Edgar Filing: AES CORP

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended September 30, 2011

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

Commission file number 1-12291

LOGO

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):

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

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

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

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

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.

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.

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

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

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 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.

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


	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	)


	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.

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
	Carrying Amount		Level 1		Level 2		Level 3		Gross 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 Amount		Fair Value						Gross Loss
	Carrying Amount		Level 1		Level 2		Level 3		Gross 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 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.

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

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.

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.

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

⁽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

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.

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	)

⁽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	)

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,

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.

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
Subsidiary	Primary Nature 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 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.

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.

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

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

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.

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

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.

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 appo

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