Edgar Filing: AES CORP

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, 2010

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):


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

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

The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, on October 29, 2010 was 788,099,808.

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2010

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*	93

*ITEM 4.*	*CONTROLS AND PROCEDURES*	95

PART II: OTHER INFORMATION		96

*ITEM 1.*	*LEGAL PROCEEDINGS*	96

*ITEM 1A.*	*RISK FACTORS*	96

*ITEM 2.*	*UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS*	96

*ITEM 3.*	*DEFAULTS UPON SENIOR SECURITIES*	96

*ITEM 4.*	*REMOVED AND RESERVED*	96

*ITEM 5.*	*OTHER INFORMATION*	96

*ITEM 6.*	*EXHIBITS*	97

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,
	2010			2009			2010			2009
	(in millions, except per share amounts)
Revenue:
Regulated	$	2,274		$	2,097		$	6,728		$	5,542
Non-Regulated		1,877			1,555			5,515			4,636

Total revenue		4,151			3,652			12,243			10,178

Cost of Sales:
Regulated		(1,653	)		(1,457	)		(4,960	)		(3,988	)
Non-Regulated		(1,513	)		(1,228	)		(4,330	)		(3,571	)

Total cost of sales		(3,166	)		(2,685	)		(9,290	)		(7,559	)

Gross margin		985			967			2,953			2,619

General and administrative expenses		(98	)		(81	)		(279	)		(251	)
Interest expense		(387	)		(406	)		(1,167	)		(1,146	)
Interest income		97			90			307			272
Other expense		(23	)		(15	)		(83	)		(67	)
Other income		20			36			97			279
Gain on sale of investments		-			17			-			132
Goodwill impairment		(18	)		-			(18	)		-
Asset impairment expense		(296	)		(6	)		(297	)		(7	)
Foreign currency transaction gains (losses) on net monetary position		103			(1	)		(19	)		(12	)
Other non-operating expense		(2	)		(2	)		(7	)		(12	)

INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES		381			599			1,487			1,807
Income tax expense		(111	)		(203	)		(562	)		(482	)
Net equity in earnings of affiliates		26			18			174			75

INCOME FROM CONTINUING OPERATIONS		296			414			1,099			1,400
Income from operations of discontinued businesses, net of income tax expense of $0, $2, $2 and $3, respectively		22			26			72			72
Gain from disposal of discontinued businesses, net of income tax expense of $38, $0, $38 and $0, respectively		79			-			57			-

NET INCOME		397			440			1,228			1,472
Noncontrolling interests:
Less: Income from continuing operations attributable to noncontrolling interests		(253	)		(243	)		(741	)		(735	)
Less: Income from discontinued operations attributable to noncontrolling interests		(30	)		(12	)		(42	)		(31	)

Total net income attributable to noncontrolling interests		(283	)		(255	)		(783	)		(766	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	114		$	185		$	445		$	706

BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.05		$	0.26		$	0.47		$	1.00
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		0.09			0.02			0.11			0.06

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.14		$	0.28		$	0.58		$	1.06

DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.05		$	0.26		$	0.47		$	1.00
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		0.09			0.02			0.11			0.06

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.14		$	0.28		$	0.58		$	1.06

AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	43		$	171		$	358		$	665
Discontinued operations, net of tax		71			14			87			41

Net income	$	114		$	185		$	445		$	706

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Balance Sheets


	September 30, 2010			December 31, 2009
	(in millions except share and per share data)
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,848		$	1,782
Restricted cash		609			407
Short-term investments		1,645			1,648
Accounts receivable, net of allowance for doubtful accounts of $305 and $290, respectively		2,349			2,118
Inventory		611			560
Receivable from affiliates		32			24
Deferred income taxes — current		244			210
Prepaid expenses		190			161
Other current assets		1,142			1,557
Current assets of discontinued and held for sale businesses		98			320

Total current assets		9,768			8,787

NONCURRENT ASSETS
Property, Plant and Equipment:
Land		1,104			1,111
Electric generation, distribution assets and other		28,800			26,815
Accumulated depreciation		(9,151	)		(8,774	)
Construction in progress		4,222			4,644

Property, plant and equipment, net		24,975			23,796

Other Assets:
Deferred financing costs, net of accumulated amortization of $303 and $293, respectively		382			377
Investments in and advances to affiliates		1,313			1,157
Debt service reserves and other deposits		606			595
Goodwill		1,276			1,299
Other intangible assets, net of accumulated amortization of $240 and $223, respectively		610			510
Deferred income taxes — noncurrent		689			587
Other		1,634			1,551
Noncurrent assets of discontinued and held for sale businesses		527			876

Total other assets		7,037			6,952

TOTAL ASSETS	$	41,780		$	39,535

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and other accrued liabilities	$	4,523		$	4,193
Accrued interest		375			269
Non-recourse debt — current		1,591			1,718
Recourse debt — current		464			214
Current liabilities of discontinued and held for sale businesses		76			227

Total current liabilities		7,029			6,621

LONG-TERM LIABILITIES
Non-recourse debt — noncurrent		13,482			12,304
Recourse debt — noncurrent		4,438			5,301
Deferred income taxes — noncurrent		1,249			1,090
Pension and other post-retirement liabilities		1,306			1,322
Other long-term liabilities		3,025			3,146
Long-term liabilities of discontinued and held for sale businesses		408			811

Total long-term liabilities		23,908			23,974

Contingencies and Commitments (see Note 8)
Redeemable stock of subsidiaries		60			60
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 804,560,572 issued and 794,115,103 outstanding at September 30, 2010 and 677,214,493 issued and 667,679,913 outstanding at December 31, 2009		8			7
Additional paid-in capital		8,462			6,868
Retained earnings		1,056			650
Accumulated other comprehensive loss		(2,504	)		(2,724	)
Treasury stock, at cost (10,445,469 shares at September 30, 2010 and 9,534,580 shares at December 31, 2009, respectively)		(132	)		(126	)

Total The AES Corporation stockholders’ equity		6,890			4,675
NONCONTROLLING INTERESTS		3,893			4,205

Total equity		10,783			8,880

TOTAL LIABILITIES AND EQUITY	$	41,780		$	39,535

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
	2010			2009
	(in millions)
OPERATING ACTIVITIES:
Net income	$	1,228		$	1,472
Adjustments to net income:
Depreciation and amortization		876			767
(Gain) loss from sale of investments and impairment expense		350			(115	)
(Gain) loss on disposal and impairment write-down — discontinued operations		(102	)		-
Provision for deferred taxes		31			(24	)
Contingencies		75			(14	)
(Gain) loss on the extinguishment of debt		9			(3	)
Undistributed gain from sale of equity method investment		(118	)		-
Other		(81	)		33
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(136	)		(82	)
(Increase) decrease in inventory		9			(10	)
(Increase) decrease in prepaid expenses and other current assets		190			92
(Increase) decrease in other assets		(51	)		(133	)
Increase (decrease) in accounts payable and accrued liabilities		4			(159	)
Increase (decrease) in income taxes and other income tax payables, net		20			96
Increase (decrease) in other liabilities		108			(43	)

Net cash provided by operating activities		2,412			1,877

INVESTING ACTIVITIES:
Capital expenditures		(1,528	)		(1,765	)
Acquisitions — net of cash acquired		(237	)		-
Proceeds from the sale of businesses		369			2
Proceeds from the sale of assets		11			16
Sale of short-term investments		4,583			3,277
Purchase of short-term investments		(4,540	)		(2,774	)
(Increase) decrease in restricted cash		(82	)		272
(Increase) decrease in debt service reserves and other assets		(9	)		80
Affiliate advances and equity investments		(77	)		(137	)
Proceeds from loan repayments		132			-
Other investing		31			(15	)

Net cash used in investing activities		(1,347	)		(1,044	)

FINANCING ACTIVITIES:
Issuance of common stock		1,566			-
Borrowings (repayments) under the revolving credit facilities, net		74			(96	)
Issuance of recourse debt		-			503
Issuance of non-recourse debt		1,497			1,189
Repayments of recourse debt		(619	)		(154	)
Repayments of non-recourse debt		(1,441	)		(622	)
Payments for deferred financing costs		(50	)		(72	)
Distributions to noncontrolling interests		(951	)		(561	)
Contributions from noncontrolling interests		-			75
Financed capital expenditures		(21	)		(27	)
Purchase of treasury stock		(15	)		-
Other financing		(18	)		8

Net cash provided by financing activities		22			243
Effect of exchange rate changes on cash		(21	)		19

Total increase in cash and cash equivalents		1,066			1,095
Cash and cash equivalents, beginning		1,782			865

Cash and cash equivalents, ending	$	2,848		$	1,960

SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	1,003		$	971
Cash payments for income taxes, net of refunds	$	589		$	389
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Assets acquired in noncash asset exchange	$	-		$	111

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statement of Changes in Equity

(Unaudited)


	THE AES CORPORATION STOCKHOLDERS													Noncontrolling Interests			Consolidated Comprehensive Income
	Common Stock		Treasury Stock			Additional Paid-In Capital		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 pension 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
Dividends declared to noncontrolling interests		-		-			-		-			-			(1,068	)
Disposition of businesses		-		-			-		-			-			(78	)
Issuance of common stock		1		-			1,566		-			-			-
Acquisition of treasury stock		-		(15	)		-		-			-			-
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


	THE AES CORPORATION STOCKHOLDERS													Noncontrolling Interests			Consolidated Comprehensive Income
	Common Stock		Treasury Stock			Additional Paid-In Capital		(Accumulated Deficit) / Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Consolidated Comprehensive Income
	(in millions)
Balance at January 1, 2009	$	7	$	(144	)	$	6,832	$	(8	)	$	(3,018	)	$	3,358
Net income		-		-			-		706			-			766		$	1,472
Change in fair value of available-for-sale securities, net of income tax		-		-			-		-			6			-			6
Foreign currency translation adjustment, net of income tax		-		-			-		-			117			437			554
Change in unfunded pension obligation, net of income tax		-		-			-		-			2			-			2
Change in derivative fair value, including a reclassification to earnings, net of income tax		-		-			-		-			38			24			62

Other comprehensive income																		624

Total comprehensive income																	$	2,096

Capital contributions from noncontrolling interests		-		-			-		-			-			79
Dividends declared to noncontrolling interests		-		-			-		-			-			(673	)
Disposition of businesses		-		-			-		-			-			(7	)
Preferred dividends of subsidiary		-		-			-		-			-			(2	)
Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax		-		18			11		-			-			-
Stock compensation		-		-			16		-			-			-

Balance at September 30, 2009	$	7	$	(126	)	$	6,859	$	698		$	(2,855	)	$	3,982

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, 2010 and 2009

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 14 — Discontinued Operations and Held for Sale Businesses.

Consolidation

In this Quarterly Report the terms “AES”, “the Company”, “us” or “we” refer to the consolidated entity including its subsidiaries and affiliates. The terms “The AES Corporation”, “the Parent” or “the Parent Company” refer only to the publicly-held holding company, The AES Corporation, excluding its subsidiaries and affiliates. Furthermore, variable interest entities (“VIEs”) in which the Company has an interest have been consolidated where the Company is the primary beneficiary. Investments in which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting. All intercompany transactions and balances have been eliminated in consolidation.

Interim Financial Presentation

The accompanying unaudited condensed consolidated financial statements and footnotes have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) as contained in the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (the “Codification” or “ASC”) for interim financial information and Article 10 of Regulation S-X issued by the Securities and Exchange Commission (“SEC”). Accordingly, they do not include all the information and footnotes required by U.S. GAAP for annual fiscal reporting periods. In the opinion of management, the interim financial information includes all adjustments of a normal recurring nature necessary for a fair presentation of the results of operations, financial position, changes in equity and cash flows. The results of operations for the three and nine months ended September 30, 2010 are not necessarily indicative of results that may be expected for the year ending December 31, 2010. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2009 audited consolidated financial statements and notes thereto, which are included in the 2009 Form 10-K filed with the SEC on February 25, 2010.

The Company completed its acquisition of the Ballylumford Power Station in the third quarter of 2010 and in accordance with the accounting guidance for business combinations, has recorded the preliminary amounts for the purchase price allocation. The final purchase price allocation is preliminary and adjustments will continue to be made during the measurement period. Subsequent adjustments, if any, will be retrospectively adjusted in future filings with the SEC.

Significant New Accounting Policies

Accounting Standards Update (“ASU”) No. 2009-16, Accounting for Transfers of Financial Assets (former Financial Accounting Standard (“FAS”) No. 166, Accounting for Transfers of Financial Assets, an Amendment of FASB Statement No. 140)

Effective January 1, 2010, the Company prospectively adopted the new accounting guidance on transfers of financial assets, which among other things: removes the concept of a qualifying special purpose entity; introduces the concept of participating interests and specifies that in order to qualify for sale accounting a partial transfer of a financial asset or a group of financial assets should meet the definition of a participating interest;

clarifies that an entity should consider all arrangements made contemporaneously with or in contemplation of a transfer and requires enhanced disclosures to provide financial statement users with greater transparency about transfers of financial assets and a transferor’s continuing involvement with transfers of financial assets accounted for as sales. Upon adoption on January 1, 2010, the Company recognized $40 million as accounts receivable and an associated secured borrowing on its condensed consolidated balance sheet; both of which have since grown to $50 million as of September 30, 2010, as additional interests in receivables have been sold. IPL, the Company’s integrated utility in Indianapolis, had securitized these accounts receivable through IPL Funding, a special purpose entity, and previously recognized the transaction as a sale and had not recognized the accounts receivable and secured borrowing on its balance sheet. Under the facility, interests in these accounts receivable are sold, on a revolving basis, to unrelated parties (the Purchasers) up to the lesser of $50 million or an amount determinable under the facility agreement. The Purchasers assume the risk of collection on the interest sold without recourse to IPL, which retains the servicing responsibilities for the interest sold. While no direct recourse to IPL exists, IPL risks loss in the event collections are not sufficient to allow for full recovery of the retained interests. No servicing asset or liability is recorded since the servicing fee paid to IPL approximates a market rate. Under the new accounting guidance, the retained interest in these securitized accounts receivable does not meet the definition of a participating interest, thereby requiring the Company to recognize on its condensed consolidated balance sheet the portion transferred and the proceeds received as accounts receivable and a secured borrowing, respectively.

ASU No. 2009-17, Consolidations, Improvements to Financial Reporting by Enterprises involved with Variable Interest Entities (former FAS No. 167, Amendments to FASB Interpretation No. 46(R))

Effective January 1, 2010, the Company prospectively adopted the new accounting guidance on the consolidation of VIEs. The new guidance requires an entity to qualitatively, rather than quantitatively, assess the determination of the primary beneficiary of a VIE. This determination is based on whether the entity has the power to direct the activities that most significantly impact the economic performance of the VIE and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Other key changes include: a requirement for the ongoing reconsideration of the primary beneficiary, the criteria for determining whether service provider or decision maker contracts are variable interests, the consideration of kick-out and removal rights in determining whether an entity is a VIE, the types of events that trigger the reassessment of whether an entity is a VIE and the expansion of the disclosures previously required.

The determination of the entity that has the power to direct the activities that most significantly impact the economic performance of the VIE required significant judgment and assumptions for certain of the Company’s businesses. That determination considered the purpose and design of the businesses, the risks that the businesses were designed to create and pass along to other entities, the activities of the businesses that could be directed and which entity could direct them, and the expected relative impact of those activities on the economic performance of the businesses through their life. The businesses for which significant judgment and assumptions were required were primarily certain generation businesses who have power purchase agreements (“PPAs”) to sell energy exclusively or primarily to a single counterparty for the term of those agreements. For these generation businesses, the counterparty has the power to dispatch energy and, in some instances, to make decisions regarding the sale of excess energy. As such, the counterparty has power to direct certain activities that significantly impact the economic performance of the business primarily through the cash flows and gross margin, if any, earned by the business from the sale of energy to the counterparty and sometimes through the absorption of fuel price risk by the counterparty. However, the counterparty usually does not have the power to direct any of the other activities that could significantly impact the economic performance. These other activities include: daily operation and management, maintenance and repairs and capital expenditures, plant expansion, decisions regarding overall financing of ongoing operations and budgets and, in some instances, decisions regarding sale of excess energy. As such, the AES generation business has power to direct some activities of the business that significantly impact its economic performance, primarily through the cash flows and gross margin earned from capacity payments received from being available to produce energy and from any sale of energy to other entities (particularly during any period beyond the end of the power purchase agreement). For these VIEs,

the determination as to which set of activities most significantly impact the economic performance of the business required significant judgment and assumptions and resulted in the conclusion that the activities directed by the counterparty were less significant than those directed by the AES business.

The adoption of the new guidance resulted in the deconsolidation of certain immaterial VIEs previously consolidated. Additionally, assets, liabilities and operating results of two of our VIEs, previously accounted for under the equity method of accounting, were required to be consolidated. Cartagena, a 71% owned generation business in Spain, and Cili, a 51% owned generation business in China, were consolidated under the new guidance resulting in a cumulative effect adjustment of $47 million to retained earnings as of January 1, 2010. The cumulative effect adjustment is primarily comprised of losses that were not recognized while the equity method of accounting was suspended for Cartagena. As of September 30, 2010, total assets and total liabilities related to these VIEs were $860 million and $960 million, respectively. In addition, revenue for the three and nine months ended September 30, 2010 included $86 million and $273 million, respectively, of revenue from these VIEs. Prior period operating results of these VIEs are reflected in “Net equity in earnings of affiliates” except for those prior periods during which the equity method of accounting was suspended.

2. INVENTORY

The following table summarizes the Company’s inventory balances as of September 30, 2010 and December 31, 2009:


	September 30, 2010		December 31, 2009
	(in millions)
Coal, fuel oil and other raw materials	$	308	$	293
Spare parts and supplies		303		267

Total	$	611	$	560

3. FAIR VALUE DISCLOSURES

The following table summarizes the carrying and fair value of certain of the Company’s financial assets and liabilities as of September 30, 2010 and December 31, 2009:


	September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Assets
Marketable securities	$	1,688	$	1,688	$	1,691	$	1,691
Derivatives		100		100		141		141

Total assets	$	1,788	$	1,788	$	1,832	$	1,832

Liabilities
Debt	$	19,975	$	20,724	$	19,537	$	20,008
Derivatives		571		571		310		310

Total liabilities	$	20,546	$	21,295	$	19,847	$	20,318

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 the value indicated by current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company does not currently determine the fair value of any of our financial assets and liabilities using the cost approach. Financial assets and liabilities that are measured at fair value on a recurring basis at AES fall into two broad categories: investments and derivatives.

Our investments are generally measured at fair value using the market approach and our derivatives are valued using the income approach.

Investments

The Company’s investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are adjusted to fair value using quoted market prices. Debt securities primarily consist of unsecured debentures, certificates of deposit and government debt securities held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the CDI (Brazilian equivalent to LIBOR) or Selic (overnight borrowing rate) rates in Brazil and are adjusted based on the banks’ assessment of the specific businesses. Fair value is determined based on comparisons to market data obtained for similar assets and are considered Level 2 inputs. 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 financial and physical derivative instruments. The Company’s 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 fluctuations in commodity prices, 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 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 the 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 where 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 used in the income approach: volatilities, spot and forward benchmark interest rates (such as LIBOR and EURIBOR), foreign exchange rates and commodity prices. Forward rates and prices generally come 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 input, such as regression analysis, Monte Carlo simulation or similarly traded instrument available in the market.

For each derivative, the income approach is used to estimate the stream of 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 and 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 estimates of the borrowing costs based on quotes from banks, 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 result in the use of unobservable inputs. In addition, in certain instances, the financial or physical instrument is traded in an inactive market requiring the use of unobservable inputs. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable. Where the use of unobservable inputs is significant, these derivatives are classified as Level 3.

Recurring Measurements:

The following table sets forth by level within the fair value hierarchy certain of the Company’s financial assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2010 and December 31, 2009. Financial assets and liabilities have been classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the determination of the fair value of the assets and liabilities and their placement within the fair value hierarchy levels.


	Total September 30, 2010		Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in millions)
Assets
Available-for-sale securities	$	1,677	$	8	$	1,627	$	42
Trading securities		10		10		-		-
Derivatives		100		-		56		44

Total assets	$	1,787	$	18	$	1,683	$	86

Liabilities
Derivatives	$	571	$	-	$	290	$	281

Total liabilities	$	571	$	-	$	290	$	281


	Total December 31, 2009		Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in millions)
Assets
Available-for-sale securities	$	1,676	$	133	$	1,501	$	42
Trading securities		7		7		-		-
Derivatives		141		-		111		30

Total assets	$	1,824	$	140	$	1,612	$	72

Liabilities
Derivatives	$	310	$	-	$	280	$	30

Total liabilities	$	310	$	-	$	280	$	30

The following tables present a reconciliation of 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, 2010 and 2009:


	Three Months Ended September 30,
	2010															2009
	Interest Rate			Cross Currency			Foreign Exchange			Commodity			Total			Total
	(in millions)
Balance at beginning of period⁽¹⁾	$	(226	)	$	(34	)	$	18		$	19		$	(223	)	$	(9	)
Total gains (losses) (realized and unrealized):⁽¹⁾
Included in earnings⁽²⁾		(2	)		-			-			(3	)		(5	)		(3	)
Included in other comprehensive income		(63	)		25			(1	)		-			(39	)		(52	)
Included in regulatory assets		(2	)		-			-			(2	)		(4	)		-
Purchases, issuances and settlements⁽¹⁾		14			-			-			(3	)		11			-
Transfers of assets (liabilities) into Level 3⁽³⁾		(3	)		-			-			-			(3	)		(23	)
Transfers of (assets) liabilities out of Level 3⁽³⁾		26			-			-			-			26			3

Balance at September 30⁽¹⁾	$	(256	)	$	(9	)	$	17		$	11		$	(237	)	$	(84	)

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	)	$	-		$	-		$	-		$	(1	)	$	(7	)


	Nine Months Ended September 30,
	2010															2009
	Interest Rate			Cross Currency			Foreign Exchange			Commodity			Total			Total
	(in millions)
Balance at beginning of period⁽¹⁾	$	(12	)	$	(12	)	$	-		$	24		$	-		$	(69	)
Total gains (losses) (realized and unrealized):⁽¹⁾
Included in earnings⁽²⁾		(1	)		5			22			(1	)		25			(26	)
Included in other comprehensive income		(78	)		(5	)		(1	)		-			(84	)		84
Included in regulatory assets		(5	)		-			-			3			(2	)		2
Purchases, issuances and settlements⁽¹⁾		16			3			-			(15	)		4			2
Transfers of assets (liabilities) into Level 3⁽³⁾		(211	)		-			(4	)		-			(215	)		(23	)
Transfers of (assets) liabilities out of Level 3⁽³⁾		35			-			-			-			35			(54	)

Balance at September 30⁽¹⁾	$	(256	)	$	(9	)	$	17		$	11		$	(237	)	$	(84	)

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⁾	$	(2	)	$	5		$	20		$	(10	)	$	13		$	(30	)

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

⁽²⁾

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 exchange derivatives as foreign currency transaction gains (losses); and commodity derivatives as non-regulated cost of sales. See Note 5 — Derivative Instruments and Hedging Activities for further information regarding the classification of gains and losses included in earnings in the condensed consolidated statements of operations.

⁽³⁾

Transfers in and out of Level 3 are determined as of the end of the reporting period and are from and to Level 2, except as noted below. The (assets) liabilities transferred out of Level 3 during the nine months ended September 30, 2009 include a PPA that was dedesignated as a cash flow hedge because the normal purchase normal sale scope exception from derivative accounting was elected as of December 31, 2008. As

such, the agreement was measured at fair value using significant unobservable inputs at December 31, 2008, but is subsequently being amortized and is no longer adjusted for subsequent changes in fair value. Otherwise, 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, 2010 and 2009:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(in millions)
Balance at beginning of period⁽¹⁾	$	42	$	2	$	42	$	42
Purchases, issuances and settlements		-		40		-		-

Balance at September 30	$	42	$	42	$	42	$	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 auction rate securities and variable rate demand notes which have failed remarketing or are not actively trading and for which there are no longer adequate observable inputs available to measure the fair value.

Nonrecurring Measurements:

The Company’s nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis include: goodwill; intangible assets, such as sales concessions, land rights and emissions allowances; and long-lived tangible assets including property, plant and equipment.

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. As noted in Note 14 — Discontinued Operations and Held for Sale Businesses, the Company recognized a loss on disposal and impairment losses in Pakistan totaling $22 million ($14 million, net of tax and noncontrolling interests) during the nine months ended September 30, 2010.

Held and Used Assets

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.

Additionally, 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 $0 million, resulting in the recognition of goodwill impairment of $18 million for the nine months ended September 30, 2010.

Since the majority of significant assumptions used in the valuations of the assets held and used were not observable, management believes that the valuations are considered Level 3 measurements in the fair value hierarchy. For further discussion of these impairments, see Note 13 — Impairments.

4. INVESTMENTS IN MARKETABLE SECURITIES

The following table sets forth the Company’s investments in marketable debt and equity securities as of September 30, 2010 and December 31, 2009 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, 2010								December 31, 2009
	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⁾	$	-	$	646	$	-	$	646	$	-	$	667	$	-	$	667
Certificates of deposit⁽²⁾		-		859		-		859		-		652		-		652
Government debt securities		-		48		-		48		-		152		-		152
Other debt securities		-		-		42		42		-		-		42		42

Subtotal		-		1,553		42		1,595		-		1,471		42		1,513
Equity securities:
Mutual funds		1		55		-		56		117		-		-		117
Common stock		7		-		-		7		16		-		-		16
Money market funds		-		19		-		19		-		30		-		30

Subtotal		8		74		-		82		133		30		-		163

Total available-for-sale		8		1,627		42		1,677		133		1,501		42	$	1,676

TRADING:
Equity securities:
Mutual funds		10		-		-		10		7		-		-		7

Total trading		10		-		-		10		7		-		-		7

TOTAL	$	18	$	1,627	$	42	$	1,687	$	140	$	1,501	$	42	$	1,683

Held-to-maturity securities⁽³⁾								1								8

Total marketable securities							$	1,688							$	1,691

⁽¹⁾	Amortized cost approximated fair value at September 30, 2010 and December 31, 2009, with the exception of certain common stock investments with a cost basis of $6 million carried at its fair value of $7 million and $16 million as of September 30, 2010 and December 31, 2009, respectively.

⁽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.

⁽³⁾

Held-to-maturity securities are carried at amortized cost and not measured at fair value on a recurring basis. These investments represent government debt securities. The amortized cost approximated fair value of the held-to-maturity securities at September 30, 2010 and December 31, 2009. As of September 30, 2010, all held-to-maturity debt securities had stated maturities within one year.

As of September 30, 2010, all available-for-sale debt securities had stated maturities within one year, with the exception of $42 million of auction rate securities and 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 as of September 30, 2010.

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, 2010 and 2009. There were no realized losses on the sale of available-for-sale securities. Gains and losses on the sale of investments are determined using the specific identification method. There was no other-than-temporary impairment recognized in earnings or other comprehensive income for the three and nine months ended September 30, 2010 and 2009.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
	(in millions)					(in millions)
Gains (losses) included in earnings that relate to trading securities held at the reporting date	$	(1	)	$	-	$	-		$	1
Gains (losses) included in other comprehensive income	$	-		$	10	$	(10	)	$	10
Gains reclassified out of other comprehensive income into earnings	$	-		$	2	$	-		$	2
Proceeds from sales	$	1,442		$	888	$	4,652		$	3,031
Gross realized gains on sales	$	-		$	2	$	2		$	3

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 applies hedge accounting for all 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 2027, and are typically designated as cash flow hedges. The following table sets forth, by type of interest rate derivative, 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, 2010 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:


	September 30, 2010
	Current				Maximum⁽¹⁾				Weighted Average Remaining Term⁽¹⁾		% of Debt Currently Hedged by Index⁽²⁾
Interest Rate Derivatives	Derivative Notional		Derivative Notional Translated to USD		Derivative Notional		Derivative Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾		% of Debt Currently Hedged by Index⁽²⁾
	(in millions)								(in years)
Libor (USD)		2,560	$	2,560		2,721	$	2,721		10		69	%
Euribor (Euro)		1,209		1,648		1,241		1,692		14		73	%
Libor (British Pound Sterling)		47		74		47		74		10		68	%
Securities Industry and Financial Markets Association Municipal Swap Index (USD)		40		40		40		40		12		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, 2010 and the maturity of the derivative instrument, which includes forward starting derivative instruments that generally start around when a construction project had been expected to be completed and commence operations. The weighted average remaining term represents the remaining tenor of our interest rate derivatives weighted by the corresponding maximum notional in USD.

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

⁽³⁾	The debt that was being hedged is no longer exposed to variable interest payments.

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 notionals of its cross currency derivative instruments as of September 30, 2010 which are all in qualifying cash flow hedge relationships. These swaps are amortizing and therefore the notional amount represents the maximum outstanding notional as of September 30, 2010:


	September 30, 2010
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	$	247		15		82	%

⁽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 environments and such operations in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. Foreign currency options and forwards are utilized, where possible, to manage the risk related to fluctuations in certain foreign currencies. These foreign currency contracts range in maturity through 2011. The following tables set forth, by type of foreign currency denomination, the Company’s outstanding notionals over the remaining terms of its foreign currency derivative instruments as of September 30, 2010 regardless of whether the derivative instruments are in qualifying hedging relationships:


	September 30, 2010
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)		232	$	132	$	40		<1
Euro (EUR)		18		24		8		<1
Philippine Peso (PHP)		376		8		2		1
British Pound (GBP)		5		7		5		<1

⁽¹⁾

Represents contractual notionals at inception of the derivative instrument.

⁽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 in USD.


	September 30, 2010
Foreign Currency Forwards	Notional		Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾
	(in millions)				(in years)
Chilean Peso (CLP)		125,761	$	250		<1
Colombian Peso (COP)		240,074		131		<1
Brazilian Real (BRL)		90		51		<1
Argentine Peso (ARS)		57		13		1

⁽¹⁾

Represents the remaining tenor of our foreign currency forwards weighted by the corresponding notional in USD.

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 their own functional currency 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 notionals over the remaining terms of its foreign currency embedded derivative instruments as of September 30, 2010:


	September 30, 2010
Embedded Foreign Currency Derivatives	Notional		Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾
	(in millions)				(in years)
Philippine Peso (PHP)		14,291	$	326		3
Kazakhstani Tenge (KZT)		43,274		293		10
Argentine Peso (ARS)		335		85		9
Euro (EUR)		31		43		4
Cameroon Franc (XAF)		1,755		4		2
Brazilian Real (BRL)		6		4		2
Hungarian Forint (HUF)		335		2		<1

⁽¹⁾

Represents the remaining tenor of our foreign currency embedded derivatives weighted by the corresponding notional in USD.

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 commodity forward contracts, futures, swaps and options. Some of our businesses hedge certain aspects of their commodity risks using financial hedging instruments.

We also enter into short-term contracts for electricity and fuel in other competitive markets in which we operate. When hedging the output of our generation assets, we have power purchase agreements or other hedging instruments that lock in the spread in dollars per MWh between the cost of fuel to generate a unit of electricity and the price at which the electricity can be sold (“Dark Spread” where the fuel is coal). The portion of our sales and fuel purchases that are not subject to such agreements will be exposed to commodity price risk. Eastern Energy, a North America generation business, sells electricity into the power pools managed by the New York Independent System Operator (“NYISO”). In addition, Eastern Energy has hedged a portion of its power

exposure for 2010 by entering into hedges of natural gas prices, as movements in natural gas prices affect power prices. While there is a strong relationship between natural gas and power prices, the natural gas hedges do not currently qualify for hedge accounting treatment and are included in the below table entitled “Commodity Derivatives”. The following table sets forth the Company’s current notionals under its commodity derivative instruments at Eastern Energy and the percentage of forecasted electricity sales hedged as of September 30, 2010 for 2010 and 2011:


	2010					2011
Commodity Hedges	Notional		% of Forecasted Sales Hedged⁽²⁾			Notional			% of Forecasted Sales Hedged⁽²⁾
	(in millions)					(in millions)
Natural gas swaps (MMBTU)		4		23	%		-			-	%
NYISO electricity swaps (MWh)		1		25	%		-	⁽¹⁾		1	%

⁽¹⁾

De minimis amount.

⁽²⁾

This amount is based on wholesale energy forecasts above committed regulated energy sales.

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 require 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 then meet the definition of a derivative.

Nonetheless, certain of the PPAs and fuel supply agreements entered into by the Company are derivatives or contain embedded derivatives requiring separate valuation and accounting. These agreements 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 (excluding the commodity hedges at Eastern Energy which are presented in the above table) and embedded derivative instruments as of September 30, 2010:


	September 30, 2010
Commodity Derivatives	Notional			Weighted Average Remaining Term⁽¹⁾
	(in millions)			(in years)
Natural gas (MMBTU)		88			8
Petcoke (Metric tons)		14			14
Coal (Metric tons)		-	⁽²⁾		<1
Log wood (Tons)		-	⁽²⁾		3
Financial transmission rights (MW)		-	⁽²⁾		1

⁽¹⁾

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

⁽²⁾

De minimis amount.

Accounting and Reporting

The following table sets forth the Company’s derivative instruments as of September 30, 2010 and December 31, 2009 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 consolidated balance sheets: current derivative assets in other current assets, noncurrent derivative assets in other noncurrent assets, current derivative liabilities in accounts payable and accrued liabilities, and noncurrent derivative liabilities in other long-term liabilities.


	September 30, 2010											December 31, 2009
	Level 1		Level 2			Level 3			Total			Level 1		Level 2		Level 3		Total
	(in millions)											(in millions)
Assets
Current assets:
Foreign exchange derivatives	$	-	$	5	⁽¹⁾	$	3		$	8		$	-	$	6	$	-	$	6
Commodity derivatives
Electricity		-		9			-			9			-		22		-		22
Natural gas		-		18			9			27			-		-		11		11
Other		-		2			4			6			-		-		17		17

Total current assets		-		34			16			50			-		28		28		56

Noncurrent assets:
Interest rate derivatives		-		12			-			12			-		83		2		85
Foreign exchange derivatives		-		6	⁽¹⁾		26			32			-		-		-		-
Cross currency derivatives		-		-			2			2			-		-		-		-
Other		-		4			-			4			-		-		-		-

Total noncurrent assets		-		22			28			50			-		83		2		85

Total assets	$	-	$	56		$	44		$	100		$	-	$	111	$	30	$	141

Liabilities
Current liabilities:
Interest rate derivatives	$	-	$	82		$	46		$	128	⁽¹⁾	$	-	$	118	$	7	$	125
Cross currency derivatives		-		-			3			3			-		-		-		-
Foreign exchange derivatives		-		15			-			15			-		3		-		3
Commodity derivatives
Electricity		-		-			-			-			-		2		-		2
Natural gas		-		-			-			-			-		5		-		5
Other		-		-			-			-			-		-		2		2

Total current liabilities		-		97			49			146			-		128		9		137

Noncurrent liabilities:
Interest rate derivatives		-		186			210			396	⁽¹⁾		-		150		7		157
Cross currency derivatives		-		-			8			8			-		-		12		12
Foreign exchange derivatives		-		7			12	⁽¹⁾		19			-		2		-		2
Commodity derivatives
Natural gas		-		-			-			-			-		-		2		2
Other fuel		-		-			2			2			-		-		-		-

Total noncurrent liabilities		-		193			232			425			-		152		21		173

Total liabilities	$	-	$	290		$	281		$	571		$	-	$	280	$	30	$	310

⁽¹⁾

Includes the impact of consolidating Cartagena beginning January 1, 2010 under VIE accounting guidance as follows: $2 million of current assets, $6 million of noncurrent assets and $5 million of noncurrent liabilities for foreign exchange derivatives and $19 million of current liabilities and $75 million of noncurrent liabilities for interest rate derivatives as of September 30, 2010.

The following table sets forth the fair value and balance sheet classification of derivative instruments as of September 30, 2010 and December 31, 2009:


	September 30, 2010								December 31, 2009
	Designated as Hedging Instruments			Not Designated as Hedging Instruments			Total		Designated as Hedging Instruments		Not Designated as Hedging Instruments		Total
	(in millions)
Assets
Other current assets:
Foreign exchange derivatives	$	-		$	8	⁽¹⁾	$	8	$	-	$	6	$	6
Commodity derivatives:
Electricity		9			-			9		22		-		22
Natural gas		-			27			27		-		11		11
Other		-			6			6		-		17		17

Total other current assets		9			41			50		22		34		56

Other assets:
Interest rate derivatives		12			-			12		85		-		85
Cross currency derivatives		2			-			2		-		-		-
Foreign exchange derivatives		-			32	⁽¹⁾		32		-		-		-
Other		-			4			4		-		-		-

Total other assets — noncurrent		14			36			50		85		-		85

Total assets	$	23		$	77		$	100	$	107	$	34	$	141

Liabilities
Accounts payable and other accrued liabilities:
Interest rate derivatives	$	115	⁽¹⁾	$	13		$	128	$	115	$	10	$	125
Cross currency derivatives		3			-			3		-		-		-
Foreign exchange derivatives		8			7			15		2		1		3
Commodity derivatives:
Electricity		-			-			-		2		-		2
Natural gas		-			-			-		-		5		5
Other		-			-			-		-		2		2

Total accounts payable and other accrued liabilities — current		126			20			146		119		18		137

Other long-term liabilities:
Interest rate derivatives		375	⁽¹⁾		21			396		141		16		157
Cross currency derivatives		8			-			8		12		-		12
Foreign exchange derivatives		-			19	⁽¹⁾		19		-		2		2
Commodity derivatives:
Natural gas		-			-			-		-		2		2
Other fuel		-			2			2		-		-		-

Total other long-term liabilities		383			42			425		153		20		173

Total liabilities	$	509		$	62		$	571	$	272	$	38	$	310

⁽¹⁾

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, 2010 and December 31, 2009, we held $20 million and $8 million, respectively, of cash collateral that we received from counterparties to our derivative positions, which is classified as restricted cash and accounts payable and accrued liabilities in the condensed consolidated balance sheets. Also, at September 30, 2010 and December 31, 2009, 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 and equity in earnings of affiliates over the next twelve months as of September 30, 2010 for the following types of derivative instruments:


	Accumulated Other Comprehensive Income (Loss)
	(in millions)
Interest rate derivatives	$	(83	)
Cross currency derivatives	$	(1	)
Foreign currency derivatives	$	(9	)
Commodity derivatives	$	8

The balance in accumulated other comprehensive loss related to derivative transactions that will be reclassified into earnings as follows: as interest expense is recognized for interest rate hedges and cross currency swaps, as depreciation is recognized for interest rate hedges during construction, as foreign currency gains and losses are recognized for hedges of foreign currency exposure, and as electricity sales and fuel purchases are recognized for hedges of forecasted electricity and fuel transactions. These balances are included in the condensed consolidated statements of cash flows as operating and/or investing activities based on the nature of the underlying transaction. Additionally, $1 million of pre-tax accumulated other comprehensive income is expected to be recognized as an increase to income from continuing operations before income taxes over the next twelve months. This amount relates to a PPA that was dedesignated as a cash flow hedge because the normal purchase normal sale scope exception from derivative accounting was elected as of December 31, 2008.

For the three and nine months ended September 30, 2010, pre-tax gains (losses) of $(1) million net of noncontrolling interests were reclassified into earnings as a result of the discontinuance of a cash flow hedge because it was probable that the forecasted transaction would not occur by the end of the originally specified time period (as documented at the inception of the hedging relationship) or within an additional two-month time period thereafter.

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, 2010 and 2009:


	Gains (Losses) Recognized in AOCL							Gains (Losses) Reclassified from AOCL into Earnings
	Three Months Ended September 30,						Classification in Condensed Consolidated Statements of Operations	Three Months Ended September 30,
	2010			2009				2010			2009
	(in millions)							(in millions)
Interest rate derivatives	$	(154	)⁽³⁾	$	(86	)	Interest expense	$	(26	)⁽¹⁾	$	(26	)⁽¹⁾
							Non-regulated cost of sales		(3	)		-
							Net equity in earnings of affiliates		-	⁽²⁾		-	⁽²⁾
Cross currency derivatives		25			3		Interest expense		-			(1	)
							Foreign currency transaction gains (losses)		-			(9	)
Foreign currency derivatives		(11	)		(1	)	Foreign currency transaction gains (losses)		1			-	⁽²⁾
Commodity derivatives — electricity		(4	)		11		Non-regulated revenue		(6	)		63

Total	$	(144	)	$	(73	)		$	(34	)	$	27


	Gains (Losses) Recognized in AOCL							Gains (Losses) Reclassified from AOCL into Earnings
	Nine Months Ended September 30,						Classification in Condensed Consolidated Statements of Operations	Nine Months Ended September 30,
	2010			2009				2010			2009
	(in millions)							(in millions)
Interest rate derivatives	$	(386	)⁽³⁾	$	7		Interest expense	$	(93	)⁽¹⁾	$	(64	)⁽¹⁾
							Non-regulated cost of sales		(3	)		-
							Net equity in earnings of affiliates		-	⁽²⁾		-	⁽²⁾
Cross currency derivatives		(5	)		37		Interest expense		(1	)		(1	)
							Foreign currency transaction gains (losses)		-			23
Foreign currency derivatives		(4	)		(1	)	Foreign currency transaction gains (losses)		1			-	⁽²⁾
Commodity derivatives — electricity		(4	)		120		Non-regulated revenue		4			150

Total	$	(399	)	$	163			$	(92	)	$	108

⁽¹⁾

Includes amounts that were reclassified from AOCL related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting. Excludes amounts related to discontinued operations as follows: $(15) million and $(9) million for the three months ended September 30, 2010 and 2009, respectively, and $(35) million and $(25) million for the nine months ended September 30, 2010 and 2009, respectively.

⁽²⁾	De minimis amount.

⁽³⁾	Includes $(19) million and $(51) million related to Cartagena for the three and nine months ended September 30, 2010, respectively, which was consolidated prospectively beginning January 1, 2010 under VIE accounting guidance.

The following tables set forth the 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, 2010 and 2009:


	Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Recognized in Earnings
		Three Months Ended September 30,
		2010			2009
		(in millions)
Interest rate derivatives	Interest expense	$	-	⁽¹⁾	$	1
	Net equity in earnings of affiliates		1			-	⁽¹⁾
Cross currency derivatives	Interest expense		-	⁽¹⁾		-	⁽¹⁾
Foreign currency derivatives	Foreign currency transaction gains (losses)		-	⁽¹⁾		-
Commodity derivatives — electricity	Non-regulated revenue		-			-	⁽¹⁾

Total		$	1		$	1


	Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Recognized in Earnings
		Nine Months Ended September 30,
		2010			2009
		(in millions)
Interest rate derivatives	Interest expense	$	2		$	8
	Net equity in earnings of affiliates		1			-	⁽¹⁾
Cross currency derivatives	Interest expense		5			2
Foreign currency derivatives	Foreign currency transaction gains (losses)		-	⁽¹⁾		-
Commodity derivatives — electricity	Non-regulated revenue		-			(2	)

Total		$	8		$	8

⁽¹⁾	De minimis amount.

The following tables set 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, 2010 and 2009, respectively:


	Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Recognized in Earnings
		Three Months Ended September 30,
		2010			2009
		(in millions)
Interest rate derivatives	Interest expense	$	(3	)	$	(23	)
Foreign exchange derivatives	Non-regulated cost of sales		-			(1	)
	Foreign currency transaction gains (losses)		(7	)⁽¹⁾		(8	)
	Net equity in earnings of affiliates		(2	)		-	⁽²⁾
Commodity derivatives — natural gas	Non-regulated revenue		9			(17	)
	Non-regulated cost of sales		1			2
Commodity derivatives — other	Non-regulated revenue		1			-
	Non-regulated cost of sales		(4	)		(3	)

Total		$	(5	)	$	(50	)

	Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Recognized in Earnings
		Nine Months Ended September 30,
		2010			2009
		(in millions)
Interest rate derivatives	Interest expense	$	(8	)	$	(42	)
Foreign exchange derivatives	Non-regulated cost of sales		2	⁽¹⁾		(12	)
	Foreign currency transaction gains (losses)		(36	)		(30	)
	Net equity in earnings of affiliates		(2	)		-	⁽²⁾
Commodity derivatives — natural gas	Non-regulated revenue		45			(17	)
	Non-regulated cost of sales		9			3
Commodity derivatives — other	Non-regulated revenue		5			(5	)
	Non-regulated cost of sales		(6	)		(4	)

Total		$	9		$	(107	)

⁽¹⁾

Includes $3 million and $(2) million for the three and nine months ended September 30, 2010, respectively, related to Cartagena, which was consolidated as of January 1, 2010 under variable interest entity accounting guidance.

⁽²⁾

De minimis amount.

In addition, IPL has two derivative instruments for which the gains and losses are accounted for as regulatory assets or liabilities in accordance with accounting standards for regulated operations. Gains and losses on these derivatives due to changes in their fair value 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 increase (decrease) 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, 2010 and 2009:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010		2009
	(in millions)
Increase (decrease) in regulatory assets	$	3		$	2		$	6	$	1
Increase (decrease) in regulatory liabilities	$	(2	)	$	(2	)	$	2	$	(4	)

Credit Risk-Related Contingent Features

The following businesses have derivative agreements that contain credit contingent provisions which would permit the counterparties with which we are in a net liability position to require collateral credit support when the fair value of the derivatives exceeds the unsecured thresholds established in the agreements. These thresholds vary based on our subsidiaries’ credit ratings and as their credit ratings are lowered, the thresholds decrease, requiring more collateral support.

Eastern Energy, our generation business in New York, enters into commodity derivative transactions with several counterparties who have market exposure limits defined in their transaction agreements. Pursuant to the aforementioned credit contingent provisions, if Eastern Energy’s credit rating were to fall below the minimum thresholds established in each of the respective transaction agreements, the counterparties could demand immediate collateralization of the entire mark-to-market value of the derivatives (excluding credit valuation adjustments) if the derivatives were in a net liability position. As of September 30, 2010, Eastern Energy had no net liability positions and so it had posted no collateral. As of December 31, 2009, Eastern Energy had net liability positions of $2 million and had posted a nominal amount of collateral to support these positions based on its current credit rating and the related thresholds in the agreements.

In December 2007, Gener entered into cross currency swap agreements with a counterparty to swap Chilean inflation indexed bonds issued in December 2007 into U.S. Dollars. Pursuant to the aforementioned credit contingent provisions, if Gener’s credit rating were to fall below the minimum threshold established in the swap agreements, the counterparty 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 $9 million and $12 million, respectively at September 30, 2010 and December 31, 2009. As of September 30, 2010 and December 31, 2009, Gener had posted zero and $25 million, respectively, in the form of a letter of credit to support these swaps.

6. INVESTMENTS IN AND ADVANCES TO AFFILIATES

During the second quarter of 2010, the Company, through Southern Electric Brasil Participações Ltda. (“SEB”) (an equity method investment of Cayman Energy Traders (“CET”), an equity method investment of the Company) transferred its shares of Companhia Energética de Minas Gerais (“CEMIG”), representing a 14.8% voting interest, to Andrade Gutierrez Concessões S.A. and its affiliate (jointly referred to as “AG”). AG also assumed SEB’s debt with Banco Nacional de Desenvolvimento Econômico e Social (“BNDES”) in the amount of approximately $1.4 billion (the “BNDES Loan”) including all unpaid interest and penalties. In

exchange, SEB received $25 million and obtained a full release from any claims of BNDES and originating from the BNDES Loan. See Note 8 — Contingencies and Commitments of this Form 10-Q for additional information regarding these claims and proceedings.

The Company had previously recognized its equity method investment in SEB as a $484 million net long-term liability on the consolidated balance sheet. See further discussion of the background in the Company’s 2009 Form 10-K — Item 8. — Financial Statements and Supplementary Data — Note 7 — Investments In and Advances to Affiliates. The consummation of the share purchase and sale agreement along with AG’s assumption of the BNDES Loan in June 2010 resulted in the reversal of the Company’s net long-term liability along with the associated cumulative translation adjustment, resulting in the recognition of a $115 million pre-tax gain reflected in “Net equity in earnings of affiliates” on the condensed consolidated statement of operations for the nine months ended September 30, 2010. Additionally, $70 million of net tax expense resulting from the CEMIG sale transaction was recorded as “income tax expense”, rather than equity earnings, since the expense is attributable to a consolidated corporate level partner in the CEMIG investment.

7. 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 fair value of the Company’s debt as of September 30, 2010 and December 31, 2009:


	September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Non-recourse debt	$	15,073	$	15,547	$	14,022	$	14,405
Recourse debt		4,902		5,177		5,515		5,603

Total debt	$	19,975	$	20,724	$	19,537	$	20,008

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 a discounted cash flow analysis or quoted market prices, if available. 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 subsidiaries or The AES Corporation. For subsidiaries located in countries with credit ratings lower than The AES Corporation, we used the appropriate country specific yield curve. For variable rate loans, carrying value approximates fair value. 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, 2010. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to September 30, 2010.

Non-Recourse Debt

Subsidiary non-recourse debt in default or accelerated, including any temporarily waived default for which a cure is not probable, is classified as current debt in the accompanying condensed consolidated balance sheets. The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of September 30, 2010:


Subsidiary	Primary Nature of Default		September 30, 2010
Subsidiary	Primary Nature of Default		Default Amount		Net Assets
			(in millions)
Sonel		Covenant	$	335	$	309
St. Nikola⁽¹⁾		Covenant		254		(28	)
Gener — Electrica Santiago		Covenant		49		5
Kelanitissa		Covenant		34		25
Aixi		Payment		2		13

Total			$	674

⁽¹⁾

St. Nikola, one of our subsidiaries in Bulgaria, has received a waiver of default which gives St. Nikola until February 2011 to cure the breached covenant; however, as this waiver does not extend beyond the Company’s current reporting cycle and the probability of curing the default cannot be determined, the debt was classified as current.

None of the subsidiaries currently in default qualifies as a material subsidiary under the Parent Company’s corporate debt agreements. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact the Company’s financial position and results of operations, it is possible that one or more of these subsidiaries could qualify as a material subsidiary, and thereby, upon an acceleration of its non-recourse debt, trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt agreements.

Recourse Debt

On May 17, 2010, the Company closed the redemption of $400 million aggregate principal of its 8.75% Second Priority Senior Secured Notes due 2013 (“the 2013 Notes”). The 2013 Notes were redeemed on a pro rata basis at a redemption price equal to 101.458% of the principal amount redeemed. The Company recognized a pre-tax loss on the redemption of the 2013 Notes of $9 million for the three months ended June 30, 2010, which is included in “Other expense” in the accompanying condensed consolidated statement of operations. The total outstanding principal amount of the 2013 Notes remaining at September 30, 2010 was $290 million.

On October 8, 2010, the Company completed the redemption of the remaining $290 million principal of the 2013 Notes at a price equal to 101.458% of the principal amount redeemed, plus accrued interest.

Amendment to Credit Agreement

On July 29, 2010, the Company entered into an Amendment No. 2 (the “Amendment No. 2”) to the Fourth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2008, among the Company, various subsidiary guarantors and various lending institutions (the “Existing Credit Agreement”) that amends and restates the Existing Credit Agreement (as so amended and restated by the Amendment No. 2, the “Fifth Amended and Restated Credit Agreement”). The Fifth Amended and Restated Credit Agreement adjusts the terms and conditions of the Existing Credit Agreement, including the following changes:

•

the aggregate commitment for the revolving credit loan facility was increased to $800 million;

•

the final maturity date of the revolving credit loan facility was extended to January 29, 2015;

•

there were changes to the facility fee applicable to the revolving credit loan facility;

•

the interest rate margin applicable to the revolving credit loan facility is now based on the credit rating assigned to the loans under the credit agreement, with pricing currently at LIBOR + 3.00%;

•

there is an undrawn fee of 0.625% per annum;

•

the Company may incur a combination of additional term loan and revolver commitments so long as total term loan and revolver commitments (including those currently outstanding) does not exceed $1.4 billion; and

•

a cap on first lien debt in the negative pledge of $3.0 billion.

8. CONTINGENCIES AND COMMITMENTS

Environmental

The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of September 30, 2010, the Company had recorded liabilities of $28 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, 2010.

The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts), and certain air emissions, such as SO₂, NO_x, particulate matter and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries, and our consolidated results of operations. For further information about these risks, see Item 1A. — Risk Factors, “Our businesses are subject to stringent environmental laws and regulations,” “Our businesses are subject to enforcement initiatives from environmental regulatory agencies,” and “Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows” set forth in the Company’s Form 10-K for the year ended December 31, 2009.

Legislation and Regulation of GHG Emissions

Regional Greenhouse Gas Initiative. As noted in the Company’s 2009 Form 10-K, to date, the primary regulation of GHG emissions affecting the Company’s U.S. plants has been through the Regional Greenhouse Gas Initiative (“RGGI”). Under RGGI, ten Northeastern States have coordinated to establish rules that require reductions in CO₂ emissions from power plant operations within those states through a cap-and-trade program. States in which our subsidiaries have generating facilities include Connecticut, Maryland, New York and New Jersey. Under RGGI, power plants must acquire one carbon allowance through auction or in the emission trading markets for each ton of CO₂ emitted. As noted in the Company’s 2009 Form 10-K, we have estimated the costs to the Company of compliance with RGGI could be approximately $17.5 million per year for 2010 and 2011.

Potential U.S. Federal GHG Legislation. As noted in the Company’s 2009 Form 10-K, federal legislation passed the U.S. House of Representatives in 2009 that, if adopted, would impose a nationwide cap-and-trade program to reduce GHG emissions. 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 such legislation will be voted on or passed by the Senate. If any such legislation is passed by the Senate, it is uncertain whether such legislation will be reconciled with the House of Representatives’ legislation and ultimately enacted into law. However, if any such legislation is enacted, the impact could be material to the Company.

EPA GHG Regulation. As noted in the Company’s 2009 Form 10-K, the U.S. Environmental Protection Agency (“EPA”) promulgated regulations governing GHG emissions from automobiles under the U.S. Clean Air Act (“CAA”). The effect of 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, after January 2, 2011, construction of new stationary sources, and modifications to existing stationary sources that result in increased GHG emissions, may require permitting under the prevention of significant deterioration (“PSD”) program of the CAA. The PSD program, if it were to become applicable to GHG emissions, would require sources that emit 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 applicable GHG emissions limitations.

The EPA promulgated a final rule on June 3, 2010, (the “Tailoring Rule”) that would set GHG emissions thresholds that would trigger PSD permitting requirements. Specifically, commencing in January of 2011, the Tailoring Rule provides that sources already subject to permitting requirements would need to install Best Available Control Technology (“BACT”) for greenhouse gases if a proposed modification would result in the increase of 75,000 tons per year of GHG emissions. Also, commencing in July of 2011, 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 the 75,000 tons per year “significance threshold,” would require PSD review and related permitting requirements. The EPA anticipates that it would adjust downward the permitting thresholds for new sources and modifications in future rulemaking actions. The Tailoring Rule, as currently proposed by the EPA, would substantially reduce 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 thresholds noted above. The higher “significance threshold” for increased GHG emissions from modifications to existing sources may enable some of our U.S. subsidiaries to avoid PSD requirements for many future modifications, although some projects that would expand capacity or electric output are likely to exceed the threshold.

International GHG Regulation. As noted in the Company’s 2009 Form 10-K, the primary international agreement concerning GHG emissions is the Kyoto Protocol which became effective on February 16, 2005 and requires the industrialized countries that have ratified it to significantly reduce their GHG emissions. The vast majority of the developing countries which have ratified the Kyoto Protocol have no GHG reduction requirements. Many of the countries in which the Company’s subsidiaries operate have no reduction obligations under the Kyoto Protocol. In addition, of the 30 countries in which the Company’s subsidiaries operate, all but one — the United States (including Puerto Rico) — have ratified the Kyoto Protocol. The Kyoto Protocol is currently expected to expire at the end of 2012, and countries have been unable to agree on a successor agreement. The next annual United Nations conference to develop a successor international agreement is scheduled for December 2010 in Cancun, Mexico. 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.

As disclosed in the Company’s Form 10-K for the year ended December 31, 2009, the number of GHG emissions allowances that AES Cartagena must surrender under the European Union ETS is greater than the number of free allowances allocated to it. AES Cartagena is currently in a contractual dispute with its fuel supply and electricity toller, GDF-Suez, regarding who has responsibility to surrender the emissions allowances necessary to meet the shortfall. AES Cartagena believes it has meritorious claims, but if AES Cartagena fails to prevail in the dispute, the resulting increase in costs could affect its ability to continue operations and/or result in a write down in the value of its assets, any of which could have a material adverse impact on the Company or its results of operations.

Other U.S. Air Emissions Regulations and Legislation

As noted in the Company’s 2009 Form 10-K, the Company’s U.S. operations are subject to regulation of air emissions such as SO₂ and NO_xunder the “Clean Air Interstate Rule” (“CAIR”). On July 6, 2010, the EPA issued a new proposed rule (the “Transport Rule”) to replace CAIR and remedy the flaws with CAIR identified in a ruling by the U.S. Court of Appeals for the D.C. Circuit. The Transport Rule would require significant reductions in SO₂ and NO_xemissions in 31 states and the District of Columbia starting in 2012, including several states where subsidiaries of the Company conduct business.

The Transport Rule contemplates three possible options for reducing SO₂ and NO_xemissions in the designated states. The EPA’s preferred option contemplates a set limit or budget on SO₂ and NO_xemissions for each of the states and limited interstate trading as well as unlimited intrastate trading of SO₂ and NO_xemissions allowances among power plants. Affected power plants would receive emissions allowances based on the applicable state emissions budgets. The EPA’s second option under the Transport Rule would establish emission budgets for each state but only allow intrastate trading of emissions allowances. The final option would set emission rate limitations for each power plant but would allow for some intrastate averaging of emission rates. Under any of the proposed options, additional pollution control technology may be required by some of our subsidiaries, and the cost of any such technology could affect the financial condition or results of operations of these subsidiaries.

The EPA has received public comments on the Transport Rule, and such public comments will be considered by the EPA prior to promulgating a final rule. A final rule is expected in the spring of 2011. In addition to the Transport Rule, legislation is also being discussed in the U.S. Congress to address emissions of SO₂, and NO_x. Such legislation, if enacted, could preempt the Transport Rule or any similar EPA regulation. While the exact impact and compliance cost of the Transport Rule or any federal legislation pertaining to SO₂ and NO_xemissions cannot be established until such regulation or legislation is finalized and implemented, the Company’s businesses and financial condition or results of operations could be materially and adversely affected by such regulation or legislation.

Water Discharges.

As noted in our 2009 Form 10-K, 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. New draft rule 316(b) regulations are expected to be issued by the EPA later this year, and 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. 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, although this date may be extended in certain circumstances, including to meet reliability needs of the electric grid. Although the ultimate compliance costs from implementation of Section 316(b) in California are uncertain, the Company expects compliance with such technology-based standards established by the State of California to require material capital expenditures and/or modifications for these power plants. The approval of this policy resulted in the recognition of asset impairment expense during the three months ended September 30, 2010. See additional discussion in Note 13 — Impairments.

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 each option would allow for the continued beneficial use of CCB. 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 was extended, and is now set to expire on November 19, 2010. The EPA will consider any public comments prior to promulgating a final rule. Requirements under a final rule would not be effective until 2011 or later. 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 business, financial condition or results of operations would not be materially and adversely affected by such regulations.

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 16 years.

The following table summarizes the Parent Company’s contingent contractual obligations as of September 30, 2010. 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 $112 million.


Contingent contractual obligations	Amount		Number of Agreements		Maximum Exposure Range for Each Agreement
	(in millions)				(in millions)
Guarantees	$	432		26		< $1 - $63
Letters of credit under the senior secured credit facility		121		32		< $1 - $54

Total	$	553		58

As of September 30, 2010, The AES Corporation had $108 million of commitments to invest in subsidiaries under construction and to purchase related equipment, excluding approximately $64 million of such obligations already included in the letters of credit discussed above. The Company expects to fund these net investment commitments over time according to the following schedule: $79 million in 2010 and $29 million in 2011. The exact payment schedule will be dictated by construction milestones.

Litigation

The Company is involved in certain claims, suits and legal proceedings in the normal course of business, some of which are described below. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information currently available and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be reasonably estimated as of September 30, 2010.

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$1.05 billion ($616 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the Fifth District Court rejected Eletropaulo’s defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro (“AC”) ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the Fifth District Court. Eletropaulo’s subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil were dismissed. Eletrobrás later requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo consented to the appointment of such an expert, subject to a reservation of rights. In February

2010, the Fifth District Court appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization, in accordance with the methodology proposed by Eletrobrás. Pursuant to its reservation of rights, Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo’s arguments and directing the Fifth District Court to proceed accordingly. Eletrobrás may restart the proceedings at the Fifth District Court at any time, which would proceed according to the AC’s April 2010 decision. In the Fifth District Court proceedings, the expert’s conclusions will be subject to the Fifth District Court’s review and approval. If Eletropaulo is determined to be responsible for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo will be required to provide security in the amount of its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the Fifth District Court grants such request, Eletropaulo’s results of operations may be materially adversely affected, and in turn the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the Fifth District Court against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. The parties are disputing the proper venue for the CTEEP lawsuit. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 1999, a state appellate court in Minas Gerais, Brazil, granted a temporary injunction suspending the effectiveness of a shareholders’ agreement between SEB and the state of Minas Gerais concerning CEMIG, an integrated utility in Minas Gerais. The Company’s investment in CEMIG is through SEB. This shareholders’ agreement granted SEB certain rights and powers with respect to the management of CEMIG (“Special Rights”). In March 2000, a lower state court in Minas Gerais held the shareholders’ agreement invalid where it purported to grant SEB the Special Rights and enjoined the exercise of the Special Rights. In August 2001, the state appellate court denied an appeal of the decision and extended the injunction. In October 2001, SEB filed appeals against the state appellate court’s decision with the SCJ and the Supreme Court. The state appellate court denied access of these appeals to the higher courts, and in August 2002 SEB filed interlocutory appeals against such denial with the SCJ and the Supreme Court. In December 2004, the SCJ declined to hear SEB’s appeal. In December 2009, the Supreme Court also declined to hear SEB’s appeal. In February 2010, SEB filed an appeal with the Supreme Court Collegiate (“SCC”). Pursuant to a settlement between SEB and BNDES relating to the collection suit filed by BNDES against SEB in April 2004 (as further described in the Form 10-Q for the period ended June 30, 2010), SEB filed a petition with the SCC waiving its right to pursue further litigation against the Minas Gerais and requesting that the SCC dismiss the appeal. In August 2010, the SCC dismissed the appeal, bringing this litigation to an end.

In August 2000, the FERC announced an investigation into the organized California wholesale power markets in order to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. FERC requested documents from each of the AES Southland, LLC plants and AES Placerita, Inc. AES Southland and AES Placerita have cooperated fully with the FERC investigations. AES Southland was not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. After hearings at FERC, AES Placerita was found subject to refund liability of $588,000 plus interest for spot sales to the California Power Exchange from October 2, 2000 to June 20, 2001. As FERC investigations and hearings progressed, numerous appeals on related issues were filed with the U.S. Court of Appeals for the Ninth Circuit. Over the past five years, the Ninth Circuit issued several opinions that had the potential to expand the scope of the FERC proceedings and increase refund exposure for AES Placerita and other sellers of electricity. Following remand of one of the Ninth Circuit appeals in March 2009, FERC started a new hearing process involving AES Placerita and other sellers. In May 2009, AES Placerita entered into a settlement, subject to FERC approval, concerning the claims before FERC against AES Placerita relating to the California energy crisis of 2000-2001, including the California refund proceeding. Pursuant to the settlement, AES Placerita paid $6 million and assigned a receivable of $168,119 due to it from the California Power

Exchange in return for a release of all claims against it at FERC by the settling parties and other consideration. In July 2009, FERC approved the settlement as submitted. More than 98% of the buyers in the market elected to join the settlement. A small amount of AES Placerita’s settlement payment was placed in escrow for buyers that did not join the settlement (“non-settling parties”). It is unclear whether the escrowed funds will be enough to satisfy any additional sums that might be determined to be owed to non-settling parties at the conclusion of the FERC proceedings concerning the California energy crisis. However, any such additional sums are expected to be immaterial to the Company’s consolidated financial statements. In November 2009, one non-settling party, the Sacramento Municipal Utility District (“SMUD”), filed an appeal of the FERC’s approval of the settlement with the U.S. Court of Appeals for the District of Columbia Circuit, which was later transferred to the Ninth Circuit. SMUD’s appeal has been consolidated with other appeals from FERC orders relating to the California energy crisis and stayed pending further order of the court. The settlement agreement is still effective and will continue to remain effective unless it is vacated by the Ninth Circuit.

In August 2001, the Grid Corporation of Orissa, India, now Gridco Ltd (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. In September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in Orissa Power Generation Corporation Ltd’s (“OPGC”), and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco’s challenge to the arbitration award is resolved. In June 2010, a 2-to-1 majority of the arbitral tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC’s existing PPA with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC’s jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court’s decision to the Supreme

Court and sought stays of both the High Court’s decision and the underlying OERC proceedings regarding the PPAs terms. In April 2005, the Supreme Court granted OPGC’s requests and ordered stays of the High Court’s decision and the OERC proceedings with respect to the PPA’s terms. The matter is awaiting further hearing. Unless the Supreme Court finds in favor of OPGC’s appeal or otherwise prevents the OERC’s proceedings regarding the PPA’s terms, the OERC will likely lower the tariff payable to OPGC under the PPA, which would have an adverse impact on OPGC’s financials. OPGC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified AES Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgás and the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo and the quality of service provided by Eletropaulo to its customers, and requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FSCP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal with the FCA, which was subsequently consolidated with the MPF’s interlocutory appeal, seeking a transfer of venue and to enjoin the FCSP from considering any of the alleged violations. In June 2009, the FCA granted the injunction sought by AES Elpa and AES Transgás and transferred the case to the Federal Court of Rio de Janeiro. In May 2010, the MPF filed an appeal with the Superior Court of Justice challenging the transfer. The MPF’s lawsuit before the FCSP has been stayed pending a final decision on the interlocutory appeals. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in resp

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