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 June 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 July 31, 2010 was 794,015,970.

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2010

TABLE OF CONTENTS


PART I: FINANCIAL INFORMATION		3

*ITEM 1.*	*FINANCIAL STATEMENTS*	3
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Cash Flows	5
	Condensed Consolidated Statements of Changes in Equity	6
	Notes to Condensed Consolidated Financial Statements	7

*ITEM 2.*	*MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*	51

*ITEM 3.*	*QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK*	88

*ITEM 4.*	*CONTROLS AND PROCEDURES*	90

PART II: OTHER INFORMATION		91

*ITEM 1.*	*LEGAL PROCEEDINGS*	91

*ITEM 1A.*	*RISK FACTORS*	91

*ITEM 2.*	*UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS*	91

*ITEM 3.*	*DEFAULTS UPON SENIOR SECURITIES*	91

*ITEM 4.*	*REMOVED AND RESERVED*	91

*ITEM 5.*	*OTHER INFORMATION*	91

*ITEM 6.*	*EXHIBITS*	91

PART I: FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

THE AES CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in millions, except per share amounts)
Revenue:
Regulated	$	2,213		$	1,779		$	4,454		$	3,445
Non-Regulated		1,808			1,512			3,638			3,081

Total revenue		4,021			3,291			8,092			6,526

Cost of Sales:
Regulated		(1,641	)		(1,311	)		(3,307	)		(2,531	)
Non-Regulated		(1,398	)		(1,177	)		(2,817	)		(2,343	)

Total cost of sales		(3,039	)		(2,488	)		(6,124	)		(4,874	)

Gross margin		982			803			1,968			1,652

General and administrative expenses		(101	)		(87	)		(181	)		(170	)
Interest expense		(394	)		(368	)		(780	)		(740	)
Interest income		101			89			210			182
Other expense		(48	)		(30	)		(60	)		(52	)
Other income		69			22			77			243
Gain on sale of investments		-			102			-			115
Asset impairment expense		(1	)		(1	)		(1	)		(1	)
Foreign currency transaction gains (losses) on net monetary position		(71	)		28			(122	)		(11	)
Other non-operating expense		(5	)		-			(5	)		(10	)

INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES		532			558			1,106			1,208
Income tax expense		(255	)		(105	)		(451	)		(279	)
Net equity in earnings of affiliates		134			50			148			57

INCOME FROM CONTINUING OPERATIONS		411			503			803			986
Income from operations of discontinued businesses, net of income tax expense of $1, $0, $2 and $1, respectively		27			28			50			46
Loss from disposal of discontinued businesses, net of income tax benefit of $0, $0, $0 and $0, respectively		(9	)		-			(22	)		-

NET INCOME		429			531			831			1,032
Noncontrolling interests:
Less: Income from continuing operations attributable to noncontrolling interests		(277	)		(217	)		(488	)		(492	)
Less: Income from discontinued operations attributable to noncontrolling interests		(8	)		(11	)		(12	)		(19	)

Total net income attributable to noncontrolling interests		(285	)		(228	)		(500	)		(511	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	144		$	303		$	331		$	521

BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.17		$	0.43		$	0.42		$	0.74
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		0.01			0.02			0.02			0.04

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.18		$	0.45		$	0.44		$	0.78

DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.17		$	0.43		$	0.42		$	0.74
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		0.01			0.02			0.02			0.04

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.18		$	0.45		$	0.44		$	0.78

AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	134		$	286		$	315		$	494
Discontinued operations, net of tax		10			17			16			27

Net income	$	144		$	303		$	331		$	521

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Balance Sheets


	June 30, 2010			December 31, 2009
	(in millions except share and per share data)
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,891		$	1,782
Restricted cash		572			407
Short-term investments		1,716			1,648
Accounts receivable, net of allowance for doubtful accounts of $288 and $290, respectively		2,184			2,118
Inventory		551			560
Receivable from affiliates		16			24
Deferred income taxes — current		257			210
Prepaid expenses		172			161
Other current assets		1,086			1,557
Current assets of discontinued and held for sale businesses		119			320

Total current assets		9,564			8,787

NONCURRENT ASSETS
Property, Plant and Equipment:
Land		1,083			1,111
Electric generation, distribution assets and other		28,299			26,815
Accumulated depreciation		(9,099	)		(8,774	)
Construction in progress		3,803			4,644

Property, plant and equipment, net		24,086			23,796

Other Assets:
Deferred financing costs, net of accumulated amortization of $290 and $293, respectively		374			377
Investments in and advances to affiliates		1,227			1,157
Debt service reserves and other deposits		603			595
Goodwill		1,293			1,299
Other intangible assets, net of accumulated amortization of $228 and $223, respectively		574			510
Deferred income taxes — noncurrent		604			587
Other		1,533			1,551
Noncurrent assets of discontinued and held for sale businesses		843			876

Total other assets		7,051			6,952

TOTAL ASSETS	$	40,701		$	39,535

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and other accrued liabilities	$	4,067		$	4,193
Accrued interest		259			269
Non-recourse debt — current		1,433			1,718
Recourse debt — current		471			214
Current liabilities of discontinued and held for sale businesses		134			227

Total current liabilities		6,364			6,621

LONG-TERM LIABILITIES
Non-recourse debt — noncurrent		13,131			12,304
Recourse debt — noncurrent		4,637			5,301
Deferred income taxes — noncurrent		1,208			1,090
Pension and other post-retirement liabilities		1,257			1,322
Other long-term liabilities		2,742			3,146
Long-term liabilities of discontinued and held for sale businesses		643			811

Total long-term liabilities		23,618			23,974

Contingencies and Commitments (see Note 8)
Redeemable stock of subsidiaries		65			60
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 804,399,275 issued and 795,495,286 outstanding at June 30, 2010 and 677,214,493 issued and 667,679,913 outstanding at December 31, 2009		8			7
Additional paid-in capital		8,457			6,868
Retained earnings		942			650
Accumulated other comprehensive loss		(2,602	)		(2,724	)
Treasury stock, at cost (8,903,989 shares at June 30, 2010 and 9,534,580 shares at December 31, 2009, respectively)		(118	)		(126	)

Total The AES Corporation stockholders’ equity		6,687			4,675
NONCONTROLLING INTERESTS		3,967			4,205

Total equity		10,654			8,880

TOTAL LIABILITIES AND EQUITY	$	40,701		$	39,535

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
	2010			2009
	(in millions)
OPERATING ACTIVITIES:
Net income	$	831		$	1,032
Adjustments to net income:
Depreciation and amortization		584			498
Loss (gain) from sale of investments and impairment expense		18			(103	)
Loss on disposal and impairment write-down — discontinued operations		18			-
Provision for deferred taxes		117			(111	)
Contingencies		72			(54	)
Loss (gain) on the extinguishment of debt		9			(3	)
Undistributed gain from sale of equity method investment		(115	)		-
Other		(42	)		4
Changes in operating assets and liabilities:
Increase in accounts receivable		(69	)		(3	)
Increase in inventory		(1	)		(11	)
Decrease in prepaid expenses and other current assets		170			34
Increase in other assets		(51	)		(139	)
Decrease in accounts payable and accrued liabilities		(91	)		(292	)
(Decrease) increase in income taxes and other income tax payables, net		(90	)		54
Increase (decrease) in other liabilities		56			(32	)

Net cash provided by operating activities		1,416			874

INVESTING ACTIVITIES:
Capital expenditures		(1,002	)		(1,193	)
Acquisitions — net of cash acquired		(100	)		-
Proceeds from the sale of businesses		198			2
Sale of short-term investments		3,139			2,269
Purchase of short-term investments		(3,255	)		(1,740	)
(Increase) decrease in restricted cash		(74	)		305
(Increase) decrease in debt service reserves and other assets		(9	)		40
Affiliate advances and equity investments		(27	)		(87	)
Proceeds from loan repayments		132			-
Other investing		43			20

Net cash used in investing activities		(955	)		(384	)

FINANCING ACTIVITIES:
Issuance of common stock		1,569			-
Borrowings (repayments) under the revolving credit facilities, net		88			(31	)
Issuance of recourse debt		-			503
Issuance of non-recourse debt		1,343			816
Repayments of recourse debt		(406	)		(154	)
Repayments of non-recourse debt		(1,297	)		(491	)
Payments for deferred financing costs		(29	)		(53	)
Distributions to noncontrolling interests		(542	)		(334	)
Contributions from noncontrolling interests		-			74
Financed capital expenditures		(17	)		(24	)
Other financing		(17	)		25

Net cash provided by financing activities		692			331
Effect of exchange rate changes on cash		(44	)		14

Total increase in cash and cash equivalents		1,109			835
Cash and cash equivalents, beginning		1,782			865

Cash and cash equivalents, ending	$	2,891		$	1,700

SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	764		$	697
Cash payments for income taxes, net of refunds	$	429		$	306
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Assets acquired in noncash asset exchange	$	-		$	110

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statement of Changes in Equity

(Unaudited)


	THE AES CORPORATION STOCKHOLDERS
	Common Stock		Treasury Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Consolidated Comprehensive Income
	(in millions)
Balance at January 1, 2010	$	7	$	(126	)	$	6,868	$	650		$	(2,724	)	$	4,205
Net income		-		-			-		331			-			500		$	831
Change in fair value of available-for-sale securities, net of income tax		-		-			-		-			(6	)		-			(6	)
Foreign currency translation adjustment, net of income tax		-		-			-		-			302			(68	)		234
Change in unfunded pensions obligation, net of income tax		-		-			-		-			2			3			5
Change in derivative fair value, including a reclassification to earnings, net of income tax		-		-			-		-			(138	)		(31	)		(169	)

Other comprehensive income																		64

Total comprehensive income																	$	895

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		-		-			-		-			-			3
Dividends declared to noncontrolling interests		-		-			-		-			-			(646	)
Disposition of businesses		-		-			-		-			-			(14	)
Issuance of common stock		1		-			1,566		-			-			-
Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax		-		8			9		-			-			-
Stock compensation		-		-			14		-			-			-
Changes in the carrying amount of redeemable stock of subsidiaries		-		-			-		7			-			-

Balance at June 30, 2010	$	8	$	(118	)	$	8,457	$	942		$	(2,602	)	$	3,967


	THE AES CORPORATION STOCKHOLDERS
	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		-		-			-		521			-			511		$	1,032
Foreign currency translation adjustment, net of income tax		-		-			-		-			65			268			333
Change in unfunded pensions obligation, net of income tax		-		-			-		-			2			-			2
Change in derivative fair value, including a reclassification to earnings, net of income tax		-		-			-		-			104			39			143

Other comprehensive income																		478

Total comprehensive income																	$	1,510

Capital contributions from noncontrolling interests		-		-			-		-			-			75
Dividends declared to noncontrolling interests		-		-			-		-			-			(412	)
Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax		-		18			5		-			-			-
Stock compensation		-		-			8		-			-			-

Balance at June 30, 2009	$	7	$	(126	)	$	6,845	$	513		$	(2,847	)	$	3,839

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Notes to Condensed Consolidated Financial Statements

For the Three and Six Months Ended June 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 13 — Discontinued Operations.

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 six months ended June 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.

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 June 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. 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. However, the counterparty usually does not have the power to direct any of the other activities that could significantly impact the economic performance, 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. 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 June 30, 2010, total assets and total liabilities related to these VIEs were $781 million and $865 million. In addition, revenue for the three and six months ended June 30, 2010 included $85 million and $187 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 June 30, 2010 and December 31, 2009:


	June 30, 2010		December 31, 2009
	(in millions)
Coal, fuel oil and other raw materials	$	284	$	293
Spare parts and supplies		267		267

Total	$	551	$	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 June 30, 2010 and December 31, 2009:


	June 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Assets
Marketable securities	$	1,758	$	1,758	$	1,691	$	1,691
Derivatives		155		155		141		141

Total assets	$	1,913	$	1,913	$	1,832	$	1,832

Liabilities
Debt	$	19,672	$	20,046	$	19,537	$	20,008
Derivatives		510		510		310		310

Total liabilities	$	20,182	$	20,556	$	19,847	$	20,318

The Company’s nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis include goodwill; intangible assets, such as sales concessions, land rights and emissions allowances; and long-lived tangible assets including property, plant and equipment. The Company recognized a loss on disposal and impairment losses totaling $9 million and $22 million before taxes and noncontrolling interests related to nonfinancial assets and liabilities at our Pakistan businesses currently reflected as discontinued operations during the three and six months ended June 30, 2010, respectively. See further discussion of these adjustments in Note 13 — Discontinued Operations and Held for Sale Businesses.

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. 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, 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 us to use 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.

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 June 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 June 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	$	1,749	$	125	$	1,582	$	42
Trading securities		8		8		-		-
Derivatives		155		-		99		56

Total assets	$	1,912	$	133	$	1,681	$	98

Liabilities
Derivatives	$	510	$	-	$	231	$	279

Total liabilities	$	510	$	-	$	231	$	279


	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 six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,
	2010															2009
	Interest Rate			Cross Currency			Foreign Exchange			Commodity			Total			Total
	(in millions)
Balance at beginning of period⁽¹⁾	$	(18	)	$	(7	)	$	(1	)	$	19		$	(7	)	$	(217	)
Total gains (losses) (realized and unrealized):⁽¹⁾
Included in earnings⁽²⁾		-			(1	)		-			(1	)		(2	)		(5	)
Included in other comprehensive income		(10	)		(28	)		-			-			(38	)		77
Included in regulatory assets		(2	)		-			-			5			3			1
Purchases, issuances and settlements⁽¹⁾		-			2			22			(4	)		20			9
Transfers of assets (liabilities) into Level 3⁽³⁾		(209	)		-			(3	)		-			(212	)		-
Transfers of (assets) liabilities out of Level 3⁽³⁾		13			-			-			-			13			126

Balance at June 30⁽¹⁾	$	(226	)	$	(34	)	$	18		$	19		$	(223	)	$	(9	)

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	)	$	20		$	(6	)	$	12		$	(5	)


	Six Months Ended June 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⁾		-			5			-			2			7			(24	)
Included in other comprehensive income		(13	)		(30	)		-			-			(43	)		140
Included in regulatory assets		(3	)		-			-			5			2			2
Purchases, issuances and settlements⁽¹⁾		1			3			22			(12	)		14			(1	)
Transfers of assets (liabilities) into Level 3⁽³⁾		(208	)		-			(4	)		-			(212	)		-
Transfers of (assets) liabilities out of Level 3⁽³⁾		9			-			-			-			9			(57	)

Balance at June 30⁽¹⁾	$	(226	)	$	(34	)	$	18		$	19		$	(223	)	$	(9	)

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	)	$	5		$	20		$	(10	)	$	14		$	(13	)

⁽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 six months ended June 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 six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,					Six Months Ended June 30,
	2010		2009			2010		2009
	(in millions)
Balance at beginning of period⁽¹⁾	$	42	$	13		$	42	$	42
Purchases, issuances and settlements		-		(11	)		-		(40	)

Balance at June 30	$	42	$	2		$	42	$	2


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.

4. INVESTMENTS IN MARKETABLE SECURITIES

The following table sets forth the Company’s investments in marketable debt and equity securities as of June 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.


	June 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⁾	$	-	$	579	$	-	$	579	$	-	$	667	$	-	$	667
Certificates of deposit⁽²⁾		-		771		-		771		-		652		-		652
Government debt securities		-		147		-		147		-		152		-		152
Other debt securities		-		-		42		42		-		-		42		42

Subtotal		-		1,497		42		1,539		-		1,471		42		1,513
Equity securities:
Mutual funds		118		65		-		183		117		-		-		117
Common stock		7		-		-		7		16		-		-		16
Money market funds		-		20		-		20		-		30		-		30

Subtotal		125		85		-		210		133		30		-		163

Total available-for-sale	$	125	$	1,582	$	42	$	1,749	$	133	$	1,501	$	42	$	1,676

TRADING:
Equity securities:
Mutual funds		8		-		-		8		7		-		-		7

Total trading		8		-		-		8		7		-		-		7

TOTAL	$	133	$	1,582	$	42	$	1,757	$	140	$	1,501	$	42	$	1,683

Held-to-maturity securities⁽³⁾								1								8

Total marketable securities							$	1,758							$	1,691

⁽¹⁾	Amortized cost approximated fair value at June 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 June 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 consist primarily of certificates of deposit and government debt securities. The amortized cost approximated fair value of the held-to-maturity securities at June 30, 2010 and December 31, 2009. As of June 30, 2010, all held-to-maturity debt securities had stated maturities within one year.

As of June 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 June 30, 2010.

The following table summarizes the pre-tax gains and losses related to available-for-sale and trading securities for the three and six months ended June 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 six months ended June 30, 2010 and 2009.


	Three Months Ended June 30,					Six Months Ended June 30,
	2010			2009		2010			2009
	(in millions)					(in millions)
Gains included in earnings that relate to trading securities held at the reporting date	$	1		$	1	$	1		$	1
Losses included in other comprehensive income	$	(3	)	$	-	$	(10	)	$	-
Proceeds from sales	$	2,247		$	1,222	$	3,210		$	2,143
Gross realized gains on sales	$	1		$	1	$	1		$	1

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 June 30, 2010 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:


	June 30, 2010
	Current			Maximum⁽¹⁾
Interest Rate Derivatives	Derivative Notional	Derivative Notional Translated to USD		Derivative Notional	Derivative Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾	% of Debt Currently Hedged by Index⁽²⁾
	(in millions)						(in years)
Libor (U.S. Dollar)	2,517	$	2,517	2,743	$	2,743	10	69	%
Euribor (Euro)	1,185		1,450	1,242		1,519	14	73	%
Libor (British Pound Sterling)	47		70	47		70	10	68	%
Securities Industry and Financial Markets Association Municipal Swap Index (U.S. Dollar)	40		40	40		40	13	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 June 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 June 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 June 30, 2010:


	June 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	$	217	16	83	%

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

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

Foreign Currency Risk

We are exposed to foreign currency risk as a result of our investments in foreign subsidiaries and affiliates. AES operates businesses in many foreign 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 June 30, 2010 regardless of whether the derivative instruments are in qualifying hedging relationships:


	June 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)	116	$	65	$	45	<1
Euro (EUR)	7		10		9	<1
Philippine Peso (PHP)	143		3		2	<1
British Pound (GBP)	3		4		4	<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.


	June 30, 2010
Foreign Currency Forwards	Notional	Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾
	(in millions)			(in years)
Chilean Peso (CLP)	91,404	$	178	<1
Colombian Peso (COP)	105,832		54	<1
Argentine Peso (ARS)	76		17	<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 June 30, 2010:


	June 30, 2010
Embedded Foreign Currency Derivatives	Notional	Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾
	(in millions)			(in years)
Philippine Peso (PHP)	13,781	$	297	4
Kazakhstani Tenge (KZT)	43,644		296	10
Argentine Peso (ARS)	330		84	10
Euro (EUR)	35		43	5
Hungarian Forint (HUF)	927		4	1
Brazilian Real (BRL)	2		1	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 the supply of electricity and fuel in other competitive markets in which we operate. When hedging the output of our generation assets, we have PPAs 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 in New York and Deepwater in Texas, two of our North America generation businesses, and IPL, a North America utility business, sell electricity into the power pools managed by the New York Independent System Operator (“NYISO”), Electric Reliability Council of Texas (“ERCOT”), and the Midwest Independent System Operator (“MISO”), respectively. In addition, Eastern Energy has hedged a portion of its power exposure for 2010 by entering into hedges of natural gas prices, as movements in natural gas prices affect power prices. While there is

a strong relationship between natural gas and power prices, the natural gas hedges do not currently qualify for hedge accounting treatment 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, Deepwater and IPL and the percentage of forecasted electricity sales hedged as of June 30, 2010 for 2010 and 2011:


	2010				2011
Commodity Hedges	Notional		% of Forecasted Sales Hedged		Notional		% of Forecasted Sales Hedged
	(in millions)				(in millions)
Natural gas swaps (MMBTU)	12		31	%	-		-	%
NYISO electricity swaps (MWh)	1		28	%	-	⁽¹⁾	-	%⁽¹⁾
ERCOT electricity swaps (MWh)	-	⁽¹⁾	12	%	-		-	%
MISO electricity swaps (MWh)	-	⁽¹⁾	17	%⁽²⁾	-		-	%

⁽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 power or fuel 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, Deepwater and IPL, which are presented in the above table) and embedded derivative instruments as of June 30, 2010:


	June 30, 2010
Commodity Derivatives	Notional		Weighted Average Remaining Term⁽¹⁾
	(in millions)		(in years)
Natural gas (MMBTU)	92		8
Petcoke (Metric tons)	14		14
Coal (Metric tons)	-	⁽²⁾	<1
Log wood (Tons)	-	⁽²⁾	3

⁽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 June 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.


	June 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	$	-	$	21		$	3		$	24		$	-	$	6	$	-	$	6
Commodity derivatives
Electricity		-		12			-			12			-		22		-		22
Natural gas		-		20			9			29			-		-		11		11
Other		-		1			14			15			-		-		17		17

Total current assets		-		54			26			80			-		28		28		56

Noncurrent assets:
Interest rate derivatives		-		37			-			37			-		83		2		85
Foreign exchange derivatives		-		5	⁽¹⁾		30			35			-		-		-		-
Other		-		3			-			3			-		-		-		-

Total noncurrent assets		-		45			30			75			-		83		2		85

Total assets	$	-	$	99		$	56		$	155		$	-	$	111	$	30	$	141

Liabilities
Current liabilities:
Interest rate derivatives	$	-	$	79		$	56		$	135	⁽¹⁾	$	-	$	118	$	7	$	125
Cross currency derivatives		-		-			14			14			-		-		-		-
Foreign exchange derivatives		-		12			-			12			-		3		-		3
Commodity derivatives
Electricity		-		4			-			4			-		2		-		2
Natural gas		-		-			-			-			-		5		-		5
Other		-		-			-			-			-		-		2		2

Total current liabilities		-		95			70			165			-		128		9		137

Noncurrent liabilities:
Interest rate derivatives		-		135			170			305	⁽¹⁾		-		150		7		157
Cross currency derivatives		-		-			20			20			-		-		12		12
Foreign exchange derivatives		-		1			15	⁽¹⁾		16			-		2		-		2
Commodity derivatives
Natural gas		-		-			1			1			-		-		2		2
Other fuel		-		-			3			3			-		-		-		-

Total noncurrent liabilities		-		136			209			345			-		152		21		173

Total liabilities	$	-	$	231		$	279		$	510		$	-	$	280	$	30	$	310

⁽¹⁾

Includes the impact of consolidating Cartagena beginning January 1, 2010 under VIE accounting guidance as follows: $2 million of noncurrent assets and $2 million in noncurrent liabilities on foreign exchange derivatives and $18 million of current liabilities and $53 million of noncurrent liabilities for interest rate derivatives as of June 30, 2010.

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


	June 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	$	6		$	18	⁽¹⁾	$	24	$	-	$	6	$	6
Commodity derivatives:
Electricity		12			-			12		22		-		22
Natural gas		-			29			29		-		11		11
Other		-			15			15		-		17		17

Total other current assets		18			62			80		22		34		56

Other assets:
Interest rate derivatives		37			-			37		85		-		85
Foreign exchange derivatives		-			35	⁽¹⁾		35		-		-		-
Other		-			3			3		-		-		-

Total other assets — noncurrent		37			38			75		85		-		85

Total assets	$	55		$	100		$	155	$	107	$	34	$	141

Liabilities
Accounts payable and other accrued liabilities:
Interest rate derivatives	$	119	⁽¹⁾	$	16		$	135	$	115	$	10	$	125
Cross currency derivatives		14			-			14		-		-		-
Foreign exchange derivatives		2			10			12		2		1		3
Commodity derivatives:
Electricity		4			-			4		2		-		2
Natural gas		-			-			-		-		5		5
Other		-			-			-		-		2		2

Total accounts payable and other accrued liabilities — current		139			26			165		119		18		137

Other long-term liabilities:
Interest rate derivatives		287	⁽¹⁾		18			305		141		16		157
Cross currency derivatives		20			-			20		12		-		12
Foreign exchange derivatives		-			16	⁽¹⁾		16		-		2		2
Commodity derivatives:
Natural gas		-			1			1		-		2		2
Other fuel		-			3			3		-		-		-

Total other long-term liabilities		307			38			345		153		20		173

Total liabilities	$	446		$	64		$	510	$	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 June 30, 2010 and December 31, 2009, we held $23 million and $8 million, respectively, of cash collateral that we received from counterparties to our derivative positions, which is classified as restricted cash and accrued and other liabilities in the condensed consolidated balance sheets. Also, at June 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 over the next twelve months as of June 30, 2010 for the following types of derivative instruments:


	Accumulated Other Comprehensive Income (Loss)
	(in millions)
Interest rate derivatives	$	(113)
Cross currency derivatives	$	(14)
Foreign currency derivatives	$	5
Commodity derivatives	$	7

The balance in accumulated other comprehensive loss related to derivative transactions that will be reclassified into earnings as interest expense is recognized for interest rate hedges and cross currency swaps, as depreciation is recognized for interest rate hedges during construction, as foreign currency 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.

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 six months ended June 30, 2010 and 2009:


	Gains (Losses) Recognized in AOCL						Classification in Condensed Consolidated Statement of Operations	Gains (Losses) Reclassified from AOCL into Earnings
	Three Months Ended June 30,							Three Months Ended June 30,
	2010			2009				2010			2009
	(in millions)							(in millions)
Interest rate derivatives	$	(160	)⁽³⁾	$	48		Interest expense	$	(34	)⁽¹⁾	$	2	⁽¹⁾
							Non-regulated cost of sales		-			-
Cross currency derivatives		(27	)		28		Interest expense		-			-
							Foreign currency transaction gains (losses)		-			-
Foreign currency derivatives		7			-	⁽²⁾	Foreign currency transaction gains (losses)		-			-
Commodity derivatives — electricity		(12	)		28		Non-regulated revenue		2			57

Total	$	(192	)	$	104			$	(32	)	$	59


	Gains (Losses) Recognized in AOCL						Classification in Condensed Consolidated Statement of Operations	Gains (Losses) Reclassified from AOCL into Earnings
	Six Months Ended June 30,							Six Months Ended June 30,
	2010			2009				2010			2009
	(in millions)							(in millions)
Interest rate derivatives	$	(232	)⁽³⁾	$	93		Interest expense	$	(67	)⁽¹⁾	$	1	⁽¹⁾
							Non-regulated cost of sales		-			-
Cross currency derivatives		(30	)		34		Interest expense		(1	)		-
							Foreign currency transaction gains (losses)		-			-
Foreign currency derivatives		7			-	⁽²⁾	Foreign currency transaction gains (losses)		-			-
Commodity derivatives — electricity		-			109		Non-regulated revenue		10			87

Total	$	(255)		$	236			$	(58	)	$	88

⁽¹⁾	Includes amounts that were reclassified from AOCL related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting.

⁽²⁾	De minimis amount.

⁽³⁾	Includes $12 million related to Cartagena for the three months ended June 30, 2010 and $32 million for the six months ended June 30, 2010, 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 six months ended June 30, 2010 and 2009:


	Classification in Condensed Consolidated Statement of Operations	Gains (Losses) Recognized in Earnings
		Three Months Ended June 30,
		2010			2009
		(in millions)
Interest rate derivatives	Interest expense	$	6		$	9
Cross currency derivatives	Interest expense		(1	)		-
Foreign currency derivatives	Foreign currency transaction gains (losses)		-			-
Commodity derivatives — electricity	Non-regulated revenue		-			-

Total		$	5		$	9


	Classification in Condensed Consolidated Statement of Operations	Gains (Losses) Recognized in Earnings
		Six Months Ended June 30,
		2010			2009
		(in millions)
Interest rate derivatives	Interest expense	$	2		$	7
Cross currency derivatives	Interest expense		5			2
Foreign currency derivatives	Foreign currency transaction gains (losses)		-	⁽¹⁾		-
Commodity derivatives — electricity	Non-regulated revenue		-			(2	)

Total		$	7		$	7

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 six months ended June 30, 2010 and 2009, respectively:


	Classification in Condensed Consolidated Statement of Operations	Gains (Losses) Recognized in Earnings
		Three Months Ended June 30,
		2010			2009
		(in millions)
Interest rate derivatives	Interest expense	$	(1	)	$	5
Foreign exchange derivatives	Non-regulated cost of sales		-			-
	Foreign currency transaction gains (losses)		(28	)⁽¹⁾		(19	)
Commodity derivatives — natural gas	Non-regulated revenue		(7	)		-
	Non-regulated cost of sales		3			-
Commodity derivatives — other	Non-regulated revenue		4			-
	Non-regulated cost of sales		(2	)		6

Total		$	(31	)	$	(8	)


	Classification in Condensed Consolidated Statement of Operations	Gains (Losses) Recognized in Earnings
		Six Months Ended June 30,
		2010			2009
		(in millions)
Interest rate derivatives	Interest expense	$	(5	)	$	-
Foreign exchange derivatives	Non-regulated cost of sales		2	⁽¹⁾		-
	Foreign currency transaction gains (losses)		(29	)		(12	)
Commodity derivatives — natural gas	Non-regulated revenue		36			-
	Non-regulated cost of sales		8			-
Commodity derivatives — other	Non-regulated revenue		4			(5	)
	Non-regulated cost of sales		(2	)		(7	)

Total		$	14		$	(24	)

⁽¹⁾

Includes $(5) million and $0 for the three and six months ended June 30, 2010, respectively, related to Cartagena, which was consolidated as of January 1, 2010 under variable interest entity accounting guidance.

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 six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,					Six Months Ended June 30,
	2010		2009			2010		2009
	(in millions)
Increase (decrease) in regulatory assets	$	2	$	2		$	1	$	(2	)
Increase (decrease) in regulatory liabilities	$	5	$	(1	)	$	6	$	(2	)

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 June 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 $35 million and $12 million, respectively at June 30, 2010 and December 31, 2009. As of June 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 three months ended June 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 June 30, 2010 and December 31, 2009:


	June 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Non-recourse debt	$	14,564	$	14,889	$	14,022	$	14,405
Recourse debt		5,108		5,157		5,515		5,603

Total debt	$	19,672	$	20,046	$	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 June 30, 2010. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to June 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 June 30, 2010:


Subsidiary	Primary Nature of Default	June 30, 2010
Subsidiary	Primary Nature of Default	Default		Net Assets
		(in millions)
Sonel	Covenant	$	301	$	272
Jordan	Covenant		209		65
St. Patrick	Covenant		50		26
Kelanitissa	Covenant		34		21
Ebute⁽¹⁾	Covenant		6		159
Aixi	Payment		2		9

Total		$	602

⁽¹⁾

Ebute, our subsidiary in Nigeria, has received a waiver of default which gives Ebute until December 31, 2010 to cure the breached covenants; however, as this waiver does not extend beyond the Company’s current reporting cycle and the probability of curing the default cannot be determined, the debt was classified as current.

Additionally, approximately $43 million of non-recourse debt at Sociedad Electrica Santiago S.A. (“ESSA”), one of the Company’s subsidiaries in Latin America, has been classified as short-term because the debt may become callable within the next twelve months.

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

Recourse Debt

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 June 30, 2010 was $290 million.

8. CONTINGENCIES AND COMMITMENTS

Environmental

The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of June 30, 2010, the Company had recorded liabilities of $43 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 June 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 introduced in recent months, 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 also promulgated a final rule on June 3, 2010, (the “Tailoring Rule”) that would significantly increase the thresholds for GHG emissions that trigger PSD review and related permitting requirements. Specifically, commencing in 2011, the Tailoring Rule would increase the “major source” threshold from 250 tons per year to 75,000 tons per year for GHG emissions – this means any new source of GHG emissions would need to emit over 75,000 tons per year in order to trigger PSD review and related permitting requirements. Also, commencing in 2011, the Tailoring Rule would increase the “significance threshold” from zero tons per year to 50,000 tons per year for GHG emissions – this means any modifications to existing sources of GHG emissions would need to increase aggregate GHG emissions by over 50,000 tons per year in order to trigger PSD review and related permitting requirements. The Tailoring Rule, as currently proposed by 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 would still generally be subject to PSD and Title V requirements because annual GHG emissions from such plants typically far exceed the “major source” threshold 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 50,000 tons per year 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 offtaker, 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 Transport Rule is subject to public comments until 60 days after it has been published in the Federal Register, and any 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.

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 two options contained in the proposed rule are subject to public comments until September 20, 2010, and any such public comments will be considered by the EPA 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 17 years.

The following table summarizes the Parent Company’s contingent contractual obligations as of June 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 $106 million.


Contingent contractual obligations	Amount		Number of Agreements	Maximum Exposure Range for Each Agreement
	(in millions)			(in millions)
Guarantees	$	422	26	< $1 - $57
Letters of credit under the senior secured credit facility		147	31	< $1 - $67

Total	$	569	57

As of June 30, 2010, The AES Corporation had $81 million of commitments to invest in subsidiaries under construction and to purchase related equipment, excluding approximately $78 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: $41 million in 2010 and $40 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 June 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$1.0 billion ($558 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 was transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the Fifth District Court. Eletropaulo’s subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil have been dismissed. Eletrobrás 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 in accordance with the methodology proposed by Eletropaulo. 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. 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 (see Note 6—Investments In and Advances to Affiliates) relating to the collection suit filed by BNDES against SEB in April 2004, which is further described below, 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. SEB is awaiting a determination on its petition.

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. The Company subsequently filed an application to recover its costs of the arbitration. In June 2010, a 2-to-1 majority of the tribunal awarded the Company some of its costs. In addition, in September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in Orissa Power Generation Corporation Ltd’s (“OPGC”), and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco’s challenge to the arbitration award is resolved. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC’s existing 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 Sao Paulo (“FSCP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. (“Light”) and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal with the FCA, which was subsequently consolidated with the MPF’s interlocutory appeal, seeking a transfer of venue and to enjoin the FCSP from considering any of the alleged violations. In June 2009, the FCA granted the injunction sought by AES Elpa and AES Transgás and transferred the case to the Federal Court of Rio de Janeiro. In May 2010, the MPF filed an appeal with the Superior Court of Justice challenging the transfer. The MPF’s lawsuit before the FCSP has been stayed pending a final decision on the interlocutory appeals. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney’s Office then requested an injunction which the judge rejected on September 26, 2008. The Public Attorney’s office has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a “Technical Cooperation Protocol” pursuant to which they requested a new deadline from FEPAM in order to present a proposal. In March 2008, the State Prosecution office filed a Public Class Action against AES Florestal, AES Sul and CEEE, requiring an injunction for the removal of the alleged sources of contamination and the payment of an indemnity in the amount of R$6 million ($3 million). The injunction was rejected and the case is in the evidentiary stage awaiting the judge’s determination concerning the production of expert evidence. The above referenced proposal was delivered on April 8, 2008. FEPAM responded by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE’s operations. It is estimated that remediation could cost approximately R$14.7 million ($8 million). Discussions between Sul and CEEE are ongoing.

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

In April 2004, BNDES filed a collection suit against SEB, a subsidiary of the Company, to obtain the payment of R$3.8 billion ($2.1 billion), which includes principal, interest and penalties under the loan agreement between BNDES and SEB, the proceeds of which were used by SEB to acquire shares of CEMIG. In May 2004,

the 15th Federal Circuit Court (“Circuit Court”) ordered the attachment of SEB’s CEMIG shares, which were given as collateral for the loan, as well as dividends paid by CEMIG to SEB. At the time of the attachment, the shares were worth approximately R$762 million ($426 million). In December 2006, SEB’s defense was ruled groundless by the Circuit Court. The Federal Court of Appeals affirmed that decision in February 2009. In June 2010, the Circuit Court approved a settlement between SEB and BNDES pursuant to which all of SEB’s alleged debt and the CEMIG shares were transferred to unrelated third parties (see Note 6—Investments In and Advances to Affiliates). The Circuit Court’s approval has become final and, consequently, the collection suit has been closed.

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

In April 2006, a putative class action complaint was filed in the U.S. District Court for the Southern District of Mississippi (“District Court”) on behalf of certain individual plaintiffs and all residents and/or property owners in the State of Mississippi who allegedly suffered harm as a result of Hurricane Katrina, and against the Company and numerous unrelated companies, whose alleged greenhouse gas emissions contributed to alleged global warming which, in turn, allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert unjust enrichment, civil conspiracy/aiding and abetting, public and private nuisance, trespass, negligence, and fraudulent misrepresentation and concealment claims against the defendants. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. In August 2007, the District Court dismissed the case. The plaintiffs subsequently appealed to the U.S. Court of Appeals for the Fifth Circuit, which, in October 2009, affirmed the District Court’s dismissal of the plaintiffs’ unjust enrichment, fraudulent misrepresentation, and civil conspiracy claims. However, the Fifth Circuit reversed the District Court’s dismissal of the plaintiffs’ public and private nuisance, trespass, and negligence claims, and remanded those claims to the District Court for further proceedings. In February 2010, the Fifth Circuit granted the petitions for en banc rehearing filed by the Company and other defendants, and thereby vacated its October 2009 decision. In May 2010, the Fifth Circuit dismissed the appeal on the ground that it had lost its quorum for en banc review. The plaintiffs may appeal to the Supreme Court of the United States. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In July 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan (the “Competition Committee”) ordered Nurenergoservice, an AES subsidiary, to pay approximately 18 billion KZT ($124 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. The

Competition Committee’s order was affirmed by the economic court in April 2008 (“April 2008 Decision”). The economic court also issued an injunction to secure Nurenergoservice’s alleged liability, freezing Nurenergoservice’s bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. Nurenergoservice’s subsequent appeals to the court of appeals were rejected. In February 2009, the Antimonopoly Agency (the Competition Committee’s successor) seized approximately 783 million KZT ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice’s alleged damages liability. However, on appeal to the Kazakhstan Supreme Court, in October 2009, the Supreme Court annulled the decisions of the lower courts because of procedural irregularities and remanded the case to the economic court for reconsideration. On remand, in January 2010, the economic court reaffirmed its April 2008 Decision. In June 2010, the court of appeals (first panel) rejected Nurenergoservice’s appeal. Nurenergoservice intends to file further appeals. In separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately 1.8 billion KZT ($12 million) in administrative fines for its alleged antimonopoly violations. Nurenergoservice’s appeal to the administrative court was rejected in February 2009. Given the adverse court decisions against Nurenergoservice, the Antimonopoly Agency may attempt to seize Nurenergoservice’s remaining assets, which are immaterial to the Company’s consolidated financial statements. The Antimonopoly Agency has not indicated whether it intends to assert claims against Nurenergoservice for alleged antimonopoly violations post first quarter 2007. Nurenergoservice believes it has meritorious claims and defenses; however, there can be no assurances that it will prevail in these proceedings.

In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of UK HPP and Shulbinsk HPP, another hydroelectric plant under AES concession (collectively, the “Hydros”), in January through February 2009. The investigation had been suspended pending the outcome of judicial proceedings concerning the inclusion of the Hydros on the list of dominant suppliers in Eastern Kazakhstan but was resumed after the Hydros failed to prevail in those proceedings. The Hydros then challenged the legality of the underlying Antimonopoly Agency investigation. If the Hydros fail to prove in those proceedings that they are not dominant suppliers and/or that the Antimonopoly Agency’s investigation is groundless, the Antimonopoly Agency’s investigation will resume. The Hydros believe they have meritorious defenses and will assert them vigorously in any formal proceeding concerning the investigation; however, there can be no assurances that they will be successful in their efforts.

In April 2009, the Antimonopoly Agency initiated an investigation of Ust-Kamenogorsk TETS LLP’s (“UKT”) power sales in 2008 through February 2009. The Antimonopoly Agency subsequently concluded that UKT abused its market position and charged monopolistically high prices for power and should pay an administrative fine of approximately KZT 136 million ($1 million). The Antimonopoly Agency later sought an order from the administrative court requiring UKT to pay the fine. The administrative court proceedings had been suspended pending the outcome of a criminal investigation of UKT employees relating to the power sales that are at issue in the administrative proceedings. However, the criminal investigation was terminated recently, and the Antimonopoly Agency thereafter resumed the administrative proceedings. If the Antimonopoly Agency prevails in the administrative proceedings, UKT may be ordered to pay the administrative fine and disgorge the profits from the sales at issue, estimated by the Antimonopoly Agency to be approximately 514 million KZT ($4 million). UKT believes it has meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In November 2007, the International Brotherhood of Electrical Workers, Local Union No. 1395, and sixteen individual retirees, (the “Complainants”), filed a complaint at the Indiana Utility Regulatory Commission (“IURC”) seeking enforcement of their interpretation of the 1995 final order and associated settlement agreement resolving IPL’s basic rate case. The Complainants requested that the IURC conduct an investigation of IPL’s failure to fund the Voluntary Employee Beneficiary Association Trust (“VEBA Trust”) at a level of approximately $19 million per year. The VEBA Trust was spun off to an independent trustee in 2001. The complaint sought an IURC order requiring IPL to make contributions to place the VEBA Trust in the financial position in which it allegedly would have been had IPL not ceased making annual contributions to the VEBA Trust after its spin off. The complaint also sought an IURC order requiring IPL to resume making annual

contributions to the VEBA Trust. IPL filed a motion to dismiss and both parties sought summary judgment in the IURC proceeding. In May 2009, the IURC granted summary judgment in favor of IPL and in June 2009, the Complainants filed an appeal of the IURC’s May 2009 order with the Indiana Court of Appeals. On January 29, 2010, the appellate court affirmed the IURC’s determination and in April 2010 a petition for reconsideration was denied. In May 2010, the Complainants appealed to the Indiana Supreme Court. IPL believes it has meritorious defenses to the Complainants’ claims and it will continue to assert them vigorously in all proceedings; however, there can be no assurances that it will be successful in its efforts.

In December 2007, an arbitral tribunal terminated ESSA’s gas supply contracts with members of the Sierra Chata Consortium in light of the restrictions that had been placed on the export of gas by the Argentine Republic. ESSA thereafter terminated its gas transportation contract with Transportadora de Gas del Norte S.A. (“TGN”), and initiated arbitration seeking relief from the obligation to pay the firm tariff under, or in the alternative terminate, ESSA’s gas transportation contracts with Gasoducto GasAndes (Argentina) S.A. (“GasAndes Argentina”) and Gasoducto GasAndes S.A. (“GasAndes Chile”). TGN (which later filed a lawsuit against ESSA in Argentina), GasAndes Argentina, and GasAndes Chile dispute that the restrictions on the export of gas justify the adjustment or termination of the respective gas transportation contracts and seek due tariff payments. If ESSA fails to prevail in the dispute resolution proceedings, the Company will need to assess whether a triggering event has occurred, in which case the Company may have to record an impairment of certain of its assets, which could be material but cannot yet be quantified. In addition, if ESSA does not prevail in the ongoing lawsuit with TGN, ESSA may be required to pay certain charges imposed by the Argentine Republic relating to gas supply infrastructure, which is the subject of ongoing administrative proceedings with the Argentine Republic.

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska, filed a complaint in the U.S. District Court for the Northern District of California against the Company and numerous unrelated companies, claiming that the defendants’ alleged GHG emissions have contributed to alleged global warming which, in turn, allegedly has led to the erosion of the plaintiffs’ alleged land. The plaintiffs assert nuisance and concert of action claims against the Company and the other defendants, and a conspiracy claim against a subset of the other defendants. The plaintiffs seek to recover relocation costs, indicated in the complaint to be from $95 million to $400 million, and other unspecified damages from the defendants. The Company filed a motion to dismiss the case, which the District Court granted in October 2009. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit. The parties are briefing the appeal. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

A public civil action has been asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of Sao Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$817,000 ($456,000), or pay an indemnification amount of approximately R$9.35 million ($5 million). Eletropaulo has appealed this decision to the Supreme Court and is awaiting a decision.

In 2007, a lower court issued a decision related to a 1993 claim that was filed by the Public Attorney’s office against Eletropaulo, the São Paulo State Government, SABESP (a state owned company), CETESB (a state owned company) and DAEE (the municipal Water and Electric Energy Department), alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from Pinheiros River into Billings Reservoir. The events in question occurred while Eletropaulo was a state owned company. An initial lower court decision in 2007 found the parties liable for the payment of approximately R$583 million ($325 million) for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo which reversed the lower court decision. The Public Attorney’s Office has filed appeals to both Superior Court of Justice (“SCJ”) and the Supreme Court (“SC”) and such appeals were answered by Eletropaulo in the fourth

quarter of 2009. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In November 2007, the U.S. Department of Justice (“DOJ”) notified AES Thames, LLC (“AES Thames”) that the EPA had requested that the DOJ file a federal court action against AES Thames for alleged violations of the CAA, the CWA, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and the Emergency Planning and Community Right-to-Know Act (“EPCRA”), in particular alleging that AES Thames had violated (i) the terms of its Prevention of Significant Deterioration (“PSD”) air permits in the calculation of its steam load permit limit; and (ii) the CWA, CERCLA and EPCRA in connection with two spills of chlorinating agents that occurred in 2006. The DOJ subsequently indicated that it would like to settle this matter prior to filing a suit and a consent decree has been finalized. During settlement negotiations, the DOJ and EPA agreed that a minor modification to AES Thames’ PSD permit would be acceptable to clarify AES Thames’ method of operation and the Connecticut Department of Environmental Protection issued the modified permit in April 2009. A Consent Decree, pursuant to which AES Thames will pay a $140,000 civil penalty and implement a training program designed to minimize the potential for future spills of chlorinating agents was lodged with the federal district court in Connecticut on February 26, 2010. The period for public comments on the Consent Decree expired in June of 2010, and the Consent Decree was signed by the Court and became effective on July 29, 2010.

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

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

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

In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Esado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF

seeks an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserts that if it is determined that AESU is responsible for the termination of the GSA, AESU is liable for TGM’s alleged losses, including losses under the TA. The procedural schedules for the arbitrations have not been established to date. AESU believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously; however, there can be no assurances that it will be successful in its efforts.

In June 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals that the environmental permit for Empresa Electrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant has stopped as a consequence of the Supreme Court’s decision. In September 2009, the Municipality of Puchuncaví issued an order to demolish the Plant on the basis of other permitting issues. In October 2009, EEC and AES Gener filed a judicial claim against the Municipality of Puchuncaví before the Civil Judge of the City of Quintero, seeking to revoke the demolition order and asking for an immediate stay of said order. At the request of EEC and AES Gener, the Civil Judge of Quintero agreed to suspend the demolition order until a final decision on the order is issued. In December 2009, Chilean authorities approved new land use regulations that entitled EEC to apply for a new environmental permit. The new land use regulations were challenged by local groups but this challenge was declared inadmissible by the Court of Appeals of Santiago. Local groups filed a motion to reconsider this decision in the same Court but this motion was dismissed. EEC applied for a new environmental permit on January 14, 2010 and permit approval was granted by the Environmental Authority on February 26, 2010. On March 24, 2010 the Mayor of Puchuncaví and another third party (collectively, “Municipality”) challenged the new environmental permit before the Court of Appeals in Valparaiso. At the parties’ request, the Court of Appeals suspended the proceedings on the new environmental permit to allow the parties to attempt to settle the challenge. On July 20, 2010, the Council of the Municipality approved a settlement agreement between EEC and the Municipality requiring the Municipality to withdraw its challenge to the new environmental permit. Subsequent to the Council’s approval, EEC and the Municipality executed the settlement agreement on July 26, 2010. Pursuant to the settlement agreement, the Municipality filed a petition with the Court of Appeals to withdraw the challenge to the new environmental permit, which petition was approved by the Court on July 27, 2010. Certain residents of the Municipality subsequently filed a petition with the Court of Appeals to reopen the proceedings on the new environmental permit, but that petition was denied by the Court of Appeals on August 2, 2010. In addition, EEC has requested that the Municipality issue the construction permits that are required to resume construction of the Plant. If the construction permits are issued, EEC intends to instruct the construction contractor to resume construction of the Plant. EEC and the construction contractor have agreed on a path forward while construction is suspended and once construction is reinitiated. However, if EEC is unable to complete the project, AES may be required to record an impairment of the Campiche project proportional to its indirect ownership, which could have a material impact on earnings in the period in which it is recorded. Based on cash investments through June 30, 2010 and potential termination costs, AES could incur an impairment of approximately $188 million. In the event an impairment charge is recognized with regard to the project, the amount of such impairment will depend on a number of factors, including EEC’s ability to recover project costs.

In June 2009, the Inter-American Commission on Human Rights of the Organization of American States (“IACHR”) requested that the Republic of Panama suspend the construction of AES Changuinola S.A.’s hydroelectric project (“Project”) until the bodies of the Inter-American human rights system can issue a final decision on a petition (286/08) claiming that the construction violates the human rights of alleged indigenous communities. In July 2009, Panama responded by informing the IACHR that it would not suspend construction of the Project and requesting that the IACHR revoke its request. In June 2010, the Inter-American Court of Human Rights vacated the IACHR’s request. With respect to the merits of the underlying petition, the IACHR heard arguments by the communities and Panama in November 2009, but has not issued a decision to date. The Company cannot predict Panama’s response to any determination on the merits of the petition by the bodies of the Inter-American human rights system.

In July 2009, AES Energía Cartagena S.R.L. (“AES Cartagena”) received notices from the Spanish national energy regulator, Comisión Nacional de Energía (“CNE”), stating that the proceeds of the sale of electricity from AES Cartagena’s plant should be reduced by roughly the value of the free CO₂ allowances granted to AES Cartagena for 2007, 2008, and the first half of 2009. In particular, the notices stated that CNE intended to invoice AES Cartagena to recover that value, which CNE calculated as approximately €20 million ($24 million) for 2007-2008 and an amount to be determined for the first half of 2009. In September 2009, AES Cartagena received invoices for €523,548 (approximately $639,000) for 2007 and €19,907,248 (approximately $24 million) for 2008. In October 2009, AES Cartagena filed an administrative appeal against both such invoices with the Spanish Ministry of Industry and also applied for a stay of its obligation to pay the invoices pending the hearing of that appeal. In November 2009, the appeal was unsuccessful and the application for stay was rejected. AES Cartagena subsequently paid the sums claimed by CNE and filed an appeal with the Spanish Court. There can be no assurances that the judicial appeal will be successful. In addition, in July 2010, AES Cartagena received an invoice for approximately €5.5 million ($7 million) for the free allowances relating to the first half of 2009. AES Cartagena intends to challenge that invoice. AES Cartagena has demanded indemnification from GDF-Suez in relation to the CNE invoices and any future such invoices under the long-term energy agreement (the “Energy Agreement”) with GDF-Suez. However, GDF-Suez has disputed that it is responsible for the CNE invoices under the Energy Agreement. Therefore, in September 2009, AES Cartagena initiated arbitration against GDF-Suez, seeking to recover the payments made to CNE. In the arbitration AES Cartagena also seeks a determination that GDF-Suez is responsible for procuring and bearing the cost of CO₂ allowances that are required to offset the emissions of AES Cartagena’s power plant, which is also in dispute between the parties. If AES Cartagena does not prevail in the arbitration and is required to bear the cost of carbon compliance, its results of operations could be materially adversely affected and, in turn, there could be a material adverse effect on the Company and its results of operations. AES Cartagena believes it has meritorious claims and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 2009, the Public Defender’s Office of the State of Rio Grande do Sul (“PDO”) filed a class action against AES Sul in the 16th District Court of Porto Alegre, Rio Grande do Sul (“District Court”), claiming that AES Sul has been illegally passing PIS and COFINS taxes (taxes based on AES Sul’s income) to consumers. According to ANEEL’s Order No. 93/05, the federal laws of Brazil, and the Brazilian Constitution, energy companies such as AES Sul are entitled to highlight PIS and COFINS taxes in power bills to final consumers, as the cost of those taxes is included in the energy tariffs that are applicable to final consumers. Before AES Sul had been served with the action, the District Court dismissed the lawsuit in October 2009 on the ground that AES Sul had been properly highlighting PIS and COFINS taxes in consumer bills in accordance with Brazilian law. In April 2010, the PDO appealed to the Appellate Court of the State of Rio Grande do Sul. If the dismissal is reversed and AES Sul does not prevail in the lawsuit and is ordered to cease recovering PIS and COFINS taxes pursuant to its energy tariff, its potential prospective losses could be approximately R$9.6 million ($5 million) per month, as estimated by AES Sul. In addition, if AES Sul is ordered to reimburse consumers, its potential retrospective liability could be approximately R$1.2 billion ($670 million), as estimated by AES Sul. AES Sul believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings if it is served with the action; however, there can be no assurances that it would be successful in its efforts. Furthermore, if AES Sul does not prevail in the litigation it will seek to adjust its energy tariff to compensate it for its losses, but there can be no assurances that it would be successful in obtaining an adjusted energy tariff.

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

have a material impact to IPL. IPL would seek recovery through customer rates of any operating or capital expenditures related to pollution control technology systems to reduce regulated emissions; however, there can be no assurances that it would be successful in that regard.

In November 2009 and April 2010, substantially similar personal injury lawsuits were filed by a total of 22 residents and estates of the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In both lawsuits the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic in October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs do not quantify their alleged damages, but generally allege that they are entitled to compensatory and punitive damages. The AES defendants have moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. The AES defendants believe they have meritorious defenses to the claims asserted against them and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.

In May 2010, Lakefield Wind Project, LLC initiated arbitration against IPL, alleging that IPL had wrongfully terminated a PPA executed in June 2009, and seeking approximately $190 million in damages. Previously, in January 2010, the Indiana Utility Regulatory Commission had approved IPL’s petition for recovery of costs associated with this PPA, via a cost recovery mechanism similar to IPL’s fuel adjustment charge mechanism. However, the approval included certain limitations, restrictions, and/or conditions which IPL did not find acceptable and, therefore, it exercised its right to terminate the PPA. IPL and Lakefield subsequently agreed to settle their dispute. Pursuant to the settlement IPL rescinded its termination of the PPA and both parties agreed to keep the original PPA intact. The project is subject to approval by the Minnesota Public Utilities Commission.

9. PENSION PLANS

Total pension cost for the three and six months ended June 30, 2010 and 2009 included the following components:


	Three Months Ended June 30,												Six Months Ended June 30,
	2010						2009						2010						2009
	U.S.			Foreign			U.S.			Foreign			U.S.			Foreign			U.S.			Foreign
	(in millions)												(in millions)
Service cost	$	2		$	4		$	2		$	3		$	4		$	9		$	4		$	6
Interest cost		9			126			9			111			17			251			17			211
Expected return on plan assets		(8	)		(105	)		(6	)		(90	)		(16	)		(210	)		(13	)		(171	)
Amortization of initial net asset		-			-			-			-			-			-			-			(1	)
Amortization of prior service cost		1			-			1			-			2			-			2			-
Amortization of net loss		3			4			4			2			6			7			8			3

Total pension cost	$	7		$	29		$	10		$	26		$	13		$	57		$	18		$	48

Total employer contributions for the six months ended June 30, 2010 for the Company’s U.S. and foreign subsidiaries were $11 million and $74 million, respectively. The expected remaining scheduled annual employer contributions for 2010 are $18 million for U.S. subsidiaries and $77 million for foreign subsidiaries.

10. EQUITY

STOCK PURCHASE AGREEMENT

On March 15, 2010, the Company completed the sale of 125,468,788 shares of common stock to Terrific Investment Corporation (“Investor”), a wholly-owned subsidiary of China Investment Corporation. The shares

were sold for $12.60 per share, for an aggregate purchase price of $1.58 billion. Investor’s ownership in the Company’s common stock is now approximately 15% percent of the Company’s total outstanding shares of common stock on a fully diluted basis.

On March 12, 2010, the Company and Investor entered into a stockholder agreement (the “Stockholder Agreement”). Under the Stockholder Agreement, as long as Investor holds more than 5% of the outstanding shares of common stock of the Company, Investor will have the right to designate one nominee, who must be reasonably acceptable to the Board, for election to the Board of Directors of the Company. As of August 5, 2010, Investor has not designated its nominee for election to the Board of Directors of the Company. In addition, until such time as Investor holds 5% or less of the outstanding shares of common stock, Investor has agreed to vote its shares in accordance with the recommendation of the Company on any matters submitted to a vote of the stockholders of the Company relating to the election of directors and compensation matters. Otherwise, Investor may vote its shares in its discretion. Further, under the Stockholder Agreement, Investor will be subject to a standstill restriction which generally prohibits Investor from purchasing additional securities of the Company beyond the level acquired by it under the stock purchase agreement entered into between Investor and the Company on November 6, 2009. In addition, Investor has agreed to a lock-up restriction such that Investor would not sell its shares for a period of 12 months following the closing, subject to certain exceptions. The standstill and lock-up restrictions also terminate at such time as Investor holds 5% or less of the outstanding shares of common stock. Investor will have certain registration rights and preemptive rights under the Stockholder Agreement with respect to its shares of common stock of the Company.

COMPREHENSIVE INCOME

The components of comprehensive income (loss) for the three and six months ended June 30, 2010 and 2009 were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in millions)
Net income	$	429		$	531		$	831		$	1,032
Change in fair value of available-for-sale securities, net of income tax (expense) benefit of $1, $0, $4 and $0, respectively		(2	)		-			(6	)		-
Foreign currency translation adjustments, net of income tax (expense) benefit of $3, $(65), $7 and $(66), respectively		408			402			234			333
Derivative activity:
Reclassification to earnings, net of income tax (expense) benefit of $(8), $15, $(19) and $26, respectively		36			(37	)		68			(43	)
Change in derivative fair value, net of income tax (expense) benefit of $45, $(29), $58 and $(69), respectively		(171	)		86			(237	)		186

Total change in fair value of derivatives		(135	)		49			(169	)		143
Change in unfunded pension obligation, net of income tax (expense) benefit of $(1), $(1), $(2) and $(1), respectively		3			1			5			2

Other comprehensive income		274			452			64			478

Comprehensive income		703			983			895			1,510
Less: Comprehensive income attributable to noncontrolling interests⁽¹⁾		(280	)		(518	)		(404	)		(818	)

Comprehensive income attributable to The AES Corporation	$	423		$	465		$	491		$	692

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

The components of accumulated other comprehensive loss as of June 30, 2010 and December 31, 2009 were as follows:


	June 30, 2010		December 31, 2009
	(in millions)
Foreign currency translation adjustment	$	2,010	$	2,312
Unrealized derivative losses		401		224
Unfunded pension obligation		191		194
Securities available-for-sale		-		(6	)

Accumulated other comprehensive loss	$	2,602	$	2,724

11. SEGMENTS

The management reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally. During the second quarter of 2010, the Company modified its internal reporting structure to move the management of the Company’s generation business in Jordan, Amman East, from Asia to Europe. Accordingly, Amman East is now reported within the Europe — Generation segment. All prior periods have been retrospectively restated to reflect this change and conform to current period presentation. The Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and concluded it has the following six reportable segments:

•

Latin America — Generation;

•

Latin America — Utilities;

•

North America — Generation;

•

North America — Utilities;

•

Europe — Generation;

•

Asia — Generation.

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

The Company uses Adjusted Gross Margin, a non-GAAP measure, to evaluate the performance of its segments. Adjusted Gross Margin is defined by the Company as: Gross Margin plus depreciation and amortization less general and administrative expenses. In the 2009 Form 10-K, the Company changed the segment performance measures disclosed to align with how management internally reviews the results and assesses the performance of the businesses. Accordingly, previously reported segment information has been revised to reflect our new measure of segment performance, Adjusted Gross Margin, to conform to current year presentation.

Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No inter-segment revenue relationships exist between other segments. Corporate allocations include certain management fees and self insurance activities which are reflected within segment Adjusted Gross Margin. All intra-segment activity has been eliminated with respect to revenue and Adjusted Gross Margin within the segment. Inter-segment activity has been eliminated within the total consolidated results. All balance sheet information for businesses that were discontinued or classified as held for sale as of June 30, 2010 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.

Information about the Company’s operations by segment for the three and six months ended June 30, 2010 and 2009 was as follows:


	Total Revenue					Intersegment						External Revenue
Three Months Ended June 30,	2010			2009		2010			2009			2010		2009
	(in millions)
Latin America — Generation	$	1,084		$	894	$	(256	)	$	(202	)	$	828	$	692
Latin America — Utilities		1,770			1,364		-			-			1,770		1,364
North America — Generation		455			475		-			-			455		475
North America — Utilities		275			261		-			-			275		261
Europe Generation		271			173		-			1			271		174
Asia — Generation		179			112		-			-			179		112
Corp/Other & eliminations		(13	)		12		256			201			243		213

Total Revenue	$	4,021		$	3,291	$	-		$	-		$	4,021	$	3,291


	Total Revenue					Intersegment						External Revenue
Six Months Ended June 30,	2010			2009		2010			2009			2010		2009
	(in millions)
Latin America — Generation	$	2,067		$	1,786	$	(511	)	$	(386	)	$	1,556	$	1,400
Latin America — Utilities		3,535			2,576		-			-			3,535		2,576
North America — Generation		987			977		-			-			987		977
North America — Utilities		563			551		-			-			563		551
Europe Generation		604			403		-			1			604		404
Asia — Generation		355			190		-			-			355		190
Corp/Other & eliminations		(19	)		43		511			385			492		428

Total Revenue	$	8,092		$	6,526	$	-		$	-		$	8,092	$	6,526


	Total Adjusted Gross Margin					Intersegment						External Adjusted Gross Margin
Three Months Ended June 30,	2010			2009		2010			2009			2010			2009
	(in millions)
Latin America — Generation	$	466		$	375	$	(253	)	$	(199	)	$	213		$	176
Latin America — Utilities		320			228		256			202			576			430
North America — Generation		121			162		3			3			124			165
North America — Utilities		93			88		1			1			94			89
Europe Generation		84			39		2			1			86			40
Asia — Generation		84			31		1			1			85			32
Corp/Other & eliminations		(3	)		28		(10	)		(9	)		(13	)		19
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization													(284	)		(235	)
Interest expense													(394	)		(368	)
Interest income													101			89
Other expense													(48	)		(30	)
Other income													69			22
Gain on sale of investments													-			102
Asset impairment expense													(1	)		(1	)
Foreign currency transaction gains (losses) on net monetary position													(71	)		28
Other non-operating expense													(5	)		-

Income from continuing operations before taxes and equity in earnings of affiliates												$	532		$	558


	Total Adjusted Gross Margin				Intersegment						External Adjusted Gross Margin
Six Months Ended June 30,	2010		2009		2010			2009			2010			2009
	(in millions)
Latin America — Generation	$	860	$	788	$	(504	)	$	(379	)	$	356		$	409
Latin America — Utilities		619		449		511			386			1,130			835
North America — Generation		301		330		7			7			308			337
North America — Utilities		206		198		1			2			207			200
Europe Generation		202		120		3			2			205			122
Asia — Generation		153		41		2			2			155			43
Corp/Other & eliminations		7		19		(20	)		(20	)		(13	)		(1	)
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization												(561	)		(463	)
Interest expense												(780	)		(740	)
Interest income												210			182
Other expense												(60	)		(52	)
Other income												77			243
Gain on sale of investments												-			115
Asset impairment expense												(1	)		(1	)
Foreign currency transaction gains (losses) on net monetary position												(122	)		(11	)
Other non-operating expense												(5	)		(10	)

Income from continuing operations before taxes and equity in earnings of affiliates											$	1,106		$	1,208

Assets by segment as of June 30, 2010 and December 31, 2009 were as follows:


	Total Assets
	June 30, 2010		December 31, 2009
	(in millions)
Assets
Latin America — Generation	$	9,857	$	9,802
Latin America — Utilities		9,206		9,233
North America — Generation		6,190		6,226
North America — Utilities		3,070		3,035
Europe Generation		3,646		3,184
Asia — Generation		1,689		1,594
Discontinued businesses		961		1,196
Corp/Other & eliminations		6,082		5,265

Total Assets	$	40,701	$	39,535

12. OTHER INCOME (EXPENSE)

The components of other income for the three and six months ended June 30, 2010 and 2009 were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(in millions)
Tax credit settlement	$	-	$	-	$	-	$	129
Performance incentive fee		-		-		-		80
Extinguishment of liability		62		-		62		-
Other		7		22		15		34

Total other income	$	69	$	22	$	77	$	243

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

Other income of $69 million for the three months ended June 30, 2010 was primarily related to the extinguishment of a swap liability owed by two of our Brazilian subsidiaries, resulting in the recognition of a $62 million gain. The net impact to the Company after taxes and non-controlling interest was $9 million. Other income of $22 million for the three months ended June 30, 2009 included a gain on early extinguishment of debt at Itabo in the Dominican Republic, a reversal of a legal reserve at Sonel in Cameroon and insurance recoveries related to turbine damage at one of our Brazilian subsidiaries.

Other income of $77 million for the six months ended June 30, 2010 was primarily related to the extinguishment of the swap liability described above. Other income of $243 million for the six months ended June 30, 2009 included a favorable court decision on a legal dispute in which Eletropaulo, the Company’s utility business in Brazil, had requested reimbursement for excess non-income taxes paid from 1989 to 1992. Eletropaulo received reimbursement in the form of tax credits to be applied against future tax liabilities resulting in a $129 million gain. The net impact to the Company after noncontrolling interests was $21 million. In addition, the Company recognized income of $80 million from a performance incentive bonus for management services provided to Ekibastuz and Maikuben in 2008. The management agreement was related to the sale of these businesses in Kazakhstan in May 2008.

The components of other expense for the three and six months ended June 30, 2010 and 2009 were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(in millions)
AES Wind transaction costs	$	22	$	-	$	22	$	-
Loss on sale and disposal of assets		12		9		19		14
Legal/dispute settlement		2		1		4		10
Other		12		20		15		28

Total other expense	$	48	$	30	$	60	$	52

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

Other expense of $48 million for the three months ended June 30, 2010 was primarily comprised of the write-off of previously capitalized transaction costs of $22 million that were incurred in connection with the preparation for the sale of a noncontrolling interest in our Wind Generation business. The costs were written off upon the expiration of the letter of intent (“LOI”) with China Investment Corporation (“CIC”) on June 30, 2010. AES and CIC mutually agreed to allow the LOI to expire at this time. Other expense also included a loss of $9 million on debt extinguishment at the Parent Company from the retirement of senior notes and a loss on disposal of assets at Eletropaulo and Gener. Other expense of $30 million for the three months ended June 30, 2009 included a $13 million loss recognized when three of our businesses in the Dominican Republic received $110 million par value bonds issued by the Dominican Republic government to settle existing accounts receivable for the same amount from the government-owned distribution companies. The loss represented an adjustment to reflect the fair value of the bonds on the date received. Other expense also included losses on disposal of assets at Eletropaulo.

Other expense of $60 million for the six months ended June 30, 2010 included the previously capitalized transaction costs discussed above, a loss on debt extinguishment at the Parent Company described above and a loss on disposal of assets at Eletropaulo and Gener. Other expense of $52 million for the six months ended June 30, 2009 primarily consisted of the previously mentioned $13 million fair value adjustment to government issued bonds in the Dominican Republic on the date received and losses on disposal of assets at Eletropaulo and Andres.

13. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

On June 11, 2010, the Company completed the sale of its 55% ownership in Lal Pir and Pak Gen, two oil-fired facilities in Pakistan with respective generation capacities of 362 MW and 365 MW. Total consideration received in the transaction was approximately $117 million, of which $65 million was AES’ portion. The Company recognized a loss on disposal and impairment losses totaling $9 million and $22 million ($3 million and $10 million, net of tax and noncontrolling interests) during the three and six months ended June 30, 2010, respectively, to reflect the change in the carrying value of net assets of Lal Pir and Pak Gen subsequent to meeting the held for sale criteria as of December 31, 2009.

In December 2009, the Company entered into an agreement to sell its 35% ownership interest in Barka, a 456 MW combined cycle gas facility and water desalination plant and its 100% ownership interest in two Barka related service companies, located in Oman, Jordan for approximately $129 million. The sale of Barka is subject to customary approvals and is expected to close during the third quarter of 2010.

In April 2010, the Company entered into an agreement to sell its 55% equity interest in Ras Laffan and the associated operations company in Qatar for approximately $190 million, subject to customary purchase price

adjustments. The transaction is subject to customary approvals and is expected to close during the second half of 2010. The Ras Laffan facility is comprised of a 756 MW combined cycle gas plant and a 40 million imperial gallons per day water desalination facility.

The following table summarizes the revenue, income from operations of discontinued businesses, income tax expense and impairment of discontinued operations for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,					Six Months Ended June 30,
	2010			2009		2010			2009
	(in millions)
Revenue	$	199		$	204	$	425		$	347

Income from operations of discontinued businesses	$	28		$	28	$	52		$	47
Income tax expense		(1	)		-		(2	)		(1	)

Income from operations of discontinued businesses, net of tax	$	27		$	28	$	50		$	46

Loss on disposal and impairment of discontinued operations	$	(9	)	$	-	$	(22	)	$	-

14. EARNINGS PER SHARE

Basic and diluted earnings per share are based on the weighted average number of shares of common stock and potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units, stock options and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.

The following tables present a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation for income from continuing operations for the three and six months ended June 30, 2010 and 2009. In the table below, income represents the numerator and weighted-average shares represent the denominator:


	Three Months Ended June 30,
	2010					2009
	Income		Shares	$ per Share		Income		Shares	$ per Share
	(in millions except per share data)
BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders	$	134	795	$	0.17	$	286	667	$	0.43
EFFECT OF DILUTIVE SECURITIES
Convertible securities		-	-		-		6	15		-
Stock options		-	2		-		-	1		-
Restricted stock units		-	3		-		-	1		-

DILUTED EARNINGS PER SHARE	$	134	800	$	0.17	$	292	684	$	0.43


	Six Months Ended June 30,
	2010					2009
	Income		Shares	$ per Share		Income		Shares	$ per Share
	(in millions except per share data)
BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders	$	315	746	$	0.42	$	494	666	$	0.74
EFFECT OF DILUTIVE SECURITIES
Stock options		-	2		-		-	1		-
Restricted stock units		-	3		-		-	1		-

DILUTED EARNINGS PER SHARE	$	315	751	$	0.42	$	494	668	$	0.74

There were approximately 17,080,471 and 20,169,060 additional options outstanding at June 30, 2010 and 2009, respectively, that could potentially dilute basic earnings per share in the future. Those options were not included in the computation of diluted earnings per share because the exercise price exceeded the average market price during the related periods. For the three months ended June 30, 2010 all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. During the three months ended June 30, 2010, 27,095 shares of common stock were issued upon the exercise of stock options. For the six months ended June 30, 2010 and 2009, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. During the six months ended June 30, 2010, 1,175,236 shares of common stock were issued under the Company’s profit sharing plan and 111,717 shares of common stock were issued upon the exercise of stock options.

In addition, on March 15, 2010, the Company issued 125,468,788 shares of common stock to Investor as described in Note 10 — Equity.

15. SUBSEQUENT EVENTS

On July 2, 2010, the Company announced that it has entered into an agreement with BG Energy Holdings to acquire 100% of Premier Power Limited (“PPL”), owner of the 1,246 MW natural gas-fired Ballylumford Power Station (“Ballylumford”) in County Antrim, Northern Ireland for £99 million (approximately $150 million). The transaction is subject to license consents from the Northern Ireland Authority for Utility Regulation and the Northern Ireland Department of Enterprise, Trade and Industry, and is expected to close in the second half of 2010. The majority of Ballylumford’s output is contracted to Northern Ireland Electricity and the affiliated agreements allow for a pass-through of fuel costs. Upon obtaining required consents, AES Ballylumford Holdings Limited will acquire PPL through an all cash transaction and the final purchase price will incorporate working capital adjustments. Ballylumford will be reported within the Europe Generation segment.

On July 7, 2010, the Company announced that the Board of Directors approved a stock repurchase program under which the Company may repurchase up to $500 million of common stock. The Board authorization permits the Company to repurchase stock from time to time until December 31, 2010 through a variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no assurance as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time.

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 is increased to $800 million;

•

the final maturity date of the revolving credit loan facility is 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.

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

In this Quarterly Report on Form 10-Q (“Form 10-Q”), the terms “AES,” “the Company,” “us,” or “we” refer to the consolidated entity and all of its subsidiaries and affiliates, collectively. The term “The AES Corporation” or “the Parent Company” refers only to the parent, publicly-held holding company, The AES Corporation, excluding its subsidiaries and affiliates.

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

FORWARD-LOOKING INFORMATION

The following discussion may contain forward-looking statements regarding us, our business, prospects and our results of operations that are subject to certain risks and uncertainties posed by many factors and events that could cause our actual business, prospects and results of operations to differ materially from those that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those described in Item 1A. — Risk Factors of our 2009 Form 10-K filed on February 25, 2010. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We undertake no obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise of the risks and factors that may affect our business.

Overview of Our Business

We are a global power company. We operate two primary lines of business. The first is our Generation business, where we own and/or operate power plants to generate and sell power to wholesale customers such as utilities, other intermediaries and certain end-users. The second is our Utilities business, where we own and/or operate utilities to distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. For the six months ended June 30, 2010 our Generation and Utilities businesses comprised approximately 45% and 55% of our consolidated revenue, respectively.

We are also continuing to expand our wind generation business and are pursuing additional opportunities in the renewable business including solar and climate solutions, which develops and invests in projects that generate greenhouse gas offsets and/or other renewable projects. These initiatives are not material contributors to our operating results, but we believe that certain of these initiatives may become material in the future. For additional information regarding our business, see Item 1. — Business of the 2009 Form 10-K.

Our Organization and Segments. The management reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The financial reporting segment structure uses the Company’s management reporting structure as its foundation and reflects how the Company manages the business internally. The Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and concluded that it has the following six reportable segments:

•

Latin America — Generation;

•

Latin America — Utilities;

•

North America — Generation;

•

North America — Utilities;

•

Europe — Generation;

•

Asia — Generation.

During the second quarter of 2010, the Company modified its internal reporting structure to move the management of the Company’s generation business in Jordan, Amman East, from Asia to Europe. Accordingly, Amman East is now reported within the Europe — Generation segment. All prior periods have been retrospectively restated to reflect this change and conform to current period presentation.

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

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

One of the key factors which affect our Generation business is our ability to enter into contracts for the sale of electricity and the purchase of fuel used to produce that electricity. Long-term contracts are intended to reduce the exposure to volatility associated with fuel prices in the market and the price of electricity by fixing the revenue and costs for these businesses. The majority of the electricity produced by our Generation businesses is sold under long-term contracts, or PPAs, to wholesale customers. In turn, most of these businesses enter into long-term fuel supply contracts or fuel tolling arrangements where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. While these long-term contractual agreements reduce exposure to volatility in the market price for electricity and fuel, the predictability of operating results and cash flows vary by business based on the extent to which a facility’s generation capacity and fuel requirements are contracted and the negotiated terms of these agreements. Entering into these contracts exposes us to counterparty credit risk. For further discussion of these risks, see “Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks.” in Item 1A. — Risk Factors of the 2009 Form 10-K.

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

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

We also attempt to limit risk by hedging much of our interest rate and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the underlying business. However, we only hedge a portion of our currency and commodity risks, and our businesses are still subject to these risks, as further described in Item 1A. — Risk Factors of the 2009 Form 10-K, “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.” Commodity and power price volatility could continue to impact our financial metrics to the extent this volatility is not hedged. For a discussion of our sensitivities to commodity, currency and interest rate risk, see Item 3. — Quantitative and Qualitative Disclosures About Market Risk in this Form 10-Q.

Due to our global presence, the Company has significant exposure to foreign currency fluctuations. The exposure is primarily associated with the impact of the translation of our foreign subsidiaries’ operating results from their local currency to U.S. dollars that is required for the preparation of our consolidated financial statements. Additionally, there is a risk of transaction exposure when an entity enters into transactions, including debt agreements, in currencies other than their functional currency. These risks are further described in Item 1A. — Risk Factors of the 2009 Form 10-K, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.” In the three and six months ended June 30, 2010, changes in foreign currency exchange rates have had a significant impact on our operating results. If the current foreign currency exchange rate volatility continues, our gross margin and other financial metrics could be affected.

Another key driver of our results is our ability to bring new businesses into commercial operations successfully. We currently have approximately 1,600 MW of projects under construction in six countries. Our prospects for increases in operating results and cash flows are dependent upon successful completion of these projects on time and within budget. However, as disclosed in Item 1A. — Risk Factors of the 2009 Form 10-K, “Our business is subject to substantial development uncertainties,” construction is subject to a number of risks, including risks associated with site identification, financing and permitting and our ability to meet construction deadlines. Delays or the inability to complete projects and commence commercial operations can result in increased costs, impairment of assets and other challenges involving partners and counterparties to our construction agreements, PPAs and other agreements.

Our gross margin is also impacted by the fact that in each country in which we conduct business, we are subject to extensive and complex governmental regulations, such as regulations governing the generation and distribution of electricity, and environmental regulations which affect most aspects of our business. Regulations differ on a country by country basis (and even at the state and local municipality levels) and are based upon the type of business we operate in a particular country, and affect many aspects of our operations and development projects. Our ability to negotiate tariffs, enter into long-term contracts, pass through costs related to capital expenditures and otherwise navigate these regulations can have an impact on our revenue, costs and gross margin. Environmental and land use regulations, including existing and proposed regulation of greenhouse gas (“GHG”) emissions, could substantially increase our capital expenditures or other compliance costs, which could in turn have a material adverse affect on our business and results of operations. For a further discussion of the Regulatory Environment, see Note 8 — Contingencies and Commitments — Environmental, included in Item 1. — Financial Statements of this Form 10-Q and Item 1. — Business — Regulatory Matters — Environmental and Land Use Regulations and Item 1A. — Risk Factors — Risks Associated with Government Regulation and Laws of the 2009 Form 10-K.

Key Drivers of Results in the Three Months Ended June 30, 2010

During the three months ended June 30, 2010, the Company’s gross margin and net cash from operating activities increased $179 million and $210 million, respectively, while net income attributable to The AES Corporation decreased $159 million compared to the same period in 2009.

We achieved increased gross margin and cash flow from operations despite the fact that certain of our North American businesses continue to face challenges associated with relatively lower gas prices and a decline in power prices relative to coal. In particular, lower gas and power prices have affected the financial results of our coal-fired plants in New York, and we expect this trend to continue through the end of 2010. Despite these challenges, gross margin and net cash provided by operating activities increased due to the favorable impact of foreign currency translation, better operating performance at certain businesses and improved working capital management. In particular, the Company’s gross margin and net cash provided by operating activities benefited from the following:

•

the favorable impact of foreign currency translation gains on the gross margin of certain of our international operations, particularly in Brazil;

•

better operating performance at certain of our operations in Latin America and Asia; and

•

improved working capital management at our Latin America utilities businesses and our Asia generation businesses.

Certain of the Company’s Latin American utilities businesses experienced continued increases in market demand due to the local economic recovery in Latin America. Additionally, rates at our Latin American utilities businesses improved compared to the prior year as part of the annual tariff adjustment process. The Company’s Latin America generation businesses also contributed to improved gross margin due to higher volume and spot prices. The Company also continued to benefit from higher demand and favorable market conditions at Masinloc, our generation business in the Philippines. Masinloc’s higher availability enabled the Company to benefit from increased contract and spot market sales and favorable market prices in the Philippines. It is unclear if Masinloc’s favorable first half performance will continue for the remainder of 2010. Despite the increase in gross margin in the quarter, net income attributable to The AES Corporation decreased primarily from an increase in our effective tax rate, as further discussed below, and the absence of gains recognized in 2009 related to the sale of our Northern Kazakhstan businesses.

We expect to face continued challenges in 2010, including the trends in North America described above. In addition, the current tax rate is higher than our budgeted rate in 2010 and reported rates in 2008 and 2009, in part because certain anticipated favorable tax law changes have not been passed by Congress at this time. There can

be no assurance that Congress will extend these benefits. Management expects that improved operating performance at certain businesses and growth from new businesses launched in 2009 or expected to commence operation in 2010 may lessen or offset the impact of the challenges described above. However, if these favorable effects do not occur or if the challenges described above or elsewhere in this section impact us more than we currently anticipate, or if volatile foreign currencies move unfavorably, then these adverse factors (or other adverse factors unknown to us) may impact our gross margin, net income attributable to The AES Corporation and net cash provided by operating activities.

The following briefly describes the key changes in our reported revenue, gross margin, net income attributable to The AES Corporation, diluted earnings per share from continuing operations, Adjusted Earnings per Share (a non-GAAP measure) and net cash provided by operating activities for the three and six months ended June 30, 2010 compared to the three and six months ended June 30, 2009 and should be read in conjunction with our Consolidated Results of Operations discussion below.

Performance Highlights


	Three Months Ended June 30,						Six Months Ended June 30,
	2010		2009		% Change		2010		2009		% Change
	($’s in millions, except per share amounts)
Revenue	$	4,021	$	3,291	22	%	$	8,092	$	6,526	24	%
Gross Margin	$	982	$	803	22	%	$	1,968	$	1,652	19	%
Net Income Attributable to The AES Corporation	$	144	$	303	-52	%	$	331	$	521	-36	%
Diluted Earnings per Share from Continuing Operations	$	0.17	$	0.43	-60	%	$	0.42	$	0.74	-43	%
Adjusted Earnings Per Share (a non-GAAP measure)⁽¹⁾	$	0.23	$	0.24	-4	%	$	0.48	$	0.61	-21	%
Net Cash Provided by Operating Activities	$	747	$	537	39	%	$	1,416	$	874	62	%

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

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

Three months ended June 30, 2010:

Revenue increased $730 million, or 22%, to $4.0 billion in the three months ended June 30, 2010 compared with $3.3 billion in the three months ended June 30, 2009. Key drivers of the increase included:

•

the favorable impact of foreign currency translation of $225 million;

•

an increase in tariff rates and volume at our utilities businesses in Latin America;

•

the impact of the consolidation of Cartagena, in Spain, in accordance with the new consolidation accounting guidance which became effective January 1, 2010;

•

higher generation rates and volume at Masinloc in the Philippines; and

•

the favorable impact of rate and volume at our generation businesses in Latin America;

•

partially offset by the unfavorable impact of rates and a mark-to-market derivative adjustment on natural gas hedges in New York.

Gross margin increased $179 million, or 22%, to $1.0 billion in the three months ended June 30, 2010 compared with $803 million in the three months ended June 30, 2009. Key drivers of the increase included:

•

the favorable impact of foreign currency translation of $54 million;

•

an increase in tariff rates and volume at our utilities businesses in Latin America;

•

higher volume at our generation businesses in Latin America; and

•

higher generation rates and volume at Masinloc in the Philippines;

•

partially offset by the unfavorable impact of rates and a mark-to-market derivative adjustment on natural gas hedges in New York.

Net income attributable to The AES Corporation decreased $159 million, or 52%, to $144 million in the three months ended June 30, 2010 compared with $303 million in the three months ended June 30, 2009. Key drivers of the decrease included:

•

a decrease in gain on sale of investments due to the sale of our businesses in Northern Kazakhstan which occurred in 2009;

•

an increase in foreign currency transaction losses, primarily at The AES Corporation and Chile related to the devaluation of notes receivable and cash balances denominated in the Euro and a devaluation of working capital balances denominated in Chilean Pesos; and

•

an increase in income tax expense as a result of the expiration of a favorable U.S. tax provision; partially offset by

•

the favorable impact of the sale of our indirect investment in CEMIG through an increase in net equity in earnings of affiliates partially offset by an increase in consolidated income tax expense; and

•

an increase in gross margin for the quarter as described above.

Net cash provided by operating activities increased $210 million, or 39%, to $747 million in the three months ended June 30, 2010 compared with $537 million in the three months ended June 30, 2009. Key drivers of the increase included:

•

an increase of $149 million at our Latin America utilities businesses primarily due to improved payables management at certain businesses compared to the prior year, combined with decreased payments in 2010 related to the settlement of contingencies;

•

an increase of $137 million at our Asia generation businesses due to improved working capital and gross margin; and

•

an increase of $37 million at our North America generation businesses due to improved working capital; partially offset by

•

a decrease of $58 million at our Latin America generation businesses primarily due to increased payments related to fuel purchases at certain businesses compared to the prior year, offset by higher gross margin;

•

a decrease of $54 million at our Europe generation businesses primarily due to the collection of a management incentive bonus of $80 million during 2009; and

•

a decrease of $21 million at our North America utilities businesses due to additional working capital requirements.

Our cash flows from operating activities may vary significantly from quarter to quarter and are influenced by such factors as our operating results, the timing of accounts receivable collections and payments of obligations or other costs. Accordingly, there is no assurance that we will achieve the amount or percentage of increase in cash flow from operations experienced in the second quarter of 2010 in future quarters.

Six months ended June 30, 2010:

Revenue increased $1.6 billion, or 24%, to $8.1 billion in the six months ended June 30, 2010 compared with $6.5 billion in the six months ended June 30, 2009. Key drivers of the increase included:

•

the favorable impact of foreign currency translation of $653 million;

•

an increase in tariff rates and volume at our utilities businesses in Latin America;

•

the impact of the consolidation of Cartagena, in Spain, in accordance with the new consolidation accounting guidance which became effective January 1, 2010;

•

the favorable impact of rate and volume at our generation businesses in Latin America; and

•

higher generation rates and volume at Masinloc in the Philippines.

Gross margin increased $316 million, or 19%, to $2.0 billion in the six months ended June 30, 2010 compared with $1.7 billion in the six months ended June 30, 2009. Key drivers of the increase included:

•

the favorable impact of foreign currency translation of $159 million;

•

an increase in tariff rates and volume at our utilities businesses in Latin America; and

•

higher generation rates and volume at Masinloc in the Philippines;

•

higher volume at our generation businesses in Latin America;

•

the impact of the consolidation of Cartagena, in Spain, in accordance with the new consolidation accounting guidance which became effective January 1, 2010; partially offset by

•

an increase in fixed costs, largely driven by bad debt recoveries and a reduction in bad debt expense in Brazil in the first quarter of 2009 that did not recur; and

•

the unfavorable impact of rates and volume partially offset by a mark-to-market derivative adjustment on natural gas hedges in New York.

Net income attributable to The AES Corporation decreased $190 million, or 36%, to $331 million in the six months ended June 30, 2010 compared with $521 million in the six months ended June 30, 2009. Key drivers of the decrease included:

•

a decrease in gain on sale of investments as described above;

•

an increase in foreign currency transaction losses as described above;

•

an increase in income tax expense as described above; and

•

a decrease in other income due to prior year tax credits received from a legal dispute and a performance incentive bonus for management services provided; partially offset by

•

an increase in net equity in earnings of affiliates partially offset by an increase in income tax expense related to the sale of the Company’s indirect investment in CEMIG; and

•

an increase in gross margin for the year to date as described above.

Net cash provided by operating activities increased $542 million, or 62%, to $1.4 billion in the six months ended June 30, 2010 compared with $874 million in the six months ended June 30, 2009. Please refer to Consolidated Cash Flows — Operating Activities for further discussion.

Non-GAAP Measure

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Reconciliation of Adjusted Earnings Per Share
Diluted earnings per share from continuing operations	$	0.17		$	0.43		$	0.42		$	0.74
Derivative mark-to-market (gains)/losses⁽¹⁾		(0.01	)		-			(0.03	)		0.03
Currency transaction (gains)/losses⁽²⁾		0.06			(0.05	)		0.08			(0.01	)
Disposition/acquisition (gains)/losses		-	⁽³⁾		(0.14	)⁽⁴⁾		-	⁽³⁾		(0.17	)⁽⁵⁾
Impairment losses		-			-			-			0.02	⁽⁶⁾
Debt retirement (gains)/losses		0.01	⁽⁷⁾		-			0.01	⁽⁷⁾		-

Adjusted earnings per share	$	0.23		$	0.24		$	0.48		$	0.61

⁽¹⁾	Derivative mark-to-market (gains)/losses were net of income tax per share of $0.00 in the three months ended June 30, 2010 and 2009, and of $(0.02) and $0.01 for the six months ended June 30, 2010 and 2009, respectively.

⁽²⁾	Unrealized foreign currency transaction (gains)/losses were net of income tax per share of $(0.01) and $0.00 in the three months ended June 30, 2010 and 2009, respectively, and of $(0.01) and $0.01 in the six months ended June 30, 2010 and 2009.

⁽³⁾

The Company has not adjusted for the gain or the related tax effect from the sale of its indirect investment in CEMIG, disclosed in Note 6 — Investments in and Advances to Affiliates, in its determination of adjusted EPS because the gain was recognized by an equity method investee. The Company does not adjust for transactions of its equity method investees in its determination of adjusted EPS.

⁽⁴⁾	Amount includes Kazakhstan gain of $98 million, or $0.14 per share, related to the termination of a management agreement.

⁽ ⁵ ⁾

Amount includes: Kazakhstan gain of $98 million, or $0.15 per share, related to the termination of a management agreement as well as a gain of $13 million, or $0.02 per share, related to the reversal of a withholding tax contingency. There were no taxes associated with these transactions.

⁽ ⁶ ⁾

Amount includes nontaxable impairment of the Company’s investment in “blue gas” (coal to gas) technology of $10 million, or $0.02 per share.

⁽ ⁷ ⁾

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

Management’s Priorities

Management continues to focus on the following priorities:

•

Improvement of operations in the existing portfolio;

•

Completion of an approximately 1,600 MW active construction program on time and within budget.

•

During 2009, the Company stopped construction on its 270 MW Campiche plant, as further described in Key Trends and Uncertainties — Operational Challenges below;

•

Prudent deployment of capital to fund growth initiatives of the Company through greenfield development or mergers and acquisitions, including $1.58 billion of proceeds received in the sale of common stock to China Investment Corporation (“CIC”) in March 2010 and funds received or to be received from the asset sales described below;

•

Completing Announced Asset Sales — In December 2009, we reached agreements to sell our interests in our two generation businesses in Pakistan and our interest in our business in Oman for aggregate gross proceeds, before purchase price adjustments, of approximately $250 million. In June 2010, the sale of the Pakistan businesses was completed. The Oman transaction is subject to customary purchase price adjustments and approvals and is expected to close in the third quarter of 2010. Additionally, in April 2010, we reached an agreement to sell our interest in Ras Laffan, our generation business in Qatar for approximately $190 million. The transaction is subject to customary approvals and is expected to close during the second half of 2010. The businesses are reported as discontinued operations in our condensed consolidated statements of operations;

•

Maximizing the use of cash, including the establishment of low-cost development options, reducing debt balances, such as the recent redemption of $400 million of senior secured notes, and repurchasing the Company’s stock; and

•

Integration of new projects. During the three months ended June 30, 2010, the following projects were acquired or commenced commercial operations:


Project	Location	Fuel	Gross MW	AES Equity Interest (Percent, Rounded)
Dong Qi⁽¹⁾	China	Wind	50	49	%
Huanghua II⁽¹⁾	China	Wind	50	49	%
JHRH⁽²⁾	China	Hydro	241	35	%

⁽¹⁾

Joint ventures with Guohua Energy Investment Co. Ltd.

⁽²⁾

Jianghe Rural Electricity Development Co. Ltd. AES China Hydropower Investment Co. Pte. Ltd. entered into an agreement to acquire up to a 49% interest in this joint venture, which includes six hydro plants, on May 20, 2010. Acquisition of a 35% ownership was completed on June 3, 2010 and the purchase of the remaining 14% ownership, which is subject to approval by the Chinese government, is expected to occur by the end of 2010.

Key Trends and Uncertainties

Our operations continue to face many risks as discussed in Item 1A. — Risk Factors of the 2009 Form 10-K. Some of these challenges are also described above in “Key Drivers of Results in the Three Months Ended June 30, 2010”. We continue to monitor our operations and address challenges as they arise.

Development. During the past quarter, the Company has successfully completed a number of construction projects, totaling approximately 100 MW, on schedule, including the Dong Qi and Huanghua II wind projects in China. However, as discussed in Item 1A. — Risk Factors — Risks Associated with our Operations — Our business is subject to substantial development uncertainties of the 2009 Form 10-K, our development projects are subject to uncertainties. Maritza, a 670 MW coal-fired project under construction in Bulgaria, has experienced certain delays. However, at this time, we believe that Maritza will still be completed by the second half of 2010. However, in the event of further delays of the project, completion of the project and commencement of commercial operations could be delayed beyond this timeframe.

In June 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals that the environmental permit for Empresa Electrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant has stopped as a consequence of the Supreme Court’s decision. In September 2009, the Municipality of Puchuncaví issued an order to demolish the Plant on the basis of other permitting issues. In October 2009, EEC and AES Gener filed a judicial claim against the Municipality of Puchuncaví before the Civil Judge of the City of Quintero, seeking to revoke the demolition order and asking for an immediate stay of said order. At the request of EEC and AES Gener, the Civil Judge of Quintero agreed to suspend the demolition order until a final decision on the order is issued. In December 2009, Chilean authorities approved new land use regulations that entitled EEC to apply for a new environmental permit. The new land use regulations were challenged by local groups but this challenge was declared inadmissible by the Court of Appeals of Santiago. Local groups filed a motion to reconsider this decision in the same Court but this motion was dismissed. EEC applied for a new environmental permit on January 14, 2010 and permit approval was granted by the Environmental Authority on February 26, 2010. On March 24, 2010 the Mayor of Puchuncaví and another third party (collectively, “Municipality”) challenged the new environmental permit before the Court of Appeals in Valparaiso. At the parties’ request, the Court of Appeals suspended the proceedings on the new environmental permit to allow the parties to attempt to settle the challenge. On July 20, 2010, the Council of the Municipality approved a settlement agreement between EEC and the Municipality requiring the Municipality to withdraw its challenge to the new environmental permit. Subsequent to the Council’s approval, EEC and the Municipality executed the settlement agreement on July 26, 2010. Pursuant to the settlement agreement, the Municipality has filed a petition with the Court of Appeals to withdraw the challenge to the new environmental permit, which petition was approved by the Court on July 27, 2010. Certain residents of the Municipality subsequently filed a petition with the Court of Appeals to reopen the proceedings on the new environmental permit, but that petition was denied by the Court of Appeals on August 2, 2010. In addition, EEC has requested that the Municipality issue the construction permits that are required to resume construction of the Plant. If the construction permits are issued, EEC intends to instruct the construction contractor to resume construction of the Plant. EEC and the construction contractor have agreed on a path forward while construction is suspended and once construction is reinitiated. However, if EEC is unable to complete the project, AES may be required to record an impairment of the Campiche project proportional to its indirect ownership, which could have a material impact on earnings in the period in which it is recorded. Based on cash investments through June 30, 2010 and potential termination costs, AES could incur an impairment of approximately $188 million. In the event an impairment charge is recognized with regard to the project, the amount of such impairment will depend on a number of factors, including EEC’s ability to recover project costs.

Impairments. The Company seeks business acquisitions as one of its growth strategies. We have achieved significant growth in the past as a result of several business acquisitions, which also resulted in the recognition of goodwill. As noted in Item 1A. — Risk Factors of the 2009 Form 10-K, there is always a risk that “Our acquisitions may not perform as expected.” The benefits of goodwill are typically realized through the future

operating results of an acquired business. Management believes that the recoverability of goodwill is positively correlated with the economic environments in which our acquired businesses operate and a severe economic downturn could negatively impact the recoverability of goodwill. Also, the evolving environmental regulations, including GHG regulations, around the globe continue to increase the operating costs of our generation businesses. In extreme situations, the environmental regulations could even make a once profitable business, uneconomic. In addition, most of our generation businesses have a finite life and as the acquired businesses reach the end of their finite lives, the carrying amount of goodwill is gradually recovered through their periodic operating results. The accounting guidance, however, prohibits the systematic amortization of goodwill and rather requires an annual impairment evaluation. Thus, as some of our acquired businesses approach the end of their finite lives, they may incur goodwill impairment charges even if there are no discrete adverse changes in the economic environment.

As part of its 2009 annual goodwill impairment evaluation, the Company noted three businesses with an aggregate goodwill balance of $202 million, whose fair values were not higher than their carrying values by more than 10%. While there were no indicators of potential impairment during the first half of 2010 that resulted in the recognition of goodwill impairment, it is possible in the future we may incur goodwill impairment charges on these businesses or even other businesses whose fair values currently exceed their carrying values by more than 10% if any of the following events occur: a significant adverse change in business climate or legal factors, an adverse action or assessment by a regulator, sale of assets at below book value, unanticipated competition, a loss of key personnel, acquisitions not performing as expected, changing environmental regulations that significantly increase the cost of doing business, or a business reaches the end of its finite life. The likelihood of the occurrence of these events may increase because of the challenging global macroeconomic conditions.

As further described in the Company’s 2009 Form 10-K within Item 1. — Regulatory Matters — United Kingdom, the Northern Ireland Authority for Utility Regulation (“NIAUR”) had the right to require the termination of the long-term PPAs under which Kilroot, our generation business in Northern Ireland, supplies electricity to Northern Ireland Electricity plc (“NIE”) as early as 2010. One of the conditions to the early termination is 180 days notice, which was provided to Kilroot on April 30, 2010. Kilroot may not be able to replace the contract on competitive terms and upon cancellation of the PPA effective November 1, 2010 will become a merchant plant and operate under the gross mandatory pool under the single electricity market (“SEM”) in Northern Ireland. At March 31, 2010, management evaluated Kilroot’s long-lived tangible assets for potential impairment assuming the early termination of the PPA and concluded that no impairment exists at this time.

Global Economic Conditions. The global economic slowdown has caused market illiquidity, widening credit spreads, volatile currencies, fluctuating fuel prices, increased counterparty credit risk and sovereign wealth crises, each of which could impact our operations.

Despite these challenges, management continues to believe that the Company can meet its near-term liquidity requirements through a combination of existing cash balances, cash provided by operating activities, financings, and, if needed, borrowings under its secured facility. Although there can be no assurance due to the challenging times currently faced by financial institutions, management believes that the participating banks under its senior secured credit facility will be able to meet their funding commitments.

The Company is subject to credit risk, which includes risk related to the ability of counterparties (such as parties to our PPAs, fuel supply agreements, our hedging agreements and other contractual arrangements) to deliver contracted commodities or services at the contracted price or to satisfy their financial or other contractual obligations. While counterparty credit risk has increased in the current crisis and there can be no assurances regarding the future, the Company has not suffered any material effects related to its counterparties during 2010.

In addition, during the past several months, certain European countries have faced a sovereign debt crisis and it is possible that other nations could be affected. This crisis (the “Euro Crisis”) has resulted in a decline in the value of the Euro, an increased risk of default by sovereign governments and the implementation of austerity

measures in countries impacted by the Euro Crisis. To date, other than the impacts of the declining Euro which we described elsewhere in this Form 10-Q, the Euro Crisis has not had a material adverse impact on the Company. However, if the Euro Crisis continues, worsens, or spreads, there could be a material adverse impact on the Company. Our businesses may be impacted if they are unable to access the capital markets, face increased taxes or labor costs, or if governments fail to fulfill their obligations to us or adopt austerity measures which adversely impact our projects. In addition, as noted in the 2009 Form 10-K Risk Factor titled, “Our renewable energy projects and other initiatives face considerable uncertainties including development, operational and regulatory challenges,” our renewables businesses are dependent on favorable regulatory incentives, including subsidies, which are provided by sovereign governments. If these subsidies or other incentives are repealed, or sovereign governments are unable or unwilling to fulfill their commitments or maintain favorable regulatory incentives for renewables, this could affect the ability of the affected businesses to continue or grow their operations. In addition, any of the foregoing could also impact contractual counterparties of our subsidiaries in core power or renewables. If such counterparties are adversely impacted, then they may be unable to meet their commitments to our subsidiaries. For further information on the importance of long-term contracts and our counterparty credit risk, see the Risk Factor from our 2009 Form 10-K titled, “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations…” As a result of any of the foregoing events, we may have to provide equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. The Company’s investment in AES Solar, whose primary operations are in Europe, at June 30, 2010 was $193 million.

The global economic weakness could also result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development, which could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses as needed. A decline in asset value, including pension asset values, could also lead to a material increase in our obligations.

In addition, as described in Overview of Our Business, volatility in foreign currency exchange rates has had an impact on the Company’s financial results. If the current volatility in foreign currencies continues, our gross margin and other financial metrics could be affected. For further discussion of the risks associated with commodity prices, see “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” in Item 1A. — Risk Factors of the 2009 Form 10-K. It is also possible that commodity or power price volatility could continue to impact our financial results. As noted in “Key Drivers of Results on the Three Months Ended June 30, 2010,” and Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk of this Form 10-Q, the Company’s North American businesses continue to face pressure as a result of high coal prices relative to natural gas, which has affected the results of certain of our coal plants in the region, particularly those which are merchant plants that are exposed to market risk and those that have hybrid merchant risk, meaning those businesses that have a PPA in place but purchase fuel at market prices or under short term contracts. If these conditions continue or worsen, these businesses may need to restructure their obligations or seek additional funding (including from the Parent) or face the possibility that they are unable to meet their obligations and continue operations. Any of these events could result in increased costs, a write-down of assets, or otherwise have a material impact on the Company.

In the event that global economic conditions deteriorate further, or continue for a prolonged period, there could be a material adverse impact on the Company. The Company could be materially affected if such events or other events occur such that participating lenders under its secured facility fail to meet their commitments, or the Company is unable to access the capital markets on favorable terms or at all, or is unable to raise funds through the sale of assets, or is otherwise unable to finance or refinance its activities, or if capital market disruptions result in increased borrowing costs (including with respect to interest payments on the Company’s variable rate debt) or if commodity prices affect the profitability of our plants or their ability to continue operations or if the effects of the Euro Crisis described above continue or worsen. The Company could also be adversely affected if the foregoing effects are exacerbated or general economic or political conditions in the markets where the

Company operates deteriorate, resulting in a reduction in cash flow from operations, a reduction in the availability and/or an increase in the cost of capital, a reduction in the value of currencies in these markets relative to the U.S. dollar (which could cause currency losses), an increase in the price of commodities used in our operations and construction, or if the value of its assets remain depressed or decline further. Any of the foregoing events or a combination thereof could have a material impact on the Company, its results of operations, liquidity, financial covenants, and/or its credit rating.

Regulatory — Environment. The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including existing and potential 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.

EPA GHG Regulation. As noted in the Company’s 2009 Form 10-K, the U.S. Environmental Protection Agency (“EPA”) has 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 also promulgated a final rule on June 3, 2010, (the “Tailoring Rule”) that would significantly increase the thresholds for GHG emissions that trigger PSD review and related permitting requirements. Specifically, commencing in 2011, the Tailoring Rule would increase the “major source” threshold from 250 tons per year to 75,000 tons per year for GHG emissions — this means any new source of GHG emissions would need to emit over 75,000 tons per year in order to trigger PSD review and related permitting requirements. Also, commencing in 2011, the Tailoring Rule would increase the “significance threshold” from zero tons per year to 50,000 tons per year for GHG emissions — this means any modifications to existing sources of GHG emissions would need to increase aggregate GHG emissions by over 50,000 tons per year in order to trigger PSD review and related permitting requirements. The Tailoring Rule, as currently proposed by 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 would still generally be subject to PSD and Title V requirements because annual GHG emissions from such plants typically far exceed the “major source” threshold 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 50,000 tons per year threshold.

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_x under 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 is subject to public comments until 60 days after it has been published in the Federal Register, and any 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 business and financial condition or results of operations could be materially and adversely affected by such regulation or legislation.

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.

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.

Regulatory — Dodd-Frank Act. On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). While the bulk of regulations contained in the Dodd-Frank Act regulate financial institutions and their products, there are several provisions related to corporate governance, executive compensation, disclosure and other matters which relate to public companies generally. None of these provisions are expected to have a material impact on the Company or its results of operations. Furthermore, while the Dodd-Frank Act substantially expands the regulation regarding the trading, clearing and reporting of derivative transactions, the Dodd-Frank Act provides for commercial end-user exemptions which may apply to our derivative transactions, though this is not certain since the Act directs the SEC, CFTC and listed companies to enact rules that will clarify the Dodd-Frank Act, and such rule making could impact the availability of the commercial end-user exemption. Even if the exemption is available, the enactment of the Dodd-Frank Act could still have a material adverse impact on the Company, as the regulation of derivatives (which includes capital and margin requirements for non-exempt companies), could limit the availability of derivative transactions that we use to reduce interest rate, commodity and currency risks, which would increase our exposure to these risks. Even if derivative transactions remain available, the costs to enter into these transactions may increase, which could adversely affect the operating results of certain projects; cause us to default on certain types of contracts where we are contractually obligated to hedge certain risks, such as project financing agreements; prevent us from developing new projects where interest rate hedging is required; cause the Company to abandon certain of its hedging strategies and transactions, thereby increasing our exposure to interest rate, commodity, currency risk; and/or consume substantial liquidity by forcing the Company to post cash in support of these derivatives. Any of these outcomes could have a material adverse affect on the Company.

Regulatory — Licensing of AES Kelanitissa. On June 12, 2009 AES Kelanitissa received a letter and an invoice from the Director General, Public Utilities Commission of Sri Lanka (“PUC”) seeking payment of an Annual Regulatory Fee and pursuant to PUC assurances on an application for renewal of the AES Kelanitissa generation license. The application is pursuant to an April 2009 revision of the Sri Lanka Electricity Act (“Act”), which came into force in April 2009, notwithstanding that in March 29, 2001 AES Kelanitissa had been granted, and pre-paid fees for, a 21 years generation license with effect from September 25, 2000 under the Electricity Act, 1950. AES Kelanitissa submitted an application to be licensed under the revised legislation and, on August 26, 2009, PUC published its intention to issue a generation license under the revised legislation to AES Kelanitissa and other Independent Power Producers (“IPPs”) in Sri Lanka. This was consistent with assurances received from relevant authorities that the revised legislation was to be amended to grandfather IPPs with existing generation licenses. In a letter dated June 21, 2010 from the PUC, AES Kelanitissa was informed that under the new regulations as amended in 2009, AES Kelanitissa (Pvt) Ltd no longer fulfilled the eligibility criteria to apply for a generation license. The “eligibility criteria” to which the letter refers is a provision requiring an element of state ownership. It is possible that an amendment to the Act to grandfather existing IPPs will still be passed, and AES Kelanitissa is working diligently to find a solution that will allow it to obtain a license under the revised legislation. In addition, AES Kelanitissa believes that under Sri Lankan law, it may continue operations under the 21 year license issued in 2001. No step has been taken to date to prohibit AES Kelanitissa from generating power and its operations. However, in the event that it is determined that AES Kelanitissa may not operate under its current license or the revised legislation is not amended (and PUC maintains that AES Kelanitissa is ineligible for a generation license or extension of the Generating License), AES Kelanitissa may not be able to continue operations on grounds that it has no license under the revised legislation. In that event, AES Kelanitissa and/or the Company could face a number of adverse consequences, including potential litigation with counterparties (which AES Kelanitissa would defend vigorously), a write down in the value of the assets of the business, continued default status under its debt documents, and/or other consequences which could have a material impact on the Company or its results of operations.

Counterparty Risk. A subsidiary of BP is a counterparty to a fuel contract with AES Andres. At this time the Deepwater Horizon oil spill in the Gulf of Mexico has affected the credit rating of BP but has not affected the performance of BP’s subsidiary under the contract. However, if BP subsidiary’s ability to fulfill its obligations under the contract is subsequently affected, AES Andres would have to find a replacement counterparty. Since the agreement is on favorable terms, it may be difficult to find a replacement on the same economic terms, which could impact the profitability of AES Andres and our results of operations.

Recent Events

On July 2, 2010, the Company announced that it has entered into an agreement with BG Energy Holdings to acquire Premier Power Limited (“PPL”), owner of the 1,246 MW natural gas-fired Ballylumford Power Station in County Antrim, Northern Ireland for £99 million (approximately $150 million). The transaction is subject to license consents from the Northern Ireland Authority for Utility Regulation and the Northern Ireland Department of Enterprise, Trade and Industry, and is expected to close in the second half of 2010. The majority of Ballylumford’s output is contracted to Northern Ireland Electricity and the affiliated agreements allow for a pass-through of fuel costs. Upon obtaining required consents, at closing, AES’ newly formed subsidiary, AES Ballylumford Holdings Limited, will acquire PPL through an all cash transaction and the final purchase price will incorporate working capital adjustments.

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 increased the aggregate commitment for the revolving credit loan facility to $800 million and extended its final maturity to January 29, 2015. Please refer to Note 15 — Subsequent Events in the notes to condensed consolidated financial statements for further details.

Consolidated Results of Operations


	Three Months Ended June 30,											Six Months Ended June 30,
	2010			2009			$ change			% change		2010			2009			$ change			% change
	(in millions, except per share amounts)											(in millions, except per share amounts)
Revenue:
Latin America Generation	$	1,084		$	894		$	190		21	%	$	2,067		$	1,786		$	281		16	%
Latin America Utilities		1,770			1,364			406		30	%		3,535			2,576			959		37	%
North America Generation		455			475			(20	)	-4	%		987			977			10		1	%
North America Utilities		275			261			14		5	%		563			551			12		2	%
Europe Generation		271			173			98		57	%		604			403			201		50	%
Asia Generation		179			112			67		60	%		355			190			165		87	%
Corporate and Other⁽¹⁾		243			213			30		14	%		492			428			64		15	%
Eliminations⁽²⁾		(256	)		(201	)		(55	)	27	%		(511	)		(385	)		(126	)	33	%

Total Revenue	$	4,021		$	3,291		$	730		22	%	$	8,092		$	6,526		$	1,566		24	%

Gross Margin:
Latin America Generation	$	415		$	335		$	80		24	%	$	759		$	708		$	51		7	%
Latin America Utilities		258			178			80		45	%		496			353			143		41	%
North America Generation		75			121			(46	)	-38	%		209			241			(32	)	-13	%
North America Utilities		52			51			1		2	%		128			121			7		6	%
Europe Generation		64			32			32		100	%		159			107			52		49	%
Asia Generation		80			26			54		208	%		145			33			112		339	%
Corporate and Other⁽³⁾		28			51			(23	)	-45	%		52			69			(17	)	-25	%
Eliminations⁽⁴⁾		10			9			1		11	%		20			20			-		-	%
General and administrative		(101	)		(87	)		(14	)	16	%		(181	)		(170	)		(11	)	6	%
Interest expense		(394	)		(368	)		(26	)	7	%		(780	)		(740	)		(40	)	5	%
Interest income		101			89			12		13	%		210			182			28		15	%
Other expense		(48	)		(30	)		(18	)	60	%		(60	)		(52	)		(8	)	15	%
Other income		69			22			47		214	%		77			243			(166	)	-68	%
Gain on sale of investments		-			102			(102	)	-100	%		-			115			(115	)	-100	%
Asset impairment expense		(1	)		(1	)		-		-	%		(1	)		(1	)		-		-	%
Foreign currency transaction gains (losses) on net monetary position		(71	)		28			(99	)	-354	%		(122	)		(11	)		(111	)	1009	%
Other non-operating expense		(5	)		-			(5	)	-	%		(5	)		(10	)		5		-50	%
Income tax expense		(255	)		(105	)		(150	)	143	%		(451	)		(279	)		(172	)	62	%
Net equity in earnings of affiliates		134			50			84		168	%		148			57			91		160	%

Income from continuing operations		411			503			(92	)	-18	%		803			986			(183	)	-19	%
Income from operations of discontinued businesses		27			28			(1	)	-4	%		50			46			4		9	%
Loss from disposal of discontinued businesses		(9	)		-			(9	)	-	%		(22	)		-			(22	)	-	%

Net income		429			531			(102	)	-19	%		831			1,032			(201	)	-19	%
Noncontrolling interests:
Income from continuing operations attributable to noncontrolling interests		(277	)		(217	)		(60	)	28	%		(488	)		(492	)		4		-1	%
Income from discontinued operations attributable to noncontrolling interests		(8	)		(11	)		3		-27	%		(12	)		(19	)		7		-37	%

Net income attributable to The AES Corporation	$	144		$	303		$	(159	)	-52	%	$	331		$	521		$	(190	)	-36	%

Per Share Data:
Basic income per share from continuing operations	$	0.17		$	0.43		$	(0.26	)	-60	%	$	0.42		$	0.74		$	(0.32	)	-43	%
Diluted income per share from continuing operations	$	0.17		$	0.43		$	(0.26	)	-60	%	$	0.42		$	0.74		$	(0.32	)	-43	%

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

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

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

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

Segment Analysis

Latin America

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


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010		2009		% Change		2010		2009		% Change
	($’s in millions)						($’s in millions)
Latin America Generation
Revenue	$	1,084	$	894	21	%	$	2,067	$	1,786	16	%
Gross Margin	$	415	$	335	24	%	$	759	$	708	7	%

Excluding the favorable impact of foreign currency translation and remeasurement of $39 million, primarily in Brazil and Colombia, generation revenue for the three months ended June 30, 2010 increased $151 million, or 17%, compared to the three months ended June 30, 2009 primarily due to higher spot prices associated with increased fuel prices in Argentina of $71 million, higher spot sales and ancillary services in the Dominican Republic of $26 million, higher contract and spot prices due to lower hydrology in Colombia of $23 million, higher volume sold at Gener of $22 million primarily driven by higher contracted volume sold, and higher volume in Panama and Argentina of $15 million and $11 million, respectively. Additionally, revenue increased due to higher spot prices in Panama of $10 million as a result of lower hydrology, higher spot sales at Tiete of $10 million and the favorable impact of $28 million related to the finalization of the settlement of the power sales agreement between Sul and Uruguaiana. These increases were partially offset by lower spot prices at Tiete of $14 million and lower contract prices at Gener of $28 million.

Excluding the favorable impact of foreign currency translation and remeasurement of $30 million, primarily in Brazil and Colombia, generation gross margin for the three months ended June 30, 2010 increased $50 million, or 15%, compared to the three months ended June 30, 2009 primarily due to higher volume and prices in Panama of $27 million due to lower hydrology, higher contract and spot prices combined with lower energy purchases in Colombia of $21 million and higher spot prices and increased energy sales at our businesses in Argentina of $19 million. Additionally, gross margin was positively impacted by higher spot sales and ancillary services in Dominican Republic of $24 million and the favorable impact of $28 million as a result of finalization of the settlement for the power sales agreement between Sul and Uruguaiana. These increases were partially offset by higher fuel and purchased energy prices of $31 million at Gener offset by higher contracted sales, lower contract prices on PPAs indexed to international coal prices and higher fuel costs at our businesses in the Dominican Republic of $31 million, and lower spot prices offset by increased energy sales at Tiete of $9 million.

Excluding the favorable impact of foreign currency translation and remeasurement of $108 million, primarily in Brazil and Colombia, generation revenue for the six months ended June 30, 2010 increased $173 million, or 10%, compared to the six months ended June 30, 2009 primarily due to higher spot prices associated with increased fuel prices in Argentina of $90 million, higher spot sales and ancillary services in the Dominican Republic of $60 million, the favorable impact of higher contract and spot prices in Colombia of $46 million and higher volume at Gener and Tiete of $43 million and $25 million, respectively. These increases were partially offset by lower contract prices at Gener of $59 million and lower volume due to lower hydrology in Colombia of $23 million.

Excluding the favorable impact of foreign currency translation and remeasurement of $85 million, primarily in Brazil and Colombia, generation gross margin for the six months ended June 30, 2010 decreased $34 million,

or 5%, compared to the six months ended June 30, 2009 primarily due to higher fuel and purchased energy prices at Gener of $82 million offset by higher contracted sales and the impact of a decrease in bad debt expense during the first quarter of 2009 of $35 million at Uruguaiana as a result of the renegotiation of one of its power sales agreements. Gross margin was also negatively impacted by higher spot prices at Panama of $8 million. These decreases were partially offset by the favorable impact of higher spot prices in Colombia of $31 million, higher spot prices and spot sales in Argentina of $33 million and higher volume of energy sales offset by increased energy purchases and fuel consumption in the Dominican Republic of $13 million and at Tiete of $12 million.

For the six months ended June 30, 2010 revenue increased 16%, while gross margin increased by 7%. This was primarily due to the positive impact on bad debt expense as a result of the renegotiation of one of the power sales agreements at Uruguaiana in the first quarter of 2009 and higher spot purchases and fuel prices at Gener and the Dominican Republic, respectively.

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


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010		2009		% Change		2010		2009		% Change
	($’s in millions)						($’s in millions)
Latin America Utilities
Revenue	$	1,770	$	1,364	30	%	$	3,535	$	2,576	37	%
Gross Margin	$	258	$	178	45	%	$	496	$	353	41	%

Excluding the favorable impact of foreign currency translation of $206 million, primarily in Brazil, utilities revenue for the three months ended June 30, 2010 increased $200 million, or 15%, compared to the three months ended June 30, 2009 primarily due to increased tariffs of $133 million partially related to the July 2009 tariff reset in Brazil and includes the recovery of energy purchases of $86 million. Additionally, volume increased $62 million due to increased market demand.

Excluding the favorable impact of foreign currency translation of $31 million, primarily in Brazil, utilities gross margin for the three months ended June 30, 2010 increased $49 million, or 28%, compared to the three months ended June 30, 2009 primarily due to increased rates of $43 million, primarily related to the July 2009 tariff reset in Brazil and $34 million of increased demand due to the market recovery. These increases were partially offset by $28 million related to the final settlement of the power sales agreement between Sul and Uruguaiana.

For the three months ended June 30, 2010 revenue increased 30%, while gross margin increased by 45%. This was primarily due to the positive impact on gross margin of the 2009 tariff readjustment at Sul and increased demand in Brazil, which caused a higher percentage increase in gross margin compared to revenue offset by the final settlement of the power sales agreement between Sul and Uruguaiana.

Excluding the favorable impact of foreign currency translation of $551 million, primarily in Brazil, utilities revenue for the six months ended June 30, 2010 increased $408 million, or 16%, compared to the six months ended June 30, 2009 primarily due to increased tariffs of $252 million partially related to the July 2009 tariff reset in Brazil which includes the recovery of energy purchases of $192 million. Volume increased $145 million due to increased market demand.

Excluding the favorable impact of foreign currency translation of $80 million, primarily in Brazil, utilities gross margin for the six months ended June 30, 2010 increased $63 million, or 18%, compared to the six months ended June 30, 2009 primarily due to $81 million of increased demand due to the market recovery and a $45 million increase related to the July 2009 tariff reset in Brazil. These increases were partially offset by $28 million related to the final settlement of the power sales agreement between Sul and Uruguaiana and $37 million of higher fixed costs related to higher provisions for commercial losses, regulatory penalties, salaries and bad debts.

North America

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


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010		2009		% Change		2010		2009		% Change
	($’s in millions)						($’s in millions)
North America Generation
Revenue	$	455	$	475	-4	%	$	987	$	977	1	%
Gross Margin	$	75	$	121	-38	%	$	209	$	241	-13	%

Excluding the favorable impact of foreign currency translation of $5 million, generation revenue for the three months ended June 30, 2010 decreased $25 million, or 5%, compared to the three months ended June 30, 2009 primarily due to a decrease in New York from the combination of a net decrease of $15 million in lower rates partially offset by higher volume of electricity sold and a $17 million unfavorable impact of a mark-to-market derivative loss. Additionally, revenue decreased in Puerto Rico by $21 million primarily due to a penalty from a forced outage. These decreases were partially offset by higher volume due to fewer outages at Warrior Run in Maryland of $14 million and higher volume due to fewer outages and an availability bonus at TEG/TEP in Mexico of $12 million.

Generation gross margin for the three months ended June 30, 2010 decreased $46 million, or 38%, compared to the three months ended June 30, 2009 primarily due to a decrease in New York from the combination of lower rates and higher coal prices partially offset by higher volume of electricity sold of $27 million and the unfavorable impact of a mark-to-market derivative loss of $17 million. Additionally gross margin decreased in Puerto Rico by $15 million primarily due to a penalty from a forced outage and in Hawaii by $8 million due to the unfavorable impact of a mark-to-market derivative loss. These decreases were partially offset by higher volume due to fewer outages and an availability bonus in TEG/TEP of $13 million and higher volume due to fewer outages in Warrior Run of $10 million.

For the three months ended June 30, revenue decreased 4%, while gross margin decreased by 38%. This was primarily due to the change in rates, volume and the mark-to-market derivative loss in New York which had a greater impact on gross margin than revenue and the gross margin effect of the mark-to-market derivative loss in Hawaii.

Excluding the favorable impact of foreign currency translation of $13 million, generation revenue for the six months ended June 30, 2010 decreased $3 million compared to the six months ended June 30, 2009 primarily due to a net decrease of $53 million in New York due to lower rates partially offset by higher volume of electricity sold and a decrease in Puerto Rico of $21 million primarily due to a penalty from a forced outage. These decreases were partially offset by favorable mark-to-market derivative gains of $27 million in New York, increased rates, volume and an availability bonus in TEG/TEP of $25 million, increased volume due to fewer outages in Warrior Run of $13 million and higher rates and volume at Merida in Mexico of $9 million.

Excluding the favorable impact of foreign currency translation of $2 million, generation gross margin for the six months ended June 30, 2010 decreased $34 million, or 14%, compared to the six months ended June 30, 2009 primarily due to a net decrease of $63 million in New York due to lower rates and higher coal prices, partially offset by higher volume of electricity sold and a decrease in Puerto Rico of $16 million primarily due to a penalty from a forced outage. These decreases were partially offset by favorable mark-to-market derivative gains of $27 million in New York and an annual availability bonus and fewer outages in TEG/TEP of $17 million.

For the six months ended June 30, revenue increased 1%, while gross margin decreased by 13%. This was primarily due to the change in rates and volume in New York having a greater impact on gross margin than revenue.

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


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010		2009		% Change		2010		2009		% Change
	($’s in millions)						($’s in millions)
North America Utilities
Revenue	$	275	$	261	5	%	$	563	$	551	2	%
Gross Margin	$	52	$	51	2	%	$	128	$	121	6	%

Utilities revenue for the three months ended June 30, 2010 increased $14 million, or 5%, compared to the three months ended June 30, 2009 primarily due to an increase in wholesale revenue of $11 million from higher availability and pricing and higher retail demand of $4 million due to warmer weather.

Utilities gross margin for the three months ended June 30, 2010 increased $1 million, or 2%, compared to the three months ended June 30, 2009 primarily due to higher gross margin from increase in wholesale revenue partially offset by increase in fixed costs.

Utilities revenue for the six months ended June 30, 2010 increased $12 million, or 2%, compared to the six months ended June 30, 2009 primarily due to a $23 million increase in wholesale revenue from higher demand. The increase was partially offset by a $10 million decrease in retail revenue due primarily to lower fuel adjustment charges.

Utilities gross margin for the six months ended June 30, 2010 increased $7 million, or 6%, compared to the six months ended June 30, 2009 primarily due to a higher wholesale margin of $10 million due to increased volume and higher prices as well as a decrease in pension expense of $6 million. These increases were partially offset by a decrease in retail margin of $4 million and an increase in maintenance expenses of $4 million.

Europe

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


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010		2009		% Change		2010		2009		% Change
	($’s in millions)						($’s in millions)
Europe Generation
Revenue	$	271	$	173	57	%	$	604	$	403	50	%
Gross Margin	$	64	$	32	100	%	$	159	$	107	49	%

Excluding the unfavorable impact of foreign currency translation of $11 million, primarily in Spain, generation revenue for the three months ended June 30, 2010 increased $109 million, or 63%, compared to the three months ended June 30, 2009 primarily due to $85 million from the adoption of new accounting guidance on the consolidation of VIE’s which resulted in the consolidation of Cartagena in Spain, a generation business previously accounted for under the equity method of accounting. Additionally, revenue increased due to higher volume and pass-through of higher fuel costs in Hungary of $10 million and $8 million due to the favorable impact from combined cycle operations at Amman East in Jordan during the second quarter 2010 compared to single cycle operations during the second quarter of 2009.

Excluding the unfavorable impact of foreign currency translation of $2 million, primarily in Spain, generation gross margin for the three months ended June 30, 2010 increased $34 million, or 106%, compared to the three months ended June 30, 2009 primarily due to $22 million from the consolidation of Cartagena as discussed above and $11 million from improved results at Altai in Kazakhstan primarily due to higher tariffs and market prices.

For the three months ended June 30, 2010, revenue increased 57%, while gross margin increased by 100%. This was primarily due to the reduction of a contingent liability at Cartagena which impacted gross margin with no corresponding impact on revenue.

Excluding the favorable impact of foreign currency translation of $9 million primarily in Hungary and the U.K., generation revenue for the six months ended June 30, 2010 increased $192 million, or 48%, compared to the six months ended June 30, 2009 primarily due to $178 million from the adoption of new accounting guidance on the consolidation of VIE’s which resulted in consolidation of Cartagena, previously accounted for under the equity method of accounting. Additionally, revenue increased due to improved results of $8 million primarily due to higher tariffs and capacity payments at Altai and the favorable impact from higher volume under the combined cycle operations at Amman East in Jordan during the second quarter 2010 compared to single cycle operations during the second quarter of 2009 of $11 million.

Excluding the favorable impact of foreign currency translation of $2 million, primarily in Hungary and the U.K., generation gross margin for the six months ended June 30, 2010 increased $50 million, or 47%, compared to the six months ended June 30, 2009 primarily due to $35 million from the consolidation of Cartagena as discussed above and improved results of $16 million at Altai primarily due to higher tariffs.

Asia

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


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010		2009		% Change		2010		2009		% Change
	($’s in millions)						($’s in millions)
Asia Generation
Revenue	$	179	$	112	60	%	$	355	$	190	87	%
Gross Margin	$	80	$	26	208	%	$	145	$	33	339	%

Excluding the favorable impact of foreign currency translation of $8 million, primarily in the Philippines, generation revenue for the three months ended June 30, 2010 increased $59 million, or 53%, compared to the three months ended June 30, 2009 primarily due to favorable generation rates and volume of $57 million at Masinloc in the Philippines compared to the three months ended June 30, 2009. This was mainly attributable to higher energy demand and power supply shortages within the Philippines power market, which resulted in a combination of higher volume and rates as well as higher contract sales from new and existing customers.

Excluding the favorable impact of foreign currency translation of $5 million, primarily in the Philippines, generation gross margin for the three months ended June 30, 2010 increased $49 million, or 188%, compared to the three months ended June 30, 2009 primarily as a result of a $43 million increase at Masinloc from a combination of higher rates as well as higher contract sales from new and existing customers.

For the three months ended June 30, 2010, revenue increased 60%, while gross margin increased by 208%. The percentage change in gross margin exceeded the percentage change in revenue as a result of the positive influence on gross margin due to higher availability, increased spot market demand and favorable prices in the wholesale electricity spot market.

Excluding the favorable impact of foreign currency translation of $13 million, primarily in the Philippines, generation revenue for the six months ended June 30, 2010 increased $152 million, or 80%, compared to the six months ended June 30, 2009 primarily due to higher generation volume and rates of $128 million at Masinloc in the Philippines as a result of increased demand and improved plant availability subsequent to the completion of its overhaul at the beginning of 2010. Revenue also increased as a result of the combined impact of higher

demand from both new and existing contract and spot customers as a result of supply shortages in the Philippines power market. Revenue also increased $20 million at Kelanitissa in Sri Lanka due to improved operational performance and availability and an increase in rates due to higher pass-through fuel costs.

Excluding the favorable impact of foreign currency translation of $7 million, primarily in the Philippines, generation gross margin for the six months ended June 30, 2010 increased $105 million, or 318%, compared to the six months ended June 30, 2009 primarily as a result of a $96 million increase at Masinloc from a combination of higher availability due to improved plant operations and favorable spot market rates in the Philippines.

For the six months ended June 30, 2010, revenue increased 87%, while gross margin increased by 339%. The percentage change in gross margin exceeded the percentage change in revenue as a result of the positive influence on gross margin of lower fuel costs attributable to better fuel rate efficiency, favorable spot and contract prices and operational efficiencies resulting from the Masinloc plant overhauls in late 2009 and early 2010, which have allowed for more efficient operations that have materially improved the operating results for the six months ended June 30, 2010 compared to the six months ended June 30, 2009.

Corporate and Other

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


	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2010			2009			% Change		2010			2009			% Change
	($’s in millions)								($’s in millions)
Revenue
Europe Utilities	$	75		$	63		19	%	$	168		$	144		17	%
Africa Utilities		93			91		2	%		188			174		8	%
Africa Generation		16			17		-6	%		30			33		-9	%
Wind Generation		53			37		43	%		95			69		38	%
Corp/Other		6			5		20	%		11			8		38	%

Total Corporate and Other	$	243		$	213		14	%	$	492		$	428		15	%

Gross Margin
Europe Utilities	$	1		$	6		-83	%	$	8		$	12		-33	%
Africa Utilities		4			30		-87	%		3			40		-93	%
Africa Generation		11			10		10	%		24			19		26	%
Wind Generation		13			7		86	%		21			9		133	%
Corp/Other		(1	)		(2	)	-50	%		(4	)		(11	)	-64	%

Total Corporate and Other	$	28		$	51		-45	%	$	52		$	69		-25	%

Corporate and Other revenue for the three months ended June 30, 2010 increased $30 million, or 14%, compared to the three months ended June 30, 2009 primarily due to incremental revenue from Armenia Mountain, a new wind project in Pennsylvania, that commenced operations in December 2009, an overall volume increase across our wind businesses and higher volume at our utilities businesses in Ukraine.

Corporate and Other gross margin for the three months ended June 30, 2010 decreased $23 million, or 45%, compared to the three months ended June 30, 2009 primarily due to increase in fixed and variable costs at Sonel in Cameroon and adverse tariff revisions in Ukraine, partially offset by incremental gross margin from new business and an overall volume increase across our wind businesses

For the three months ended June 30, 2010, revenue increased 14%, while gross margin decreased by 45%. This was primarily due to increased fixed costs at Sonel driven by an increase in salaries, insurance expense, fuel cost and incremental deprecation on new plant and equipment.

Corporate and Other revenue for the six months ended June 30, 2010 increased $64 million, or 15%, compared to the six months ended June 30, 2009 primarily due to incremental revenue from Armenia Mountain, an overall volume increase across our wind businesses and higher volume at our utilities businesses in Ukraine, as discussed above.

Corporate and Other gross margin for the six months ended June 30, 2010 decreased $17 million, or 25%, compared to the six months ended June 30, 2009 primarily due to an increase in fixed and variable costs at Sonel and adverse tariff revisions in Ukraine, partially offset by incremental gross margin from new business and an overall volume increase across our wind businesses, as discussed above.

For the six months ended June 30, 2010, revenue increased 15%, while gross margin decreased by 25%. The percentage change in revenue exceeded the percentage change in gross margin as a result of increased volume at our Ukraine utilities which had a more favorable impact on revenue than gross margin. Additionally, increased fixed costs at Sonel had an unfavorable impact on the gross margin primarily due to an increase in salaries, insurance expense, fuel cost and incremental depreciation on new plant and equipment.

General and Administrative Expense

General and administrative expense includes those expenses related to corporate staff functions and/or initiatives, executive management, finance, legal, human resources, information systems, and certain development costs which are not allocable to our business segments.

General and administrative expense increased $14 million, or 16%, to $101 million for the three months ended June 30, 2010. The increase was due to business development costs primarily related to renewable energy projects.

General and administrative expense increased $11 million, or 6%, to $181 million for the six months ended June 30, 2010. The increase was due to business development costs primarily related to renewable energy projects.

Interest expense

Interest expense increased $26 million, or 7%, to $394 million for the three months ended June 30, 2010. The increase was primarily due to increased debt principal at Eletropaulo and the unfavorable impact of inflation adjustments and foreign currency translation in Brazil partially offset by a decline in interest rates at Eletropaulo.

Interest expense increased $40 million, or 5%, to $780 million for the six months ended June 30, 2010. The increase was primarily due to the above mentioned items and interest expense at Cartagena, which is now a consolidated entity, offset by higher capitalized interest and lower fees on the revolving line of credit at the Parent Company.

Interest income

Interest income increased $12 million, or 13%, to $101 million for the three months ended June 30, 2010. The increase was primarily due to a higher average balance in short term investments at Eletropaulo, the favorable impact of foreign currency translation in Brazil, and interest earned on cash proceeds from the CIC investment.

Interest income increased $28 million, or 15%, to $210 million for the six months ended June 30, 2010. The increase was primarily due to the settlement of a dispute related to inflation adjustments for energy sales at Tiete and foreign currency translation in Brazil described above.

Other expense

Other expense of $48 million for the three months ended June 30, 2010 was primarily comprised of the write-off of previously capitalized transaction costs of $22 million that were incurred in connection with the preparation for the sale of a noncontrolling interest in our Wind Generation business. The costs were written off upon the expiration of the letter of intent (“LOI”) with China Investment Corporation on June 30, 2010. Other expense also included the loss on debt extinguishment of $9 million at the Parent Company from the retirement of senior notes and a loss on disposal of assets at Eletropaulo and Gener. Other expense of $30 million for the three months ended June 30, 2009 included a $13 million loss recognized when three of our businesses in the Dominican Republic received $110 million par value bonds issued by the Dominican Republic government to settle existing accounts receivable for the same amount from the government-owned distribution companies. The loss represented an adjustment to reflect the fair value of the bonds on the date received. Other expense also included losses on disposal of assets at Eletropaulo.

Other expense of $60 million for the six months ended June 30, 2010 included the write-off of previously capitalized transaction costs discussed above, the loss on debt extinguishment at the Parent Company described above and a loss on disposal of assets at Eletropaulo and Gener. Other expense of $52 million for the six months ended June 30, 2009 was primarily comprised of the previously mentioned $13 million fair value adjustment to government issued bonds in the Dominican Republic on the date received and losses on the disposal of assets at Eletropaulo and Andres.

Other income

Other income of $69 million for the three months ended June 30, 2010 was primarily related to the extinguishment of a swap liability owed by two of our Brazilian subsidiaries which resulted in a $62 million gain. The net impact after tax and noncontrolling interests was $9 million. Other income of $22 million for the three months ended June 30, 2009 included a gain on early extinguishment of debt at Itabo in the Dominican Republic, a reversal of a legal reserve at Sonel in Cameroon and insurance recoveries related to turbine damage at one of our Brazilian subsidiaries.

Other income of $77 million for the six months ended June 30, 2010 was primarily related to the extinguishment of the swap liability described above. Other income of $243 million for the six months ended June 30, 2009 included a favorable court decision on a legal dispute in which Eletropaulo, the Company’s utility business in Brazil, had requested reimbursement for excess non-income taxes paid from 1989 to 1992. Eletropaulo received reimbursement in the form of tax credits to be applied against future tax liabilities resulting in a $129 million gain. The net impact to the Company after noncontrolling interests was $21 million. In addition, the Company recognized income of $80 million in 2009 from a performance incentive bonus for management services provided to Ekibastuz and Maikuben in 2008. The management agreement was related to the sale of these businesses in Kazakhstan in May 2008.

Gain on sale of investments

There was no gain on sale of investments for the three months ended June 30, 2010. Gain on sale of investments for the three months ended June 30, 2009 was $102 million which primarily consisted of $98 million recognized in May 2009 related to the termination of the management agreement between the Company and Kazakhmys PLC for Ekibastuz and Maikuben.

There was no gain on sale of investments for the six months ended June 30, 2010. Gain on sale of investments for the six months ended June 30, 2009 was $115 million which primarily consisted of $13 million from the reversal of a contingent liability in March 2009 related to the Kazakhstan sale in addition to the $98 million described above.

Foreign currency transaction gains (losses) on net monetary position

Foreign currency transaction gains (losses) were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in millions)						(in millions)
AES Corporation	$	(54	)	$	15		$	(86	)	$	(11	)
Chile		(11	)		29			(20	)		55
Brazil		(6	)		4			(13	)		(3	)
Argentina		18			(3	)		13			(12	)
Kazakhstan		-			(12	)		1			(27	)
Colombia		(1	)		(11	)		(6	)		(5	)
Other		(17	)		6			(11	)		(8	)

Total⁽¹⁾	$	(71	)	$	28		$	(122	)	$	(11	)

⁽¹⁾

Includes $22 million and $(23) million gains (losses) on foreign currency derivative contracts for the three months ended June 30, 2010 and 2009, respectively, and includes $17 million and $(34) million gains (losses) on foreign currency derivative contracts for the six months ended June 30, 2010 and 2009, respectively.

The Company recognized foreign currency transaction losses of $71 million for the three months ended June 30, 2010. These consisted primarily of losses at The AES Corporation and in Chile, partially offset by gains in Argentina.

•

Losses of $54 million at The AES Corporation were primarily due to the devaluation of notes receivable and cash balances denominated in Euros.

•

Losses of $11 million in Chile were primarily due to a 4% devaluation of the Chilean Peso, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with net working capital denominated in Chilean Pesos, primarily cash, accounts receivable and tax receivables. These losses were partially offset by a $4 million gain on foreign currency derivatives.

•

Gains of $18 million in Argentina were primarily due to a gain on a foreign currency embedded derivative related to government receivables, partially offset by losses due to the devaluation of the Argentine Peso by 1%, resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt.

The Company recognized foreign currency transaction gains of $28 million for the three months ended June 30, 2009. These consisted primarily of gains in Chile, The AES Corporation and Brazil, partially offset by losses in Kazakhstan, Colombia and Argentina.

•

Gains of $29 million in Chile were primarily due to the appreciation of the Chilean Peso by 9%, resulting in gains at Gener (a U.S. Dollar functional currency subsidiary) associated with net working capital denominated in Chilean Pesos, mainly cash and accounts receivable. This gain was partially offset by a $3 million loss on foreign currency derivatives.

•

Gains of $15 million at The AES Corporation were primarily due to the strengthening of the Euro and British Pound during the quarter, resulting in gains on outstanding notes receivable, which were partially offset by losses on third party debt denominated in the British Pound.

•

Losses of $12 million in Kazakhstan were primarily due to net foreign currency transaction losses related to energy sales denominated and fixed in the U.S. Dollar.

•

Losses of $11 million in Colombia were primarily due to the appreciation of the Colombian Peso by 16%, resulting in losses at Chivor (a U.S. Dollar functional currency subsidiary) associated with its Colombian Peso denominated debt and a $3 million loss on foreign currency derivatives.

The Company recognized foreign currency transaction losses of $122 million for the six months ended June 30, 2010. These consisted primarily of losses at The AES Corporation, in Chile and Brazil, partially offset by gains in Argentina.

•

Losses of $85 million at The AES Corporation were primarily due to the devaluation of notes receivable and cash balances denominated in Euros, partially offset by gains on third-party debt denominated in the British Pound.

•

Losses of $20 million in Chile were primarily due to an 8% devaluation of the Chilean Peso, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with net working capital denominated in Chilean Pesos, primarily cash, accounts receivables and tax receivables. These losses were partially offset by a $7 million gain on foreign currency derivatives.

•

Losses of $13 million in Brazil were primarily due to the realization of deferred exchange variances on past energy purchases made by Eletropaulo denominated in U.S. Dollar, resulting in foreign currency transaction losses of $10 million. In addition, the devaluation of the Brazilian Real by 3% resulted in losses of $3 million associated with U.S. Dollar denominated payables.

•

Gains of $13 million in Argentina were primarily due to a gain on a foreign currency embedded derivative related to government receivables, partially offset by losses related to the devaluation of the Argentine Peso by 3%, resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt.

The Company recognized foreign currency transaction losses of $11 million for the six months ended June 30, 2009. These consisted primarily of losses in Kazakhstan, The AES Corporation, Argentina, the Philippines, Colombia and Brazil, partially offset by gains in Chile.

•

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

•

Losses of $11 million at The AES Corporation were primarily due to the strengthening of the British Pound during the period resulting in losses related to outstanding third party debt denominated in the British Pound.

•

Losses of $12 million in Argentina were primarily due to the devaluation of the Argentine Peso by 10% mainly resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt, partially offset by a $2 million gain on derivative instruments; and also affecting Termoandes (a U.S. Dollar functional currency subsidiary) resulting in losses associated with its trade and tax receivables denominated in the Argentine Peso.

•

Gains of $55 million in Chile were primarily due to the appreciation of the Chilean Peso by 16%, resulting in gains at Gener (a U.S. Dollar functional currency subsidiary) associated with its net working capital denominated in Chilean Peso, mainly cash and accounts receivable. This gain was partially offset by a $14 million loss on foreign currency derivatives.

Other non-operating expense

Other non-operating expense of $5 million for the three months ended June 30, 2010 primarily consisted of an other-than-temporary impairment of an equity method investment. There was no other non-operating expense for the three months ended June 30, 2009.

Other non-operating expense of $5 million for the six months ended June 30, 2010 primarily consisted of an other-than-temporary impairment of an equity method investment. Other non-operating expense of $10 million for the six months ended June 30, 2009 primarily consisted of an other-than-temporary impairment of a cost method investment.

Income tax expense

Income tax expense on continuing operations increased $150 million, or 143%, to $255 million for the three months ended June 30, 2010 compared to $105 million for the three months ended June 30, 2009. The Company’s effective tax rates were 48% and 19% for the three months ended June 30, 2010 and 2009, respectively.

The net increase in the effective tax rate for the three months ended June 30, 2010 compared to the same period in 2009 was primarily due to expense recorded in the second quarter of 2010 relating to the CEMIG sale transaction and the increase in U.S. taxes owing to the expiration at December 31, 2009 of a favorable U.S. tax law impacting distributions from certain non-U.S. subsidiaries as well as a tax benefit recorded in the second quarter of 2009 upon the release of valuation allowances at a U.S. and a Brazilian subsidiary. Included in the net tax expense relating to the CEMIG sale is tax expense on the equity earnings associated with the reversal of the net long-term liability and tax benefit upon the release of a valuation allowance against deferred tax assets.

Income tax expense on continuing operations increased $172 million, or 62%, to $451 million for the six months ended June 30, 2010 compared to $279 million for the six months ended June 30, 2009. The Company’s effective tax rates were 41% and 23% for the six months ended June 30, 2010 and 2009, respectively.

The net increase in the effective tax rate for the six months ended June 30, 2010 compared to the same period in 2009 was primarily due to expense recorded in the second quarter of 2010 relating to the CEMIG sale transaction and the increase in U.S. taxes owing to the expiration at December 31, 2009 of a favorable U.S. tax law impacting distributions from certain non-U.S. subsidiaries offset by a current year income tax benefit generated by a release of an uncertain tax position reserve at one of our Chilean subsidiaries. Included in the net tax expense relating to the CEMIG sale is tax expense on the equity earnings associated with the reversal of the net long-term liability and tax benefit upon the release of a valuation allowance against deferred tax assets.

Net equity in earnings of affiliates

Net equity in earnings of affiliates increased $84 million, or 168%, to $134 million for the three months ended June 30, 2010. The increase was primarily due to the sale of our interests in CEMIG during the second quarter of 2010, as discussed in Note 6 — Investments In and Advances to Affiliate, partially offset by 2009 equity in earnings of Cartagena which is now a consolidated entity.

Net equity in earnings of affiliates increased $91 million, or 160%, to $148 million for the six months ended June 30, 2010. The increase was primarily due to the above mentioned sale of our interests in CEMIG, partially offset by 2009 equity in earnings of Cartagena which is now a consolidated entity.

Income from continuing operations attributable to noncontrolling interests

Income from continuing operations attributable to noncontrolling interests increased $60 million, or 28%, to $277 million for the three months ended June 30, 2010. The increase was primarily due to a gain associated with the extinguishment of swap liabilities owed by two of our Brazilian subsidiaries.

Income from continuing operations attributable to noncontrolling interests decreased $4 million, or 1%, to $488 million for the six months ended June 30, 2010. The decrease was primarily due to decreased earnings at Itabo and devaluation of the Chilean Peso at Gener, offset by a favorable gain at Tiete and a favorable legal settlement at Eletropaulo.

Discontinued operations

As further discussed in Note 13 — Discontinued Operations and Held for Sale Businesses, discontinued operations includes the results of four businesses: Lal Pir and Pak Gen, generation businesses in Pakistan (sold in

June 2010), Barka, a generation business in Oman (held for sale in December 2009) and Ras Laffan, a generation business in Qatar (held for sale in April 2010). Prior periods have been restated to reflect these businesses within Discontinued Operations for all periods presented.

For the three months ended June 30, 2010 and 2009, income from operations of discontinued businesses, net of tax and income attributable to noncontrolling interests, was $12 million and $17 million, respectively, and reflected the operations of our 55% stake in Lal Pir and Pak Gen, two oil-fired facilities in Pakistan, our 35% stake in Barka, a combined cycle gas facility and water desalination plant in Oman, and our 55% stake in Ras Laffan, a combined cycle gas facility and water desalination plant in Qatar.

For the six months ended June 30, 2010 and 2009, income from operations of discontinued businesses, net of tax and income attributable to noncontrolling interests, was $26 million and $27 million, respectively, and reflected the operations of Lal Pir, Pak Gen, Barka and Ras Laffan. During the six months ended June 30, 2010, the Company recognized impairment expense and a loss on the sale of Lal Pir and Pak Gen of $10 million, net of tax and noncontrolling interests, consisting of $7 million of impairment expense in the first quarter and $3 million loss on sale in the second quarter.

Capital Resources and Liquidity

Overview. In November 2009, the Company announced a binding stock purchase agreement with CIC, to sell 125.5 million shares of AES stock to CIC, representing a 15% ownership stake in the Company. The transaction closed in March 2010 and generated $1.58 billion of new equity to fund future growth opportunities. As further discussed in Note 7 — Debt, a portion of these proceeds were used for the redemption of $400 million aggregate principal of The AES Corporation’s outstanding 8.75% Second Priority Senior Secured Notes due 2013. The Notes were redeemed on a pro rata basis on May 15, 2010 at a redemption price equal to 101.458% of the principal amount redeemed.

As of June 30, 2010, the Company had unrestricted cash and cash equivalents of $2.9 billion and short term investments of $1.7 billion. In addition, we had restricted cash and debt service reserves of $1.2 billion. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $14.6 billion and $5.1 billion, respectively. Of the approximately $1.4 billion of our short-term non-recourse debt, $831 million is presented as current because it is due in the next twelve months and $602 million relates to defaulted debt. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. Approximately $471 million of our recourse debt matures within the next twelve months, which we expect to repay using cash on hand at the Parent Company or through net cash provided by operating activities. See further discussion of Parent Company Liquidity below.

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

We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related

assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks. For more information on our long-term debt, see Note 7 — Debt of the condensed consolidated financial statements included in Item 1. — Financial Statements, of this Form 10-Q.

Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. While the Company believes that this represents an economic hedge, the Company is required to mark-to-market all of these interest rate swaps and other derivatives. Presently, the Parent Company’s only exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility. On a consolidated basis, of the Company’s $19.7 billion of total debt outstanding as of June 30, 2010, approximately $4.7 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate.

In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At June 30, 2010, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $422 million in aggregate (excluding investment commitments and those collateralized by letters of credit and other obligations discussed below).

As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At June 30, 2010, we had $147 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and business operations. These letters of credit were provided under the senior secured credit facility. During the six months ended June 30, 2010, the Company paid letter of credit fees ranging from 3.19% to 3.75% per annum on the outstanding amounts.

We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. See Global Economic Conditions discussion above. If we decide not to

provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.

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

As of June 30, 2010, the Company had approximately $280 million of trade accounts receivable related to some of its generation businesses in Latin America classified as other long-term assets. These consist primarily of trade accounts receivable that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond June 30, 2011, or one year past the balance sheet date. All payments are being received as scheduled and the Company expects all of these receivables to be fully collectible. Additionally, the current portion of these trade accounts receivable was $137 million at June 30, 2010.

Consolidated Cash Flows. At June 30, 2010, cash and cash equivalents increased $1.1 billion from June 30, 2009 to $2.9 billion. The increase in cash and cash equivalents was due to $1.4 billion of cash provided by operating activities, $955 million of cash used for investing activities, $692 million of cash provided by financing activities and the unfavorable effect of foreign currency exchange rates on cash of $44 million.

Operating Activities

Net cash provided by operating activities increased $542 million to $1.4 billion during the six months ended June 30, 2010 compared to $874 million during the six months ended June 30, 2009. This net increase was mainly the result of the following:

•

an increase of $434 million at our Latin American Utilities businesses primarily due to higher gross margin and higher payments in 2009 for the settlement of contingencies and payments made during the first quarter of 2009 on swap agreements made by two of our subsidiaries in Brazil; and

•

an increase of $123 million at our Latin American Generation businesses due to improved accounts receivable collections at certain businesses compared to the prior year combined with higher gross margin ; offset by

•

a decrease of $51 million at our Europe Generation businesses due to the collection of a management incentive bonus of $80 million during 2009 and increased working capital requirements.

Investing Activities

Net cash used for investing activities increased $571 million to $955 million during the six months ended June 30, 2010 compared to net cash used of $384 million during the six months ended June 30, 2009. This net increase was primarily due to the following:

•

an increase of $645 million to $116 million from the purchase of short-term investments, net of sales, for the six months ended June 30, 2010 from $529 million from the sale of short-term investments, net of purchases for the six months ended June 30, 2009. The increase was primarily due to an increase in

net purchases of $380 million at our Brazilian subsidiaries and $87 million at Gener. In addition, there were decreases in net sales of $82 million and $40 million in Alicura and IPALCO, respectively, due to the maturity of investments during the second quarter of 2009;

•

an increase of $74 million in restricted cash balances for the six months ended June 30, 2010 primarily due to increases of $33 million at Masinloc and $32 million at Kilroot; and

•

an increase of $100 million in acquisitions, net of cash acquired, primarily due to $35 million at AES China Hydro related to the acquisition of Jianghe Rural Hydro (JHRH), $32 million related to the purchase of Your Energy Limited and $32 million related to the purchase of Poland Wind; partially offset by

•

an increase of $196 million in proceeds from the sale of businesses for the six months ended June 30, 2010. The increase was partially due to the final settlement proceeds of $99 million received in January 2010 from the termination of a management agreement with Kazakhmys in Kazakhstan related to Ekibastuz and Maikuben which were sold in May 2008 and the net proceeds from the sale of Lal Pir and Pak Gen in Pakistan of $100 million;

•

a decrease of $191 million in capital expenditures to $1 billion for the six months ended June 30, 2010. This was primarily due to an overall decrease in expenditures of $113 million at our Europe wind generation projects, $60 million at our U.S. wind generation projects, $32 million at Gener and $18 million each at Panama, Sonel and Jordan. These decreases were partially offset by a net increase in capital expenditures of $63 million at our Brazilian subsidiaries;

•

an increase of $132 million in proceeds from loan repayments for the six months ended June 30, 2010 which represented a payment received for the Brazil Wind note receivable. There were no proceeds from loan repayments for the six months ended June 30, 2009; and

•

a decrease of $83 million in cash used for advances to affiliates and equity investments and other investing activities due to a $64 million decrease in equity investments in AES Solar.

Financing Activities

Net cash provided by financing activities increased $361 million to $692 million during the six months ended June 30, 2010 compared to $331 million during the six months ended June 30, 2009. This net increase was primarily due to the following:

•

a $1.6 billion issuance of common stock, net of transaction costs;

•

a $119 million increase in net borrowings under revolving credit facilities to $88 million for the first six months ended June 30, 2010 compared to net repayments under revolving credit facilities of $31 million for the first six months ended June 30, 2009. The increase was primarily due to decreases in repayments of $61 million at Lal Pir and Pak Gen in Pakistan, $31 million at IPALCO to pay off a working capital line of credit in 2009 and $28 million at Alicura, offset by a decrease in borrowings of $19 million at Panama;

•

an increase of $24 million from issuances of recourse and non-recourse debt primarily due to an increase of $945 million at our Brazilian businesses, partially offset by decreases of $503 million at Arlington, $119 million at Gener, $122 million at IPALCO, $96 million at Sonel and $59 million at our European wind businesses; partially offset by

•

a $1.1 billion increase in repayments of recourse and non-recourse debt, predominately due to increases of $793 million at our Brazilian businesses, $252 million at Corporate, $31 million at Chigen, $30

million at Masinloc in the Philippines, $34 million at our European wind businesses and $27 million at Puerto Rico, partially offset by a $132 million decrease at IPALCO;

•

a $208 million increase in distributions to noncontrolling interests, primarily due to dividend distributions of $81 million at our Brazilian businesses, $69 million at Armenia Mountain and $39 million at Oasis Cayman; and

•

a $74 million decrease in contributions from noncontrolling interests primarily due to a reduction of contributions at Gener.

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

•

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

•

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

•

proceeds from asset sales.

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

•

interest;

•

principal repayments of debt;

•

acquisitions;

•

construction commitments;

•

other equity commitments;

•

taxes; and

•

Parent Company overhead and development costs.

The Company defines Parent Company Liquidity as cash available to the Parent Company and qualified holding companies plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents” at June 30, 2010 and December 31, 2009 as follows:


Parent Company Liquidity	June 30, 2010			December 31, 2009
	(in millions)
Consolidated cash and cash equivalents	$	2,891		$	1,782
Less: Cash and cash equivalents at subsidiaries		(1,115	)		(1,105	)

Parent and qualified holding companies cash and cash equivalents		1,776			677

Commitments under Parent credit facilities		605			785
Less: Borrowings and letters of credit under the credit facilities		(147	)		(204	)

Borrowings available under Parent credit facilities		458			581

Total Parent Company Liquidity	$	2,234	⁽¹⁾	$	1,258

⁽¹⁾

The increase in Parent Company Liquidity from December 31, 2009 to June 30, 2010 is primarily driven by $1.6 billion of cash proceeds from the share issuance in March 2010.

The following table summarizes our Parent Company contingent contractual obligations as of June 30, 2010:


Contingent contractual obligations	Amount		Number of Agreements	Maximum Exposure Range for Each Agreement
	(in millions)			(in millions)
Guarantees	$	422	26	< $1 - $57
Letters of credit under the senior secured credit facility		147	31	< $1 - $67

Total	$	569	57

As of June 30, 2010, the Company had $81 million of commitments to invest in subsidiaries under construction and to purchase related equipment, excluding $78 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: $41 million in 2010 and $40 million in 2011. The exact payment schedules will be dictated by the construction milestones. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.

We have a diverse portfolio of performance related contingent contractual obligations. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, subsidiary default, political risk, tax indemnities, spot market power prices, supplies support and liquidated damages under power sales agreements for projects in development, in operation and under construction. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations during 2010 or beyond, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.

While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets (see “Key Trends and Uncertainties” and “Global Economic Conditions”),

the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured credit facility. See Item 1A. — Risk Factors, “The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.” of the 2009 Form 10-K.

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

•

limitations on other indebtedness, liens, investments and guarantees;

•

limitations on dividends, stock repurchases and other equity transactions;

•

restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements;

•

maintenance of certain financial ratios; and

•

financial and other reporting requirements.

As of June 30, 2010, we were in compliance with these covenants at the Parent Company level.

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 June 30, 2010 is $290 million.

Debt Covenants and Defaults:

While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:

•

reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the parent level during the time period of any default;

•

triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;

•

causing us to record a loss in the event the lender forecloses on the assets; and

•

triggering defaults in our outstanding debt at the parent level.

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

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying condensed consolidated balance sheets amounts to $1.4 billion. The portion of current debt related to such defaults was $602 million at June 30, 2010, all of which was non-recourse debt related to six subsidiaries — Sonel, Jordan, St. Patrick, Kelanitissa, Ebute and Aixi.

None of the subsidiaries that are currently in default are subsidiaries that currently meet the applicable definition of materiality in AES’s corporate debt agreements in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. At June 30, 2010, none of our subsidiaries that are currently in default met the definition of material subsidiary under our recourse senior secured credit facility or other 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 our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the AES Parent Company’s outstanding debt securities.

Critical Accounting Policies and Estimates

The condensed consolidated financial statements of AES are prepared in conformity with generally accepted accounting principles in the United States of America, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. The Company’s significant accounting policies are described in Note 1 — General and Summary of Significant Accounting Policies to the consolidated financial statements included in the Company’s 2009 Form 10-K. The Company’s critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s 2009 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods.

The Company has reviewed and determined that those policies remain the Company’s critical accounting policies as of and for the six months ended June 30, 2010. The only significant change to our critical accounting policies and estimates is the adoption of accounting guidance for the consolidation of variable interest entities effective January 1, 2010. See further discussion of the Company’s policy in Item 1. Financial Statements, Notes to Condensed Consolidated Financial Statements, Note 1 — Financial Statement Presentation in this Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks

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

These disclosures set forth in this Item 3 are based upon a number of assumptions, and actual impacts to the Company may not follow the assumptions made by the Company. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 3. For further information regarding market risk, see Item 1A. — Risk Factors, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations,” “Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance,” and “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” in the Company’s 2009 Form 10-K.

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, a portion of our current and expected future revenue is derived from businesses without significant long-term revenue or supply contracts. These businesses subject our operational results to the volatility of prices for electricity, fuel and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options.

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

AES businesses will see variance in margin performance as global commodity prices shift. For the remainder of 2010, we project pre-tax earnings exposure of approximately $15 million for a $10/barrel move in oil, $25 million for $1/MMBTU move in natural gas and $10 million for a $10/ton shift in coal prices. These estimates exclude correlation. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal prices if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed.

Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Generation costs can be directly affected by movements in the price of natural gas, oil, and coal. Spot power prices and contract indexation provisions are affected by these same commodity price movements. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. Variance is not perfectly linear or symmetric. The sensitivities are affected by a number of non-market, or indirect market factors. Examples of these factors include hydrology,

energy market supply/demand balances, regional fuel supply issues and regulator interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, power plants may reduce dispatch in low market environments limiting downside exposure. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices.

Our larger contributors to commodity risk include the North American businesses of Eastern Energy, Deepwater and wholesale power sales of IPL; the Latin American businesses in Chile, Argentina, the Dominican Republic and Panama; and the Masinloc business in Asia.

In North America, the variance is due to “dark spread” to the extent a portion of sales are un-hedged. Natural gas-fired generators set power prices for many periods so higher natural gas prices expand margins and higher coal prices cause a decline. The positive impact on margins will be moderated if natural-gas fired generators set the market price only during certain peak periods. IPL sells power at wholesale rates once retail demand is served so retail sales demand may affect commodity exposure.

In Chile, we own assets and have associated contracts in both the central and northern regions of the country. Contracts tend to be long-term and indexed to fuel which limits commodity risk. Oil-fired generators set power prices for some periods so lower oil prices can erode margins on spot power market sales. Gener has been adding coal-fired generation in response to the Argentine gas crisis, increasing its exposure to dark spreads on un-hedged volumes. Gener also owns natural gas/diesel, hydropower and biomass generation facilities.

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

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

Foreign Exchange Rate Risk

In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in U.S. Dollar or currencies other than their own functional currencies. Primarily, we are exposed to changes in the exchange rate between the U.S. Dollar and the following currencies: Argentine Peso, Brazilian Real, British Pound, Cameroonian Franc, Chilean Peso, Colombian Peso, Euro, Kazakhstani Tenge, Mexican Peso, and Philippine Peso. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.

During the three months ended June 30, 2010, we entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. Given a 10% U.S. Dollar appreciation, pre-tax earnings attributable to foreign subsidiaries exposed to movements in the exchange rates of the Argentinean Peso, Brazilian Real, Colombian Peso, and Euro (the earnings attributable to subsidiaries exposed to Cameroonian Franc movements are included under Euro due to the fixed exchange rate of the Cameroonian

Franc to the Euro) relative to the U.S. Dollar are projected to be $2 million, $12 million, $2 million and $4 million, respectively, for the remainder of 2010. Total AES pre-tax earnings for the remainder of 2010 would be reduced by approximately $15 million on a correlated basis. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to exposed pre-tax earnings for the remainder of 2010 coming from subsidiaries where the local currency is either not the U.S. Dollar or is not exhibiting the characteristics of a peg or managed float relative to the U.S. Dollar, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses and the correlation effect is based on historical foreign exchange rate movement over a period equal in length to the period over which the simulated move occurs. These sensitivities may change in the future as new hedges are executed or existing hedges unwind. Additionally, updates to the forecasted pre-tax earnings exposed to foreign exchange risk may result in further modification.

Interest Rate Risks

We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt, as well as interest rate swap, cap and floor and option agreements.

Decisions on the fixed-floating debt ratio are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing.

As of June 30, 2010, the portfolio’s pre-tax earnings exposure for the remainder of 2010 (adjusted to reflect non-controlling interests) to a one-time 100 basis point increase in Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro, Philippine Peso, Ukraine Hryvnia and U.S. Dollar interest rates is approximately $10 million. The debt denominated in these currencies together account for more than 99% of the portfolio’s floating-rate debt, which is primarily non-recourse financing. The numbers do not take into account the historical correlation between these interest rates.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective as of June 30, 2010 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Controls Over Financial Reporting

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

PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is involved in certain claims, suits and legal proceedings in the normal course of business, some of which are described Note 8 — Contingencies and Commitments of the condensed consolidated financial statements included in Item 1. — Financial Statements of this Form 10-Q. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of June 30, 2010. See Note 8 — Contingencies and Commitments of the condensed consolidated financial statements included in Item 1. — Financial Statements, of this Form 10-Q for additional information regarding these claims and proceedings.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2009 Form 10-K.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. REMOVED AND RESERVED

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS


10.1		Amendment No. 2 dated as of July 29, 2010, to the Fourth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2008, which is incorporated herein by reference to the Company’s Form 8-K filed on July 30, 2010.

10.1.A		Fifth Amended and Restated Credit And Reimbursement Agreement dated as of July 29, 2010 among The AES Corporation, a Delaware corporation, the Subsidiary Guarantors listed therein, the Banks listed on the signature pages thereof, Citicorp USA, Inc., as Administrative Agent, Citibank, N.A. as Collateral Agent, Citigroup Global Markets Inc., as Lead Arranger and Book Runner, Banc of America Securities LLC, as Lead Arranger and Book Runner and Co-Syndication Agent, Barclays Capital, as Lead Arranger and Book Runner and Co-Syndication Agent, RBS Securities Inc., as Lead Arranger and Book Runner and Co-Syndication Agent, RBS Securities Inc., as Lead Arranger and Book Runner and Co-Syndication Agent, and Union Bank, N.A., as Lead Arranger and Book Runner and Co-Syndication Agent is incorporated herein by reference to the Company’s Form 8-K filed on 30, 2010.


10.1.B		Appendices and Exhibits to the Fifth Amended and Restated Credit and Reimbursement Agreement dated as of July 29, 2010 is incorporated herein by reference to the Company’s Form 8-K filed on July 30, 2010.

31.1		Rule13a-14(a)/15d-14(a) Certification of Paul Hanrahan (filed herewith).

31.2		Rule 13a-14(a)/15d-14(a) Certification of Victoria D. Harker (filed herewith).

32.1		Section 1350 Certification of Paul Hanrahan (filed herewith).

32.2		Section 1350 Certification of Victoria D. Harker (filed herewith).

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

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


	THE AES CORPORATION (Registrant)

Date: August 5, 2010	By:	/s/ VICTORIA D. HARKER
		Name:	Victoria D. Harker
		Title:	Executive Vice President and Chief Financial Officer (Principal Financial Officer)

	By:	/s/ MARY E. WOOD
		Name:	Mary E. Wood
		Title:	Vice President and Controller (Principal Accounting Officer)