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, 2009

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, at August 3, 2009, and was 667,006,929.

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED June 30, 2009

TABLE OF CONTENTS


PART I: FINANCIAL INFORMATION		3

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

*ITEM 2.*	*MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*	43

*ITEM 3.*	*QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK*	74

*ITEM 4.*	*CONTROLS AND PROCEDURES*	76

PART II: OTHER INFORMATION		77

*ITEM 1.*	*LEGAL PROCEEDINGS*	77

*ITEM 1A.*	*RISK FACTORS*	77

*ITEM 2.*	*UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS*	77

*ITEM 3.*	*DEFAULTS UPON SENIOR SECURITIES*	77

*ITEM 4.*	*SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS*	77

*ITEM 5.*	*OTHER INFORMATION*	77

*ITEM 6.*	*EXHIBITS*	77

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,
	2009			2008			2009			2008
	(in millions, except per share data)
Revenues:
Regulated	$	1,782		$	2,039		$	3,450		$	3,954
Non-regulated		1,713			2,087			3,423			4,253

Total revenues		3,495			4,126			6,873			8,207

Cost of Sales:
Regulated		(1,317	)		(1,452	)		(2,545	)		(2,807	)
Non-regulated		(1,331	)		(1,645	)		(2,598	)		(3,329	)

Total cost of sales		(2,648	)		(3,097	)		(5,143	)		(6,136	)

Gross margin		847			1,029			1,730			2,071
General and administrative expenses		(88	)		(99	)		(173	)		(197	)
Interest expense		(383	)		(469	)		(774	)		(904	)
Interest income		90			133			188			249
Other expense		(30	)		(85	)		(52	)		(110	)
Other income		22			150			244			195
Gain on sale of investments		102			908			115			912
Impairment expense		(1	)		(25	)		(1	)		(72	)
Foreign currency transaction gains (losses) on net monetary position		27			(85	)		(12	)		(63	)
Other non-operating expense		-			-			(10	)		-

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EQUITY IN EARNINGS OF AFFILIATES		586			1,457			1,255			2,081
Income tax expense		(105	)		(318	)		(280	)		(557	)
Net equity in earnings of affiliates		50			20			57			42

INCOME FROM CONTINUING OPERATIONS		531			1,159			1,032			1,566
Income from operations of discontinued businesses, net of income tax benefit of $—, $1, $— and $—, respectively		-			1			-			3
Loss from disposal of discontinued businesses, net of income tax expense of $—, $—, $— and $—, respectively		-			-			-			(1	)

NET INCOME		531			1,160			1,032			1,568
Less: Net income attributable to noncontrolling interests		(228	)		(257	)		(511	)		(432	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	303		$	903		$	521		$	1,136

BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockolders, net of tax	$	0.45		$	1.34		$	0.78		$	1.69
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		-			-			-			-

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.45		$	1.34		$	0.78		$	1.69

DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.45		$	1.31		$	0.78		$	1.65
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		-			-			-			-

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.45		$	1.31		$	0.78		$	1.65

AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	303		$	902		$	521		$	1,134
Discontinued operations, net of tax		-			1			-			2

Net income	$	303		$	903		$	521		$	1,136

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Balance Sheets


	June 30, 2009			December 31, 2008
	(in millions except share and per share data)
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,735		$	903
Restricted cash		444			729
Short-term investments		1,152			1,382
Accounts receivable, net of allowance for doubtful accounts of $260 and $254, respectively		2,293			2,233
Inventory		577			564
Receivable from affiliates		21			31
Deferred income taxes—current		201			180
Prepaid expenses		350			177
Other current assets		1,249			1,117

Total current assets		8,022			7,316

NONCURRENT ASSETS
Property, plant and equipment:
Land		1,024			854
Electric generation and distribution assets, and other		26,427			24,654
Accumulated depreciation		(8,368	)		(7,515	)
Construction in progress		3,971			3,410

Property, plant and equipment, net		23,054			21,403

Other assets:
Deferred financing costs, net of accumulated amortization of $273 and $272, respectively		392			366
Investments in and advances to affiliates		1,043			901
Debt service reserves and other deposits		655			636
Goodwill		1,430			1,421
Other intangible assets, net of accumulated amortization of $191 and $185, respectively		486			500
Deferred income taxes—noncurrent		633			567
Other assets		1,703			1,696

Total other assets		6,342			6,087

TOTAL ASSETS	$	37,418		$	34,806

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	1,038		$	1,042
Accrued interest		270			252
Accrued and other liabilities		2,705			2,660
Non-recourse debt—current		1,384			1,074
Recourse debt—current		-			154

Total current liabilities		5,397			5,182

LONG-TERM LIABILITIES
Non-recourse debt—noncurrent		12,321			11,869
Recourse debt—noncurrent		5,515			4,994
Deferred income taxes—noncurrent		1,237			1,132
Pension and other post-retirement liabilities		1,110			1,017
Other long-term liabilities		3,547			3,525

Total long-term liabilities		23,730			22,537

Commitments and contingent liabilities (see Note 8)
Cumulative preferred stock of subsidiary		60			60
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($.01 par value, 1,200,000,000 shares authorized; 676,362,823 issued and 666,828,233 outstanding at June 30, 2009; 673,478,012 issued and 662,786,745 outstanding at December 31, 2008)		7			7
Additional paid-in capital		6,845			6,832
Retained earnings (accumulated deficit)		513			(8	)
Accumulated other comprehensive loss		(2,847	)		(3,018	)
Treasury stock, at cost (9,534,590 and 10,691,267 shares at June 30, 2009 and December 31, 2008, respectively)		(126	)		(144	)

Total The AES Corporation stockholders’ equity		4,392			3,669
NONCONTROLLING INTERESTS		3,839			3,358

Total equity		8,231			7,027

TOTAL LIABILITIES AND EQUITY	$	37,418		$	34,806

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
	2009			2008
	(in millions)
OPERATING ACTIVITIES:
Net income	$	1,032		$	1,568
Adjustments to net income:
Depreciation and amortization		498			500
Gain from sale of investments and impairment expense		(103	)		(850	)
Provision for deferred taxes		(111	)		208
Settlement of non-cash contingencies		(54	)		(35	)
(Gain) loss on the extinguishment of debt		(3	)		55
Other		4			(120	)
Changes in operating assets and liabilities:
Increase in accounts receivable		(3	)		(243	)
Increase in inventory		(11	)		(79	)
Decrease (increase) in prepaid expenses and other current assets		31			(217	)
Increase in other assets		(139	)		(121	)
Decrease in accounts payable and accrued liabilities		(292	)		(15	)
Increase in income tax receivables and payables, net		54			89
(Decrease) increase in other long-term liabilities		(32	)		44

Net cash provided by operating activities		871			784

INVESTING ACTIVITIES:
Capital expenditures		(1,193	)		(1,385	)
Acquisitions—net of cash acquired		-			(1,137	)
Proceeds from the sales of businesses		2			1,093
Proceeds from the sales of assets		4			80
Sale of short-term investments		2,269			2,888
Purchase of short-term investments		(1,740	)		(2,887	)
Decrease in restricted cash		305			2
Decrease (increase) in debt service reserves and other assets		40			(60	)
Affiliate advances and equity investments		(87	)		(148	)
Loan advances		-			(173	)
Other investing		16			92

Net cash used in investing activities		(384	)		(1,635	)

FINANCING ACTIVITIES:
(Repayments) borrowings under the revolving credit facilities, net		(31	)		199
Issuance of recourse debt		503			625
Issuance of non-recourse debt		816			1,566
Repayments of recourse debt		(154	)		(1,037	)
Repayments of non-recourse debt		(491	)		(674	)
Payments for deferred financing costs		(53	)		(36	)
Distributions to noncontrolling interests		(334	)		(244	)
Contributions from noncontrolling interests		74			161
Financed capital expenditures		(24	)		(51	)
Other financing		25			17

Net cash provided by financing activities		331			526
Effect of exchange rate changes on cash		14			3

Total increase (decrease) in cash and cash equivalents		832			(322	)
Cash and cash equivalents, beginning		903			2,043

Cash and cash equivalents, ending	$	1,735		$	1,721

SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	697		$	832
Cash payments for income taxes, net of refunds	$	306		$	233
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Assets acquired in noncash asset exchange	$	110		$	-
Assets acquired in acquisition of subsidiary	$	-		$	946
Non-recourse debt assumed in acquisition of subsidiary	$	-		$	12
Liabilities assumed in acquisition of subsidiary	$	-		$	7

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statements of Changes in Equity

(Unaudited)


	THE AES CORPORATION STOCKHOLDERS										Noncontrolling Interests		Consolidated Comprehensive Income
	Common Stock		Treasury Stock		Additional Paid-In Capital		(Accumulated Deficit) Retained Earnings		Accumulated Other Comprehensive Loss
	Common Stock		Treasury Stock		Additional Paid-In Capital		(Accumulated Deficit) Retained Earnings		Accumulated Other Comprehensive Loss
Balance at January 1, 2009	$	7	$	(144)	$	6,832	$	(8)	$	(3,018)	$	3,358
Comprehensive income
Net income		-		-		-		521		-		511		1,032
Foreign currency translation adjustment, net of income tax		-		-		-		-		65		268		333
Change in derivative fair value (including a reclassification to earnings of $(43), net of income tax)		-		-		-		-		104		39		143
Change in unfunded pension obligation, net of income tax		-		-		-		-		2		-		2

Other comprehensive income														478

Total comprehensive income													$	1,510

Capital contributions from noncontrolling interests		-		-		-		-		-		75
Dividends paid to noncontrolling interests		-		-		-		-		-		(412)
Issuance of common stock under benefit plans and exercise of stock options		-		18		5		-		-		-
Stock compensation		-		-		8		-		-		-

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


	THE AES CORPORATION STOCKHOLDERS
	Common Stock		Additional Paid-In Capital		(Accumulated Deficit) Retained Earnings		Accumulated Other Comprehensive Loss		Noncontrolling Interests		Consolidated Comprehensive Income
	Common Stock		Additional Paid-In Capital		(Accumulated Deficit) Retained Earnings		Accumulated Other Comprehensive Loss		Noncontrolling Interests		Consolidated Comprehensive Income
Balance at January 1, 2008	$	7	$	6,776	$	(1,241)	$	(2,378)	$	3,241
Comprehensive income
Net income		-		-		1,136		-		432		1,568
Change in fair value of available-for-sale securities, net of income tax		-		-		-		(1)		-		(1)
Foreign currency translation adjustment, net of income tax		-		-		-		97		193		290
Change in derivative fair value (including a reclassification to earnings of $— million, net of income tax)		-		-		-		(145)		(1)		(146)
Change in unfunded pension obligation, net of income tax		-		-		-		(5)		(6)		(11)

Other comprehensive income												132

Total comprehensive income											$	1,700

Capital contributions from noncontrolling interests		-		-		-		-		165
Dividends declared to noncontrolling interests		-		-		-		-		(215)
Issuance of common stock under benefit plans and exercise of stock options		-		27		-		-		-
Stock compensation		-		16		-		-		-

Balance at June 30, 2008	$	7	$	6,819	$	(105)	$	(2,432)	$	3,809

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, 2009 and 2008

1. FINANCIAL STATEMENT PRESENTATION

The prior period condensed consolidated financial statements in this Quarterly Report have been reclassified to reflect the financial statement presentation requirements of Statement of Financial Accounting Standard (“FAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (“FAS No. 160”), the new reportable segment structure discussed in Note 11 — Segments and businesses held for sale and discontinued operations as discussed in Note 13 — Discontinued Operations. In addition, certain immaterial prior period amounts have been reclassified within the condensed consolidated financial statements to conform to current period presentation.

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. 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”) 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 and cash flows. The results of operations for the three and six months ended June 30, 2009, are not necessarily indicative of results that may be expected for the year ending December 31, 2009. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2008 audited consolidated financial statements and notes thereto, which are included in the 2008 Form 10-K, as filed with the SEC on February 26, 2009.

Significant New Accounting Policies

Noncontrolling Interests

Effective January 1, 2009, the Company adopted FAS No. 160, which changed the accounting for and the reporting of minority interest, now referred to as noncontrolling interests, in the Company’s condensed consolidated financial statements. The adoption of FAS No. 160 resulted in the reclassification of amounts previously attributable to minority interest to a separate component of stockholders’ equity titled “Noncontrolling Interests” in the accompanying condensed consolidated balance sheets and statements of changes in equity. Additionally, net income and comprehensive income attributable to noncontrolling interests are shown separately from consolidated net income and comprehensive income in the accompanying condensed consolidated statements of operations and statements of changes in equity. Prior period financial statements have been reclassified to conform to the current year presentation as required by FAS No. 160.

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

FAS No. 160 significantly revises the provisions of Accounting Research Bulletin (“ARB”) No. 51, Consolidated Financial Statements. Under FAS No. 160, losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests’ basis has been reduced to zero. Prior to the implementation of FAS No. 160, losses that otherwise would have been attributed to the noncontrolling interests were allocated to the controlling interest after the associated noncontrolling interests’ basis was reduced to zero. The Company had no material losses that it did not allocate to noncontrolling interests prior to the adoption of FAS No. 160 and the adoption did not have a material impact.

FAS No. 160 requires a change in a parent’s ownership interest in a subsidiary when the parent retains its controlling financial interest to be accounted for as an equity transaction. Gains or losses from such transactions are no longer recognized in net income and the carrying values of the subsidiary’s assets (including goodwill) and liabilities are not adjusted. SEC Staff Accounting Bulletin (“SAB”) No. 51, Accounting for Sales of Stock by a Subsidiary (“SAB 51”), had previously provided an option in certain circumstances for a parent to recognize a gain or loss on the sale of stock by a subsidiary or account for the sale as an equity transaction. In certain transactions, AES had previously elected the option to recognize a gain or loss under SAB 51. This option is no longer available under FAS No. 160.

A parent company deconsolidates a subsidiary when that parent company no longer controls the subsidiary. When control is lost, the parent-subsidiary relationship no longer exists and the parent derecognizes the assets and liabilities of the subsidiary. In accordance with FAS No. 160, if the parent company retains a noncontrolling interest, the remaining noncontrolling investment in the subsidiary is remeasured at fair value and is included in the gain or loss recognized upon the deconsolidation of the subsidiary. Under SAB 51, the retained noncontrolling interest in the subsidiary was not adjusted to fair value.

New Accounting Pronouncements

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

FAS No. 166, Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140 (“FAS No. 166”)

In June 2009, the FASB issued FAS No. 166, which removes the concept of a qualifying special-purpose entity (“QSPE”) from FAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities-a replacement of FASB Statement No. 125. The QSPE concept had initially been established to facilitate off-balance sheet treatment for certain securitizations. FAS No. 166 also removes the exception from applying FASB Interpretation (“FIN”) No. 46(R), Consolidation of Variable Interest Entities (“FIN No. 46(R)”), to QSPEs. FAS No. 166 is effective for fiscal years beginning after November 15, 2009, or January 1, 2010 for AES. AES does not believe the adoption of FAS No. 166 will have a material impact on the Company’s financial statements.

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

In June 2009, the FASB issued FAS No. 167, which amends FIN 46(R) to among other things, require an entity to qualitatively rather than quantitatively assess the determination of the primary beneficiary of a variable interest entity (“VIE”). This determination should be based on whether the entity has 1) the power to direct matters that most significantly impact the activities of the VIE and 2) the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Other key changes include: the

requirement for an ongoing reconsideration of the primary beneficiary, the criteria for determining whether service provider or decision maker contracts are variable interests, the consideration of kick-out and removal rights in determining whether an entity is a VIE, the types of events that trigger the reassessment of whether an entity is a VIE and the expansion of the disclosures previously required under FASB Staff Position (“FSP”) FAS 140-4 and FIN 46(R), Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities. These disclosures were provided in the Company’s 2008 Form 10-K. The impact of the adoption of FAS No. 167 may be applied retrospectively with a cumulative-effect adjustment to retained earnings as of the beginning of the first year restated, or through a cumulative-effect adjustment on the date of adoption. FAS No. 167 is effective for fiscal years beginning after November 15, 2009, or January 1, 2010 for AES. Early adoption is prohibited. AES is currently reviewing the potential impact of FAS No. 167, but at this time cannot determine the impact on the Company’s financial statements.

FAS No. 168, FASB Codification and the Hierarchy of GAAP (“FAS No. 168”)

In June 2009, the FASB issued FAS No. 168, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with U.S. GAAP. FAS No. 168 replaces FAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, and establishes the FASB Accounting Standards Codification (“the Codification”) as the single source of authoritative guidance recognized by the FASB. Under the Codification, all guidance carries an equal level of authority. FAS No. 168 is effective for interim and annual periods ending after September 15, 2009, or the quarter ending September 30, 2009 for AES.

2. INVENTORY

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


	June 30, 2009		December 31, 2008
	(in millions)
Coal, fuel oil and other raw materials	$	300	$	311
Spare parts and supplies		277		253

Total	$	577	$	564

3. FAIR VALUE DISCLOSURES

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”) which amended FAS No. 107, Disclosures about Fair Value of Financial Instruments and APB Opinion No. 28, Interim Financial Reporting, to require disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements. AES has incorporated these additional disclosures into this Form 10-Q.

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


	June 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Assets
Marketable securities⁽¹⁾	$	1,194	$	1,194	$	1,413	$	1,413
Derivatives⁽²⁾		215		215		350		350

Total assets	$	1,409	$	1,409	$	1,763	$	1,763

Liabilities
Debt⁽³⁾	$	19,220	$	19,228	$	18,091	$	15,588
Derivatives⁽²⁾		372		372		534		534

Total liabilities	$	19,592	$	19,600	$	18,625	$	16,122

⁽¹⁾

See Note 4 — Investments in Marketable Securities for additional information regarding the classification of marketable securities in the Fair Value Hierarchy in accordance with FAS No. 157, Fair Value Measurements (“FAS No. 157”).

⁽²⁾

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

⁽³⁾

See Note 7 — Long-Term Debt for additional information regarding the fair value of debt.

The Company adopted the provisions of FAS No. 157 as of January 1, 2008 for financial assets and liabilities and January 1, 2009 for all nonrecurring fair value measurements of nonfinancial assets. In general the Company’s nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis include goodwill; intangible assets, such as sales concessions, land rights and emissions allowances; and long-lived tangible assets including property, plant and equipment. The Company did not adjust any nonfinancial assets or liabilities measured at fair value on a nonrecurring basis to fair value during the three or six months ended June 30, 2009. Although the adoption of FAS No. 157 did not materially impact our financial condition, results of operations or cash flows, additional disclosures about fair value measurements are discussed below.

The Company’s financial assets and liabilities that are measured at fair value on a recurring basis fall into two broad categories: marketable securities and derivatives. Marketable securities are generally measured at fair value using the market approach. The Company’s investments generally consist of debt and equity securities. Equity securities are adjusted to fair value using quoted market prices. Debt securities primarily consist of certificates of deposit, government debt securities and money market funds held by our Brazilian subsidiaries. The Company’s derivatives are valued using the income approach. When deemed appropriate, the Company minimizes its risk from interest and foreign currency exchange rate and commodity price fluctuations through the use of derivative financial instruments. The Company’s derivatives are primarily interest rate swaps on non-recourse debt to establish a fixed rate on variable rate debt, foreign exchange instruments to hedge against currency fluctuations and derivatives or embedded derivatives associated with commodity contracts. The fair value of the Company’s derivative portfolio was determined using internal valuation models, most of which are based on observable market inputs including interest rate curves and forward and spot prices for currencies and commodities.

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were measured at fair value on a recurring basis as of June 30, 2009 in accordance with FAS No. 157. 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.


	June 30, 2009		Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in millions)
Assets
Available-for-sale securities	$	1,131	$	1	$	1,128	$	2
Trading securities		7		7		-		-
Derivatives		215		-		123		92

Total assets	$	1,353	$	8	$	1,251	$	94

Liabilities
Derivatives	$	372	$	-	$	271	$	101

Total liabilities	$	372	$	-	$	271	$	101

The following table presents a reconciliation of all assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the six months ended June 30, 2009:


	Derivatives⁽¹⁾			Available-For- Sale Securities
	(in millions)
Balance at December 31, 2008	$	(69	)	$	42	⁽⁵⁾
Total gains (losses) (realized/unrealized)
Included in earnings ⁽²⁾		(24	)		-
Included in other comprehensive income		140			-
Included in regulatory assets		2			-
Purchases, issuances and settlements		(1	)		(40	)
Asset transferred in (out) of Level 3		(187	)⁽³⁾		-
Liabilities transferred (in) out of Level 3		130	⁽⁴⁾		-

Balance at June 30, 2009	$	(9	)	$	2

Total gains/losses for the period included in earnings attributable to the change in unrealized gains/losses relating to assets and liabilities held at June 30, 2009 and December 31, 2008	$	(26	)	$	-

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

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

⁽³⁾

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

⁽⁴⁾	Liabilities transferred out of Level 3 primarily resulted from a decrease in the significance of the unobservable inputs to credit valuation adjustments in the valuation of these derivative instruments.

⁽⁵⁾	Available-for-sale securities in Level 3 are auction rate securities and variable rate demand notes which have failed remarketing, 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

FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (“FSP FAS 115-2”) became effective and was adopted by the Company for the quarter ended June 30, 2009. FSP FAS 115-2 amended existing other-than-temporary impairment guidance for debt securities to change the recognition threshold and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. For debt securities, FSP FAS 115-2 changed the accounting requirements related to the recognition of other-than-temporary impairment. If other-than-temporary impairment is recognized, it is separated into two pieces 1) the amount representing the credit loss is recognized in earnings and 2) the amount related to other factors is recognized in other comprehensive income. The amount recognized in other comprehensive income for held-to-maturity debt securities is then amortized over the remaining life of the security. FSP FAS 115-2 covers new and existing securities held by an entity as of the beginning of the period adopted and requires a cumulative adjustment to the opening balance of retained earnings in the period of adoption with a corresponding adjustment to accumulated other comprehensive income. The adoption did not have a material impact on the Company’s financial condition, results of operations, or cash flows. AES has incorporated the additional disclosure requirements below.

The following table sets forth the Company’s investments in marketable debt and equity securities reported at fair value as of June 30, 2009 and December 31, 2008 by security type and by level within the fair value hierarchy in accordance with SFAS No. 157. The security types are determined based on the nature and risk of the security and are consistent with how the Company manages, monitors and measures its securities. These securities have been classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the determination of the fair value of the securities and their placement within the fair value hierarchy levels.


	June 30, 2009								December 31, 2008
	Level 1		Level 2		Level 3		Total⁽²⁾		Total⁽²⁾
	(in millions)
AVAILABLE-FOR-SALE:
Unsecured debentures⁽ ¹⁾	$	-	$	582	$	-	$	582	$	674
Certificates of deposit⁽¹⁾		-		406		-		406		493
Government debt securities ⁽³⁾		-		110		-		110		32
Common stock		1		-		-		1		1
Money market funds		-		30		-		30		21
Other		-		-		2		2		42

Subtotal	$	1	$	1,128	$	2	$	1,131	$	1,263
TRADING:
Mutual funds		7		-		-		7		-

Subtotal		7		-		-		7		-

TOTAL	$	8	$	1,128	$	2	$	1,138	$	1,263

⁽¹⁾

Unsecured debentures are instruments similar to certificates of deposit that are held primarily by our subsidiaries in Brazil. The unsecured debentures and certificates of deposit included here do not qualify as cash equivalents under SFAS No. 95, Statement of Cash Flows, and meet the definition of a security under SFAS No. 115 and are therefore classified as available-for-sale securities.

⁽²⁾	The amortized cost approximated fair value of the available-for-sale securities at June 30, 2009 and December 31, 2008.

⁽³⁾	During the three months ended June 30, 2009, three of the Company’s generation businesses in the Dominican Republic exchanged $110 million in accounts receivable due from the government-owned

distribution companies of the Dominican Republic for sovereign bonds of the same amount. The bonds, which are classified as available-for-sale securities in the accompanying condensed consolidated balance sheet, were adjusted to fair value when acquired. During the second quarter, the Company used a portion of the bonds with a carrying value of $31 million to settle third party liabilities and sold bonds with a carrying value of $28 million. The remaining bonds were subsequently marked to market as of June 30, 2009 with any changes in fair value reflected in accumulated other comprehensive income. As of June 30, 2009, the fair value of such bonds approximated $39 million.

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


	Available-for-sale debt securities
	(in millions)
Less than one year	$	377
One to five years		701
Five to ten years		20

Total	$	1,098

The following table summarizes the gains and losses related to available-for-sale and trading securities for the three and six months ended June 30, 2009 and 2008. There were no realized losses on the sale of available-for-sale securities. Gains and losses on sales 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, 2009 and 2008.


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
	(in millions)
Gains (losses) included in earnings that relate to trading securities held at the reporting date	$	1	$	-		$	1	$	-
Gain (losses) included in other comprehensive income	$	-	$	(1	)	$	-	$	(2	)
Proceeds from sales	$	733	$	774		$	1,270	$	1,583
Gross realized gains on sales	$	1	$	-		$	1	$	-

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


	June 30, 2009		December 31, 2008
	(in millions)
Certificates of deposit	$	41	$	45
Government debt securities		8		93
Other		7		12

Total	$	56	$	150

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

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Risk Management Objectives

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

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 2026. The following table sets forth, by type of interest rate index, the Company’s current and maximum outstanding notional under its interest rate derivative instruments, the weighted average remaining term and the percentage of variable-rate debt hedged that is based on that index as of June 30, 2009 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:


	June 30, 2009
	Current Derivative Notional Translated to USD		Maximum Derivative Notional Translated to USD⁽¹⁾		Weighted Average Remaining Term	% of Debt Currently Hedged by Index⁽²⁾
	(in millions)				(in years)
Libor (U.S. Dollar)	$	2,800	$	3,292	8	73	%
Euribor (Euro)		1,050		1,152	5	89	%
Libor (British Pound Sterling)		75		84	6	60	%
Treasury Bills (U.S. Dollar)⁽³⁾		65		70	1	116	%
City of Petersburg, Indiana Pollution Control Refunding Revenue Bonds Adjustable Rate (U.S. Dollar)		40		40	14	100	%
Bubor (Hungarian Forint)		19		19	1	71	%

⁽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, 2009 and the maturity of the derivative instrument, which includes forward starting derivative instruments.

⁽²⁾

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

⁽³⁾

Debt and swap are related to a construction project. This swap does not currently qualify for cash flow hedge accounting.

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


	June 30, 2009
	Notional Translated to USD		Weighted Average Remaining Term
	(in millions)		(in years)
Chilean Unidad de Fomento (CLF)	$	220	17
Euro (EUR)		9	1

Foreign Currency Risk

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


	June 30, 2009
	Notional Translated to USD		Weighted Average Remaining Term
	(in millions)		(in years)
Argentina Peso (ARS)	$	119	<1
Brazilian Real (BRL)		67	<1
Colombian Peso (COP)		34	<1
Chilean Peso (CLP)		27	<1
U.S. Dollar (USD)		5	<1

In addition, certain of our subsidiaries have entered into contracts denominated in currencies other than their own functional currencies. These contracts range in maturity through 2028. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notional over the remaining terms of its foreign currency embedded derivative instruments as of June 30, 2009:


	June 30, 2009
	Notional Translated to USD			Weighted Average Remaining Term
	(in millions)			(in years)
Kazakhstani Tenge (KZT)	$	289		9
Argentine Peso (ARS)		12		2
British Pound Sterling (GBP)		5		<1
Euro (EUR)		3		10
Brazilian Real (BRL)		2		1
Hungarian Forint (HUF)		-	⁽¹⁾	1

⁽¹⁾

De minimis amount

Commodity Price Risk

We are exposed to the impact of market fluctuations in the price of electricity, fuels and environmental credits. Although we primarily consist of businesses with long-term contracts or retail sales concessions, a portion of our current and expected future revenues are derived from businesses without significant long-term revenue or supply contracts. These businesses subject our results of operations to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We have used a hedging strategy, where appropriate, to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy can involve the use of commodity forward contracts, futures, swaps and options. Some businesses hedge certain aspects of their commodity risks using financial hedge instruments.

We also enter into short-term contracts for the supply of electricity and fuel in other competitive markets in which we operate. When hedging the output of our generation assets, we have power purchase agreements or other hedging instruments that lock in the spread in dollars per MWh between the cost of fuel to generate a unit of electricity and the price at which the electricity can be sold. The portion of our sales and fuel purchases that

are not subject to such agreements will be exposed to commodity price risk. Eastern Energy and Deepwater, two of our North America generation businesses, sell electricity into the power pools managed by the New York Independent System Operator and the Electric Reliability Council of Texas, respectively. Our commodity transactions at Eastern Energy hedge 78% of the forecasted sales of this electricity through the remainder of 2009 and 9% of the forecasted sales of this electricity through 2010. Our commodity transactions at Deepwater hedge 46% of the forecasted sales of this electricity through the remainder of 2009 and 18% of the forecasted sales of this electricity through 2010.

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


	June 30, 2009
	Volume	Weighted Average Remaining Term
	(in millions)	(in years)
Natural gas (MMBtu)	107	9
Petcoke (Metric tons)	15	15
Coal (Metric tons)	2	1
Log wood (Tons)	1	4
Electricity (MWhs)	1	1

Accounting and Reporting

Under FAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“FAS No. 133”), as amended, we recognize all derivatives, except those designated as “normal purchase normal sale” at inception as either assets or liabilities on the balance sheet at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. Gains or losses on derivatives that do not qualify for hedge accounting are recognized as interest expense for interest rate derivatives, foreign currency gains or losses on foreign currency derivatives, and non-regulated revenue or non-regulated cost of sales for commodity derivatives.

FAS No. 133 enables companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as, a cash flow hedge are deferred in accumulated other comprehensive income and are recognized into earnings as the hedged transactions affect earnings. Any ineffectiveness is immediately recognized in earnings as interest expense for interest rate hedges, foreign currency gains or losses on foreign currency hedges, and non-regulated revenue or non-regulated cost of sales for commodity hedges. For all hedge contracts, the Company maintains formal documentation of the hedge and effectiveness testing in accordance with FAS No. 133. If AES deems that a derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively. During the first six months of 2009 no cash flow hedges were discontinued because it was probable that the forecasted transaction would not occur by the end of the originally specified time period (as documented at the inception of the hedging relationship) or within an additional two-month time period thereafter.

Certain derivatives are not designated as hedging instruments. While these instruments economically hedge interest rate risk, foreign exchange risk or commodity price risk, they do not qualify for hedge accounting treatment as defined by FAS No. 133.

As of June 30, 2009, approximately $(108) million, $1 million and $105 million of the pre-tax accumulated other comprehensive (loss) income related to interest rate derivative instruments, cross currency derivative

instruments and commodity derivative instruments, respectively, is expected to be recognized as a (decrease) increase to income from continuing operations before income taxes over the next twelve months. The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for interest rate hedges, as depreciation is recognized for hedges of capitalized interest, as foreign currency transaction and translation gains and losses are recognized for hedges of foreign currency exposure and as electricity sales are recognized for hedges of forecasted electricity transactions. These balances are included in the condensed consolidated statements of cash flows as operating and/or investing activities based on the nature of the underlying transaction.

The following table sets forth by type of derivative the financial statement location and fair value of the Company’s investments in derivative instruments as of June 30, 2009:


	June 30, 2009
	Designated as Hedging Instruments		Not Designated as Hedging Instruments
	(in millions)
Assets
Other current assets
Cross currency derivatives	$	1	$	-
Foreign exchange derivatives		-		2
Commodity derivatives:
Electricity		107		-
Fuel		-		23
Other		-		3

Total other current assets		108		28

Other assets
Interest rate derivatives		63		-
Commodity derivatives:
Electricity		10		-
Fuel		-		6

Total other assets—noncurrent		73		6

Total assets	$	181	$	34

Liabilities
Accrued and other liabilities
Interest rate derivatives	$	118	$	17
Foreign exchange derivatives		-		12
Commodity derivatives:
Electricity		2		-
Fuel		-		4

Total accrued and other liabilities—current		120		33

Other long-term liabilities
Interest rate derivatives		198		16
Foreign exchange derivatives		-		3
Commodity derivatives:
Fuel		-		2

Total other long-term liabilities		198		21

Total liabilities	$	318	$	54

The following tables set forth by type of derivative, the financial statement location and amount of gains (losses) recognized in accumulated other comprehensive loss and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships, as defined under FAS No. 133, for the three and six months ended June 30, 2009:


	Three Months Ended June 30, 2009
	Gain (Loss) Recognized in OCI on Derivatives		Location of Gain/(Loss) Reclassified from Accumulated OCI into Earnings	Gain (Loss) Reclassified from Accumulated OCI
	(in millions)			(in millions)
Interest rate derivatives	$	49	Interest expense	$	(9	)⁽¹⁾
Cross currency derivatives		28	Interest expense		-
Commodity derivatives - electricity		28	Non-regulated revenue		57

Total	$	105		$	48


	Six Months Ended June 30, 2009
	Gain (Loss) Recognized in OCI on Derivatives		Location of Gain/(Loss) Reclassified from Accumulated OCI into Earnings	Gain (Loss) Reclassified from Accumulated OCI
	(in millions)			(in millions)
Interest rate derivatives	$	99	Interest expense	$	(10	)⁽¹⁾
Cross currency derivatives		34	Interest expense		-
Commodity derivatives - electricity		109	Non-regulated revenue		87

Total	$	242		$	77

⁽¹⁾

Excludes $0 and $14 million of losses for the three and six months ended June 30, 2009, respectively, reclassified from accumulated other comprehensive income related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting

The following tables set forth by type of derivative, the financial statement location and amount of gains (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined under FAS No. 133, for the three and six months ended June 30, 2009:


	Amount of Gain (Loss) Recognized in Earnings
	Location of Gain (Loss) Recognized in Earnings	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
		(in millions)
Interest rate derivatives	Interest expense	$	10		$	10
Cross currency derivatives	Interest expense		-	⁽¹⁾		2
Commodity derivatives - electricity	Non-regulated revenue		-	⁽¹⁾		(2	)

Total		$	10		$	10

⁽¹⁾

De minimis amount of ineffectiveness recognized

The following table sets forth by type of derivative, the financial statement location and amount of gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under FAS No. 133 for the three and six months ended June 30, 2009:


	Amount of Gain (Loss) Recognized in Earnings
	Location of Gain (Loss) Recognized in Earnings	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
		(in millions)
Interest rate derivatives	Interest expense	$	5		$	-
Foreign exchange derivatives	Foreign currency transaction gains (losses) on net monetary position		(19)			(12)
Commodity derivatives - PPA embedded	Non-regulated revenue		-			(5)
Commodity derivatives - fuel	Non-regulated cost of sales		6			(7)

Total		$	(8	)	$	(24	)

In addition, Indianapolis Power & Light Company (“IPL”), the Company’s North American integrated utility, has two derivative instruments for which the gains and losses are accounted for in accordance with FAS No. 71, Accounting for the Effects of Certain Types of Regulation, as regulatory assets or liabilities. Gains and losses on these derivatives due to changes in fair value are recoverable through future rates and are recognized as an adjustment to the regulatory asset or liability instead of being recognized through earnings, so they are excluded from the above table. For the three and six months ended June 30, 2009, there was an increase (decrease) in the fair value of these derivatives of $2 million and $(1) million, respectively, included in regulatory assets and liabilities on the accompanying condensed consolidated balance sheet.

Credit Risk-Related Contingent Features

In December 2007, Gener, our generation business in Chile, entered into cross currency swap agreements with a counterparty to swap the Chilean inflation indexed bonds issued in December 2007 into U.S. Dollars. The cross currency swap agreements require Gener to provide collateral credit support when the fair value of the swaps exceeds the thresholds established in the agreements. These thresholds vary based on Gener’s credit rating. As Gener’s credit rating drops the threshold drops, requiring more collateral support. If Gener’s credit rating were to fall below the minimum threshold established in the swap agreements, the counterparty could demand immediate collateralization of the entire mark-to-market value of the swaps (excluding credit valuation adjustments) if they were in a liability position, which would have been $4 million at June 30, 2009. As of June 30, 2009, Gener had posted $50 million in the form of a letter of credit to support these swaps.

6. INVESTMENTS IN AND ADVANCES TO AFFILIATES

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

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

proportionate share of the settlement, $35 million, which was recognized as “net equity in earnings of affiliates” because the distribution was in excess of the Company’s current investment balance of zero and AES does not have an obligation or intent to fund future cash flow requirements of Cartagena.

The following table summarizes financial information of the affiliates accounted for using the equity method in which we own 50% or less and have the ability to exercise significant influence but do not control and our majority-owned unconsolidated subsidiaries:


	50%-or-less Owned Affiliates⁽¹⁾								Majority-owned Unconsolidated Subsidiaries⁽²⁾
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008		2009		2008		2009		2008			2009		2008
	(in millions)								(in millions)
Revenue	$	289	$	299	$	537	$	587	$	77	$	42		$	79	$	87
Gross margin	$	52	$	37	$	70	$	85	$	20	$	14		$	20	$	32
Net income	$	23	$	42	$	34	$	84	$	24	$	(1	)	$	22	$	3

⁽¹⁾

The 50%-or-less Owned Affiliates portion of the table excludes information related to the Companhia Energetica de Minas Gerais (“CEMIG”) business because the Company discontinued the application of the equity method of accounting in accordance with its accounting policy regarding equity method investments. In addition, although the Company’s ownership interest in Trinidad Generation Unlimited, (“Trinidad”) is 10%, the Company accounts for its investment in Trinidad as an equity method investment because AES continues to exercise significant influence through the supermajority vote requirement for any significant future project development activities.

⁽²⁾

The Majority-owned Unconsolidated Subsidiaries portion of the table includes information related to Barry, Cartagena, Cili and IC Ictas Energy Group. Although we continue to maintain 100% ownership of Barry, as a result of an amended credit agreement, no material financial or operating decisions can be made without the banks’ consent, and the Company no longer controls Barry. Consequently, the Company discontinued consolidating the business’s results and began using the equity method to account for this unconsolidated majority-owned subsidiary.

7. LONG-TERM DEBT

The Company has two types of debt reported on its 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 farms and distribution companies at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. The default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries. Recourse debt is direct borrowings by the Parent Company and is used to fund development, construction or acquisition and serves as funding to equity investments or loans to the affiliates. This debt is with recourse to the Parent Company and is structurally subordinated to the affiliates’ non-recourse debt.

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


	June 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Non-recourse debt	$	13,705	$	13,992	$	12,943	$	11,200
Recourse debt		5,515		5,236		5,148		4,388

Total debt	$	19,220	$	19,228	$	18,091	$	15,588

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

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

Non-Recourse Debt

Subsidiary non-recourse debt in default or accelerated, including any temporarily waived default, is classified as current debt in the accompanying condensed consolidated balance sheets. The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of June 30, 2009:


Subsidiary	Primary Nature of Default	June 30, 2009
Subsidiary	Primary Nature of Default	Default		Net Assets
		(in millions)
Kelanitissa	Covenant	$	45	$	4
Kievoblenergo	Covenant		26		49
Rivneenergo	Covenant		13		24
Ebute⁽¹⁾	Covenant		10		154
Aixi	Payment		3		8

Total		$	97

⁽¹⁾

Ebute, our subsidiary in Nigeria, received a waiver of default on September 18, 2008. The waiver gives Ebute until December 31, 2009 to cure the breached covenants; however, as this waiver does not extend beyond the Company’s current reporting cycle and the probability of curing the default cannot be determined, the debt was classified as current.

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

On April 8, 2009, AES Gener S.A. (“Gener”) issued $196 million aggregate principal amount of 8% unsecured notes due in 2019. The unsecured notes were priced at a discount to par resulting in an 8.5% yield. The proceeds from this issuance will be used to provide Gener’s funding requirements for projects under construction.

Recourse Debt

Fourth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2008 (the “senior secured credit facility”). The senior secured credit facility previously included a $200 million term loan facility maturing on August 10, 2011 and a $750 million revolving credit facility maturing on June 23, 2010 (the “revolving credit facility”).

The principal modification set forth in Amendment No. 1 was a one-year extension of $570 million of revolving credit facility commitments from an original maturity date of June 23, 2010 to July 5, 2011. In addition, certain lenders determined that they would increase their commitment under the revolving credit facility by $35 million from March 26, 2009 through July 5, 2011. Accordingly, Amendment No. 1 increased the size of the revolving credit facility from $750 million to $785 million for the period between the dates of Amendment No. 1 and June 23, 2010. Between June 23, 2010 and July 5, 2011, the revolving credit facility size will be $605 million. No modifications were made to the amount or maturity date of the $200 million term loan facility.

The extended commitments from this amendment were subject to new pricing that included an upfront fee of 1.25% for participating in the extensions and an increase in undrawn commitment fees from 50 to 100 basis points. The annual interest rate on the drawn loans was also increased by 200 basis points to LIBOR plus 3.50%. Pricing and all other material terms remain unchanged for the revolving credit facility commitments which have not been extended.

On April 2, 2009 the Parent Company issued $535 million aggregate principal amount of 9.75% senior unsecured notes due 2016 in a private placement. The notes were priced at a discount to yield 11%. Subsequently, the Parent Company allocated a substantial portion of the proceeds to voluntarily reduce the size of its $600 million senior unsecured credit facility among the Parent Company, Merrill Lynch Bank USA and the banks party thereto (the “senior unsecured credit facility”), by $465 million. The remaining $135 million under the senior unsecured credit facility consists of letters of credit, the majority of which support several projects currently under construction.

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

8. CONTINGENCIES AND COMMITMENTS

Environmental

The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of June 30, 2009, the Company had recorded liabilities of $29 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, 2009.

For a discussion of potential U.S. federal climate change legislation and potential international agreements on climate change, see Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview of Our Business — Key Trends and Uncertainties — Regulatory Environment.

If national climate change legislation or other legislation is not enacted that precludes the U.S. Environmental Protection Agency (“EPA”) from regulating greenhouse gas (“GHG”) under the Clean Air Act (“CAA”), the EPA is likely to regulate GHG emissions. As noted in the Company’s 2008 Form 10-K, on April 2, 2007, the U.S. Supreme Court issued a decision in a case involving the regulation of CO₂ emissions from motor vehicles under the CAA. The Court ruled that CO₂ is a pollutant which potentially could be subject to regulation under Section 202 of the CAA and that the EPA had a duty to determine whether CO₂ emissions contribute to

climate change or to provide some reasonable explanation why it would not exercise its authority. In response to the Court’s decision, on July 11, 2008, the U.S. EPA issued an Advanced Notice of Public Rulemaking soliciting public input on whether CO₂ emissions should be regulated from both mobile and stationary sources under Section 202 the CAA. In order for the EPA to regulate CO₂ and other greenhouse emissions under Section 202 of the CAA, such emissions must be “endangering public health and welfare” under the CAA. On April 17, 2009, EPA released proposed findings for comment which included a proposed finding that atmospheric concentrations of six greenhouse gases, including CO₂, “endanger public health and welfare within the meaning of Section 202(a) of the CAA.” The EPA held two public meetings in May 2009, and the period for public comments closed on June 23, 2009. While the EPA has not proposed regulations at this time, a finding that CO₂ and other greenhouse emissions endanger the public health and welfare would allow the agency to regulate mobile sources of greenhouse gas emissions under the CAA. It is possible that the EPA could subsequently make a similar finding with respect to greenhouse gas emissions from stationary sources. Such a determination by the EPA could result in CO₂ emission limits on stationary sources that do not include market-based compliance mechanisms, which could increase our costs directly and indirectly and have a material adverse effect on our business and/or results of operations.

As noted in the Company’s 2008 Form 10-K, ten northeastern States have entered into the Regional Greenhouse Gas Initiative (“RGGI”) under which the States coordinate 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. For additional information regarding the risks associated with carbon emissions, see the following items in the Company’s 2008 Form 10-K: Item 1 — Business — Regulatory Matters — Environmental and Land Use Regulations and Item 1A: Risk Factors — Risks Associated with Governmental Regulations and Laws.

As noted in the Company’s 2008 Form 10-K, on February 6, 2009, the Acting Solicitor General of the United States filed a motion in the U.S. Supreme Court to dismiss the EPA’s request for review of the D.C. Circuit Court’s February 2008 decision vacating the Clean Air Mercury Rule (“CAMR”). On February 23, 2009, the U.S. Supreme Court declined to review the lower court’s CAMR decision. The EPA is now expected to propose a new rule to address hazardous air pollutants (“HAPs”) from electric generation power plants, including mercury. With respect to the HAPs, the EPA recently issued a notice of the agency’s intent to collect information so that it can develop a maximum achievable control technology standard for coal-fired power plants which, unlike CAMR, will not provide a market-based compliance option (e.g., cap-and-trade) for power plants subject to the rule. The EPA has indicated that such standards would impose controls on existing sources within three years of a final rule. While the exact impact and cost of any such new federal rules cannot be established until they are promulgated and any related litigation resolved, there can be no assurance that the Company’s business, financial conditions or results of operations would not be materially and adversely affected by such rules.

Guarantees, Letters of Credit and Commitments

As of June 30, 2009, The AES Corporation had provided outstanding financial and performance related guarantees or other credit support commitments for the benefit of its subsidiaries, which were limited by the terms of the agreements to an aggregate of approximately $404 million (excluding investment commitments and those collateralized by letters of credit discussed below). The term of these credit support arrangements generally parallels the length of the related financing arrangements or transactions.

As of June 30, 2009, the Parent Company had $207 million in letters of credit outstanding under the revolving credit facility and under the senior unsecured credit facility that operate to guarantee performance of certain project development activities and subsidiary operations. During the second quarter the Company paid letter of credit fees ranging from 3.17% to 8.84% per annum on the outstanding amounts.

As of June 30, 2009, The AES Corporation had $185 million of commitments to invest in subsidiaries under construction and to purchase related equipment excluding approximately $144 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: $89 million in 2009, $39 million in 2010 and $57 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, 2009.

In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the Fifth District Court found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$970 million ($500 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the Fifth District Court rejected Eletropaulo’s defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro ruled that Eletropaulo was not a proper party to the litigation because any alleged liability was transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the Fifth District Court. Eletropaulo’s subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil have been dismissed. Eletrobrás has requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo has consented to the appointment of such an expert, subject to a reservation of rights. After the amount of the alleged debt is determined, Eletrobrás may resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo will be required to provide security in the amount of its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the Fifth District Court grants such request, Eletropaulo’s results of operations may be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the Fifth District Court against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 1999, a state appellate court in Minas Gerais, Brazil, granted a temporary injunction suspending the effectiveness of a shareholders’ agreement between Southern Electric Brasil Participacoes, Ltda. (“SEB”) and the state of Minas Gerais concerning CEMIG, an integrated utility in Minas Gerais. The Company’s investment in CEMIG is through SEB. This shareholders’ agreement granted SEB certain rights and powers in respect of CEMIG (“Special Rights”). In March 2000, a lower state court in Minas Gerais held the shareholders’ agreement invalid where it purported to grant SEB the Special Rights and enjoined the exercise of the Special Rights. In August 2001, the state appellate court denied an appeal of the decision and extended the injunction. In October 2001, SEB filed appeals against the state appellate court’s decision with the Superior Court of Justice (“SCJ”) and the Supreme Court. The state appellate court denied access of these appeals to the higher courts, and in August 2002 SEB filed interlocutory appeals against such denial with the SCJ and the Supreme Court. In

December 2004, the SCJ declined to hear SEB’s appeal. However, the Supreme Court is considering whether to hear SEB’s appeal. SEB intends to vigorously pursue a restoration of the value of its investment in CEMIG by all legal means; however, there can be no assurances that it will be successful in its efforts. Failure to prevail in this matter may limit SEB’s influence on the daily operation of CEMIG.

In August 2000, the Federal Energy Regulation Commission (“FERC”) announced an investigation into the organized California wholesale power markets in order to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. FERC requested documents from each of the AES Southland, LLC plants and AES Placerita, Inc. AES Southland and AES Placerita have cooperated fully with the FERC investigations. AES Southland was not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. After hearings at FERC, AES Placerita was found subject to refund liability of $588,000 plus interest for spot sales to the California Power Exchange from October 2, 2000 to June 20, 2001. As FERC investigations and hearings progressed, numerous appeals on related issues were filed with the U.S. Court of Appeals for the Ninth Circuit. Over the past five years, the Ninth Circuit issued several opinions that had the potential to expand the scope of the FERC proceedings and increase refund exposure for AES Placerita and other sellers of electricity. Following remand of one of the Ninth Circuit appeals in March 2009, FERC started a new hearing process involving AES Placerita. In May 2009, AES Placerita entered into a settlement, subject to FERC approval, concerning the claims before FERC against AES Placerita relating to the California energy crisis of 2000-2001, including the California refund proceeding. Pursuant to the settlement, AES Placerita paid $6 million and assigned a receivable of $168,119 due 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. To date, in excess of 97% of the buyers in the market have elected to join the settlement. A small amount of AES Placerita’s settlement payment was placed in escrow for buyers that do not join the settlement (“non-settling parties”). It is unclear whether the escrowed funds will be enough to satisfy any additional sums that might be determined to be owed to non-settling parties at the conclusion of the FERC proceedings concerning the California energy crisis. However, any such additional sums are expected to be immaterial to the Company’s consolidated financial statements. On July 30, 2009, one-settling party, the Sacramento Municipal Utility District, requested that the FERC rehear its order approving the settlement. We cannot predict the FERC’s determination on the request for rehearing.

In August 2001, the Grid Corporation of Orissa, India, now Gridco Ltd (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus

undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. The Company subsequently filed an application to recover its costs of the arbitration, which is under consideration by the tribunal. In addition, in September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in Orissa Power Generation Corporation Ltd’s (“OPGC”), and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco’s challenge to the arbitration award is resolved. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC’s existing Power Purchase Agreement (“PPA”) with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC’s jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court’s decision to the Supreme Court and sought stays of both the High Court’s decision and the underlying OERC proceedings regarding the PPAs terms. In April 2005, the Supreme Court granted OPGC’s requests and ordered stays of the High Court’s decision and the OERC proceedings with respect to the PPA’s terms. The matter is awaiting further hearing. Unless the Supreme Court finds in favor of OPGC’s appeal or otherwise prevents the OERC’s proceedings regarding the PPA’s terms, the OERC will likely lower the tariff payable to OPGC under the PPA, which would have an adverse impact on OPGC’s financials. OPGC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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

AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a

privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney’s Office then requested an injunction which the judge rejected on September 26, 2008. The Public Attorney’s office has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul 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 ($3.1 million). The injunction was rejected and the case is in the evidentiary stage awaiting the judge’s determination concerning the production of expert evidence. The above referenced proposal was delivered on April 8, 2008. FEPAM responding by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE’s operations. It is estimated that remediation could cost approximately R$14.7 million ($7.6 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 ($2.0 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 ($393 million). In December 2006, SEB’s defense was ruled

groundless by the Circuit Court. The Federal Court of Appeals affirmed that decision in February 2009. SEB intends to file further appeals. BNDES has seized a total of approximately R$630 million ($325 million) in attached dividends to date, with the approval of the Circuit Court, and is seeking to recover additional attached dividends. Also, BNDES has filed a plea to seize the attached CEMIG shares. The Circuit Court will consider BNDES’s request to seize the attached CEMIG shares after the net value of the alleged debt is recalculated in light of BNDES’s seizure of dividends. SEB believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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

In April 2006, a putative class action complaint was filed in the U.S. District Court for the Southern District of Mississippi (“District Court”) on behalf of certain individual plaintiffs and all residents and/or property owners in the State of Mississippi who allegedly suffered harm as a result of Hurricane Katrina, and against the Company and numerous unrelated companies, whose alleged greenhouse gas emissions allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert unjust enrichment, civil conspiracy/aiding and abetting, public and private nuisance, trespass, negligence, and fraudulent misrepresentation and concealment claims against the defendants. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. In August 2007, the District Court dismissed the case. The plaintiffs have appealed to the U.S. Court of Appeals for the Fifth Circuit, which heard oral arguments in November 2008 and is considering 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.

In July 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan (the “Competition Committee”) ordered Nurenergoservice, an AES subsidiary, to pay approximately 18 billion KZT ($121 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. The Competition Committee’s order was affirmed by the economic court in April 2008. Nurenergoservice’s subsequent appeals have been unsuccessful to date, including at the court of appeals (first panel), which dismissed Nurenergoservice’s appeal in July 2008. Also, the economic court has issued an injunction to secure Nurenergoservice’s alleged liability, freezing Nurenergoservice’s bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. In separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately 1.8 billion KZT (approximately

$12 million) in administrative fines for its alleged antimonopoly violations. Nurenergoservice’s appeal to the administrative court of first instance was rejected in February 2009. The Competition Committee’s successor, the Antimonopoly Agency, has not indicated whether it intends to assert claims against Nurenergoservice for alleged antimonopoly violations post first quarter 2007. Nurenergoservice believes it has meritorious claims and defenses; however, there can be no assurances that it will prevail in these proceedings. As Nurenergoservice did not prevail in the economic court or the court of appeals (first panel) with respect to the alleged damages, it will have to pay the alleged damages or risk seizure of its assets. In February 2009, the Antimonopoly Agency seized approximately 783 million KZT ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice’s alleged damages liability. Furthermore, as Nurenergoservice did not prevail in the administrative court with respect to the fines, it will have to pay the fines or risk seizure of its assets.

In December 2008, the Antimonopoly Agency ordered Ust-Kamenogorsk HPP (“UK HPP”), a hydroelectric plant under AES concession, to pay approximately 1.1 billion KZT ($7 million) for alleged antimonopoly violations in February through November 2007. The economic court of first instance has issued an injunction to secure UK HPP’s alleged liability, among other things freezing UK HPP’s bank accounts. Also, in March 2009, the economic court affirmed the Antimonopoly Agency’s order. UK HPP’s subsequent appeal to the court of appeals (first panel) was dismissed in April 2009. In June 2009, UK HPP paid the alleged damages and thus the economic court thereafter canceled the injunction on UK HPP’s assets. Furthermore, the Antimonopoly Agency has initiated administrative proceedings against UK HPP for its alleged antimonopoly violations. In May 2009, the administrative court of first instance ordered UK HPP to pay approximately 99 million KZT ($668,000) in administrative fines, which UK HPP did in June 2009. UK HPP believes it has meritorious defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.

In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of UK HPP and Shulbinsk HPP, another hydroelectric plant under AES concession (collectively, the “Hydros”), in 2008 through February 2009. The investigation is ongoing and no order has been issued relating to it. The Hydros believe they have meritorious defenses and will assert them vigorously in any formal proceeding concerning the investigation; however, there can be no assurances that they will be successful in their efforts.

In April 2009, the Antimonopoly Agency initiated an investigation of AES Ust-Kamenogorsk TETS LLP’s (“UKT”) power sales in 2008 through February 2009. With respect to UKT’s 2008 sales, the Antimonopoly Agency has issued an order allegedly quantifying UKT’s revenues from those sales, but the amount of damages and/or fines that UKT will have to pay, if any, for its alleged antimonopoly violations relating to the 2008 sales has not been determined and is the subject of ongoing court proceedings. As for UKT’s sales in January and February 2009, the Antimonopoly Agency’s investigation of those sales is temporarily suspended pending court proceedings concerning UKT’s market share. If UKT fails to prove in those proceedings that it is not a dominant market entity, the Antimonopoly Agency’s investigation will resume. UKT believes it has meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In July 2007, AES Energia Cartagena SRL, (“AESEC”) initiated arbitration against Initec Energia SA, Mitsubishi Corporation, and MC Power Project Management, SL (“Contractor”) to recover damages from the Contractor for its delay in completing the construction of AESEC’s majority-owned power facility in Murcia, Spain. In October 2007, the Contractor denied AESEC’s claims and asserted counterclaims to recover approximately €12 million ($17 million) for alleged unpaid milestone and scope change order payments, among other things, and an unspecified amount for an alleged early completion bonus. The final hearing was scheduled to begin in June 2009, however, prior to the hearing the parties settled.

In November 2007, the International Brotherhood of Electrical Workers, Local Union No. 1395, and sixteen individual retirees, (the “Complainants”), filed a complaint at the Indiana Utility Regulatory Commission (“IURC”) seeking enforcement of their interpretation of the 1995 final order and associated settlement agreement resolving IPL’s basic rate case. The Complainants requested that the IURC conduct an investigation of IPL’s

failure to fund the Voluntary Employee Beneficiary Association Trust (“VEBA Trust”), at a level of approximately $19 million per year. The VEBA Trust was spun off to an independent trustee in 2001. The complaint sought an IURC order requiring IPL to make contributions to place the VEBA Trust in the financial position in which it allegedly would have been had IPL not ceased making annual contributions to the VEBA Trust after its spin off. The complaint also sought an IURC order requiring IPL to resume making annual contributions to the VEBA Trust. IPL filed a motion to dismiss and both parties sought summary judgment in the IURC proceeding. In May 2009, the IURC issued an order granting summary judgment in favor of IPL. In June 2009, the Complainants filed a notice of appeal with the IURC to provide notice that an appeal of the IURC’s May 2009 order will be taken to the Indiana Court of Appeals; IPL believes it has meritorious defenses to the Complainants’ claims and it will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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

In January 2008, the Tioga Preservation Group and two individuals (collectively, “TPG”) filed a land use appeal with the Tioga County Court of Common Pleas of Pennsylvania (“Common Pleas Court”) with respect to the Tioga County Planning Commission’s grant to AES Armenia Mountain Wind, LLC (“Armenia Mountain”) of preliminary approval for development of a wind project. Although the appeal is against the Tioga County Planning Commission, Armenia Mountain joined as an interested party. In August 2008, the Common Pleas Court entered an Opinion and Order denying TPG’s land use appeal with prejudice and affirming Armenia Mountain’s preliminary approval. In September 2008, TPG filed a Notice of Appeal with the Commonwealth Court of Pennsylvania. In October 2008, the Planning Commission notified Armenia Mountain that all of the conditions to the preliminary approval had been satisfied and that Armenia Mountain was authorized to start construction of the wind project. In March 2009, the Commonwealth Court denied TPG’s appeal, also affirming Armenia Mountain’s preliminary approval. In April 2009, TPG filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court asking it to review the Commonwealth Court’s order. We cannot predict whether the Pennsylvania Supreme Court will agree to hear this petition.

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska, filed a complaint in the U.S. District Court for the Northern District of California against the Company and numerous unrelated companies, claiming that the defendants’ alleged GHG emissions are destroying the plaintiffs’ alleged land. The plaintiffs assert nuisance and concert of action claims against the Company and the other defendants, and a conspiracy claim against a subset of the other defendants. The plaintiffs seek to recover relocation costs, indicated in the complaint to be from $95 million to $400 million, and other alleged damages from the defendants, which are not quantified. The Company has filed a motion to dismiss the case, which the plaintiffs have opposed. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In June 2008, an individual plaintiff, on his own behalf and on behalf of two environmental groups, filed a constitutional protection action (recurso de protección) with the Valparaiso Court of Appeals (“VCA”) against the Comisión Regional del Medio Ambiente, V Region (Chile) (“COREMA”) and other authorities that participated in the environmental assessment of the Campiche Thermal Power Plant (“Plant”), seeking to revoke the environmental permit for the Plant. Empresa Eléctrica Campiche (“EEC”), an affiliate of the Company, joined the action as an interested party. In January 2009, the VCA held that the permit was not properly granted and was thus illegal. According to the VCA the Plant was located in a zone that did not allow for its construction (an allegedly unsafe area) and thus affected the rights of the plaintiffs to live in an unpolluted environment. Later in January 2009, EEC and COREMA filed separate appeals with the Supreme Court of Chile against the VCA’s decision. The Supreme Court heard arguments on the appeals in April 2009 and later requested information about the location of the Plant and related issues from the Ministry of Housing and Urbanism and the Municipality of

Puchuncaví. In June 2009, the Supreme Court issued a decision affirming the VCA’s decision reasoning that the relevant land regulation did not allow for the Plant’s construction. Construction of the Plant has stopped as a consequence of the Supreme Court’s decision. EEC is working with Chilean authorities to attempt to find a solution that might allow the Plant’s construction to resume. Campiche has issued to the EPC contractor a notification of Force Majeure under the relevant construction contract. The EPC contractor has disputed such declaration of Force Majeure by Campiche. Management believes it is probable that the Campiche project will be completed. However, if Gener is unable to complete the project, AES may be required to record an impairment of Campiche 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, 2009 and potential termination costs, Gener could incur an impairment of approximately $186 million. In the event an impairment is taken with regard to the project, the amount of such impairment will depend on a number of factors, including our ability to recover project costs. In addition, Empresa Electrica Ventanas S.A., a 270 MW gross coal plant under development in Ventanas, is reviewing the potential effects, if any, that the decision of the Supreme Court could have on the Nueva Ventanas project.

A public civil action has been asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of Sao Paulo in 2006 found that Eletropaulo should either repair the alleged environmental damage by demolishing certain construction and reforesting the area, pursuant to a project which would cost approximately $628,000, or pay an indemnification amount of approximately $5 million. Eletropaulo has appealed this decision to the Supreme Court and is awaiting a decision.

In 2007, a lower court issued a decision related to a 1993 claim that was filed by the Public Attorney’s office against Eletropaulo, the São Paulo State Government, SABESP (a state owned company), CETESB (a state owned company) and DAEE (the municipal Water and Electric Energy Department), alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from Pinheiros River into Billings Reservoir. The events in question occurred while Eletropaulo was a state owned company. An initial lower court decision in 2007 found the parties liable for the payment of approximately $230 million for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo which reversed the lower court decision. It is not yet known whether this appellate decision will be appealed by the Public Attorney’s office. If so, Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 2008, IPL received a CAA Section 114 information request. The request seeks various information regarding production levels and projects implemented at IPL’s generating stations, generally for the time period from January 1, 2001 to the date of the information request. A subsequent related request extended the time period to cover certain operational data for the year 2000. 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. At this time it is not possible to predict what impact, if any, this request may have on IPL, its results of operation or its financial position.

In November 2007, the U.S. Department of Justice (“DOJ”) notified AES Thames, LLC (“AES Thames”) that the EPA had requested that the DOJ file a federal court action against AES Thames for alleged violations of the CAA, the CWA, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and the Emergency Planning and Community Right-to-Know Act (“EPCRA”), in particular alleging that AES Thames had violated (i) the terms of its Prevention of Significant Deterioration (“PSD”) air permits in the calculation of its steam load permit limit; and (ii) the CWA, CERCLA and EPCRA in connection with two spills of chlorinating agents that occurred in 2006. The DOJ subsequently indicated that it would like to settle this matter prior to filing a suit and negotiations are ongoing. During such discussions, the DOJ and EPA have accepted AES Thames method of operation and have asked AES Thames to seek a minor permit modification to clarify the air permit condition in a manner that is consistent with AES Thames’ historical

method of operation. On October 21, 2008, the DOJ proposed a civil penalty of $245,000 for the alleged violations. The Company believes that it has meritorious defenses to the claims asserted against it and if a settlement cannot be achieved, the Company will defend itself vigorously in any lawsuit.

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

In January 2009, an alleged shareholder of the Company filed a putative derivative and class action in Delaware state court against the Company and certain members of its board of directors at the time. The plaintiff claimed that aspects of Section 2.17(B) of the Company’s bylaws, concerning certain informational requirements in connection with shareholder action by written consent, violated Delaware law. The plaintiff did not seek damages but declarations that Section 2.17(B) was unlawful and void and that the board member defendants breached their respective fiduciary duties of loyalty by adopting that bylaw in October 2008. The plaintiff further sought to recover his litigation costs. In April 2009, the parties executed a stipulation of settlement requiring an amendment of Section 2.17(B), and filed the stipulation with the court for approval. In July 2009, the court approved the stipulation of settlement dismissing the action.

A CAA Section 114 information request regarding Cayuga and Somerset was received in February 2009. 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. The Company responded to the EPA’s information request in June 2009. At this time it is not possible to predict what impact, if any, this request may have on Cayuga and/or Somerset, their results of operation or their financial position.

On February 2, 2009, the Cayuga facility received a Notice of Violation from the New York State Department of Environmental Conservation that the facility had exceeded the permitted volume limit of coal ash that can be disposed of in the on-site landfill. Cayuga has met with and submitted a demonstration plan to the agency and discussions between the parties are ongoing. 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, Glencore International AG initiated arbitration against Itabo in the International Chamber of Commerce concerning the parties’ coal supply agreement. Glencore claimed that Itabo repudiated and breached the agreement by allegedly failing to purchase coal pursuant to the terms of the agreement. Glencore sought approximately $75 million in damages, plus interest, among other relief. In June 2009, the parties settled the arbitration.

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

On July 30, 2009, AES Energía Cartagena S.R.L. (“AES Cartagena”) received a notice from the Spanish national energy regulator, Comisión Nacional de Energía (“CNE”), stating that it intends to invoice AES Cartagena for CO₂ allowances previously granted to AES Cartagena for 2007, 2008 and the first half of 2009. CNE alleges that generators selling into the electricity pool offered prices that included the costs of purchasing CO₂ allowances to offset their emissions, despite the fact that the generators were allegedly allocated free CO₂

allowances to cover some or all of those emissions. CNE’s notice asserts that AES Cartagena’s revenues should be reduced by roughly the amount of free CO₂ allowances allocated to AES Cartagena for 2007, 2008 and the first half of 2009, which CNE calculates as approximately $29 million for 2007-2008 and an amount to be determined for the first half of 2009. AES Cartagena is currently considering its options with respect to CNE’s notice, including whether to contest the allegations in CNE’s notice. There can be no assurance that any attempt to contest CNE’s allegations will be successful. Regardless of whether AES Cartagena contests such allegations, it will likely seek remedies for any CNE invoice from GDF-Suez under its long-term energy agreement (the “Energy Agreement”) with GDF-Suez, as further described below. AES Cartagena understands that CNE has sent notices to other generators, also alleging that they sold into the electricity pool at prices which reflected the cost of purchasing CO₂ allowances when they allegedly received free allowances. AES Cartagena does not sell electricity into the electricity pool, but instead, it provides electricity directly to GDF-Suez when requested by GFD-Suez to do so, subject to the terms of the Energy Agreement. AES Cartagena receives a fixed capacity payment from GDF-Suez under the Energy Agreement in return for keeping the plant available to run when requested. GDF-Suez then sells the electricity provided by AES Cartagena directly into the electricity pool and GDF-Suez receives all of the revenue associated with such sales into the electricity pool. Accordingly, AES Cartagena believes that GDF-Suez should bear the costs associated with any invoices from CNE. However, GDF-Suez has previously disputed that it is liable under the Energy Agreement for CO₂ emissions related costs. Therefore, if CNE invoices AES Cartagena, AES Cartagena would likely have to pay the amount of the invoices and then seek reimbursement of the payment from GDF-Suez by initiating formal dispute resolution proceedings against them. While the Company believes that AES Cartagena has meritorious arguments in any such proceedings, dispute resolution involves a number of inherent uncertainties. Therefore, we cannot predict the outcome of any dispute resolution proceedings that might be necessary to attempt to pass the costs of the invoices to GDF-Suez.

9. PENSION PLANS

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


	Three Months Ended June 30,												Six Months Ended June 30,
	2009						2008						2009						2008
	U.S.			Foreign			U.S.			Foreign			U.S.			Foreign			U.S.			Foreign
	(in millions)												(in millions)
Service cost	$	2		$	3		$	2		$	4		$	4		$	6		$	3		$	7
Interest cost		9			111			8			123			17			211			16			244
Expected return on plan assets		(6	)		(90	)		(9	)		(111	)		(13	)		(171	)		(17	)		(220	)
Amortization of initial net asset		-			-			-			-			-			(1	)		-			(2	)
Amortization of prior service cost		1			-			-			-			2			-			1			-
Amortization of net loss		4			2			1			1			8			3			1			2

Total pension cost	$	10		$	26		$	2		$	17		$	18		$	48		$	4		$	31

Total employer contributions for the six months ended June 30, 2009 for the Company’s U.S. and foreign subsidiaries were $10 million and $85 million, respectively. The expected remaining scheduled annual employer contributions for 2009 are $12 million for U.S. subsidiaries and $66 million for foreign subsidiaries. As of June 30, 2009, the depreciation of the U.S. Dollar compared to the Brazilian Real (“BRL”) resulted in an increase of $18 million in the estimate of total remaining expected 2009 employer contributions for foreign subsidiaries when translated into U.S. Dollar. This increase is entirely due to the change in the exchange rate used to translate the BRL, the local currency, to a U.S. Dollar estimate of expected future contributions. The expected contributions, which will be made in BRL, remain unchanged.

10. COMPREHENSIVE INCOME

The components of comprehensive income for the three and six months ended June 30, 2009 and 2008 were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in millions)
Net income	$	531		$	1,160		$	1,032		$	1,568
Change in fair value of available-for-sale securities, net of income tax benefit of $—, $—, $— and $1, respectively		-			-			-			(1	)
Foreign currency translation adjustments, net of income tax expense of $30, $13, $31 and $16, respectively		402			210			333			290

Derivative activity:
Reclassification to earnings, net of income tax benefit of $15, $6, $26 and $10, respectively		(37	)		1			(43	)		-
Change in derivative fair value, net of income tax (expense) benefit of $(29), $8, $(69) and $94, respectively		86			11			186			(146	)

Total change in fair value of derivatives		49			12			143			(146	)
Change in unfunded pension obligation, net of income tax (expense) benefit of $(1), $12, $(1) and $12, respectively		1			(11	)		2			(11	)

Other comprehensive income		452			211			478			132

Comprehensive income		983			1,371			1,510			1,700
Less: Comprehensive income attributable to noncontrolling interests⁽¹⁾		(518	)		(426	)		(818	)		(618	)

Comprehensive income attributable to The AES Corporation	$	465		$	945		$	692		$	1,082

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

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


	(in millions)
Foreign currency translation adjustment	$	2,518
Unrealized derivative losses		159
Unfunded pension obligation		170

Accumulated other comprehensive loss as of June 30, 2009	$	2,847

11. SEGMENTS

As further described below, beginning with the Company’s Quarterly Report on Form 10-Q for the three months ended March 31, 2009 filed with the SEC on May 8, 2009, the Company modified its segment reporting in accordance with FAS No. 131, Disclosures about Segments of an Enterprise and Related Information (“FAS No. 131”).

Background

Through the end of 2008, the Company organized its operations for management reporting purposes along two primary lines of business – the generation of electricity (“Generation”) and the distribution of electricity (“Utilities”) within four geographic regions: Latin America; North America; Europe & Africa; and Asia & the Middle East (“Asia”). Three regions, North America, Latin America and Europe & Africa, are engaged in both Generation and Utility businesses. Our Asia region only has Generation businesses. This regional management structure resulted in the Company reporting seven segments, as defined in FAS No. 131 in the 2008 Form 10-K. These reportable segments included Latin America – Generation, Latin America – Utilities, North America – Generation, North America – Utilities, Europe & Africa – Generation, Europe & Africa – Utilities and Asia – Generation. In addition, the Company reported certain activities in “Corporate and Other” including corporate overhead costs which are not directly associated with the operations of our primary operating segments; and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation. The Company’s alternative energy business which included AES Wind Generation, climate solutions, and certain other initiatives, was managed by our alternative energy group. The associated revenue, development and operational costs were reported under “Corporate and Other” since its results were not material to the presentation of the Company’s operating segments.

2009 Segment Reporting

Management Reporting Structure – In early 2009, we implemented certain internal organizational changes in an effort to streamline the organization. These changes affected how results are reported internally for management review, but did not change any of the chief operating decision makers. The new management reporting structure continues to be organized along our two lines of businesses, but there are now three regions: (1) Latin America & Africa; (2) North America and AES Wind; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The Company no longer has an alternative energy group. Instead, AES Wind Generation is managed with our North America region while climate solutions projects are now managed in the region in which they are located. In addition to the change in regional management structure, with the exception of AES Wind Development, the Company now manages all development efforts centrally through a development group.

Segment Reporting Structure – The new segment reporting structure uses the management reporting structure as its foundation. The Company’s segment reporting structure continues to be organized along our two lines of business and three regions to reflect how the Company manages the business internally. The Company applied the guidance in FAS No. 131, which provides certain quantitative thresholds and aggregation criteria, and the Company concluded that it now has six reportable segments. The operating segments comprising the former Europe & Africa Generation and Utilities reportable segments are no longer managed together. Under the new management structure Africa is managed with the Latin America region and Europe is managed with the Asia region. Only Europe – Generation was determined to be a reportable segment based on the Company’s application of FAS No. 131. As described below, our Europe Utilities, Africa Utilities and Africa Generation operating segments are now reported within “Corporate and Other” because they do not meet the quantitative thresholds for separate disclosure under FAS No. 131.

Therefore, as a result of this analysis, the Company now reports six segments, which include:

•

Latin America – Generation;

•

Latin America – Utilities;

•

North America – Generation;

•

North America – Utilities;

•

Europe – Generation;

•

Asia – Generation.

Corporate and Other – Corporate and Other now includes corporate overhead costs which are not directly associated with the operations of our six primary reportable segments, other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation, the operations for the Company’s Europe and Africa Utilities and Africa Generation businesses, the operations of AES Wind and the development and operational costs related to the development group. None of these operations is currently material to our presentation of reportable segments, individually or in the aggregate.

The Company uses multiple measures to evaluate the performance of its segments. The GAAP measure that most closely aligns with the Company’s performance measures is gross margin. Gross margin is defined as total revenue less operating expenses including depreciation and amortization, local fixed operating and other overhead costs. Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within the Latin America region. No inter-segment revenue relationships exist between other segments. Corporate allocations include certain management fees and self insurance activity which are reflected within segment gross margin. All intra-segment activity has been eliminated with respect to revenue and gross margin within the segment; inter-segment activity has been eliminated within the total consolidated results.

As required by FAS No. 131, all prior period information has been recast to reflect the realignment of reportable segments.

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


	Total Revenue					Inter-segment						External Revenue
Three Months Ended June 30,	2009		2008			2009			2008			2009		2008
						(in millions)
Latin America–Generation	$	895	$	1,177		$	(203	)	$	(252	)	$	692	$	925
Latin America–Utilities		1,367		1,577			-			-			1,367		1,577
North America–Generation		475		538			-			-			475		538
North America–Utilities		261		267			-			-			261		267
Europe–Generation		152		268			-			-			152		268
Asia–Generation		337		301			-			-			337		301
Corporate and Other		8		(2	)		203			252			211		250

Total Revenue	$	3,495	$	4,126		$	-		$	-		$	3,495	$	4,126


	Total Revenue					Inter-segment						External Revenue
Six Months Ended June 30,	2009		2008			2009			2008			2009		2008
						(in millions)
Latin America–Generation	$	1,786	$	2,383		$	(386	)	$	(510	)	$	1,400	$	1,873
Latin America–Utilities		2,581		3,040			-			-			2,581		3,040
North America–Generation		977		1,089			-			-			977		1,089
North America–Utilities		551		516			-			-			551		516
Europe–Generation		356		572			-			-			356		572
Asia–Generation		584		613			-			-			584		613
Corporate and Other		38		(6	)		386			510			424		504

Total Revenue	$	6,873	$	8,207		$	-		$	-		$	6,873	$	8,207


	Total Gross Margin				Inter-segment						External Gross Margin
Three Months Ended June 30,	2009		2008		2009			2008			2009		2008
					(in millions)
Latin America–Generation	$	335	$	319	$	(193	)	$	(247	)	$	142	$	72
Latin America–Utilities		175		254		203			252			378		506
North America–Generation		122		242		13			6			135		248
North America–Utilities		51		61		1			-			52		61
Europe–Generation		27		64		-			-			27		64
Asia–Generation		77		40		3			1			80		41
Corporate and Other		60		49		(27	)		(12	)		33		37

Total Gross Margin	$	847	$	1,029	$	-		$	-		$	847	$	1,029


	Total Gross Margin				Inter-segment						External Gross Margin
Six Months Ended June 30,	2009		2008		2009			2008			2009		2008
					(in millions)
Latin America–Generation	$	707	$	718	$	(373	)	$	(500	)	$	334	$	218
Latin America–Utilities		346		479		387			510			733		989
North America–Generation		242		402		17			11			259		413
North America–Utilities		121		113		2			1			123		114
Europe–Generation		95		179		1			-			96		179
Asia–Generation		124		88		4			2			128		90
Corporate and Other		95		92		(38	)		(24	)		57		68

Total Gross Margin	$	1,730	$	2,071	$	-		$	-		$	1,730	$	2,071

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


	Total Assets
	June 30, 2009		December 31, 2008
	(in millions)
Latin America–Generation	$	9,155	$	8,228
Latin America–Utilities		8,262		7,267
North America–Generation		6,343		6,426
North America–Utilities		3,034		3,093
Europe–Generation		2,798		2,656
Asia–Generation		3,172		3,239
Corporate and Other		4,654		3,897

Total Assets	$	37,418	$	34,806

12. OTHER INCOME (EXPENSE)

The components of other income were summarized as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(in millions)
Tax credit settlement	$	-	$	-	$	129	$	-
Management performance incentive		-		-		80		-
Gain on extinguishment of liabilities		3		117		3		124
Gain on sale of assets		2		1		8		4
Other		17		32		24		67

Total other income	$	22	$	150	$	244	$	195

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

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 $150 million for the three months ended June 30, 2008 included a $117 million gain related to the extinguishment of a tax liability at Eletropaulo, whose net impact to the Company after noncontrolling interests was $19 million, and insurance recoveries of $14 million for damaged turbines at Uruguaiana.

Other income of $244 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; see further discussion of this transaction in Note 14 — Acquisitions and Dispositions. Other income of $195 million for the six months ended June 30, 2008 included the previously mentioned gain on extinguishment of a tax liability and insurance recoveries in the second quarter of 2008, as well as $14 million of compensation received from the local government for the impairment of plant assets and cessation of the power purchase agreement associated with a settlement agreement to shut down the Hefei generation facility in China recorded during the first quarter of 2008.

The components of other expense were summarized as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(in millions)
Loss on extinguishment of debt	$	-	$	69	$	-	$	69
Loss on sale and disposal of assets		9		8		14		15
Legal/dispute settlement		1		1		10		15
Other		20		7		28		11

Total other expense	$	30	$	85	$	52	$	110

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

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 $85 million for the three months ended June 30, 2008 included $69 million of losses related to the retirement of debt at the Parent Company in connection with a refinancing in June 2008 and the refinancing of $375 million of debt by IPALCO in April 2008.

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 the disposal of assets at Eletropaulo and Andres. Other expense of $110 million for the six months ended June 30, 2008 included the previously mentioned loss on debt retirements in the second quarter of 2008, as well as losses on disposal of assets at one of our Brazilian subsidiaries and legal reserves.

13. DISCONTINUED OPERATIONS

The Company had no discontinued operations for the three and six months ended June 30, 2009.

In December 2008, the Company completed the sale of its 70% equity interest in Jiaozuo AES Wanfang Power Co., Ltd. (“Jiaozuo”), which was reported in the Asia Generation segment, for approximately $73 million, net of any withholding taxes. For the three and six months ended June 30, 2008, income from operations of discontinued businesses was $1 million and $3 million, respectively, and reflected the operations of Jiaozuo.

The following table summarizes the revenue, income tax expense and income from operations of the discontinued businesses for the three and six months ended June 30, 2008:


	Three Months Ended June 30, 2008		Six Months Ended June 30, 2008
	(in millions)
Revenue	$	20	$	43

Income from operations of discontinued businesses	$	-	$	3
Income tax benefit		1		-

Income from operations of discontinued businesses, net of tax	$	1	$	3

Loss on disposal of discontinued operations	$	-	$	(1	)

14. ACQUISITIONS AND DISPOSITIONS

Dispositions

On May 30, 2008 the Company completed the sale of two of its wholly-owned subsidiaries in Kazakhstan, AES Ekibastuz LLP (“Ekibastuz”), a coal-fired generation plant, and Maikuben West LLP (“Maikuben”), a coal mine. Total consideration received in the transaction was approximately $1.1 billion plus additional potential earn-out provisions, a three-year management and operation agreement and a capital expenditures program bonus. Due to the fact that AES was to have significant continuing involvement in the management and operations of the businesses through its three-year management and operation agreement, the results of operations from Ekibastuz and Maikuben were included in income from continuing operations through the date of the disposition. Income earned as a result of the three-year management and operation agreement has been recognized as management fee income for all periods subsequent to the disposition.

On March 23, 2009, the Company and Kazakhmys PLC (“Kazakhmys”), which purchased the subsidiaries, mutually agreed to terminate the original sale agreement and the three-year management and operation agreement. In connection with the termination of these agreements, the Company and Kazakhmys entered into a new agreement (the “2009 Agreement”). Under the 2009 Agreement, Kazakhmys agreed to pay the Company an $80 million performance incentive bonus in April 2009 for management services provided in 2008. This was recognized as “Other Income” in the Company’s condensed consolidated statement of operations during the first quarter of 2009. The cash was received by the Company in April 2009. A $13 million gain was recognized related to a reversal of a tax contingency for a contractual obligation, under which the Company provided indemnification to Kazakhmys, which expired in January 2009. This was recorded as an adjustment to the gain on the sale of Ekibastuz and Maikuben during the first quarter of 2009.

The 2009 agreement also provided for an additional $102 million payment, primarily related to the termination of the management agreement, payable to AES in January 2010. In May 2009, Kazakhmys provided an irrevocable standby letter of credit from a credit worthy institution to AES of $102 million to secure the final payment. The payment of the final component of the management termination agreement is not contingent upon

any future events. As a result, the Company recognized an additional gain on the sale of Ekibastuz and Maikuben of approximately $98.5 million in the second quarter of 2009.

The parties agreed to terminate both the Stock Purchase Agreement and the Management Agreement, and have further agreed to a mutual release of prior claims. As part of the management termination agreement, AES agreed to transition the management of the businesses to Kazakhmys over a period of 100 days from March 13, 2009. The transition period ended June 21, 2009 and at that time the management of Ekibastuz and Maikuben became the responsibility of Kazakhmys. Despite the termination of the management agreement, the Company’s involvement with the businesses remained in place for more than one year from the date of the sale; therefore, the Company has continued to include the businesses as part of continuing operations in the condensed consolidated financial statements for all periods presented.

Excluding income earned under the three-year management and operation agreement (terminated in March 2009), Ekibastuz and Maikuben generated no revenue for the three and six months ended June 30, 2009 and generated revenue of $45 million and $108 million for the three and six months ended June 30, 2008.

15. EARNINGS PER SHARE

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

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


	Three Months Ended June 30,
	2009					2008
	Income		Shares	$ per Share		Income		Shares	$ per Share
	(in millions except per share data)
BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders	$	303	667	$	0.45	$	902	672	$	1.34
EFFECT OF DILUTIVE SECURITIES
Convertible securities		6	15		-		6	15		(0.03	)
Stock options		-	1		-		-	6		-
Restricted stock units		-	1		-		-	1		-

DILUTED EARNINGS PER SHARE	$	309	684	$	0.45	$	908	694	$	1.31


	Six Months Ended June 30,
	2009					2008
	Income		Shares	$ per Share		Income		Shares	$ per Share
	(in millions except per share data)
BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders	$	521	666	$	0.78	$	1,134	671	$	1.69
EFFECT OF DILUTIVE SECURITIES
Convertible securities		-	-		-		11	15		(0.04	)
Stock options		-	1		-		-	6		-
Restricted stock units		-	1		-		-	2		-

DILUTED EARNINGS PER SHARE	$	521	668	$	0.78	$	1,145	694	$	1.65

There were approximately 20,169,060 and 7,616,664 additional options outstanding at June 30, 2009 and 2008, respectively, that could potentially dilute basic earnings per share in the future. Those options were not included in the computation of diluted earnings per share because the exercise price exceeded the average market price during the related periods. For the three months ended June 30, 2009 and 2008, no convertible debentures were omitted from the earnings per share calculation because they were all dilutive. For the six months ended June 30, 2009, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. For the six months ended June 30, 2008, there were no convertible debentures omitted from the earnings per share calculation because they were all dilutive. During the six months ended June 30, 2009, 2,096,389 shares of common stock were issued under the Company’s profit sharing plan and 113,484 shares of common stock were issued upon the exercise of stock options.

16. ACCOUNTS RECEIVABLE SECURITIZATION

IPL, a consolidated subsidiary of the Company, formed IPL Funding Corporation (“IPL Funding”) in 1996 as a special purpose entity to purchase, on a revolving basis, up to $50 million of the accounts receivable and related collections of IPL. IPL Funding is consolidated by IPL and IPALCO, the holding company of IPL, as a qualified special-purpose entity under FAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. IPL Funding has entered into a sale facility with unrelated parties (“the Purchasers”) pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, interests in the pool of receivables purchased from IPL up to the lesser of (1) an amount determined pursuant to the sale facility that takes into account certain eligibility requirements and reserves relating to the receivables, or (2) $50 million. During the second quarter of 2009, this agreement was extended through May 25, 2010. Accounts receivable on the Company’s condensed consolidated balance sheets are stated net of the $50 million sold and include $78 million and $87 million as of June 30, 2009 and December 31, 2008, respectively, related to IPL Funding’s accounts receivable.

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

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

The losses recognized on the sales of receivables were $0.3 million and $0.4 million for the three months ended June 30, 2009 and 2008, respectively, and $0.6 million and $1 million for the six months ended June 30, 2009 and 2008, respectively. These losses are included in other expense on the condensed consolidated statements of operations. The amount of the losses recognized depends on the previous carrying amount of the financial assets involved in the transfer, allocated between the assets sold and the interests that continue to be held by the transferor based on their relative fair value at the date of transfer, and the proceeds received.

There were no proceeds from new securitizations for each of the three and six months ended June 30, 2009 and 2008. IPL Funding pays IPL annual service fees totaling $0.6 million, which is financed by capital contributions from IPL to IPL Funding.

The following table shows the receivables sold and retained interests as well as the cash flows for the periods ended June 30, 2009 and 2008:


	Six Months Ended June 30,
	2009		2008
	(in millions)
Retail receivables at IPL	$	128	$	119
Less: Retained interests		78		69

Net receivables sold	$	50	$	50


	Six Months Ended June 30,
	2009		2008
	(in millions)
Cash proceeds from interest retained	$	325	$	275
Cash proceeds from sold receivables	$	202	$	198

IPL and IPL Funding provide certain indemnities to the Purchasers, including indemnification in the event that there is a breach of representations and warranties made with respect to the purchased receivables. IPL Funding and IPL each have agreed to indemnify the Purchasers on an after-tax basis for any and all damages, losses, claims, liabilities, penalties, taxes, costs and expenses at any time imposed on or incurred by the indemnified parties arising out of, or otherwise relating to, the sale facility, subject to certain limitations as defined in the sale facility.

Under the sale facility, if IPL fails to maintain certain financial covenants regarding interest coverage and debt to capital, it would constitute a “termination event.” As of June 30, 2009, IPL was in compliance with such covenants. In the event that IPL’s credit rating falls below a threshold identified in the sale facility, the facility agent has the ability to replace IPL as the collection agent and declare a “lock-box” event. Under a lock-box event or a termination event, the facility agent has the ability to require all proceeds of purchased receivables of IPL to be directed to lock-box accounts within 45 days of notifying IPL. In addition, a termination event would also give the facility agent the option to take control of the lock-box account, give the Purchasers the option to discontinue the purchase of new receivables, and require all proceeds to be used to reduce the Purchaser’s investment and pay other amounts owed to the Purchasers and the facility agent. This could reduce the operating capital available to IPL by the aggregate amount of any purchased receivables up to $50 million.

17. SUBSEQUENT EVENTS

On July 30, 2009, Cartagena received a notice from the Spanish national energy regulator, CNE, stating its intention to invoice Cartagena for CO₂ allowances previously granted to Cartagena from 2007 through the first half of 2009. The impact to the Parent Company, if any, cannot be determined at this time. See further discussion in Note 8 — Contingencies and Commitments — Litigation.

On July 31, 2009, the Company secured $221 million in project financing and credit facilities for its 101 MW Armenia Mountain wind project located in Pennsylvania. Commercial operation is scheduled for the fourth quarter of 2009.

Subsequent events have been evaluated through August 6, 2009, the date of issuance of this Form 10-Q.

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

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

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 the “Risk Factors” section of our 2008 Form 10-K filed on February 26, 2009. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We undertake no obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise interested parties of the risks and factors that may affect our business.

The interim financial statements filed on this Form 10-Q and the discussions contained herein should be read in conjunction with our 2008 Form 10-K.

Overview of Our Business

We are a global power company. We operate two primary lines of business. The first is our Generation business, where we own and/or operate power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. The second is our Utilities business, where we own and/or operate utilities to distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. The Utilities line of business also includes our integrated utilities that both distribute and generate electricity. Each of our primary lines of business generates approximately half of our revenues.

We are also continuing to expand our wind generation business and are pursuing additional renewable projects in solar and climate solutions. These initiatives are not material contributors to our operating results, but we believe that they may become material in the future. For additional information regarding our Business, see Item 1: Business in our 2008 Form 10-K.

Our Company is organized along our two lines of businesses in three regions: (1) Latin America & Africa; (2) North America and AES Wind Generation; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. AES Wind Generation is managed as part of our North America region while climate solutions projects are managed in the region in which they are located. With certain exceptions, the Company manages development efforts centrally through a development group. The Company recently realigned its accounting segments to reflect the structure described above. See Footnote 15 in the 2008 Form 10-K for a discussion of these segments.

Key Drivers of Our Results of Operations. Our Generation and Utilities businesses are distinguished by the nature of their customers, operational differences, cost structure, regulatory environment, and risk exposure. As a result, each line of business has slightly different drivers which affect operating results. Performance drivers for our Generation businesses include, among other things, plant availability, reliability and efficiency, management of fixed and operational 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 market price of electricity and the marginal cost of production. Growth in our Generation business is largely tied to securing new PPAs expanding capacity in our existing facilities, and building new power plants. Performance drivers for our Utilities businesses include, but are not limited to, reliability of service, negotiation of tariff adjustments, compliance with extensive regulatory requirements, management of working capital including collection of receivables, and in developing countries, reduction of commercial and technical losses. The results of operations of our Utilities businesses are sensitive to changes in economic growth and weather conditions in the areas in which they operate.

One of the key factors which affects our Generation business is our ability to enter into long-term contracts for the sale of electricity and the purchase of fuel used to produce that electricity. These contracts are intended to reduce the volatility associated with fuel prices and the price of electricity by fixing the revenues and costs for these businesses. The majority of the electricity produced by our Generation businesses is sold under long-term contracts, or PPAs, to wholesale customers. Approximately 73% of the revenues from our Generation businesses during the first half of 2009 were derived from plants that operate under PPAs of three years or longer for 75% or more of their output capacity. In turn, most of these businesses enter into long-term fuel supply contracts or fuel tolling contracts where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. While these long-term contractual agreements reduce exposure to volatility in the market price for electricity and fuel, the amount of earnings and cash flow predictability varies by business based on the extent to which facility’s generation capacity and fuel requirements are contracted and the negotiated terms of these agreements.

When fuel costs increase, many of our Generation businesses with long-term contracts and our Utilities businesses are able to pass these costs on to the customer through fuel pass-through or fuel indexing arrangements in their contracts or through increases in tariff rates. Therefore, in a rising fuel cost environment increases in fuel costs for these businesses often result in increases in revenue (though not necessarily on a one-for-one basis). Conversely, in a declining fuel cost environment, decreases in fuel costs can result in decreases in revenue. While these circumstances may not have a large impact on gross margin, they can significantly affect gross margin as a percentage of revenue.

Diversification also helps us to mitigate some operational risks. Our portfolio employs a broad range of fuels, including coal, gas, fuel oil and renewable sources such as hydroelectric power, wind and solar, which reduces the risks associated with dependence on any one fuel source. Our presence in mature markets helps reduce the volatility associated with our businesses in faster-growing emerging markets. In addition, as noted above, our Generation portfolio is largely contracted, which reduces the risk related to the market prices of electricity and fuel. We also attempt to limit risk by hedging certain currency and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the business that issued that debt. However, we only hedge a portion of our currency and commodity risks, and our businesses are still subject to these risks, as further described in the 2008 Form 10-K, Item 1A – Risk Factors, “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” and “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.”

Another key driver of our results is our ability to bring new businesses into commercial operations successfully. We currently have an aggregate of 3,156 MW of projects under construction in 10 countries. Our prospects for increases in operating results and cash flows are dependant upon successful completion of these projects on time and within budget. However, as disclosed in the 2008 Form 10-K, Item 1A – Risk Factors, “Our business is subject to substantial development uncertainties,” construction is subject to a number of risks, including risks associated with siting, financing and permitting, and our ability to meet construction milestones. Delays or inability to complete projects 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 where we conduct business, we are subject to extensive and complex governmental regulations which affect most aspects of our business, such as

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

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

Key Drivers of Results in the Second Quarter

As described further below, during the quarter ended June 30, 2009, our results of operations, including the key metrics set forth below, were impacted by factors including:

•

Foreign currency losses on our international business operations;

•

Spot market prices

•

Fluctuations in fuel and other commodity prices, including the impact of derivative transactions; and

•

Decreases in demand (as measured by volume) at certain of our businesses.

During the first six months of 2009, we have been able to address these challenges through its fuel and geographic diversification, operational improvements at certain businesses, improvements in the management of working capital, and cost reductions including development expense. During the second quarter, we also incurred a lower effective tax rate primarily from a tax benefit recorded upon the release of a valuation allowance at a U.S. and Brazilian subsidiary, we recognized a significant gain from the termination of a management agreement and we settled a legal claim of a European affiliate.

However, as a result of the macroeconomic challenges described above (and other factors described below), our gross margin has declined by 18% for the three months ended June 30, 2009 and 16% for the six months ended June 30, 2009. Management believes that the challenges described above may continue for some period of time, and will continue to seek ways to mitigate the effects of the global recession. However, there can be no assurance regarding our ability to do so in future periods. For example, during the second quarter of 2009, low natural gas prices caused a reduction in electricity prices which have placed pressure on certain North American coal-fired plants. At the same time, our gas-fired plants in countries such as Chile have benefited from low gas prices, which have helped that business expand margins and volume. The ability of these gas-fired plants to continue this performance (and mitigate the challenges described above) depends on access to fuel, continued plant availability, weather and other factors which may not recur in future periods. For further discussion of the impact of the global recession on our business, please see “Management’s Discussion and Analysis — Key Trends and Uncertainties — Global Recession” in this Form 10-Q.


	Three Months Ended June 30,								Six Months Ended June 30,
	2009			2008			% Change		2009			2008			% Change
	($’s in millions, except per share amounts)								($’s in millions, except per share amounts)
Revenue	$	3,495		$	4,126		-15	%	$	6,873		$	8,207		-16	%
Gross margin	$	847		$	1,029		-18	%	$	1,730		$	2,071		-16	%
Gross margin as a % of revenue		24	%		25	%				25	%		25	%
Net income attributable to The AES Corporation	$	303		$	903		-66	%	$	521		$	1,136		-54	%
Net cash provided by operating activities	$	495		$	314		58	%	$	871		$	784		11	%

Our second quarter financial results include the following highlights:

Revenue

Revenue decreased $631 million, or 15%, to $3.5 billion for the three months ended June 30, 2009 compared with the same period in 2008. The unfavorable impact of foreign currency of $520 million, largely driven by the Brazilian Real, the impact of lower energy prices at our generation business in Chile and a decrease in wholesale prices in North America contributed to an overall decrease in revenue for the quarter.

Revenue decreased $1.3 billion, or 16%, to $6.9 billion for the six months ended June 30, 2008 compared with the same period in 2008 primarily due to the unfavorable impact of foreign currency of $1.1 billion, largely driven by the Brazilian Real, and generation rates and volume in Latin America partially offset by the contribution of our new business in Asia.

Gross Margin

Gross margin decreased $182 million, or 18%, to $847 million for the three months ended June 30, 2009 compared with the same period in 2008 primarily due to the unfavorable impact of foreign currency of $101 million and mark-to-market derivative adjustments of certain commodity contracts partially offset by improved operations at our Latin America generation businesses and the impact of new businesses in Asia.

Gross margin decreased $341 million, or 16%, to $1.7 billion for the six months ended June 30, 2009 compared with the same period in 2008 primarily due to the unfavorable impact of foreign currency of $238 million and mark-to-market derivative adjustments of certain commodity contracts and the lack of contribution from the Kazakhstan businesses sold in May 2008 partially offset by improved operations in Latin America and Asia.

The Company’s gross margin may continue to be significantly impacted by global macroeconomic conditions such as the volatility in currency exchange rates and commodity prices for fuel and other resources that we use in our business and reduced demand.

Gross margin as a percentage of revenue for the three and six months ended June 30, 2009 compared with the same period in 2008 remained relatively flat at 24% and 25%, respectively. Please refer to Segment Analysis for further discussion of gross margin as a percentage of revenue for each of our reportable segments.

Net Income Attributable to The AES Corporation

Net income attributable to The AES Corporation decreased $600 million or 66% to $303 million for the three months ended June 30, 2009 compared with the same period in 2008. The decrease was primarily attributable to the following events that occurred in 2008. In 2008, the Company recognized a net gain of $908 million from the sale of two wholly-owned subsidiaries in Kazakhstan, AES Ekibastuz (“Ekibastuz”) and Maikuben West LLP (“Maikuben”) which occurred in May 2008, which was partially offset by $144 million additional tax expense on the repatriation of a portion of the sale proceeds. Additionally in 2008, the Company recognized net pre-tax gains on mark-to-market derivative adjustments of $89 million, but also incurred expenses of $55 million related to a corporate debt refinancing. These items were partially offset in 2009 by the recognition of an additional gain on the Kazakhstan sale upon the termination of the management agreement of $98.5 million and the favorable impact of foreign currency largely from transaction gains in Chile and the Philippines.

Net income attributable to The AES Corporation decreased $615 million or 54% to $521 million for the six months ended June 30, 2009 compared with the same period in 2008. This decrease was primarily attributable to the 2008 events described above. In addition, in 2008 impairment charges were recognized in Africa, Asia and Latin America as further described in Impairment expenses. These items were partially offset by a performance incentive bonus recognized in 2009 of $80 million for management services provided to the Kazakhstan

businesses following their sale in May 2008; and the $98.5 million gain from the termination of the management agreement described above.

In 2008, the $908 million gain recognized on the sale of our two Northern Kazakhstan businesses had a significant impact on net income attributable to The AES Corporation. However, while the Company engages in the sale of assets and businesses from time to time, the gain or loss recognized in any such sale will depend on a number of factors related to the asset or business that may be sold. Therefore the Company does not expect that the increase in net income attributable to The AES Corporation which occurred between 2007 and 2008, will continue in future periods nor does it expect that the decline in net income between 2008 and 2009 will continue in future periods.

Net Cash Provided By Operating Activities

Net cash provided by operating activities increased $181 million, or 58% to $495 million for the three months ended June 30, 2009 compared to the same period in 2008 despite the decrease in net income of $629 million to $531 million for the three months ended June 30, 2009. As previously described, the Company recognized a gain of $908 million associated with the sale of Ekibastuz and Maikuben in 2008. This resulted in significant income recognized without a corresponding increase in operating cash flows. These proceeds are reflected as net cash provided by investing activities. The increase in net cash provided by operating activities was primarily due to improved working capital management, which resulted in an improvement in cash provided by operating activities of $156 million at our Latin America Generation businesses, $89 million at Corporate and other, $47 million at our Europe Generation businesses, of which $80 million was the receipt of the 2008 performance incentive bonus for the management of Ekibastuz and Maikuben recognized in the first quarter of 2009, and $27 million at our Africa Generation businesses. These increases were offset by decreases of $86 million at our Latin America Utilities businesses, primarily due to lower cash earnings and increased employer pension contributions, and $62 million at our Asia Generation businesses due to higher working capital requirements.

While net income decreased $536 million to $1,032 million for the six months ended June 30, 2009, net cash provided by operating activities increased $87 million, or 11%, to $871 million compared with $784 million for the same period in 2008. This increase was primarily due to improved working capital at our subsidiaries. For further discussion, see Consolidated Cash Flows – Operating Activities.

Management’s Priorities

Management continues to focus on the following priorities:

–

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

–

Improvement of operations in the existing portfolio.

–

Completion of more than 3,000 MW construction program on time and within budget. During the quarter, the Company stopped construction on its Campiche Plant, as further described in “Operational Challenges” below.

–

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


Project	Location	Fuel	Gross MW	AES Equity Interest (Percent, Rounded)
Santa Lidia	Chile	Diesel	130	71	%
Kilroot OCGT	United Kingdom	Gas	80	99	%
InnoVent ⁽¹⁾	France	Wind	12	40	%

⁽¹⁾

InnoVent is an equity method investment of AES.

–

The Company currently expects eight generation projects totaling 835 MW to come on-line over the remainder of 2009 including Amman East in Jordan (380 MW); Guacolda 3 in Chile (152 MW), which commenced commercial operations on July 31, 2009; Dibamba in Cameroon (86 MW); Armenia Mountain, a wind project in Pennsylvania (101 MW) and other wind generation projects in China, France and Scotland (116 MW).

–

Investing excess cash to its highest and best use, including establishment of low-cost development options, reduction of debt, stock repurchases and expanding cash balances.

Key Trends and Uncertainties

Global Recession

The current global economic slowdown has caused unprecedented market illiquidity, widening credit spreads, volatile currencies, illiquidity, and increased counterparty credit risk. Despite these challenges, management currently believes that it can meet its liquidity requirements through a combination of existing cash balances, cash provided by operating activities, financings, and, if needed, borrowings under its secured and unsecured facilities. Although there can be no assurance due to the challenging times currently faced by financial institutions, management believes that the participating banks under its facilities will be able to meet their funding commitments.

The Company is subject to credit risk, which includes risk related to the ability of counterparties (such as parties to our power purchase agreements, fuel supply agreements, our hedging agreements, and other contractual arrangements) to deliver contracted commodities or services at the contracted price or to satisfy their financial or other contractual obligations. While counterparty credit risk has increased in the current crisis and there can be no assurances regarding the future, the Company has not suffered any material effects related to its counterparties for the quarter ended June 30, 2009.

The global economic slowdown could also result in a decline in the value of our assets including the businesses we operate, equity investments and projects under development, which could result in impairments that could be material to our operations. For example, during the fourth quarter of 2008, and in response to the financial market crisis, the Company reviewed and prioritized the projects in its development pipeline and consequently recognized an impairment charge of approximately $75 million ($34 million, net of noncontrolling interests and income taxes). The Company did not realize material impairment charges during the first or second quarters of 2009. However in the future, we may be required to adjust to fair value and record an impairment of certain of our assets if any of the following events occur: a significant adverse change in business climate or legal factors, an adverse action or assessment by a regulator, sale of assets at below book value, unanticipated competition, a loss of key personnel or our acquisitions do not perform as expected. The likelihood of the occurrence of these events may increase as a result of the credit crisis and deteriorating global macroeconomic conditions.

A decline in asset value could also result in a material increase in our obligations. For instance, certain subsidiaries have defined benefit pension plans. The Company periodically evaluates the value of the pension plan assets to ensure that they will be sufficient to fund their respective pension obligations. Given the declines in worldwide asset values, we are expecting an increase in pension expense and funding requirements in future periods, which may be material.

In addition, volatility in foreign currency exchange rates has had an impact on the Company’s financial results. For example, in the second quarter of 2009, our gross margin declined by $182 million compared to the same period last year, of which $238 million was due to foreign currency translation losses. If the current volatility in foreign currencies continues, our gross margin and other financial metrics could be adversely affected. It is also possible that commodity or power price volatility could impact our financial metrics. For

example, as further discussed in Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk, we estimate that a 10% decline in power prices related to our U.S. operations alone would result in an estimated reduction in gross margin of $5 million. Foreign operations may also be impacted by volatility in currency and commodity prices.

To date, other than the impacts described above, the global economic slowdown has not significantly impacted the Company. However, in the event that the credit crisis and macroeconomic conditions deteriorate further, or continue for a prolonged period, there could be a material adverse impact on the Company. The Company could be materially affected if such events or other events occur such that participating lenders under its secured and unsecured facilities fail to meet their commitments, or the Company is unable to access the capital markets on favorable terms or at all, is unable to raise funds through the sale of assets, or is otherwise unable to finance or refinance its activities, or if capital market disruptions result in increased borrowing costs (including with respect to interest payments on the Company’s variable rate debt). The Company could also be adversely affected if the foregoing effects are exacerbated or general economic or political conditions in the markets where the Company operates deteriorate, resulting in a reduction in cash flow from operations, a reduction in the availability and/or an increase in the cost of capital, a reduction in the value of currencies in these markets relative to the U.S. dollar (which could cause currency losses), an increase in the price of commodities used in our operations and construction, or if the value of its assets remain depressed or decline further. Any of the foregoing events or a combination thereof could have a material impact on the Company, its results of operations, liquidity, financial covenants, and/or its credit rating.

Regulatory Environment

As disclosed in the Company’s 2008 Form 10-K and its Form 10-Q for the three months ended March 31, 2009, the Company faces certain risks related to potential GHG legislation or regulations, including risks related to increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations.

During the quarter ended June 30, 2009, a key development in the area of GHG legislation was the passage of H.R. 2454, “The American Clean Energy and Security Act of 2009 (“ACESA”)” by the U.S. House of Representatives on June 26, 2009. The Senate is expected to consider its own version of climate change legislation later this year and several key Senate committees have begun hearings on energy and GHG legislation. Any legislation passed by the Senate will need to be reconciled with H.R. 2454, and both the House and Senate would then need to approve such reconciled legislation before it can become law.

As currently proposed, ACESA contemplates a nationwide cap and trade program to reduce U.S. emissions of CO₂ and other greenhouse gases starting in 2012. Key features of ACESA include, among other things:

•

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

•

A requirement that certain GHG emitting companies, including most power generators, surrender on an annual basis one ton of CO₂equivalent allowances or GHG offset credits for each ton of annual CO₂ equivalent emissions. Such companies will be required to meet allowance surrender requirements via the allocations of free allowances if available from the U.S. Environmental Protection Agency (“EPA”) or purchases in the open market at auctions if free allowances are not allocated, or otherwise.

•

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

•

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

•

A provision precluding the EPA from regulating GHG emissions under the existing provisions of the Clean Air Act.

•

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

•

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

At this time, if ACESA were to be enacted into law its impact on the Company’s consolidated results of operations could not be accurately predicted because of a number uncertainties with respect to the specific implementation of such legislation, including, among other provisions, the provisions set forth in ACESA related to:

•

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

•

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

•

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

•

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

•

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

•

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

In light of the substantial uncertainties noted above, the Company is currently unable to make a reasonable estimate of the potential costs associated with ACESA. At this time there is also substantial uncertainty as to whether the Senate will pass climate change legislation and whether any such legislation will be reconciled with ACESA and ultimately enacted into law. However, the Company believes that it is reasonably possible that the final provisions of any federal GHG legislation that is enacted into law or further State or regional GHG legislation that is enacted into law will impose costs on the Company which could be material to our consolidated results of operations. U.S. based operations account for 21% of the Company’s revenue for the six months ended June 30, 2009.

As disclosed in the Company’s 2008 Form 10-K, our subsidiaries conduct business in a number of countries which have ratified the Kyoto Protocol, which is currently expected to expire at the end of 2012. A United Nations climate conference called COP 15 has been planned for December of 2009 in Copenhagen, Denmark. The conference is expected to include environmental ministers and other government officials from over 100 countries to discuss a new international agreement that would succeed Kyoto. However, there are a number of uncertainties and challenges regarding these discussions, including, among other factors, the difficulties of negotiating burden-sharing between developing and wealthier nations. In light of these uncertainties, it is difficult to predict whether a successor agreement to the Kyoto Protocol will be adopted and the impact to the Company of any such agreement.

Operational Challenges

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

As previously discussed under the 2008 Form 10-K Risk Factor – Risks Associated with our Operations – Our acquisitions may not perform as expected, the Company continued to evaluate its Masinloc operations, which were acquired in April 2008. The Company completed a goodwill impairment test of the Masinloc reporting unit as of March 31, 2009 and concluded that no impairment existed. In the second quarter of 2009 we continued to monitor Masinloc’s operations noting no impairment indicators. The Company will continue to monitor Masinloc’s operating results and business outlook to identify any changes that could indicate a potential impairment. As of June 30, 2009 the book value of Masinloc’s goodwill was approximately $57 million.

As discussed under the Risk Factor - Risk Associated with our Operations – Our business is subject to substantial development uncertainties, our development projects are subject to uncertainties. On June 22, 2009, the Supreme Court of Chile invalidated an environmental permit granted on May 9, 2008 by the Chilean regulatory authorities for the Campiche Project, a 270 MW gross coal plant located in Ventanas, Chile which started construction upon approval of the environmental permit. We indirectly own a 71% interest in Empresa Electrica Campiche S.A. (“Campiche”) through our subsidiary AES Gener (“Gener”), the second largest generator of electricity in Chile. As a result of the Supreme Court’s ruling against the local permitting authority, Gener has suspended work on Campiche, which was previously expected to commence commercial operations in the second quarter of 2011. Construction on the project would resume when a solution has been implemented which complies with all applicable laws. Campiche has issued to the EPC contractor a notification of Force Majeure under the relevant construction contract. The EPC contractor has disputed such declaration of Force Majeure by Campiche. Management believes it is probable that the Campiche project will be completed. However, if Gener is unable to complete the project, AES may be required to record an impairment of Campiche proportional to its indirect ownership, which could have a material impact on earnings in the period in which it is recorded. Based on cash investment through June 30, 2009 and potential termination costs, Gener could incur an impairment of approximately $186 million. In the event an impairment is taken with regard to the project, the amount of such impairment will depend on a number of factors, including our ability to recover project costs. In addition, Empresa Electrica Ventanas S.A., a 270 MW gross coal plant under development in Ventanas, is reviewing the potential effects, if any, that the decision of the Supreme Court could have on the Nueva Ventanas project.

Second Quarter Events

On April 2, 2009, the Parent Company issued $535 million aggregate principal amount of 9.75% senior unsecured notes (“the Senior Notes”) due 2016. The notes were priced at a discount to yield 11%. The Parent Company intends to use the net proceeds from the sale of the notes for general corporate purposes, including, but not limited to, refinancing debt or providing working capital. Subsequently, the Parent Company allocated a substantial portion of the proceeds to voluntarily reduce the size of its $600 million senior unsecured credit facility by $465 million. The remaining $135 million under the senior unsecured credit facility consists of letters of credit, the majority of which supports several projects currently under construction.

On April 8, 2009, Gener issued $196 million aggregate principal amount of 8% unsecured notes in the Chilean market. The unsecured notes were issued in the Chilean market at a discount resulting in a yield of 8.5%. The proceeds from this issuance will be used to provide Gener’s funding requirements for projects currently under construction.

In March 2009, the Company reached an agreement with Kazakhmys PLC (“Kazakhmys”) to terminate the management agreement signed at the time Ekibastuz and Maikuben were sold to Kazakhmys in May 2008 for $1.1 billion. Under the original terms of the management agreement, the Company would have continued to manage and operate Ekibastuz and Maikuben through 2010. As part of the management termination agreement,

AES agreed to transition the management of the businesses to Kazakhmys over a period of 100 days from March 13, 2009. The transition period ended June 21, 2009 and at that time the management of Ekibastuz and Maikuben became the responsibility of Kazakhmys. Additionally, the termination agreement provided for an $80 million management performance incentive bonus as compensation for the management services provided by AES in 2008. This was recognized as other income in the first quarter of 2009 for which cash payment was received in April 2009. The termination agreement also provided for an additional $102 million payment, primarily related to the termination of the management agreement, payable to AES in January 2010.

In May 2009, Kazakhmys provided an irrevocable standby letter of credit to AES of $102 million to secure the final payment. The payment of the final component of the management termination agreement is not contingent upon any future events. As a result, the Company recognized an additional gain on sale of investments of approximately $98.5 million in the second quarter of 2009. For further description, please refer to Note 14 — Acquisitions and Dispositions in the condensed consolidated financial statements included in Item 1 of this Form 10-Q.

AES holds a 71% ownership interest in AES Energia Cartagena (“Cartagena”), a VIE, in which the Company is not the primary beneficiary. The Company’s investment in Cartagena is a combination of common stock and participative loans. In June 2009, Cartagena received a cash settlement of $53 million for liquidated damages including legal costs incurred related to the construction delay from December 2005 to November 2006 of the 1,200 MW generation plant in Cartagena, Spain. Cartagena used the settlement proceeds to repay a portion of the participative loans outstanding to its investors including AES. In June 2009, the Company received its proportionate share of the settlement, $35 million, which was recognized as “net equity in earnings of affiliates” as the distribution was in excess of the Company’s current investment balance of zero and AES does not have an obligation or intent to fund future cash flow requirements of Cartagena.

In June 2009, the Company secured $39.5 million in project financing to fund its 34.5 MW St. Patrick wind project in France. St. Patrick will bring AES Wind Generation’s global capacity to more than 1,300 MW when it reaches full commercial operation expected during the third quarter of 2009. St. Patrick will sell electricity generated by the wind project to Électricité de France, the French national utility, under a 15-year PPA.

Recent Developments

Consolidated Results of Operations


	Three Months Ended June 30,											Six Months Ended June 30,
RESULTS OF OPERATIONS	2009			2008			$ change			% change		2009			2008			$ change			% change
	($’s in millions, except per share amounts)											($’s in millions, except per share amounts)
Revenue:
Latin America Generation	$	895		$	1,177			$ (282)		-24	%	$	1,786		$	2,383			$ (597)		-25	%
Latin America Utilities		1,367			1,577			(210	)	-13	%		2,581			3,040			(459	)	-15	%
North America Generation		475			538			(63	)	-12	%		977			1,089			(112	)	-10	%
North America Utilities		261			267			(6	)	-2	%		551			516			35		7	%
Europe Generation		152			268			(116	)	-43	%		356			572			(216	)	-38	%
Asia Generation		337			301			36		12	%		584			613			(29	)	-5	%
Corporate and Other ⁽¹⁾		8			(2	)		10		500	%		38			(6	)		44		733	%

Total Revenue		3,495			4,126			(631	)	-15	%		6,873			8,207			(1,334	)	-16	%

Gross Margin:
Latin America Generation		335			319			16		5	%		707			718			(11	)	-2	%
Latin America Utilities		175			254			(79	)	-31	%		346			479			(133	)	-28	%
North America Generation		122			242			(120	)	-50	%		242			402			(160	)	-40	%
North America Utilities		51			61			(10	)	-16	%		121			113			8		7	%
Europe Generation		27			64			(37	)	-58	%		95			179			(84	)	-47	%
Asia Generation		77			40			37		93	%		124			88			36		41	%
Total Corporate and Other ⁽²⁾		(28	)		(50	)		22		44	%		(78	)		(105	)		27		26	%
Interest expense		(383	)		(469	)		86		18	%		(774	)		(904	)		130		14	%
Interest income		90			133			(43	)	-32	%		188			249			(61	)	-24	%
Other expense		(30	)		(85	)		55		65	%		(52	)		(110	)		58		53	%
Other income		22			150			(128	)	-85	%		244			195			49		25	%
Gain on sale of investments		102			908			(806	)	-89	%		115			912			(797	)	-87	%
Impairment expense		(1	)		(25	)		24		96	%		(1	)		(72	)		71		99	%
Foreign currency transaction (losses) gains on net monetary position		27			(85	)		112		132	%		(12	)		(63	)		51		81	%
Other non-operating expense		-			-			-		0	%		(10	)		-			(10	)	-100	%
Income tax expense		(105	)		(318	)		213		67	%		(280	)		(557	)		277		50	%
Net equity in earnings of affiliates		50			20			30		150	%		57			42			15		36	%

Income from continuing operations		531			1,159			(628	)	-54	%		1,032			1,566			(534	)	-34	%
Income from operations of discontinued businesses		-			1			(1	)	-100	%		-			3			(3	)	-100	%
Loss from disposal of discontinued businesses		-			-			-		0	%		-			(1	)		1		100	%

Net income		531			1,160			(629	)	-54	%		1,032			1,568			(536	)	-34	%
Noncontrolling interest		(228	)		(257	)		29		11	%		(511	)		(432	)		(79	)	-18	%

Net income attributable to The AES Corporation	$	303		$	903		$	(600	)	-66	%	$	521		$	1,136		$	(615	)	-54	%


PER SHARE DATA:
Basic income per share from continuing operations	$	0.45		$	1.34		$	(0.89	)	-66	%	$	0.78		$	1.69		$	(0.91	)	-54	%
Diluted income per share from continuing operations	$	0.45		$	1.31		$	(0.86	)	-66	%	$	0.78		$	1.65		$	(0.87	)	-53	%

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

⁽²⁾

Total Corporate and Other includes the gross margin from our generation and utilities businesses in Africa, utilities businesses in Europe and AES Wind and other renewables projects, development costs, corporate general and administrative expenses as well as certain inter-segment eliminations, primarily corporate charges for self insurance premiums.

Revenue

Revenue decreased $631 million, or 15%, to $3.5 billion for the three months ended June 30, 2009 compared with the same period in 2008. Excluding the unfavorable impact of foreign currency translation of $520 million, largely driven by the Brazilian Real, which accounted for $344 million of the impact, revenue decreased $111 million. This was a result of the decrease at our generation businesses in Latin America of $203 million primarily due to the impact of lower energy prices offset by increases in net volume at Gener. In addition, wholesale prices decreased at our North America generation plants during the quarter. These decreases were partially offset by higher tariffs of $39 million at our Brazilian utilities and improved operations at Masinloc in the Philippines of $56 million.

Revenue decreased $1.3 billion, or 16%, to $6.9 billion for the six months ended June 30, 2009 compared with the same period in 2008. Excluding the unfavorable impact of foreign currency of $1.1 billion, largely driven by the Brazilian Real, which accounted for $751 million of the impact, revenue decreased $225 million primarily due to the impact of lower energy prices at Gener and a reduction in volume at Uruguaiana. The decrease was partially offset by higher tariffs of $117 million at our Brazilian utilities and the impact of our new businesses in Asia of $158 million.

Gross Margin

Gross margin decreased $182 million, or 18%, to $847 million for the three months ended June 30, 2009 compared with the same period in 2008. Excluding the unfavorable impact of foreign currency translation of $101 million, gross margin decreased $81 million. This decrease was primarily the result of increased fixed costs, primarily in Latin America and a reduction in net mark-to-market derivative gains on certain commodity contracts of $84 million at our North America generation subsidiaries. These decreases were partially offset by improved operating margins at our Latin America generation businesses of $57 million, mainly at Gener. Additionally our results in Asia increased $43 million reflecting operational improvements at Masinloc.

Gross margin decreased $341 million, or 16%, to $1.7 billion for the six months ended June 30, 2009 compared with the same period in 2008. Excluding the unfavorable impact of foreign currency translation of $238 million, gross margin decreased $103 million. The decrease was largely a result of a reduction in the mark-to-market derivative gains of $91 million, increased fixed costs, primarily in Latin America and the lack of contribution from the Kazakhstan businesses sold in May 2008 of $41 million. These were partially offset by the improved operations at our generation businesses in Latin America, primarily at Gener, and an increase of $48 million in Asia largely due to the impact of our new businesses, Masinloc and Amman East in Jordan.

Gross margin as a percentage of revenue for the three and six months ended June 30, 2009 compared with the same period in 2008 remained essentially flat at 24% and 25%, respectively. Please refer to Segment Analysis for further discussion of gross margin as a percentage of revenue for each of our reportable segments.

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,
	2009		2008		% Change	2009		2008		% Change
	(in millions)					(in millions)
Latin America Generation
Revenue	$	895	$	1,177	-24%	$	1,786	$	2,383	-25%
Gross Margin	$	335	$	319	5%	$	707	$	718	-2%
Gross Margin as a % of Segment Revenue		37%		27%			40%		30%

Generation revenue for the three months ended June 30, 2009 decreased $282 million, or 24%, compared to the three months ended June 30, 2008 primarily due to lower spot and contract prices at Gener in Chile and our businesses in the Dominican Republic of $129 million and $18 million, respectively, and lower spot prices at our businesses in Argentina of $25 million. The decrease was also due to the unfavorable impact of foreign currency translation of $79 million in Brazil and Argentina, lower volume at Uruguaiana in Brazil of $43 million due to the renegotiation of its power sales agreements in 2009 and lower volume at our businesses in the Dominican Republic of $30 million. These decreases were partially offset by a net increase in volume at Gener of $60 million driven by the unfavorable impact in 2008 of gas curtailments in Argentina.

Generation gross margin for the three months ended June 30, 2009 increased $16 million, or 5%, compared to the three months ended June 30, 2008 primarily due to an increase at Gener of $94 million from an increase in the volume of spot sales driven by the unfavorable impact in 2008 of gas curtailments in Argentina, a decrease in fuel prices and savings from the use of more efficient fuel. These increases were partially offset by the unfavorable impact of foreign currency translation of $41 million in Brazil and Argentina, lower spot prices at our businesses in Argentina of $26 million and lower spot and contract prices at Gener of $25 million. The favorable impacts to gross margin, primarily driven by the decrease in fuel prices and use of more efficient fuel, combined with the decrease in generation revenue, in particular at Gener, resulted in an increase in gross margin as a percentage of segment revenue from 27% for the three months ended June 30, 2008 to 37% for the three months ended June 30, 2009.

Generation revenue for the six months ended June 30, 2009 decreased $597 million, or 25%, compared to the six months ended June 30, 2008 primarily due to lower spot and contract prices at Gener of $258 million. Also contributing to the decrease was the unfavorable impact of foreign currency translation of $155 million at our businesses in Brazil and Argentina, lower volume at Uruguaiana of $92 million as a result of the renegotiation of its power sales agreements in 2009 and lower prices and volume at our businesses in the Dominican Republic and Argentina of $71 million and $34 million, respectively. These decreases were partially offset by higher volume at Gener of $27 million.

Generation gross margin for the six months ended June 30, 2009 decreased $11 million, or 2%, compared to the six months ended June 30, 2008 primarily due to a decrease of $125 million due to lower spot and contract prices at Gener partially offset by a decrease in fuel prices, the unfavorable impact of foreign currency translation of $93 million in Brazil and Argentina, higher purchased energy prices at Uruguaiana of $50 million and higher fuel prices at our businesses in Argentina of $46 million. These decreases were partially offset by lower purchases of energy and fuel at Gener of $157 million, a reduction in purchased energy at Uruguaiana of $77 million, and the favorable impact at Uruguaiana of a decrease in bad debt expense of $54 million, largely a result

of the renegotiation of its power sales agreements in 2009. These favorable impacts to gross margin, primarily driven by the decrease in fuel prices and the decrease in bad debt expense, combined with the decrease in generation revenue, in particular at Gener and Uruguaiana, resulted in an increase in gross margin as a percentage of segment revenue, despite the overall decrease in gross margin, from 30% for the six months ended June 30, 2008 to 40% for the six months ended June 30, 2009.

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,
	2009		2008		% Change	2009		2008		% Change
	(in millions)					(in millions)
Latin America Utilities
Revenue	$	1,367	$	1,577	-13%	$	2,581	$	3,040	-15%
Gross Margin	$	175	$	254	-31%	$	346	$	479	-28%
Gross Margin as a % of Segment Revenue		13%		16%			13%		16%

Utilities revenue for the three months ended June 30, 2009 decreased $210 million, or 13%, compared to the three months ended June 30, 2008 primarily due to the unfavorable impact of foreign currency translation of $297 million, primarily at our businesses in Brazil. This decrease was partially offset by higher tariffs in Brazil of $39 million and higher purchased energy costs which are passed through to the customer of $48 million in El Salvador.

Utilities gross margin for the three months ended June 30, 2009 decreased $79 million, or 31%, compared to the three months ended June 30, 2008 primarily due to an increase in fixed costs at Eletropaulo in Brazil of $67 million primarily related to higher bad debt expense, contingencies and pension costs, unfavorable impact of foreign currency translation in Brazil of $38 million and lower volume at Sul in Brazil of $18 million. These decreases were partially offset by higher tariffs in Brazil of $28 million and an increase of $24 million from lower purchased energy prices, primarily driven by a reduction in volume as a result of the renegotiation of the PPA between Uruguaiana and Sul in Brazil. The unfavorable impacts to gross margin resulted in a decrease in gross margin as a percentage of segment revenue from 16% for the three months ended June 30, 2008 to 13% for the three months ended June 30, 2009 primarily due to higher fixed costs in Brazil.

Utilities revenue for the six months ended June 30, 2009 decreased $459 million, or 15%, compared to the six months ended June 30, 2008 primarily due to the unfavorable impact of foreign currency translation of $643 million, primarily in Brazil. This decrease was partially offset by higher tariffs in Brazil of $117 million and higher purchased energy costs which are passed through to the customer of $54 million in El Salvador.

Utilities gross margin for the six months ended June 30, 2009 decreased $133 million, or 28%, compared to the six months ended June 30, 2008 primarily due to the unfavorable impact of foreign currency translation of $90 million, primarily in Brazil, an $84 million increase in fixed costs at Eletropaulo driven primarily by higher pension costs, labor contingencies and bad debt expense in addition to a decrease in volume across the region of $73 million. These decreases were partially offset by higher tariffs of $75 million and an increase of $54 million from lower purchased energy prices, primarily driven by a reduction in volume as a result of the renegotiation of the PPA between Uruguaiana and Sul. The unfavorable impacts to gross margin resulted in a decrease in gross margin as a percentage of segment revenue from 16% for the six months ended June 30, 2008 to 13% for the six months ended June 30, 2009 primarily due to higher fixed costs in Brazil.

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,
	2009		2008		% Change	2009		2008		% Change
	(in millions)					(in millions)
North America Generation
Revenue	$	475	$	538	-12%	$	977	$	1,089	-10%
Gross Margin	$	122	$	242	-50%	$	242	$	402	-40%
Gross Margin as a % of Segment Revenue		26%		45%			25%		37%

Generation revenue for the three months ended June 30, 2009 decreased $63 million, or 12%, compared to the three months ended June 30, 2008 primarily due to a decrease of $42 million at Merida in Mexico as a result of reduced natural gas prices in the second quarter of 2009 and a net decrease of $17 million in New York due to a combination of a reduction in the volume of electricity sold in the spot market as a result of lower spot rates, partially offset by a rate increase on electricity sold under favorable contracts and fewer outages. Additionally, revenue decreased due to an increase in outages at Warrior Run in Maryland of $16 million, the unfavorable impact of foreign currency translation in Mexico of $12 million and lower rates at Deepwater in Texas of $9 million. These decreases were partially offset by the favorable impact in 2009 of a $23 million mark-to-market derivative loss at Deepwater recognized in 2008.

Generation gross margin for the three months ended June 30, 2009 decreased $120 million, or 50%, compared to the three months ended June 30, 2008 primarily due to a $110 million mark-to-market derivative gain on a coal supply contract in Hawaii in 2008 compared to a $5 million gain recognized in the second quarter of 2009 and an increase in outages at Warrior Run of $16 million. These decreases were partially offset by the favorable impact in 2009 of a $23 million mark-to-market derivative loss at Deepwater recognized in 2008 and an increase in gross margin of $4 million in New York due to a combination of favorable contracted rates and fewer outages that were partially offset by a reduction in the volume of electricity sold in the spot market as a result of lower spot rates. Gross margin as a percentage of revenue for the three months ended June 30, 2009 decreased to 26% compared to 45% in the same period in 2008 primarily due to the unfavorable impact in 2009 of a significant reduction in the mark-to-market derivative gain in Hawaii.

Generation revenue for the six months ended June 30, 2009 decreased $112 million, or 10%, compared to the six months ended June 30, 2008 primarily due to a decrease of $42 million in New York due to a combination of a reduction in the volume of electricity sold in the spot market as a result of lower spot rates partially offset by a rate increase on electricity sold under favorable contracts and fewer outages. Additionally, revenue decreased $29 million due to a reduction in natural gas prices at Merida, partially offset by a revenue adjustment in 2008, the unfavorable impact of foreign currency translation in Mexico of $28 million, an increase in outages at Warrior Run of $16 million, a reduction in revenue from back-up power recoveries due to fewer outages at TEG/TEP in Mexico of $15 million and lower rates at Deepwater of $13 million. These decreases were partially offset by a $23 million mark-to-market derivative loss at Deepwater recognized in 2008.

Generation gross margin for the six months ended June 30, 2009 decreased $160 million, or 40%, compared to the six months ended June 30, 2008 primarily due to a $110 million mark-to-market derivative gain on a coal supply contract at Hawaii in 2008 compared to a $4 million loss recognized in the first six months of 2009, a decrease of $20 million in New York due to a combination of a reduction in the volume of electricity sold in the spot market as a result of lower spot rates partially offset by favorable contracted rates and fewer outages and an increase in outages at Warrior Run of $16 million. These decreases were partially offset by the favorable impact in 2009 of a $23 million mark-to-market derivative loss at Deepwater recognized in 2008 and a $17 million

revenue adjustment at Merida in 2008. Gross margin as a percentage of revenue for the six months ended June 30, 2009 decreased to 25% compared to 37% in the same period in 2008 primarily due to the unfavorable impact in 2009 of the mark-to-market derivative gain recognized in Hawaii in 2008.

The Utilities segment in North America consists solely of our integrated utility business in Indiana, IPL. The following table summarizes revenue and gross margin for our Utilities segment in North America for the periods indicated:


	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2009		2008		% Change	2009		2008		% Change
	(in millions)					(in millions)
North America Utilities
Revenue	$	261	$	267	-2%	$	551	$	516	7%
Gross Margin	$	51	$	61	-16%	$	121	$	113	7%
Gross Margin as a % of Segment Revenue		20%		23%			22%		22%

Utilities revenue for the three months ended June 30, 2009 decreased $6 million, or 2%, compared to the three months ended June 30, 2008 primarily due to lower wholesale revenue of $9 million and a decrease in revenue related to clean coal projects of $4 million. This decrease was partially offset by higher pass-through fuel costs of $7 million.

Utilities gross margin for the three months ended June 30, 2009 decreased $10 million, or 16%, compared to the three months ended June 30, 2008 primarily due to lower wholesale margin of $9 million and increased pension expense of $6 million largely due to the decline in market value of IPL’s pension assets during 2008. Gross margin as a percentage of segment revenue for the three months ended June 30, 2009 decreased compared to the same period in 2008 primarily due to the decline in wholesale energy prices in 2009.

Utilities revenue for the six months ended June 30, 2009 increased $35 million, or 7%, compared to the six months ended June 30, 2008 primarily due to $32 million of credits to retail customers established during the first six months of 2008 and higher pass-through fuel costs of $26 million. These increases were partially offset by a decrease in wholesale revenue of $13 million, primarily driven by prices, and a decrease in retail volume of $9 million.

Utilities gross margin for the six months ended June 30, 2009 increased $8 million, or 7%, compared to the six months ended June 30, 2008 primarily due to $32 million of credits to retail customers established during the first six months of 2008. This increase was partially offset by a decrease in wholesale margin of $14 million due to unfavorable prices and increased pension expense of $12 million largely due to the decline in market value of IPL’s pension assets during 2008. Gross margin as a percentage of segment revenue for the six months ended June 30, 2009 was consistent compared to the same period in 2008.

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,
	2009		2008		% Change	2009		2008		% Change
	(in millions)					(in millions)
Europe Generation
Revenue	$	152	$	268	-43%	$	356	$	572	-38%
Gross Margin	$	27	$	64	-58%	$	95	$	179	-47%
Gross Margin as a % of Segment Revenue		18%		24%			27%		31%

Generation revenue for the three months ended June 30, 2009 decreased $116 million, or 43%, compared to the three months ended June 30, 2008 primarily due to the unfavorable impact of foreign currency translation of $44 million across the region, mainly driven by our businesses in the U.K and Hungary, a decrease of $41 million in Kazakhstan reflecting the impact of the sale of Ekibastuz and Maikuben in May 2008 and lower volume at Kilroot and our businesses in Hungary of $41 million, primarily due to a decrease in demand. These decreases were partially offset by increased rates of $8 million in Hungary.

Generation gross margin for the three months ended June 30, 2009 decreased $37 million, or 58%, compared to the three months ended June 30, 2008 primarily due to lower volume at our businesses in Hungary of $14 million, a decrease of $17 million in Kazakhstan as a result of the sale of Ekibastuz and Maikuben in May 2008 and the unfavorable impact of foreign currency translation and increased fixed costs of $6 million and $12 million, respectively, across the region. These decreases were partially offset by higher rates at our businesses in Hungary of $8 million and increased rates and volume of $6 million at Altai, our remaining business in Kazakhstan. Gross margin as a percentage of revenue for the three months ended June 30, 2009 decreased compared to the same period in 2008 primarily due to lower volume at our businesses in Hungary and the sale of two subsidiaries in Kazakhstan in May 2008.

Generation revenue for the six months ended June 30, 2009 decreased $216 million, or 38%, compared to the six months ended June 30, 2008 primarily due to the unfavorable impact of foreign currency translation of $107 million across the region, mainly driven by our businesses in the U.K and Hungary, a decrease of $101 million in Kazakhstan reflecting the impact of the sale of Ekibastuz and Maikuben in May 2008 and a decrease in volume and rate of $16 million at Borsod in Hungary primarily driven by decreased demand.

Generation gross margin for the six months ended June 30, 2009 decreased $84 million, or 47%, compared to the six months ended June 30, 2008 primarily due to a decrease of $43 million in Kazakhstan as a result of the sale of Ekibastuz and Maikuben in May 2008, the unfavorable impact of foreign currency translation of $27 million across the region, lower volume at our businesses in Hungary of $27 million and higher fixed costs of $13 million across the region. These unfavorable impacts were partially offset by higher rates at Kilroot and Tisza II in Hungary of $31 million. Gross margin as a percentage of revenue for the six months ended June 30, 2009 decreased compared to the same period in 2008 primarily due to the impact of lower volume at our businesses in Hungary and the sale of two subsidiaries in Kazakhstan in May 2008.

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,
	2009		2008		% Change	2009		2008		% Change
	(in millions)					(in millions)
Asia Generation
Revenue	$	337	$	301	12%	$	584	$	613	-5%
Gross Margin	$	77	$	40	93%	$	124	$	88	41%
Gross Margin as a % of Segment Revenue		23%		13%			21%		14%

Generation revenue for the three months ended June 30, 2009 increased $36 million, or 12%, compared to the three months ended June 30, 2008 primarily due to an increase in generation volume of $56 million at Lal Pir and Pak Gen in Pakistan, as a result of fuel supply constraints in 2008 that did not continue in the second quarter of 2009; improved operations and availability of $56 million at Masinloc in the Philippines; and the favorable impact of $21 million from our new business at Amman East in Jordon, which started production in July 2008. These increases were partially offset by a decrease in rates of $53 million in Pakistan, as a result of a drop in pass-through fuel prices, and the unfavorable impact of foreign currency translation of $41 million across the region.

Generation gross margin for the three months ended June 30, 2009 increased $37 million, or 93%, compared to the three months ended June 30, 2008 primarily due to improved operations at Masinloc of $29 million, excluding the impact of foreign currency, which was largely driven by an increase in availability and reduced coal prices, and the impact of Amman East of $8 million. Gross margin as a percentage of revenue for the three months ended June 30, 2009 increased to 23% compared to 13% in the same period in 2008 primarily due to improved operations at Masinloc.

Generation revenue for the six months ended June 30, 2009 decreased $29 million, or 5%, compared to the six months ended June 30, 2008 primarily due to a decrease in rates of $76 million in Pakistan, due mainly to a decline in pass-through fuel prices; the unfavorable impact of foreign currency translation of $75 million across the region and a decrease in rates of $21 million at Kelanitissa in Sri Lanka, primarily due to lower pass-through energy costs. These decreases were partially offset by improved operations and availability of $56 million at Masinloc in the second quarter. We also benefited from the impact of our new businesses Masinloc, which was acquired in April 2008, and Amman East, which started operation in July 2008, of $46 million and $47 million, respectively.

Generation gross margin for the six months ended June 30, 2009 increased $36 million, or 41%, compared to the six months ended June 30, 2008 primarily due to the favorable impact of Masinloc of $38 million, excluding the impact of foreign currency, and the impact of our new business in Jordon of $16 million partially offset by the unfavorable impact of foreign currency translation of $12 million across the region. Gross margin as a percentage of revenue for the six months ended June 30, 2009 increased to 21% compared to 14% during the same period in 2008 primarily due to improved operations at Masinloc.

Corporate and Other

Corporate and other includes general and administrative 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. In addition, this category includes the net operating results from our generation and utilities businesses in Africa, utilities businesses in Europe and AES Wind and other renewables projects and costs associated with our development group which are immaterial for the purposes of separate segment disclosure and the effects of eliminating transactions such as self-insurance charges, between the operating segments and corporate. For the three and six months ended June 30, 2009 and 2008, Corporate and other was approximately 1% of consolidated revenue.

Corporate and other decreased $22 million, or 44%, to $28 million for the three months ended June 30, 2009 compared to the three months ended June 30, 2008. The decrease was primarily due to favorable operating results at Sonel, our utility business in Cameroon, of $18 million largely driven by a decrease in fixed costs, and an $11 million decrease in corporate expenses driven by remediation costs incurred in 2008 and a current year decrease in development efforts.

Corporate and other decreased $27 million, or 26%, to $78 million for the six months ended June 30, 2009 compared to the six months ended June 30, 2008. The decrease was primarily due to a $24 million decrease in corporate expenses driven by remediation costs incurred in 2008 and a current year decrease in development efforts and travel costs. Additionally, corporate and other decreased due to favorable operating results at Sonel of $12 million, largely driven by a decrease in fixed costs.

Interest expense

Interest expense decreased $86 million, or 18%, to $383 million for the three months ended June 30, 2009. The decrease for the three months ended June 30, 2009 was primarily due to favorable foreign currency translation and lower interest rates in Brazil.

Interest expense decreased $130 million, or 14%, to $774 million for the six months ended June 30, 2009. The decrease for the six months ended June 30, 2009 was primarily due to favorable foreign currency translation

and lower interest rates in Brazil, in addition to payment of debt at the Parent Company in June 2008. These decreases were partially offset by interest expense at our Masinloc plant in the Philippines which was acquired in April 2008.

Interest income

Interest income decreased $43 million, or 32%, to $90 million for the three months ended June 30, 2009 and decreased $61 million, or 24%, to $188 million for the six months ended June 30, 2009. The decreases for the three and six months ended June 30, 2009 were primarily due to unfavorable foreign currency translation on the Brazilian Real, lower interest rates in Brazil and lower cash balances at the Parent Company.

Other expense

Other expense of $30 million for the three months ended June 30, 2009 included $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 $85 million for the three months ended June 30, 2008 included $69 million of losses related to the retirement of debt at the Parent Company in connection with a refinancing in June 2008 and the refinancing of $375 million of debt by IPALCO in April 2008.

Other income

Other income of $244 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. See further discussion of this transaction in Note 14 — Acquisitions and Dispositions to the condensed consolidated financial statements included in this Quarterly Report. Other income of $195 million for the six months ended June 30, 2008 included the previously mentioned gain on extinguishment of a tax liability and insurance recoveries in the second quarter of 2008, as well as $14 million of compensation received from the local government for the impairment of plant assets and cessation of the power purchase agreement associated with a settlement agreement to shut down the Hefei generation facility in China recorded during the first quarter of 2008.

Gain on sale of investments

Gain on sale of investments for the three and six months ended June 30, 2009 was $102 million and $115 million, respectively. The gain for the three months ended June 30, 2009 primarily consisted of $98 million recognized in May 2009 related to the termination of the management agreement between the Company and Kazakhmys PLC for Ekibastuz and Maikuben; see further discussion of this transaction in Note 14 – Acquisitions and Dispositions to the condensed consolidated financial statements included in this Quarterly Report. In addition, the gain for the six months ended June 30, 2009 included $13 million from the reversal of a contingent liability in March 2009 related to the Kazakhstan sale.

Gain on sale of investments for the three and six months ended June 30, 2008 was $908 million and $912 million, respectively. The gain for the three and six months ended June 30, 2008 primarily consisted of a $908 million net gain on the sale of two wholly-owned subsidiaries in Kazakhstan, AES Ekibastuz LLP and Maikuben West LLP in May 2008.

Impairment expense

Impairment expense for the three and six months ended June 30, 2009 was $1 million. Impairment expense for the three and six months ended June 30, 2008 was $25 million and $72 million, respectively. Impairment expenses in 2008 consisted primarily of impairment charges in the first and second quarter of $14 million and $20 million, respectively, resulting from the analysis of Uruguaiana’s long-lived assets, which was triggered by the combination of gas curtailments and increases in the spot market price of energy in 2007. In addition, there were impairment charges of $20 million related to South African peakers project development costs that were written off due to withdrawal from the project and $14 million associated with a settlement agreement to shut down the Hefei plant in China.

Foreign currency transaction (losses) gains on net monetary position

Foreign currency transaction (losses) gains were as follows:


	Three months ended June 30,						Six months ended June 30,
	2009			2008			2009			2008
	(in millions)						(in millions)
The AES Corporation	$	14		$	(11	)	$	(12	)	$	15
Chile		29			(46	)		55			(33	)
Kazakhstan		(12	)		(3	)		(27	)		(3	)
Colombia		(11	)		4			(5	)		(2	)
Brazil		4			(10	)		(3	)		(21	)
Argentina		(3	)		9			(12	)		7
Philippines		2			(28	)		(5	)		(27	)
Other		4			-			(3	)		1

Total ⁽¹⁾	$	27		$	(85	)	$	(12	)	$	(63	)

⁽¹⁾

Includes $23 million losses on foreign currency derivative contracts for the three months ended June 30, 2009 and 2008, respectively, and includes $34 million and $18 million losses on foreign currency derivative contracts for the six months ended June 30, 2009 and 2008, respectively.

The Company recognized foreign currency transaction gains of $27 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 Peso, mainly cash and accounts receivables. This gain was partially offset by $3 million loss on foreign currency derivatives.

Gains of $14 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 British Pound.

Losses of $12 million in Kazakhstan were primarily due to net foreign currency transaction losses of $12 million 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 $3 million loss on foreign currency derivatives.

Gains of $4 million in Brazil were primarily due to the 16% appreciation of the Brazilian Real compared to the U.S. Dollar, which resulted in gains at Sul and Uruguaiana in Brazil.

Losses of $3 million in Argentina were primarily due to the devaluation of Argentina Peso by 2%, resulting in losses at Alicura (an Argentina Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt.

The Company recognized foreign currency transaction losses of $85 million for the three months ended June 30, 2008. These consisted primarily of losses in Chile, the Philippines, The AES Corporation and Brazil, partially offset by gains in Argentina.

Losses of $46 million in Chile were primarily due to the devaluation of the Chilean Peso by 19%, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with its net working capital denominated in Chilean Pesos, mainly cash, accounts receivables and VAT receivables.

Losses of $28 million in the Philippines were primarily due to the weakening of the Philippine Peso to the U.S. Dollar on remeasurement of external and intercompany loans at Masinloc in the Philippines.

Losses of $11 million at The AES Corporation were primarily due to the loss on foreign currency forwards related to the capital contribution for Gener, partially offset by favorable exchange rates on notes denominated in British Pound.

Losses of $10 million in Brazil were primarily due to energy purchases made by Eletropaulo that were denominated in U.S. Dollar, resulting in foreign currency transaction losses of $17 million.

Gains of $9 million in Argentina were primarily due to the appreciation of Argentina Peso by 5% in 2008, resulting in gains at our generation in Argentina (an Argentina Peso functional currency subsidiary) associated with U.S. Dollar denominated debt.

The Company recognized foreign currency transaction losses of $12 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.

Gains of $55 million at 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 receivables. This gain was partially offset by $14 million loss on foreign currency derivatives.

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

Losses of $12 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 British Pound.

Losses of $12 million in Argentina were primarily due to the devaluation of Argentina Peso by 10% mainly resulting in losses at Alicura, an Argentina 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 Argentinean Peso.

Losses of $5 million in the Philippines were primarily due to the weakening of the Philippine Peso to the U.S. Dollar resulting in losses on remeasurement of debt at Masinloc in the Philippines.

Losses of $5 million in Colombia were primarily due to the appreciation of the Colombian Peso by 4%, resulting in losses at Chivor (a U.S. Dollar functional currency subsidiary) associated with its Colombian Peso denominated debt and $3 million loss on foreign currency derivatives.

Losses of $3 million in Brazil were primarily due to U.S. Dollar denominated energy purchases made by Eletropaulo resulting in losses of $7 million, which were partially offset by gains of $4 million at Sul and Uruguaiana due to the 16% appreciation of the Brazilian Real compared to the U.S. Dollar.

The Company recognized foreign currency transaction losses of $63 million for the six months ended June 30, 2008. These consisted primarily of losses in Chile, the Philippines and Brazil, partially offset by gains at The AES Corporation.

Losses of $33 million in Chile were primarily due to the devaluation of the Chilean Peso by 5%, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) associated with its net working capital denominated in Chilean Pesos, mainly cash, accounts receivables and VAT receivables.

Losses of $27 million in the Philippines were primarily due to the weakening of the Philippine Peso to the U.S. Dollar on remeasurement of debt at Masinloc in the Philippines.

Losses of $21 million in Brazil were primarily due to energy purchases made by Eletropaulo that were denominated in U.S. Dollar, resulting in foreign currency transaction losses of $29 million.

Gains of $15 million at The AES Corporation were primarily due to favorable exchange rates for cash accounts and outstanding notes denominated in Euros and British Pound, partially offset by losses on foreign currency exchange forwards related to the capital contribution for Gener.

Other non-operating expense

Other non-operating expense was zero for the three months ended June 30, 2009 and $10 million for the six months ended June 30, 2009, consisting primarily of an other-than-temporary impairment of a cost method investment. During the first quarter of 2009, the market value of the investee’s shares continued to decline due to the downward trends in the capital markets and management concluded that the decline was other-than-temporary. There was no non-operating expense for the three and six months ended June 30, 2008.

Income taxes

Income tax expense on continuing operations decreased $213 million to $105 million for the three months ended June 30, 2009 from $318 million for the three months ended June 30, 2008. The Company’s effective tax rates were 18% and 22% for the three months ended June 30, 2009 and 2008, respectively.

Income tax expense on continuing operations decreased $277 million to $280 million for the six months ended June 30, 2009 from $557 million for the six months ended June 30, 2008. The Company’s effective tax rates were 22% and 27% for the six months ended June 30, 2009 and 2008, respectively.

The net decrease in the effective tax rate for the three and six months ended June 30, 2009 compared to the same periods in 2008 was primarily due to tax benefit recorded in the second quarter of 2009 upon the release of valuation allowance at a U.S. and a Brazilian subsidiary and the increase in U.S. taxes on distributions from the Company’s primary holding company to facilitate early retirement of parent debt in the second quarter of 2008, offset by the impact of the non-taxable Kazakhstan transactions in 2008 and 2009. See further discussion about the Kazakhstan transactions in Note 14 – Acquisitions and Dispositions.

Net equity in earnings of affiliates

Net equity in earnings of affiliates increased $30 million, or 150%, to $50 million for the three months ended June 30, 2009 compared to the three months ended June 30, 2008. The increase was primarily due to a cash settlement of $35 million received by Cartagena, in Spain, for liquidated damages including legal costs incurred related to a construction delay from December 2005 to November 2006; see further discussion of this transaction in Note 6 – Investments in and Advances to Affiliate to the condensed consolidated financial statements included in the Quarterly Report. This increase was partially offset by a payment received in the second quarter of 2008 related to a legal settlement at AES Barry Ltd.

Net equity in earnings of affiliates increased $15 million, or 36%, to $57 million for the six months ended June 30, 2009. The increase was primarily due to a cash settlement received by Cartagena, as mentioned above, and a reduction of net losses at our affiliates in Turkey. These increases were partially offset by the legal settlement at AES Barry Ltd, as mentioned above, decreased earnings at Chigen due to increased prices and lower supplies of coal, increased development costs related to AES Solar which was formed in March 2008, and decreased earnings at OPGC, in India, mainly due to lower tariff revenue.

Discontinued operations

There were no discontinued operations in 2009. For the three and six months ended June 30, 2008, income from operations of discontinued businesses was $1 million and $3 million, respectively, and reflected the operations of Jiaozuo, a coal-fired generation facility in China, previously reflected in our Asia Generation segment which was sold in December 2008.

Net income attributable to noncontrolling interests

Net income attributable to noncontrolling interests decreased $29 million, or 11%, to $228 million for the three months ended June 30, 2009 compared to the same period in 2008 primarily due to decreased earnings at Eletropaulo in Brazil and the depreciation of the Brazilian Real. These decreases were partially offset by increased earnings at Uruguaiana and Tiete in Brazil and Gener in Chile.

Net income attributable to noncontrolling interests increased $79 million, or 18%, to $511 million for the six months ended June 30, 2009 compared to the same period in 2008 primarily due to increased earnings at Uruguaiana and Tiete, Gener, Itabo in the Dominican Republic, Merida in Mexico, and Jordan which began production in July 2008, as well as the impact of an increase in noncontrolling interests from 20% to 29% as a

result of the sale of shares at Gener in November 2008. These increases were partially offset by decreased earnings at Eletropaulo and the depreciation of the Brazilian Real.

Liquidity and Capital Resources

Overview

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 farms 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 and to fund equity investments or provide loans to affiliates. This debt is with recourse to the Parent Company and is structurally subordinated to the affiliates’ non-recourse debt.

As of June 30, 2009, the Company had unrestricted cash and cash equivalents of $1.7 billion and short term investments of $1.2 billion. In addition, we had restricted cash and debt service reserves of $444 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $13.7 billion and $5.5 billion, respectively. Of the total $1.4 billion of our short-term non-recourse debt currently outstanding, $1.3 billion is presented as current because it is due in the next twelve months and $97 million relates to debt currently in default. We expect such maturities will be repaid from cash on hand or cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. None of our recourse debt matures within the next twelve months.

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 and is generally secured by the capital stock, physical assets, contracts and cash flow of the related subsidiary or affiliate. Generally our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases the currency is matched through the use of derivative instruments. These derivatives can require that the Company post collateral to support the currency match. The majority of our non-recourse debt is funded by international commercial banks with debt capacity supplemented by multilaterals and local regional banks. For more information on our long-term debt, see Note 7 — Long-term Debt to the condensed consolidated financial statements included in Item 1 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 may be required to mark-to-market all or a portion of these interest rate swaps and other derivatives. Presently, the Parent Company’s only exposure to variable interest rate debt relates to indebtedness under its senior secured and senior unsecured credit facilities. On a consolidated basis, of the Company’s $19.2 billion of total debt outstanding as of June 30, 2009, approximately $3.5 billion bore interest at variable rates of interest that were not subject to derivative instruments which fixed the interest rate.

In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our debt issuances, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity with our subsidiaries or lenders. In such circumstances, if a subsidiary defaults on its payment or supply obligation, the Parent Company will be responsible for the subsidiary’s obligations up to the amount provided for in the relevant guarantee or other credit support. At June 30, 2009, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to, or for the benefit of our subsidiaries, which were limited by the terms of the agreements, of approximately $404 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, 2009, the Parent Company had $207 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations. These letters of credit were provided under our senior secured and senior unsecured credit facilities. During the second quarter the Company paid letter of credit fees ranging from 3.17% to 8.84% per annum on the outstanding amounts.

We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available or may not be available on economically attractive terms. See Global Recession discussion above. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary chooses not to proceed with a project or is unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.

Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations 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.

AES Solar, one of our equity investments, was formed in March 2008 as a joint venture with Riverstone. Under the terms of the AES Solar joint venture agreement, the Company and Riverstone may each provide up to $500 million of capital through 2013. The joint venture has commitments to purchase solar panels for use in their business and, while the Company is not required to fund AES Solar’s obligations, it is possible that if we decide not to fund the joint venture in the future it could impact AES Solar’s development plans or operations.

Cash Flows

At June 30, 2009, cash and cash equivalents increased $832 million from December 31, 2008 to $1.7 billion. The increase in cash and cash equivalents was due to $871 million of cash provided by operating activities, $384 million of cash used in investing activities, $331 million of cash provided by financing activities and the favorable effect of foreign currency exchange rates on cash of $14 million.

At June 30, 2008, cash and cash equivalents decreased by $322 million from December 31, 2007 to a total of $1.7 billion. The change in cash and cash equivalents was due to $784 million of cash provided by operating activities, $1.6 billion of cash used for investing activities, $526 million of cash provided by financing activities and the favorable effect of exchange rates on cash of $3 million.

Operating Activities

Net cash provided by operating activities increased $87 million, or 11%, to $871 million for the six months ended June 30, 2009 from $784 million for the same period in 2008. This increase was primarily due to increases of approximately $132 million, $131 million and $92 million at our Latin America Generation, Asia Generation businesses and Corporate and other, respectively, due to reduced working capital requirements, corporate overhead and development costs. In addition, our Europe and Africa Generation businesses experienced increases in net cash provided by operating activities of approximately $86 million and $30 million, respectively, due to the $80 million collection of the management performance incentive bonus and improvements in working capital. These increases were offset by a decrease of approximately $376 million at our Latin America Utilities businesses due to lower cash earnings, payment on the settlement of a swap agreement and increased settlement of legal contingencies.

Investing Activities

Net cash used in investing activities decreased $1.3 billion to net cash used of $384 million for the six months ended June 30, 2009 from net cash used of $1.6 billion for six months ended June 30, 2008. This decrease was primarily attributable to the following:

Capital expenditures decreased $192 million, or 14% to $1.2 billion for the six months ended June 30, 2009 from $1.4 billion for the six months ended June 30, 2008. This was mainly due to net decreased expenditures of $182 million for wind generation projects at our U.S. businesses and $145 million at Maritza in Bulgaria. These decreases were offset by a net increase in expenditures of $106 million for plant construction at Gener. Please refer to Management’s Priorities discussed above for a description of operations that came on-line in 2009 or are expected to come on-line during the year.

Acquisitions, net of cash acquired were $1.1 billion for the six months ended June 30, 2008, due to the purchase of a coal-fired thermal power generation facility at Masinloc in the Philippines and the purchase of Mountain View, a wind generation facility in the U.S.

Proceeds from the sales of businesses decreased $1.1 billion to $2 million for the six months ended June 30, 2009 from $1.1 billion for the same period in 2008. The 2008 activity was primarily attributable to the sale of Ekibastuz, a coal-fired generation plant, and Maikuben, a coal mine, in Kazakhstan.

The sale of short-term investments, net of purchases, increased $528 million to $529 million net sales of short-term investments for the six months ended June 30, 2009 from $1 million net sales of short-term investments for the six months ended June 30, 2008. The activity included increases in net sales of $188 million, $127 million and $122 million at Eletropaulo, Tiete and Brasiliana Energia, respectively, all located in Brazil to fund interest and dividend payments. In addition, there was an increase in net sales of $85 million at Alicura due to maturities of investments.

Restricted cash balances decreased $305 million for the six months ended June 30, 2009, primarily due to decreases of $216 million at Gener, $72 million at Chigen, and $20 million at New York.

Debt service reserves and other assets decreased $40 million for the six months ended June 30, 2009 primarily due to decreases of $53 million at St. Nikola and $13 million at Eletropaulo. These decreases were offset by an increase of $28 million at Gener and a net increase of $5 million at other wind generation projects in Europe.

Cash used in advances to affiliate and equity investments was $87 million for the six months ended June 30, 2009, primarily driven by contributions made to AES Solar. Loan advances were $173 million for the six months ended June 30, 2008 and represented amounts paid for a convertible loan from a Brazilian wind development business. There were no loan advances made in the six months ended June 30, 2009.

Financing Activities

Net cash provided by financing activities decreased $195 million to $331 million for the six months ended June 30, 2009 compared to net cash provided of $526 million for the six months ended June 30, 2008. As discussed below, this decrease was primarily attributable to an increase in distributions to noncontrolling interests of $90 million, a decrease in contributions from noncontrolling interests of $87 million, and a net decrease in debt balances, net of repayments of $36 million.

Net repayments under revolving credit facilities were $31 million for the six months ended June 30, 2009, compared to net borrowings of $199 million for the six months ended June 30, 2008. The increase in net repayments of $230 million was primarily due to increased net repayments of $105 million at Lal Pir/Pak Gen in Pakistan due to off-taker collections, $53 million at Panama for project financing, $47 million at the Parent Company due to decreased usage of revolving credit in 2009, and $30 million at IPL due to a successful remarketing of notes that had previously failed remarketing and were supported by a letter of credit.

Issuances of recourse and non-recourse debt for the six months ended June 30, 2009 were $1.3 billion compared to $2.2 billion for the six months ended June 30, 2008. This decrease in debt issuances of $872 million was primarily due to a decrease of $593 million at Masinloc where the 2008 activity was for acquisition and improvement related costs, $262 million at IPL due to refinancing of debt, $183 million at Buffalo Gap 3 due to completion of construction, and $122 million at the Parent Company from decreased bond issuances. These decreases were offset by an increase of $200 million at Gener due to the bond issuances discussed above and construction financing.

Repayments of recourse and non-recourse debt for the six months ended June 30, 2009 were $645 million compared to $1.7 billion for the six months ended June 30, 2008. This decrease of $1.1 billion was predominately due to decreases in repayments of recourse debt of $883 million at the Parent Company and $257 million at IPL due to debt refinancing.

Payments made for deferred financing costs for the six months ended June 30, 2009 were $53 million compared to $36 million for the six months ended June 30, 2008, which was primarily due to an increase of $12 million at the Parent Company due to senior note issuances in 2009.

Distributions to noncontrolling interests increased $90 million to $334 million for the six months ended June 30, 2009 from $244 million for the six months ended June 30, 2008. The increase was primarily due to increased distributions of $73 million at Brasiliana Energia and $32 million at Eletropaulo. These increases were partially offset by a decrease in distributions of $11 million at Panama.

Contributions from noncontrolling interests decreased $87 million to $74 million for the six months ended June 30, 2009 from $161 million for the six months ended June 30, 2008. The decrease was primarily due to decreases of $78 million at Mountain View and $22 million at Masinloc. These decreases were offset by an increase of $19 million at Gener.

Financed capital expenditures decreased $27 million to $24 million for the six months ended June 30, 2009 from $51 million for the six months ended June 30, 2008, predominately due to a decrease of $37 million at Gener due to decreased financed construction, partially offset by an increase of $6 million at Kilroot due to financed plant construction.

Parent Company Liquidity

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

•

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

•

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

•

proceeds from asset sales.

Our cash requirements at the Parent Company level are primarily to fund:

•

interest and preferred dividend payments;

•

principal repayments of debt;

•

acquisitions;

•

construction commitments;

•

other equity commitments;

•

taxes; and

•

Parent Company overhead and development costs.

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, 2009 and December 31, 2008 as follows:


Parent Company Liquidity	June 30, 2009		December 31, 2008
	(in millions)
Consolidated cash and cash equivalents	$	2,179	$	903
Less: Cash and cash equivalents at subsidiaries		1,576		656

Cash and cash equivalents at Parent and qualified holding companies		603		247
Borrowing available under senior secured credit facility		712		720
Borrowing available under senior unsecured credit facility⁽¹⁾		1		423

Total Parent Company Liquidity	$	1,316	$	1,390

⁽¹⁾

During the second quarter of 2009, the Parent Company voluntarily reduced the size of its senior unsecured credit facility by $465 million. Please refer to “Recourse Debt” below for further description.

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


Contingent Contractual Obligations	Amount		Number of Agreements	Exposure Range for Each Agreement
	(in millions)			(in millions)
Guarantees	$	404	32	< $1 - $53
Letters of credit under the revolving credit facility		73	13	< $1 - $28
Letters of credit under the senior unsecured credit facility		134	10	< $1 - $119

Total	$	611	55

As of June 30, 2009, the Parent Company had $185 million of commitments to invest in subsidiaries with projects under construction and to purchase related equipment, excluding approximately $144 million of such obligations already included in the letters of credit discussed above. The Parent Company expects to fund these net investment commitments over time according to the following schedule: $89 million in 2009, $39 million in 2010 and $57 million in 2011. The exact payment schedule will be dictated by construction milestones. We expect to fund these commitments from a combination of current liquidity and internally generated Parent Company cash flow.

We have a varied portfolio of performance related contingent contractual obligations. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these obligations include change of control, construction cost overruns, subsidiary default, political risk, buyer and tax indemnities, equity subscription, spot market power prices, supplier support and liquidated damages under power sales agreements for projects in development, under construction and in operation. While we do not expect that we will be required to fund any material amounts under these contingent contractual obligations during 2009 or beyond, many of the events which would give rise to such obligations are beyond our control. We can provide no assurance that we will be able to fund our obligations under these contingent contractual obligations if we are required to make substantial payments thereunder.

While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets, the operating and financial performance of our subsidiaries, exchange rates, power market pool prices and the ability of our subsidiaries to pay dividends. In addition, our project subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in project loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that our actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured and senior unsecured credit facilities. If, due to new corporate opportunities or otherwise, our capital requirements exceed amounts available from cash on hand or borrowings under our credit facilities, we may need to access the capital markets to raise additional debt or equity financing. Various debt instruments at the Parent Company level contain certain restrictive covenants. The covenants provide for, among other items:

•

limitations on other indebtedness, liens, investments and guarantees;

•

restrictions on dividends and redemptions and payments of unsecured and subordinated debt and the use of proceeds;

•

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

•

maintenance of certain financial ratios; and

•

financial and other reporting requirements.

Recourse Debt:

On March 26, 2009, the Parent Company and certain subsidiary guarantors amended the Parent Company’s existing senior secured credit facility pursuant to the terms of Amendment No. 1 to the senior secured credit facility. The senior secured credit facility previously included a $200 million term loan facility maturing on August 10, 2011 and a $750 million revolving credit facility maturing on June 23, 2010.

The principal modification set forth in Amendment No. 1 was a one year extension of the $570 million of revolving credit facility commitments from an original maturity date of June 23, 2010 to July 5, 2011. In addition, certain lenders determined that they would increase their commitments under the revolving credit facility by $35 million from March 26, 2009 through July 5, 2011. Accordingly, Amendment No. 1 also increased the size of the revolving credit facility from $750 million to $785 million for the period between the date of Amendment No. 1 and June 23, 2010. Between June 23, 2010 and July 5, 2011, the revolving credit facility size will be $605 million. No modifications were made to the amount or maturity date of the $200 million term loan facility.

The extended commitments from this amendment were subject to new pricing that included an upfront fee of 1.25% for participating in the extensions and an increase in undrawn commitment fees from 50 to 100 basis points. The annual interest rate on the drawn loans was also increased by 200 basis points to LIBOR plus 3.50%. Pricing and all other terms remained unchanged for the revolving credit facility commitments which have not been extended.

On April 2, 2009, the Parent Company issued $535 million aggregate principal amount of 9.75% senior unsecured notes due 2016 in a private placement. The notes were priced at a discount to yield 11%. Subsequently, the Parent Company allocated a substantial portion of the proceeds to voluntarily reduce the size of its $600 million senior unsecured credit facility by $465 million. The remaining $135 million of the senior unsecured credit facility consists primarily of letters of credit, the majority of which continues to support several projects currently under construction.

On June 1, 2009, the Parent Company repaid at maturity all outstanding 9.5% senior unsecured notes at par for an aggregate principal amount of $154 million. Future maturities of recourse debt as of June 30, 2009 are set forth in the table below:


	Annual Maturities
	(in millions)
July 1 – December 31, 2009		-
2010		214
2011		471
2012		-
2013		690
Thereafter		4,140

Total recourse debt	$	5,515

Non-Recourse Debt:

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

•

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

•

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

•

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

•

triggering defaults in our outstanding debt at the parent level.

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total debt classified as current in the accompanying condensed consolidated balance sheet related to such defaults was $97 million at June 30, 2009, all of which is non-recourse debt.

None of the subsidiaries that are currently in default meet the applicable definition of materiality in The AES Corporation’s debt agreements in order for such defaults to trigger an event of default or permit acceleration under such indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary,” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities.

On April 8, 2009, Gener issued $196 million aggregate principal amount of 8% unsecured notes due in 2019. The unsecured notes were priced at a discount to par resulting in an 8.5% yield. The proceeds from this issuance will be used to provide Gener’s funding requirements for projects under construction.

Critical Accounting Policies and Estimates

The consolidated financial statements of AES are prepared in conformity with generally accepted accounting principles in the United States of America, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. The Company’s significant accounting policies are described in Note 1 — Financial Statement Presentation to the consolidated financial statements included in the Company’s 2008 Annual Report on 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 2008 Annual Report on 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 three months ended June 30, 2009. The only significant change to our critical accounting policies and estimates is the adoption of FAS No. 157 for nonfinancial assets and liabilities as of

January 1, 2009. See further discussion of the Company’s policy in Item 1. Financial Statements, Notes to Condensed Consolidated Financial Statements, Note 1—Financial Statement Presentation in this Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks

We are exposed to market risks associated with interest rates, foreign exchange rates and commodity prices. We often utilize financial instruments and other contracts to hedge against such fluctuations. We also utilize financial derivatives for the purpose of hedging exposures to market risk.

Interest Rate Risks

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

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

As of June 30, 2009, the portfolio’s interest expense exposure (adjusted to reflect noncontrolling interests) to a 100 basis point increase in U.S. Dollar and Brazilian Real interest rates is approximately $9 million. These numbers assume a one-time, 100 basis point increase in interest rates and calculating its impact on interest expense for U.S. Dollar and Brazilian Real-denominated debt for the remainder of 2009, which together account for more than 90% of the portfolio’s floating-rate debt which are primarily non-recourse financing. The numbers do not take into account the historical correlation between U.S. Dollar and Brazilian Real interest rates and do not include other currencies which account for less than 10% of the portfolio floating-rate debt.

Foreign Exchange Rate Risk

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

During the second quarter, we entered into hedges to partially mitigate the exposure of earnings translated into U.S. Dollar to foreign exchange volatility. Given a 10% U.S. Dollar appreciation, AES pre-tax earnings for the balance of 2009 would be reduced by approximately $26 million on a correlated basis. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to un-hedged pre-tax earnings for the balance of 2009 coming from subsidiaries where the local currency is either not the U.S. Dollar or it is not exhibiting the characteristics of a peg or managed float relative to the U.S. Dollar and holding all other variables constant. The numbers presented above are net of any transactional gains/losses and the correlation effect is based on historical foreign exchange rate movement over a period equal in length to the period over which the simulated move occurs.

Commodity Price Risk

When hedging the output of our generation assets, we have power purchase agreements or other hedging instruments that lock in the spread in dollars per MWh between the cost of fuel to generate a unit of electricity and the price at which the electricity can be sold. The portion of our sales and fuel purchases that are not subject to such agreements will be exposed to commodity price risk. For our U.S.-based assets including Eastern Energy, Deepwater, and wholesale sales for IPALCO, a 10% decline in the price of electricity as of June 30, 2009 would produce an estimated decrease in gross margin of $5 million for the balance of 2009. We limited our analysis to the U.S. markets as they have quoted forward electricity curves. We shifted the forward electricity curves for western New York, Houston, Texas, and the Cinergy hub down by 10%. We applied the change in electricity prices to our un-hedged sales volumes. An increase of 10% in petroleum coke prices at Deepwater would result in a decline in projected gross margin of $1 million for the remainder of 2009.

Value at Risk

We have performed a company wide value at risk analysis (“VaR”) of all of our material financial assets, liabilities and derivative instruments. VaR measures the potential loss in a portfolio’s value due to market volatility, over a specified time horizon, stated with a specific degree of probability and is calculated based on volatilities and correlations of the different risk exposures of the portfolio. The quantification of market risk using VaR provides a consistent measure of risk across diverse markets and instruments. VaR is not necessarily indicative of actual results that may occur. Additionally, VaR represents changes in fair value of financial instruments and not the economic exposure to AES and its affiliates. Because of the inherent limitations of VaR, including those specific to Analytic VaR, in particular the assumption that values or returns are normally distributed, we rely on VaR as only one component in our risk assessment process. In addition to using VaR measures, we perform sensitivity and scenario analyses to estimate the economic impact of market changes to our portfolio of businesses. We use these results to complement the VaR methodology. For a further discussion of the Company’s VaR methodology and its limitations, see Item 7A — Quantitative and Qualitative Disclosures about Market Risk — Risk Management in Part II, of the 2008 Form 10-K.

Embedded derivatives are not appropriately measured here and are excluded since VaR is not representative of the overall contract valuation. The VaR calculation incorporates numerous variables that could impact the fair value of our instruments, including interest rates, foreign exchange rates and commodity prices, as well as correlation within and across these variables. The interest rate component of VaR is due to changes in the fair value of our fixed rate debt instruments and interest rate swaps. These instruments themselves would expose a holder to market risk; however, utilizing these fixed rate debt instruments as part of a fixed price contract generation business mitigates the overall exposure to interest rates. Similarly, our foreign exchange rate sensitive instruments are often part of businesses which have revenues denominated in the same currency, thus offsetting the exposure.

We express Analytic VaR herein as a dollar amount of the potential loss in the fair value of our portfolio based on a 95% confidence level and a one day holding period. Our commodity analysis is a VaR calculation

within the commodity transaction management system, and is reported for financially settled derivative products at our Eastern Energy business in New York State and Deepwater in Texas as these are the only businesses with commodity transactions that are deemed derivatives. These commodity transactions are marked to market on a daily basis. Collateral is then posted or recalled for any changes in exposures at Eastern Energy but is not required at Deepwater. However, not every transaction requires Eastern Energy to post collateral, as several counterparties have caps defined in their transaction agreements. For those counterparties that do require Eastern Energy to post collateral, two facilities that are non-recourse to The AES Corporation in the amounts of $75 million and $350 million are used to issue letters of credit. As of June 30, 2009, $19 million and $77 million have been utilized under these facilities.

The VaR as of June 30, 2009 for foreign exchange rate-sensitive instruments was $78 million compared with $78 million as of March 31, 2009. These amounts include foreign currency denominated debt and hedge instruments.

The VaR as of June 30, 2009 for interest rate-sensitive instruments was $155 million compared with $176 million as of March 31, 2009. These amounts include the financial instruments that serve as hedges and the underlying hedged items. The decrease in VaR relative to the first quarter is attributable to the decrease in volatility in interest rates.

The VaR as of June 30, 2009 for commodity price-sensitive instruments was $4 million compared with $4 million as of March 31, 2009. For Eastern Energy, these amounts include the financial instruments that serve as hedges and do not include the underlying physical assets or contracts that are not permitted to be settled in cash. For Deepwater, these include the physically settled derivative products that serve as hedges. For the second quarter of 2009, the VaR of Deepwater is disclosed for the first time and represents $800,000 of the aggregate VaR for commodity price-sensitive instruments.

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, 2009 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls Over Financial Reporting

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 in Item 1 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, 2009. See Note 8 — Contingencies and Commitments in Item 1 of this Form 10-Q for additional information regarding these claims and proceedings.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2008 Form 10-K.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Please see the Company’s Form 10-Q for the period ended March 31, 2009 for a description of the Company’s 2009 annual meeting and the matters voted upon therein.

ITEM 5. OTHER INFORMATION

None

ITEM 6. EXHIBITS


10.1		Fourth Amended And Restated Credit And Reimbursement Agreement dated as of July 29, 2008 among THE AES CORPORATION, a Delaware corporation, the SUBSIDIARY GUARANTORS listed herein, the BANKS listed on the signature pages hereof, CITIGROUP GLOBAL MARKETS INC., as Lead Arranger and Book Runner, BANC OF AMERICA SECURITIES LLC, as Lead Arranger and Book Runner and as Co-Syndication Agent, DEUTSCHE BANK SECURITIES INC, as Lead Arranger and Book Runner, UNION BANK OF CALIFORNIA, N.A., as Co-Syndication Agent and as Lead Arranger and Book Runner and as Syndication Agent, LEHMAN COMMERCIAL PAPER INC., as Co-Documentation Agent, UBS SECURITIES LLC, as Co-Documentation Agent, SOCIÉTÉ GÉNÉRALE, as Co-Documentation Agent, CREDIT LYONNAIS NEW YORK BRANCH, as Co-Documentation Agent, CITICORP USA, INC., as Administrative Agent for the Bank Parties and CITIBANK, N.A., as Collateral Agent for the Bank Parties (filed herewith) including:



10.1.A		Appendix I, Revolving Credit Loan Facility pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.B		Appendix II, Initial Term Loan Facility pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.C		Appendix III, Existing Letters of Credit pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.D		Schedule I, Pledged Subsidiaries pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.E		Schedule II, Assigned Agreements pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.F		Schedule III, Non-Pledged Subsidiaries pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.G		Schedule IV, Excluded AES Entities pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.H		Schedule 5.15, Existing Agreements with Affiliates pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.I		Schedule V, Qualified Holding Companies pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.J		Schedule VI, Existing Debt pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.K		Schedule VII, Revolving Fronting Banks pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.L		Exhibit A-1, Form of Revolving Credit Loan Note pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.M		Exhibit A-2, Form of Term Loan Note pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.N		Exhibit B-1, Form of Opinion of the General Counsel of the Borrower pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.O		Exhibit B-2, Form of Opinion of Davis Polk & Wardwell, Special Counsel for the Borrower pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.P		Exhibit B-3, Form of Opinion of Special Counsel for certain Subsidiaries of the Borrower pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.Q		Exhibit B-4, Form of Opinion of Morris, Nichols, Arsht & Tunnell, Delaware counsel for the Borrower pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.R		Exhibit B-5, Form of Opinion of Maples and Calder, Cayman Islands counsel for the Borrower pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.S		Exhibit B-6, Form of Opinion of Conyers Dill & Pearman, British Virgin Islands counsel for the Borrower pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.T		Exhibit B-7, Form of Opinion of Shearman & Sterling, Special Counsel for the Agent pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.U		Exhibit C-1, Form of Revolving Credit Loan Facility Assignment and Assumption Agreement pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.V		Exhibit C-2, Form of Term Loan Facility Assignment and Assumption Agreement pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.1.W		Exhibit C-3, Form of Third Party Fronting Bank Assignment and Assumption Agreement pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).



10.1.X		Exhibit D, Form of Revolving Fronting Bank Agreement pursuant to the Fourth Amended and Restated Credit Agreement (filed herewith).

10.2		Credit Agreement dated as of March 29, 2006 among The AES Corporation as Borrower, Merrill Lynch Capital Corporation as Administrative Agent, Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Lead Arranger (filed herewith) including:

10.2.A		Appendix I, Funding Amounts pursuant to the Credit Agreement dated as of March 29, 2006 (filed herewith).

10.2.B		Schedule I, Excluded AES Entities pursuant to the Credit Agreement dated as of March 29, 2006 (filed herewith).

10.2.C		Exhibit A, Form of Note pursuant to the Credit Agreement dated as of March 29, 2006 (filed herewith).

10.2.D		Exhibit B-1, Form of Opinion of the Assistant General Counsel of the Borrower pursuant to the Credit Agreement dated as of March 29, 2006 (filed herewith).

10.2.E		Exhibit B-2, Form of Opinion of Sherman & Sterling, Special Counsel for the Borrower pursuant to the Credit Agreement dated as of March 29, 2006 (filed herewith).

10.2.F		Exhibit C-1, Form of Loan Facility Assignment and Assumption Agreement pursuant to the Credit Agreement dated as of March 29, 2006 (filed herewith).

10.2.G		Exhibit C-2, Form of Fronting Bank Assignment and Assumption Agreement pursuant to the Credit Agreement dated as of March 29, 2006 (filed herewith).

10.2.H		Exhibit D, Form of Fronting Bank Agreement pursuant to the Credit Agreement dated as of March 29, 2006 (filed herewith).

10.2.I		Exhibit E, Form of Request for Loan pursuant to the Credit Agreement dated as of March 29, 2006 (filed herewith).

10.2.J		Exhibit F, Form of Interest Election Request pursuant to the Credit Agreement dated as of March 29, 2006 (filed herewith).

31.1		Certification of principal executive officer required by Rule 13a-14(a)/15d-14(a) of the Exchange Act.

31.2		Certification of principal financial officer required by Rule 13a-14(a)/15d-14(a) of the Exchange Act.

32.1		Certification of principal executive officer required by Rule 13a-14(b) or 15d-14(b) of the Exchange Act.

32.2		Certification of principal financial officer required by Rule 13a-14(b) or 15d-14(b) of the Exchange Act.

101		The following materials from The AES Corporation’s Quarterly Report on Form 10-Q for the interim period ended June 30, 2009 formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Balance Sheets, (iii) the Condensed Consolidated Statements of Cash Flows, (iv) the Condensed Consolidated Statements of Changes in Equity, (v) the Notes to the Condensed Consolidated Financial Statements, tagged as block text.

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 6, 2009	By:	/s/ VICTORIA D. HARKER
		Name:	Victoria D. Harker
		Title:	Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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