateral, our derivative assets are exposed to the credit risk of the respective counterparty and, due to this credit risk, the fair values of our derivative assets (as shown in the above two tables) have been reduced by a credit valuation adjustment. Also, at September 30, 2011 and December 31, 2010, we had no cash collateral posted with (held by) counterparties to our derivative positions.

The table below sets forth the pre-tax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes over the next twelve months as of September 30, 2011 for the following types of derivatives:

	Accumulated
	Other Comprehensive
	Income (Loss)
	(in millions)
Interest rate derivatives	$	(116)
Cross currency derivatives	$	(1)
Foreign currency derivatives	$	16

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, and as foreign currency gains and losses are recognized for hedges of foreign currency exposure. These balances are included in the condensed consolidated statements of cash flows as operating and/or investing activities based on the nature of the underlying transaction.

The following tables set forth the 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, 2011 and 2010:

		Gains (Losses)						Gains (Losses) Reclassified
		Recognized in AOCL						from AOCL into Earnings(1)
		Three Months				Classification in		Three Months
		Ended September 30,				Condensed Consolidated		Ended September 30,
		2011		2010		Statements of Operations		2011		2010
		(in millions)						(in millions)
Interest rate derivatives		$	(297)	$	(138)	Interest expense		$	(35) (2)	$	(24) (2)
						Non-regulated cost of sales			(1) (2)		(3) (2)
						Net equity in earnings of
							affiliates		(1)		(1)
Cross currency derivatives			(37)		24	Interest expense			(3)		-
						Foreign currency transaction
							gains (losses)		(26)		30
Foreign currency derivatives			29		(12)	Foreign currency transaction
							gains (losses)		3		1
Commodity and other
	derivatives		-		(4)	Non-regulated cost of sales			(2)		-
Total		$	(305)	$	(130)			$	(65)	$	3

		Gains (Losses)						Gains (Losses) Reclassified
		Recognized in AOCL						from AOCL into Earnings(1)
		Nine Months				Classification in		Nine Months
		Ended September 30,				Condensed Consolidated		Ended September 30,
		2011		2010		Statements of Operations		2011		2010
		(in millions)						(in millions)
Interest rate derivatives		$	(389)	$	(388)	Interest expense		$	(88) (2)	$	(81) (2)
						Non-regulated cost of sales			(3) (2)		(3) (2)
						Net equity in earnings of
							affiliates		(3)		(3)
Cross currency derivatives			(34)		(5)	Interest expense			(7)		(1)
						Foreign currency transaction
							gains (losses)		(20)		16
Foreign currency derivatives			27		(5)	Foreign currency transaction
							gains (losses)		(1)		1
Commodity and other
	derivatives		-		(4)	Non-regulated cost of sales			(2)		-
Total		$	(396)	$	(402)			$	(124)	$	(71)

(1)        Excludes $0 million and $20million related to discontinued operations for the three months ended September 30, 2011 and 2010, respectively, and $0 million and $30 million related to discontinued operations for the nine months ended September 30, 2011 and 2010, respectively.

(2)       Includes amounts that were reclassified from AOCL related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting.

The following table sets forth the pre-tax 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, 2011 and 2010:

			Gains (Losses)				Gains (Losses)
			Recognized in Earnings				Recognized in Earnings
	Classification in Condensed		Three Months Ended				Nine Months Ended
	Consolidated Statements		September 30,				September 30,
	of Operations		2011		2010		2011		2010
			(in millions)				(in millions)
Interest rate derivatives	Interest expense		$	1	$	(10)	$	(6)	$	(18)
	Net equity in earnings of
		affiliates		(1)		-(1)		(2)		(1)
Cross currency derivatives	Interest expense			(3)		-(1)		(5)		4
Foreign currency derivatives	Foreign currency transaction
		gains (losses)		- (1)		-(1)		- (1)		-(1)
Total			$	(3)	$	(10)	$	(13)	$	(15)

(1)       De minimis amount.

The following table sets forth the gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging, for the three and nine months ended September 30, 2011 and 2010:

				Gains (Losses)				Gains (Losses)
				Recognized in Earnings				Recognized in Earnings
		Classification		Three Months Ended				Nine Months Ended
		in Condensed Consolidated		September 30,				September 30,
		Statements of Operations		2011		2010		2011		2010
				(in millions)				(in millions)
Interest rate derivatives		Interest expense		$	(1)	$	(3)	$	(2)	$	(8)
Foreign exchange derivatives		Foreign currency transaction
			gains (losses)		27		(7)		54		(32)
		Net equity in earnings
			of affiliates		-		-		-		2
Commodity and other
	derivatives	Non-regulated revenue			(54)		1		(63)		5
		Non-regulated cost of sales			3		(3)		2		2
Total				$	(25)	$	(12)	$	(9)	$	(31)

In addition, IPL 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 the fair value of these derivatives are probable of recovery 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. The following table sets forth the change in regulatory assets and liabilities resulting from the change in the fair value of these derivatives for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(in millions)
(Increase) decrease in regulatory assets	$	(4)	$	(3)	$	(6)	$	(6)
Increase (decrease) in regulatory liabilities	$	(3)	$	(2)	$	3	$	2

Credit Risk-Related Contingent Features

Gener, our business in Chile, has cross currency swap agreements with counterparties to swap Chilean inflation indexed bonds issued in December 2007 into U.S. Dollars. The derivative agreements contain credit contingent provisions which would permit the counterparties with which Gener is in a net liability position to require collateral credit support when the fair value of the derivatives exceeds the unsecured thresholds established in the agreement. These thresholds vary based on Gener's credit rating. If Gener's credit rating were to fall below the minimum threshold established in the swap agreements, the counterparties can demand immediate collateralization of the entire mark-to-market value of the swaps (excluding credit valuation adjustments) if Gener is in a net liability position, which was $21 million at September 30, 2011. The swaps were in a net asset position at December 31, 2010. As of September 30, 2011 and December 31, 2010, Gener had not posted collateral to support these swaps.

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Subsequent Events

3 Months Ended

Sep. 30, 2011

SUBSEQUENT EVENTS

20. SUBSEQUENT EVENTS

On October 3, 2011, the Company completed the placement of $1.25 billion aggregate principal amount senior notes with Wells Fargo Bank N.A. See Note 8―Debt, Non-Recourse Debt for further information.

In July 2011, a subsidiary of the Company entered into an agreement to sell its ownership interest in two telecommunication companies in Brazil.The Company held approximately 46% ownership interest in these companies through the subsidiary. The transaction closed on October 31, 2011 andthe subsidiary received approximately R$1,522million ($901 million), subject to customary purchase price adjustments. The estimated gain on the sale before noncontrolling interests and taxes is approximately R$1,333 million ($789 million), subject to final purchase price adjustments.

On October 20, 2011, a subsidiary of the Company signed a share sale agreement with Electrabel International Holdings B.V. (“EIH”), a subsidiary of GDFSUEZS.A. (“GDFS”) for the sale of 80% of its interest in the wholly-owned holding company that holds the Company's interest in AES Energia CartagenaS.R.L. (“AES Cartagena”), a 1,199 MW gas-fired generation business in Spain, for €172 million ($234 million), subject to customary purchase price adjustments.AES owns approximately 70.81% of AES Cartagena through this holding company structure.Under the terms of the sale agreement, EIHhas an option to purchase AES' remaining 20% interest in the holding company for a fixed price of €28 million ($38 million) during a five month period beginning 13 months from the date the sale closes.Subject to regulatory and lenders'approvals,the saleis expected to close by the end of 2011. Concurrent with the sale, GDFSagreed to settle the outstanding arbitration between the parties regarding certain emissions costs and other taxes that AES Cartagena sought to recover from GDFS as energy manager under the existing commercial arrangements and to pay €58 million ($79 million) to AES Cartagenafor such costs incurred by AES Cartagena during the period up to December 31, 2010 and additional amounts for such costs incurred by AES Cartagena during the period from January 1, 2011 until closing of the sale. However, the settlement of the arbitration is contingent on consummation of the sale. See Note9—Contingencies and Commitments for further information.

Subsequent to September 30, 2011, the Company continued to repurchase stock under the stock repurchase program announced on July 7, 2010. The Company has repurchased 5,554,185 shares at a cost of $54 million subsequent to September 30, 2011, bringing the cumulative total through November 3, 2011 to 33,924,805 shares at a total cost of $378 million (average price of $11.16 per share including commissions). For additional information, see Note 11—Equity.

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Inventory (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Inventory Disclosure Abstract
Coal, fuel oil and other raw materials	$ 377	$ 276
Spare parts and supplies	291	285
Total	$ 668	$ 561

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Other Income and Expense (Tables)

3 Months Ended

Sep. 30, 2011

Other Income Expense Tables [Abstract]

Components Of Other Income Table

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(in millions)
Tax credit settlement	$	31	$	-	$	31	$	-
Tax dispute settlement		14		-		14		-
Extinguishment of liability		-		-		-		62
Gain on sale of assets		9		5		25		7
Other		4		12		38		25
Total other income	$	58	$	17	$	108	$	94

Components Of Other Expense Table

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(in millions)
Loss on sale and disposal of assets	$	31	$	17	$	60	$	36
Loss on extinguishment of debt		36		-		52		9
Wind Generation transaction costs		-		-		-		22
Other		9		6		19		16
Total other expense	$	76	$	23	$	131	$	83

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Earnings Per Share

3 Months Ended

Sep. 30, 2011

EARNINGS PER SHARE

18. 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. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units, stock options and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.

 The following tables present 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, 2011 and 2010. In the table below, income represents the numerator and weighted-average shares represent the denominator:

			Three Months Ended September 30,
			2011					2010
			Loss		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	$	(119)	778	$	(0.15)	$	41	794	$	0.05
EFFECT OF DILUTIVE SECURITIES
	Stock options			-	-		-		-	2		-
	Restricted stock units			-	-		-		-	3		-
DILUTED EARNINGS PER SHARE			$	(119)	778	$	(0.15)	$	41	799	$	0.05

			Nine Months Ended September 30,
			2011					2010
			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	$	296	783	$	0.38	$	354	762	$	0.46
EFFECT OF DILUTIVE SECURITIES
	Stock options			-	1		-		-	2		-
	Restricted stock units			-	3		-		-	3		-
DILUTED EARNINGS PER SHARE			$	296	787	$	0.38	$	354	767	$	0.46

There were approximately 15,564,118and 16,951,804additional options outstanding at September 30, 2011 and 2010, 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, 2011 and 2010, allconvertible debentures were omitted from the earnings per share calculation because they were anti-dilutive.During the three months ended September 30, 2011, 115,597shares of common stock were issued upon the exercise of stock options. For the nine months ended September 30, 2011 and 2010, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. During the nine months ended September 30, 2011, 1,073,539shares of common stock were issued under the Company's profit sharing plan and 589,948shares of common stock were issued upon the exercise of stock options.

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Pension Plans

3 Months Ended

Sep. 30, 2011

PENSION PLANS

10. PENSION PLANS

Total pension cost for the three and nine months ended September 30, 2011 and 2010 included the following components:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011				2010				2011				2010
	U.S.		Foreign		U.S.		Foreign		U.S.		Foreign		U.S.		Foreign
	(in millions)								(in millions)
Service cost	$	1	$	6	$	1	$	3	$	5	$	16	$	4	$	12
Interest cost		8		145		8		129		24		436		24		380
Expected return on plan assets		(8)		(130)		(7)		(108)		(24)		(391)		(22)		(318)
Amortization of prior service cost		1		-		1		-		3		-		3		-
Amortization of net loss		3		6		3		4		10		18		9		11
Loss on curtailment		-		-		-		-		-		4		-		-
Total pension cost	$	5	$	27	$	6	$	28	$	18	$	83	$	18	$	85

Total employer contributions for the nine months ended September 30, 2011 for the Company's U.S. and foreign subsidiaries were $30million and $132 million, respectively. The expected remaining scheduled employer contributions for 2011 are $7 million for U.S. subsidiaries and $39 million for foreign subsidiaries.

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Financial Statement Presentation

3 Months Ended

Sep. 30, 2011

FINANCIAL STATEMENT PRESENTATION

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 businesses held for sale and discontinued operations as discussed in Note 16—Discontinued Operations and Held for Sale Businesses.

On June 1, 2011, The AES Corporation filed a Current Report on Form 8-K (“June 2011 Form 8-K”) to recast previously filed financial statements and other information included in the Company's Form 10-K for the year ended December 31, 2010 (“2010 Form 10-K”) to reclassify certain businesses held for sale as discussed in Note 16—Discontinued Operations and Held for Sale Businesses. The updates to the 2010 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, respectively. All other information in the 2010 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 a variable 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.

AES Thames, LLC (“Thames”), a 208 MW coal−fired plant in Connecticut, filed petitions for bankruptcy protection under Chapter 11 in the U.S. Bankruptcy Court on February 1, 2011. Effective that date, the Company lost control of the business and is no longer able to exercise significant influence over its operating and financial policies. In accordance with the accounting guidance on consolidations, Thames was deconsolidated in February 2011 and is now accounted for as a cost method investment. At the time of deconsolidation, Thames had total assets and total liabilities of $158 million and $170 million, respectively. Subsequently, the Company paid $5 million in satisfaction of a pre-existing guarantee. Anet gain of $7 million has been deferred pending the completion of the bankruptcy proceedings.

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,for interim financial information and Article 10 of Regulation S-X issued by the U.S. 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, 2011 are not necessarily indicative of results that may be expected for the year ending December 31, 2011. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2010 audited consolidated financial statements and notes thereto, which are included in the June 2011 Form 8-K.

Change in Estimate

On January 1, 2011, the Company changed its estimates related to depreciation of property, plant and equipment at its Brazilian concessionary utility and generation businesses. Based on recent information received from regulators, the depreciation rates and salvage values for its concession assets were adjusted on a prospective basis to reflect a remuneration basis, which equates to the reimbursement expected by the Company at the end of the respective concession periods. For the three months ended September 30, 2011, the impact to the condensed consolidated statement of operations was an increase in depreciation expense of $17 million and a decrease in net income attributable to The AES Corporation of $5 million, or $0.01 per share.For the nine months ended September 30, 2011, the impact to the condensed consolidated statement of operations was an increase in depreciation expense of $52 millionand a decrease in net income attributable to The AES Corporation of $14 million, or $0.02 per share.

New Accounting Policies Adopted

Accounting Standards Update (“ASU”) No. 2009-13, Revenue Recognition (Topic 605), “Multiple-Deliverable Revenue Arrangements”

In October 2009, the FASB issued ASU No. 2009-13, which amended the accounting guidance related to revenue recognition. The amended guidance provides primarily two changes to the prior guidance for multiple-element revenue arrangements. The first eliminated the requirement that there be “objective and reliable evidence” of fair value for any undelivered items in order for a delivered item to be treated as a separate unit of accounting. The second required that the consideration from multiple-element revenue arrangements be allocated to all the deliverables based on their relative selling price at the inception of the arrangement. AES adopted the standard on January 1, 2011. AES elected prospective adoption and applied the revised guidance to all revenue arrangements entered into or materially modified after the date of adoption. The adoption of ASU No. 2009-13 did not have a material impact on the financial position and results of operations of AES and is not expected to have a material impact in future periods.

ASU No. 2010-28, Intangibles—Goodwill and Other (Topic 350), “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”

In December 2010, the FASB issued ASU No. 2010-28, which amended the accounting guidance related to goodwill. The amendment modified Step One of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step Two of the goodwill impairment test if it is more likely than not that a goodwill impairment exists, eliminating an entity's ability to assert that a reporting unit is not required to perform Step Two because the carrying amount of the reporting unit is zero or negative, despite the existence of qualitative factors that indicate the goodwill is more likely than not impaired. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. The Company adopted ASU No. 2010-28 on January 1, 2011. The adoption did not have any impact on the Company as none of its reporting units with goodwill has a zero or negative carrying amount.

ASU No. 2011-2, Receivables (Topic 310), “A Creditor's Determination of Whether a Restructuring Is a Troubled Debt Restructuring”

In April 2011, the FASB issued ASU No. 2011-2, which provides additional guidance and clarification to help creditors determine whether a creditor has granted a concession and whether a debtor is experiencing financial difficulties for purposes of determining whether a restructuring constitutes a troubled debt restructuring. The Company adopted ASU No. 2011-2 on July 1, 2011. The adoption did not have any impact on the Company's financial position, results of operations or cash flows.

ASU No. 2011-8, Intangibles—Goodwill and Other (Topic 350), “Testing Goodwill for Impairment”

In September 2011, the FASB issued ASU No. 2011-8, which amends the existing guidance for goodwill impairment testing. Under the amendments in ASU No. 2011-8, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after this qualitative assessment, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. Also, an entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. The amendments do not change the existing accounting guidance on how Step 1 and Step 2 of the goodwill impairment test are performed. In addition, an entity is no longer permitted to carry forward its detailed calculation of a reporting unit's fair value from a prior year as previously permitted under the existing guidance. ASU No. 2011-8 is effective for annual and interim goodwill impairment tests performed for fiscal periods beginning on or after December 15, 2011 and early adoption is permitted. AES elected to early adopt ASU No. 2011-8 for its annual goodwill impairment evaluations, which are performed at October 1 each year. The adoption is not expected to have a material impact on the Company's financial position, results of operations or cash flows in current or future periods.

Accounting Pronouncements Issued But Not Yet Effective

As of September 30, 2011, the following accounting standards have been issued, but are not yet effective for, and have not been adopted by AES.

ASU No. 2011-4, Fair Value Measurements (Topic 820), “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS”

In May 2011, the FASB issued ASU No. 2011-4,which among other requirements, prohibits the use of the block discount factor for all fair value level hierarchies; permits an entity to measure the fair value of its financial instruments on a net basis when the related market risks are managed on a net basis; states the highest and best use concept is no longer relevant in the measurement of financial assets and liabilities; clarifies that a reporting entity should disclose quantitative information about the unobservable inputs used in Level 3 measurements and that the application of premiums and discounts is related to the unit of account for the asset or liability being measured at fair value; and requires expanded disclosures to describe the valuation process used for Level 3 measurements and the sensitivity of Level 3 measurements to changes in unobservable inputs. In addition, entities are required to disclose the hierarchy level for items which are not measured at fair value in the statement of financial position, but for which fair value is required to be disclosed. ASU No. 2011-4 is effective for the first interim or annual period beginning on or after December 15, 2011, or January 1, 2012 for AES. The adoption is not expected to have a material impact on the Company's financial position, results of operations or cash flows.

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Pension Plans (Tables)

3 Months Ended

Sep. 30, 2011

Pension Plans Tables [Abstract]

Net Periodic Benefit Cost Table

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011				2010				2011				2010
	U.S.		Foreign		U.S.		Foreign		U.S.		Foreign		U.S.		Foreign
	(in millions)								(in millions)
Service cost	$	1	$	6	$	1	$	3	$	5	$	16	$	4	$	12
Interest cost		8		145		8		129		24		436		24		380
Expected return on plan assets		(8)		(130)		(7)		(108)		(24)		(391)		(22)		(318)
Amortization of prior service cost		1		-		1		-		3		-		3		-
Amortization of net loss		3		6		3		4		10		18		9		11
Loss on curtailment		-		-		-		-		-		4		-		-
Total pension cost	$	5	$	27	$	6	$	28	$	18	$	83	$	18	$	85

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Financing Receivables

3 Months Ended

Sep. 30, 2011

FINANCING RECEIVABLES

7. FINANCING RECEIVABLES

Accounts and notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable by considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other available evidence of the collectability, and records an allowance for doubtful accounts for the estimated uncollectable amount as appropriate. Certain of our businesses charge interest on accounts receivable under contractual terms or where charging interest is a customary business practice. In such cases, interest income is recognized on an accrual basis. In situations where the collection of interest is uncertain, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectable.

Included in “Noncurrent other assets” on the condensed consolidated balance sheets as of September 30, 2011 and December 31, 2010 are long-term financing receivables of $282 million and $151 million, respectively, primarily with certain Latin American governmental bodies. These receivables have contractual maturities of greater than one year and are being collected in installments as scheduled. Of the total $282 million as of September 30, 2011, $220 million and $50 million, respectively, relate to our businesses in Argentina and the Dominican Republic. The remaining amounts relate to our distribution businesses in Brazil.

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Segments

3 Months Ended

Sep. 30, 2011

SEGMENTS

12. SEGMENTS

The Company's current management reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The segment reporting structure uses the Company's management reporting structure as its foundation to reflect how the Company manages the business internally.On September 6, 2011, the Company announced the appointment of Andrés Gluski as its President and Chief Executive Officer. Subsequently, on October 18, 2011, the Company announced a plan to redefine its operational management and organizational structure. The planned reporting structure will remain organized along two lines of business – Generation and Utilities, however, we are continuing to evaluate both the timing and impact, if any, that the realignment will have on our reportable segments. For the three and nine months ended September 30, 2011 the Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and concluded it has the following six reportable segments:

•       Latin America—Generation;

•       Latin America—Utilities;

•       North America—Generation;

•       North America—Utilities;

•       Europe—Generation; and

•       Asia—Generation.

Corporate and Other—The Company's Europe Utilities, Africa Utilities, Africa Generation, Wind Generation operating segments and other climate solutions and renewables projects are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our presentation of reportable segments, individually or in the aggregate. AES Solar and certain other unconsolidated businesses are accounted for using the equity method of accounting; therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Consolidated Statements of Operations, not in revenue or gross margin. “Corporate and Other” also includes costs related to corporate overhead costs which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

The Company uses Adjusted Gross Margin, a non-GAAP measure, to evaluate the performance of its segments. Adjusted Gross Margin is defined by the Company as: Gross Margin plus depreciation and amortization less general and administrative expenses.

Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain self insurance activities which are reflected within segment Adjusted Gross Margin. All intra-segment activity has been eliminated with respect to revenue and Adjusted Gross Margin within the segment. Inter-segment activity has been eliminated within the total consolidated results. All balance sheet information for businesses that were discontinued or classified as held for sale as of September 30, 2011 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.

Information about the Company's operations by segment for the three and nine months ended September 30, 2011 and 2010 was as follows:

Three Months Ended	Total Revenue				Intersegment				External Revenue
September 30,	2011		2010		2011		2010		2011		2010
	(in millions)
Latin America - Generation	$	1,302	$	1,111	$	(328)	$	(267)	$	974	$	844
Latin America - Utilities		1,930		1,757		-		-		1,930		1,757
North America - Generation		372		413		-		-		372		413
North America - Utilities		321		306		-		-		321		306
Europe - Generation		397		282		-		-		397		282
Asia - Generation		172		136		-		-		172		136
Corp/Other & eliminations		(113)		(15)		328		267		215		252
Total Revenue	$	4,381	$	3,990	$	-	$	-	$	4,381	$	3,990

Nine Months Ended	Total Revenue				Intersegment				External Revenue
September 30,	2011		2010		2011		2010		2011		2010
	(in millions)
Latin America - Generation	$	3,810	$	3,178	$	(842)	$	(778)	$	2,968	$	2,400
Latin America - Utilities		5,774		5,236		-		-		5,774		5,236
North America - Generation		1,116		1,173		(4)		-		1,112		1,173
North America - Utilities		890		869		-		-		890		869
Europe - Generation		1,125		864		(1)		-		1,124		864
Asia - Generation		449		491		-		-		449		491
Corp/Other & eliminations		(47)		(34)		847		778		800		744
Total Revenue	$	13,117	$	11,777	$	-	$	-	$	13,117	$	11,777

Three Months Ended	Total Adjusted Gross Margin				Intersegment				External Adjusted Gross Margin
September 30,	2011		2010		2011		2010		2011		2010
	(in millions)
Latin America - Generation	$	505	$	436	$	(313)	$	(262)	$	192	$	174
Latin America - Utilities		378		306		322		267		700		573
North America - Generation		145		146		3		5		148		151
North America - Utilities		113		118		-		-		113		118
Europe - Generation		128		71		2		2		130		73
Asia - Generation		35		51		-		1		35		52
Corp/Other & eliminations		(62)		12		(14)		(13)		(76)		(1)
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization										(313)		(271)
Interest expense										(432)		(381)
Interest income										103		96
Other expense										(76)		(23)
Other income										58		17
Goodwill impairment										(17)		(18)
Asset impairment expense										(163)		(296)
Foreign currency transaction (losses) gains on net monetary position										(92)		103
Other non-operating expense										(82)		(2)
Income from continuing operations before taxes and equity in earnings of affiliates									$	228	$	365

Nine Months Ended	Total Adjusted Gross Margin				Intersegment				External Adjusted Gross Margin
September 30,	2011		2010		2011		2010		2011		2010
	(in millions)
Latin America - Generation	$	1,493	$	1,296	$	(800)	$	(766)	$	693	$	530
Latin America - Utilities		1,035		888		820		778		1,855		1,666
North America - Generation		402		406		6		12		408		418
North America - Utilities		292		324		1		1		293		325
Europe - Generation		327		287		4		5		331		292
Asia - Generation		133		204		1		3		134		207
Corp/Other & eliminations		(37)		19		(32)		(33)		(69)		(14)
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization										(909)		(802)
Interest expense										(1,178)		(1,151)
Interest income										293		304
Other expense										(131)		(83)
Other income										108		94
Gain on sale of investments										7		-
Goodwill impairment										(17)		(18)
Asset impairment expense										(196)		(297)
Foreign currency transaction (losses) gains on net monetary position										(21)		(19)
Other non-operating expense										(82)		(7)
Income from continuing operations before taxes and equity in earnings of affiliates									$	1,519	$	1,445

Assets by segment as of September 30, 2011 and December 31, 2010 were as follows:

	Total Assets
	September 30, 2011		December 31, 2010
	(in millions)
Assets
Latin America - Generation	$	10,545	$	10,373
Latin America - Utilities		8,938		9,872
North America - Generation		4,403		4,681
North America - Utilities		3,218		3,139
Europe - Generation		4,264		4,178
Asia - Generation		1,725		1,762
Discontinued businesses		407		468
Corp/Other & eliminations		7,383		6,038
Total Assets	$	40,883	$	40,511

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Debt

3 Months Ended

Sep. 30, 2011

DEBT

8. 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, distribution companies and other project-related investments at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. Absent guarantees, intercompany loans or other credit support, the default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries, though the Company's equity investments and/or subordinated loans to projects (if any) are at risk. 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.

The following table summarizes the carrying amount and estimated fair values of the Company's recourse and non-recourse debt as of September 30, 2011 and December 31, 2010:

	September 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(in millions)
Non-recourse debt	$	14,686	$	14,885	$	14,938	$	15,269
Recourse debt		6,192		6,216		4,612		4,868
Total debt	$	20,878	$	21,101	$	19,550	$	20,137

Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated differently based upon the type of loan. The fair value of fixed rate loans is estimated using quoted market prices, if available, or a discounted cash flow analysis. In the discounted cash flow analysis, the discount rate is based on the credit rating of the individual debt instruments if available, or the credit rating of the subsidiary. If the subsidiary's credit rating is not available, a synthetic credit rating is determined using certain key metrics, including cash flow ratios and interest coverage, as well as other industry specific factors. For subsidiaries located outside the U.S., in the event that the country rating is lower than the credit rating previously determined, the country rating is used for the purposes of the discounted cash flow analysis. The fair value of recourse and non-recourse debt excludes accrued interest at the valuation date.

The fair value was determined using available market information as of September 30, 2011. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to September 30, 2011.

Non-Recourse Debt

The following table summarizes the Company's subsidiary non-recourse debt in default or acceleratedas of September 30, 2011 and is in the current portion of non-recourse debt unless otherwise indicated:

	Primary Nature	September 30, 2011
Subsidiary	of Default	Default Amount		Net Assets
		(in millions)
Maritza	Covenant	$	935	$	216
Sonel	Covenant		342		306
Kelanitissa	Covenant		22		6
Total		$	1,299

Included in “Current liabilities of discontinued and held for sale businesses” in the condensed consolidated balance sheet as of September 30, 2011 is approximately $203 million of non-recourse debt relating to our businesses in New York, which has been classified as current due to certain facts and circumstances that create significant uncertainty about the business's ability to generate sufficient cash flows and remain in compliance with the terms of its contractual obligations in the next twelve months.

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES' corporate debt agreements as of September 30, 2011 in order to trigger an event of default or permit acceleration under such indebtedness. The bankruptcy or acceleration of material amounts of debt at such entities would cause a cross default under the recourse senior secured credit facility. 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 or the financial position or results of operations of an individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby a bankruptcy or an acceleration of its non-recourse debt trigger an event of default and possible acceleration of the indebtedness under the AES Parent Company's outstanding debt securities.

On October 3, 2011, Dolphin Subsidiary II, Inc. (“Dolphin II”), a newly formed, wholly owned special purpose indirect subsidiary of AES, entered into an indenture (the "Indenture") with Wells Fargo Bank, N.A. (the "Trustee") as part of its issuance of $450 million aggregate principalamount of 6.50% senior notes due 2016 (the "2016 Notes") and $800 million aggregate principal amount of 7.25% senior notes due 2021 (the "7.25% 2021 Notes", together with the 2016 Notes, the "notes") to finance the pending acquisition (the "Acquisition") by AES of DPL Inc. ("DPL"). See Note 17—Acquisitionsfor further information.

Interest on the 2016 Notes and the 7.25% 2021 Notesaccrues at a rate of 6.50% and 7.25% per year, respectively, and is payable on April 15 and October 15 of each year, beginning April 15, 2012. Prior to September 15, 2016 with respect to the 2016 Notes orJuly 15, 2021 with respect to the 7.25% 2021 Notes, Dolphin II may redeem some or all of the 2016 Notes or 7.25% 2021 Notes at par, plus a "make-whole" amount setforth in the Indenture and accrued and unpaid interest. At any time on or after September 15, 2016 or July 15, 2021 with respect to the 2016 Notes and 7.25% 2021 Notes, respectively, Dolphin II may redeem some or all of the 2016 Notes or 7.25% 2021 Notes at par plus accrued and unpaid interest.

The proceeds from issuance of the notes were deposited into an escrow account pledged for the benefit of the Trustee pending the consummation of theAcquisition. The notes are subject to a special mandatory redemption at a price of 101% of the offering price of the notes plus accrued and unpaid interest inthe event that the Acquisition is not consummated on or before September 30, 2012. If the acquisition closes on or before such date, Dolphin II will concurrently merge with and into DPL, with DPL being the surviving company and obligor under the notes.

On September 28, 2011, the Company provided a letter of credit for approximately $115 million in favor of the escrow agent for the benefit of the Trustee pending the consummation of the Acquisition to cover payment of the interest expense from October 3, 2011 to September 30, 2012, the discount paid to the initial purchasers of the notes and special mandatory redemption price of 1% of the offering price of the notes. On September 29, 2011, at the instructions of the Dolphin II, escrow agent drew the entire amount of the letter of credit and deposited into the same escrow account for the benefit of the Trustee pending the consummation of the Acquisition. At the Acquisition consummation, any excess amount in the escrow account will be returned to Dolphin II.

Recourse Debt

During the nine months ended September 30, 2011, the Company secured recourse debt of $2.05 billion.The proceeds of the debtmay, among other things, be used to partially finance the Company's contemplated acquisition of DPL Inc, as discussed further in Note 17—Acquisitions.

On May 27, 2011, the Companysecureda $1.05 billion term loan under a senior secured credit facility (the "senior secured term loan"). The senior secured term loan will bear annual interest, at the Company's option, at a variable rate of LIBOR plus 3.25% or Base Rate plus 2.25%, and will mature on the seventh anniversary of the closing date.The senior secured term loan issubject tocertain customary representations, covenants and events of default.

On June 15, 2011, the Company issued $1 billion aggregate principal amount of 7.375% senior unsecured notes maturing July 1, 2021 (the "7.375% 2021 Notes"). Upon a change of control, the Company must offer to repurchase the 7.375% 2021 Notes at a price equal to 101% of principal, plus accrued and unpaid interest. The 7.375% 2021 Notes are also subject to certain covenants restricting the ability of the Company to incur additional secured debt; to enter into sale-lease back transactions; to consolidate, merge, convey or transfer substantially all of its assets; as well as other covenants and events of default that are customary for debt securities similar to the 7.375% 2021 Notes.The Company entered into interest rate locks in May 2011 to hedge the risk of changes in LIBOR until the issuance of the 7.375% 2021 Notes. The Company paid $24 million to settle those interest rate locks as of June 15, 2011. The payment was recognized in accumulated other comprehensive loss and is being amortized over the life of the 7.375% 2021 Notes.

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Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Sep. 30, 2011

Derivative Instruments And Hedging Activities Tables [Abstract]

Interest Rate Derivatives By Type Table

		September 30, 2011
		Current			Maximum(1)
			Derivative			Derivative		Weighted	% of Debt
			Notional			Notional		Average	Currently
		Derivative	Translated		Derivative	Translated		Remaining	Hedged
Interest Rate Derivatives		Notional	to USD		Notional	to USD		Term(1)	by Index(2)
		(in millions)						(in years)
Libor (U.S. Dollar)		3,511	$	3,511	3,585	$	3,585	9	75%
Euribor (Euro)		1,072		1,435	1,072		1,435	13	66%
Libor (British Pound Sterling)		63		98	72		112	12	87%
Securities Industry and Financial
	Markets Association Municipal
	Swap Index (U.S. Dollar)	40		40	40		40	11	N/A(3)

Cross Currency Derivatives By Type Table

	September 30, 2011
				Weighted	% of Debt
		Notional		Average	Currently
		Translated		Remaining	Hedged
Cross Currency Swaps	Notional	to USD		Term(1)	by Index(2)
	(in millions)			(in years)
Chilean Unidad de Fomento (CLF)	6	$	237	14	83%

Foreign Currency Options By Type Table

	September 30, 2011
						Weighted
		Notional		Probability		Average
		Translated		Adjusted		Remaining
Foreign Currency Options	Notional	to USD(1)		Notional(2)		Term(3)
	(in millions)					(in years)
Brazilian Real (BRL)	173	$	105	$	96	<1
Euro (EUR)	67		96		82	<1
British Pound (GBP)	29		47		40	<1
Argentine Peso (ARS)	88		20		8	<1

Foreign Currency Forwards By Type Table

	September 30, 2011
		Notional		Weighted Average
Foreign Currency Forwards	Notional	Translated to USD		Remaining Term(1)
	(in millions)			(in years)
Chilean Peso (CLP)	98,944	$	201	<1
Euro (EUR)	123		169	2
Colombian Peso (COP)	80,376		44	<1
British Pound (GBP)	11		17	1
Argentine Peso (ARS)	61		13	1

Embedded Foreign Currency Derivatives By Type Table

	September 30, 2011
		Notional		Weighted Average
Embedded Foreign Currency Derivatives	Notional	Translated to USD		Remaining Term(1)
	(in millions)			(in years)
Philippine Peso (PHP)	15,973	$	363	2
Argentine Peso (ARS)	904		215	11
Kazakhstani Tenge (KZT)	30,606		207	9
Hungarian Forint (HUF)	10,114		46	<1
Euro (EUR)	20		27	2
Brazilian Real (BRL)	4		2	1

Commodity Non Hedge Derivatives By Type Table

	September 30, 2011
		Weighted Average
Commodity Derivatives	Notional	Remaining Term(1)
	(in millions)	(in years)
Natural gas (MMBTU)	33	11
Aluminum (MWh)	16(2)	8
Petcoke (Metric tons)	13	13

Fair Value Hierarchy Derivative Assets Liabilities By Balance Sheet Classification Table

				September 30, 2011								December 31, 2010
				Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
				(in millions)								(in millions)
Assets
Current assets:
	Foreign currency derivatives			$	-	$	48	$	4	$	52	$	-	$	4	$	3	$	7
	Commodity and other derivatives				-		-		5		5		-		2		3		5
		Total current assets			-		48		9		57		-		6		6		12
Noncurrent assets:
	Interest rate derivatives				-		-		-		-		-		49		-		49
	Cross currency derivatives				-		-		1		1		-		-		12		12
	Foreign currency derivatives				-		5		49		54		-		4		27		31
	Commodity and other derivatives				-		4		1		5		-		4		16		20
		Total noncurrent assets			-		9		51		60		-		57		55		112
			Total assets	$	-	$	57	$	60	$	117	$	-	$	63	$	61	$	124
Liabilities
Current liabilities:
	Interest rate derivatives			$	-	$	102	$	29	$	131	$	-	$	137	$	-	$	137
	Cross currency derivatives				-		-		5		5		-		-		2		2
	Foreign currency derivatives				-		6		1		7		-		13		-		13
	Commodity and other derivatives				-		5		3		8		-		-		-		-
		Total current liabilities			-		113		38		151		-		150		2		152
Long-term liabilities:
	Interest rate derivatives				-		294		162		456		-		246		1		247
	Cross currency derivatives				-		-		17		17		-		-		-		-
	Foreign currency derivatives				-		11		11		22		-		15		8		23
	Commodity and other derivatives				-		1		41		42		-		-		1		1
		Total long-term liabilities			-		306		231		537		-		261		10		271
			Total liabilities	$	-	$	419	$	269	$	688	$	-	$	411	$	12	$	423

Derivative Assets Liabilities At Fair Value Net By Balance Sheet Classification And Type Table

		September 30, 2011						December 31, 2010
				Not						Not
		Designated		Designated				Designated		Designated
		as Hedging		as Hedging				as Hedging		as Hedging
		Instruments		Instruments		Total		Instruments		Instruments		Total
		(in millions)						(in millions)
Assets
Current assets:
	Foreign currency derivatives	$	17	$	35	$	52	$	-	$	7	$	7
	Commodity and other derivatives		-		5		5		-		5		5
	Total current assets		17		40		57		-		12		12
Noncurrent assets:
	Interest rate derivatives		-		-		-		49		-		49
	Cross currency derivatives		1		-		1		12		-		12
	Foreign currency derivatives		2		52		54		-		31		31
	Commodity and other derivatives		-		5		5		-		20		20
	Total noncurrent assets		3		57		60		61		51		112
Total assets		$	20	$	97	$	117	$	61	$	63	$	124
Liabilities
Current liabilities:
	Interest rate derivatives	$	126	$	5	$	131	$	126	$	11	$	137
	Cross currency derivatives		5		-		5		2		-		2
	Foreign currency derivatives		1		6		7		8		5		13
	Commodity and other derivatives		-		8		8		-		-		-
	Total current liabilities		132		19		151		136		16		152
Long-term liabilities:
	Interest rate derivatives		437		19		456		232		15		247
	Cross currency derivatives		17		-		17		-		-		-
	Foreign currency derivatives		-		22		22		-		23		23
	Commodity and other derivatives		-		42		42		-		1		1
	Total long-term liabilities		454		83		537		232		39		271
Total liabilities		$	586	$	102	$	688	$	368	$	55	$	423

Accumulated Other Comprehensive Income Loss Derivatives Table

	Accumulated
	Other Comprehensive
	Income (Loss)
	(in millions)
Interest rate derivatives	$	(116)
Cross currency derivatives	$	(1)
Foreign currency derivatives	$	16

Gain Loss In Accumulated Other Comprehensive Income And Earnings On Effective Portion Of Qualifying Cash Flow Hedges Table

		Gains (Losses)						Gains (Losses) Reclassified
		Recognized in AOCL						from AOCL into Earnings(1)
		Three Months				Classification in		Three Months
		Ended September 30,				Condensed Consolidated		Ended September 30,
		2011		2010		Statements of Operations		2011		2010
		(in millions)						(in millions)
Interest rate derivatives		$	(297)	$	(138)	Interest expense		$	(35) (2)	$	(24) (2)
						Non-regulated cost of sales			(1) (2)		(3) (2)
						Net equity in earnings of
							affiliates		(1)		(1)
Cross currency derivatives			(37)		24	Interest expense			(3)		-
						Foreign currency transaction
							gains (losses)		(26)		30
Foreign currency derivatives			29		(12)	Foreign currency transaction
							gains (losses)		3		1
Commodity and other
	derivatives		-		(4)	Non-regulated cost of sales			(2)		-
Total		$	(305)	$	(130)			$	(65)	$	3

		Gains (Losses)						Gains (Losses) Reclassified
		Recognized in AOCL						from AOCL into Earnings(1)
		Nine Months				Classification in		Nine Months
		Ended September 30,				Condensed Consolidated		Ended September 30,
		2011		2010		Statements of Operations		2011		2010
		(in millions)						(in millions)
Interest rate derivatives		$	(389)	$	(388)	Interest expense		$	(88) (2)	$	(81) (2)
						Non-regulated cost of sales			(3) (2)		(3) (2)
						Net equity in earnings of
							affiliates		(3)		(3)
Cross currency derivatives			(34)		(5)	Interest expense			(7)		(1)
						Foreign currency transaction
							gains (losses)		(20)		16
Foreign currency derivatives			27		(5)	Foreign currency transaction
							gains (losses)		(1)		1
Commodity and other
	derivatives		-		(4)	Non-regulated cost of sales			(2)		-
Total		$	(396)	$	(402)			$	(124)	$	(71)

Gain Loss In Earnings On Ineffective Portion Of Qualifying Cash Flow Hedges Table

			Gains (Losses)				Gains (Losses)
			Recognized in Earnings				Recognized in Earnings
	Classification in Condensed		Three Months Ended				Nine Months Ended
	Consolidated Statements		September 30,				September 30,
	of Operations		2011		2010		2011		2010
			(in millions)				(in millions)
Interest rate derivatives	Interest expense		$	1	$	(10)	$	(6)	$	(18)
	Net equity in earnings of
		affiliates		(1)		-(1)		(2)		(1)
Cross currency derivatives	Interest expense			(3)		-(1)		(5)		4
Foreign currency derivatives	Foreign currency transaction
		gains (losses)		- (1)		-(1)		- (1)		-(1)
Total			$	(3)	$	(10)	$	(13)	$	(15)

Gain Loss In Earnings On Non Hedging Instruments Table

				Gains (Losses)				Gains (Losses)
				Recognized in Earnings				Recognized in Earnings
		Classification		Three Months Ended				Nine Months Ended
		in Condensed Consolidated		September 30,				September 30,
		Statements of Operations		2011		2010		2011		2010
				(in millions)				(in millions)
Interest rate derivatives		Interest expense		$	(1)	$	(3)	$	(2)	$	(8)
Foreign exchange derivatives		Foreign currency transaction
			gains (losses)		27		(7)		54		(32)
		Net equity in earnings
			of affiliates		-		-		-		2
Commodity and other
	derivatives	Non-regulated revenue			(54)		1		(63)		5
		Non-regulated cost of sales			3		(3)		2		2
Total				$	(25)	$	(12)	$	(9)	$	(31)

Regulatory Asset Liability Change In Fair Value Of Derivatives

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(in millions)
(Increase) decrease in regulatory assets	$	(4)	$	(3)	$	(6)	$	(6)
Increase (decrease) in regulatory liabilities	$	(3)	$	(2)	$	3	$	2

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Investments In and Advances To Affiliates

3 Months Ended

Sep. 30, 2011

INVESTMENTS IN AND ADVANCES TO AFFILIATES

6. INVESTMENTS IN AND ADVANCES TO AFFILIATES

In February 2011, the Company acquired a 49.6% interest in Entek Elektrik Uretim A.S. (“Entek”) for approximately $136 million. Additional purchase considerationof $13 million was paid in May 2011, increasing the total purchase consideration to $149 million. Entek owns and operates two gas-fired generation facilities in Turkey with an aggregate capacity of 312 MW, and is also engaged in an energy trading business. The Company has significant influence, but not control, of Entek and accordingly the investment has been accounted for under the equity method of accounting.

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Equity (Details) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended	3 Months Ended		9 Months Ended		21 Months Ended	22 Months Ended
	Nov. 03, 2011	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Nov. 03, 2011	Dec. 31, 2010
Stock Repurchase Plan [Abstract]
Stock Repurchase Program, Authorized Amount						$ 500
Acquisition of treasury stock (shares)	5,554,185			19,987,795		28,370,620	33,924,805
Treasury Stock Value Acquired Cost Method Excluding Commissions	54			224		324	378
Treasury Stock Acquired Average Cost Per Share				$ 11.24		$ 11.42
Treasury stock, shares		36,832,776		36,832,776		36,832,776		17,287,073
Components Of Comprehensive Income
Net income		175	397	1,085	1,228
Change in fair value of available-for-sale securities, net of income tax benefit of $0, $0, $1 and $4, respectively		(1)	0	(3)	(6)
Foreign currency translation adjustments, net of income tax (expense) of $42, $(15), $28 and $(7), respectively		(589)	285	(327)	519
Derivative activity:
Reclassification to earnings, net of income tax (expense) of $(13), $(3), $(15) and $(22), respectively		53	13	112	81
Change in derivative fair value, net of income tax benefit of $68, $23, $93 and $82, respectively		(236)	(99)	(305)	(336)
Total net change in fair value of derivatives		(183)	(86)	(193)	(255)
Change in unfunded pension obligation, net of income tax (expense) of $(2), $(1), $(6) and $(3), respectively		5	1	12	6
Other comprehensive income (loss)		(768)	200	(511)	264
Comprehensive income (loss)		(593)	597	574	1,492
Less: Comprehensive (income) loss attributable to noncontrolling interests		(12)	385	651	789
Comprehensive income (loss) attributable to The AES Corporation		(581)	212	(77)	703
Components Of Comprehensive Income (Parentheticals)
Change in fair value of available-for-sale securities, income tax		0	0	1	4
Foreign currency translation adjustments, income tax		42	(15)	28	(7)
Derivative reclassification to earnings, income tax		(13)	(3)	(15)	(22)
Change in derivative fair value, income tax		68	23	93	82
Change in unfunded pension obligation, income tax		(2)	(1)	(6)	(3)
Accumulated Other Comprehensive Loss
Foreign currency translation adjustment		2,002		2,002		2,002		1,824
Unrealized derivative losses, net		511		511		511		344
Unfunded pension obligation		212		212		212		216
Securities available-for-sale		2		2		2		(1)
Accumulated other comprehensive loss		2,727		2,727		2,727		2,383
Net Income Attributable To Parent And Transfers To From Noncontrolling Interests [Abstract]
Net income (loss) attributable to The AES Corporation		(131)	114	267	445
Transfers To From Noncontrolling Interests [Abstract]
Net increase in The AES Corporation's paid-in capital for sale of subsidiary shares		19	0	19	0
Net transfers (to) from noncontrolling interest		19	0	19	0
Change from net income attributable to The AES Corporation and transfers (to) from noncontrolling interests		$ (112)	$ 114	$ 286	$ 445
Mong Duong [Member]
Subsidiary or Equity Method Investee [Line Items]
Equity interest purchased				10.00%
Generation Capacity (MW)		1,200		1,200		1,200
Ownership in Mong Duong after all transactions				51.00%
Mong Duong [Member] | Posco [Member]
Subsidiary or Equity Method Investee [Line Items]
Equity interest sold				30.00%
Mong Duong [Member] | CIC [Member]
Subsidiary or Equity Method Investee [Line Items]
Equity interest sold				19.00%

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Condensed Consolidated Statements of Cash Flows (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
OPERATING ACTIVITIES:
Net income	$ 1,085	$ 1,228
Adjustments to net income:
Depreciation and amortization	947	876
Loss from sale of investments and impairment expense	321	350
(Gain) loss on disposal and impairment write-down - discontinued operations	1	(102)
Provision for deferred taxes	(67)	31
Contingencies	36	75
Loss on the extinguishment of debt	52	9
Noncontrolling interest of discontinued operations	0	0
Undistributed gain from sale of equity method investment	0	(118)
Other	65	(81)
Changes in operating assets and liabilities:
Increase in accounts receivable	(185)	(136)
(Increase) decrease in inventory	(118)	9
Decrease in prepaid expenses and other current assets	62	194
Increase in other assets	(167)	(51)
Increase in accounts payable and accrued liabilities	200	4
Increase (decrease) in income taxes and other income tax payables, net	(151)	20
Increase in other liabilities	227	108
Net cash provided by operating activities	2,308	2,416
INVESTING ACTIVITIES:
Capital expenditures	(1,832)	(1,528)
Acquisitions - net of cash acquired	(158)	(237)
Proceeds from the sale of businesses	47	369
Proceeds from the sale of assets	89	11
Sale of short-term investments	4,191	4,583
Purchase of short-term investments	(3,632)	(4,540)
Increase in restricted cash	(164)	(82)
Increase in debt service reserves and other assets	(379)	(9)
Affiliate advances and equity investments	(91)	(77)
Proceeds from loan repayments	0	132
Proceeds from performance bonds	199	0
Other investing	(4)	31
Net cash used in investing activities	(1,734)	(1,347)
FINANCING ACTIVITIES:
Issuance of common stock	0	1,566
Borrowings under the revolving credit facilities, net	126	74
Issuance of recourse debt	2,050	0
Issuance of non-recourse debt	1,516	1,497
Repayments of recourse debt	(474)	(619)
Repayments of non-recourse debt	(1,489)	(1,441)
Payments for financing fees	(153)	(50)
Distributions to noncontrolling interests	(990)	(951)
Contributions from noncontrolling interests	6	0
Financed capital expenditures	(13)	(21)
Purchase of treasury stock	(225)	(15)
Other financing	(7)	(18)
Net cash provided by financing activities	347	22
Effect of exchange rate changes on cash	(79)	(21)
Total increase in cash and cash equivalents	842	1,070
Cash and cash equivalents, beginning	2,550	1,775
Cash and cash equivalents, ending	3,392	2,845
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	982	1,003
Cash payments for income taxes, net of refunds	$ 647	$ 589

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Inventory

3 Months Ended

Sep. 30, 2011

INVENTORY

2. INVENTORY

The following table summarizes the Company's inventory balances as of September 30, 2011 and December 31, 2010:

	September 30,		December 31,
	2011		2010
	(in millions)
Coal, fuel oil and other raw materials	$	377	$	276
Spare parts and supplies		291		285
Total	$	668	$	561

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Discontinued Operations and Held For Sale Businesses (Tables)

3 Months Ended

Sep. 30, 2011

Discontinued Operations And Held For Sale Business Tables [Abstract]

Revenue Income From Operations Of Discontinued Businesses Income Tax Expense And Impairment Of Discontinued Operations

		Three Months				Nine Months
		Ended September 30,				Ended September 30,
		2011		2010		2011		2010
		(in millions)
Revenue		$	107	$	218	$	327	$	948
(Loss) income from operations of discontinued businesses		$	(6)	$	37	$	(10)	$	115
Income tax benefit (expense)			31		(8)		33		(23)
Income from operations of discontinued
	businesses, net of tax	$	25	$	29	$	23	$	92
Gain on sale of discontinued operations		$	-	$	79	$	-	$	57

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Investments In Marketable Securities (Tables)

3 Months Ended

Sep. 30, 2011

Investments In Marketable Securities Tables [Abstract]

Marketable Securities By Type Table

		September 30, 2011								December 31, 2010
		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
		(in millions)
AVAILABLE-FOR-SALE:(1)
Debt securities:
	Unsecured debentures(2)	$	-	$	498	$	-	$	498	$	-	$	723	$	-	$	723
	Certificates of deposit(2)		-		447		-		447		-		876		-		876
	Government debt securities		-		40		-		40		-		47		-		47
	Other debt securities		-		-		40		40		-		-		42		42
	Subtotal		-		985		40		1,025		-		1,646		42		1,688
Equity securities:
	Mutual funds		-		56		-		56		1		61		-		62
	Common stock		2		-		-		2		7		-		-		7
	Subtotal		2		56		-		58		8		61		-		69
Total available-for-sale			2		1,041		40		1,083		8		1,707		42	$	1,757
TRADING:
Equity securities:
	Mutual funds		10		-		-		10		10		-		-		10
Total trading			10		-		-		10		10		-		-		10
TOTAL		$	12	$	1,041	$	40	$	1,093	$	18	$	1,707	$	42	$	1,767

Pre-Tax Gains And Losses On Available For Sale And Trading Securities

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in millions)				(in millions)
Losses included in earnings that relate to trading
	securities held at the reporting date	$	(2)	$	(1)	$	(1)	$	-
Unrealized losses on available-for-sale securities
	included in other comprehensive income	$	(1)	$	-	$	(4)	$	(10)
Proceeds from sales of available-for-sale securities		$	1,134	$	1,420	$	4,218	$	4,644
Gross realized gains on sales		$	1	$	-	$	5	$	2

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Acquisitions (Details) (USD $)	Sep. 30, 2011	Apr. 20, 2011 DPL Acquisition [Member] mw customers	Sep. 30, 2011 Senior Unsecured Note 7375 Due 2021 And Senior Secured Term Loan LIBOR Plus 325 [Member]
Business Acquisition [Line Items]
Total enterprise value of DPL acquisition		$ 4,700,000,000
Amount paid	3,500,000,000	3,500,000,000
Net debt portion of enterprise value of DPL acquisition		1,200,000,000
Customers Served		500,000
Generation Capacity Mega Watts		3,800
Recourse Debt Total			2,050,000,000
Business Acquisition Penalty Receivable From Acquiree For Early Rejection Of Merger Offer		$ 106,000,000

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Regulatory Assets and Liabilities (Details) (Brazil Tariff Estimated Rate Change Liability [Member], USD $) In Millions	Sep. 30, 2011
Brazil Tariff Estimated Rate Change Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 104

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Pension Plans (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
U.S. [Member]
Defined Benefit Plan Net Periodic Benefit Cost Abstract
Service cost	$ 1	$ 1	$ 5	$ 4
Interest cost	8	8	24	24
Expected return on plan assets	(8)	(7)	(24)	(22)
Amortization of prior service cost	1	1	3	3
Amortization of net loss	3	3	10	9
Loss on curtailment	0	0	0	0
Total pension cost	5	6	18	18
Defined Benefit Pension Contributions Disclosure [Abstract]
Defined Benefit Plan Contributions By Employer			30
Defined Benefit Plan Estimated Future Employer Contributions Remainder Of Fiscal Year	7		7
Foreign [Member]
Defined Benefit Plan Net Periodic Benefit Cost Abstract
Service cost	6	3	16	12
Interest cost	145	129	436	380
Expected return on plan assets	(130)	(108)	(391)	(318)
Amortization of prior service cost	0	0	0	0
Amortization of net loss	6	4	18	11
Loss on curtailment	0	0	4	0
Total pension cost	27	28	83	85
Defined Benefit Pension Contributions Disclosure [Abstract]
Defined Benefit Plan Contributions By Employer			132
Defined Benefit Plan Estimated Future Employer Contributions Remainder Of Fiscal Year	$ 39		$ 39

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Fair Value

3 Months Ended

Sep. 30, 2011

FAIR VALUE

3. FAIR VALUE

The fair value of current financial assets and liabilities, debt service reserves and other deposits approximates their reported carrying amounts. The fair value of non-recourse debt is estimated based upon the type of loan. The fair value of variable rate loansgenerally approximates their carrying amounts. For fixed rate loans, fair value is estimated using quoted market prices or discounted cash flow analyses. See Note 8—Debt for additional information on the fair value and carrying value of debt. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards, swaps and options and energy derivatives is the estimated net amount that the Company would receive or pay to sell or transfer the agreements as of the balance sheet date.

The estimated fair values of the Company's assets and liabilities have been determined using available market information. By virtue of these amounts being estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

The following table summarizes the carrying amount and fair value of certain of the Company's financial assets and liabilities as of September 30, 2011 and December 31, 2010:

			September 30, 2011				December 31, 2010
			Carrying		Fair		Carrying		Fair
			Amount		Value		Amount		Value
			(in millions)
Assets
	Marketable securities		$	1,093	$	1,093	$	1,767	$	1,767
	Derivatives			117		117		124		124
		Total assets	$	1,210	$	1,210	$	1,891	$	1,891
Liabilities
	Debt		$	20,878	$	21,101	$	19,550	$	20,137
	Derivatives			688		688		423		423
		Total liabilities	$	21,566	$	21,789	$	19,973	$	20,560

Valuation Techniques:

The fair value measurement accounting guidance describes three main approaches to measuring the fair value of assets and liabilities: (1) market approach; (2) income approach and (3) cost approach. The market approach uses prices and other relevant information generated from market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future amounts to a single present value amount. The measurement is based on current market expectations of the return on those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company measures its investments and derivatives at fair value on a recurring basis. Additionally, in connection with annual or event-driven impairment evaluations, certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis. These include long-lived tangible assets (i.e., property, plant and equipment), goodwill and intangible assets (e.g., sales concessions, land use rights and emissions allowances, etc.). In general, the Company determines the fair value of investments and derivatives using the market approach and the income approach, respectively. In the nonrecurring measurements of nonfinancial assets and liabilities, all three approaches are considered; however, fair value estimated under the income approach is often selected.

Investments

The Company's investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are measured at fair value using quoted market prices. Debt securities primarily consist of unsecured debentures, certificates of deposit and government debt securities held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to London Inter-Bank Offered Rate, or LIBOR, a benchmark interest rate widely used by banks in the interbank lending market) or Selic (overnight borrowing rate) rates in Brazil. Fair value is determined from comparisons to market data obtained for similar assets and are considered Level 2 in the fair value hierarchy. For more detail regarding the fair value of investments see Note 4—Investments in Marketable Securities.

Derivatives

When deemed appropriate, the Company manages its risk from interest and foreign currency exchange rate and commodity price fluctuations through the use of over-the-counter financial and physical derivative instruments. The derivatives are primarily interest rate swaps to hedge non-recourse debt to establish a fixed rate on variable rate debt, foreign exchange instruments to hedge against currency fluctuations, commodity derivatives to hedge against commodity price fluctuations and embedded derivatives associated with commodity contracts. The Company's subsidiaries are counterparties to various over-the-counter derivatives, which include interest rate swaps and options, foreign currency options and forwards and commodity swaps. In addition, the Company's subsidiaries are counterparties to certain power purchase agreements (“PPAs”) and fuel supply agreements that are derivatives or include embedded derivatives.

For the derivatives where there is a standard industry valuation model, the Company uses that model to estimate the fair value. For the derivatives (such PPAs and fuel supply agreements that are derivatives or include embedded derivatives) where there is not a standard industry valuation model, the Company has created internal valuation models to estimate the fair value, using observable data to the extent available. For all derivatives, the income approach is used, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The following are among the most common market data inputs used in the income approach: volatilities, spot and forward benchmark interest rates (such as LIBOR and Euro Inter Bank Offered Rate (“EURIBOR”)), foreign exchange rates and commodity prices. Forward rates and prices are generally obtained from published information provided by pricing services for an instrument with the same duration as the derivative instrument being valued. In situations where significant inputs are not observable, the Company uses relevant techniques to best estimate the inputs, such as regression analysis, Monte Carlo simulation or prices for similarly traded instruments available in the market.

For each derivative, the income approach is used to estimate the cash flows over the remaining term of the contract. Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR or EURIBOR) plus a spread that reflects the credit or nonperformance risk. This risk is estimated by the Company using credit spreads and risk premiums that are observable in the market, whenever possible, or estimated borrowing costs based on bank quotes, industry publications and/or information on financing closed on similar projects. To the extent that management can estimate the fair value of these assets or liabilities without the use of significant unobservable inputs, these derivatives are classified as Level 2.

In certain instances, the published forward rates or prices may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable inputs, such as proxy commodity prices or historical settlements to forecast forward prices. In addition, in certain instances, there may not be third party data readily available, which requires the use of unobservable inputs. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable. The fair value hierarchy of an asset or a liability is based on the level of significance of the input assumptions. An input assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are transferred to Level 3 when the use of unobservable inputs becomes significant. Similarly, when the use of unobservable input becomes insignificant for Level 3 assets and liabilities, they are transferred to Level 2.

Transfers in and out of Level 3 are from and to Level 2 and are determined as of the end of the reporting period. The Company has not had any Level 1 derivatives so there have not been any transfers between Levels 1 and 2.

Nonfinancial Assets and Liabilities

For nonrecurring measurements derived using the income approach, fair value is determined using valuation models based on the principles of discounted cash flows (“DCF”). The income approach is most often used in the impairment evaluation of long-lived tangible assets, goodwill and intangible assets. The Company has developed internal valuation models for such valuations; however, an independent valuation firm may be engaged in certain situations. In such situations, the independent valuation firm largely uses DCF valuation models as the primary measure of fair value though other valuation approaches are also considered. A few examples of input assumptions to such valuations include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates and power and commodity prices. Whenever possible, the Company attempts to obtain market observable data to develop input assumptions. Where the use of market observable data is limited or not possible for certain input assumptions, the Company develops its own estimates using a variety of techniques such as regression analysis and extrapolations.

For nonrecurring measurements derived using the market approach, recent market transactions involving the sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to find sale transactions of identical or similar assets. This approach is used in the impairment evaluations of certain intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.

For nonrecurring measurements derived using the cost approach, fair value is typically determined using the replacement cost approach. Under this approach, the depreciated replacement cost of assets is determined by first determining the current replacement cost of assets and then applying the remaining useful life percentages to such cost. Further adjustments for economic and functional obsolescence are made to the depreciated replacement cost. This approach involves a considerable amount of judgment, which is why its use is limited to the measurement of a few long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach. For the nine months ended September 30, 2011, the Company did not measure any nonfinancial assets under the cost approach.

Fair Value Considerations:

In determining fair value, the Company considers the source of observable market data inputs, liquidity of the instrument, the credit risk of the counterparty and the risk of the Company's or its counterparty's nonperformance. The conditions and criteria used to assess these factors are:

Sources of market assumptions

The Company derives most of its market assumptions from market efficient data sources (e.g., Bloomberg and Platt's). To determine fair value, where market data is not readily available, management uses comparable market sources and empirical evidence to develop its own estimates ofmarket assumptions.

Market liquidity

The Company evaluates market liquidity based on whether the financial or physical instrument, or the underlying asset, is traded in an active or inactive market. An active market exists if the prices are fully transparent to market participants, can be measured by market bid and ask quotes, the market has a relatively large proportion of trading volume as compared to the Company's current trading volume and the market has a significant number of market participants that will allow the market to rapidly absorb the quantity of the assets traded without significantly affecting the market price. Another factor the Company considers when determining whether a market is active or inactive is the presence of government or regulatory controls over pricing that could make it difficult to establish a market based price when entering into a transaction.

Nonperformance risk

Nonperformance risk refers to the risk that the obligation will not be fulfilled and affects the value at which a liability is transferred or an asset is sold. Nonperformance risk includes, but may not be limited to, the Company or counterparty's credit and settlement risk. Nonperformance risk adjustments are dependent on credit spreads, letters of credit, collateral, other arrangements available and the nature of master netting arrangements. The Company and its subsidiaries are parties to various interest rate swaps and options; foreign currency options and forwards; and derivatives and embedded derivatives which subject the Company to nonperformance risk. The financial and physical instruments held at the subsidiary level are generally non-recourse to the Parent Company.

Nonperformance risk on the investments held by the Company is incorporated in the fair value derived from quoted market data to mark the investments to fair value.

The Company adjusts for nonperformance or credit risk on its derivative instruments by deducting a credit valuation adjustment (“CVA”). The CVA is based on the margin or debt spread of the Company's subsidiary or counterparty and the tenor of the respective derivative instrument. The counterparty for a derivative asset position is considered to be the bank or government sponsored banking entity or counterparty to the PPA or commodity contract. The CVA for asset positions is based on the counterparty's credit ratings and debt spreads or, in the absence of readily obtainable credit information, the respective country debt spreads are used as a proxy. The CVA for liability positions is based on the Parent Company's or the subsidiary's current debt spread, the margin on indicative financing arrangements, or in the absence of readily obtainable credit information, the respective country debt spreads are used as a proxy. All derivative instruments are analyzed individually and are subject to unique risk exposures.

Recurring Measurements

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, 2011 and December 31, 2010. 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.

			Quoted Market		Significant
			Prices in Active		Other		Significant
			Market for		Observable		Unobservable		Total
			Identical Assets		Inputs		Inputs		September 30,
			(Level 1)		(Level 2)		(Level 3)		2011
			(in millions)
Assets
	Available-for-sale securities		$	2	$	1,041	$	40	$	1,083
	Trading securities			10		-		-		10
	Derivatives			-		57		60		117
		Total assets	$	12	$	1,098	$	100	$	1,210
Liabilities
	Derivatives		$	-	$	419	$	269	$	688
		Total liabilities	$	-	$	419	$	269	$	688
			Quoted Market		Significant
			Prices in Active		Other		Significant
			Market for		Observable		Unobservable		Total
			Identical Assets		Inputs		Inputs		December 31,
			(Level 1)		(Level 2)		(Level 3)		2010
			(in millions)
Assets
	Available-for-sale securities		$	8	$	1,707	$	42	$	1,757
	Trading securities			10		-		-		10
	Derivatives			-		63		61		124
		Total assets	$	18	$	1,770	$	103	$	1,891
Liabilities
	Derivatives		$	-	$	411	$	12	$	423
		Total liabilities	$	-	$	411	$	12	$	423

The following tables present a reconciliation of net derivative 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, 2011 and 2010 (presented net by type of derivative):

				Three Months Ended September 30, 2011
				Interest		Cross		Foreign		Commodity
				Rate		Currency		Currency		and Other		Total
			(in millions)
Balance at July 1				$	(60)	$	15	$	38	$	17	$	10
	Total gains (losses) (realized and unrealized):
		Included in earnings (1)			-		(3)		4		(44)		(43)
		Included in other comprehensive income			(36)		(37)		-		-		(73)
		Included in regulatory (assets) liabilities			-		-		-		(3)		(3)
	Settlements				4		4		(1)		(8)		(1)
	Transfers of assets (liabilities) into Level 3 (2)				(101)		-		-		-		(101)
	Transfers of (assets) liabilities out of Level 3 (2)				2		-		-		-		2
Balance at September 30				$	(191)	$	(21)	$	41	$	(38)	$	(209)
Total gains/(losses) for the period included in earnings
	attributable to the change in unrealized gains/(losses)
	relating to assets and liabilities held at the end of the
	period			$	-	$	(2)	$	2	$	(52)	$	(52)
				Three Months Ended September 30, 2010
				Interest		Cross		Foreign		Commodity
				Rate		Currency		Currency		and Other		Total
			(in millions)
Balance at July 1				$	(226)	$	(34)	$	18	$	19	$	(223)
	Total gains (losses) (realized and unrealized):
		Included in earnings (1)			(2)		-		-		(3)		(5)
		Included in other comprehensive income			(63)		24		(1)		-		(40)
		Included in regulatory (assets) liabilities			(3)		-		-		(2)		(5)
	Settlements				15		1		-		(3)		13
	Transfers of assets (liabilities) into Level 3 (2)				(3)		-		-		-		(3)
	Transfers of (assets) liabilities out of Level 3 (2)				26		-		-		-		26
Balance at September 30				$	(256)	$	(9)	$	17	$	11	$	(237)
Total gains/(losses) for the period included in earnings
	attributable to the change in unrealized gains/(losses)
	relating to assets and liabilities held at the end of the
	period			$	(1)	$	-	$	-	$	-	$	(1)

				Nine Months Ended September 30, 2011
				Interest		Cross		Foreign		Commodity
				Rate		Currency		Currency		and Other		Total
			(in millions)
Balance at January 1				$	(1)	$	10	$	22	$	18	$	49
	Total gains (losses) (realized and unrealized):
		Included in earnings (1)			-		(5)		21		(50)		(34)
		Included in other comprehensive income			(3)		(34)		-		-		(37)
		Included in regulatory (assets) liabilities			-		-		-		3		3
	Settlements				-		8		(2)		(9)		(3)
	Transfers of assets (liabilities) into Level 3 (2)				(189)		-		-		-		(189)
	Transfers of (assets) liabilities out of Level 3 (2)				2		-		-		-		2
Balance at September 30				$	(191)	$	(21)	$	41	$	(38)	$	(209)
Total gains/(losses) for the period included in earnings
	attributable to the change in unrealized gains/(losses)
	relating to assets and liabilities held at the end of the
	period			$	-	$	(2)	$	18	$	(56)	$	(40)
				Nine Months Ended September 30, 2010
				Interest		Cross		Foreign		Commodity
				Rate		Currency		Currency		and Other		Total
			(in millions)
Balance at January 1				$	(12)	$	(12)	$	-	$	24	$	-
	Total gains (losses) (realized and unrealized):
		Included in earnings (1)			1		4		19		1		25
		Included in other comprehensive income			(20)		(5)		-		-		(25)
		Included in regulatory (assets) liabilities			(6)		-		-		2		(4)
	Settlements				6		4		(1)		(16)		(7)
	Transfers of assets (liabilities) into Level 3 (2)				(251)		-		(1)		-		(252)
	Transfers of (assets) liabilities out of Level 3 (2)				26		-		-		-		26
Balance at September 30				$	(256)	$	(9)	$	17	$	11	$	(237)
Total gains/(losses) for the period included in earnings
	attributable to the change in unrealized gains/(losses)
	relating to assets and liabilities held at the end of the
	period			$	(2)	$	5	$	20	$	(10)	$	13

(1)       The gains (losses) included in earnings for these Level 3 derivatives are classified as follows: interest rate and cross currency derivatives as interest expense, foreign currency derivatives as foreign currency transaction gains (losses) and commodity and other derivatives as either non-regulated revenue, non-regulated cost of sales, or other expense. 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.

(2)       Transfers in and out of Level 3 are determined as of the end of the reporting period and are from and to Level 2, as the Company has no Level 1 derivative assets or liabilities. The (assets) liabilities transferred out of Level 3 are primarily the result of a decrease in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments. Similarly, the assets (liabilities) transferred into Level 3 are primarily the result of an increase in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments.

The following table presents a reconciliation of available-for-sale securities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and nine months ended September 30, 2011 and 2010:

			Three Months				Nine Months
			Ended September 30,				Ended September 30,
			2011		2010		2011		2010
		(in millions)
Balance at beginning of period(1)			$	40	$	42	$	42	$	42
	Settlements			-		-		(2)		-
Balance at September 30			$	40	$	42	$	40	$	42
Total gains/(losses) for the period included in
	earnings attributable to the change in unrealized
	gains/losses relating to assets held at the
	end of the period		$	-	$	-	$	-	$	-

(1)       Available-for-sale securities in Level 3 are variable rate demand notes which have failed remarketing and for which there are no longer adequate observable inputs available to measure the fair value.

Nonrecurring Measurements:

For purposes of impairment evaluation, the Company measured the fair value of long-lived assets and equity method investments under the fair value measurement accounting guidance. For purposes of the measurement of impairment expense, the Company compares the fair value of assets and liabilities at the evaluation date to the carrying amount at the end of the month prior to the evaluation date.The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:

				Nine Months Ended September 30, 2011
			Carrying	Fair Value						Gross
			Amount	Level 1		Level 2		Level 3		Loss
			(in millions)
Long-lived assets held and used:
	Wind turbines and deposits	$	161	$	-	$	45	$	-	$	116
	Kelanitissa		66		-		-		29		37
	Carbon Reduction Projects		49		-		-		11		33(1)
	Bohemia		14		-		5		-		9
Equity method affiliates:
	YangCheng		100		-		-		26		74
Goodwill:
	Chigen		17		-		-		-		17
				Nine Months Ended September 30, 2010
			Carrying	Fair Value						Gross
			Amount	Level 1		Level 2		Level 3		Loss
			(in millions)
Long-lived assets held and used:
	Southland (Huntington Beach)	$	288	$	-	$	-	$	88	$	200
	Tisza II		160		-		-		75		85
Goodwill:
	Deepwater		18		-		-		-		18

(1)The carrying amounts and fair value of the asset groups also include other assets and liabilities; however, impairment expense recognized was limited to the carrying amounts of long-lived assets.

Long-lived Assets Held and Used

Wind Turbines and Deposits.During the third quarter of 2011, the Company determined thatcertain wind turbines and deposits held by our Wind Generation business were impaired. The long-lived assets with a carrying amount of $161 million were written down to their estimated fair value of $45 millionunder the market approach. This resulted in the recognition of asset impairment expense of $116 million for the three and nine months ended September 30, 2011.

Kelanitissa.During the second quarter of 2011, the Company determined the long-lived assets at Kelanitissa,our diesel-fired plant in Sri Lanka, were impaired. The long-lived assets with a carrying amount of $66 million were written down to their estimated fair value of $33 million based on a discounted cash flow analysis. An additional impairment of $4 million was recognized in the three months ended September 30, 2011. This resulted in the recognition of asset impairment expense of $37 millionfor the nine months ended September 30, 2011.

Carbon Reduction Projects. During the third quarter of 2011, the Company determined there were impairment indicators for the long-lived asset groups at Carbon Reduction projects, our emission reduction credit projects in Asia and Latin America. The long-lived asset groups with an aggregate carrying amount of $49 million were written down as their estimated fair value was $11 million based on discounted cash flows analysis. This resulted in the recognition of asset impairment expense of $33 million for the three and nine months ended September 30, 2011.

Tisza II and Southland (Huntington Beach).During the third quarter of 2010, the Company determined there were impairment indicators for the long-lived assets at Tisza II, our gas-fired generation plant in Hungary, and Southland, our gas-fired generation plants in California. These long-lived assets had carrying amounts of $160 million and $288 million, respectively and were written down to their fair value of $75 million and $88 million, respectively. These resulted in the recognition of asset impairment expense of $85 million and $200 million, respectively during the three and nine months ended September 30, 2010.

For further discussion of these impairments, see Note 14—Impairments.

Equity Method Affiliate

YangCheng.During the third quarter of 2011, the Company determined thatthe carrying amount of YangCheng, a 2,100 MW venture in China in which AES owns a 25% interest,had incurred an other-than-temporary impairment. YangCheng's carrying amount of $100 million was written down to its estimated fair value of $26 million determined under the income approach. This resulted in the recognition of other non-operating expense of $74 million for the three and nine months ended September 30, 2011. See Note 15—Other Non-Operating Expense for further information.

Goodwill

During the third quarter of 2011, the Company determined there were impairment indicators for the goodwill at Chigen, our holding company in China that holds AES' interests in Chinese ventures. Goodwill of $17 million was written down to its implied fair value of zero during an interim impairment evaluation, resulting in the recognition of goodwill impairment of $17 million for the three and nine months ended September 30, 2011.

During the third quarter of 2010, the Company determined there were impairment indicators for the long-lived assets and goodwill at Deepwater, our pet coke-fired generation plant in Texas. Goodwill with an aggregate carrying amount of $18 million was written down to its implied fair value of zero, resulting in the recognition of goodwill impairment of $18 million for the nine months ended September 30, 2010.

For further discussion, see Note 14—Impairments.

Discontinued Operations and Held for Sale Businesses

The Company determined the fair value of nonfinancial assets and liabilities of our held for sale businesses during the nine months ended September 30, 2010. These included the Company's operations in Pakistan, Oman and Qatar. See Note 16—Discontinued Operations and Held for Sale Businesses for further information.

XML

Financial Statement Presentation (Details) (USD $) In Millions, except Per Share data, unless otherwise specified			9 Months Ended		3 Months Ended	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Thames [Member]	Feb. 01, 2011 Thames [Member] mw	Sep. 30, 2011 Brazil Depreciation Rates and Salvage Value [Member]	Sep. 30, 2011 Brazil Depreciation Rates and Salvage Value [Member]
Bankruptcy Proceedings [Line Items]
Generation Capacity (MW)				208
Assets	$ 40,883	$ 40,511		$ 158
Liabilities				170
Deconsolidation Gain Or Loss Amount Deferred			7
Amount Paid To Satisfy Guarantee			5
Change In Accounting Estimate [Line Items]
Increase in depreciation expense from change in estimate					17	52
Decrease in net income attributable to AES from change in estimate					$ 5	$ 14
Per share impact of decrease in net income attributable to AES from change in estimate					$ 0.01	$ 0.02

XML

Significant Accounting Policies (Policies)

3 Months Ended

Sep. 30, 2011

Significant accounting policies [Abstract]

Reclassifications

The prior period condensed consolidated financial statements in this Quarterly Report on Form 10-Q (“Form 10-Q”) have been reclassified to reflect the businesses held for sale and discontinued operations as discussed in Note 16—Discontinued Operations and Held for Sale Businesses.

Consolidation

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 a variable 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.

Accounting Standards Update (ASU) No. 2009-13, Revenue Recognition (Topic 605), Multiple-Deliverable Revenue Arrangements

Accounting Standards Update (“ASU”) No. 2009-13, Revenue Recognition (Topic 605), “Multiple-Deliverable Revenue Arrangements”

In October 2009, the FASB issued ASU No. 2009-13, which amended the accounting guidance related to revenue recognition. The amended guidance provides primarily two changes to the prior guidance for multiple-element revenue arrangements. The first eliminated the requirement that there be “objective and reliable evidence” of fair value for any undelivered items in order for a delivered item to be treated as a separate unit of accounting. The second required that the consideration from multiple-element revenue arrangements be allocated to all the deliverables based on their relative selling price at the inception of the arrangement. AES adopted the standard on January 1, 2011. AES elected prospective adoption and applied the revised guidance to all revenue arrangements entered into or materially modified after the date of adoption. The adoption of ASU No. 2009-13 did not have a material impact on the financial position and results of operations of AES and is not expected to have a material impact in future periods.

ASU No. 2010-28, Intangibles - Goodwill and Other (Topic 350), When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts

ASU No. 2010-28, Intangibles—Goodwill and Other (Topic 350), “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”

In December 2010, the FASB issued ASU No. 2010-28, which amended the accounting guidance related to goodwill. The amendment modified Step One of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step Two of the goodwill impairment test if it is more likely than not that a goodwill impairment exists, eliminating an entity's ability to assert that a reporting unit is not required to perform Step Two because the carrying amount of the reporting unit is zero or negative, despite the existence of qualitative factors that indicate the goodwill is more likely than not impaired. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. The Company adopted ASU No. 2010-28 on January 1, 2011. The adoption did not have any impact on the Company as none of its reporting units with goodwill has a zero or negative carrying amount.

ASU No. 2011-2, Receivables (Topic 310), A Creditors Determination of Whether a Restructuring Is a Troubled Debt Restructuring

ASU No. 2011-2, Receivables (Topic 310), “A Creditor's Determination of Whether a Restructuring Is a Troubled Debt Restructuring”

In April 2011, the FASB issued ASU No. 2011-2, which provides additional guidance and clarification to help creditors determine whether a creditor has granted a concession and whether a debtor is experiencing financial difficulties for purposes of determining whether a restructuring constitutes a troubled debt restructuring. The Company adopted ASU No. 2011-2 on July 1, 2011. The adoption did not have any impact on the Company's financial position, results of operations or cash flows.

ASU No. 2011-28, Intangibles - Goodwill and Other (Topic 350), Testing Goodwill for Impairment

ASU No. 2011-8, Intangibles—Goodwill and Other (Topic 350), “Testing Goodwill for Impairment”

In September 2011, the FASB issued ASU No. 2011-8, which amends the existing guidance for goodwill impairment testing. Under the amendments in ASU No. 2011-8, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after this qualitative assessment, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. Also, an entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. The amendments do not change the existing accounting guidance on how Step 1 and Step 2 of the goodwill impairment test are performed. In addition, an entity is no longer permitted to carry forward its detailed calculation of a reporting unit's fair value from a prior year as previously permitted under the existing guidance. ASU No. 2011-8 is effective for annual and interim goodwill impairment tests performed for fiscal periods beginning on or after December 15, 2011 and early adoption is permitted. AES elected to early adopt ASU No. 2011-8 for its annual goodwill impairment evaluations, which are performed at October 1 each year. The adoption is not expected to have a material impact on the Company's financial position, results of operations or cash flows in current or future periods.

Fair Value Of Financial Instruments Policy

Investments

The Company's investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are measured at fair value using quoted market prices. Debt securities primarily consist of unsecured debentures, certificates of deposit and government debt securities held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to London Inter-Bank Offered Rate, or LIBOR, a benchmark interest rate widely used by banks in the interbank lending market) or Selic (overnight borrowing rate) rates in Brazil. Fair value is determined from comparisons to market data obtained for similar assets and are considered Level 2 in the fair value hierarchy. For more detail regarding the fair value of investments see Note 4—Investments in Marketable Securities.

Derivatives

When deemed appropriate, the Company manages its risk from interest and foreign currency exchange rate and commodity price fluctuations through the use of over-the-counter financial and physical derivative instruments. The derivatives are primarily interest rate swaps to hedge non-recourse debt to establish a fixed rate on variable rate debt, foreign exchange instruments to hedge against currency fluctuations, commodity derivatives to hedge against commodity price fluctuations and embedded derivatives associated with commodity contracts. The Company's subsidiaries are counterparties to various over-the-counter derivatives, which include interest rate swaps and options, foreign currency options and forwards and commodity swaps. In addition, the Company's subsidiaries are counterparties to certain power purchase agreements (“PPAs”) and fuel supply agreements that are derivatives or include embedded derivatives.

For the derivatives where there is a standard industry valuation model, the Company uses that model to estimate the fair value. For the derivatives (such PPAs and fuel supply agreements that are derivatives or include embedded derivatives) where there is not a standard industry valuation model, the Company has created internal valuation models to estimate the fair value, using observable data to the extent available. For all derivatives, the income approach is used, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The following are among the most common market data inputs used in the income approach: volatilities, spot and forward benchmark interest rates (such as LIBOR and Euro Inter Bank Offered Rate (“EURIBOR”)), foreign exchange rates and commodity prices. Forward rates and prices are generally obtained from published information provided by pricing services for an instrument with the same duration as the derivative instrument being valued. In situations where significant inputs are not observable, the Company uses relevant techniques to best estimate the inputs, such as regression analysis, Monte Carlo simulation or prices for similarly traded instruments available in the market.

For each derivative, the income approach is used to estimate the cash flows over the remaining term of the contract. Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR or EURIBOR) plus a spread that reflects the credit or nonperformance risk. This risk is estimated by the Company using credit spreads and risk premiums that are observable in the market, whenever possible, or estimated borrowing costs based on bank quotes, industry publications and/or information on financing closed on similar projects. To the extent that management can estimate the fair value of these assets or liabilities without the use of significant unobservable inputs, these derivatives are classified as Level 2.

In certain instances, the published forward rates or prices may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable inputs, such as proxy commodity prices or historical settlements to forecast forward prices. In addition, in certain instances, there may not be third party data readily available, which requires the use of unobservable inputs. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable. The fair value hierarchy of an asset or a liability is based on the level of significance of the input assumptions. An input assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are transferred to Level 3 when the use of unobservable inputs becomes significant. Similarly, when the use of unobservable input becomes insignificant for Level 3 assets and liabilities, they are transferred to Level 2.

Transfers in and out of Level 3 are from and to Level 2 and are determined as of the end of the reporting period. The Company has not had any Level 1 derivatives so there have not been any transfers between Levels 1 and 2.

Fair Value Of Nonfinancial Assets Liabilities Policy [Text Block]

Nonfinancial Assets and Liabilities

For nonrecurring measurements derived using the income approach, fair value is determined using valuation models based on the principles of discounted cash flows (“DCF”). The income approach is most often used in the impairment evaluation of long-lived tangible assets, goodwill and intangible assets. The Company has developed internal valuation models for such valuations; however, an independent valuation firm may be engaged in certain situations. In such situations, the independent valuation firm largely uses DCF valuation models as the primary measure of fair value though other valuation approaches are also considered. A few examples of input assumptions to such valuations include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates and power and commodity prices. Whenever possible, the Company attempts to obtain market observable data to develop input assumptions. Where the use of market observable data is limited or not possible for certain input assumptions, the Company develops its own estimates using a variety of techniques such as regression analysis and extrapolations.

For nonrecurring measurements derived using the market approach, recent market transactions involving the sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to find sale transactions of identical or similar assets. This approach is used in the impairment evaluations of certain intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.

For nonrecurring measurements derived using the cost approach, fair value is typically determined using the replacement cost approach. Under this approach, the depreciated replacement cost of assets is determined by first determining the current replacement cost of assets and then applying the remaining useful life percentages to such cost. Further adjustments for economic and functional obsolescence are made to the depreciated replacement cost. This approach involves a considerable amount of judgment, which is why its use is limited to the measurement of a few long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach. For the nine months ended September 30, 2011, the Company did not measure any nonfinancial assets under the cost approach.

Derivatives Basis And Use Of Derivatives Use Of Derivatives

The Company is exposed to market risks associated with its enterprise-wide business activities, namely the purchase and sale of fuel 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. The Company generally applies hedge accounting to contracts as long as they are eligible under the accounting standards for derivatives and hedging. While derivative transactions are not entered into for trading purposes, some contracts are not eligible for hedge accounting.

Derivatives Basis And Use Of Derivatives Basis

Derivative assets and liabilities are recognized at their fair value.

Derivatives Offsetting Fair Value Amounts Policy

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.

Financing Receivable Allowance For Credit Losses Policy Or Methodology Change Policy Text Block

Accounts and notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable by considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other available evidence of the collectability, and records an allowance for doubtful accounts for the estimated uncollectable amount as appropriate. Certain of our businesses charge interest on accounts receivable under contractual terms or where charging interest is a customary business practice. In such cases, interest income is recognized on an accrual basis. In situations where the collection of interest is uncertain, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectable.

Commitments And Contingencies Policy

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 has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims of approximately $372 million and $448 million as of September 30, 2011 and December 31, 2010, respectively. These reserves are reported on the condensed consolidated balance sheets within “accrued and other liabilities” and “other long-term liabilities.” A significant portion of the reserves relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company's subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that these reserves will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

Segment Reporting General Information

The Company’s current management reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally. On September 6, 2011, the Company announced the appointment of Andrés Gluski as its President and Chief Executive Officer. Subsequently, on October 18, 2011, the Company announced a plan to redefine its operational management and organizational structure. The planned reporting structure will remain organized along two lines of business – Generation and Utilities, however, we are continuing to evaluate both the timing and impact, if any, that the realignment will have on our reportable segments. For the three and nine months ended September 30, 2011 the Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and concluded it has the following six reportable segments: •        Latin America—Generation; •        Latin America—Utilities; •        North America—Generation; •        North America—Utilities; •        Europe—Generation; and •        Asia—Generation. Corporate and Other—The Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation operating segments and other climate solutions and renewables projects are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our presentation of reportable segments, individually or in the aggregate. AES Solar and certain other unconsolidated businesses are accounted for using the equity method of accounting; therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Consolidated Statements of Operations, not in revenue or gross margin. “Corporate and Other” also includes costs related to corporate overhead costs which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation. The Company uses Adjusted Gross Margin, a non-GAAP measure, to evaluate the performance of its segments. Adjusted Gross Margin is defined by the Company as: Gross Margin plus depreciation and amortization less general and administrative expenses. Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain self insurance activities which are reflected within segment Adjusted Gross Margin. All intra-segment activity has been eliminated with respect to revenue and Adjusted Gross Margin within the segment. Inter-segment activity has been eliminated within the total consolidated results. All balance sheet information for businesses that were discontinued or classified as held for sale as of September 30, 2011 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.

Earnings Per Share Policy

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. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units, stock options and convertible securities. 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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Debt (Tables)

3 Months Ended

Sep. 30, 2011

Debt Tables [Abstract]

Debt Fair Value By Type Table

	September 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(in millions)
Non-recourse debt	$	14,686	$	14,885	$	14,938	$	15,269
Recourse debt		6,192		6,216		4,612		4,868
Total debt	$	20,878	$	21,101	$	19,550	$	20,137

Debt In Default Table

	Primary Nature	September 30, 2011
Subsidiary	of Default	Default Amount		Net Assets
		(in millions)
Maritza	Covenant	$	935	$	216
Sonel	Covenant		342		306
Kelanitissa	Covenant		22		6
Total		$	1,299

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Earnings Per Share (Tables)

3 Months Ended

Sep. 30, 2011

Earnings Per Share Tables [Abstract]

Earnings Per Share Basic And Diluted Table

			Three Months Ended September 30,
			2011					2010
			Loss		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	$	(119)	778	$	(0.15)	$	41	794	$	0.05
EFFECT OF DILUTIVE SECURITIES
	Stock options			-	-		-		-	2		-
	Restricted stock units			-	-		-		-	3		-
DILUTED EARNINGS PER SHARE			$	(119)	778	$	(0.15)	$	41	799	$	0.05

			Nine Months Ended September 30,
			2011					2010
			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	$	296	783	$	0.38	$	354	762	$	0.46
EFFECT OF DILUTIVE SECURITIES
	Stock options			-	1		-		-	2		-
	Restricted stock units			-	3		-		-	3		-
DILUTED EARNINGS PER SHARE			$	296	787	$	0.38	$	354	767	$	0.46

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Fair Value (Tables)

3 Months Ended

Sep. 30, 2011

Fair Value Disclosure Tables [Abstract]

Fair Value Summary Table

			September 30, 2011				December 31, 2010
			Carrying		Fair		Carrying		Fair
			Amount		Value		Amount		Value
			(in millions)
Assets
	Marketable securities		$	1,093	$	1,093	$	1,767	$	1,767
	Derivatives			117		117		124		124
		Total assets	$	1,210	$	1,210	$	1,891	$	1,891
Liabilities
	Debt		$	20,878	$	21,101	$	19,550	$	20,137
	Derivatives			688		688		423		423
		Total liabilities	$	21,566	$	21,789	$	19,973	$	20,560

Fair Value Hierarchy For Recurring Measurements Table

			Quoted Market		Significant
			Prices in Active		Other		Significant
			Market for		Observable		Unobservable		Total
			Identical Assets		Inputs		Inputs		September 30,
			(Level 1)		(Level 2)		(Level 3)		2011
			(in millions)
Assets
	Available-for-sale securities		$	2	$	1,041	$	40	$	1,083
	Trading securities			10		-		-		10
	Derivatives			-		57		60		117
		Total assets	$	12	$	1,098	$	100	$	1,210
Liabilities
	Derivatives		$	-	$	419	$	269	$	688
		Total liabilities	$	-	$	419	$	269	$	688
			Quoted Market		Significant
			Prices in Active		Other		Significant
			Market for		Observable		Unobservable		Total
			Identical Assets		Inputs		Inputs		December 31,
			(Level 1)		(Level 2)		(Level 3)		2010
			(in millions)
Assets
	Available-for-sale securities		$	8	$	1,707	$	42	$	1,757
	Trading securities			10		-		-		10
	Derivatives			-		63		61		124
		Total assets	$	18	$	1,770	$	103	$	1,891
Liabilities
	Derivatives		$	-	$	411	$	12	$	423
		Total liabilities	$	-	$	411	$	12	$	423

Derivatives Level 3 Rollforward Table

				Three Months Ended September 30, 2011
				Interest		Cross		Foreign		Commodity
				Rate		Currency		Currency		and Other		Total
			(in millions)
Balance at July 1				$	(60)	$	15	$	38	$	17	$	10
	Total gains (losses) (realized and unrealized):
		Included in earnings (1)			-		(3)		4		(44)		(43)
		Included in other comprehensive income			(36)		(37)		-		-		(73)
		Included in regulatory (assets) liabilities			-		-		-		(3)		(3)
	Settlements				4		4		(1)		(8)		(1)
	Transfers of assets (liabilities) into Level 3 (2)				(101)		-		-		-		(101)
	Transfers of (assets) liabilities out of Level 3 (2)				2		-		-		-		2
Balance at September 30				$	(191)	$	(21)	$	41	$	(38)	$	(209)
Total gains/(losses) for the period included in earnings
	attributable to the change in unrealized gains/(losses)
	relating to assets and liabilities held at the end of the
	period			$	-	$	(2)	$	2	$	(52)	$	(52)
				Three Months Ended September 30, 2010
				Interest		Cross		Foreign		Commodity
				Rate		Currency		Currency		and Other		Total
			(in millions)
Balance at July 1				$	(226)	$	(34)	$	18	$	19	$	(223)
	Total gains (losses) (realized and unrealized):
		Included in earnings (1)			(2)		-		-		(3)		(5)
		Included in other comprehensive income			(63)		24		(1)		-		(40)
		Included in regulatory (assets) liabilities			(3)		-		-		(2)		(5)
	Settlements				15		1		-		(3)		13
	Transfers of assets (liabilities) into Level 3 (2)				(3)		-		-		-		(3)
	Transfers of (assets) liabilities out of Level 3 (2)				26		-		-		-		26
Balance at September 30				$	(256)	$	(9)	$	17	$	11	$	(237)
Total gains/(losses) for the period included in earnings
	attributable to the change in unrealized gains/(losses)
	relating to assets and liabilities held at the end of the
	period			$	(1)	$	-	$	-	$	-	$	(1)

				Nine Months Ended September 30, 2011
				Interest		Cross		Foreign		Commodity
				Rate		Currency		Currency		and Other		Total
			(in millions)
Balance at January 1				$	(1)	$	10	$	22	$	18	$	49
	Total gains (losses) (realized and unrealized):
		Included in earnings (1)			-		(5)		21		(50)		(34)
		Included in other comprehensive income			(3)		(34)		-		-		(37)
		Included in regulatory (assets) liabilities			-		-		-		3		3
	Settlements				-		8		(2)		(9)		(3)
	Transfers of assets (liabilities) into Level 3 (2)				(189)		-		-		-		(189)
	Transfers of (assets) liabilities out of Level 3 (2)				2		-		-		-		2
Balance at September 30				$	(191)	$	(21)	$	41	$	(38)	$	(209)
Total gains/(losses) for the period included in earnings
	attributable to the change in unrealized gains/(losses)
	relating to assets and liabilities held at the end of the
	period			$	-	$	(2)	$	18	$	(56)	$	(40)
				Nine Months Ended September 30, 2010
				Interest		Cross		Foreign		Commodity
				Rate		Currency		Currency		and Other		Total
			(in millions)
Balance at January 1				$	(12)	$	(12)	$	-	$	24	$	-
	Total gains (losses) (realized and unrealized):
		Included in earnings (1)			1		4		19		1		25
		Included in other comprehensive income			(20)		(5)		-		-		(25)
		Included in regulatory (assets) liabilities			(6)		-		-		2		(4)
	Settlements				6		4		(1)		(16)		(7)
	Transfers of assets (liabilities) into Level 3 (2)				(251)		-		(1)		-		(252)
	Transfers of (assets) liabilities out of Level 3 (2)				26		-		-		-		26
Balance at September 30				$	(256)	$	(9)	$	17	$	11	$	(237)
Total gains/(losses) for the period included in earnings
	attributable to the change in unrealized gains/(losses)
	relating to assets and liabilities held at the end of the
	period			$	(2)	$	5	$	20	$	(10)	$	13

			Three Months				Nine Months
			Ended September 30,				Ended September 30,
			2011		2010		2011		2010
		(in millions)
Balance at beginning of period(1)			$	40	$	42	$	42	$	42
	Settlements			-		-		(2)		-
Balance at September 30			$	40	$	42	$	40	$	42
Total gains/(losses) for the period included in
	earnings attributable to the change in unrealized
	gains/losses relating to assets held at the
	end of the period		$	-	$	-	$	-	$	-

Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Table Text Block]

				Nine Months Ended September 30, 2011
			Carrying	Fair Value						Gross
			Amount	Level 1		Level 2		Level 3		Loss
			(in millions)
Long-lived assets held and used:
	Wind turbines and deposits	$	161	$	-	$	45	$	-	$	116
	Kelanitissa		66		-		-		29		37
	Carbon Reduction Projects		49		-		-		11		33(1)
	Bohemia		14		-		5		-		9
Equity method affiliates:
	YangCheng		100		-		-		26		74
Goodwill:
	Chigen		17		-		-		-		17
				Nine Months Ended September 30, 2010
			Carrying	Fair Value						Gross
			Amount	Level 1		Level 2		Level 3		Loss
			(in millions)
Long-lived assets held and used:
	Southland (Huntington Beach)	$	288	$	-	$	-	$	88	$	200
	Tisza II		160		-		-		75		85
Goodwill:
	Deepwater		18		-		-		-		18

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Equity

3 Months Ended

Sep. 30, 2011

EQUITY

11. EQUITY

STOCK REPURCHASE PROGRAM

In July 2010, the Company's Board of Directors approved a stock repurchase program (the “Program”) under which the Company can repurchase up to $500 million of AES common stock. The Board authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The Program does not have an expiration date and it can be modified or terminated by the Board of Directors at any time.During the nine months ended September 30, 2011, shares of common stock repurchased under this plan totaled 19,987,795 at a total cost of $224 million plus a nominal amount of commissions (average of $11.24 per share including commissions), bringing the cumulative total purchases under the program to 28,370,620 shares at a total cost of $324 million plus a nominal amount of commissions (average of $11.42 per share including commissions).

The shares of stock repurchased have been classified as treasury stock and accounted for using the cost method. A total of 36,832,776 and 17,287,073 shares were held as treasury stock at September 30, 2011 and December 31, 2010, respectively. The Company has not retired any shares held in treasury during the nine months ended September 30, 2011.

COMPREHENSIVE INCOME

The components of comprehensive income (loss) for the three and nine months ended September 30, 2011 and 2010 were as follows:

				Three Months Ended				Nine Months Ended
				September 30,				September 30,
				2011		2010		2011		2010
				(in millions)				(in millions)
Net income				$	175	$	397	$	1,085	$	1,228
	Change in fair value of available-for-sale securities, net of income tax benefit
		of $0, $0, $1 and $4, respectively			(1)		-		(3)		(6)
	Foreign currency translation adjustments, net of income tax (expense)
		of $42, $(15), $28 and $(7), respectively			(589)		285		(327)		519
	Derivative activity:
		Reclassification to earnings, net of income tax (expense)
			of $(13), $(3), $(15) and $(22), respectively		53		13		112		81
		Change in derivative fair value, net of income tax benefit
			of $68, $23, $93 and $82, respectively		(236)		(99)		(305)		(336)
	Total net change in fair value of derivatives				(183)		(86)		(193)		(255)
	Change in unfunded pension obligation, net of income tax (expense)
		of $(2), $(1), $(6) and $(3), respectively			5		1		12		6
Other comprehensive income (loss)					(768)		200		(511)		264
Comprehensive income (loss)					(593)		597		574		1,492
Less: Comprehensive (income) loss attributable to noncontrolling interests(1)					12		(385)		(651)		(789)
Comprehensive income (loss) attributable to The AES Corporation				$	(581)	$	212	$	(77)	$	703

(1)Includes the income 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, 2011 and December 31, 2010 were as follows:

	September 30,		December 31,
	2011		2010
	(in millions)
Foreign currency translation adjustment	$	2,002	$	1,824
Unrealized derivative losses, net		511		344
Unfunded pension obligation		212		216
Securities available-for-sale		2		(1)
Accumulated other comprehensive loss	$	2,727	$	2,383

EQUITY TRANSACTIONS WITH NONCONTROLLING INTERESTS

On July 7, 2011, a subsidiary of the Company completed the acquisition of an additional 10% equity interest in AES-VCM Mong Duong Power Company Limited (“Mong Duong”), a 1,200 MW coal-fired power plant in development in the Quang Ninh province in Vietnam, from Vietnam National Coal and Mineral Industries Group, its minority shareholder. On July 8, 2011, through a subsidiary, the Company sold 30% and 19% equity interests in Mong Duong to PSC Energy Global Co., Ltd. (a wholly owned subsidiary of POSCO Corporation) and Stable Investment Corporation (a wholly owned subsidiary of China Investment Corporation, a related party) respectively, resulting in the Company retaining a 51% indirect equity interest in Mong Duong.As a result of these transactions, the Company did not lose control of Mong Duong, which continues to be accounted for as a consolidated subsidiary. A net gain of $19 million resulting from these transactions was recorded as an equity transactionin additional paid-in capital.

The following table summarizes the net income attributable to The AES Corporation and transfers (to) from noncontrolling interests for the three and nine months endedSeptember 30, 2011 and 2010:

				Three Months Ended				Nine Months Ended
				September 30,				September 30,
				2011		2010		2011		2010
				(in millions)
Net (loss) income attributable to The AES Corporation				$	(131)	$	114	$	267	$	445
	Transfers (to) from the noncontrolling interests:
		Net increase in The AES Corporation's paid-in capital
			for sale of subsidiary shares		19		-		19		-
	Net transfers (to) from noncontrolling interest				19		-		19		-
Change from net income attributable to The AES Corporation
	and transfers (to) from noncontrolling interests			$	(112)	$	114	$	286	$	445

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Other Non-Operating Expense (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Component of Other Expense, Nonoperating [Line Items]
Other non-operating expense	$ 82	$ 2	$ 82	$ 7
Yangcheng [Member]
Component of Other Expense, Nonoperating [Line Items]
Effective Ownership %	25.00%		25.00%
Generation Capacity (MW)	2,100		2,100
Fair Value	26		26
Carrying Amount	$ 100		$ 100

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Subsequent Events (Details) In Millions, except Share data, unless otherwise specified	1 Months Ended	3 Months Ended		9 Months Ended		21 Months Ended	22 Months Ended	0 Months Ended	1 Months Ended		0 Months Ended		22 Months Ended
	Nov. 03, 2011 USD ($)	Sep. 30, 2011 USD ($)	Sep. 30, 2010 USD ($)	Sep. 30, 2011 USD ($)	Sep. 30, 2010 USD ($)	Sep. 30, 2011 USD ($)	Nov. 03, 2011 USD ($)	Oct. 03, 2011 Dolphin Debt Issuance [Member] USD ($)	Oct. 31, 2011 EP Telecom Disposal [Member] USD ($)	Oct. 31, 2011 EP Telecom Disposal [Member] BRL	Oct. 20, 2011 Cartagena Sale [Member] USD ($) mw	Oct. 20, 2011 Cartagena Sale [Member] EUR (€)	Nov. 03, 2011 Stock Repurchase [Member] USD ($)
Subsequent Event [Line Items]
Subsequent Event, Amount								$ 1,250	$ 901	1,522	$ 234	€ 172
Divestiture Of Ownership In Subsidiary Percent									46.00%	46.00%
Gain from disposal of discontinued businesses, net of income taxexpense of $0, $38, $0 and $38, respectively		0	79	0	57				789	1,333
Generation Capacity (MW)											1,199	1,199
Ownership interest in subsidiary											70.81%	70.81%
Percent of current ownership to be sold											80.00%	80.00%
Percent of current ownership with option to sell in future											20.00%	20.00%
Future sale proceeds from option to sell remaining interest											38	28
Arbitration settlement received from counterparty											79	58
Acquisition of treasury stock (shares)	5,554,185			19,987,795		28,370,620	33,924,805
Treasury Stock Value Acquired Cost Method Excluding Commissions	$ 54			$ 224		$ 324	$ 378
Treasury Stock Acquired Average Cost Per Share				$ 11.24		$ 11.42							$ 11.16

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Investments In Marketable Securities

3 Months Ended

Sep. 30, 2011

INVESTMENTS IN MARKETABLE SECURITIES

4. INVESTMENTS IN MARKETABLE SECURITIES

The following table sets forth the Company's investments in marketable debt and equity securities as of September 30, 2011 and December 31, 2010 by security class and by level within the fair value hierarchy. The security classes are determined based on the nature and risk of a security and are consistent with how the Company manages, monitors and measures its marketable securities.

		September 30, 2011								December 31, 2010
		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
		(in millions)
AVAILABLE-FOR-SALE:(1)
Debt securities:
	Unsecured debentures(2)	$	-	$	498	$	-	$	498	$	-	$	723	$	-	$	723
	Certificates of deposit(2)		-		447		-		447		-		876		-		876
	Government debt securities		-		40		-		40		-		47		-		47
	Other debt securities		-		-		40		40		-		-		42		42
	Subtotal		-		985		40		1,025		-		1,646		42		1,688
Equity securities:
	Mutual funds		-		56		-		56		1		61		-		62
	Common stock		2		-		-		2		7		-		-		7
	Subtotal		2		56		-		58		8		61		-		69
Total available-for-sale			2		1,041		40		1,083		8		1,707		42	$	1,757
TRADING:
Equity securities:
	Mutual funds		10		-		-		10		10		-		-		10
Total trading			10		-		-		10		10		-		-		10
TOTAL		$	12	$	1,041	$	40	$	1,093	$	18	$	1,707	$	42	$	1,767

(1)Cost/amortized cost approximated fair value at September 30, 2011 and December 31, 2010, with the exception of certaincommon stock investments with a cost basis and fair value of $4 million and $2million, respectively, at September 30, 2011, and a cost basis and fair value of $6 million and $7 million, respectively, at December 31, 2010.

(2)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,but meet the definition of a security under the relevant guidance and are therefore classified as available-for-sale securities.

As of September 30, 2011, all available-for-sale debt securities had stated maturities within one year, with the exception of $40million of variable rate demand notes held by IPL. These securities, classified as other debt securities in the table above, had stated maturities of greater than ten years.

The following table summarizes the pre-tax gains and losses related to available-for-sale and trading securities for thethree and nine months ended September 30, 2011 and 2010. Gains and losses on the sale of investments are determined using the specific identification method.For the three and nine months ended September 30, 2011 and 2010, there were no realizedlosses on the sale of available-for-sale securities and no other-than-temporary impairment of marketable securities recognized in earnings or other comprehensive income.

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in millions)				(in millions)
Losses included in earnings that relate to trading
	securities held at the reporting date	$	(2)	$	(1)	$	(1)	$	-
Unrealized losses on available-for-sale securities
	included in other comprehensive income	$	(1)	$	-	$	(4)	$	(10)
Proceeds from sales of available-for-sale securities		$	1,134	$	1,420	$	4,218	$	4,644
Gross realized gains on sales		$	1	$	-	$	5	$	2

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Impairments

3 Months Ended

Sep. 30, 2011

IMPAIRMENTS

14. IMPAIRMENTS

Asset Impairment

Asset impairment expense for the three and nine months ended September 30, 2011 and 2010 consisted of:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(in millions)
Wind turbines & deposits	$	116	$	-	$	116	$	-
Carbon reduction projects		33		-		33		-
Kelanitissa		4		-		37		-
Southland (Huntington Beach)		-		200		-		200
Tisza II		-		85		-		85
Other		10		11		10		12
Total asset impairment expense	$	163	$	296	$	196	$	297

During the third quarter of 2011, the Company evaluated the future use of certain wind turbines held in storage pending their installation. Due to reduced wind turbine market pricing and advances in turbine technology, the Company determined it was more likely than not that the turbines would be sold significantly before the end of their previously estimated useful lives. In addition, the Company has concluded that more likely than not non-refundable deposits it had made in prior years to a turbine manufacturer for the purchase of wind turbines are not recoverable. The Company determined it was more likely than not that it would not proceed with the purchase of turbines due to the availability of more advanced and lower cost turbines in the market. These developments were more likely than not as of September 30, 2011 and as a result were considered impairment indicators. In October 2011, the Company determined that an impairment had occurred as of September 30, 2011 as the aggregate carrying amount of $161 million of these assets was not recoverable and was reduced to their estimated fair value of $45 million determined under the market approach. This resulted in asset impairment expense of $116 million for the three and nine months ended September 30, 2011. Wind Generation is reported in the Corporate and Other segment.

During the third quarter of 2011, the markets for emission reduction offsets, including Certified Emission Reductions (CERs) and European Allowance Units (EUAs), experienced a significant adverse change, as the global economic conditions contributed to unforeseen deterioration in the market prices of CERs and EUAs.This decline in the market prices of emission reduction offsets adversely impacted the Company's Carbon Reduction Projects in Asia and Latin America.The Latin American project also incurred current period operating losses and is projecting continuing operating and cash flow losses for future periods.Consequently, we determined that indicators of impairment existed as of September 30, 2011 and the carrying amounts of these projects were not recoverable based on undiscounted cash flows. The fair value of the projects was then determined using discounted cash flow analysis. The aggregate carrying amount of $49 million of these projects was written down as their estimated fair value was$11 million, resulting in asset impairment expense of $33 million, which was limited to the carrying amounts of long-lived assets. Carbon Reduction Projects are reported in the Corporate and Other segment.

During the second quarter of 2011, the Company recognized asset impairment expense of $33 million for the long-lived assets of Kelanitissa, our diesel-fired generation plant in Sri Lanka. We have continued to evaluate the recoverability of our long-lived assets at Kelanitissa as a result of both the existing government regulation which may require the government to acquire an ownership interest and the current expectation of future losses. Our evaluation during the quarter indicated that the long-lived assets were no longer recoverable and accordingly they were written down to their estimated fair value of $33 million based on a discounted cash flow analysis. The long-lived assets had a carrying amount of $66 million prior to the recognition of asset impairment expense. An additional impairment of $4 million was recognized in the three months ended September 30, 2011.Kelanitissa is a Build-operate-transfer (BOT) generation facility and payments under its PPA are scheduled to decline over the PPA term. It is possible that further impairment charges may be required in the future as Kelanitissa gets closer to the BOT date.Kelanitissa is reported in the Asia Generation reportable segment.

During the third quarter of 2011, the Company concluded it was more likely than not that it would sell its interest in two distribution companies and a small generation plant in Argentina. This was considered an impairment indicator. An evaluation of the recoverability of their carrying amount concluded that using probability-weighted undiscounted cash flows, the carrying amounts of the asset groups were recoverable and no impairment charge was recognized for the three months ended September 30, 2011. However, it is reasonably possible that the estimate of undiscounted cash flows at September 30, 2011 could change in the near term. For example, sales negotiations may be finalized in the near term resulting in the need to recognize an impairment charge, which may be material.The aggregate carrying amount of the entities at September 30, 2011 was approximately $317 million, which includes cumulative translationlosses of $208 million currently classified as accumulated other comprehensive loss in equity.As the proceeds from a possible sale are likely to be minimal, we would be required to write down substantially all of the carrying amount of these entities.

During the third quarter of 2010, the Company entered into annual negotiations with the offtaker of its Tisza II generation plant in Hungary. As a result of these preliminary negotiations, as well as the further deterioration of the economic environment in Hungary, the Company determined that an indicator of impairment existed at September 30, 2010. Thus, the Company performed an asset impairment test in accordance with the accounting guidance on property, plant and equipment and determined that based on the undiscounted cash flow analysis, the carrying amount of the Tisza II asset group was not recoverable. The fair value of the asset group was then determined using a discounted cash flow analysis. The carrying value of the Tisza II asset group of $160 million exceeded the fair value of $75 million resulting in the recognition of asset impairment expense of $85 million during the three and nine months ended September 30, 2010. Tisza II is reported in the Europe Generation reportable segment.

In September 2010, the Office of Administrative Law in California approved the policy that will require the Company to change the process through which it uses ocean water to cool the generation turbines at its Alamitos, Huntington Beach and Redondo Beach (collectively “Southland”) gas-fired generation facilities in California. The policy requires compliance with the new regulations by December 31, 2020. The change in the water cooling process will result in significant future capital expenditures to ensure compliance with the new regulations or a shut down of the plants and the Company determined that an indicator of impairment existed at September 30, 2010. The Company performed an asset impairment test and the asset group was determined to be at the individual plant level and based on the undiscounted cash flow analysis, the Company determined that the Huntington Beach asset group was not recoverable. The fair value of the Huntington Beach asset group was then determined using a discounted cash flow analysis. The carrying value of the Huntington Beach plant of $288 million exceeded the fair value of $88 million resulting in the recognition of asset impairment expense of $200 million for the three and nine months ended September 30, 2010. The undiscounted cash flows of the Alamitos and Redondo Beachasset groups exceeded their respective carrying values and resulted in no impairment. Huntington Beach is reported in the North America Generation reportable segment.

Goodwill Impairment

Goodwill impairment was $17 million for the three and nine months ended September 30, 2011. During the third quarter of 2011, the Company identified higher coal prices and the resulting reduced operating margins in China as an impairment indicator for the goodwill at Chigen, our holding company that holds equity interests in Chinese ventures.A significant downward revision of cash flow forecasts indicated that the fair value of Chigen reporting unit was lower than its carrying amount. See Note 15―Other Non-operating Expense for further information. As of September 30, 2011, Chigen had goodwill of $17 million. The Company performed an interim impairment evaluation of Chigen's goodwill and determined that goodwill had no implied fair value.As a result, the entire carrying amount of $17 million was recognized as goodwill impairment.

Goodwill impairment was $18 million for the three and nine months ended September 30, 2010. During the third quarter of 2010, the Company determined that there was an indicator that the carrying value of goodwill related to Deepwater, our pet coke-fired merchant generation facility in Texas, was not recoverable. This determination was based primarily on the fact that Deepwater did not operate for more than 30 days in the three months ended September 30, 2010, had incurred operating and cash flow losses and was forecasting operating and cash flow losses for the remainder of 2010 through 2014 as a result of decreases in future power price expectations and an increase in pet coke prices affecting the market. Deepwater is reported in the North America Generation segment.

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Impairments (Tables)

3 Months Ended

Sep. 30, 2011

Impairments Tables [Abstract]

Details of Impairment of Long-Lived Assets Held and Used by Asset [Table Text Block]

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(in millions)
Wind turbines & deposits	$	116	$	-	$	116	$	-
Carbon reduction projects		33		-		33		-
Kelanitissa		4		-		37		-
Southland (Huntington Beach)		-		200		-		200
Tisza II		-		85		-		85
Other		10		11		10		12
Total asset impairment expense	$	163	$	296	$	196	$	297

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Inventory (Tables)

3 Months Ended

Sep. 30, 2011

Inventory Tables [Abstract]

Inventory Balance By Type

	September 30,		December 31,
	2011		2010
	(in millions)
Coal, fuel oil and other raw materials	$	377	$	276
Spare parts and supplies		291		285
Total	$	668	$	561

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data	Sep. 30, 2011	Dec. 31, 2010
Accounts receivable, allowance for doubtful accounts	$ 293	$ 304
Other intangible assets, accumulated amortization	153	157
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	1,200,000,000	1,200,000,000
Common stock, shares issued	807,093,084	804,894,313
Common stock, shares outstanding	770,260,308	787,607,240
Treasury stock, shares	36,832,776	17,287,073
Variable Interest Entity [Line Items]
Non-recourse debt - current, balance at variable interest entities	2,163	2,567
Non-recourse debt - noncurrent, balance at variable interest entities	12,523	12,371
Consolidated Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Non-recourse debt - current, balance at variable interest entities	269	1,150
Non-recourse debt - noncurrent, balance at variable interest entities	$ 2,168	$ 2,199

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Other Non-Operating Expense

3 Months Ended

Sep. 30, 2011

OTHER NON-OPERATING EXPENSE

15. OTHER NON-OPERATING EXPENSE

Other non-operating expense of $82 million for the three and nine months ended September 30, 2011 primarily consisted of other-than-temporary impairments of equity method investments in China.

During the third quarter of 2011 as part of the quarterly close process, the Company evaluated YangCheng International Power Generating Co Ltd (“YangCheng”), a 2,100 MW coal-fired plant in China, for other-than-temporary-impairment. AES owns a 25% interest in YangCheng and the remaining equity interest in the venture is held by Chinese partners. During the nine months ended September 30, 2011, coal prices continued an upward trend in China, thereby, reducing the operating margin of coal generation facilities. During this time, there was no corresponding increase in tariffs to compensate for higher coal prices. Power prices in China are tightly regulated by the national and provincial governments, which often limit power generators' ability to pass through increases in fuel costs to customers. In addition, under the YangCheng venture agreement, AES will surrender its equity interest to theventure partners in 2016 without additional compensation. During the nine months ended September 30, 2011, management continued to monitor the situation andin the third quarter determined that it was unlikely that there would be a reversal in the trendsin coal prices during the remaining term of the venture. Accordingly, during September 2011, management revised downward its forecasts of earning and cash flows over the remaining term of the venture.The revised forecasts were significantly lower than management's earlier estimates such that the carrying amount of the investment in YangCheng was considered to have incurred an other-than-temporary-impairment. In determining the fair value of our investment, management used a discounted cash flow analysis based on probability-weighted revised cash distribution forecasts under multiple scenarios. As of September 30, 2011, YangCheng had a carrying amount of $100 million which was written down to the estimated fair value of $26 million, and the difference was recognized as other non-operating expense.

Other non-operating expense of $2 million and $7 million, respectively, for the three and nine months ended September 30, 2010 primarily consisted of an other-than-temporary impairment of an equity method investment.

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Fair Value (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended																																																3 Months Ended		9 Months Ended									3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010	Sep. 30, 2011 Carrying Amount	Dec. 31, 2010 Carrying Amount	Sep. 30, 2011 Fair Value	Dec. 31, 2010 Fair Value	Sep. 30, 2011 Level 1	Dec. 31, 2010 Level 1	Sep. 30, 2011 Level 1 Recurring	Dec. 31, 2010 Level 1 Recurring	Sep. 30, 2011 Level 1 Nonrecurring Long Lived Assets Held And Used [Member] Kelanitissa [Member]	Sep. 30, 2010 Level 1 Nonrecurring Long Lived Assets Held And Used [Member] Southland Huntington Beach Subsidiary [Member]	Sep. 30, 2010 Level 1 Nonrecurring Long Lived Assets Held And Used [Member] Tisza I I Subsidiary [Member]	Sep. 30, 2011 Level 1 Nonrecurring Long Lived Assets Held And Used [Member] Wind Turbines And Deposits [Member]	Sep. 30, 2011 Level 1 Nonrecurring Long Lived Assets Held And Used [Member] Carbon Reduction Projects [Member]	Sep. 30, 2011 Level 1 Nonrecurring Long Lived Assets Held And Used [Member] Bohemia [Member]	Sep. 30, 2010 Level 1 Nonrecurring Goodwill [Member] Deepwater Subsidiary [Member]	Sep. 30, 2011 Level 1 Nonrecurring Goodwill [Member] Chigen [Member]	Sep. 30, 2011 Level 1 Nonrecurring Equity Method Affiliate [Member] Yangcheng [Member]	Sep. 30, 2011 Level 2	Dec. 31, 2010 Level 2	Sep. 30, 2011 Level 2 Recurring	Dec. 31, 2010 Level 2 Recurring	Sep. 30, 2011 Level 2 Nonrecurring Long Lived Assets Held And Used [Member] Kelanitissa [Member]	Sep. 30, 2010 Level 2 Nonrecurring Long Lived Assets Held And Used [Member] Southland Huntington Beach Subsidiary [Member]	Sep. 30, 2010 Level 2 Nonrecurring Long Lived Assets Held And Used [Member] Tisza I I Subsidiary [Member]	Sep. 30, 2011 Level 2 Nonrecurring Long Lived Assets Held And Used [Member] Wind Turbines And Deposits [Member]	Sep. 30, 2011 Level 2 Nonrecurring Long Lived Assets Held And Used [Member] Carbon Reduction Projects [Member]	Sep. 30, 2011 Level 2 Nonrecurring Long Lived Assets Held And Used [Member] Bohemia [Member]	Sep. 30, 2010 Level 2 Nonrecurring Goodwill [Member] Deepwater Subsidiary [Member]	Sep. 30, 2011 Level 2 Nonrecurring Goodwill [Member] Chigen [Member]	Sep. 30, 2011 Level 2 Nonrecurring Equity Method Affiliate [Member] Yangcheng [Member]	Sep. 30, 2011 Level 3	Dec. 31, 2010 Level 3	Sep. 30, 2011 Level 3 Recurring	Dec. 31, 2010 Level 3 Recurring	Sep. 30, 2011 Level 3 Nonrecurring Long Lived Assets Held And Used [Member] Kelanitissa [Member]	Sep. 30, 2010 Level 3 Nonrecurring Long Lived Assets Held And Used [Member] Southland Huntington Beach Subsidiary [Member]	Sep. 30, 2010 Level 3 Nonrecurring Long Lived Assets Held And Used [Member] Tisza I I Subsidiary [Member]	Sep. 30, 2011 Level 3 Nonrecurring Long Lived Assets Held And Used [Member] Wind Turbines And Deposits [Member]	Sep. 30, 2011 Level 3 Nonrecurring Long Lived Assets Held And Used [Member] Carbon Reduction Projects [Member]	Sep. 30, 2011 Level 3 Nonrecurring Long Lived Assets Held And Used [Member] Bohemia [Member]	Sep. 30, 2010 Level 3 Nonrecurring Goodwill [Member] Deepwater Subsidiary [Member]	Sep. 30, 2011 Level 3 Nonrecurring Goodwill [Member] Chigen [Member]	Sep. 30, 2011 Level 3 Nonrecurring Equity Method Affiliate [Member] Yangcheng [Member]	Sep. 30, 2011 Recurring	Dec. 31, 2010 Recurring	Sep. 30, 2011 Nonrecurring Long Lived Assets Held And Used [Member] Kelanitissa [Member]	Jun. 30, 2011 Nonrecurring Long Lived Assets Held And Used [Member] Kelanitissa [Member]	Sep. 30, 2011 Nonrecurring Long Lived Assets Held And Used [Member] Kelanitissa [Member]	Sep. 30, 2010 Nonrecurring Long Lived Assets Held And Used [Member] Southland Huntington Beach Subsidiary [Member]	Sep. 30, 2010 Nonrecurring Long Lived Assets Held And Used [Member] Tisza I I Subsidiary [Member]	Sep. 30, 2011 Nonrecurring Long Lived Assets Held And Used [Member] Wind Turbines And Deposits [Member]	Sep. 30, 2011 Nonrecurring Long Lived Assets Held And Used [Member] Carbon Reduction Projects [Member]	Sep. 30, 2011 Nonrecurring Long Lived Assets Held And Used [Member] Bohemia [Member]	Sep. 30, 2010 Nonrecurring Goodwill [Member] Deepwater Subsidiary [Member]	Sep. 30, 2011 Nonrecurring Goodwill [Member] Chigen [Member]	Sep. 30, 2011 Nonrecurring Equity Method Affiliate [Member] Yangcheng [Member] mw	Sep. 30, 2011 Interest Rate Derivatives	Sep. 30, 2010 Interest Rate Derivatives	Sep. 30, 2011 Interest Rate Derivatives	Sep. 30, 2010 Interest Rate Derivatives	Sep. 30, 2011 Cross Currency Swaps	Sep. 30, 2010 Cross Currency Swaps	Sep. 30, 2011 Cross Currency Swaps	Sep. 30, 2010 Cross Currency Swaps	Sep. 30, 2011 Foreign Currency	Sep. 30, 2010 Foreign Currency	Sep. 30, 2011 Foreign Currency	Sep. 30, 2010 Foreign Currency	Sep. 30, 2011 Commodity & Other	Sep. 30, 2010 Commodity & Other	Sep. 30, 2011 Commodity & Other	Sep. 30, 2010 Commodity & Other	Sep. 30, 2011 Debt securities	Sep. 30, 2010 Debt securities	Sep. 30, 2011 Debt securities	Sep. 30, 2010 Debt securities
Fair Value Disclosures Details [Abstract]
An input assumption is considered significant if it affects the fair value by at least 10%.	10.00%		10.00%
Assets
Marketable securities	$ 1,093		$ 1,093		$ 1,767	$ 1,093	$ 1,767	$ 1,093	$ 1,767	$ 12	$ 18												$ 1,041	$ 1,707												$ 40	$ 42
Derivatives	117		117		124	117	124	117	124
Total assets						1,210	1,891	1,210	1,891
Liabilities
Debt						20,878	19,550	21,101	20,137
Derivatives	688		688		423	688	423	688	423
Total liabilities						21,566	19,973	21,789	20,560
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Available-for-sale securities												2	8												1,041	1,707												40	42										1,083	1,757
Trading securities												10	10												0	0												0	0										10	10
Derivatives												0	0												57	63												60	61										117	124
Total assets												12	18												1,098	1,770												100	103										1,210	1,891
Derivatives												0	0												419	411												269	12										688	423
Total liabilities												0	0												419	411												269	12										688	423
Fair Value Assets And Liabilities Measured On Nonrecurring Basis [Abstract]
Carrying Amount, Nonrecurring																																																			66		66	288	160	161	49	14	18	17	100
Fair Value, Nonrecurring														0	0	0	0	0	0	0	0	0					0	0	0	45	0	5	0	0	0					29	88	75	0	11	0	0	0	26
(Gain) loss on disposal and impairment write-down - discontinued operations			(1)	102
Asset Impairment Charges	163	296	196	297																																															4	33	37	200	85	116	33	9
Goodwill impairment	17	18	17	18																																																							18	17
Generation Capacity (MW)																																																													2,100
Ownership Interest In Subsidiary																																																													25.00%
Other non-operating expense	82	2	82	7																																																									74
Fair Value Derivative Assets Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	10	(223)	49	0																																																										(60)	(226)	(1)	(12)	15	(34)	10	(12)	38	18	22	0	17	19	18	24
Included in earnings	(43)	(5)	(34)	25																																																										0	(2)	0	1	(3)	0	(5)	4	4	0	21	19	(44)	(3)	(50)	1
Included in other comprehensive income	(73)	(40)	(37)	(25)																																																										(36)	(63)	(3)	(20)	(37)	24	(34)	(5)	0	(1)	0	0	0	0	0	0
Included in regulatory (assets) liabilities	(3)	(5)	3	(4)																																																										0	(3)	0	(6)	0	0	0	0	0	0	0	0	(3)	(2)	3	2
Settlements	(1)	13	(3)	(7)																																																										4	15	0	6	4	1	8	4	(1)	0	(2)	(1)	(8)	(3)	(9)	(16)
Transfers of assets (liabilities) into Level 3	(101)	(3)	(189)	(252)																																																										(101)	(3)	(189)	(251)	0	0	0	0	0	0	0	(1)	0	0	0	0
Transfers of (assets) liabilities out of Level 3	2	26	2	26																																																										2	26	2	26	0	0	0	0	0	0	0	0	0	0	0	0
Balance at end of period	(209)	(237)	(209)	(237)																																																										(191)	(256)	(191)	(256)	(21)	(9)	(21)	(9)	41	17	41	17	(38)	11	(38)	11
Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/(losses) relating to assets and liabilities held at the end of the period	(52)	(1)	(40)	13																																																										0	(1)	0	(2)	(2)	0	(2)	5	2	0	18	20	(52)	0	(56)	(10)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period																																																																														40	42	42	42
Settlements																																																																														0	0	(2)	0
Balance at end of period																																																																														40	42	40	42
Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets held at the end of the period																																																																														$ 0	$ 0	$ 0	$ 0

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Acquistions

3 Months Ended

Sep. 30, 2011

ACQUISTIONS

17. ACQUISITIONS

In the second quarter of 2011, the Company finalized the purchase price allocation related to the acquisition of Ballylumford. There were no significant adjustments made to the preliminary purchase price allocation recorded in the third quarter of 2010 when the acquisition was completed.

On April 20, 2011, the Company announced the execution of a definitive agreement (the “Merger Agreement”) with DPL, the parent company of Dayton Power & Light Company, a utility company based in Ohio. Under the terms of the Merger Agreement, AES agreed to acquire DPL for an enterprise value of $4.7 billion, consisting of cash of $3.5 billion and the assumption of net debt of approximately $1.2 billion. Through its operating subsidiaries DP&L and DPL Energy Resources, DPL serves over 500,000 customers in West Central Ohio. Additionally, DPL operates over 3,800 MW of power generation facilities and provides competitive retail energy services to industrial and commercial customers. Upon closing of the transaction, DPL will become a wholly-owned subsidiary of AES.

The consummation of the transaction is subject to approval of the Public Utilities Commission of Ohio and FERC. By September 30, 2011, the transaction had been approved by DPL shareholders and had satisfied the antitrust review under the Hart-Scott-Rodino Act. Remaining approvals are expected to be obtained during the fourth quarter of 2011 or the first quarter of 2012, although there can be no assurance that such approvals will be obtained, or that they will be obtained on reasonable terms. The transaction is also subject to certain other closing conditions. After the announcement of the transaction, certain lawsuits were filed seeking to enjoin the merger and/or seek unspecified monetary damages, some of which name AES as a defendant. The Company believes it has meritorious defenses to the lawsuits and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.

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Condensed Consolidated Statements Of Changes in Equity (USD $) In Millions	Total	Common Stock Member	Treasury Stock	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Noncontrolling Interests	Consolidated Comprehensive Income
Beginning Balance at Dec. 31, 2009		$ 7	$ (126)	$ 6,868	$ 650	$ (2,724)	$ 4,205
Net income	1,228	0	0	0	445	0	783	1,228
Change in fair value of available-for-sale securities, net of income tax	(6)					(6)		(6)
Foreign currency translation adjustments, net of income tax	519	0	0	0	0	465	54	519
Change in unfunded pensions obligation, net of income tax	6	0	0	0	0	3	3	6
Change in derivative fair value, including a reclassification to earnings, net of income tax	(255)	0	0	0	0	(204)	(51)	(255)
Other comprehensive income	264							264
Total comprehensive income	703							1,492
Cumulative effect of consolidation of entities under variable interest entity accounting guidance		0	0	0	(47)	(38)	15
Cumulative effect of deconsolidation of entities under variable interest entity accounting guidance		0	0	0	1	0	0
Capital contributions from noncontrolling interests		0	0	0	0	0	30
Distributions to noncontrolling interests		0	0	0	0	0	(1,068)
Disposition of businesses		0	0	0	0	0	(78)
Issuance of common stock		1	0	1,566	0	0	0
Acquisition of treasury stock		0	(15)	0	0	0	0
Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax		0	9	10	0	0	0
Stock compensation		0	0	18	0	0	0
Changes in the carrying amount of redeemable stock of subsidiaries		0	0	0	7	0	0
Net gain on sale of subsidiary shares to noncontrolling interests	0
Ending Balance at Sep. 30, 2010		8	(132)	8,462	1,056	(2,504)	3,893
Beginning Balance at Dec. 31, 2010	10,413	8	(216)	8,444	620	(2,383)	3,940
Net income	1,085	0	0	0	267	0	818	1,085
Change in fair value of available-for-sale securities, net of income tax	(3)	0	0	0	0	(3)	0	(3)
Foreign currency translation adjustments, net of income tax	(327)	0	0	0	0	(178)	(149)	(327)
Change in unfunded pensions obligation, net of income tax	12	0	0	0	0	4	8	12
Change in derivative fair value, including a reclassification to earnings, net of income tax	(193)	0	0	0	0	(167)	(26)	(193)
Other comprehensive income	(511)							(511)
Total comprehensive income	(77)							574
Capital contributions from noncontrolling interests		0	0	0	0	0	9
Distributions to noncontrolling interests		0	0	0	0	0	(990)
Disposition of businesses		0	0	0	0	0	(2)
Acquisition of treasury stock		0	(225)	0	0	0	0
Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax		0	7	20	0	0	0
Stock compensation		0	0	16	0	0	0
Net gain on sale of subsidiary shares to noncontrolling interests	19	0	0	19	0	0	0
Sale of subsidiary shares to noncontrolling interests		0	0	0	0	0	16
Ending Balance at Sep. 30, 2011	$ 9,857	$ 8	$ (434)	$ 8,499	$ 887	$ (2,727)	$ 3,624

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Contingencies and Commitments

3 Months Ended

Sep. 30, 2011

CONTINGENCIES AND COMMITMENTS

9. 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, 2011, the Company had recorded liabilities of $22 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, 2011.

The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and 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 byproducts), and certain air emissions, such as SO2, NOx, particulate matter and mercury. Such risks and uncertainties could result in 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.

Legislation and Regulation of GHG Emissions

Currently, in the United States there is no federal legislation establishing mandatory GHG emissions reduction programs (including CO2) affecting the electric power generation facilities of the Company's subsidiaries. There are numerous state programs regulating GHG emissions from electric power generation facilities and there is a possibility that federal GHG legislation will be enacted within the next several years. Further, the United States Environmental Protection Agency (“EPA”) has adopted regulations pertaining to GHG emissions and has announced its intention to propose new regulations for electric generating units under Section 111 of the United States Clean Air Act (“CAA”).

Potential U.S. Federal GHG LegislationFederal legislation passed the U.S. House of Representatives in 2009 that, if adopted, would have imposed a nationwide cap-and-trade program to reduce GHG emissions. This legislation was never signed into law, and is no longer under consideration. In the U.S. Senate, several different draft bills pertaining to GHG legislation have been considered, including comprehensive GHG legislation similar to the legislation that passed the U.S. House of Representatives and more limited legislation focusing only on the utility and electric generation industry. It is uncertain whether any legislation pertaining to GHG emissions will be voted on and passed by the U.S. Senate and House of Representatives. If any such legislation is enacted into law, the impact could be material to the Company.

EPA GHG Regulation The EPA has promulgated regulations governing GHG emissions from automobiles under the CAA. The effect of the EPA's regulation of GHG emissions from mobile sources is that certain provisions of the CAA will also apply to GHG emissions from existing stationary sources, including many U.S. power plants. In particular, beginning January 2, 2011, construction of new stationary sources and modifications to existing stationary sources that result in increased GHG emissions became subject to permitting requirements under the prevention of significant deterioration ("PSD") program of the CAA. The PSD program, as currently applicable to GHG emissions, requires sources that emit above a certain threshold of GHGs to obtain PSD permits prior to commencement of new construction or modifications to existing facilities. In addition, major sources of GHG emissions may be required to amend, or obtain new, Title V air permits under the CAA to reflect any new applicable GHG emissions requirements for new construction or for modifications to existing facilities.

The EPA promulgated a final rule on June 3, 2010 (the "Tailoring Rule") that sets thresholds for GHG emissions that would trigger PSD permitting requirements. The Tailoring Rule, which became effective in January of 2011, provides that sources already subject to PSD permitting requirements need to install Best Available Control Technology (“BACT”) for greenhouse gases if a proposed modification would result in the increase of more than 75,000 tons per year of GHG emissions. Also, under the Tailoring Rule, any new sources of GHG emissions that would emit over 100,000 tons per year of GHG emissions, in addition to any modification that would result in GHG emissions exceeding 75,000 tons per year, require PSD review and are subject to related permitting requirements. The EPA anticipates that it will adjust downward the permitting thresholds of 100,000 tons and 75,000 tons for new sources and modifications, respectively, in future rulemaking actions. The Tailoring Rule substantially reduces the number of sources subject to PSD requirements for GHG emissions and the number of sources required to obtain Title V air permits, although new thermal power plants may still be subject to PSD and Title V requirements because annual GHG emissions from such plants typically far exceed the 100,000 ton threshold noted above. The 75,000 ton threshold for increased GHG emissions from modifications to existing sources may reduce the likelihood that future modifications to plants owned by some of our United States subsidiaries would trigger PSD requirements, although some projects that would expand capacity or electric output are likely to exceed this threshold, and in any such cases the capital expenditures necessary to comply with the PSD requirements could be significant. 

In December 2010, the EPA entered into a settlement agreement with several states and environmental groups to resolve a petition for review challenging the EPA's new source performance standards (“NSPS”) rulemaking for electric utility steam generating units (“EUSGUs”) based on the NSPS's failure to address GHG emissions. Under the settlement agreement, the EPA had committed to propose GHG emissions standards for EUSGUs by July 26, 2011.TheEPA previously announced that it would delay the proposal of such standards until September 30, 2011, and it subsequently announced a further delay without specifying a deadline for the proposal of such standards. The EPA has also committed to finalize GHG NSPS for EUSGUs by May 26, 2012. The NSPS will establish GHG emission standards for newly constructed and reconstructed EUSGUs. The NSPS also will establish guidelines regarding the best system for achieving further GHG emissions reductions from existing EUSGUs.Based on the guidelines, individual states will be required to develop regulations establishing GHG performance standards for existing EUSGUs within their states. It is impossible to estimate the impact and compliance cost associated with any future NSPS applicable to EUSGUs until such regulations are finalized.However, the compliance costs could have a material and adverse impact on our consolidated financial condition or results of operations.

Regional Greenhouse Gas Initiative 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 participating in RGGI 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 2010 Form 10-K, we have estimated the costs to the Company of compliance with RGGI to be approximately $15 million for 2011.

International GHG Regulation 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 emissions reduction requirements. Many of the countries in which the Company's subsidiaries operate have no emissions reduction obligations under the Kyoto Protocol. In addition, of the 27 countries in which the Company's subsidiaries operate, all but one—the United States (including Puerto Rico)—have ratified the Kyoto Protocol. The first commitment period under the Kyoto Protocol is currently expected to expire at the end of 2012, and countries have been unable to agree on a successor commitment period. The next annual United Nations conference to develop a successor international agreement is scheduled for November 2011 in South Africa. It currently appears unlikely that a successor agreement will be reached at such conference; however, if a successor agreement is reached the impact could be material to the Company.

There is substantial uncertainty with respect to whether U.S. federal GHG legislation will be enacted into law, whether new country-specific GHG legislation will be adopted in countries in which our subsidiaries conduct business, and whether a new international agreement to succeed the Kyoto Protocol will be reached. There is additional uncertainty regarding the final provisions or implementation of any potential U.S. federal or foreign country GHG legislation, the EPA's 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 or financial condition from potential U.S. federal or foreign country GHG legislation, the EPA's 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.

Other U.S. Air Emissions Regulations and Legislation

The Company's subsidiaries in the United States are subject to the Clean Air Act (“CAA”) and various state laws and regulations that regulate emissions of air pollutants, including SO2, NOX, particulate matter (“PM”), mercury and other hazardous air pollutants (“HAPs”).

The EPA promulgated the Clean Air Interstate Rule (“CAIR”) on March 10, 2005, which required allowance surrender for SO2 and NOX emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the EPA. In response to the D.C. Circuit's opinion, on July 7, 2011, the EPA issueda final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”).Starting in 2012, the CSAPR requires significant reductions in SO2 and NOx emissions from covered sources, such as power plants, in many states in which subsidiaries of the Company operate.Once fully implemented in 2014, the rule requires additional SO2 emission reductions of 73% and additional NOx reductions of 54% from 2005 levels.The CSAPR will be implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of new emissions allowances that the EPA will create.The CSAPR contemplates limited interstate and intra-state trading of emissions allowances by covered sources.Initially, at least through 2012,the EPA will issue emissions allowances to affected power plants based onstate emissions budgets established by the EPA under the CSAPR.The availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time.The CSAPR was published in the Federal Register on August 8, 2011 and on October 6, 2011, the EPA proposed some technical revisions to the CSAPR, including allowing for additional allowances for certain states.The EPA will be taking public comments on the proposed revisions for thirty days, and such public comments will be considered by the EPA prior to promulgating a final rule.Many states, utilities and other affected parties have filed lawsuits in the U.S. Court of Appeals for the District of Columbia seeking to stay the implementation of the CSAPR and challenging the validity of the CSAPR. We cannot predict the outcome of such litigation or the effect it might have on the possible implementation of the CSAPR.To comply with the CSAPR, additional pollution control technology may be required by some of our subsidiaries, and the cost of implementing any such technology could affect the financial condition or results of operations of these subsidiaries or the Company.Additionally, compliance with the CSAPR could require the purchase of newly issued allowances, the switch to higher priced, lower sulfur coal or the retirement of existing generating units.While the capital costs, other expenditures or operational restrictions necessary to comply with the CSAPR cannot be specified at this time, and the outcome of litigation pertaining to CSAPR is uncertain, the Company anticipates that the CSAPRmay have a material impact on the Company's business and results of operations.

As a result of prior EPA determinations and the D.C. Circuit Court ruling, the EPA is obligated under Section 112 of the CAA to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, hydrogen chloride, hydrogen fluoride, and other metal species from coal and oil-fired power plants. The EPA has entered into a consent decree under which it is obligated to finalize the rule by November 2011,and it has subsequently requested an extension of this deadline until December 16, 2011. In connection with such rule, the CAA requires the EPA to establish maximum achievable control technology (“MACT”) standards for each pollutant regulated under the rule. MACT is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. The EPA published a proposed rule on May 3, 2011 that would establish national emissions standards for hazardous air pollutants (“NESHAP”) from coal and oil-fired electric utility steam generating units. The rule, as currently proposed, may require all coal-fired power plants to retire operations or install acid gas control technology, upgrade particulate control devices and/or install some other type of mercury control technology, such as sorbent injection. The public comment period for this proposed rule has expired, and the public comments will be considered by the EPA prior to promulgating a final rule. Most of the United States coal-fired plants operated by the Company's subsidiaries have acid gas scrubbers or comparable control technologies, but as proposed there are other improvements to such control technologies that may be needed at some of the Company's plants. Under the CAA, compliance is required within three years of the effective date of the rule; however, the compliance period for a unit, or group of units, may be extended by state permitting authorities (for one additional year) or through a determination by the President (for up to two additional years). At this time, the Company cannot predict the extent of the final regulations for hazardous air pollutants, but the cost of compliance with any such regulations could be material.

Other International Air Emissions Regulations and Legislation

On January 18, 2011, the President of Chile approved a new air emissions regulation submitted to him by the national environmental regulatory agency (“CONAMA”). The new regulation establishes limits on emissions of NOX, SO2, metals and particulate matter for both existing and new thermal power plants, with more stringent limitations on new facilities. The regulation became effective on June 23, 2011. The regulation will require AES Gener, the Company's Chilean subsidiary, to install emissions reduction equipment at its existing thermal plants from late 2011 through 2015. The costs of compliance with such regulation have not yet been determined and the Company believes some of the compliance costs are contractually passed through to counterparties. However, the compliance costs could be material.

Cooling Water Intake Regulations

The Company's U.S. facilities are subject to the U.S. Clean Water Act Section 316(b) rule issued by the EPA which seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the “best technology available” for cooling water intake structures. The EPA published a proposed rule establishing requirements under 316(b) regulations on April 20, 2011. The proposal, based on Section 316(b) of the U.S. Clean Water Act, establishes Best Technology Available (“BTA”) requirements regarding impingement standards with respect to aquatic organisms for all facilities that withdraw above 2 million gallons per day of water from certain water bodies and utilize at least 25% of the withdrawn water for cooling purposes. To meet these BTA requirements, as currently proposed, cooling water intake structures associated with once through cooling processes will need modifications of existing traveling screens that protect aquatic organisms and will need to add a fish return and handling system for each cooling system.Existing closed cycle cooling facilities may require upgrades to water intake structure systems. The proposal would also require comprehensive site-specific studies during the permitting process and may require closed-cycle cooling systems in order to meet BTA entrainment standards.

The public comment period for this proposed rule has expired, and the EPA will consider the public comments with a view to issuing a final rule by July of 2012.Until such regulations are final, the EPA has instructed state regulatory agencies to use their best professional judgment in determining how to evaluate what constitutes “best technology available” for protecting fish and other aquatic organisms from cooling water intake structures. Certain states in which the Company operates power generation facilities, such as New York, have been delegated authority and are moving forward with best technology available determinations in the absence of any final rule from the EPA. On September 27, 2010, the California Office of Administrative Law approved a policy adopted by the California Water Resources Control Board with respect to power plant cooling water intake structures. This policy became effective on October 1, 2010, and establishes technology-based standards to implement Section 316(b) of the U.S. Clean Water Act. At this time, it is contemplated that the Company's Redondo Beach, Huntington Beach and Alamitos power plants in California will need to have in place best technology available by December 31, 2020, or repower the facilities. At present, the Company cannot predict the final requirements under Section 316(b) or whether compliance with the anticipated new 316(b) rule will have a material impact on our operations or results, but the Company expects that capital investments and/or modifications resulting from such requirements could be significant.

Waste Management

In the course of operations, many of the Company's facilities generate coal combustion byproducts (“CCB”), including fly ash, requiring disposal or processing. On June 21, 2010 the EPA published in the Federal Register a proposed rule to regulate CCB under the Resource Conservation and Recovery Act (“RCRA”). The proposed rule provides two possible options for CCB regulation, and both options contemplate heightened structural integrity requirements for surface impoundments of CCB. The first option contemplates regulation of CCB as a hazardous waste subject to regulation under Subtitle C of the RCRA. Under this option, existing surface impoundments containing CCB would be required to be retrofitted with composite liners and these impoundments would likely be phased out over several years. State and/or federal permit programs would be developed for storage, transport and disposal of CCB. States could bring enforcement actions for non-compliance with permitting requirements, and the EPA would have oversight responsibilities as well as the authority to bring lawsuits for non-compliance. The second option contemplates regulation of CCB under Subtitle D of the RCRA. Under this option, the EPA would create national criteria applicable to CCB landfills and surface impoundments. Existing impoundments would also be required to be retrofitted with composite liners and would likely be phased out over several years. This option would not contain federal or state permitting requirements. The primary enforcement mechanism under regulation pursuant to Subtitle D would be private lawsuits.

The public comment period for this proposed regulation has expired, and the EPA is required to consider the public comments prior to promulgating a final rule. Requirements under a final rule are expected to become effective by January 2012, with a compliance schedule of five years. While the exact impact and compliance cost associated with future regulations of CCB cannot be established until such regulations are finalized, there can be no assurance that the Company's businesses, financial condition or results of operations would not be materially and adversely affected by such regulations.

IndianaSenate Bill 251

In May 2011, Senate Bill 251 became a law in the State of Indiana. Senate Bill 251 is a comprehensive bill which, among otherthings, provides Indiana utilities, including IPL, with a means for recovering 80% of costs incurred to comply with federal mandates through a periodic retail rate adjustment mechanism, and additional cost recovery is possible through a subsequent general rate case. This includes costs to comply with regulations from the EPA, FERC, NERC, the Department of Energy, etc., including capital intensive requirements and/or proposals such as those relating to cooling water intake regulations, waste management and coal combustion byproducts, wastewater effluent, MISO transmission expansion costs and polychlorinated biphenyls. It does not change existing legislation that allows for 100% recovery of clean coal technology designed to reduce air pollutants (Indiana Senate Bill 29).

Some of the most important features of Senate Bill 251 to IPL are as follows: any energy utility in Indiana seeking to recover federally mandated costs incurred in connection with a compliance project shall apply to the Indiana Utility Regulatory Commission (“IURC”) for a certificate of public convenience and necessity (“CPCN”) for the compliance project. It sets forth certain factors that the IURC must consider in determining whether to grant a CPCN. It further specifies that if the IURC approves a proposed compliance project and the projected federally mandated costs associated with the project, the following apply: (i) 80% of the approved costs shall be recovered by the energy utility through a periodic retail rate adjustment mechanism; (ii) 20% of the approved costs shall be deferred and recovered by the energy utility as part of the next general rate case filed by the energy utility with the IURC; and (iii) actual costs exceeding the projected federally mandated costs of the approved compliance project by more than 25% shall require specific justification and approval by the IURC before being authorized in the energy utility's next general rate case.

Guarantees, Letters of Credit and Commitments

In connection with certain project financing, acquisition, power purchase, and other agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, AES has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations primarily relate to future performance commitments which the Company or its businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 15 years.

The following table summarizes the Parent Company's contingent contractual obligations as of September 30, 2011. Amounts presented in the table below represent the Parent Company's current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of businesses of $26 million.

Contingent contractual obligations	Amount		Number of Agreements	Maximum Exposure Range for Each Agreement
	(in millions)			(in millions)
Guarantees	$	357	23	<$1 - $53
Letters of credit under the senior secured credit facility		12	11	<$1 - $7
Cash collateralized letters of credit		260	13	<$1 - $223
Total	$	629	47

As of September 30, 2011, the Company had $16 million of commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit discussed above. The Company expects to fund these net investment commitments in 2011. The exact payment schedules will be dictated by the construction milestones. Additionally, subject to regulatory approvals, the Company is committed to purchase DPL for $3.5 billion, see Note 17―Acquisitions for further information. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.

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 has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims of approximately $372 million and $448 million as of September 30, 2011 and December 31, 2010, respectively. These reserves are reported on the condensed consolidated balance sheets within “accrued and other liabilities” and “other long-term liabilities.” A significant portion of the reserves relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company's subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that these reserves will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

The Company believes, based upon information it currently possesses and taking into account established reserves for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company's financial statements. However, even where no reserve has been recognized, it is reasonably possible 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 could not be estimated as of September 30, 2011. The material contingencies where a loss is reasonably possible are described below. In aggregate, the Company estimates that the range of potential losses related to these material contingences to be up to $1.2 billion. The amounts considered reasonably possible do not include amounts reserved, as discussed above. Where a loss or range of loss cannot be estimated, a statement to this effect has been included in the applicable case descriptions presented below.

In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties' financing agreement. In April 1999, the Fifth District Court found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$1.2 billion ($656 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 (“AC”) ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been 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 were dismissed. Eletrobrás later requested that the amount of Eletropaulo's alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo consented to the appointment of such an expert, subject to a reservation of rights. In February 2010, the Fifth District Court appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization, in accordance with the methodology proposed by Eletrobrás. Pursuant to its reservation of rights, Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo's arguments and directing the Fifth District Court to proceed accordingly. Eletrobrás has restarted the accounting proceedings at the Fifth District Court, which will proceed in accordance with the AC's April 2010 decision. The parties are briefing the issues. In the Fifth District Court proceedings, the expert's conclusions will be subject to the Fifth District Court's review and approval. If Eletropaulo is determined to be responsible for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to 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 and, in turn the Company's results of operations could 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. The parties are disputing the proper venue for the CTEEP lawsuit. 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 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 seeking 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. 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. (“OPGC”), an equity method investment of the Company, 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. In June 2010, a 2-to-1 majority of the arbitral tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. 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 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 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 São 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. 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. In May 2010, the MPF filed an appeal with the Superior Court of Justice challenging the transfer. The MPF's lawsuit before the FCSP has been stayed pending a final decision on the interlocutory appeals. AES Elpa and AES Brasiliana (the successor of 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.

In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”), for the period from January through February 2009. The investigation of both Hydros has now been completed. The Antimonopoly Agency determined that the Hydros abused their market position and charged monopolistically high prices for power from January through February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($3 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of the Hydros. In the course of criminal proceedings, the financial police have expanded the periods at issue to the entirety of 2009 in the case of UK HPP and from January through October 2009 in the case of Shulbinsk HPP, and sought increased damages of KZT 1.2 billion ($8 million) in the case of UK HPP and KZT 1.3 billion ($9 million) in the case of Shulbinsk HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

In July 1993, the Public Attorney's office filed a claim against Eletropaulo, the Sao Paulo State Government, SABESP (a state-owned company), CETESB (the Environmental Agency of Sao Paulo State) and DAEE (the Municipal Water and Electric Energy Department) alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from the Pinheiros River into the 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 R$760 million ($415 million) for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo, which reversed the lower court decision. In 2009, the Public Attorney's Office filed appeals to both the Superior Court of Justice and the Supreme Court and such appeals were answered by Eletropaulo in the fourth quarter of 2009. 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 February 2009, a CAA Section 114 information request from the EPA regarding Cayuga and Somerset was received. The request seeks various operating and testing data and other information regarding certain types of projects at the Cayuga and Somerset facilities, generally for the time period from January 1, 2000 through the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. 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 the Company, its results of operations or its financial position.

On February 2, 2009, the Cayuga facility received a Notice of Violation from the New York State Department of Environmental Conservation (“NYSDEC”) 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 NYSDEC and submitted a Landfill Liner Demonstration Report to them. Such report found that the landfill has adequate engineering integrity to support the additional coal ash and there is no inherent environmental threat. NYSDEC has indicated they accept the finding of the report. A permit modification was approved by the NYSDEC on May 14, 2010 and such permit modification allows for closure of this approximately 10-acre portion of the landfill. The construction in accordance with the approved permit modification was completed in November 2010 and the certification report for this construction project was submitted to the NYSDEC in the second quarter of 2011. While at this time it is not possible to predict what impact, if any, this matter may have on the Company, its results of operations or its financial position, based upon the discussions to date, the Company does not believe the impact will be material.

In July 2009, AES Energía Cartagena S.R.L. (“AES Cartagena”) received notices from the Spanish national energy regulator, Comisión Nacional de Energía (“CNE”), stating that the proceeds of the sale of electricity from AES Cartagena's plant should be reduced by roughly the value of the CO2 allowances that were granted to AES Cartagena for free for the years 2007, 2008, and the first half of 2009. In particular, the notices stated that CNE intended to invoice AES Cartagena to recover that value, which CNE calculated as approximately €20 million ($27 million) for 2007-2008 and an amount to be determined for the first half of 2009. In September 2009, AES Cartagena received invoices for €523,548 (approximately $712,000) for the allowances granted for free for 2007 and €19,907,248 (approximately $27 million) for 2008. In July 2010, AES Cartagena received an invoice for approximately €5 million ($7 million) for the allowances granted for free for the first half of 2009. AES Cartagena does not expect to be charged for CO2 allowances issued free of charge for subsequent periods. AES Cartagena has paid the amounts invoiced and has filed challenges to the CNE's demands in the Spanish judicial system. There can be no assurances that the challenges will be successful. AES Cartagena has demanded indemnification from its fuel supply and electricity toller, GDF Suez S.A. (“GDFS”), in relation to the CNE invoices under the long-term energy agreement (the “Energy Agreement”) with GDFS. However, GDFS has disputed that it is responsible for the CNE invoices under the Energy Agreement. Therefore, in September 2009, AES Cartagena initiated arbitration against GDFS, seeking to recover the payments made to CNE. In the arbitration, AES Cartagena also seeks a determination that GDFS is responsible for procuring and bearing the cost of CO2 allowances that are required to offset the CO2 emissions of AES Cartagena's power plant, which is also in dispute between the parties. To date, AES Cartagena has paid approximately €25 million ($34 million) for the CO2 allowances that have been required to offset 2008, 2009 and 2010 CO2 emissions. AES Cartagena expects that allowances will need to be purchased to offset emissions for subsequent years. The evidentiary hearing in the arbitration took place from May 31-June 4, 2010, and closing arguments were heard on September 1, 2010. In February 2011, the arbitral tribunal requested further briefing on certain issues in the arbitration, which was later submitted by the parties. The tribunal has the matter under consideration. If AES Cartagena does not prevail in the arbitration and is required to bear the cost of carbon compliance, its results of operations could be materially adversely affected and, in turn, there could be a material adverse effect on the Company and its results of operations. 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. The parties have agreed to settle the dispute subject to the closing of a share sale agreement, which is subject to regulatory and lender approvals. See Note 20—Subsequent Events for further information. If the transaction does not close, the arbitration will continue, including the risks described above.

In November 2009, April 2010, December 2010, April 2011, June 2011, and August 2011, substantially similar personal injury lawsuits were filed by a total of 47 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico's power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs' birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The AES defendants moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs' international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. The AES defendants will respond to those amended complaints by October 31, 2011. The AES defendants will also respond to the December 2010, April 2011, June 2011 and August 2011 lawsuits after the relevant plaintiffs file amended complaints. The AES defendants believe they have meritorious defenses to the claims asserted against them and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.

On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns an unfinished 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor's obligations under the parties' EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million ($211 million). The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. The Contractor may attempt to seek relief relating to the bond dispute in the French or English courts. In addition, in December 2010, the Contractor stopped commissioning of the power plant's two units because of the alleged characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor's claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor's failure to complete the power plant and other breaches of the EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately €240 million ($326 million) in the arbitration, unspecified damages for alleged injury to reputation, and other relief. The arbitral hearing on the merits is in September 2012. Maritza 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.

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Impairments (Details) (USD $) In Millions	3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended			9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended				3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010	Sep. 30, 2011 Wind Turbines And Deposits [Member]	Sep. 30, 2010 Wind Turbines And Deposits [Member]	Sep. 30, 2011 Wind Turbines And Deposits [Member]	Sep. 30, 2010 Wind Turbines And Deposits [Member]	Sep. 30, 2011 Carbon Reduction Projects [Member]	Sep. 30, 2010 Carbon Reduction Projects [Member]	Sep. 30, 2011 Carbon Reduction Projects [Member]	Sep. 30, 2010 Carbon Reduction Projects [Member]	Sep. 30, 2011 Kelanitissa [Member]	Jun. 30, 2011 Kelanitissa [Member]	Sep. 30, 2010 Kelanitissa [Member]	Sep. 30, 2011 Kelanitissa [Member]	Sep. 30, 2010 Kelanitissa [Member]	Sep. 30, 2011 Southland Huntington Beach Subsidiary [Member]	Sep. 30, 2010 Southland Huntington Beach Subsidiary [Member]	Sep. 30, 2011 Southland Huntington Beach Subsidiary [Member]	Sep. 30, 2010 Southland Huntington Beach Subsidiary [Member]	Sep. 30, 2011 Tisza I I Subsidiary [Member]	Sep. 30, 2010 Tisza I I Subsidiary [Member]	Sep. 30, 2011 Tisza I I Subsidiary [Member]	Sep. 30, 2010 Tisza I I Subsidiary [Member]	Sep. 30, 2010 Deepwater Subsidiary [Member]	Sep. 30, 2011 Argentina Distribution And Generation Businesses [Member]	Sep. 30, 2011 Other Impairment [Member]	Sep. 30, 2010 Other Impairment [Member]	Sep. 30, 2011 Other Impairment [Member]	Sep. 30, 2010 Other Impairment [Member]	Sep. 30, 2011 Chigen [Member]
Asset Impairment Expense [Line Items]
Asset Impairment Charges	$ 163	$ 296	$ 196	$ 297		$ 116	$ 0	$ 116	$ 0	$ 33	$ 0	$ 33	$ 0	$ 4	$ 33	$ 0	$ 37	$ 0	$ 0	$ 200	$ 0	$ 200	$ 0	$ 85	$ 0	$ 85			$ 10	$ 11	$ 10	$ 12
Impairment losses	17	18	17	18																							18						17
Fair Value						45		45		11		11			33					88		88		75		75	0						0
Carrying Amount						161		161		49		49		66			66			288		288		160		160	18	317					17
Foreign currency translation adjustment	$ 2,002		$ 2,002		$ 1,824																							$ (208)

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Earnings Per Share (Details) (USD $) In Millions, except Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
BASIC EARNINGS PER SHARE
Income (loss) from continuing operations attributable to The AES Corporation common stockholders (Income)	$ (119)	$ 41	$ 296	$ 354
Income (loss) from continuing operations attributable to The AES Corporation common stockholders (Shares)	778,000,000	794,000,000	783,000,000	762,000,000
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax	$ (0.15)	$ 0.05	$ 0.38	$ 0.46
EFFECT OF DILUTIVE SECURITIES
Stock options (Shares)	0	2,000,000	1,000,000	2,000,000
Restricted stock units (Shares)	0	3,000,000	3,000,000	3,000,000
DILUTED EARNINGS PER SHARE (INCOME)	$ (119)	$ 41	$ 296	$ 354
DILUTED EARNINGS PER SHARE (SHARES)	778,000,000	799,000,000	787,000,000	767,000,000
Diluted Earnings Per Share	$ (0.15)	$ 0.05	$ 0.38	$ 0.46
Additional options outstanding that could potentially dilute EPS in the future			15,564,118	16,951,804
Shares of common stock issued upon exercise of stock options	115,597		589,948
Shares of common stock issued under the Company's profit sharing plan			1,073,539

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Contingencies and Commitments (Tables)

3 Months Ended

Sep. 30, 2011

Contingencies And Commitments Tables [Abstract]

Contingent Contractual Obligations

Contingent contractual obligations	Amount		Number of Agreements	Maximum Exposure Range for Each Agreement
	(in millions)			(in millions)
Guarantees	$	357	23	<$1 - $53
Letters of credit under the senior secured credit facility		12	11	<$1 - $7
Cash collateralized letters of credit		260	13	<$1 - $223
Total	$	629	47

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Other Income and Expense

3 Months Ended

Sep. 30, 2011

OTHER INCOME AND EXPENSE

13. OTHER INCOME (EXPENSE)

The components of other income for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(in millions)
Tax credit settlement	$	31	$	-	$	31	$	-
Tax dispute settlement		14		-		14		-
Extinguishment of liability		-		-		-		62
Gain on sale of assets		9		5		25		7
Other		4		12		38		25
Total other income	$	58	$	17	$	108	$	94

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

Other income of $58million for the three months ended September 30, 2011was primarily due to an additional tax credit settlement from a favorable court decision in 2011 concerning reimbursement of excess non-income taxes paid from 1989 to 1992 at Eletropaulo and the reimbursement of income tax expense recognized during the quarter related to anindemnity agreement between Los Mina and the Dominican Republic government.Other income of $17 million for the three months ended September 30, 2010 was primarily related to the gain on sale of assets at Eletropaulo.

Other income of $108million for the nine months ended September 30, 2011 was primarily related to the items described above, in addition to the gain on sale of mineral rights and land at IPL.Other income of $94 million for the nine months ended September 30, 2010 was primarily related to the extinguishment of a swap liability owed by two of our Brazilian subsidiaries, resulting in the recognition of a $62 million gain. The net impact to the Company after taxes and non-controlling interest was $9 million.

The components of other expense for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(in millions)
Loss on sale and disposal of assets	$	31	$	17	$	60	$	36
Loss on extinguishment of debt		36		-		52		9
Wind Generation transaction costs		-		-		-		22
Other		9		6		19		16
Total other expense	$	76	$	23	$	131	$	83

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

Other expense of $76million for the three months ended September 30, 2011 was primarily due to the premium paid on the early retirement of debt at Gener andlosses on the disposal of assets at TermoAndes and Eletropaulo.Other expense of $23 million for the three months ended September 30, 2010 was primarily comprised of losses on the disposal of assets at Eletropaulo and Gener.

Other expense of $131 million for the nine months ended September 30, 2011 was primarily due to the premium paid on early retirement of debt at Gener, a loss related to the early retirement of senior notes due in 2011 at IPL, and loss on disposal of assets at Eletropaulo and TermoAndes.Other expense of $83 million for the nine months ended September 30, 2010 included the previously capitalized transaction costs of $22 million that were incurred in connection with the preparation for the sale of a noncontrolling interest in our Wind Generation business. These costs were written off upon the expiration of the letter of intent (“LOI”) on June 30, 2010. Also, there was a $9 million loss on debt extinguishment at the Parent Company from the retirement of senior notes, and losses on disposal of assets at Eletropaulo and Gener.

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Condensed Consolidated Statements Of Operations (USD $) In Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Revenue:
Regulated	$ 2,405	$ 2,244	$ 7,228	$ 6,642
Non-Regulated	1,976	1,746	5,889	5,135
Total Revenue	4,381	3,990	13,117	11,777
Cost of Sales:
Regulated	(1,743)	(1,638)	(5,435)	(4,918)
Non-Regulated	(1,618)	(1,385)	(4,663)	(3,958)
Total cost of sales	(3,361)	(3,023)	(10,098)	(8,876)
Gross margin	1,020	967	3,019	2,901
General and administrative expenses	(91)	(98)	(283)	(279)
Interest expense	(432)	(381)	(1,178)	(1,151)
Interest income	103	96	293	304
Other expense	(76)	(23)	(131)	(83)
Other income	58	17	108	94
Gain on sale of investments	0	0	7	0
Goodwill impairment	(17)	(18)	(17)	(18)
Asset impairment expense	(163)	(296)	(196)	(297)
Foreign currency transaction (losses) gains on net monetary position	(92)	103	(21)	(19)
Other non-operating expense	(82)	(2)	(82)	(7)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES	228	365	1,519	1,445
Income tax expense	(84)	(102)	(469)	(540)
Net equity in earnings of affiliates	6	26	12	174
INCOME FROM CONTINUING OPERATIONS	150	289	1,062	1,079
Income from operations of discontinued businesses, net of income tax (benefit) expense of $(31), $8, $(33) and $23, respectively	25	29	23	92
Gain from disposal of discontinued businesses, net of income taxexpense of $0, $38, $0 and $38, respectively	0	79	0	57
NET INCOME	175	397	1,085	1,228
Noncontrolling interests:
Income from continuing operations attributable to noncontrolling interests	269	248	766	725
Income from discontinued operations attributable to noncontrolling interests	37	35	52	58
Total net income attributable to noncontrolling interests	(306)	(283)	(818)	(783)
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	(131)	114	267	445
BASIC EARNINGS PER SHARE:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax	$ (0.15)	$ 0.05	$ 0.38	$ 0.46
Discontinued operations attributable to The AES Corporation common stockholders, net of tax	$ (0.02)	$ 0.09	$ (0.04)	$ 0.12
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$ (0.17)	$ 0.14	$ 0.34	$ 0.58
DILUTED EARNINGS PER SHARE:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax	$ (0.15)	$ 0.05	$ 0.38	$ 0.46
Discontinued operations attributable to The AES Corporation common stockholders, net of tax	$ (0.02)	$ 0.09	$ (0.04)	$ 0.12
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$ (0.17)	$ 0.14	$ 0.34	$ 0.58
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income (loss) from continuing operations, net of tax	(119)	41	296	354
Discontinued operations, net of tax	(12)	73	(29)	91
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	$ (131)	$ 114	$ 267	$ 445

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Equity (Tables)

3 Months Ended

Sep. 30, 2011

Equity Tables [Abstract]

Components Of Comprehensive Income

				Three Months Ended				Nine Months Ended
				September 30,				September 30,
				2011		2010		2011		2010
				(in millions)				(in millions)
Net income				$	175	$	397	$	1,085	$	1,228
	Change in fair value of available-for-sale securities, net of income tax benefit
		of $0, $0, $1 and $4, respectively			(1)		-		(3)		(6)
	Foreign currency translation adjustments, net of income tax (expense)
		of $42, $(15), $28 and $(7), respectively			(589)		285		(327)		519
	Derivative activity:
		Reclassification to earnings, net of income tax (expense)
			of $(13), $(3), $(15) and $(22), respectively		53		13		112		81
		Change in derivative fair value, net of income tax benefit
			of $68, $23, $93 and $82, respectively		(236)		(99)		(305)		(336)
	Total net change in fair value of derivatives				(183)		(86)		(193)		(255)
	Change in unfunded pension obligation, net of income tax (expense)
		of $(2), $(1), $(6) and $(3), respectively			5		1		12		6
Other comprehensive income (loss)					(768)		200		(511)		264
Comprehensive income (loss)					(593)		597		574		1,492
Less: Comprehensive (income) loss attributable to noncontrolling interests(1)					12		(385)		(651)		(789)
Comprehensive income (loss) attributable to The AES Corporation				$	(581)	$	212	$	(77)	$	703

Components Of Accumulated Other Comprehensive Income

	September 30,		December 31,
	2011		2010
	(in millions)
Foreign currency translation adjustment	$	2,002	$	1,824
Unrealized derivative losses, net		511		344
Unfunded pension obligation		212		216
Securities available-for-sale		2		(1)
Accumulated other comprehensive loss	$	2,727	$	2,383

Schedule Of Net Income Attributable To Parent And Transfers To From Noncontrolling Interests [Text Block]

				Three Months Ended				Nine Months Ended
				September 30,				September 30,
				2011		2010		2011		2010
				(in millions)
Net (loss) income attributable to The AES Corporation				$	(131)	$	114	$	267	$	445
	Transfers (to) from the noncontrolling interests:
		Net increase in The AES Corporation's paid-in capital
			for sale of subsidiary shares		19		-		19		-
	Net transfers (to) from noncontrolling interest				19		-		19		-
Change from net income attributable to The AES Corporation
	and transfers (to) from noncontrolling interests			$	(112)	$	114	$	286	$	445

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Debt (Details) (USD $) In Millions, unless otherwise specified						9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011 Carrying Reported Amount Debt Disclosure [Member]	Dec. 31, 2010 Carrying Reported Amount Debt Disclosure [Member]	Sep. 30, 2011 Estimate Of Fair Value Debt Disclosure [Member]	Dec. 31, 2010 Estimate Of Fair Value Debt Disclosure [Member]	Sep. 30, 2011 Senior Unsecured Note 7375 Due 2021 [Member]	Sep. 30, 2011 Senior Secured Term Loan LIBOR Plus 325 [Member]	Sep. 30, 2011 Senior Unsecured Note 7375 Due 2021 And Senior Secured Term Loan LIBOR Plus 325 [Member]	Oct. 03, 2011 Senior Note 650 Due 2016 [Member]	Oct. 03, 2011 Senior Note 725 Due 2021 [Member]	Oct. 03, 2011 Senior Note 650 Due 2016 And 725 Due 2021 [Member]	Sep. 30, 2011 Covenant Violation [Member] Sonel [Member]	Sep. 30, 2011 Covenant Violation [Member] Kelanitissa [Member]	Sep. 30, 2011 Covenant Violation [Member] Maritza [Member]	Sep. 30, 2011 Sonel [Member]	Sep. 30, 2011 Kelanitissa [Member]	Sep. 30, 2011 Maritza [Member]	Sep. 30, 2011 New York [Member]
Debt Fair Value Detail [Abstract]
Non-recourse debt		$ 14,686	$ 14,938	$ 14,885	$ 15,269				$ 450	$ 800
Recourse debt		6,192	4,612	6,216	4,868	1,000	1,050	2,050
Total debt		20,878	19,550	21,101	20,137
Non Recourse Debt Transactions [Abstract]
Non Recourse Debt Total		14,686	14,938	14,885	15,269				450	800
Interest rate									6.50%	7.25%
Mandatory redemption price											101.00%
Letter of credit provided to cover interest payments											115
Mandatory redemption penalty											1.00%
Recourse Debt Transactions [Abstract]
Recourse Debt Total		6,192	4,612	6,216	4,868	1,000	1,050	2,050
Debt Instrument Interest Rate Plus Libor At Period End							3.25%
Debt Instrument Interest Rate Plus Base Rate At Period End							2.25%
Debt Instrument Repurchase Price Percent						101.00%
Interest Rate Lock Settlement Amount						24
Nonrecourse Debt Default [Line Items]
Default	1,299											342	22	935
Net Assets															306	6	216
Debt Accelerated Amount																		$ 203

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Discontinued Operations And Held For Sale Businesses (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Gain (loss) on disposal and impairment, after taxes	$ 0	$ 79	$ 0	$ 57
Tax effect of gain on disposal of discontinued operations	0	38	0	38
Discontinued Operations Income Loss
Revenue	107	218	327	948
(Loss) income from operations of discontinued businesses	(6)	37	(10)	115
Income tax benefit (expense)	31	(8)	33	(23)
Income from operations of discontinued businesses	25	29	23	92
Subsidiary Lal Pir And Pak Gen [Member]
Loss on disposal and impairment recognized net of tax and noncontrolling interests				14
Subsidiary Barka [Member]
Gain (loss) on disposal and impairment, after taxes				63
Tax effect of gain on disposal of discontinued operations				$ 38

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Investments In Marketable Securities (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Debt securities:
Unsecured debentures	$ 498		$ 498		$ 723
Certificates of deposit	447		447		876
Government debt securities	40		40		47
Other debt securities	40		40		42
Subtotal	1,025		1,025		1,688
Equity securities:
Mutual funds	56		56		62
Common stock	2		2		7
Subtotal	58		58		69
Total available-for-sale	1,083		1,083		1,757
Equity securities:
Mutual funds	10		10		10
Total trading	10		10		10
Total marketable securities	1,093		1,093		1,767
Footnotes to Marketable Securities Detail Table [Abstract]
Amortized cost of commmon stock available-for-sale	4		4		6
Debt securities with future maturities greater than ten years	40		40
Gain Loss On Marketable Securities
Losses included in earnings that relate to tradingsecurities held at the reporting date	(2)	(1)	(1)	0
Unrealized losses on available-for-sale securities included in other comprehensive income	(1)	0	(4)	(10)
Proceeds from sales of available-for-sale securities	1,134	1,420	4,218	4,644
Gross realized gains on sales	1	0	5	2
Level 1
Debt securities:
Unsecured debentures	0		0		0
Certificates of deposit	0		0		0
Government debt securities	0		0		0
Other debt securities	0		0		0
Subtotal	0		0		0
Equity securities:
Mutual funds	0		0		1
Common stock	2		2		7
Subtotal	2		2		8
Total available-for-sale	2		2		8
Equity securities:
Mutual funds	10		10		10
Total trading	10		10		10
Total marketable securities	12		12		18
Level 2
Debt securities:
Unsecured debentures	498		498		723
Certificates of deposit	447		447		876
Government debt securities	40		40		47
Other debt securities	0		0		0
Subtotal	985		985		1,646
Equity securities:
Mutual funds	56		56		61
Common stock	0		0		0
Subtotal	56		56		61
Total available-for-sale	1,041		1,041		1,707
Equity securities:
Mutual funds	0		0		0
Total trading	0		0		0
Total marketable securities	1,041		1,041		1,707
Level 3
Debt securities:
Unsecured debentures	0		0		0
Certificates of deposit	0		0		0
Government debt securities	0		0		0
Other debt securities	40		40		42
Subtotal	40		40		42
Equity securities:
Mutual funds	0		0		0
Common stock	0		0		0
Subtotal	0		0		0
Total available-for-sale	40		40		42
Equity securities:
Mutual funds	0		0		0
Total trading	0		0		0
Total marketable securities	$ 40		$ 40		$ 42

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Derivative Instruments and Hedging Activities (Details) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended																			3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended				3 Months Ended				9 Months Ended		3 Months Ended				3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended																																													3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2011 USD ($)	Sep. 30, 2010 USD ($)	Sep. 30, 2011 USD ($)	Sep. 30, 2010 USD ($)	Dec. 31, 2010 USD ($)	Sep. 30, 2011 Interest Rate Derivatives Current [Member] Libor USD [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Current [Member] Euribor EUR [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Current [Member] Euribor EUR [Member] EUR (€)	Sep. 30, 2011 Interest Rate Derivatives Current [Member] Libor GBP [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Current [Member] Libor GBP [Member] GBP (£)	Sep. 30, 2011 Interest Rate Derivatives Current [Member] Securities Industry and Financial Markets Association Municipal Swap Index USD [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Maximum [Member] Libor USD [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Maximum [Member] Euribor EUR [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Maximum [Member] Euribor EUR [Member] EUR (€)	Sep. 30, 2011 Interest Rate Derivatives Maximum [Member] Libor GBP [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Maximum [Member] Libor GBP [Member] GBP (£)	Sep. 30, 2011 Interest Rate Derivatives Maximum [Member] Securities Industry and Financial Markets Association Municipal Swap Index USD [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Libor USD [Member]	Sep. 30, 2011 Interest Rate Derivatives Euribor EUR [Member]	Sep. 30, 2011 Interest Rate Derivatives Libor GBP [Member]	Sep. 30, 2011 Interest Rate Derivatives Securities Industry and Financial Markets Association Municipal Swap Index USD [Member]	Sep. 30, 2011 Interest Rate Derivatives USD ($)	Sep. 30, 2010 Interest Rate Derivatives USD ($)	Sep. 30, 2011 Interest Rate Derivatives USD ($)	Sep. 30, 2010 Interest Rate Derivatives USD ($)	Sep. 30, 2011 Interest Rate Derivatives Interest expense [Member] USD ($)	Sep. 30, 2010 Interest Rate Derivatives Interest expense [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Interest expense [Member] USD ($)	Sep. 30, 2010 Interest Rate Derivatives Interest expense [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Non-regulated revenue USD ($)	Sep. 30, 2010 Interest Rate Derivatives Non-regulated revenue USD ($)	Sep. 30, 2011 Interest Rate Derivatives Non-regulated cost of sales USD ($)	Sep. 30, 2010 Interest Rate Derivatives Non-regulated cost of sales USD ($)	Sep. 30, 2011 Interest Rate Derivatives Net Equity In Earnings Of Affiliates [Member] USD ($)	Sep. 30, 2010 Interest Rate Derivatives Net Equity In Earnings Of Affiliates [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Net Equity In Earnings Of Affiliates [Member] USD ($)	Sep. 30, 2010 Interest Rate Derivatives Net Equity In Earnings Of Affiliates [Member] USD ($)	Sep. 30, 2011 Interest Rate Derivatives Discontinued Operations [Member] USD ($)	Sep. 30, 2010 Interest Rate Derivatives Discontinued Operations [Member] USD ($)	Sep. 30, 2011 Cross Currency Swaps Chilean Unidad De Fomento CLF [Member] USD ($)	Sep. 30, 2011 Cross Currency Swaps Chilean Unidad De Fomento CLF [Member] CLF	Sep. 30, 2011 Cross Currency Swaps USD ($)	Sep. 30, 2010 Cross Currency Swaps USD ($)	Sep. 30, 2011 Cross Currency Swaps USD ($)	Sep. 30, 2010 Cross Currency Swaps USD ($)	Sep. 30, 2011 Cross Currency Swaps Interest expense [Member] USD ($)	Sep. 30, 2010 Cross Currency Swaps Interest expense [Member] USD ($)	Sep. 30, 2011 Cross Currency Swaps Interest expense [Member] USD ($)	Sep. 30, 2010 Cross Currency Swaps Interest expense [Member] USD ($)	Sep. 30, 2011 Cross Currency Swaps Foreign currency transaction gains (losses) USD ($)	Sep. 30, 2010 Cross Currency Swaps Foreign currency transaction gains (losses) USD ($)	Sep. 30, 2011 Cross Currency Swaps Foreign currency transaction gains (losses) USD ($)	Sep. 30, 2010 Cross Currency Swaps Foreign currency transaction gains (losses) USD ($)	Sep. 30, 2011 Foreign Currency Options Euro EUR [Member] USD ($)	Sep. 30, 2011 Foreign Currency Options Euro EUR [Member] EUR (€)	Sep. 30, 2011 Foreign Currency Options Brazilian Real BRL [Member] USD ($)	Sep. 30, 2011 Foreign Currency Options Brazilian Real BRL [Member] BRL	Sep. 30, 2011 Foreign Currency Options British Pound GBP [Member] USD ($)	Sep. 30, 2011 Foreign Currency Options British Pound GBP [Member] GBP (£)	Sep. 30, 2011 Foreign Currency Options Argentine Peso ARS [Member] USD ($)	Sep. 30, 2011 Foreign Currency Options Argentine Peso ARS [Member] ARS	Sep. 30, 2011 Foreign Currency Forwards Euro EUR [Member] USD ($)	Sep. 30, 2011 Foreign Currency Forwards Euro EUR [Member] EUR (€)	Sep. 30, 2011 Foreign Currency Forwards British Pound GBP [Member] USD ($)	Sep. 30, 2011 Foreign Currency Forwards British Pound GBP [Member] GBP (£)	Sep. 30, 2011 Foreign Currency Forwards Chilean Peso CLP [Member] USD ($)	Sep. 30, 2011 Foreign Currency Forwards Chilean Peso CLP [Member] CLP	Sep. 30, 2011 Foreign Currency Forwards Colombian Peso COP [Member] USD ($)	Sep. 30, 2011 Foreign Currency Forwards Colombian Peso COP [Member] COP	Sep. 30, 2011 Foreign Currency Forwards Argentine Peso ARS [Member] USD ($)	Sep. 30, 2011 Foreign Currency Forwards Argentine Peso ARS [Member] ARS	Sep. 30, 2011 Embedded Foreign Currency Derivatives Euro EUR [Member] USD ($)	Sep. 30, 2011 Embedded Foreign Currency Derivatives Euro EUR [Member] EUR (€)	Sep. 30, 2011 Embedded Foreign Currency Derivatives Brazilian Real BRL [Member] USD ($)	Sep. 30, 2011 Embedded Foreign Currency Derivatives Brazilian Real BRL [Member] BRL	Sep. 30, 2011 Embedded Foreign Currency Derivatives Philippine Peso PHP [Member] USD ($)	Sep. 30, 2011 Embedded Foreign Currency Derivatives Philippine Peso PHP [Member] PHP	Sep. 30, 2011 Embedded Foreign Currency Derivatives Argentine Peso ARS [Member] USD ($)	Sep. 30, 2011 Embedded Foreign Currency Derivatives Argentine Peso ARS [Member] ARS	Sep. 30, 2011 Embedded Foreign Currency Derivatives Kazakhstani Tenge KZT [Member] USD ($)	Sep. 30, 2011 Embedded Foreign Currency Derivatives Kazakhstani Tenge KZT [Member] KZT	Sep. 30, 2011 Embedded Foreign Currency Derivatives Hungarian Forint HUF [Member] USD ($)	Sep. 30, 2011 Embedded Foreign Currency Derivatives Hungarian Forint HUF [Member] HUF	Sep. 30, 2011 Commodity Derivatives Natural Gas MMBTU [Member] MMBTU	Sep. 30, 2011 Commodity Derivatives Petcoke Metric Tons [Member] MetricTons	Sep. 30, 2011 Commodity Derivatives Aluminum M Wh [Member] MWh	Sep. 30, 2011 Level 1 USD ($)	Dec. 31, 2010 Level 1 USD ($)	Sep. 30, 2011 Level 2 USD ($)	Dec. 31, 2010 Level 2 USD ($)	Sep. 30, 2011 Level 3 USD ($)	Dec. 31, 2010 Level 3 USD ($)	Sep. 30, 2011 Designated as Hedging Instruments USD ($)	Dec. 31, 2010 Designated as Hedging Instruments USD ($)	Sep. 30, 2011 Not Designated as Hedging Instruments USD ($)	Dec. 31, 2010 Not Designated as Hedging Instruments USD ($)	Sep. 30, 2011 Foreign Currency USD ($)	Sep. 30, 2010 Foreign Currency USD ($)	Sep. 30, 2011 Foreign Currency USD ($)	Sep. 30, 2010 Foreign Currency USD ($)	Sep. 30, 2011 Foreign Currency Foreign currency transaction gains (losses) USD ($)	Sep. 30, 2010 Foreign Currency Foreign currency transaction gains (losses) USD ($)	Sep. 30, 2011 Foreign Currency Foreign currency transaction gains (losses) USD ($)	Sep. 30, 2010 Foreign Currency Foreign currency transaction gains (losses) USD ($)	Sep. 30, 2011 Foreign Currency Net Equity In Earnings Of Affiliates [Member] USD ($)	Sep. 30, 2010 Foreign Currency Net Equity In Earnings Of Affiliates [Member] USD ($)	Sep. 30, 2011 Foreign Currency Net Equity In Earnings Of Affiliates [Member] USD ($)	Sep. 30, 2010 Foreign Currency Net Equity In Earnings Of Affiliates [Member] USD ($)	Sep. 30, 2011 Commodity & Other USD ($)	Sep. 30, 2010 Commodity & Other USD ($)	Sep. 30, 2011 Commodity & Other USD ($)	Sep. 30, 2010 Commodity & Other USD ($)	Sep. 30, 2011 Commodity & Other Non-regulated revenue USD ($)	Sep. 30, 2010 Commodity & Other Non-regulated revenue USD ($)	Sep. 30, 2011 Commodity & Other Non-regulated revenue USD ($)	Sep. 30, 2010 Commodity & Other Non-regulated revenue USD ($)	Sep. 30, 2011 Commodity & Other Non-regulated cost of sales USD ($)	Sep. 30, 2010 Commodity & Other Non-regulated cost of sales USD ($)	Sep. 30, 2011 Commodity & Other Non-regulated cost of sales USD ($)	Sep. 30, 2010 Commodity & Other Non-regulated cost of sales USD ($)	Sep. 30, 2011 Discontinued Operations [Member] USD ($)	Sep. 30, 2010 Discontinued Operations [Member] USD ($)	Sep. 30, 2011 Gener Subsidiary [Member] USD ($)
Derivative Tables [Line Items]
Notional Amount Of Interest Rate Derivatives						$ 3,511	$ 1,435	€ 1,072	$ 98	£ 63	$ 40	$ 3,585	$ 1,435	€ 1,072	$ 112	£ 72	$ 40
Weighted Average Remaining Term																		9	13	12	11																			14	14													<1	<1	<1	<1	<1	<1	<1	<1	2	2	1	1	<1	<1	<1	<1	1	1	2	2	1	1	2	2	11	11	9	9	<1	<1	11	13	8
% of Debt Currently Hedged by Index																		75.00%	66.00%	87.00%																				83.00%	83.00%
Notional Amount Of Foreign Currency Derivatives																																								237														96	67	105	173	47	29	20	88	169	123	17	11	201	98,944	44	80,376	13	61	27	20	2	4	363	15,973	215	904	207	30,606	46	10,114
Notional (CLF)																																									6
Probability Adjusted Notional																																																						82		96		40		8
Notional																																																																																				33,000,000	13,000,000	16,000,000
Current assets:
Foreign currency derivatives	52		52		7																																																																																		0	0	48	4	4	3	17	0	35	7
Commodity and other derivatives	5		5		5																																																																																		0	0	0	2	5	3	0	0	5	5
Total current assets	57		57		12																																																																																		0	0	48	6	9	6	17	0	40	12
Noncurrent assets:
Interest rate derivatives	0		0		49																																																																																		0	0	0	49	0	0	0	49	0	0
Foreign currency derivatives	54		54		31																																																																																		0	0	5	4	49	27	2	0	52	31
Cross currency derivatives	1		1		12																																																																																		0	0	0	0	1	12	1	12	0	0
Commodity and other derivatives	5		5		20																																																																																		0	0	4	4	1	16	0	0	5	20
Total noncurrent assets	60		60		112																																																																																		0	0	9	57	51	55	3	61	57	51
Total assets	117		117		124																																																																																		0	0	57	63	60	61	20	61	97	63
Current liabilities:
Interest rate derivatives	131		131		137																																																																																		0	0	102	137	29	0	126	126	5	11
Cross currency derivatives	5		5		2																																																																																		0	0	0	0	5	2	5	2	0	0
Foreign currency derivatives	7		7		13																																																																																		0	0	6	13	1	0	1	8	6	5
Commodity and other derivatives	8		8		0																																																																																		0	0	5	0	3	0	0	0	8	0
Total current liabilities	151		151		152																																																																																		0	0	113	150	38	2	132	136	19	16
Noncurrent liabilities:
Interest rate derivatives	456		456		247																																																																																		0	0	294	246	162	1	437	232	19	15
Cross currency derivatives	17		17		0																																																																																		0	0	0	0	17	0	17	0	0	0
Foreign currency derivatives	22		22		23																																																																																		0	0	11	15	11	8	0	0	22	23
Commodity and other derivatives	42		42		1																																																																																		0	0	1	0	41	1	0	0	42	1
Total noncurrent liabilities	537		537		271																																																																																		0	0	306	261	231	10	454	232	83	39
Total liabilities	688		688		423																																																																																		0	0	419	411	269	12	586	368	102	55
AOCI to be recognized in next 12 months table
Accumulated Other Comprehensive Income (Loss)																						(116)		(116)																		(1)		(1)																																																					16		16
Gain Loss By Type Of Derivative Tables
Gains (Losses) Recognized in AOCL	(305)	(130)	(396)	(402)																		(297)	(138)	(389)	(388)																	(37)	24	(34)	(5)																																																				29	(12)	27	(5)									0	(4)	0	(4)
Gains (Losses) Reclassified from AOCL into Earnings	(65)	3	(124)	(71)																						(35)	(24)	(88)	(81)	(3)	(3)	(1)	(3)	(1)	(1)	(3)	(3)	0	(20)							(3)	0	(7)	(1)	(26)	30	(20)	16																																																3	1	(1)	1													(2)	0	(2)	0	0	(30)
Gains (Losses) Recognized in Earnings (ineffective portion)	(3)	(10)	(13)	(15)																						1	(10)	(6)	(18)					(1)	0	(2)	(1)									(3)	0	(5)	4																																																				0	0	0	0
Gains (Losses) Recognized in Earnings (not designated as hedging instruments)	(25)	(12)	(9)	(31)																						(1)	(3)	(2)	(8)																																																																								27	(7)	54	(32)	0	0	0	2					(54)	1	(63)	5	3	(3)	2	2
IPL Regulatory Activity Narrative
(Increase) decrease in regulatory assets	(4)	(3)	(6)	(6)
Increase (decrease) in regulatory liabilities	(3)	(2)	3	2
Credit Risk-Related Contingent Features [Line Items]
Net liability position, derivative transactions																																																																																																																											$ 21

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Other Income and Expense (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Component Of Other Income [Line Items]
Total other income	$ 58	$ 17	$ 108	$ 94
Other Income Net Of Tax And NCI				9
Component Of Operating Other Cost And Expense [Line Items]
Total other expense	76	23	131	83
Tax Credit Settlement [Member]
Component Of Other Income [Line Items]
Total other income	31	0	31	0
Tax Dispute Settlement [Member]
Component Of Other Income [Line Items]
Total other income	14	0	14	0
Extinguishment Of Liability [Member]
Component Of Other Income [Line Items]
Total other income	0	0	0	62
Gain on sale of assets
Component Of Other Income [Line Items]
Total other income	9	5	25	7
Other Income Other [Member]
Component Of Other Income [Line Items]
Total other income	4	12	38	25
Loss On Sale And Disposal Of Assets [Member]
Component Of Operating Other Cost And Expense [Line Items]
Total other expense	31	17	60	36
Parent Company | Loss On Extinguishment Of Debt [Member]
Component Of Operating Other Cost And Expense [Line Items]
Total other expense				9
Loss On Extinguishment Of Debt [Member]
Component Of Operating Other Cost And Expense [Line Items]
Total other expense	36	0	52	9
Wind Generation Transaction Costs [Member]
Component Of Operating Other Cost And Expense [Line Items]
Total other expense	0	0	0	22
Other Member
Component Of Operating Other Cost And Expense [Line Items]
Total other expense	$ 9	$ 6	$ 19	$ 16

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Segments (Tables)

3 Months Ended

Sep. 30, 2011

Segments Tables [Abstract]

Revenue By Segment Table

Three Months Ended	Total Revenue				Intersegment				External Revenue
September 30,	2011		2010		2011		2010		2011		2010
	(in millions)
Latin America - Generation	$	1,302	$	1,111	$	(328)	$	(267)	$	974	$	844
Latin America - Utilities		1,930		1,757		-		-		1,930		1,757
North America - Generation		372		413		-		-		372		413
North America - Utilities		321		306		-		-		321		306
Europe - Generation		397		282		-		-		397		282
Asia - Generation		172		136		-		-		172		136
Corp/Other & eliminations		(113)		(15)		328		267		215		252
Total Revenue	$	4,381	$	3,990	$	-	$	-	$	4,381	$	3,990

Nine Months Ended	Total Revenue				Intersegment				External Revenue
September 30,	2011		2010		2011		2010		2011		2010
	(in millions)
Latin America - Generation	$	3,810	$	3,178	$	(842)	$	(778)	$	2,968	$	2,400
Latin America - Utilities		5,774		5,236		-		-		5,774		5,236
North America - Generation		1,116		1,173		(4)		-		1,112		1,173
North America - Utilities		890		869		-		-		890		869
Europe - Generation		1,125		864		(1)		-		1,124		864
Asia - Generation		449		491		-		-		449		491
Corp/Other & eliminations		(47)		(34)		847		778		800		744
Total Revenue	$	13,117	$	11,777	$	-	$	-	$	13,117	$	11,777

Adjusted Gross Margin by Segment Table

Three Months Ended	Total Adjusted Gross Margin				Intersegment				External Adjusted Gross Margin
September 30,	2011		2010		2011		2010		2011		2010
	(in millions)
Latin America - Generation	$	505	$	436	$	(313)	$	(262)	$	192	$	174
Latin America - Utilities		378		306		322		267		700		573
North America - Generation		145		146		3		5		148		151
North America - Utilities		113		118		-		-		113		118
Europe - Generation		128		71		2		2		130		73
Asia - Generation		35		51		-		1		35		52
Corp/Other & eliminations		(62)		12		(14)		(13)		(76)		(1)
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization										(313)		(271)
Interest expense										(432)		(381)
Interest income										103		96
Other expense										(76)		(23)
Other income										58		17
Goodwill impairment										(17)		(18)
Asset impairment expense										(163)		(296)
Foreign currency transaction (losses) gains on net monetary position										(92)		103
Other non-operating expense										(82)		(2)
Income from continuing operations before taxes and equity in earnings of affiliates									$	228	$	365

Nine Months Ended	Total Adjusted Gross Margin				Intersegment				External Adjusted Gross Margin
September 30,	2011		2010		2011		2010		2011		2010
	(in millions)
Latin America - Generation	$	1,493	$	1,296	$	(800)	$	(766)	$	693	$	530
Latin America - Utilities		1,035		888		820		778		1,855		1,666
North America - Generation		402		406		6		12		408		418
North America - Utilities		292		324		1		1		293		325
Europe - Generation		327		287		4		5		331		292
Asia - Generation		133		204		1		3		134		207
Corp/Other & eliminations		(37)		19		(32)		(33)		(69)		(14)
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization										(909)		(802)
Interest expense										(1,178)		(1,151)
Interest income										293		304
Other expense										(131)		(83)
Other income										108		94
Gain on sale of investments										7		-
Goodwill impairment										(17)		(18)
Asset impairment expense										(196)		(297)
Foreign currency transaction (losses) gains on net monetary position										(21)		(19)
Other non-operating expense										(82)		(7)
Income from continuing operations before taxes and equity in earnings of affiliates									$	1,519	$	1,445

Assets By Segment Table

	Total Assets
	September 30, 2011		December 31, 2010
	(in millions)
Assets
Latin America - Generation	$	10,545	$	10,373
Latin America - Utilities		8,938		9,872
North America - Generation		4,403		4,681
North America - Utilities		3,218		3,139
Europe - Generation		4,264		4,178
Asia - Generation		1,725		1,762
Discontinued businesses		407		468
Corp/Other & eliminations		7,383		6,038
Total Assets	$	40,883	$	40,511