Edgar Filing: AES CORP

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

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, 2012

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

Commission file number 1-12291

LOGO

THE AES CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		54 1163725
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
4300 Wilson Boulevard Arlington, Virginia		22203
(Address of principal executive offices)		(Zip Code)

(703) 522-1315

Registrant’s telephone number, including area code:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, on July 27, 2012 was 747,996,061.

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2012

TABLE OF CONTENTS


PART I: FINANCIAL INFORMATION		1

*ITEM 1.*	*FINANCIAL STATEMENTS*	1
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Comprehensive Income	3
	Condensed Consolidated Statements of Cash Flows	4
	Notes to Condensed Consolidated Financial Statements	5

*ITEM 2.*	*MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*	40

*ITEM 3.*	*QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK*	83

*ITEM 4.*	*CONTROLS AND PROCEDURES*	86

PART II: OTHER INFORMATION		87

*ITEM 1.*	*LEGAL PROCEEDINGS*	87

*ITEM 1A.*	*RISK FACTORS*	94

*ITEM 2.*	*UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS*	94

*ITEM 3.*	*DEFAULTS UPON SENIOR SECURITIES*	94

*ITEM 4.*	*MINE SAFETY DISCLOSURES*	94

*ITEM 5.*	*OTHER INFORMATION*	94

*ITEM 6.*	*EXHIBITS*	96

SIGNATURES		97

PART I: FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

THE AES CORPORATION

Condensed Consolidated Balance Sheets

(Unaudited)


	June 30, 2012			December 31, 2011
				(Revised)
	(in millions, except share and per share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,727		$	1,704
Restricted cash		574			478
Short-term investments		883			1,356
Accounts receivable, net of allowance for doubtful accounts of $285 and $273, respectively		2,628			2,534
Inventory		826			785
Deferred income taxes		433			454
Prepaid expenses		159			157
Other current assets		1,087			1,570
Current assets of discontinued and held for sale businesses		-			191

Total current assets		8,317			9,229

NONCURRENT ASSETS
Property, Plant and Equipment:
Land		1,037			1,090
Electric generation, distribution assets and other		31,016			31,029
Accumulated depreciation		(9,274	)		(8,944	)
Construction in progress		2,318			1,833

Property, plant and equipment, net		25,097			25,008

Other Assets:
Investments in and advances to affiliates		1,392			1,422
Debt service reserves and other deposits		800			876
Goodwill		3,801			3,803
Other intangible assets, net of accumulated amortization of $230 and $164, respectively		507			570
Deferred income taxes		658			715
Other		2,177			2,330
Noncurrent assets of discontinued and held for sale businesses		-			1,340

Total other assets		9,335			11,056

TOTAL ASSETS	$	42,749		$	45,293

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,171		$	2,014
Accrued interest		320			327
Accrued and other liabilities		2,250			3,398
Non-recourse debt, including $238 and $259, respectively, related to variable interest entities		2,287			2,123
Recourse debt		11			305
Current liabilities of discontinued and held for sale businesses		-			279

Total current liabilities		7,039			8,446

NONCURRENT LIABILITIES
Non-recourse debt, including $1,161 and $1,156, respectively, related to variable interest entities		13,250			13,412
Recourse debt		6,178			6,180
Deferred income taxes		1,354			1,289
Pension and other post-retirement liabilities		1,593			1,729
Other noncurrent liabilities		3,756			3,082
Noncurrent liabilities of discontinued and held for sale businesses		-			1,348

Total noncurrent liabilities		26,131			27,040

Contingencies and Commitments (see Note 8)
Cumulative preferred stock of subsidiaries		78			78
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 809,947,514 issued and 749,556,111 outstanding at June 30, 2012 and 807,573,277 issued and 765,186,316 outstanding at December 31, 2011		8			8
Additional paid-in capital		8,530			8,507
Retained earnings		1,159			678
Accumulated other comprehensive loss		(2,865	)		(2,758	)
Treasury stock, at cost (60,391,403 shares at June 30, 2012 and 42,386,961 shares at December 31, 2011, respectively)		(709	)		(489	)

Total AES Corporation stockholders’ equity		6,123			5,946
NONCONTROLLING INTERESTS		3,378			3,783

Total equity		9,501			9,729

TOTAL LIABILITIES AND EQUITY	$	42,749		$	45,293

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions, except per share amounts)
Revenue:
Regulated	$	2,209		$	2,414		$	4,829		$	4,763
Non-Regulated		1,983			2,021			4,103			3,828

Total revenue		4,192			4,435			8,932			8,591

Cost of Sales:
Regulated		(1,971	)		(1,852	)		(4,153	)		(3,625	)
Non-Regulated		(1,529	)		(1,591	)		(3,009	)		(2,981	)

Total cost of sales		(3,500	)		(3,443	)		(7,162	)		(6,606	)

Gross margin		692			992			1,770			1,985

General and administrative expenses		(74	)		(97	)		(161	)		(192	)
Interest expense		(385	)		(381	)		(801	)		(719	)
Interest income		83			96			174			191
Other expense		(15	)		(35	)		(44	)		(50	)
Other income		15			34			33			50
Gain on sale of investments		5			1			184			7
Asset impairment expense		(18	)		(33	)		(29	)		(33	)
Foreign currency transaction gains (losses)		(101	)		37			(102	)		70
Other non-operating expense		(1	)		-			(50	)		-

INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES		201			614			974			1,309
Income tax expense		(76	)		(174	)		(343	)		(389	)
Net equity in earnings of affiliates		11			(4	)		24			6

INCOME FROM CONTINUING OPERATIONS		136			436			655			926
Income (loss) from operations of discontinued businesses, net of income tax (benefit) expense of $3, $(3), $5, and $(6), respectively		(4	)		(9	)		(3	)		(16	)
Net gain (loss) from disposal and impairments of discontinued businesses, net of income tax expense of $61, $0, $61, and $0, respectively		75			-			70			-

NET INCOME		207			427			722			910
Noncontrolling interests:
Less: Income from continuing operations attributable to noncontrolling interests		(67	)		(245	)		(241	)		(498	)
Less: Income from discontinued operations attributable to noncontrolling interests		-			(8	)		-			(14	)

Total net income attributable to noncontrolling interests		(67	)		(253	)		(241	)		(512	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	140		$	174		$	481		$	398

BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.09		$	0.24		$	0.54		$	0.54
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		0.09			(0.02	)		0.09			(0.03	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.18		$	0.22		$	0.63		$	0.51

DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.09		$	0.24		$	0.54		$	0.53
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		0.09			(0.02	)		0.09			(0.03	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.18		$	0.22		$	0.63		$	0.50

AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	69		$	191		$	414		$	428
Discontinued operations, net of tax		71			(17	)		67			(30	)

Net income	$	140		$	174		$	481		$	398

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statements of Comprehensive Income

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
NET INCOME	$	207		$	427		$	722		$	910

Available-for-sale securities activity:

Change in fair value of available-for-sale securities, net of income tax (expense) benefit of $0, $(1), $0, and $0, respectively		1			1			1			1

Reclassification to earnings, net of income tax (expense) benefit of $0, $1, $0, and $1, respectively		(1	)		(2	)		(1	)		(3	)


Total change in fair value of available-for-sale securities		-			(1	)		-			(2	)

Foreign currency translation activity:

Foreign currency translation adjustments, net of income tax (expense) benefit of $2, $(10), $1, and $(14), respectively		(383	)		139			(241	)		270

Reclassification to earnings, net of income tax (expense) benefit of $0, $0, $0, and $0, respectively		(2	)		(5	)		(3	)		(8	)


Total foreign currency translation adjustments		(385	)		134			(244	)		262

Derivative activity:

Change in derivative fair value, net of income tax (expense) benefit of $24, $34, $20, and $26, respectively		(133	)		(110	)		(112	)		(69	)

Reclassification to earnings, net of income tax (expense) benefit of $(5), $5, $(33), and $(3), respectively		40			29			126			59


Total change in fair value of derivatives		(93	)		(81	)		14			(10	)

Pension activity:

Amortization of net actuarial loss, net of income tax (expense) benefit of $(3) $(2), $(6), and $(4), respectively		7			4			13			7



Total pension adjustments		7			4			13			7


OTHER COMPREHENSIVE INCOME (LOSS)		(471	)		56			(217	)		257



COMPREHENSIVE INCOME (LOSS)		(264	)		483			505			1,167

Less: Comprehensive (income) loss attributable to noncontrolling interests		114			(339	)		(131	)		(664	)


COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	$	(150	)	$	144		$	374		$	503

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
	2012			2011
	(in millions)
OPERATING ACTIVITIES:
Net income	$	722		$	910
Adjustments to net income:
Depreciation and amortization		706			622
(Gain) loss from sale of investments and impairment expense		(71	)		37
Provision for deferred taxes		72			28
Contingencies		35			46
(Gain) loss on the extinguishment of debt		-			15
(Gain) loss on disposal and impairment write-down - discontinued operations		(131	)		-
Other		50			(89	)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(175	)		(182	)
(Increase) decrease in inventory		(43	)		(88	)
(Increase) decrease in prepaid expenses and other current assets		18			149
(Increase) decrease in other assets		(293	)		(43	)
Increase (decrease) in accounts payable and other current liabilities		228			(254	)
Increase (decrease) in income taxes and other income tax payables, net		(249	)		(152	)
Increase (decrease) in other liabilities		245			178

Net cash provided by operating activities		1,114			1,177

INVESTING ACTIVITIES:
Capital expenditures		(1,071	)		(1,019	)
Acquisitions - net of cash acquired		(13	)		(157	)
Proceeds from the sale of businesses, net of cash sold		332			8
Proceeds from the sale of assets		2			22
Sale of short-term investments		3,605			3,065
Purchase of short-term investments		(3,261	)		(2,493	)
Increase in restricted cash		(73	)		(16	)
(Increase) decrease in debt service reserves and other assets		26			(92	)
Affiliate advances and equity investments		1			(60	)
Proceeds from government grants for asset construction		117			5
Other investing		(17	)		(20	)

Net cash used in investing activities		(352	)		(757	)

FINANCING ACTIVITIES:
(Repayments) borrowings under the revolving credit facilities, net		(310	)		125
Issuance of recourse debt		-			2,050
Issuance of non-recourse debt		579			574
Repayments of recourse debt		(5	)		(471	)
Repayments of non-recourse debt		(328	)		(768	)
Payments for financing fees		(17	)		(74	)
Distributions to noncontrolling interests		(578	)		(714	)
Contributions from noncontrolling interests		12			-
Financed capital expenditures		(12	)		(6	)
Purchase of treasury stock		(231	)		(98	)
Other financing		28			2

Net cash (used in) provided by financing activities		(862	)		620
Effect of exchange rate changes on cash		3			29
Decrease in cash of discontinued and held for sale businesses		120			10

Total increase in cash and cash equivalents		23			1,079
Cash and cash equivalents, beginning		1,704			2,522

Cash and cash equivalents, ending	$	1,727		$	3,601

SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	783		$	734
Cash payments for income taxes, net of refunds	$	525		$	506

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, 2012 and 2011

1. FINANCIAL STATEMENT PRESENTATION

The prior period condensed consolidated financial statements in this Quarterly Report on Form 10-Q (“Form 10-Q”) have been reclassified to reflect the businesses held for sale and discontinued operations as discussed in Note 16 — Discontinued Operations and Held for Sale Businesses and the prior period condensed consolidated balance sheet has been revised to reflect the adjustments to the preliminary purchase price allocation related to the DPL acquisition as discussed in Note 17 — Acquisitions and Dispositions.

On June 26, 2012, The AES Corporation filed a Current Report on Form 8-K (“June 2012 Form 8-K”) to recast previously filed financial statements included in the Company’s Form 10-K for the year ended December 31, 2011 (“2011 Form 10-K”) to reclassify certain businesses held for sale as discussed in Note 16 —Discontinued Operations and Held for Sale Businesses, to present a separate consolidated statement of comprehensive income in accordance with the new accounting guidance on comprehensive income and to reflect changes in the Company’s reportable segments in accordance with the accounting guidance on segment reporting as discussed in Note 12 — Segments. The revisions to the 2011 Form 10-K were limited to the Company’s Business Overview, Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations, the Consolidated Financial Statements and Notes, and the Financial Statement Schedules contained in Items 1, 6, 7, 8 and 15, respectively.

Consolidation

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

On June 29, 2012, the State Public Service Commission of New York approved the sale of Somerset and Cayuga, two coal-fired power plants in New York, to the bondholders for approximately $240 million. The plants were owned by AES Eastern Energy L.P. (“AES Eastern Energy”), which had filed for bankruptcy protection under Chapter 11 in the U.S. Bankruptcy Court on December 30, 2011 and, effective that date, had been deconsolidated from the Company’s consolidated financial statements due to the loss of control. The gain on deconsolidation of AES Eastern Energy continues to be deferred pending the resolution of bankruptcy protection proceedings. See Note 1. — General and Summary of Significant Accounting Policies, Principles of Consolidation to the Consolidated Financial Statement in our June 2012 Form 8-K for further information.

Interim Financial Presentation

The accompanying unaudited condensed consolidated financial statements and footnotes have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”), as contained in the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification, for interim financial information and Article 10 of Regulation S-X issued by the U.S. Securities and Exchange Commission (“SEC”). Accordingly, they do not include all the information and footnotes required by U.S. GAAP for annual fiscal reporting periods. In the opinion of management, the interim financial information includes all adjustments of a normal recurring nature necessary for a fair presentation of the results of operations,

financial position, comprehensive income and cash flows. The results of operations for the three and six months ended June 30, 2012 are not necessarily indicative of results that may be expected for the year ending December 31, 2012. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2011 audited consolidated financial statements and notes thereto, which are included in the June 2012 Form 8-K.

New Accounting Policies Adopted

ASU No. 2011-04, Fair Value Measurements (Topic 820), “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS”

In May 2011, the FASB issued ASU No. 2011-04, which among other requirements, prohibits the use of the block discount factor for all fair value level hierarchies; permits an entity to measure the fair value of its financial instruments on a net basis when the related market risks are managed on a net basis; states the highest and best use concept is no longer relevant in the measurement of financial assets and liabilities; clarifies that a reporting entity should disclose quantitative information about the unobservable inputs used in Level 3 measurements and that the application of premiums and discounts is related to the unit of account for the asset or liability being measured at fair value; and requires expanded disclosures to describe the valuation process used for Level 3 measurements and the sensitivity of Level 3 measurements to changes in unobservable inputs. In addition, entities are required to disclose the hierarchy level for items which are not measured at fair value in the statement of financial position, but for which fair value is required to be disclosed. AES adopted ASU No. 2011-04 on January 1, 2012. The adoption did not have a material impact on the Company’s financial position, results of operations or cash flows.

ASU No. 2011-05, Comprehensive Income (Topic 220), “Presentation of Comprehensive Income”

In June 2011, the FASB issued ASU No. 2011-05, which requires comprehensive income to be reported in either a single statement or in two consecutive statements reporting net income and other comprehensive income. The amendment does not change what items are reported in other comprehensive income or the U.S. GAAP requirement to report the reclassification of items from other comprehensive income to net income. The Company adopted ASU No. 2011-05 on January 1, 2012 and chose to report comprehensive income in two consecutive statements by adding a new consolidated statement of comprehensive income for the three and six months ended June 30, 2012 and 2011 in these consolidated financial statements. As ASU No. 2011-05 impacts financial statement presentation only, the adoption did not have an impact on the Company’s historical financial position or results of operations and is not expected to have an impact in future periods.

Revenue Recognition — Following the Company’s acquisition of DPL Inc. (“DPL”) and its competitive retail supply business in November 2011, we have modified our definition of regulated and non-regulated revenue as follows: revenue is classified as regulated on the condensed consolidated statements of operations where the price is determined or set by a regulator, including alternative forms of price regulation such as a price range, price cap or earnings tests. Typically, revenue of utility businesses meets the above criteria and would be classified as regulated revenue. Revenue that is not subject to rate regulation or is not determined by a regulator is classified as non-regulated revenue. Typically, revenue of generation businesses would be classified as non-regulated revenue.

Accounting Pronouncements Issued But Not Yet Effective

The following accounting standard has been issued, but are not yet effective for, and has not been adopted by AES.

ASU No. 2012-02, Intangibles — Goodwill and Other (Topic 350,)” Testing Indefinite-Lived Intangible Assets for Impairment”

On July 27, 2012, the FASB issued ASU No. 2012-02 under which an entity has the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount. An entity also has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012 or January 1, 2013 for the Company. Early adoption is permitted. The adoption of ASU No. 2012-02 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

2. INVENTORY

The following table summarizes the Company’s inventory balances as of June 30, 2012 and December 31, 2011:


	June 30, 2012		December 31, 2011
	(in millions)
Coal, fuel oil and other raw materials	$	452	$	444
Spare parts and supplies		374		341

Total	$	826	$	785

3. FAIR VALUE

The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The fair value of non-recourse debt is estimated differently based upon the type of loan. In general, the carrying amount of variable rate debt is a close approximation of its fair value. For fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow analyses. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards, swaps and options, and energy derivatives is the estimated net amount that the Company would receive or pay to sell or transfer the agreements as of the balance sheet date.

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

Valuation Techniques

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

etc.). In general, the Company determines the fair value of investments and derivatives using the market approach and the income approach, respectively. In the nonrecurring measurements of nonfinancial assets and liabilities, all three approaches are considered; however, fair value estimated under the income approach is often selected. Assets and liabilities are 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.

Investments

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

Derivatives

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

For derivatives for which there is a standard industry valuation model, the Company uses a third-party treasury and risk management software product that uses a standard model and observable inputs to estimate the fair value. For these derivatives, the Company performs analytical procedures and makes comparisons to other third-party information in order to assess the reasonableness of the fair value. For derivatives (such as PPAs and fuel supply agreements that are derivatives or include embedded derivatives) for which there is not a standard industry valuation model, the Company has created internal valuation models to estimate the fair value, using observable data to the extent available. At each quarter-end, the models for the commodity and foreign currency-based derivatives are generally prepared by employees who globally manage the respective commodity and foreign currency risks. For all derivatives, with the exception of those classified as Level 1, the income approach is used, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. Among the most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (such as LIBOR and Euro Inter Bank Offered Rate (“EURIBOR”)), foreign exchange rates and commodity prices. Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published information provided from another source. In situations where significant inputs are not observable, the Company uses relevant techniques to best estimate the inputs, such as regression analysis, Monte Carlo simulation or prices for similarly traded instruments available in the market.

For each derivative, with the exception of those classified as Level 1, the income approach is used to estimate the cash flows over the remaining term of the contract. Those cash flows are then discounted using the

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

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

The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) at June 30, 2012:


	Fair Value		Unobservable Input	Amount or Range (Weighted Average)
	(in millions)
Interest rate	$	(281)	Subsidiaries’ credit risk		3% - 4.1% (3.5%)
Foreign currency:
Embedded derivative — Argentine Peso		48	Argentine Peso to U.S. Dollar currency exchange rate after 2 years		7.53
Other		(1)
Commodity & other:
Embedded derivative — Aluminum		(66)	Market price of power for customer in Cameroon (per KWh)		$0.05 -$0.17 ($0.12)
Embedded derivative — Philippine inflation		8	U.S. Producer Price Index after 5 years (where base year of 2005 = 100)		143 - 174 (154)
Other		6

Total	$	(286)

Changes in the above significant unobservable inputs that lead to a significant and unusual impact to current period earnings are disclosed to the Financial Audit Committee. For interest rate derivatives, increases (decreases) in the estimates of our own credit risk would decrease (increase) the value of the derivatives in a liability position. For foreign currency derivatives, increases (decreases) in the estimate of the above exchange rate would increase (decrease) the value of the derivative. For commodity and other derivatives in the above table, increases (decreases) in the estimated inflation would increase (decrease) the value of those embedded derivatives, while increases (decreases) in the estimated market price for power would increase (decrease) the value of that embedded derivative.

The only Level 1 derivative instruments as of June 30, 2012 are exchange-traded commodity futures for which the pricing is observable in active markets, and as such, these are not expected to transfer to other levels. There have been no transfers between Level 1 and Level 2.

Debt

Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated based upon the type of borrowing. The fair value of fixed rate borrowings is estimated using quoted market prices, if available, or a discounted cash flow analysis. In the discounted cash flow analysis, the discount rate is based on the credit rating of the individual debt instruments, if available, or the credit rating of the subsidiary. If the subsidiary’s credit rating is not available, a synthetic credit rating is determined using certain key metrics, including cash flow ratios and interest coverage, as well as other industry specific factors. For subsidiaries located outside the U.S., in the event that the country rating is lower than the credit rating previously determined, the country rating is used for the purposes of the discounted cash flow analysis. The fair value of recourse and non-recourse debt excludes accrued interest at the valuation date. The fair value was determined using available market information as of June 30, 2012. The Company is [not] aware of any factors that would significantly affect the fair value amounts subsequent to June 30, 2012.

Nonfinancial Assets and Liabilities

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

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

For nonrecurring measurements derived using the cost approach, fair value is typically determined using the replacement cost approach. Under this approach, the depreciated replacement cost of assets is determined by first determining the current replacement cost of assets and then applying the remaining useful life percentages to such costs. Further adjustments for economic and functional obsolescence are made to the depreciated replacement cost. This approach involves a considerable amount of judgment, which is why its use is limited to the measurement of a few long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value determined under the income approach.

Fair Value Considerations

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

Sources of market assumptions

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

Market liquidity

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

Nonperformance risk

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

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

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

Recurring Measurements

The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were measured at fair value on a recurring basis as of June 30, 2012 and December 31, 2011:


	Fair Value
	Total		Level 1		Level 2		Level 3
	(in millions)
June 30, 2012
Assets
Available-for-sale securities	$	864	$	1	$	863	$	-
Trading securities		12		12		-		-
Derivatives		116		-		45		71

Total assets	$	992	$	13	$	908	$	71

Liabilities
Derivatives	$	805	$	-	$	448	$	357

Total liabilities	$	805	$	-	$	448	$	357


December 31, 2011
Assets
Available-for-sale securities	$	1,340	$	1	$	1,339	$	-
Trading securities		12		12		-		-
Derivatives		120		2		52		66

Total assets	$	1,472	$	15	$	1,391	$	66

Liabilities
Derivatives	$	690	$	-	$	476	$	214

Total liabilities	$	690	$	-	$	476	$	214

The following tables present a reconciliation of net derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and six months ended June 30, 2012 and 2011 (presented net by type of derivative where any foreign currency impacts are presented as part of gains (losses) in earnings or other comprehensive income as appropriate):


	Three Months Ended June 30, 2012
	Interest Rate			Cross Currency		Foreign Currency			Commodity and Other			Total
	(in millions)
Balance at April 1	$	(124	)	$	-	$	48		$	(46	)	$	(122	)
Total gains (losses) (realized and unrealized):
Included in earnings⁽¹⁾		-			-		-			(13	)		(13	)
Included in other comprehensive income		(58	)		-		-			-			(58	)
Included in regulatory (assets) liabilities		-			-		-			7			7
Settlements		6			-		(1	)		-			5
Transfers of assets (liabilities) into Level 3⁽²⁾		(105	)		-		-			-			(105	)
Transfers of (assets) liabilities out of Level 3⁽²⁾		-			-		-			-			-

Balance at June 30	$	(281	)	$	-	$	47		$	(52	)	$	(286	)

Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/(losses) relating to assets and liabilities held at the end of the period	$	-		$	-	$	(1	)	$	(13	)	$	(14	)


	Three Months Ended June 30, 2011
	Interest Rate			Cross Currency			Foreign Currency			Commodity and Other			Total
	(in millions)
Balance at April 1	$	(7	)	$	5		$	23		$	24		$	45
Total gains (losses) (realized and unrealized):
Included in earnings⁽¹⁾		-			(2	)		18			(16	)		-
Included in other comprehensive income		(12	)		8			-			-			(4	)
Included in regulatory (assets) liabilities		-			-			-			7			7
Settlements		1			4			(1	)		-			4
Transfers of assets (liabilities) into Level 3⁽²⁾		(58	)		-			-			-			(58	)
Transfers of (assets) liabilities out of Level 3⁽²⁾		16			-			(2	)		2			16

Balance at June 30	$	(60	)	$	15		$	38		$	17		$	10

Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/(losses) relating to assets and liabilities held at the end of the period	$	-		$	(2	)	$	15		$	(7	)	$	6


	Six Months Ended June 30, 2012
	Interest Rate			Cross Currency			Foreign Currency			Commodity and Other			Total
	(in millions)
Balance at January 1	$	(128	)	$	(18	)	$	51		$	(53	)	$	(148	)
Total gains (losses) (realized and unrealized):
Included in earnings⁽¹⁾		(1	)		-			(2	)		(5	)		(8	)
Included in other comprehensive income		(19	)		4			-			-			(15	)
Included in regulatory (assets) liabilities		-			-			-			7			7
Settlements		13			8			(2	)		(1	)		18
Transfers of assets (liabilities) into Level 3⁽²⁾		(146	)		-			-			-			(146	)
Transfers of (assets) liabilities out of Level 3⁽²⁾		-			6			-			-			6

Balance at June 30	$	(281	)	$	-		$	47		$	(52	)	$	(286	)


Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/(losses) relating to assets and liabilities held at the end of the period	$	-		$	-		$	(3	)	$	(5	)	$	(8	)


	Six Months Ended June 30, 2011
	Interest Rate			Cross Currency			Foreign Currency			Commodity and Other			Total
	(in millions)
Balance at January 1	$	(1	)	$	10		$	22		$	18		$	49
Total gains (losses) (realized and unrealized):
Included in earnings⁽¹⁾		-			-			18			(7	)		11
Included in other comprehensive income		(1	)					-			-			(1	)
Included in regulatory (assets) liabilities		-			-			-			6			6
Settlements		-			5			(2	)		-			3
Transfers of assets (liabilities) into Level 3⁽²⁾		(58	)		-			-			-			(58	)
Transfers of (assets) liabilities out of Level 3⁽²⁾		-			-			-			-			-

Balance at June 30	$	(60	)	$	15		$	38		$	17		$	10

Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/(losses) relating to assets and liabilities held at the end of the period	$	-		$	-		$	15		$	(1	)	$	14

⁽¹⁾

The gains (losses) included in earnings for these Level 3 derivatives are classified as follows: interest rate and cross currency derivatives as interest expense; foreign currency derivatives as foreign currency transaction gains (losses); and commodity and other derivatives as either non-regulated revenue, non-regulated cost of sales, or other expense. See Note 5—Derivative Instruments and Hedging Activities for further information regarding the classification of gains and losses included in earnings in the condensed consolidated statements of operations.

⁽²⁾

Transfers in and out of Level 3 are determined as of the end of the reporting period and are from and to Level 2. The assets (liabilities) transferred into and out of Level 3 are primarily the result of an increase or decrease in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments.

The following table presents a reconciliation of available-for-sale securities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and six months ended June 30, 2012 and 2011:


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions)
Balance at beginning of period	$	-	$	40	$	-	$	42
Settlements		-		-		-		(2	)

Balance at June 30	$	-	$	40	$	-	$	40

Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets held at the end of the period	$	-	$	-	$	-	$	-

Nonrecurring Measurements

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


	Six Months Ended June 30, 2012
	Carrying Amount		Fair Value						Gross Loss
	Carrying Amount		Level 1		Level 2		Level 3		Gross Loss
	in million
Assets
Long-lived assets held and used:⁽¹⁾
Kelanitissa	$	22	$	-	$	-	$	10	$	12
Long-lived assets held for sale:⁽¹⁾
St. Patrick		33		-		22		-		11
Equity method investments⁽²⁾		205		-		155		-		50
	Six Months Ended June 30, 2011
	Carrying Amount		Fair Value						Gross Loss
	Carrying Amount		Level 1		Level 2		Level 3		Gross Loss
	in million
Assets
Long-lived assets held and used:⁽¹⁾
Kelanitissa	$	66	$	-	$	-	$	33	$	33

⁽¹⁾	See Note 14 — Asset Impairment Expense for further information.

⁽²⁾	See Note 15 — Other Non-Operating Expense for further information.

The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets during the period:

Fair Value

Valuation
Technique

Unobservable Input

Range

(in millions)

Long-lived assets held and used:

Kelanitissa

Discounted
cash flow

Annual revenue growth

-9% to 4%

Annual pretax operating margin

-4% to 16%

Weighted average cost of capital

11.9%

Total

Financial Instruments not Measured at Fair Value in the Condensed Consolidated Balance Sheets

The following table sets forth the carrying amount and fair value of the Company’s financial assets and liabilities that are not measured at fair value in the condensed consolidated balance sheets as of June 30, 2012 and December 31, 2011, but for which fair value is disclosed. In addition, the fair value level hierarchy of such assets and liabilities is presented as of June 30, 2012:


			Fair Value
	Carrying Amount		Total		Level 1		Level 2		Level 3
June 30, 2012	(in millions)
Assets
Trade receivables⁽¹⁾	$	460	$	398	$	-	$	-	$	398
Liabilities
Non-recourse debt		15,537		16,021		-		11,944		4,077
Recourse debt		6,189		6,802		-		6,802		-
December 31, 2011
Assets
Trade receivables	$	469	$	484
Liabilities
Non-recourse debt		15,535		15,862
Recourse debt		6,485		6,640

⁽¹⁾

Trade receivables are included in “Current Assets — Accounts Receivable” and “Noncurrent Assets — Other” in the accompanying condensed consolidated balance sheets. These receivables principally relate to amounts due from the independent system operator in Argentina. During the three months ended June 30, 2012, the significant decline in fair value of these receivables was a result of the increased credit risk in Argentina.

4. INVESTMENTS IN MARKETABLE SECURITIES

The following table sets forth the Company’s investments in marketable debt and equity securities as of June 30, 2012 and December 31, 2011 by security class and by level within the fair value hierarchy. The security classes are determined based on the nature and risk of a security and are consistent with how the Company manages, monitors and measures its marketable securities.


	June 30, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)
AVAILABLE-FOR-SALE:⁽¹⁾
Debt securities:
Unsecured debentures	$	-	$	377	$	-	$	377	$	-	$	665	$	-	$	665
Certificates of deposit		-		389		-		389		-		576		-		576
Government debt securities		-		26		-		26		-		31		-		31
Other		-		14		-		14		-		-		-		-

Subtotal		-		806		-		806		-		1,272		-		1,272
Equity securities:
Mutual funds		-		57		-		57		-		67		-		67
Common stock		1		-		-		1		1		-		-		1

Subtotal		1		57		-		58		1		67		-		68

Total available-for-sale		1		863		-		864		1		1,339		-	$	1,340

TRADING:
Equity securities:
Mutual funds		12		-		-		12		12		-		-		12

Total trading		12		-		-		12		12		-		-		12

TOTAL	$	13	$	863	$	-	$	876	$	13	$	1,339	$	-	$	1,352


Held-to-maturity securities								7								4

Total marketable securities							$	883							$	1,356

⁽¹⁾

Cost/amortized cost approximated fair value at June 30, 2012 and December 31, 2011, with the exception of certain common stock investments with a cost basis and fair value of $1 million at June 30, 2012, and a cost basis and fair value of $4 million and $1 million, respectively, at December 31, 2011.

As of June 30, 2012, all available-for-sale debt securities had stated maturities within one year.

The following table summarizes the pre-tax gains and losses related to available-for-sale and trading securities for the three and six months ended June 30, 2012 and 2011. Gains and losses on the sale of investments are determined using the specific identification method. For the three and six months ended June 30, 2012 and 2011, there were [no] realized losses on the sale of available-for-sale securities and [no] other-than-temporary impairment of marketable securities recognized in earnings or other comprehensive income.


	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
	(in millions)
Gains included in earnings that relate to trading securities held at the reporting date	$	-	$	-		$	-	$	1
Unrealized gains (losses) on available-for-sale securities included in other comprehensive income		-		(1	)		-		(3	)
Proceeds from sales of available-for-sale securities		2,080		1,846			3,603		3,077
Gross realized gains on sales		1		3			1		4

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Risk Management Objectives

The Company is exposed to market risks associated with its enterprise-wide business activities, namely the purchase and sale of fuel and electricity as well as foreign currency risk and interest rate risk. In order to manage the market risks associated with these business activities, we enter into contracts that incorporate derivatives and financial instruments, including forwards, futures, options, swaps or combinations thereof, as appropriate. The Company generally applies hedge accounting to contracts as long as they are eligible under the accounting standards for derivatives and hedging. While derivative transactions are not entered into for trading purposes, some contracts are not eligible for hedge accounting.

Interest Rate Risk

AES and its subsidiaries utilize variable rate debt financing for construction projects and operations, resulting in an exposure to interest rate risk. Interest rate swap, cap and floor agreements are entered into to manage interest rate risk by effectively fixing or limiting the interest rate exposure on the underlying financing. These interest rate contracts range in maturity through 2030, and are typically designated as cash flow hedges. The following table sets forth, by underlying type of interest rate index, the Company’s current and maximum outstanding notional under its interest rate derivative instruments, the weighted average remaining term and the percentage of variable-rate debt hedged that is based on the related index as of June 30, 2012 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:


	June 30, 2012
	Current				Maximum⁽¹⁾
Interest Rate Derivatives	Derivative Notional		Derivative Notional Translated to USD		Derivative Notional		Derivative Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾		% of Debt Currently Hedged by Index⁽²⁾
	(in millions)								(in years)
Libor (U.S. Dollar)		3,604	$	3,604		4,608	$	4,608		10		69	%
Euribor (Euro)		626		793		629		796		10		63	%
Libor (British Pound)		60		94		101		158		14		91	%

⁽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, 2012 and the maturity of the derivative instrument, which includes forward starting derivative instruments. The weighted average remaining term represents the remaining tenor of our interest rate derivatives weighted by the corresponding maximum notional.

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

Cross currency swaps are utilized in certain instances to manage the risk related to fluctuations in both interest rates and certain foreign currencies. These cross currency contracts range in maturity through 2028. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notional amount under its cross currency derivative instruments as of June 30, 2012, which are all in qualifying cash flow hedge relationships. These swaps are amortizing and therefore the notional amount represents the maximum outstanding notional amount as of June 30, 2012:


	June 30, 2012
Cross Currency Swaps	Notional		Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾		% of Debt Currently Hedged by Index⁽²⁾
	(in millions)				(in years)
Chilean Unidad de Fomento (CLF)		6	$	253		14		85	%

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

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

Foreign Currency Risk

We are exposed to foreign currency risk as a result of our investments in foreign subsidiaries and affiliates. AES operates businesses in many foreign countries and such operations may be impacted by significant fluctuations in foreign currency exchange rates. Foreign currency options and forwards are utilized, where deemed appropriate, to manage the risk related to fluctuations in certain foreign currencies. These foreign currency contracts range in maturity through 2015. The following tables set forth, by type of foreign currency denomination, the Company’s outstanding notional amounts over the remaining terms of its foreign currency derivative instruments as of June 30, 2012 regardless of whether the derivative instruments are in qualifying hedging relationships:


	June 30, 2012
Foreign Currency Options	Notional		Notional Translated to USD⁽¹⁾		Probability Adjusted Notional⁽²⁾		Weighted Average Remaining Term⁽³⁾
	(in millions)						(in years)
Euro (EUR)		68	$	87	$	56		<1
Philippine Peso (PHP)		1,625		38		15		<1
British Pound (GBP)		2		3		2		<1

⁽¹⁾	Represents contractual notionals at inception of trade.

⁽²⁾	Represents the gross notional amounts times the probability of exercising the option, which is based on the relationship of changes in the option value with respect to changes in the price of the underlying currency.

⁽³⁾	Represents the remaining tenor of our foreign currency options weighted by the corresponding notional.


	June 30, 2012
Foreign Currency Forwards	Notional		Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾
	(in millions)				(in years)
Euro (EUR)		95	$	131		2
Chilean Peso (CLP)		60,833		122		<1
Colombian Peso (COP)		189,847		105		<1
Philippine Peso (PHP)		2,183		51		<1
British Pound (GBP)		24		37		<1
Argentine Peso (ARS)		31		7		<1

⁽¹⁾

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

In addition, certain of our subsidiaries have entered into contracts which contain embedded derivatives that require separate valuation and accounting due to the fact that the item that is being purchased or sold is denominated in a currency other than the functional currency of the subsidiary or the currency of the item. These contracts range in maturity through 2026. 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, 2012:


	June 30, 2012
Embedded Foreign Currency Derivatives	Notional		Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾
	(in millions)				(in years)
Philippine Peso (PHP)⁽²⁾		64,870	$	1,553		11
Argentine Peso (ARS)		943		208		12
Kazakhstani Tenge (KZT)		1,275		9		4
Euro (EUR)		2		3		9

⁽¹⁾

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

⁽²⁾

Notional also relates to an embedded derivative related to inflation.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the price of electricity, fuel and environmental credits. Although our businesses primarily enter into long-term contracts or retail sales concessions (which provide our distribution businesses with a franchise to serve a specific geographic region), a portion of our current and expected future revenues are derived from businesses without significant long-term purchase or sales contracts. These businesses subject our results of operations to the volatility of prices for electricity, fuel and environmental credits in competitive markets. We have used a hedging strategy, where appropriate, to hedge our financial performance against the effects of fluctuations in energy commodity prices.

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

Nonetheless, certain of the PPAs and fuel supply agreements entered into by certain of the Company’s subsidiaries are derivatives or contain embedded derivatives requiring separate valuation and accounting. These contracts range in maturity through 2024. The following table sets forth, by type of commodity, the Company’s outstanding notionals for the remaining term of its commodity derivatives and embedded derivative instruments as of June 30, 2012:


	June 30, 2012
Commodity Derivatives	Notional			Weighted Average Remaining Term⁽¹⁾
	(in millions)			(in years)
Natural gas (MMBTU)		30			11
Aluminum (MWh)		15	⁽²⁾		8
Petcoke (Metric tons)		12			12
Coal (Metric tons)		2			1
Power (Mwh)		3			3
Heating Oil (Gallons)		1			<1

⁽¹⁾

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

⁽²⁾

The embedded derivative relates to fluctuations in the price of aluminum versus fluctuations in the price of electricity, where the notional is based on the amount of power we sell under the PPA.

Accounting and Reporting

The following table sets forth the Company’s derivative instruments as of June 30, 2012 and December 31, 2011 by type of derivative and by level within the fair value hierarchy. Derivative assets and liabilities are recognized at their fair value. Derivative assets and liabilities are combined with other balances and included in the following captions in our condensed consolidated balance sheets: current derivative assets in other current assets, noncurrent derivative assets in other noncurrent assets, current derivative liabilities in accrued and other liabilities and noncurrent derivative liabilities in other noncurrent liabilities.


	June 30, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)								(in millions)
Assets
Current assets:
Foreign currency derivatives	$	-	$	9	$	5	$	14	$	-	$	24	$	4	$	28
Commodity and other derivatives		-		19		8		27		2		16		3		21

Total current assets		-		28		13		41		2		40		7		49

Noncurrent assets:
Interest rate derivatives		-		2		-		2		-		-		-		-
Cross currency derivatives		-		4		-		4		-		-		1		1
Foreign currency derivatives		-		6		50		56		-		3		58		61
Commodity and other derivatives		-		5		8		13		-		9		-		9

Total noncurrent assets		-		17		58		75		-		12		59		71

Total assets	$	-	$	45	$	71	$	116	$	2	$	52	$	66	$	120

Liabilities
Current liabilities:
Interest rate derivatives	$	-	$	78	$	44	$	122	$	-	$	97	$	22	$	119
Cross currency derivatives		-		6		-		6		-		-		5		5
Foreign currency derivatives		-		4		1		5		-		5		1		6
Commodity and other derivatives		-		20		7		27		-		17		6		23

Total current liabilities		-		108		52		160		-		119		34		153

Noncurrent liabilities:
Interest rate derivatives		-		250		237		487		-		334		106		440
Cross currency derivatives		-		4		-		4		-		-		14		14
Foreign currency derivatives		-		76		7		83		-		10		10		20
Commodity and other derivatives		-		10		61		71		-		13		50		63

Total noncurrent liabilities		-		340		305		645		-		357		180		537

Total liabilities	$	-	$	448	$	357	$	805	$	-	$	476	$	214	$	690

The following table sets forth the fair value and balance sheet classification of derivative instruments as of June 30, 2012 and December 31, 2011:


	June 30, 2012						December 31, 2011
	Designated as Hedging Instruments		Not Designated as Hedging Instruments		Total		Designated as Hedging Instruments		Not Designated as Hedging Instruments		Total
	(in millions)						(in millions)
Assets
Current assets:
Foreign currency derivatives	$	6	$	8	$	14	$	10	$	18	$	28
Commodity and other derivatives		2		25		27		2		19		21

Total current assets		8		33		41		12		37		49

Noncurrent assets:
Interest rate derivatives		-		2		2		-		-		-
Cross currency derivatives		4		-		4		1		-		1
Foreign currency derivatives		6		50		56		3		58		61
Commodity and other derivatives		1		12		13		-		9		9

Total noncurrent assets		11		64		75		4		67		71

Total assets	$	19	$	97	$	116	$	16	$	104	$	120

Liabilities
Current liabilities:
Interest rate derivatives	$	114	$	8	$	122	$	110	$	9	$	119
Cross currency derivatives		6		-		6		5		-		5
Foreign currency derivatives		3		2		5		1		5		6
Commodity and other derivatives		3		24		27		-		23		23

Total current liabilities		126		34		160		116		37		153

Noncurrent liabilities:
Interest rate derivatives		473		14		487		425		15		440
Cross currency derivatives		4		-		4		14		-		14
Foreign currency derivatives		-		83		83		-		20		20
Commodity and other derivatives		4		67		71		3		60		63

Total noncurrent liabilities		481		164		645		442		95		537

Total liabilities	$	607	$	198	$	805	$	558	$	132	$	690

The Company has elected not to offset derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements. At June 30, 2012 and December 31, 2011, we held $0 million and $3 million, respectively, of cash collateral that we received from counterparties to our derivative positions. Beyond the cash collateral held by us, our derivative assets are exposed to the credit risk of the respective counterparty and, due to this credit risk, the fair value of our derivative assets (as shown in the above two tables) have been reduced by a credit valuation adjustment. Also, at June 30, 2012 and December 31, 2011, there was $20 million and $16 million, respectively, of cash collateral posted with (held by) counterparties to our derivative positions.

The table below sets forth the pre-tax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes (in millions) over the next twelve months as of June 30, 2012 for the following types of derivative instruments:


Interest rate derivatives	$	(114	)
Cross currency derivatives	$	4
Foreign currency derivatives	$	2
Commodity and other derivatives	$	(1	)

The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for interest rate hedges and cross currency swaps (except for the amount reclassified to foreign currency transaction gains and losses to offset the remeasurement of the foreign currency-denominated debt being hedged by the cross currency swaps), as depreciation is recognized for interest rate hedges during construction, as foreign currency transaction gains and losses are recognized for hedges of foreign currency exposure, and as electricity sales and fuel purchases are recognized for hedges of forecasted electricity and fuel transactions. These balances are included in the consolidated statements of cash flows as operating and/or investing activities based on the nature of the underlying transaction.

The following tables set forth the gains (losses) recognized in accumulated other comprehensive loss (“AOCL”) and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the three and six months ended June 30, 2012 and 2011:


	Gains (Losses) Recognized in AOCL						Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Reclassified from AOCL into Earnings
	Three Months Ended June 30,							Three Months Ended June 30,
	2012			2011				2012			2011
	(in millions)							(in millions)
Interest rate derivatives	$	(153	)	$	(144	)	Interest expense	$	(30	)	$	(27	)
							Non-regulated cost of sales		(1	)		(1	)
							Net equity in earnings of affiliates		(1	)		(1	)
							Gain on sale of investments		(4	)		-
Cross currency derivatives		(9	)		11		Interest expense		(3	)		7
							Foreign currency transaction gains (losses)		(6	)		10
Foreign currency derivatives		6			(7	)	Foreign currency transaction gains (losses)		-			(2	)
Commodity and other derivatives		(1	)		(1	)	Non-regulated revenue		-			-

Total	$	(157	)	$	(141	)		$	(45	)	$	(14	)


	Gains (Losses) Recognized in AOCL						Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Reclassified from AOCL into Earnings⁽¹⁾
	Six Months Ended June 30,							Six Months Ended June 30,
	2012			2011				2012			2011
	(in millions)							(in millions)
Interest rate derivatives	$	(142	)	$	(92	)	Interest expense	$	(62	)	$	(53	)
							Non-regulated cost of sales		(3	)		(2	)
							Net equity in earnings of affiliates		(2	)		(2	)
							Gain on sale of investments		(96	)		-
Cross currency derivatives		5			3		Interest expense		(6	)		2
							Foreign currency transaction gains (losses)		12			5
Foreign currency derivatives		12			(2	)	Foreign currency transaction gains (losses)		-			(4	)
Commodity and other derivatives		(7	)		-		Non-regulated revenue		(2	)		-

Total	$	(132	)	$	(91	)		$	(159	)	$	(54	)

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

The following table sets forth the pre-tax gains (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the three and six months ended June 30, 2012 and 2011:


		Gains (Losses) Recognized in Earnings						Gains (Losses) Recognized in Earnings
	Classification in Condensed Consolidated Statements of Operations	Three Months Ended June 30,						Six Months Ended June 30,
		2012			2011			2012			2011
		(in millions)						(in millions)
Interest rate derivatives	Interest expense	$	2		$	-	⁽¹⁾	$	1		$	(7	)
	Net equity in earnings of affiliates		(1	)		(1	)		(1	)		(1	)
Cross currency derivatives	Interest expense		-	⁽¹⁾		(2	)		-	⁽¹⁾		(2	)
Foreign currency derivatives	Foreign currency transaction gains (losses)		-	⁽¹⁾		-	⁽¹⁾		-	⁽¹⁾		-	⁽¹⁾
Commodity derivatives — electricity	Non-regulated revenue		-	⁽¹⁾		-	⁽¹⁾		-	⁽¹⁾		-	⁽¹⁾

Total		$	1		$	(3	)	$	-		$	(10	)

⁽¹⁾	De minimis amount.

The following table sets forth the gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging, for the three and six months ended June 30, 2012 and 2011:


		Gains (Losses) Recognized in Earnings						Gains (Losses) Recognized in Earnings
	Classification in Condensed Consolidated Statements of Operations	Three Months Ended June 30,						Six Months Ended June 30,
		2012			2011			2012			2011
		(in millions)
Interest rate derivatives	Interest expense	$	(1	)	$	(1	)	$	(3	)	$	(1	)
Foreign currency derivatives	Foreign currency transaction gains		(38	)		20			(76	)		27
Commodity and other derivatives	Non-regulated revenue		(13	)		(13	)		1			(9	)
	Regulated revenue		(3	)		-			1			-
	Non-regulated cost of sales		-			(2	)		3			(1	)
	Regulated cost of sales		(5	)		-			(17	)		-

Total		$	(60	)	$	4		$	(91	)	$	16

In addition, DPL and IPL, our utilities in North America, have derivative instruments for which the gains and losses are accounted for in accordance with accounting standards for regulated operations, as regulatory assets or liabilities. Gains and losses due to changes in the fair value of these derivatives are probable of recovery through future rates and are initially recognized as an adjustment to the regulatory asset or liability and

recognized through earnings when the related costs are recovered through rates. Therefore, these gains and losses are excluded from the above table. The following table sets forth the change in regulatory assets and liabilities resulting from the change in the fair value of these derivatives for the three and six months ended June 30, 2012 and 2011:


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
(Increase) decrease in regulatory assets	$	(8	)	$	(2	)	$	(5	)	$	(2	)
Increase (decrease) in regulatory liabilities	$	(1	)	$	7		$	(1	)	$	6

Credit Risk-Related Contingent Features

Gener, our generation business in Chile, has cross currency swap agreements with counterparties to swap Chilean inflation indexed bonds issued in December 2007 into U.S. Dollars. The derivative agreements contain credit contingent provisions which would permit the counterparties with which Gener is in a net liability position to require collateral credit support when the fair value of the derivatives exceeds the unsecured thresholds established in the agreements. These thresholds vary based on Gener’s credit rating. If Gener’s credit rating were to fall below the minimum threshold established in the swap agreements, the counterparties can demand immediate collateralization of the entire mark-to-market loss of the swaps (excluding credit valuation adjustments), which was $10 million at June 30, 2012. The mark-to-market value of the swaps was $18 million at December 31, 2011. As of June 30, 2012 and December 31, 2011, Gener had not posted collateral to support these swaps.

DPL has certain over-the-counter commodity derivative contracts under master netting agreements that contain provisions that require its debt to maintain an investment-grade credit rating from credit rating agencies. If its debt were to fall below investment grade, the business would be in violation of these provisions, and the counterparties to the derivative contracts could request immediate payment or demand immediate and ongoing full overnight collateralization of the mark-to-market loss (excluding credit valuation adjustments), which was $29 million as of June 30, 2012. As of June 30, 2012, DPL had posted $20 million of cash collateral directly with third parties and in a broker margin account and held $0 million of cash collateral that it received from counterparties to its derivative instruments that were in an asset position. As of December 31, 2011, DPL had posted $16 million of cash collateral directly with third parties and in a broker margin account and held $3 million of cash collateral that it received from counterparties to its derivative instruments that were in an asset position.

6. LONG-TERM FINANCING RECEIVABLES

Long-term financing receivables represent receivables from certain Latin American governmental bodies that have contractual maturities of greater than one year. Management continually assesses the collectability of these receivables and believes they are recoverable. The receivables are included in “Noncurrent assets – other” on the condensed consolidated balance sheets. The following table sets forth the breakdown of financing receivables by country as of June 30, 2012 and December 31, 2011:


	June 30, 2012		December 31, 2011
	(in millions)
Argentina	$	218	$	232
Dominican Republic		43		49
Brazil		12		14

Total long-term financing receivables	$	273	$	295

7. DEBT

Non-Recourse Debt

The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of June 30, 2012 and is in the current portion of non-recourse debt unless otherwise indicated:


	Primary Nature of Default	June 30, 2012
Subsidiary	Primary Nature of Default	Default Amount		Net Assets (Liabilities)
		(in millions)
Maritza	Covenant	$	861	$	231
Sonel	Covenant		302		288
Kribi	Payment		137		(11	)
Dibamba	Covenant		77		36
Saurashtra	Covenant		26		15
Kelanitissa	Covenant		10		48

Total		$	1,413

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’ corporate debt agreements as of June 30, 2012 in order to trigger an event of default or permit acceleration under such indebtedness. The bankruptcy or acceleration of material amounts of debt at such subsidiaries would cause a cross default under the recourse senior secured credit facility. It is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position or results of operations of an individual subsidiary, and thereby a bankruptcy or an acceleration of its non-recourse debt could trigger an event of default and possible acceleration of the indebtedness under the AES Parent Company’s outstanding debt securities.

8. CONTINGENCIES AND COMMITMENTS

Guarantees, Letters of Credit and Commitments

In connection with certain project financing, acquisition, power purchase and other agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, AES has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations relate to future performance commitments which the Company or its businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 14 years.

The following table summarizes the Parent Company’s contingent contractual obligations as of June 30, 2012. Amounts presented in the table below represent the Parent Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of its businesses of $24 million.


Contingent Contractual Obligations	Amount		Number of Agreements		Maximum Exposure Range for Each Agreement
	(in millions)				(in millions)
Guarantees	$	528		18	<$	1 - $219
Letters of credit under the senior secured credit facility		5		9		<$1 - $2
Cash collateralized letters of credit		246		11		<$1 - $209

Total	$	779		38

As of June 30, 2012, the Company had $9 million of commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit discussed above. The Company expects to fund these net investment commitments in 2012. The exact payment schedules will be dictated by the construction milestones.

Environmental

The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of June 30, 2012, the Company had recorded liabilities of $24 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, 2012.

Litigation

The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims of approximately $342 million and $363 million as of June 30, 2012 and December 31, 2011, respectively. These reserves are reported on the consolidated balance sheets within “accrued and other liabilities” and “other noncurrent liabilities.” A significant portion of the reserves relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company’s subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that these reserves will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

The Company believes, based upon information it currently possesses and taking into account established reserves for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company’s consolidated financial statements. However, where no reserve has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be

material but could not be estimated as of June 30, 2012. The material contingencies where a loss is reasonably possible primarily include: claims under financing agreements; disputes with offtakers, suppliers and EPC contractors; alleged violation of monopoly laws and regulations; income tax and non-income tax assessments by tax authorities; and environmental and regulatory matters. In aggregate, the Company estimates that the range of potential losses, where estimable, related to these material contingences to be in the range of $227 million to $1.4 billion. The amounts considered reasonably possible do not include amounts reserved, as discussed above. These material contingencies do not include income tax related contingencies which are considered part of our uncertain tax positions.

9. REGULATORY LIABILITIES

In July 2012, the Brazilian energy regulator (the “Regulator”) approved the periodic review and reset of a component of Eletropaulo’s regulated tariff which determines the margin to be earned by Eletropaulo. The review and reset of this tariff component is retroactive to July 2011 and will be applied to customers’ invoices from July 2012 to June 2015. From July 2011 through June 2012, Eletropaulo invoiced customers under the then existing tariff rate, as required by the Regulator. As the new tariff rate is lower than the pre-existing tariff rate, Eletropaulo is required to reduce customer tariffs for this difference over the next three years. Accordingly, since the third quarter of 2011, Eletropaulo has been recognizing a regulatory liability for such estimated future refunds and updating this estimate as the periodic review and tariff reset process has progressed with the Regulator. As of June 30, 2012, Eletropaulo had recorded a regulatory liability of $536 million. This includes a cumulative increase of $80 million related to the estimated regulatory liability recognized in the second half of 2011 and the first quarter of 2012 based on the latest information available.

10. PENSION PLANS

Total pension cost for the three and six months ended June 30, 2012 and 2011 included the following components:


	Three Months Ended June 30,												Six Months Ended June 30,
	2012						2011						2012						2011
	U.S.			Foreign			U.S.			Foreign			U.S.			Foreign			U.S.			Foreign
	(in millions)												(in millions)
Service cost	$	3		$	3		$	2		$	5		$	7		$	10		$	4		$	10
Interest cost		12			126			8			148			24			267			16			290
Expected return on plan assets		(14	)		(111	)		(8	)		(133	)		(28	)		(233	)		(16	)		(261	)
Amortization of prior service cost		2			-			1			-			3			-			2			-
Amortization of net loss		6			11			4			6			12			21			7			12
Loss on curtailment		-			-			-			-			-			-			-			4

Total pension cost	$	9		$	29		$	7		$	26		$	18		$	65		$	13		$	55

Total employer contributions for the six months ended June 30, 2012 for the Company’s U.S. and foreign subsidiaries were $17 million and $83 million, respectively. The expected remaining scheduled employer contributions for 2012 are $31 million for U.S. subsidiaries and $85 million for foreign subsidiaries.

11. EQUITY

Changes in Equity

The following table provides a reconciliation of the beginning and ending equity attributable to stockholders of The AES Corporation, noncontrolling interests and total equity as of June 30, 2012 and 2011:


	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	The AES Corporation Stockholders’ Equity			Noncontrolling Interests			Total Equity			The AES Corporation Stockholders’ Equity			Noncontrolling Interests			Total Equity
	(in millions)									(in millions)
Balance at January 1	$	5,946		$	3,783		$	9,729		$	6,473		$	3,940		$	10,413
Net income		481			241			722			398			512			910
Total change in fair value of available-for-sale securities, net of income tax		-			-			-			(2	)		-			(2	)
Total foreign currency translation adjustment, net of income tax		(134	)		(110	)		(244	)		118			144			262
Total pension adjustments, net of income tax		4			9			13			2			5			7
Total change in fair value of derivatives, net of income tax		23			(9	)		14			(13	)		3			(10	)
Capital contributions from noncontrolling interests		-			12			12			-			3			3
Distributions to noncontrolling interests		-			(507	)		(507	)		-			(679	)		(679	)
Disposition of businesses		-			(37	)		(37	)		-			(2	)		(2	)
Acquisition of treasury stock		(231	)		-			(231	)		(98	)		-			(98	)
Issuance and exercise of stock-based compensation benefit plans, net of income tax		34			-			34			33			-			33
Acquisition of subsidiary shares from noncontrolling interests		-			(4	)		(4	)		-			-			-

Balance at June 30	$	6,123		$	3,378		$	9,501		$	6,911		$	3,926		$	10,837

Accumulated Other Comprehensive Loss

The components of accumulated other comprehensive loss as of June 30, 2012 and December 31, 2011 were as follows:


	June 30, 2012		December 31, 2011
	June 30, 2012		December 31, 2011
	(in millions)
Foreign currency translation adjustment	$	2,101	$	1,967
Unrealized derivative losses, net		511		534
Unfunded pension obligation		253		257

Accumulated other comprehensive loss	$	2,865	$	2,758

Stock Repurchase Program

On April 19, 2012, the Company’s Board of Directors approved an increase to the stock repurchase program (the “Program”), which was announced on July 7, 2010, bringing the total amount authorized for purchases of AES common stock from $500 million to $680 million. The Board authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated

transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The Program does not have an expiration date and it can be modified or terminated by the Board of Directors at any time. During the three and six months ended June 30, 2012, shares of common stock repurchased under this plan totaled 18,744,363 at a total cost of $231 million, which includes a nominal amount of commissions (average of $12.31 per share including commissions), bringing the cumulative total purchases under the program to 52,669,168 shares at a total cost of $608 million plus a nominal amount of commissions (average of $11.57 per share including commissions).

The shares of stock repurchased have been classified as treasury stock and accounted for using the cost method. A total of 60,391,403 and 42,386,961 shares were held as treasury stock at June 30, 2012 and December 31, 2011, respectively. The Company has not retired any shares held in treasury during the three and six months ended June 30, 2012.

12. SEGMENTS

During the first quarter of 2012, the Company completed its operational management and reporting restructuring. The management reporting structure is organized along two lines of business – Generation and Utilities, each led by a Chief Operating Officer. The segment reporting structure primarily uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally with further aggregation by geographic regions to provide better socio-political-economic understanding of our business. For the three and six months ended June 30, 2012, the Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria. The Company concluded that Tietê, our 2,663 MW hydro generation business in Brazil, met the quantitative thresholds to require separate presentation. As such, an additional reportable segment which consists solely of the results of Tietê is now reported as Generation — Tietê. Tietê was formerly reported within the Latin America — Generation segment. The previously disclosed Latin America — Generation segment is now reported as Generation — Latin America — Other and, with the exception of Tietê, includes the results of all remaining businesses as previously reported. All prior period results have been retrospectively revised to reflect the new segment reporting structure. The Company has increased from six to the following seven reportable segments:

•

Generation — Latin America — Other;

•

Generation — Tietê;

•

Generation — North America;

•

Generation — Europe;

•

Generation — Asia;

•

Utilities — Latin America;

•

Utilities — North America.

Corporate and Other — The Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation operating segments and other climate solutions and renewables projects are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our presentation of reportable segments, individually or in the aggregate. AES Solar and certain other unconsolidated businesses are accounted for using the equity method of accounting; therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Condensed Consolidated Statements of Operations, not in revenue or gross margin. “Corporate and Other” also includes corporate overhead costs which are not directly associated with the operations of our seven reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

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

Total revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain self-insurance activities which are reflected within segment adjusted gross margin. All intra-segment activity has been eliminated with respect to revenue and adjusted gross margin within the segment. Inter-segment activity has been eliminated within the total consolidated results. Asset information for businesses that were discontinued or classified as held for sale as of June 30, 2012 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.

Information about the Company’s operations by segment for the three and six months ended June 30, 2012 and 2011 was as follows:


Three months ended	Total Revenue				Intersegment			External Revenue
June 30,	2012		2011		2012			2011			2012		2011
	(in millions)
Generation — Latin America — Other	$	1,029	$	1,122	$	(9	)	$	(11	)	$	1,020	$	1,111
Generation — Tietê		274		256		(248	)		(251	)		26		5
Generation — North America		328		339		-			(4	)		328		335
Generation — Europe		233		328		(1	)		-			232		328
Generation — Asia		181		162		-			-			181		162
Utilities — Latin America		1,446		1,944		-			-			1,446		1,944
Utilities — North America		678		280		-			-			678		280
Corp and Other		284		273		(3	)		(3	)		281		270

Total Revenue	$	4,453	$	4,704	$	(261	)	$	(269	)	$	4,192	$	4,435


Six Months Ended	Total Revenue				Intersegment						External Revenue
June 30,	2012		2011		2012			2011			2012		2011
	(in millions)
Generation — Latin America — Other	$	1,988	$	2,000	$	(19	)	$	(20	)	$	1,969	$	1,980
Generation — Tietê		579		509		(530	)		(493	)		49		16
Generation — North America		645		673		-			(4	)		645		669
Generation — Europe		683		728		(1	)		(1	)		682		727
Generation — Asia		362		277		-			-			362		277
Utilities — Latin America		3,180		3,784		-			-			3,180		3,784
Utilities — North America		1,410		569		-			-			1,410		569
Corp and Other		640		574		(5	)		(5	)		635		569

Total Revenue	$	9,487	$	9,114	$	(555	)	$	(523	)	$	8,932	$	8,591


Three months ended	Total Adjusted Gross Margin					Intersegment						External Adjusted Gross Margin
June 30,	2012		2011			2012			2011			2012			2011
	(in millions)
Generation — Latin America — Other	$	232	$	326		$	6		$	3		$	238		$	329
Generation — Tietê		210		191			(248	)		(251	)		(38	)		(60	)
Generation — North America		116		110			4			(1	)		120			109
Generation — Europe		84		93			-			1			84			94
Generation — Asia		64		53			1			-			65			53
Utilities — Latin America		44		340			250			253			294			593
Utilities — North America		193		89			1			1			194			90
Corp and Other		14		(9	)		(12	)		(9	)		2			(18	)
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization													(341	)		(295	)
Interest expense													(385	)		(381	)
Interest income													83			96
Other expense													(15	)		(35	)
Other income													15			34
Gain on sale of investments													5			1
Asset impairment expense													(18	)		(33	)
Foreign currency transaction gains (losses)													(101	)		37
Other non-operating expense													(1	)		-

Income from continuing operations before taxes and equity in earnings of affiliates												$	201		$	614


Six months ended	Total Adjusted Gross Margin					Intersegment						External Adjusted Gross Margin
June 30,	2012		2011			2012			2011			2012			2011
	(in millions)
Generation — Latin America — Other	$	519	$	594		$	10		$	6		$	529		$	600
Generation — Tietê		449		393			(530	)		(493	)		(81	)		(100	)
Generation — North America		222		216			6			3			228			219
Generation — Europe		321		199			(7	)		2			314			201
Generation — Asia		122		98			1			1			123			99
Utilities — Latin America		211		660			535			498			746			1,158
Utilities — North America		406		179			1			1			407			180
Corp and Other		61		34			(26	)		(22	)		35			12
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization													(692	)		(576	)
Interest expense													(801	)		(719	)
Interest income													174			191
Other expense													(44	)		(50	)
Other income													33			50
Gain on sale of investments													184			7
Asset impairment expense													(29	)		(33	)
Foreign currency transaction gains (losses)													(102	)		70
Other non-operating expense													(50	)		-

Income from continuing operations before taxes and equity in earnings of affiliates													$974			$1,309

Assets by segment as of June 30, 2012 and December 31, 2011 were as follows:


	Total Assets
	June 30, 2012		December 31, 2011
	(in millions)
Assets
Generation — Latin America — Other	$	9,120	$	9,067
Generation — Tietê		1,422		1,645
Generation — North America		3,568		3,625
Generation — Europe		3,340		3,276
Generation — Asia		2,099		1,717
Utilities — Latin America		8,491		9,468
Utilities — North America		9,245		9,344
Discontinued businesses		-		1,531
Corp and Other		5,464		5,620

Total assets	$	42,749	$	45,293

13. OTHER INCOME (EXPENSE)

The components of other income for the three and six months ended June 30, 2012 and 2011 were as follows:


	Three MonthsEnded June 30,				Six MonthsEnded June 30,
	2012		2011		2012		2011
	(in millions)
Gain on sale of assets	$	1	$	14	$	3	$	16
Other		14		20		30		34

Total other income	$	15	$	34	$	33	$	50

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

Other income of $15 million for the three months ended June 30, 2012 was primarily related to the receipt of insurance proceeds related to a claim in Panama for damage to the Esti tunnel. Other income of $34 million for the three months ended June 30, 2011 was primarily related to the gain on sale of mineral rights and land in Indiana at IPL, and the receipt of insurance proceeds related to a claim in Panama for damage associated with the Esti tunnel.

Other income of $33 million for the six months ended June 30, 2012 was primarily related to the receipt of insurance proceeds as described above, the release of a heavy fuel oil stock at Ballylumford and the receipt of dividends from a cost method investment at Gener. Other income of $50 million for the six months ended June 30, 2011 was primarily related to the gain on sale at IPL and receipt of insurance proceeds as described above.

The components of other expense for the three and six months ended June 30, 2012 and 2011 were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions)
Loss on sale and disposal of assets	$	11	$	16	$	35	$	26
Loss on extinguishment of debt		-		15		-		15
Other		4		4		9		9

Total other expense	$	15	$	35	$	44	$	50

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

Other expense for the three months ended June 30, 2012 of $15 million was primarily comprised of losses on the disposal of assets at Eletropaulo. Other expense for the three months ended June 30, 2011 of $35 million was primarily comprised of a loss related to the early retirement of senior notes due in 2011 at IPALCO, and a loss on disposal of assets at Eletropaulo.

Other expense of $44 million for the six months ended June 30, 2012 was primarily due to the loss on disposal of assets at Eletropaulo. Other expense of $50 million for the six months ended June 30, 2011 included early retirement of senior notes due in 2011 at IPALCO and loss on disposal of assets at Eletropaulo, as discussed above.

14. ASSET IMPAIRMENT EXPENSE

Asset impairment expense was $18 million and $29 million for the three and six months ended June 30, 2012, respectively.

Kelanitissa — We continue to evaluate the recoverability of our long-lived assets at Kelanitissa, our diesel-fired generation plant in Sri Lanka, as a result of both the requirement to transfer the plant to the government at the end of our PPA and the current expectation of lower future operating cash flows. During the first half of 2012, the Company recognized asset impairment expense of $12 million for the long-lived assets of Kelanitissa. Our evaluations during this period indicated that the long-lived assets were no longer recoverable and accordingly were written down to their estimated fair value of $10 million based on a discounted cash flow analysis. The long-lived assets had a carrying amount of $22 million prior to the recognition of asset impairment expense. Kelanitissa is reported in the Asia Generation reportable segment.

St. Patrick — During the current quarter, the Company received approval from its Board of Directors for the sale of its wholly-owned subsidiary Ferme Eolienne Saint Patrick SAS (“St. Patrick”). Upon meeting the held for sale criteria including the Board’s approval, long-lived assets with a carrying amount of $33 million were written down to their fair value of $22 million (i.e., the sale price attributed to St. Patrick) and an impairment expense of $11 million was recorded. The sale transaction subsequently closed on June 28, 2012. St. Patrick is reported in “Corporate and Other”.

The remaining asset impairment expense consists of write-offs related to smaller projects.

Asset impairment expense was $33 million for the three and six months ended June 30, 2011.

15. OTHER NON-OPERATING EXPENSE

Other non-operating expense of $1 million and $50 million, respectively, for the three and six months ended June 30, 2012 consisted of the other-than-temporary impairment of the following equity method investments:

InnoVent — During the first quarter of 2012, the Company concluded it was more likely than not that it would sell its interest in InnoVent S.A.S. (“InnoVent”), an equity method investment in France with wind generation projects totaling 75 MW. InnoVent had a carrying value of $36 million which exceeded its fair value of $19 million, resulting in an other-than-temporary impairment expense of $17 million. The sale transaction closed on June 28, 2012.

China — During the first quarter of 2012, the Company concluded it was more likely than not that it would sell its interests in certain investments in China before the end of their joint venture terms. These investments include coal-fired, hydropower and wind generation facilities accounted for under the equity method of accounting. These were considered impairment indicators. In measuring the other-than-temporary impairment, the carrying value of $164 million of these investments was compared to their fair value of $133 million resulting in an other-than-temporary impairment expense of $31 million.

The remaining other non-operating expense consists of other-than-temporary impairments related to smaller equity method investments.

There was no other non-operating expense for the three and six months ended June 30, 2011.

16. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

The following table summarizes the revenue, income from operations, income tax expense, impairment and gain on sale of all discontinued operations for the three and six months ended June 30, 2012 and 2011:


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
Revenue	$	10		$	168		$	47		$	365

Income (loss) from operations of discontinued businesses	$	(1	)	$	(12	)	$	2		$	(22	)
Income tax (expense) benefit		(3	)		3			(5	)		6

Income (loss) from operations of discontinued businesses, net of tax	$	(4	)	$	(9	)	$	(3	)	$	(16	)

Net gain/(loss) on sale and impairments of discontinued operations, net of tax	$	75		$	-		$	70		$	-

During the six months ended June 30, 2012, we completed the sale of the following discontinued operations:

Red Oak — On April 12, 2012, a subsidiary of the Company closed a sale transaction with a newly-formed portfolio company of Energy Capital Partners II, LP for the sale of 100% of its membership interest in AES Red Oak, LLC and AES Sayreville, two wholly-owned subsidiaries that hold the Company’s interest in Red Oak, for $143 million. The Company recognized a pretax gain of $65 million in the second quarter of 2012. Red Oak was reported in the North America Generation segment.

Ironwood — On April 13, 2012, a subsidiary of the Company closed a sale transaction with an indirect wholly-owned subsidiary of PPL Corporation for the sale of 100% of its equity interest in AES Ironwood, Inc., a wholly-owned subsidiary, that holds the Company’s interest in Ironwood for $84 million. The Company recognized a pretax gain of $71 million in the second quarter of 2012. Ironwood was reported in the North America Generation segment.

17. ACQUISITIONS AND DISPOSITIONS

Acquisitions

DPL — On November 28, 2011, AES completed its acquisition of 100% of the common stock of DPL for approximately $3.5 billion, pursuant to the terms and conditions of a definitive agreement (the “Merger Agreement”) dated April 19, 2011.

The preliminary purchase allocation, the adjustment recorded in the current period and the updated purchase price allocation are as follows (in millions):


	Preliminary			Adjustments			Updated
Cash	$	116		$	-		$	116
Accounts receivable		278			-			278
Inventory		124			-			124
Other current assets		41			(1	)		40
Property, plant and equipment		2,549			(114	)		2,435
Intangible assets subject to amortization		166			4			170
Intangible assets — indefinite-lived		5			-			5
Regulatory assets		201			1			202
Other noncurrent assets		58			-			58
Current liabilities		(401	)		-			(401	)
Non-recourse debt		(1,255	)		-			(1,255	)
Deferred taxes		(558	)		39			(519	)
Regulatory liabilities		(117	)		1			(116	)
Other noncurrent liabilities		(195	)		-			(195	)
Redeemable preferred stock		(18	)		-			(18	)

Net identifiable assets acquired		994			(70	)		924
Goodwill		2,489			70			2,559

Net assets acquired	$	3,483		$	-			3,483

The assets acquired and liabilities assumed in the acquisition have been recorded at provisional amounts based on the preliminary purchase price allocation. The Company is in the process of obtaining additional information that could impact the purchase price allocation within the measurement period, which could be up to one year from the date of acquisition: discount rates; energy price curves, dispatching assumptions, and contractual arrangements associated with jointly owned plants, all of which could affect the value of the generation business property, plant and equipment; assumptions around customer switching and aggregation, which could affect the value of intangible assets; assumptions on the valuation of regulatory assets and liabilities; deferred income taxes; and the determination of reporting units. If materially different from the final amounts, such provisional amounts will be retrospectively adjusted to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. Additionally, key input assumptions and their sensitivity to the valuation of assets acquired and liabilities assumed are continuing to be reviewed by management, which may result in requiring additional information related to these key input assumptions. During the three months ended June 30, 2012, the Company recognized a decrease of $114 million in the provisional value of property, plant and equipment and a related decrease of $39 million in the provisionally recognized deferred tax liabilities as a result of additional information associated with growth and ancillary revenue assumptions. Additionally, the Company recognized an increase of $4 million for certain customer contracts of DPL Energy Resource, Inc. (i.e., DPL’s wholly-owned Competitive Retail Electric Service (“CRES”) provider) and other intangibles due to additional contractual information obtained during this quarter. These purchase price adjustments increased the provisionally

recognized goodwill by $70 million and have been reflected retrospectively as of December 31, 2011 in the accompanying Condensed Consolidated Balance Sheet. The effect on net income for the period November 28, 2011 through December 31, 2011 was not material.

The unaudited actual DPL revenue and net income attributable to The AES Corporation included in AES’s Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2012, and the unaudited pro forma revenue and net income attributable to The AES Corporation, of the combined entity for the three and six months ended June 30, 2011, as if the acquisition had occurred January 1, 2011, are as follows:


	Revenue		Net Income (Loss) Attributable to The AES Corporation
	(in millions)
Actual for the three months ended June 30, 2012	$	385	$	5
Actual for the six months ended June 30, 2012		816		27
Pro forma for the three months ended June 30, 2011		4,866		186
Pro forma for the six months ended June 30, 2011		9,489		406

The pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the results of operations that would have been achieved had the acquisition been completed on the dates indicated, or the future consolidated results of operations of AES.

Net income attributable to The AES Corporation in the table above has been reduced by the net of tax pro forma adjustments of $20 million and $68 million, respectively, for the three and six months ended June 30, 2011. These pro forma adjustments primarily include: the amortization of fair value adjustment of DPL’s generation plant and equipment and intangible assets subject to amortization, reversal of transaction costs, interest expense on additional borrowings used to finance the acquisition.

Dispositions

Cartagena — On February 9, 2012, a subsidiary of the Company completed the sale of 80% of its interest in the wholly-owned holding company of AES Energia Cartagena S.R.L. (“AES Cartagena”), a 1,199 MW gas-fired generation business in Spain. The Company owned approximately 70.81% of AES Cartagena through this holding company structure, as well as 100% of a related operations and maintenance company. Net proceeds from the sale were approximately €172 million ($229 million) and during first quarter of 2012, the Company recognized a pretax gain of $178 million on the transaction. Under the terms of the sale agreement, the buyer, Electrabel International Holdings B.V. (“Electrabel”), a subsidiary of GDF SUEZ S.A. or “GDFS”, has an option to purchase the Company’s remaining 20% interest at a fixed price of €28 million ($37 million) during a five month period beginning March 2013. Of the total proceeds received, approximately $9 million was deferred and allocated to Electrabel’s option to purchase the Company’s remaining interest. Concurrent with the sale, GDFS settled the outstanding arbitration between the parties regarding certain emissions costs and other taxes that AES Cartagena sought to recover from GDFS as energy manager under the existing commercial arrangements. GDFS agreed to pay €71 million ($95 million) to AES Cartagena for such costs incurred by AES Cartagena for the 2008—2010 period and for 2011 through the date of sale close, of which €28 million ($38 million) was paid at closing. Due to the Company’s expected continuing ownership interest extending beyond one year from the completion of the sale of its 80% interest, the prior period operating results of AES Cartagena have not been reclassified as discontinued operations.

St. Patrick and InnoVent — On June 28, 2012, the Company closed the sale of its interest in InnoVent and St. Patrick. Net proceeds from the sale transactions were $42 million. The prior period operating results of St. Patrick were not deemed material for reclassification to discontinued operations. See Note 14 — Impairment Expense and Note 15 — Other Non-Operating Expense for further information.

18. EARNINGS PER SHARE

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

The following tables present a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation for income from continuing operations for the three and six months ended June 30, 2012 and 2011. In the table below, income represents the numerator and weighted-average shares represent the denominator:


	Three Months Ended June 30,
	2012						2011
	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	$	69		764	$	0.09	$	191		782	$	0.24
EFFECT OF DILUTIVE SECURITIES
Stock options		-		1		-		-		2		-
Restricted stock units		-		3		-		-		3		-

DILUTED EARNINGS PER SHARE	$	69		768	$	0.09	$	191		787	$	0.24


	Six Months Ended June 30,
	2012						2011
	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	$	414		765	$	0.54	$	428		785	$	0.54
EFFECT OF DILUTIVE SECURITIES
Stock options		-		1		-		-		2		-
Restricted stock units		-		3		-		-		3		(0.01	)

DILUTED EARNINGS PER SHARE	$	414		769	$	0.54	$	428		790	$	0.53

The calculation of diluted earnings per share excluded 6,685,692 and 15,930,917 options outstanding at June 30, 2012 and 2011, 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 of those options exceeded the average market price during the related period.

The calculation of diluted earnings per share excluded 2,444,811 restricted stock units outstanding at June 30, 2012, that could potentially dilute basic earnings per share in the future. Those restricted stock units were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive for June 30, 2012.

For the three and six months ended June 30, 2012 and 2011, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. During the three months ended June 30, 2012, 743,524 shares of common stock were issued upon the exercise of stock options. During the six months ended

June 30, 2012, 1,013,872 shares of common stock were issued under the Company’s profit sharing plan and 1,044,017 shares of common stock were issued upon the exercise of stock options.

19. SUBSEQUENT EVENTS

Stock Repurchase Plan — Subsequent to June 30, 2012, the Company, under its stock repurchase program, repurchased an additional 1,734,000 shares at a cost of $22 million, bringing the cumulative total through August 3, 2012 to 54,403,168 shares at a total cost of $630 million (average price of $11.60 per share including commissions). For additional information on stock repurchases during the quarter, see Note 11 — Equity.

Dividend — On August 1, 2012, the Company’s Board of Directors declared dividend of 4 cents per outstanding share that will be paid in the fourth quarter of 2012.

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

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

The condensed consolidated financial statements included in Item 1. — Financial Statements of this Form 10-Q and the discussions contained herein should be read in conjunction with our 2011 Form 10-K and the June 2012 Form 8-K.

FORWARD-LOOKING INFORMATION

The following discussion may contain forward-looking statements regarding us, our business, prospects and our results of operations that are subject to certain risks and uncertainties posed by many factors and events that could cause our actual business, prospects and results of operations to differ materially from those that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those described in Item 1A. — Risk Factors of our 2011 Form 10-K. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We undertake no obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise of the risks and factors that may affect our business.

Overview of Our Business

We are a global power company. We operate two primary lines of business. The first is our Generation business, where we own and/or operate power plants to generate and sell power to wholesale customers such as utilities, other intermediaries and certain end-users. The second is our Utilities business, where we own and/or operate utilities which distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area and, in certain circumstances, generate and sell electricity on the wholesale market. For the six months ended June 30, 2012, our Generation and Utilities businesses comprised approximately 46% and 54% of our consolidated revenue, respectively.

For additional information regarding our business, see Item 1. — Business of the June 2012 Form 8-K.

Our Organization — The management reporting structure is organized along our two lines of business — Generation and Utilities. These lines of business are further disaggregated geographically for management reporting. Accordingly, management’s discussion and analysis of revenue and gross margin is organized as follows:

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Generation — Latin America;

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Generation — North America;

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Generation — Europe;

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Generation — Asia;

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Utilities — Latin America;

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Utilities — North America;

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Corporate and Other.

As discussed in Item 1. — Financial Statements — Note 12 — Segments of this Form 10-Q, based on application of the segment accounting guidance, Tietê is reported as a separate segment for purposes of the required segment accounting disclosures, but is included in Generation — Latin America within the discussion of operating results for revenue and gross margin in management’s discussion and analysis as is it managed with the other Latin American generation businesses.

Components of Revenue and Cost of Sales — Revenue includes revenue earned from the sale of energy from our utilities and the production of energy from our generation plants. Revenue also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the sale of electricity. Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, depreciation and amortization expense, operations and maintenance costs, bad debt expense and recoveries, general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.

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

One of the key factors which affect our Generation business is our ability to enter into contracts for the sale of electricity and the purchase of fuel used to produce that electricity. Long-term contracts are intended to reduce the exposure to volatility associated with fuel prices in the market and the price of electricity by fixing the revenue and costs for these businesses. The majority of the electricity produced by our Generation businesses is sold under long-term contracts, or PPAs, to wholesale customers. In turn, most of these businesses enter into long-term fuel supply contracts or fuel tolling arrangements where the customer assumes full responsibility for purchasing and supplying the fuel to the power plant. While these long-term contractual agreements reduce exposure to volatility in the market price for electricity and fuel, the predictability of operating results and cash flows vary by business based on the extent to which a facility’s generation capacity and fuel requirements are contracted and the negotiated terms of these agreements. Entering into these contracts exposes us to counterparty credit risk. For further discussion of these risks, see “Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks.” in Item 1A. — Risk Factors of the 2011 Form 10-K.

When fuel costs increase, many of our businesses are able to pass these costs on to their customers. Generation businesses with long-term contracts in place do this by including fuel pass-through or fuel indexing

arrangements in their contracts. Utilities businesses can pass costs on to their customers through increases in current or future tariff rates. Therefore, in a rising fuel cost environment, the increased fuel costs for these businesses often result in an increase in revenue to the extent these costs can be passed through (though not necessarily on a one-for-one basis). Conversely, in a declining fuel cost environment, the decreased fuel costs can result in a decrease in revenue. Increases or decreases in revenue at these businesses that have the ability to pass through costs to the customer have a corresponding impact on cost of sales, to the extent the costs can be passed through, resulting in a limited impact on gross margin, if any. Similarly, some of our businesses are able to pass through to customers, certain other costs, such as: environmental compliance costs, transmission costs, regional transmission organization costs and energy efficiency or demand side management program costs. Although these circumstances may not have a large impact on gross margin, they can significantly affect gross margin as a percentage of revenue. As a result, gross margin as a percentage of revenue is a less relevant measure when evaluating our operating performance. To the extent our businesses are unable to pass through fuel cost increases to their customers, gross margin may be adversely affected.

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

We also attempt to limit risk by hedging much of our interest rate and commodity risk, and by matching the currency of most of our subsidiary debt to the revenue of the underlying business. However, we only hedge a portion of our currency and commodity risks, and our businesses are still subject to these risks, as further described in Item 1A. — Risk Factors of the 2011 Form 10-K, “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.” Commodity and power price volatility could continue to impact our financial metrics to the extent this volatility is not hedged. For a discussion of our sensitivities to commodity, currency and interest rate risk, see Item 3. — Quantitative and Qualitative Disclosures About Market Risk of this Form 10-Q.

Due to our global presence, the Company has significant exposure to foreign currency fluctuations. The exposure is primarily associated with the impact of the translation of our foreign subsidiaries’ operating results from their local currency to U.S. dollars that is required for the preparation of our consolidated financial statements. Additionally, there is a risk of transaction exposure when an entity enters into transactions, including debt agreements, in currencies other than their functional currency. These risks are further described in Item 1A. — Risk Factors of the 2011 Form 10-K, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.” In the three months ended June 30, 2012, changes in foreign currency exchange rates have had a significant impact on our operating results. If the current foreign currency exchange rate volatility continues, our gross margin and other financial metrics will continue to be affected.

Another key driver of our results is our ability to bring new businesses into commercial operations successfully and to integrate acquisitions. We currently have approximately 2,200 MW of projects under construction in six countries. Our prospects for increased operating results and cash flows are dependent upon successful completion of these projects on time and within budget. However, as disclosed in Item 1A. — Risk Factors of the 2011 Form 10-K, “Our business is subject to substantial development uncertainties,” construction is subject to a number of risks, including risks associated with site identification, financing and permitting and our ability to meet construction deadlines. Delays or the inability to complete projects and commence

commercial operations can result in increased costs, impairment of assets and other challenges involving partners and counterparties to our construction agreements, PPAs and other agreements. Similarly, failure to integrate acquisitions and manage market risk, including the Company’s recent acquisition of DPL, could impact our future operating results as disclosed in Item 1A. — Risk Factors of the 2011 Form 10-K, “We may fail to realize the anticipated benefits and cost savings of the acquisition, which could adversely affect the value of the Company’s common stock or result in goodwill impairment” and Key Trends and Uncertainties – Goodwill, below.

Our gross margin is also impacted by the fact that in each country in which we conduct business, we are subject to extensive and complex governmental regulations such as regulations governing the generation and distribution of electricity, and environmental regulations which affect most aspects of our business. Regulations differ on a country by country basis (and even at the state and local municipality levels) and are based upon the type of business we operate in a particular country, and affect many aspects of our operations and development projects. Our ability to negotiate tariffs, enter into long-term contracts, pass through costs related to capital expenditures and otherwise navigate these regulations can have an impact on our revenue, costs and gross margin. Environmental and land use regulations, including existing and proposed regulation of greenhouse gas (“GHG”) emissions, could substantially increase our capital expenditures or other compliance costs, which could in turn have a material adverse effect on our business and results of operations. For a further discussion of the regulatory environment, see Item 1. — Business — Regulatory Matters and Item 1A. — Risk Factors — Risks Associated with Governmental Regulation and Laws of the 2011 Form 10-K.

Management’s Priorities

Management is focused on the following priorities:

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Execution of our geographic concentration strategy to maximize shareholder value through disciplined capital allocation including:

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platform expansion in Brazil, Chile and the United States,

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platform development in select markets, including: Turkey, Poland, Colombia, India, the Philippines, the United Kingdom and the Dominican Republic,

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corporate debt reduction, and

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a return of capital to shareholders, including share repurchases and payment of dividends;

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Prudently exiting select non-strategic markets;

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Optimizing profitability of operations in the existing portfolio;

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Realizing cost savings through the alignment of overhead costs with business requirements, systems automation and optimal allocation of business development spending under our two business lines: Generation and Utilities;

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Completion of an approximately 2,200 MW construction program and the integration of new projects into existing businesses; and

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Integration of new projects. The following projects commenced commercial operations during the three months ended June 30, 2012:

Project

Location

Fuel

Gross MW

AES Equity Interest
(Percent, Rounded)

AES Solar⁽¹⁾

Various

Solar

⁽¹⁾	AES Solar Energy Ltd. is a joint venture with Riverstone Holdings and is accounted for as an equity method investment. Plants that came on-line during the quarter include: Fox, Geran, Montan, Okean, Renar, Vilo, Castelnau, Uglas, Electrismos, Patan, Cangiano and Santa Maria.

Key Trends and Uncertainties

We continue to face many risks as discussed in Item 1A. — Risk Factors of the 2011 Form 10-K. Some of these challenges are also described below in “Key Drivers of Results in the Three Months Ended June 30, 2012”. We continue to monitor our operations and address challenges as they arise.

Operations

On March 30, 2012, DP&L, our regulated utility in Ohio, filed with the Public Utilities Commission of Ohio (“PUCO”) for approval of its next Standard Service Offer to replace the existing Electric Security Plan that expires on December 31, 2012. The filing requested approval of a five-year and five month Market Rate Option, which will be effective January 1, 2013, and would phase in market rates over this period. The PUCO is currently reviewing the filing and no decision has been made. The outcome of the proceeding is uncertain and could have a material impact on our results. See Item 1 — Business — Regulatory Matters — United States — The Dayton Power and Light Company included in the 2011 Form 10-K for further information. In addition, as further described in “Key Trends and Uncertainties — Impairments” below, if we are unable to realize the benefits associated with the goodwill recorded in connection with the acquisition of DPL, there is a risk that we may have to impair the goodwill we recorded in connection with the DPL acquisition. In addition to the regulatory risks noted above, DPL also faces a number of additional uncertainties related to the impact of customer switching and low power prices which could impact DPL’s results of operations, its ability to refinance certain debt (or to do so on favorable terms) which is due in the near to intermediate term, and/or realize the benefits associated with the goodwill. Any of the above-referenced conditions, events or factors could have a material impact on the Company or its results of operations.

On April 2, 2012, Eletropaulo received an infraction notice from the Brazilian energy regulator, the “Regulator” relating to the financial audit of its fixed assets, which occurred from December 2010 to February 2011. The notice alleges non-conformities in the regulatory accounting applied by Eletropaulo to the fixed assets, which impact the regulatory asset base used by the Regulator to calculate the tariff charged to customers. Management has filed an appeal to the Regulator contesting the non-conformities and fine imposed, and is awaiting the Regulator’s response. Management believes that there is a reasonable possibility of loss for certain issues listed in the infraction notice. As of June 30, 2012, a contingent liability has been recognized for the amount of the probable loss.

In August 2010, the Esti power plant, a 120 MW run-of-river hydroelectric power plant in Panama, was taken offline due to damage to its tunnel infrastructure. The repairs of the Esti power plant were completed and the plant resumed operations in June 2012.

Global Economic Considerations

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

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

The Company could be adversely affected if general economic or political conditions in the markets where our subsidiaries operate deteriorate, resulting in a reduction in cash flow from operations, a reduction in the availability and/or an increase in the cost of capital, or if the value of our assets remains depressed or declines further. Any of the foregoing events or a combination thereof could have a material impact on the Company, its results of operations, liquidity, financial covenants, and/or its credit rating.

Our subsidiaries are subject to credit risk, which includes risk related to the ability of counterparties (such as parties to our PPAs, fuel supply agreements, hedging agreements and other contractual arrangements) to deliver contracted commodities or services at the contracted price or to satisfy their financial or other contractual obligations. The Company has not suffered any material effects related to its counterparties during the three or six months ended June 30, 2012. However, if macroeconomic conditions impact our counterparties, they may be unable to meet their commitments which could result in the loss of favorable contractual positions, which could have a material impact on our business.

Euro Zone Debt Crisis — During the past few years, certain European Union countries have continually faced a sovereign debt crisis and it is possible that this crisis could spread to other countries. This crisis has resulted in an increased risk of default by governments and the implementation of austerity measures in certain countries. If the crisis continues, worsens, or spreads, there could be a material adverse impact on the Company. Our businesses may be impacted if they are unable to access the capital markets, face increased taxes or labor costs, or if governments fail to fulfill their obligations to us or adopt austerity measures which adversely impact our projects. At June 30, 2012, the Company had unfunded commitments from European banks for our corporate revolver and for certain project finance debt totaling $225 million and $716 million, respectively. Approximately 9% of the non-recourse debt held by subsidiaries was denominated in Euros and 14% of our variable rate debt was indexed to Euribor at June 30, 2012. In addition, as discussed in Item 1A. — Risk Factors — Our renewable energy projects and other initiatives face considerable uncertainties including development, operational and regulatory challenges of the 2011 Form 10-K, our renewables businesses are dependent on favorable regulatory incentives, including subsidies, which are provided by sovereign governments, including European governments. If these subsidies or other incentives are reduced or repealed, or sovereign governments are unable or unwilling to fulfill their commitments or maintain favorable regulatory incentives for renewables, in whole or in part, this could impact the ability of the affected businesses to continue to sustain and/or grow their operations and could result in losses or asset impairments for these businesses which could be material. For example, in 2011, tariffs for certain of our European solar businesses were reduced, and could be reduced further. The carrying value of the Company’s investment in AES Solar Energy Ltd., whose primary operations are in Europe, was $220 million at June 30, 2012. In addition, any of the foregoing could also impact contractual counterparties of our subsidiaries in core power or renewables. If such counterparties are adversely impacted, then they may be unable to meet their commitments to our subsidiaries. For example, our investments in Bulgaria rely on offtaker contracts with NEK, the state-owned national electricity distribution company. The Company has long-lived assets in Bulgaria of $1.7 billion, including receivables from NEK of $112 million. While we believe that our businesses in Bulgaria will be able to collect these receivables, there can be no assurance that the business will succeed in making these collections, which could result in a write-off of the receivables. In addition, depending on NEK’s ability to honor its obligations and other factors, the value of other assets could also be impaired, or the business may be in default of its loan covenants. Any of the above could have a material impact on our results of operations. For further information on the importance of long-term contracts and our counterparty credit risk, see Item 1A. — Risk Factors — ”We may not be able to enter into long-term contracts, which reduce volatility in

our results of operations…” of the 2011 Form 10-K. As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses and have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.

Argentina — In Argentina, potential deteriorating economic indicators such as falling commodity prices on exports, increased inflation, devaluation of the local currency, currency liquidity and large government deficits could cause significant volatility in our results of operations, cash flows, the ability to pay dividends, and the value of our assets. At June 30, 2012, AES’s long-lived assets and long-term receivables in Argentina were $562 million. In addition, recent actions by the Argentine government may indicate deeper government intervention in the local economy. For example, on April 16, 2012, the Argentine government expropriated 51% of the assets of the country’s largest oil company. The statute used to expropriate the oil company is not applicable to our businesses in Argentina. However, potential deteriorating economic conditions or further government action could have a material impact on the Company or its financial statements.

United States — As noted in Item 1A — Risk Factors — ”We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” of the 2011 Form 10-K and Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk of this Form 10-Q, the Company’s North American businesses continue to face pressure as a result of high coal prices relative to natural gas. This has affected the results of certain of our coal-fired plants in the region, including our coal-fired generating assets within our utility businesses where retail competition exists and those businesses that have a PPA in place, but purchase fuel at market prices or under short term contracts. The coal-fired generating assets within both IPL and DPL have experienced reduced output associated with the decline in coal price relative competitiveness in their merit order dispatch. In 2011, Eastern Energy, our coal-fired plants in New York, filed for bankruptcy and is no longer in our portfolio of businesses. In connection with the Eastern Energy bankruptcy filing, it is possible that creditors may attempt to bring claims against Eastern Energy and/or directly against The AES Corporation. While we believe Eastern Energy and The AES Corporation would have meritorious defenses against any such claims, there can be no assurance that Eastern Energy or The AES Corporation would prevail in such claims. In 2011, AES Deepwater was idled to mitigate operating risks caused by high fuel costs and other competitive pressures. Although the Deepwater unit was restarted during the second quarter of 2012 to capture potential summer price volatility, the long-term economic viability of the business is uncertain. Our coal-fired business in Hawaii faces uncertainty beyond 2012 when the fuel price supporting the PPA is no longer fixed. If the conditions described above continue or worsen, our North American businesses with market exposure may need to restructure their obligations or seek additional funding (including from the Parent) or face the possibility that they may be unable to meet their obligations and continue operations, which could result in the loss of earnings or cash flow or result in a write down in the value of these assets, any of which could have a material impact on the Company. For further discussion of the risks associated with commodity prices, see Item 1A. — Risk Factors “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” of the 2011 Form 10-K.

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

Impairments

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

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

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

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

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

Kelanitissa — We continue to evaluate the recoverability of our long-lived assets at Kelanitissa, our diesel-fired generation plant in Sri Lanka, as a result of both the requirement to transfer the plant to the government at the end of our PPA and the current expectation of lower future operating cash flows. These evaluations resulted in the recognition of asset impairment expense of $42 million in 2011 and an additional $12 million during the first half of 2012. As of June 30, 2012, the estimated fair value of the long-lived assets was $10 million. Kelanitissa is a Build-Operate-Transfer (“BOT”) generation facility and payments under its PPA are scheduled to decline over the PPA term. It is likely that further impairment charges will be required in 2012 as Kelanitissa gets closer to the BOT date.

Goodwill — The Company seeks business acquisitions as one of its growth strategies. We have achieved significant growth in the past as a result of several business acquisitions, which also resulted in the recognition of goodwill. As noted in Item 1A. — Risk Factors of the 2011 Form 10-K, there is always a risk that “Our acquisitions may not perform as expected.” One of the primary factors contributing to goodwill is the synergies expected from an acquisition that follow the integration of the acquired business with the existing operations of an entity. Thus, an entity’s ability to realize benefits of goodwill depends on the successful integration of the acquired business. If such integration efforts are not successful, it could be difficult to realize the benefits of goodwill, which could result in impairment of goodwill. As described in Note 17 — Acquisitions and Dispositions included in Item 1. — Financial Statements of this Form 10-Q, the Company completed the acquisition of DPL on November 28, 2011, which resulted in the provisional recognition of $2.6 billion of goodwill. The Company’s ability to realize the benefit of DPL’s goodwill will depend on our ability to realize the expected operating synergies and manage the market risks of DPL as further described in Item 1A. — Risk Factors of the 2011 Form 10-K “We may fail to realize the anticipated benefits and cost savings of the acquisition, which could adversely affect the value of the Company’s common stock or result in goodwill impairment.” Additionally, utilities in Ohio continue to face downward pressure on operating margins due to the evolving regulatory environment, which is moving towards a market-based competitive pricing mechanism. At the same time, the declining energy prices are also reducing operating margins across the utility industry. These competitive forces could adversely impact the future operating performance of DPL and may result in impairment of its goodwill.

The value of goodwill is also positively correlated with the economic environments in which our acquired businesses operate and a severe economic downturn could negatively impact the value of goodwill. Also, the evolving environmental regulations, including GHG regulations, around the world continue to increase the operating costs of our generation businesses. In extreme situations, environmental regulations could even make a once profitable business uneconomical. In addition, most of our generation businesses have a finite life and as the acquired businesses reach the end of their finite lives, the carrying amount of goodwill is gradually realized

through their periodic operating results. The accounting guidance, however, prohibits the systematic amortization of goodwill and rather requires an annual impairment evaluation. Thus, as some of our acquired businesses approach the end of their finite lives, they may incur goodwill impairment charges even if there are no discrete adverse changes in the economic environment. For example, Ebute, our 294 MW gas-fired plant in Nigeria, currently operates under a 15 year PPA with the Nigerian national electricity distribution company that expires in 2016. The inability to replace the PPA on similar terms or identify alternate uses for the plant could adversely affect the carrying amount of Ebute’s goodwill, which could be material. The carrying amount of the goodwill at June 30, 2012 was approximately $58 million.

In the fourth quarter of 2011, the Company completed its annual goodwill impairment evaluation and did not have any reporting units that were considered “at risk”. A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. While there were no potential impairment indicators at that time that could result in the recognition of goodwill impairment at our reporting units, it is possible we may incur goodwill impairment at our reporting units in future periods if any of the following events occur: a deterioration in general economic conditions (e.g., a recession), or the environment in which a business operates; an increased competitive environment (e.g., a new plant in the grid); a change in the market for a business’ products or services or a regulatory or political development (e.g., changing environmental regulations on coal consumption and water intake); increases in raw materials, labor, or other costs that have a negative effect on earnings (e.g., where a business cannot pass through the increase in input costs); negative or declining cash flows or a decline in actual or planned revenue or earnings (e.g., where recent results have been worse than previously expected); a more-likely-than-not expectation of selling or disposing all, or a portion of, a reporting unit; the testing for recoverability of a significant asset group within a reporting unit; or a business reaches the end of its finite life.

Regulatory — Environment. The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts), and certain air emissions, such as SO₂, NO_x, particulate matter and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A. — Risk Factors, “Our businesses are subject to stringent environmental laws and regulations,” “Our businesses are subject to enforcement initiatives from environmental regulatory agencies,” and “Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows” set forth in the Company’s Form 10-K for the year ended December 31, 2011. Also, for further information about environmental laws and regulations impacting the company, see Item 1. Business — Regulatory Matters — Environmental and Land Use Regulations set forth in the Company’s Form 10-K for the year ended December 31, 2011.

Legislation and Regulation of GHG Emissions

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

Potential U.S. Federal GHG Legislation Federal legislation passed the United States House of Representatives in 2009 that, if adopted, would have imposed a nationwide cap-and-trade program to reduce GHG emissions. This legislation was never signed into law, and is no longer under consideration. In the U.S. Senate, several different draft bills pertaining to GHG legislation have been considered, including comprehensive GHG legislation similar to the legislation that passed the U.S. House of Representatives and more limited legislation focusing only on the utility and electric generation industry. Although it is unlikely that any legislation pertaining to GHG emissions will be voted on and passed by the U.S. Senate and House of Representatives in 2012, it is uncertain if any such legislation will be voted on and passed by the U.S. Congress in subsequent years. If any such legislation is enacted into law, the impact could be material to the Company.

EPA GHG Regulation The EPA made a finding that GHG emissions from mobile sources represent an “endangerment” to human health and the environment (the “Endangerment Finding”) following the Supreme Court’s decision in Massachusetts v. EPA, that the EPA has the authority under the CAA to regulate GHG emissions. The EPA then subsequently promulgated regulations governing GHG emissions from automobiles under the CAA (“Motor Vehicle Rule”). The effect of the EPA’s regulation of GHG emissions from mobile sources is that certain provisions of the CAA will also apply to GHG emissions from existing stationary sources, including many United States power plants. In particular, since January 2, 2011, owners or operators who plan construction of new stationary sources and/or modifications to existing stationary sources, which would result in a significant increase in GHG emissions, are required to obtain prevention of significant deterioration (“PSD”) permits prior to commencement of construction. In addition, major sources of GHG emissions may be required to amend, or obtain new, Title V air permits under the CAA to reflect any new applicable GHG emissions requirements for new construction or for modifications to existing facilities.

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

In December 2010, the EPA entered into a settlement agreement with several states and environmental groups to resolve a petition for review challenging the EPA’s new source performance standards (“NSPS”) rulemaking for electric utility steam generating units (“EUSGUs”) based on the NSPS’s failure to address GHG emissions. Under the settlement agreement, the EPA committed to propose GHG emissions standards for EUSGUs and on March 27, 2012, the EPA proposed a rule that would establish NSPS for CO₂ emissions for new fossil-fueled EUSGUs larger than 25 megawatts (“MW”). The proposed rule would not apply to modified or existing EUSGUs, including the Company’s subsidiaries existing power plants. The EPA may separately issue emissions guidelines for modified or existing EUSGUs at a later date. The proposed rule was published in the Federal Register on April 13, 2012, and the period for public comments expired on June 12, 2012. The EPA will consider the public comments before promulgating a final rule by the end of 2012.

A consortium of industry petitioners challenged the Endangerment Finding, Tailoring Rule and the Motor Vehicle Rule in the United States Court of Appeals for the District of Columbia Circuit. These challenges were consolidated and on June 26, 2012, the D.C. Circuit issued an order rejecting challenges to the EPA’s authority to regulate GHGs from stationary sources and upholding the Endangerment Finding, the Tailoring Rule and the Motor Vehicle Rule. Following this decision, the PSD and Title V permitting requirements for electric generating units established by these rules will remain in place.

International GHG Regulation On February 16, 2005, the Kyoto Protocol became effective. The Kyoto Protocol requires the industrialized countries that have ratified it to significantly reduce their GHG emissions, including CO₂. The vast majority of developing countries which have ratified the Kyoto Protocol have no GHG reduction requirements, including many of the countries in which the Company’s subsidiaries operate. Of the 27 countries in which the Company’s subsidiaries currently operate, all but one — the United States (including Puerto Rico) — have ratified the Kyoto Protocol. The first commitment period under the Kyoto Protocol is currently expected to expire at the end of 2012, and countries have been unable to agree on any legally binding second commitment period or successor agreement to the Kyoto Protocol, but most of the original signatories to the Kyoto Protocol have agreed to extend their GHG emissions reduction commitments under the Kyoto Protocol by at least five years and countries have agreed to continue to work toward a successor international agreement on GHG emissions reductions by 2015. The next annual United Nations conference of the parties to the Kyoto Protocol (“COP 18”) will be held in Doha, Qatar from November 26 through December 7, 2012 to focus on establishing a second commitment period under the Kyoto Protocol or an international agreement or framework to succeed the Kyoto Protocol.

There is substantial uncertainty with respect to whether U.S. federal GHG legislation will be enacted into law, whether new country-specific GHG legislation will be adopted in countries in which our subsidiaries conduct business, and whether a successor commitment period under the Kyoto Protocol or a new international agreement to succeed the Kyoto Protocol will be reached. There is additional uncertainty regarding the final provisions or implementation of any potential U.S. federal or foreign country GHG legislation, future EPA rules regulating GHG emissions and any successor commitment period under the Kyoto Protocol or international agreement to succeed the Kyoto Protocol. In light of these uncertainties, the Company cannot accurately predict the impact on its consolidated results of operations or financial condition from potential U.S. federal or foreign country GHG legislation, EPA regulation of GHG emissions or any successor commitment period under the Kyoto Protocol or new international agreement on such emissions, or make a reasonable estimate of the potential costs to the Company associated with any such legislation, future regulation or international agreement; however, the impact from any such legislation, future regulation or international agreement could have a material adverse effect on certain of our U.S. or international subsidiaries and on the Company and its consolidated results of operations.

Other U.S. Air Emissions Regulations and Legislation

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

The EPA is obligated under Section 112 of the CAA to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, hydrogen chloride, hydrogen fluoride, and nickel species from coal and oil-fired power plants. In connection with such rule, the CAA requires the EPA to establish Maximum Achievable Control Technology (“MACT”). MACT is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. Pursuant to Section 112 of the CAA, the EPA promulgated a final rule on December 16, 2011, called the Mercury Air Toxics Standards (“MATS” or the “Utility MACT”) establishing national emissions standards for hazardous air pollutants (“NESHAP”) from coal and oil-fired electric utility steam generating units. These emission standards reflect the EPA’s application of Utility MACT standards for each pollutant regulated under the rule. The rule requires all coal-fired power plants to comply with the applicable Utility MACT standards within three years, with the possibility of obtaining an additional year, if

needed, to complete the installation of necessary controls. To comply with the rule, many coal-fired power plants may need to install additional control technology to control acid gases, mercury or particulate matter, or they may need to repower with an alternate fuel or retire operations. Most of the Company’s U.S. coal-fired plants operated by its subsidiaries have acid gas scrubbers or comparable control technologies, but there are other improvements to such control technologies that may be needed at some of the Company’s plants to assure compliance with the Utility MACT standards. Older coal-fired facilities that do not currently have a SO₂ scrubber installed are particularly at risk.

On July 15, 2011, Duke Energy, co-owner with DP&L at the Beckjord Unit 6 facility, a 414 MW power plant, filed their Long-term Forecast Report with the Public Utilities Commission of Ohio (“PUCO”). The report indicated that Duke Energy plans to cease production at the Beckjord Station, including the jointly-owned Unit 6, in December 2014. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. With respect to DP&L’s Hutchings Station, a six unit coal-fired power plant with 365MW of total capacity, DP&L has notified PJM that it intends to deactivate Hutchings Station’s Units 1 and 2 by 2015 and that Unit 4, currently out of service due to equipment failure, would not be available for service any time earlier than 2014. The decision to deactivate Units 1 and 2 has been made because these two units are not equipped with the advanced environmental control technologies needed to comply with the MACT standards and the cost of compliance with the MACT standards or conversion to natural gas for these units would likely exceed the expected return. DP&L is still studying the option of converting two or more Hutchings Station’s Units 3-6 to natural gas in order to comply with environmental requirements.

The combination of existing and expected environmental regulations, including the Utility MACT, make it likely that IPL will temporarily or permanently retire several of its existing, primarily coal-fired, smaller and older generating units within the next several years. These units are not equipped with the advanced environmental control technologies needed to comply with existing and expected regulations, and collectively make up less than 15% of IPL’s net electricity generation over the past five years. IPL is continuing to evaluate options for replacing this generation. In addition IPL is currently reviewing the impact of the new Utility MACT on its base load generating units and estimates total additional capital expenditures for IPL related to this rule and other environmental regulations and rules, such as the Cross-State Air Pollution Rule and rules or regulations pertaining to coal combustion byproducts and cooling water intake structures, to be approximately $500 million to $700 million over the next several years. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions or other operating or capital expenditures to comply with these rules and regulations; however, there can be no assurances that IPL would be successful in that regard.

Several lawsuits challenging the Utility MACT rule have been filed and consolidated into a single proceeding before the United States Court of Appeals for the District of Columbia Circuit. On June 28, 2012, the D.C. Circuit issued an order granting a motion to sever and expedite challenges to emissions standards for new units under the Utility MACT, with oral argument to be scheduled after September 27, 2012. On July 20, 2012, the EPA announced its decision to stay the standards under the Utility MACT rule with respect to new sources for approximately 3 months, so that the EPA may reconsider those standards. The EPA filed a motion asking the D.C. Circuit to hold the litigation challenging these standards in abeyance during this three month period. We cannot predict the outcome of this litigation. The aggregate capital costs, other expenditures or operational restrictions necessary to comply with the rule cannot be specified at this time. The Company anticipates that the rule may have a material impact on the Company’s business, financial condition and results of operations.

The EPA promulgated the “Clean Air Interstate Rule” (“CAIR”) on March 10, 2005, which required allowance surrender for SO₂ and NO_x emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR contemplated two implementation phases. The first phase was to begin in 2009 and 2010 for NO_x and SO₂, respectively. A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015. To implement the required emission reductions for this rule, the states were to establish emission allowance based “cap-and-trade” programs. CAIR was subsequently challenged in federal

court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the EPA.

In response to the D.C. Circuit’s opinion, on July 7, 2011, the EPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, the CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered sources, such as power plants, in many states in which subsidiaries of the Company operate. Once fully implemented in 2014, the rule would require additional SO₂ emission reductions of 73% and additional NO_x reductions of 54% from 2005 levels. The CSAPR will be implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of new emissions allowances that the EPA will create. The CSAPR contemplates limited interstate and intra-state trading of emissions allowances by covered sources. Initially, at least through 2012, the EPA will issue emissions allowances to affected power plants based on state emissions budgets established by the EPA under the CSAPR. The future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time. The CSAPR was published in the Federal Register on August 8, 2011, and on October 6, 2011, the EPA proposed some technical revisions to the CSAPR, including allowing for additional allowances for certain states.

Many states, utilities and other affected parties filed petitions for review, challenging the CSAPR before the U.S. Court of Appeals for the District of Columbia. A large subset of the Petitioners also sought a stay of the CSAPR. On December 30, 2011, the D.C. Circuit granted a stay of the CSAPR and directed the EPA to continue administering CAIR. Oral argument on these issues was heard on April 13, 2012 and a decision is expected by late summer or early fall. We cannot predict the outcome of this litigation, including whether the stay will be lifted and whether the CSAPR will be ultimately implemented in its current form or a modified form. To comply with the CSAPR as currently proposed, additional pollution control technology may be required by some of our subsidiaries, and the cost of implementing any such technology could affect the financial condition or results of operations of these subsidiaries or the Company. Additionally, compliance with the CSAPR could require the purchase of newly issued allowances, the switch to higher priced, lower sulfur coal, and changes in the dispatch of our facilities or the retirement of existing generating units. While the capital costs, other expenditures or operational restrictions necessary to comply with the CSAPR cannot be specified at this time, and the ultimate outcome of litigation pertaining to the CSAPR is uncertain, the Company anticipates that the CSAPR may have a material impact on the Company’s business, financial condition and results of operations.

The new source review (“NSR”) requirements under the CAA impose certain requirements on major emission sources, such as electric generating stations, if changes are made to the sources that result in a significant increase in air emissions. Certain projects, including power plant modifications, are excluded from these NSR requirements, if they meet the routine maintenance, repair and replacement (“RMRR”) exclusion of the CAA. There is ongoing uncertainty, and significant litigation, regarding which projects fall within the RMRR exclusion. The EPA has pursued a coordinated compliance and enforcement strategy to address NSR compliance issues at the nation’s coal-fired power plants. The strategy has included both the filing of suits against power plant owners and the issuance of Notices of Violation (“NOVs”) to a number of power plant owners alleging NSR violations. See Item 1. — Legal Proceedings in this Form 10-Q for more detail with respect to environmental litigation and regulatory action, including a NOV issued by the EPA against IPL concerning NSR and prevention of significant deterioration issues under the United States Clean Air Act.

During the last decade, DP&L’s Stuart Station and Hutchings Station have received NOVs from the EPA alleging that certain activities undertaken in the past are outside the scope of the RMRR exclusion. Additionally, generation units partially owned by DP&L but operated by other utilities have received such NOVs relating to equipment repairs or replacements alleged to be outside the RMRR exclusion. The NOVs issued to DP&L operated plants have not been pursued through litigation by the EPA.

If NSR requirements were imposed on any of the power plants owned by subsidiaries of the Company, the results could have a material impact on the Company’s business, financial condition and results of operations. In

connection with the imposition of any such NSR requirements on our U.S. utilities, DP&L and IPL, the utilities would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that they would be successful in that regard.

U.S. Clean Water Act §316(b)

As disclosed in the Company’s form 10-K for the year ended December 31, 2011, the Company faces a proposed rule under U.S. Clean Water Act Section 316(b), pursuant to which certain cooling water intake structures at subsidiaries such as AES Southland may require modifications or upgrades. The proposal would also require comprehensive site-specific studies during the permitting process and may require closed-cycle cooling systems in order to meet the rule’s standards. On July 17, 2012, the EPA announced that it would delay issuance of the final rule until no later than June 27, 2013.

Other Regulatory Matters

In July 2012, the Indiana Utility Regulatory Commission (“IURC”) issued its final order in the tree trimming practices rulemaking, which is expected to become law upon approval by the Governor of Indiana. IPL is implementing procedures to ensure it appropriately complies with the requirements of the new rule that addresses notification, dispute resolution and other activities associated with its vegetation management practices. We are unable to predict costs to comply with this new rule. The requirements of the new ruling are similar to current practices. The cost impact of the rule will not be known until IPL has experience operating under its terms.

In its 2011 Form 10-K, the Company disclosed a dispute between AES Tisza (an AES subsidiary in Hungary) and related entities (collectively, “AES Tisza”) concerning the reintroduction of the administrative pricing for Hungarian electricity generators. As noted in the Form 10-K, the arbitration panel who heard the case issued its final determination in 2010, pursuant to which AES’ Tisza’s claim was dismissed. AES Tisza subsequently challenged the panel’s decision and requested the annulment thereof. In July of 2012, the request for annulment was denied.

In its Form 10-K for the year ended December 31, 2011, the Company disclosed that AES Sul filed a lawsuit against ANEEL (Brazilian regulator) related to ANEEL Order 288, issued in May of 2002, which retroactively changed rules regarding the sale of energy in the spot market and required CCEE (Chamber of Electric Energy Commercialization) to cancel the AES Sul’s gains in the settlements occurred between 2000-2002. The amount at issue is approximately $90 million and it is reserved. In the lawsuit, AES Sul challenged ANEEL Order 288 as illegal. In June of 2012, the first instance court rejected AES Sul’s argument and found that Order 288 is legal. AES Sul sought and received an order staying the court’s decision, pending an appeal by AES Sul. However, there can be no assurance that AES Sul will be successful on appeal.

Key Drivers of Results in the Three Months Ended June 30, 2012

During the three months ended June 30, 2012, the Company’s gross margin decreased $300 million, net income attributable to The AES Corporation decreased $34 million and net cash from operating activities decreased $95 million compared to the same period in 2011.

During the three months ended June 30, 2012, the Company experienced a decrease in operating results primarily due to unfavorable impact of foreign currency, lower contract prices and an unfavorable adjustment to regulatory liabilities at Eletropaulo related to the finalization of the July 2011 tariff reset as further discussed below. Results were also impacted by lower plant availability at Gener in Chile. These unfavorable results were partially offset by new businesses including the impact of DPL in the United States, which was acquired in November 2011, and Angamos in Chile, Maritza in Bulgaria and Changuinola in Panama, which commenced commercial operations in April, June and October 2011, respectively.

Eletropaulo, our utility business in Brazil, was billing its customers under the pre-existing tariff from July 2011 to June 2012 as required by the Regulator. In July 2012, the Regulator approved the periodic review and reset of a component of Eletropaulo’s regulated tariff which determines the margin to be earned by Eletropaulo. This resulted in a $221 million reduction to revenue during the three months ended June 30, 2012. The impact to the Company after taxes and noncontrolling interest was $23 million. The review and reset of this tariff component is retroactive to July 2011 and will be applied to customers’ invoices from July 2012 to June 2015. As the new tariff rate is lower than the pre-existing tariff rate, Eletropaulo is required to reduce customer tariffs for this difference over the next three years. Accordingly, since the third quarter of 2011, Eletropaulo has been recognizing a regulatory liability for such estimated future refunds and updating this estimate as the periodic review and tariff reset process has progressed with the Regulator. As of June 30, 2012, Eletropaulo had recognized a regulatory liability of $536 million. This includes a cumulative increase of $80 million relating to the estimated regulatory liability recognized in the second half of 2011 and the first quarter of 2012 based on the latest information available.

For the remainder of 2012, we expect to face continued challenges at certain of our businesses:

•

The Company will continue to see the adverse effects of relatively lower gas prices in the United States and a decline in power prices relative to coal. See Item 3. — Quantitative and Qualitative Disclosures About Market Risk of this Form 10-Q for more information.

•

The Company faces uncertainty over the U.S. taxation of earnings from its foreign subsidiaries following the expiration of a favorable tax provision in 2011 and its effective tax rate may increase, if such provision is not renewed.

•

The Company is sensitive to changes in foreign exchange rates and could experience adverse effects of a devaluation of currencies where our businesses operate. See Item 3 — Quantitative and Qualitative Disclosures about Market Risk of this Form 10-Q for more information.

Additional items that could impact our 2012 results are discussed in Key Trends and Uncertainties above, along with the risk factors included in Item 1A. — Risk Factors of the 2011 Form 10-K. However, management expects that improved operating performance at certain businesses, growth from new business and global cost reduction initiatives may lessen or offset the impact of the challenges described above. If these favorable effects do not occur, or if the challenges described above and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may impact our gross margin, net income attributable to The AES Corporation and cash flows.

The following briefly describes the key changes in our reported revenue, gross margin, net income attributable to The AES Corporation, net cash provided by operating activities, diluted earnings per share from continuing operations, and adjusted earnings per share (a non-GAAP measure) for the three and six months ended June 30, 2012 compared to the three and six months ended June 30, 2011 and should be read in conjunction with our Consolidated Results of Operations discussion below.

Performance Highlights


	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		% Change			2012		2011		% Change
	($’s in millions, except per share amounts)
Revenue	$	4,192	$	4,435		-5	%	$	8,932	$	8,591		4	%
Gross Margin	$	692	$	992		-30	%	$	1,770	$	1,985		-11	%
Net Income Attributable to The AES Corporation	$	140	$	174		-20	%	$	481	$	398		21	%
Net Cash Provided by Operating Activities	$	580	$	675		-14	%	$	1,114	$	1,177		-5	%
Diluted Earnings per Share from Continuing Operations	$	0.09	$	0.24		-63	%	$	0.54	$	0.53		2	%
Adjusted Earnings Per Share (a non-GAAP measure)⁽¹⁾	$	0.18	$	0.29		-38	%	$	0.55	$	0.53		4	%

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

Highlights of second quarter and year to date financial results include:

Three months ended June 30, 2012:

Revenue decreased $243 million, or 5%, to $4.2 billion in the three months ended June 30, 2012 compared with $4.4 billion in the three months ended June 30, 2011. Key drivers of the decrease included:

•

the unfavorable impact of foreign currency of $400 million; and

•

lower prices at Eletropaulo, in Brazil, due to the unfavorable impact of the finalization of the July 2011 tariff reset, which was finalized by the Brazilian regulator at the beginning of July 2012 and included a cumulative catch up to cover the period back to July 2011.

These decreases were partially offset by:

•

the impact of the Company’s new businesses including DPL, in the United States, acquired in November 2011, and Angamos, in Chile, Maritza, in Bulgaria and Changuinola, in Panama, which commenced commercial operations in April, June and October of 2011, respectively.

Gross margin decreased $300 million, or 30%, to $692 million in the three months ended June 30, 2012 compared with $992 million in the three months ended June 30, 2011. Key drivers of the decrease included:

•

the unfavorable impact of foreign currency of $36 million;

•

lower prices due to the unfavorable tariff reset at Eletropaulo, as discussed above; and

•

lower plant availability at Gener in Chile, primarily due to outages of baseload capacity, and lower exports from Termoandes to Chile.

These decreases were partially offset by:

•

the impact of new businesses, as discussed above.

Net income attributable to The AES Corporation decreased $34 million to $140 million in the three months ended June 30, 2012 compared to $174 million in the three months ended June 30, 2011. Key drivers of the decrease included:

•

the decrease in gross margin as described above; and

•

foreign currency losses in 2012 compared to gains in 2011.

These decreases were partially offset by:

•

gains on the disposal of Red Oak and Ironwood, in the United States.

Net cash provided by operating activities decreased $95 million, or 14%, to $580 million in the three months ended June 30, 2012 compared with $675 million in the three months ended June 30, 2011.

Operating cash flow of $580 million for the three months ended June 30, 2012 resulted primarily from net income adjusted for non-cash items, principally depreciation and amortization, gains and losses on sales and disposals and impairment charges, and from a net favorable change of $58 million in operating assets and liabilities. Other liabilities contributed $204 million primarily due to an increase in long-term regulatory liabilities related to the tariff reset at Eletropaulo. Prepaid expenses and other current assets contributed $135 million, including the recovery of value added tax on a construction project in Chile and the use of prepaid fuel at one of our plants in the Dominican Republic. These favorable changes were partially offset by a $137 million use of cash by other assets mainly due to an increase in long-term regulatory assets at Eletropaulo, resulting from higher priced energy purchases and regulatory charges compared with the ones recovered through the current tariff, and an $88 million use of cash primarily for the payment of income taxes in excess of the accrual of new tax liabilities.

Net cash provided by operating activities was $675 million during the three months ended June 30, 2011. Operating cash flow resulted primarily from net earnings adjusted for non-cash items, principally depreciation and amortization, partially offset by a net unfavorable change of $148 million in operating assets and liabilities. Accounts payable and other current liabilities consumed $213 million mainly due to the payment of accrued interest at the parent Company and several businesses and to reductions in regulatory and other liabilities at Eletropaulo. Accounts receivable used $70 million due to increased revenue from several generation businesses, including new plants at Maritza and Angamos. These uses of operating cash flows were offset by contributions arising from a decrease of $136 million in prepaid expenses and other current assets, mainly resulting from a decrease in short term regulatory assets at Eletropaulo due to recoveries through the tariff of prior period energy purchases and regulatory charges partially offset by subsidies to be recovered through future tariffs and the collection of interest receivable at Eletropaulo, as well as an increase of $119 million in other liabilities, mainly related to regulatory liabilities due to lower energy purchases compared with the ones recovered through the current tariff at Eletropaulo and Sul.

Six months ended June 30, 2012:

Revenue increased $341 million, or 4%, to $8.9 billion in the six months ended June 30, 2012 compared with $8.6 billion in the six months ended June 30, 2011. Key drivers of the increase included:

•

impact of the Company’s new businesses including DPL, acquired in November 2011, and Angamos, Maritza, and Changuinola, which commenced commercial operations in April, June and October of 2011, respectively;

•

higher prices at our utility businesses in El Salvador and at Sul, in Brazil;

•

increased volume at our utility businesses in Latin America; and

•

increased volume and prices in the Dominican Republic.

These increases were partially offset by:

•

the unfavorable impact of foreign currency of $549 million;

•

lower prices at Eletropaulo, due to the unfavorable impact of the finalization of the July 2011 tariff reset, which was finalized by the Brazilian regulator at the beginning of July 2012 and included a cumulative catch up to cover the period back to July 2011; and

•

lower volume and prices at Gener.

Gross margin decreased $215 million, or 11%, to $1.8 billion in the six months ended June 30, 2012 compared with $2.0 billion in the six months ended June 30, 2011. Key drivers of the decrease included:

•

the unfavorable impact of foreign currency of $61 million;

•

lower prices due to the unfavorable tariff reset at Eletropaulo, as discussed above; and

•

lower energy exports from Termoandes to Chile and lower plant availability at Gener.

These decreases were partially offset by:

•

the impact of new businesses, as discussed above;

•

the favorable impact of a non-recurring arbitration settlement during the first quarter of 2012 at Cartagena, in Spain; and

•

increased volume at our utility businesses in Brazil.

Net income attributable to The AES Corporation increased $83 million, or 21%, to $481 million in the six months ended June 30, 2012 compared with $398 million in the six months ended June 30, 2011. Key drivers of the increase included:

•

the gain on the sale of 80% of our interest in Cartagena; and

•

the gain on the sale of Red Oak and Ironwood;

These increases were partially offset by:

•

the decrease in gross margin as described above;

•

foreign currency losses in 2012 compared to gains in 2011;

•

an increase in interest expense primarily due to debt at DPL which was acquired in November 2011 and additional indebtedness at the Parent Company to fund the acquisition of DPL; and

•

other-than-temporary impairments in China and France.

Net cash provided by operating activities decreased $63 million, or 5%, to $1.1 billion in the six months ended June 30, 2012 compared with $1.2 billion in the six months ended June 30, 2011. Please refer to Consolidated Cash Flows — Operating Activities for further discussion.

Non-GAAP Measure

We define adjusted earnings per share (“Adjusted EPS”) as diluted earnings per share from continuing operations excluding gains or losses of the consolidated entity due to (a) mark-to-market amounts related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) significant gains or losses due to

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

Beginning with the quarter ended March 31, 2012, the Company refined its process for computing the tax effects of Adjusted EPS items for interim periods. Accordingly, the Company has also reflected the refined process in the comparative three and six months ended June 30, 2011.


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Reconciliation of Adjusted Earnings Per Share
Diluted earnings per share from continuing operations	$	0.09		$	0.24		$	0.54		$	0.53
Derivative mark-to-market (gains)/losses⁽¹⁾		0.04			-			0.07			(0.01	)
Currency transaction (gains)/losses⁽²⁾		0.04			-			0.01			(0.04	)
Disposition/acquisition (gains)		-			-			(0.14	)⁽³⁾		-
Impairment losses		0.01	⁽⁴⁾		0.04	⁽⁵⁾		0.07	⁽⁶⁾		0.04	⁽⁵⁾
Debt retirement losses		-			0.01	⁽⁷⁾		-			0.01	⁽⁷⁾

Adjusted earnings per share	$	0.18		$	0.29		$	0.55		$	0.53

⁽¹⁾	Derivative mark-to-market (gains)/losses were net of income tax per share of $0.02 and $0.00 in the three months ended June 30, 2012 and 2011, and of $0.03 and $0.01 in the six months ended June 30, 2012 and 2011, respectively.

⁽²⁾	Unrealized foreign currency transaction (gains)/losses were net of income tax per share of $0.02 and $0.01 in the three months ended June 30, 2012 and 2011, respectively, and of $0.00 and $0.03 in the six months ended June 30, 2012 and 2011, respectively.

⁽³⁾	Amount primarily relates to the gain from the sale of 80% of our interest in Cartagena for $178 million ($106 million or $0.14 per share, net of income tax per share of $0.09).

⁽⁴⁾	Amount includes impairments at our St. Patrick business of $11 million ($7 million, or $0.01 per share, net of income tax per share of $0.00) and Kelanitissa of $7 million ($4 million, or $0.01 per share, net of non-controlling interest and income tax per share of $0.00).

⁽⁵⁾	Amount includes impairment at Kelanitissa of $33 million ($30 million, or $0.04 per share, net of non-controlling interest).

⁽⁶⁾

Amount primarily includes other-than-temporary impairments of equity method investments in China of $32 million ($26 million, or $0.03 per share, net of income tax per share of $0.01) and at InnoVent of $17 million ($12 million or $0.02 per share, net of income tax per share of $0.01), and asset impairments at St. Patrick of $11 million ($7 million or $0.01 per share, net of income tax per share of $0.00) and at Kelanitissa of $12 million ($8 million, or $0.01 per share, net of non-controlling interest and income tax per share of $0.00).

⁽⁷⁾	Amount includes loss on retirement of debt at IPL of $15 million ($11 million, or $0.01 per share, net of income tax per share of $0.01).

Consolidated Results of Operations


	Three Months Ended June 30,												Six Months Ended June 30,
							$			%									$			%
	2012			2011			change			change			2012			2011			change			change
	(in millions, except per share amounts)
Revenue:
Generation — Latin America	$	1,303		$	1,378		$	(75	)		-5	%	$	2,567		$	2,509		$	58			2	%
Generation — North America		328			339			(11	)		-3	%		645			673			(28	)		-4	%
Generation — Europe		233			328			(95	)		-29	%		683			728			(45	)		-6	%
Generation — Asia		181			162			19			12	%		362			277			85			31	%
Utilities — Latin America		1,446			1,944			(498	)		-26	%		3,180			3,784			(604	)		-16	%
Utilities — North America		678			280			398			142	%		1,410			569			841			148	%
Corporate and Other⁽¹⁾		284			273			11			4	%		640			574			66			11	%
Intersegment Eliminations⁽²⁾		(261	)		(269	)		8			3	%		(555	)		(523	)		(32	)		-6	%

Total Revenue		4,192			4,435			(243	)		-5	%		8,932			8,591			341			4	%

Gross Margin:
Generation — Latin America		370			453			(83	)		-18	%		826			868			(42	)		-5	%
Generation — North America		89			84			5			6	%		166			166			-			-	%
Generation — Europe		62			64			(2	)		-3	%		275			145			130			90	%
Generation — Asia		60			54			6			11	%		114			98			16			16	%
Utilities — Latin America		(15	)		266			(281	)		-106	%		84			512			(428	)		-84	%
Utilities — North America		92			49			43			88	%		206			99			107			108	%
Corporate and Other⁽³⁾		23			14			9			64	%		87			80			7			9	%
Intersegment Eliminations⁽⁴⁾		11			8			3			38	%		12			17			(5	)		-29	%
General and administrative expenses		(74	)		(97	)		23			24	%		(161	)		(192	)		31			16	%
Interest expense		(385	)		(381	)		(4	)		-1	%		(801	)		(719	)		(82	)		-11	%
Interest income		83			96			(13	)		-14	%		174			191			(17	)		-9	%
Other expense		(15	)		(35	)		20			57	%		(44	)		(50	)		6			12	%
Other income		15			34			(19	)		-56	%		33			50			(17	)		-34	%
Gain on sale of investments		5			1			4			400	%		184			7			177			2529	%
Asset impairment expense		(18	)		(33	)		15			45	%		(29	)		(33	)		4			12	%
Foreign currency transaction gains (losses)		(101	)		37			(138	)		-373	%		(102	)		70			(172	)		-246	%
Other non-operating expense		(1	)		-			(1	)		N/A			(50	)		-			(50	)		N/A
Income tax expense		(76	)		(174	)		98			56	%		(343	)		(389	)		46			12	%
Net equity in earnings of affiliates		11			(4	)		15			375	%		24			6			18			300	%

INCOME FROM CONTINUING OPERATIONS		136			436			(300	)		-69	%		655			926			(271	)		-29	%
Income (loss) from operations of discontinued businesses		(4	)		(9	)		5			56	%		(3	)		(16	)		13			81	%
Net gain (loss) from disposal and impairments of discontinued businesses		75			-			75			N/A			70			-			70			N/A

NET INCOME		207			427			(220	)		-52	%		722			910			(188	)		-21	%
Noncontrolling interests:
Income from continuing operations attributable to noncontrolling interests		(67	)		(245	)		178			73	%		(241	)		(498	)		257			52	%
Income from discontinued operations attributable to noncontrolling interests		-			(8	)		8			100	%		-			(14	)		14			100	%

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	140		$	174		$	(34	)		-20	%	$	481		$	398		$	83			21	%


Earnings Per Share Data:
Basic earnings per share from continuing operations	$	0.09		$	0.24		$	(0.15	)		-63	%	$	0.54		$	0.54		$	-			-	%
Diluted earnings per share from continuing operations	$	0.09		$	0.24		$	(0.15	)		-63	%	$	0.54		$	0.53		$	0.01			2	%

⁽¹⁾	Corporate and other includes revenue from the Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation operating segments and other climate solutions and renewable projects.

⁽²⁾	Represents inter-segment eliminations of revenue primarily related to transfers of electricity from Tietê (Generation — Latin America) to Eletropaulo (Utilities — Latin America).

⁽³⁾	Corporate and other gross margin includes gross margin from the Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation operating segments and other climate solutions and renewable projects.

⁽⁴⁾	Inter-segment eliminations represent eliminations of revenue and gross margin among segments.

Revenue and Gross Margin Analysis

Generation

Generation — Latin America

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


	For the Three Months Ended June 30,							For the Six Months Ended June 30,
	2012		2011		% Change			2012		2011		% Change
	($’s in millions)							($’s in millions)
Revenue	$	1,303	$	1,378		-5	%	$	2,567	$	2,509		2	%
Gross Margin	$	370	$	453		-18	%	$	826	$	868		-5	%

Excluding the unfavorable impact of foreign currency translation and remeasurement of $87 million, primarily in Brazil and Argentina, generation revenue for the three months ended June 30, 2012 increased $12 million, or 1%, compared to the three months ended June 30, 2011 primarily due to:

•

higher volume and prices of $80 million at Tietê in Brazil mainly driven by higher demand by the offtaker and higher energy sold to the spot market administrator at higher prices due to lower water inflows in the system;

•

the positive impact of $41 million in the Dominican Republic primarily as a result of higher international gas prices and volume of gas sales to third parties and ancillary services;

•

new business of $26 million at Angamos in Chile and at Changuinola in Panama, which commenced operations in 2011;

•

higher volume of $18 million in Argentina due to higher dispatch of thermal units; and

•

the positive impact of $15 million due to the Esti plant being back on line since June 2012 in Panama.

These increases were partially offset by:

•

the adverse impact of $69 million on prices in Argentina as a result of a price adjustment agreement executed in 2011;

•

negative impact of $42 million at Gener in Chile mainly due to lower volume and prices;

•

negative impact of $30 million in Argentina as a result of outages at San Nicolas and Parana; and

•

lower volume and PPA price of $23 million in the Dominican Republic mainly driven by lower generation and lower price indexation due to decrease in NYMEX gas prices.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $47 million, primarily in Brazil and Argentina, generation gross margin for the three months ended June 30, 2012 decreased $36 million, or 8%, compared to the three months ended June 30, 2011 primarily due to:

•

negative impact of $85 million at Gener in Chile mainly due to lower plant availability, primarily due to outages of baseload capacity and lower exports from Termoandes to Chile;

•

lower volume and PPA price of $24 million in the Dominican Republic as described above;

•

lower price of $14 million in Argentina as a result of a price adjustment agreement executed in 2011; and

•

higher fixed and operating costs of $18 million across the region, primarily attributable to higher maintenance costs and employee costs. We expect that this trend may continue through the second half of 2012.

These decreases were partially offset by:

•

higher volume and prices of $71 million at Tietê as discussed above;

•

new business of $26 million at Changuinola as described above; and

•

the positive impact of $8 million in the Dominican Republic of higher gas sales and ancillary services as discussed above.

For the three months ended June 30, 2012, revenue decreased 5%, while gross margin decreased by 18%. This was primarily due to the higher spot purchases and fuel costs in Panama, Chile and the Dominican Republic, the pass-through effect of gas sales to third parties in the Dominican Republic on gross margin and the increase in fixed costs due to higher maintenance and employee costs.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $112 million, primarily in Brazil and Argentina, generation revenue for the six months ended June 30, 2012 increased $170 million, or 7%, compared to the six months ended June 30, 2011 primarily due to:

•

higher volume and prices of $151 million at Tietê in Brazil mainly driven by higher demand by the offtaker and higher energy sold to the spot market administrator at higher prices due to lower water inflows in the system;

•

new business impact of $113 million at Angamos in Chile and at Changuinola in Panama, which commenced operations in 2011;

•

the positive impact of $67 million in the Dominican Republic as a result of higher international gas prices and volume of gas sales to third parties and ancillary services;

•

higher volume of $25 million in Argentina mainly as a result of higher thermal generation; and

•

the positive impact of $14 million due to the Esti plant being back on line since June 2012 in Panama.

These increases were partially offset by:

•

the adverse impact of $66 million on prices in Argentina as a result of a price adjustment agreement executed in 2011;

•

negative impact of $101 million at Gener in Chile mainly due to lower energy exports from Termoandes to Chile and lower prices;

•

lower volume and PPA price of $27 million in the Dominican Republic mainly driven by lower generation and lower price indexation due to decrease in NYMEX gas prices; and

•

negative impact of $26 million in Argentina as a result of outages at San Nicolas and Parana plants.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $60 million, generation gross margin for the six months ended June 30, 2012 increased $18 million, or 2%, compared to the six months ended June 30, 2011 primarily due to:

•

higher volume and prices of $134 million at Tietê as discussed above;

•

new business of $58 million at Angamos and Changuinola as described above;

•

higher contract prices of $21 million in the Dominican Republic primarily from PPAs indexed to coal;

•

the positive impact of $15 million in the Dominican Republic of higher gas sales and ancillary services as discussed above;

•

higher volume and prices of $15 million at Panama due to higher spot and PPA prices and sales; and

•

lower fixed costs of $14 million in Colombia as a result of non-recurring equity tax expense incurred in 2011.

These increases were partially offset by:

•

negative impact of $146 million at Gener mainly due to lower exports from Termoandes to Chile and lower plant availability;

•

negative impact of $22 million due primarily to outages in Panama;

•

lower volume and PPA price of $19 million in the Dominican Republic as described above;

•

lower price of $15 million in Argentina as a result of a price adjustment agreement executed in 2011; and

•

higher fixed and operating costs of $35 million across the region, primarily attributable to higher maintenance costs and employee costs. We expect that this trend may continue through the second half of 2012.

For the six months ended June 30, 2012, revenue increased 2%, while gross margin decreased by 5%. This was primarily due to the higher spot purchases and fuel costs in Panama, Chile and the Dominican Republic, the pass through effect of gas sales to third parties in the Dominican Republic on gross margin and the increase in fixed costs due to higher maintenance and employee costs.

Generation — North America

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


	For the Three Months Ended June 30,							For the Six Months Ended June 30,
	2012		2011		% Change			2012		2011		% Change
	($’s in millions)							($’s in millions)
Revenue	$	328	$	339		-3	%	$	645	$	673		-4	%
Gross Margin	$	89	$	84		6	%	$	166	$	166		0	%

Excluding the unfavorable impact of foreign currency translation of $10 million in Mexico, generation revenue for the three months ended June 30, 2012 decreased $1 million, remained flat compared to the three months ended June 30, 2011 primarily due to:

•

a decrease in Puerto Rico of $10 million primarily due to higher forced outages and a 2011 insurance recovery for force majeure; and

•

lower pass-through rates of $9 million at Merida in Mexico due to lower fuel costs.

These decreases were partially offset by:

•

an increase of $8 million at TEG/TEP in Mexico primarily due to higher availability bonuses; and

•

an increase of $7 million at Southland in California primarily due to the short-term restart of two generating units at the Huntington Beach plant

Excluding the unfavorable impact of foreign currency translation of $1 million in Mexico, generation gross margin for the three months ended June 30, 2012 increased $6 million, or 7%, compared to the three months ended June 30, 2011 primarily due to:

•

an increase of $8 million at Southland primarily due to the short-term restart of two generating units at the Huntington Beach plant; and

•

an increase of $6 million at TEG/TEP primarily due to the higher availability bonuses.

These increases were partially offset by:

•

a decrease in Puerto Rico of $6 million primarily due to higher forced outages and a 2011 insurance recovery for force majeure.

Excluding the unfavorable impact of foreign currency translation of $15 million in Mexico, generation revenue for the six months ended June 30, 2012 decreased $13 million, or 2%, compared to the six months ended June 30, 2011 primarily due to:

•

lower pass-through rates of $21 million at Merida due to lower fuel costs; and

•

a decrease in Puerto Rico of $14 million primarily due to higher forced outages and a 2011 insurance recovery for force majeure.

These decreases were partially offset by:

•

an increase at TEG/TEP of $8 million primarily due to higher availability bonuses and $6 million due to higher rates; and

•

higher rates of $4 million in Puerto Rico.

Excluding the unfavorable impact of foreign currency translation of $2 million in Mexico, generation gross margin for the six months ended June 30, 2012 increased $2 million, or 1%, compared to the six months ended June 30, 2011 primarily due to:

•

an increase of $9 million at TEG/TEP primarily due to higher availability bonuses.

This increase was partially offset by:

•

a decrease in Puerto Rico of $7 million primarily due to higher forced outages and related maintenance costs as well as a 2011 insurance recovery for force majeure.

Generation — Europe

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


	For the Three Months Ended June 30,							For the Six Months Ended June 30,
	2012		2011		% Change			2012		2011		% Change
	($’s in millions)							($’s in millions)
Revenue	$	233	$	328		-29	%	$	683	$	728		-6	%
Gross Margin	$	62	$	64		-3	%	$	275	$	145		90	%

Excluding the unfavorable impact of foreign currency translation of $13 million, generation revenue for the three months ended June 30, 2012 decreased $82 million, or 25%, compared to the three months ended June 30, 2011 primarily due to:

•

lower revenue of $49 million in Hungary driven by the decision to cease operations at the plant as of March 31, 2012;

•

lower revenue of $46 million at Cartagena as a result of the sale of 80% of our ownership in February 2012; and

•

lower revenue of $42 million at Ballylumford in Northern Ireland, mainly attributable to higher forced outages and lower capacity prices as originally established in the PPA.

These decreases were partially offset by:

•

new business of $55 million from the operations at Maritza, in Bulgaria, which commenced commercial operations in June 2011; and

•

higher revenue of $18 million at Kilroot, in Northern Ireland, primarily due to increased dispatch of the plant.

Excluding the unfavorable impact of foreign currency translation of $5 million, generation gross margin for the three months ended June 30, 2012 increased $3 million, or 5%, compared to the three months ended June 30, 2011 primarily due to:

•

new business of $42 million from Maritza as discussed above; and

•

higher gross margin of $12 million at Kilroot driven by higher dispatch of the units in the market.

These increases were partially offset by:

•

lower gross margin of $28 million at Ballylumford primarily due to lower capacity prices in the PPA and higher forced outages;

•

lower gross margin of $18 million at Cartagena as result of the sale in February 2012; and

•

lower gross margin of $5 million in Hungary, driven by the cease in operations.

For the three months ended June 30, 2012, revenue decreased 29%, while gross margin decreased 3% primarily due to ceasing operations in Hungary on March 31, 2012, which had a greater impact on revenue than gross margin due to fuel cost savings.

Excluding the unfavorable impact of foreign currency translation of $31 million, generation revenue for the six months ended June 30, 2012 decreased $14 million, or 2%, compared to the six months ended June 30, 2011 primarily due to:

•

lower revenue of $79 million in Hungary due to a decrease in volume and prices for ancillary services which have caused management to cease operations at the plant as of March 31, 2012;

•

lower revenue of $79 million at Ballylumford, in Northern Ireland, attributable to higher forced and planned outages as well as lower capacity prices in the PPA in the second quarter of 2012; and

•

$17 million lower revenue as a result of the sale of 80% of our ownership of Cartagena in February 2012, partially offset by non-recurring favorable arbitration settlement in the first quarter 2012 of $95 million.

These decreases were partially offset by:

•

new business of $155 million from Maritza, in Bulgaria, which commenced commercial operations in June 2011; and

•

$26 million higher revenue at Kilroot, in Northern Ireland, primarily due to increased dispatch of units in the market.

Excluding the unfavorable impact of foreign currency translation of $13 million, generation gross margin for the six months ended June 30, 2012 increased $143 million, or 99%, compared to the six months ended June 30, 2011 primarily due to:

•

new business of $98 million from Maritza, in Bulgaria;

•

a $77 million increase at Cartagena, mainly attributable to a non-recurring favorable arbitration settlement as discussed above, partially offset by lower gross margin as a result of the sale in February 2012; and

•

$19 million higher gross margin from Kilroot as discussed above.

These increases were partially offset by:

•

lower gross margin of $34 million at Ballylumford, in Northern Ireland, attributable to higher forced and planned outages as well as lower capacity prices in the PPA in the second quarter; and

•

$16 million lower gross margin in Hungary as discussed above.

For the six months ended June 30, 2012, revenue decreased 6%, while gross margin increased by 90% primarily due to the arbitration settlement in Cartagena and due to the cessation of operations in Hungary.

Generation — Asia

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


	For the Three Months Ended June 30,							For the Six Months Ended June 30,
	2012		2011		% Change			2012		2011		% Change
	($’s in millions)							($’s in millions)
Revenue	$	181	$	162		12	%	$	362	$	277		31	%
Gross Margin	$	60	$	54		11	%	$	114	$	98		16	%

Excluding the unfavorable impact of foreign currency translation of $5 million, generation revenue for the three months ended June 30, 2012 increased $24 million, or 15%, compared to the three months ended June 30, 2011 primarily due to:

•

higher volume of $21 million at Masinloc in the Philippines primarily as a result of higher demand from existing contract customers; and

•

higher volume of $8 million at Kelanitissa in Sri Lanka attributable to higher off-taker demand.

Generation gross margin for the three months ended June 30, 2012 increased $6 million, or 11%, compared to the three months ended June 30, 2011 primarily due to:

•

an increase of $16 million at Masinloc largely attributable to higher market demand as explained above.

This increase was partially offset by:

•

higher fixed costs of $4 million related to commitment fees on undrawn construction loans at Mong Duong, a 1240 MW coal-fired power plant under construction in Vietnam.

Excluding the unfavorable impact of foreign currency translation of $7 million, generation revenue for the six months ended June 30, 2012 increased $92 million, or 33%, compared to the six months ended June 30, 2011 primarily due to:

•

higher volume of $38 million at Masinloc primarily as a result of higher market demand; and

•

higher volume of $43 million at Kelanitissa in Sri Lanka attributable to higher offtaker demand as a result of lower hydrology, coupled with 2011 plant reserve shutdown and curtailment due to higher market capacity in 2011 as a result of the addition of a new coal plant to the grid.

Excluding the favorable impact of foreign currency translation of $1 million, generation gross margin for the six months ended June 30, 2012 increased $15 million, or 15%, compared to the six months ended June 30, 2011 primarily due to:

•

an increase of $23 million largely attributable to higher market demand at Masinloc.

This increase was partially offset by:

•

higher cost of $7 million related to commitment fees on undrawn construction loans at Mong Duong, a 1240 MW coal-fired power plant in Vietnam.

For the six months ended June 30, 2012, revenue increased 31%, while gross margin increased by 16%. This was primarily due to the pass-through fuel costs at Kelanitissa which had a positive impact on revenue, but no corresponding impact on gross margin.

Utilities

Utilities — Latin America

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


	For the Three Months								For the Six Months
	Ended June 30,								Ended June 30,
	2012			2011		% Change			2012		2011		% Change
	($’s in millions)								($’s in millions)
Revenue	$	1,446		$	1,944		-26	%	$	3,180	$	3,784		-16	%
Gross Margin	$	(15	)	$	266		-106	%	$	84	$	512		-84	%

Excluding the unfavorable impact of foreign currency translation of $271 million, utilities revenue for the three months ended June 30, 2012 decreased $227 million, or 12%, compared to the three months ended June 30, 2011 primarily due to:

•

lower tariffs of $244 million at Eletropaulo in Brazil primarily related to the final impact of the July 2011 tariff reset, which was finalized by the Regulator on July 2, 2012. This includes a cumulative adjustment of $80 million to the estimated regulatory liability recorded in the second half of 2011 and first quarter of 2012 based on information received during the second quarter of 2012. The negative impact of the tariff reset is being partially offset by an increase in spot revenues.

These decreases were partially offset by:

•

higher pass-through tariffs of $29 million in El Salvador due to increased energy prices driven by higher fuel prices and drier weather.

Excluding the favorable impact of foreign currency translation of $16 million, utilities gross margin for the three months ended June 30, 2012 decreased $297 million, or 112%, compared to the three months ended June 30, 2011 primarily due to lower tariffs of $279 million at Eletropaulo, primarily related to the impact of the July 2011 tariff reset as discussed above.

For the three months ended June 30, 2012, revenue decreased 26%, while gross margin decreased 106%. The difference is primarily due to the impact of the July 2011 tariff reset at Eletropaulo, which had a greater unfavorable impact on gross margin than revenue and the increase in pass-through revenue at El Salvador, which had no corresponding impact on gross margin.

Excluding the unfavorable impact of foreign currency translation of $362 million, utilities revenue for the six months ended June 30, 2012 decreased $242 million, or 6%, compared to the six months ended June 30, 2011 primarily due to:

•

lower tariffs of $426 million at Eletropaulo in Brazil primarily related to the impact of the July 2011 tariff reset, which was finalized by the Regulator on July 2, 2012. This includes a cumulative adjustment of $75 million to the estimated regulatory liability recorded in the second half of 2011 based on information received during the first half of 2012. The negative impact of the tariff reset is being partially offset by an increase in spot revenues.

These decreases were partially offset by:

•

higher volume of $70 million due to increased market demand in Brazil;

•

higher pass-through tariffs of $67 million in El Salvador primarily due to increased energy prices driven by higher fuel prices and drier weather; and

•

higher tariffs of $44 million at Sul, in Brazil, due to the annual adjustment in April 2011 that increased the tariff by 12% to cover energy and transmission costs, regulatory charges, taxes and operations and maintenance.

Excluding the favorable impact of foreign currency translation of $13 million, utilities gross margin for the six months ended June 30, 2012 decreased $441 million, or 86%, compared to the six months ended June 30, 2011 primarily due to:

•

lower tariffs of $449 million at Eletropaulo, primarily related to the impact of the July 2011 tariff reset as discussed above; and

•

higher fixed costs of $35 million primarily due to higher employee costs resulting from a collective wage agreement and bad debt expense at Eletropaulo.

These decreases were partially offset by:

•

higher volume of $34 million, primarily in Brazil, due to increased market demand.

For the six months ended June 30, 2012, revenue decreased 16%, while gross margin decreased by 84%. This was primarily due to the impact of the July 2011 tariff reset finalized in July 2012 at Eletropaulo, which had a greater unfavorable impact on gross margin than revenue, higher fixed costs at Eletropaulo and the increase in spot revenues at Eletropaulo and pass-through revenue at Sul and El Salvador, which had no corresponding impact on gross margin.

Utilities — North America

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


	For the Three Months							For the Six Months
	Ended June 30,							Ended June 30,
	2012		2011		% Change			2012		2011		% Change
	($’s in millions)							($’s in millions)
Revenue	$	678	$	280		142	%	$	1,410	$	569		148	%
Gross Margin	$	92	$	49		88	%	$	206	$	99		108	%

Utilities revenue for the three months ended June 30, 2012 increased $398 million, or 142%, compared to the three months ended June 30, 2011 primarily due to:

•

an increase of $385 million from the operations of DPL, in Ohio, which was acquired in November 2011; and

•

higher prices of $22 million at IPL in Indiana, primarily due to higher fuel adjustment charges and other pass-through charges.

These increases were partially offset by:

•

lower volume of $10 million at IPL, primarily due to lower wholesale sales resulting from IPL’s generating units being priced out of market more often in 2012.

Utilities gross margin for the three months ended June 30, 2012 increased $43 million, or 88%, compared to the three months ended June 30, 2011 primarily due to:

•

an increase of $45 million from the operations of DPL, which was acquired in November 2011; and

•

higher retail volume at IPL of $3 million, primarily due to warmer weather.

These increases were partially offset by:

•

lower wholesale margin of $5 million at IPL, primarily due to lower wholesale sales resulting from IPL’s generating units being priced out of market more often in 2012.

For the three months ended June 30, 2012, revenue increased 142%, while gross margin increased by 88% primarily due to the unfavorable impact on gross margin from the amortization of intangible assets of $28 million related to the DPL acquisition, and the positive impact on revenue of higher pass-through charges at IPL, which had no corresponding impact on gross margin.

Utilities revenue for the six months ended June 30, 2012 increased $841 million, or 148%, compared to the six months ended June 30, 2011 primarily due to:

•

an increase of $816 million from the operations of DPL, in Ohio, which was acquired in November 2011; and

•

higher prices of $48 million at IPL in Indiana primarily due to higher fuel adjustment charges and other pass-through charges.

These increases were partially offset by:

•

lower volume of $23 million at IPL, primarily due to warmer winter weather in 2012 and because IPL’s generating units are being priced out of the market more often in 2012, reducing wholesale sales opportunities.

Utilities gross margin for the six months ended June 30, 2012 increased $107 million, or 108%, compared to the six months ended June 30, 2011 primarily due to:

•

an increase of $104 million from the operations of DPL, which was acquired in November 2011; and

•

lower repairs and maintenance costs at IPL of $11 million, primarily due to reduced generating unit outages.

These increases were partially offset by:

•

lower wholesale margin of $8 million at IPL, primarily due to lower wholesale sales resulting from IPL’s generating units being priced out of market more often in 2012.

For the six months ended June 30, 2012, revenue increased 148%, while gross margin increased by 108% primarily due to the unfavorable impact on gross margin from the amortization of intangible assets of $56 million related to the DPL acquisition, and the positive impact on revenue of higher pass-through charges at IPL which had no corresponding impact on gross margin.

Corporate and Other

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


	For the Three Months Ended June 30,									For the Six Months Ended June 30,
	2012			2011			% Change			2012			2011			% Change
	($’s in millions)									($’s in millions)
Revenue
Europe Utilities	$	103		$	90			14	%	$	239		$	200			20	%
Africa Utilities		92			100			-8	%		222			210			6	%
Africa Generation		24			23			4	%		47			44			7	%
Wind Generation		69			66			5	%		140			130			8	%
Corp/Other		4			2			100	%		8			5			60	%
Eliminations		(8	)		(8	)		0	%		(16	)		(15	)		-7	%

Total Corporate and Other	$	284		$	273			4	%	$	640		$	574			11	%

Gross Margin
Europe Utilities	$	2		$	-			N/A		$	12		$	10			20	%
Africa Utilities		(15	)		(16	)		6	%		(5	)		2			-350	%
Africa Generation		16			12			33	%		32			25			28	%
Wind Generation		20			24			-17	%		51			48			6	%
Corp/Other		(2	)		(7	)		71	%		(5	)		(7	)		29	%
Eliminations		2			1			100	%		2			2			0	%

Total Corporate and Other	$	23		$	14			64	%	$	87		$	80			9	%

Excluding the unfavorable impact of foreign currency translation of $13 million, revenue for the three months ended June 30, 2012 increased $24 million, or 9%, compared to the three months ended June 30, 2011 primarily due to higher tariffs at our utility businesses in the Ukraine and at Sonel, in Cameroon, of $11 million and $8 million, respectively.

Excluding the favorable impact of foreign currency translation of $1 million, gross margin for the three months ended June 30, 2012 increased $8 million, or 57%, compared to the three months ended June 30, 2011 primarily due to a decrease in fixed costs at our Africa generation businesses, offset by decreased performance at our wind generation businesses.

Excluding the unfavorable impact of foreign currency translation of $22 million, revenue for the six months ended June 30, 2012 increased $88 million, or 15%, compared to the six months ended June 30, 2011 primarily due to higher volume and rates at our businesses in the Ukraine and at Sonel, in Cameroon, of $41 million and $31 million, respectively.

Gross margin for the six months ended June 30, 2012 increased $7 million, or 9%, compared to the six months ended June 30, 2011 primarily due to higher rates at our utility businesses in the Ukraine and at Sonel, partially offset by lower volume at Sonel.

General and Administrative Expense

General and administrative expense decreased $23 million, or 24%, to $74 million for the three months ended June 30, 2012 primarily related to reduction of business development costs.

General and administrative expense decreased $31 million, or 16%, to $161 million for the six months ended June 30, 2012. The decrease was primarily due to reduction in business development and information systems administration costs.

Interest Expense

Interest expense increased $4 million, or 1%, to $385 million for the three months ended June 30, 2012. The increase was primarily due to debt at DPL acquired in November 2011, additional indebtedness at the Parent Company to finance the acquisition of DPL and less interest capitalization at Maritza due to the commencement of operations in June 2011, partially offset by a reduction in the interest rate, a reduction in debt principal and favorable foreign currency translation in Brazil as well as the absence of interest expense for Cartagena due to the sale of 80% of our interest in the first quarter of 2012.

Interest expense increased $82 million, or 11%, to $801 million for the six months ended June 30, 2012. The increase was primarily due to debt at DPL acquired in November 2011, additional indebtedness at the parent company to finance the acquisition of DPL and less interest capitalization at Maritza due to the commencement of operations in June 2011, partially offset by a reduction in the interest rate, reduction in debt principal and favorable foreign currency translation in Brazil.

Interest Income

Interest income decreased $13 million, or 14%, to $83 million for the three months ended June 30, 2012. The decrease was primarily due to unfavorable foreign currency translation and a reduction in the interest rate in Brazil.

Interest income decreased $17 million, or 9%, to $174 million for the six months ended June 30, 2012. The decrease was primarily due to unfavorable foreign currency translation and a reduction in the interest rate in Brazil.

Other Income (Expense)

See discussion of the components of other income and expense in Note 13 — Other Income (Expense) included in Item 1. — Financial Statements of this Form 10-Q.

Asset Impairment Expense

Asset impairment expense was $18 million and $29 million for the three and six months ended June 30, 2012, respectively. Asset impairment expense was $33 million for the three and six months ended June 30, 2011.

See Note 14 — Asset Impairment Expense included in Item 1. — Financial Statements of this Form 10-Q for further information.

Gain on Sale of Investments

Gain on sale of investments for the three months ended June 30, 2012 was $5 million, which was primarily related to the sale of InnoVent, an equity method investment in France. Gain on sale of investment for the three months ended June 30, 2011 was $1 million.

Gain on sale of investments for the six months ended June 30, 2012 was $184 million, of which $178 million related to the sale of 80% of our interest in Cartagena. Gain on sale of investments for the six months ended June 30, 2011 was $7 million, primarily related to our sale of Wuhu, an equity investment in China that was accounted for under the equity method of accounting.

Foreign Currency Transaction Gains (Losses)

Foreign currency transaction gains (losses) were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)						(in millions)
AES Corporation	$	(34	)	$	15		$	(16	)	$	48
Chile		(6	)		4			3			(1	)
Philippines		(42	)		2			(66	)		8
Brazil		(9	)		4			(6	)		4
Argentina		(6	)		15			(12	)		13
Colombia		-			(3	)		(4	)		(4	)
Other		(4	)		-			(1	)		2

Total⁽¹⁾	$	(101	)	$	37		$	(102	)	$	70

⁽¹⁾

Includes $41 million in losses and $17 million in gains on foreign currency derivative contracts for the three months ended June 30, 2012 and 2011, respectively, and $80 million in losses and $19 million in gains on foreign currency derivative contracts for the six months ended June 30, 2012 and 2011, respectively.

The Company recognized net foreign currency transaction losses of $101 million for the three months ended June 30, 2012 as discussed below:

•

Losses at The AES Corporation were primarily due to decreases in the valuation of inter-company notes receivable denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the quarter, partially offset by gains related to foreign currency options.

•

Losses in the Philippines were primarily due to unrealized foreign exchange losses on embedded derivatives, which was a result of the forecasted strengthening of the Philippine Peso versus the U.S. Dollar in future periods.

•

Losses in Brazil mainly related to commercial liabilities denominated in U.S. Dollars due to the 8% weakening of the Brazilian Real versus the U.S. Dollar.

The Company recognized foreign currency transaction gains of $37 million for the three months ended June 30, 2011 as discussed below:

•

Gains at The AES Corporation were primarily due to increases in the valuation of inter-company notes and trade receivables denominated in foreign currency, resulting from the strengthening of the Euro and the British Pound during the quarter.

•

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

The Company recognized foreign currency transaction losses of $102 million for the six months ended June 30, 2012 as discussed below:

•

Losses at The AES Corporation were primarily due to decreases in the valuation of inter-company notes receivable denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the year, and due to a decline in value of foreign currency options.

•

Losses in Argentina were primarily related to losses due to the devaluation of the Argentine Peso by 5%, resulting in losses at Alicura (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt and losses at Termoandes (a U.S. Dollar functional currency subsidiary) mainly associated with Cash and Account Receivable Balances in Local Currency. These losses were partially offset by a gain on a foreign currency embedded derivative related to Government receivables.

•

Losses in Brazil mainly related to commercial liabilities denominated in U.S. Dollar due to the 8% weakening of the Brazilian Real versus the U.S. Dollar.

The Company recognized foreign currency transaction gains of $70 million for the six months ended June 30, 2011 as discussed below:

•

Gains at The AES Corporation were primarily due to increases in the valuation of inter-company notes receivable and cash balances denominated in foreign currency resulting from the strengthening of the Euro and British Pound during the year.

•

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

•

Gains in the Philippines were at Masinloc (a Philippine Peso functional currency subsidiary) as a result of gains on foreign currency embedded derivatives due to the forecasted depreciation in the Philippine Peso versus the U.S. Dollar in future periods and gains from the remeasurement of U.S. Dollar denominated debt due to the actual appreciation of the Philippine Peso versus the U.S Dollar.

Other Non-Operating Expense

Other non-operating expense of $1 million and $50 million for the three and six months ended June 30, 2012, respectively, primarily included other-than-temporary impairments of equity method investments in China and France. See Note 15 — Other Non-operating Expense included in Item 1. — Financial Statements of this Form 10-Q for further information. There was no other non-operating expense for the three and six months ended June 30, 2011.

Income Tax Expense

Income tax expense decreased $98 million, or 56%, to $76 million for the three months ended June 30, 2012 compared to $174 million for the three months ended June 30, 2011. The Company’s effective tax rates were 38% and 28% for the three months ended June 30, 2012 and 2011, respectively.

The net increase in the effective tax rate for the three months ended June 30, 2012 compared to the same period in 2011 was due, in part, to an increase in U.S. taxes applicable to certain non-U.S. subsidiaries and lower pretax book income in certain low tax jurisdictions.

Income tax expense decreased $46 million, or 12%, to $343 million for the six months ended June 30, 2012 compared to $389 million for the six months ended June 30, 2011. The Company’s effective tax rates were 35% and 30% for the six months ended June 30, 2012 and 2011, respectively.

The net increase in the effective tax rate for the six months ended June 30, 2012 compared to the same period in 2011 was due, in part, to the partial sale of our interest in AES Cartagena and an increase in U.S. taxes applicable to certain non-U.S. subsidiaries. See Note 17-Acquisitions and Dispositions regarding the sale of AES Cartagena included in Item 1. — Financial Statements of this Form 10-Q for further information.

Net Equity in Earnings of Affiliates

Net equity in earnings of affiliates increased $15 million, or 375%, to $11 million for the three months ended June 30, 2012. The increase was primarily due to higher generation, increased tariff pricing, and lower depreciation at Yangcheng in China. Additionally, there were $18 million of impairment charges at AES Solar in 2011, of which our share was $9 million. This increase was partially offset by lower net income caused by higher electricity purchase costs at Guacolda.

Net equity in earnings of affiliates increased $18 million to $24 million for the six months ended June 30, 2012. The increase was primarily due to higher generation, increased tariff pricing and lower depreciation at Yangcheng in China. Additionally, there were $30 million of impairment charges at AES Solar in 2011, of which our share was $15 million. This increase was offset by lower net income caused by higher electricity purchase costs at Guacolda.

Income from Continuing Operations Attributable to Noncontrolling Interests

Income from continuing operations attributable to noncontrolling interests decreased $178 million, or 73%, to $67 million for the three months ended June 30, 2012. The decrease was primarily due to lower distribution revenue at Eletropaulo as a result of the impact of the tariff reset as well as a decrease in gross margin due to lower plant availability combined with higher contract levels at Gener.

Income from continuing operations attributable to noncontrolling interests decreased $257 million, or 52%, to $241 million for the six months ended June 30, 2012. The decrease was primarily due to lower distribution revenue at Eletropaulo as a result of the impact of the tariff reset. This was partially offset by higher sales volume and increased spot prices at Tietê.

Discontinued Operations

Total discontinued operations was a net gain of $71 million for the three months ended June 30, 2012 and a net loss of $9 million for the three months ended June 30, 2011, and a net gain of $67 million for the six months ended June 30, 2012 and a net loss of $16 million for the six months ended June 30, 2011. See Note 16 — Discontinued Operations and Held for Sale Businesses included in Item 1. — Financial Statements of this Form 10-Q for further information.

Capital Resources and Liquidity

Overview

As of June 30, 2012, the Company had unrestricted cash and cash equivalents of $1.7 billion, of which approximately $240 million was held at the Parent Company and qualified holding companies, and approximately $883 million was held in short term investments primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $1.4 billion. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.5 billion and $6.2 billion, respectively. Of the approximately $2.3 billion of our current non-recourse debt, $874 million was presented as such because it is due in the next twelve months and $1.4 billion relates to debt considered in default due to covenant violations. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. Approximately $11 million of our recourse debt matures within the next twelve months, which we expect to repay using cash on hand at the Parent Company or through net cash provided by operating activities. See further discussion of Parent Company Liquidity below.

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

assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks.

Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company’s only material un-hedged exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility. On a consolidated basis, of the Company’s $15.5 billion of total non-recourse debt outstanding as of June 30, 2012, approximately $4.5 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate.

In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At June 30, 2012, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $528 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, 2012, we had $5 million in letters of credit outstanding, provided under our senior secured credit facility, and $246 million in cash collateralized letters of credit outstanding outside of our senior secured credit facility. These letters of credit operate to guarantee performance relating to certain project development activities and business operations. During the quarter ended June 30, 2012, the Company paid letter of credit fees ranging from 0.25% to 3.25% per annum on the outstanding amounts.

We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our

investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.

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

As of June 30, 2012, the Company had approximately $375 million and $21 million of trade accounts receivable related to certain of its generation and utility businesses in Latin America classified as other noncurrent assets and current trade accounts receivable, respectively. The noncurrent portion primarily consists of trade accounts receivable that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond June 30, 2013, or one year past the latest balance sheet date. The Company believes such amounts are recoverable based on collection history and performance under agreements. For example, since 2004, our subsidiaries in Argentina have entered into three agreements with the Argentine government called Fondos de inversion Mercado Electrico Mayorista (“Foninvemem Agreements”), in which our subsidiaries contributed a portion of their accounts receivable into a fund used to finance the construction of combined cycle and gas-fired plants. Our subsidiaries in Argentina have been actively collecting on the accounts receivable from the combined cycle plants constructed under the first two Foninvemem Agreements since 2010 while the accounts receivable related to the third Foninvemem Agreement are not currently due as commercial operation of the related combined cycle and gas-fired plant has not been achieved. Additionally, our subsidiaries in Argentina are currently working with the Argentine government to include certain outstanding receivables covered under government resolutions into the third Foninvemem Agreement. As of June 30, 2012, the Company had approximately $320 million of trade accounts receivable related to the Foninvemem Agreements and government resolutions classified as other noncurrent assets. See Item 1 — Business — Regulatory Matters — Argentina included in the 2011 Form 10-K for further information on these agreements.

Consolidated Cash Flows

During the six months ended June 30, 2012, cash and cash equivalents increased $23 million to $1.7 billion. The increase in cash and cash equivalents was due to $1.1 billion of cash provided by operating activities, $352 million of cash used for investing activities, $862 million of cash used for financing activities, a favorable effect of foreign currency exchange rates on cash of $3 million and a $120 million decrease in cash of discontinued and held for sale businesses.

Operating Activities — Net cash provided by operating activities decreased $63 million to $1.1 billion during the six months ended June 30, 2012 compared to $1.2 billion during the six months ended June 30, 2011.

Operating cash flow for the six months ended June 30, 2012 resulted primarily from net income adjusted for non-cash items, principally depreciation and amortization, deferred income taxes, gains and losses on sales and disposals and impairment charges, partially offset by changes in operating assets and liabilities. The net change in operating assets and liabilities consumed $269 million of operating cash flow. Other assets used $293 million primarily due to an increase in long term regulatory assets at Eletropaulo as a result of the high price and volume of energy purchases and regulatory charges to be recovered in future tariffs and the establishment of a long term note receivable at Cartagena in Spain following the arbitration settlement. Income taxes and other income tax payables consumed $249 million primarily due to the payment of income taxes in excess of accruals for new current tax liabilities. Accounts receivable consumed $175 million primarily due to lower collection rates at Maritza, Sonel and Itabo. These uses of operating cash flows were offset by a contribution of $245 million from

an increase in other liabilities primarily explained by long term regulatory liabilities at Eletropaulo related to the tariff reset discussed in the gross margin analysis above. Accounts payable and other current liabilities contributed $228 million primarily at Eletropaulo due to an increase in short term regulatory liabilities driven by the tariff reset, offset by a decrease in other current liabilities arising from value added tax payments.

Net cash provided by operating activities was $1.2 billion during the six months ended June 30, 2011. Operating cash flow resulted primarily from net income adjusted for non-cash items, principally depreciation and amortization, contingencies, deferred income taxes, gains and losses on sales and disposals and impairment charges, partially offset by a net unfavorable change of $392 million in operating assets and liabilities. Accounts payable and other current liabilities consumed $254 million primarily due to decreases in short term regulatory liabilities and other current liabilities at Eletropaulo mainly due to the reimbursement to customers of prior period costs and decreases in liabilities at Gener due to reduced power purchases following a modification of an affiliate PPA. Accounts receivable used $182 million driven by a lower collections rate at Eletropaulo and an increase in revenue at several generation businesses including new plants at Maritza and Angamos. Income taxes and other income tax payables consumed $152 million primarily due to the payment of income taxes in excess of accruals for new tax liabilities. These uses of operating cash flows were offset by contributions arising from an increase of $178 million in other liabilities and a decrease of $149 million in prepaid expenses and other current assets. The increase in other liabilities was mainly explained by long-term regulatory liabilities increasing as the result of lower prices paid for energy purchases and transmission costs compared with the ones recovered through the current tariff at Eletropaulo and at Sul, and accruals for other amounts to be reimbursed to customers through future tariffs at Eletropaulo. The decrease in prepaid expenses and other current assets was primarily due to decreases in short term regulatory assets at Eletropaulo, reflecting the recovery of prior period energy purchases and regulatory charges.

This net decrease of cash flows from continuing operations of $63 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011 was primarily the result of the following:

•

a decrease of $357 million at our utility businesses in Latin America primarily in Brazil due to higher priced energy purchases and regulatory charges paid, including an increase in related other current assets, partially offset by higher collections due to higher sales and lower interest paid by Brasiliana on reduced debt balances. The decrease in gross margin at Eletropaulo attributable to the tariff reset as discussed in the revenue and gross margin analysis did not impact current period operating cash flows but will impact operating cash flows in the future; offset by

•

an increase of $164 million at our utility businesses in North America primarily due to the operations, net of debt service costs, of DPL, which was acquired in November 2011;

•

an increase of $86 million at our generation businesses in Latin America primarily due to higher gross margin at Tiete, resulting from higher sales to Eletropaulo and the spot market and cash provided by the operating activities of the new plant at Angamos in Chile; and

•

an increase of $37 million at our generation businesses in Europe, mainly due to higher energy margins at Kilroot in Northern Ireland and a non-recurring favorable arbitration settlement at Cartagena, partially offset by the elimination of operating cash flows provided by Cartagena due to its sale in the first quarter of 2012, and a loss in revenue from a generator failure at Ballylumford in Northern Ireland. The gain on sale of investment recognized from the sale of a majority of our interest in Cartagena is included in net income in 2012 but is reflected as proceeds from the sale of businesses, net of cash sold, within investing activities.

Investing Activities — Net cash used for investing activities decreased $405 million to $352 million during the six months ended June 30, 2012 compared to net cash used of $757 million during the six months ended June 30, 2011. This net decrease was primarily due to the following:

•

an increase of $324 million in proceeds from the sale of businesses, net of cash sold, primarily due to the sale of Red Oak for $142 million, Ironwood for $84 million, $63 million from the sale of 80% of our interest in Cartagena and $42 million due to the sale of St. Patrick and Innovent;

•

a decrease of $144 million in acquisitions, net of cash acquired, primarily due to the investment in Entek in 2011;

•

a decrease of $118 million in debt service reserves and other assets primarily due to decreases of $58 million at Sonel related to transfer to restricted cash in 2011 and a use of debt service reserve in 2012 for a loan repayment, $30 million at Angamos due to transfer to restricted cash as it commenced operations in June 2011, $14 million at a European wind project due to prepayment of loan in 2012 and $13 million at our Parent Company related to the collateralization in 2012 of a letter of credit for various projects;

•

an increase of $112 million in proceeds from government grants for asset construction primarily due to funds received at our wind projects, $82 million at Laurel Mountain and $30 million at Mountain View 4; partially offset by

•

an increase of $228 million in sale of short-term investments, net of purchases, primarily due to an increase of $234 million at our Brazilian subsidiaries for working capital requirements.

Financing Activities — Net cash used for financing activities increased $1.5 billion to $862 million during the six months ended June 30, 2012 compared to net cash provided by financing of $620 million during the six months ended June 30, 2011. This net increase was primarily due to the following:

•

a $2.1 billion decrease in the proceeds from issuances of recourse debt due to the issuance at the Parent Company to partially fund the acquisition of DPL in 2011;

•

a $435 million decrease in net borrowings under revolving credit facilities primarily due to a $295 million payment in 2012 at the Parent Company as well as decreases of $49 million at Alicura in Argentina, $49 million at IPL and $31 million at Changuinola;

•

a $133 million increase in the purchase of treasury stock under the Company’s common stock repurchase plan in 2012; partially offset by

•

a $906 million decrease in repayments of recourse and non-recourse debt attributable to decreases of $466 million at the Parent Company, $389 million at IPL, $28 million at Sonel, $23 million at Puerto Rico, $17 million at Gener and $17 million at Cartagena, offset by an increase of $19 million at Kribi; and

•

a $136 million decrease in distributions to non-controlling interests primarily due to decreases of $92 million at our Brazilian subsidiaries and $43 million at Gener.

Parent Company Liquidity

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

statements of cash flows. Parent Company liquidity may differ from similarly titled measures used by other companies. The principal sources of liquidity at the Parent Company level are:

•

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

•

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

•

proceeds from asset sales.

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

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interest;

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principal repayments of debt;

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acquisitions;

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construction commitments;

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other equity commitments;

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equity repurchases;

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taxes;

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Parent Company overhead and development costs; and

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dividends on common stock.

The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents,” at June 30, 2012 and December 31, 2011 as follows:


Parent Company Liquidity	June 30, 2012			December 31, 2011
	(in millions)
Consolidated cash and cash equivalents	$	1,727		$	1,704
Less: Cash and cash equivalents at subsidiaries		(1,487	)		(1,504	)

Parent and qualified holding companies’ cash and cash equivalents		240			200

Commitments under Parent credit facilities		800			800
Less: Letters of credit under the credit facilities		(5	)		(12	)
Less: Borrowings under the credit facilities		-			(295	)

Borrowings available under Parent credit facilities		795			493

Total Parent Company Liquidity	$	1,035		$	693

The following table summarizes our Parent Company contingent contractual obligations as of June 30, 2012:


Contingent Contractual Obligations	Amount		Number of Agreements		Maximum Exposure Range for Each Agreement
	(in millions)				(in millions)
Guarantees	$	528		18	<$1 - $219
Letters of credit under the senior secured credit facility		5		9	<$1 - $2
Cash collateralized letters of credit		246		11	<$1 - $209

Total	$	779		38

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

In August 2012, we declared a dividend payable in the fourth quarter of 2012. While we believe we will have sufficient liquidity in future periods, we can provide no assurance we will be able to declare dividends at the amount indicated, if at all.

While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets (see Key Trends and Uncertainties and Global Economic Conditions), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured credit facility. See Item 1A. — Risk Factors, “The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.” of the Company’s 2011 Form 10-K.

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

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limitations on other indebtedness, liens, investments and guarantees;

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limitations on dividends, stock repurchases and other equity transactions;

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

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maintenance of certain financial ratios; and

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financial and other reporting requirements.

As of June 30, 2012, the Parent Company was in compliance with these covenants.

Non-Recourse Debt

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

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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;

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

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

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triggering defaults in our outstanding debt at the Parent Company.

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

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying condensed consolidated balance sheet amounts to $2.3 billion. The portion of current debt related to such defaults was $1.4 billion at June 30, 2012, all of which was non-recourse debt related to six subsidiaries — Maritza, Sonel, Kribi, Dibamba, Kelanitissa and Saurashtra.

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’s corporate debt agreements as of June 30, 2012 in order for such defaults to trigger an event of default or permit acceleration under AES’s indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities.

Critical Accounting Policies and Estimates

The condensed consolidated financial statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. The Company’s significant accounting policies are described in Note 1 — General and Summary of Significant Accounting Policies to the consolidated financial statements included in the June 2012 Form 8-K. The Company’s critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the June 2012 Form 8-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed

are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods.

The Company has reviewed and determined that those policies remain the Company’s critical accounting policies as of and for the six months ended June 30, 2012, with the exception of the revenue recognition policy that has been updated in Note 1 — Financial Statement Presentation included in Item 1. — Financial Statements in this Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks

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

These disclosures set forth in this Item 3 are based upon a number of assumptions; actual impacts to the Company may not follow the assumptions made by the Company. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 3. For further information regarding market risk, see Item 1A. — Risk Factors, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations”, “Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance” and “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” of the 2011 Form 10-K.

Commodity Price Risk

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

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

AES businesses will see variance in variable margin performance as global commodity prices shift. For the remainder of 2012, we project pre-tax earnings exposure would be approximately $10 million for a $10/ton move in coal, $5 million for a $10/barrel move in oil and $20 million for a $1/MMBTU move in natural gas. Our estimates exclude correlation. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed.

Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Generation costs can be directly affected by movements in the price of natural gas, oil and coal. Spot power prices and contract indexation provisions are affected by the same commodity price movements. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. Offsets are not perfectly linear or symmetric. The sensitivities are affected by a number of non-market, or indirect market factors. Examples of these factors include hydrology, energy market supply/demand balances, regional fuel supply issues, regional competition, bidding strategies and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For

instance, certain power plants may reduce dispatch in low market environments limiting downside exposure. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices.

In North America, the Generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. The Utility businesses, IPL and DPL sell power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Given that natural gas-fired generators set power prices for many markets, higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during peak periods. Additionally, at DPL, open access allows our retail customers to switch to alternative suppliers; falling energy prices may increase the rate at which our customers switch to alternative suppliers.

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

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

In Europe, our Kilroot facility operates on a merchant basis. The commodity risk at our Kilroot business is due to dark spread to the extent sales are un-hedged. Natural gas-fired generators set power prices for many periods, so higher natural gas prices expand margins and higher coal prices cause a decline. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods. At our Ballylumford facility, NIAUR, the regulator, has the right to terminate the PPA, which would impact our commodity exposure. Our operations in Turkey are sensitive to the spread between power and natural gas prices, both of which have historically demonstrated a relationship to oil. As a result of these relationships, falling oil prices could compress margins realized at the business.

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

Foreign Exchange Rate Risk

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

We have entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. As of June 30, 2012, assuming a 10% U.S. Dollar appreciation, pre-tax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine Peso, Brazilian Real, Philippine Peso and Euro (the earnings attributable to the subsidiaries exposed to the Cameroonian Franc movements are included under Euro due to the fixed exchange rate of the Cameroonian Franc to the Euro) relative to the U.S. Dollar are projected to decline by approximately $5 million, $10 million, $5 million and $5 million, respectively, for the remainder of 2012. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pre-tax earnings for the remainder of 2012 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges unwound. Additionally, updates to the forecasted pre-tax earnings exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility.

Interest Rate Risks

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

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

As of June 30, 2012, the portfolio’s pre-tax earnings exposure for the remainder of 2012 to a 100 basis point increase in the Argentine Peso, Brazilian Real, Columbian Peso, British Pound, Euro, Indian Rupee, Kazakhstan Tenge, Phillipine Peso, Ukrainian Hryvna, and U.S. Dollar interest rates would be approximately $15 million. This number is based on the impact of a one-time, 100 basis point increase in interest rates on interest expense for the Argentine Peso, Brazilian Real, Columbian Peso, British Pound, Euro, Indian Rupee, Kazakhstan Tenge, Phillipine Peso, Ukrainian Hryvna, and U.S. denominated debt, which is primarily non-recourse financing. The amounts do not take into account the historical correlation between these interest rates.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”) and Interim 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, 2012 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.

AES completed the acquisition of DPL on November 28, 2011. As of and for the six months ended June 30, 2012, DPL’s total assets, total liabilities and net income represented 9%, 11% and 4% of AES’s consolidated total assets, total liabilities and net income, respectively. While AES continues to assess the effectiveness of DPL’s internal control over financial reporting at this time, such internal control over financial reporting has been excluded from management’s formal evaluation of material changes in AES’s disclosure controls and procedures as of June 30, 2012 as permitted by the SEC guidance.

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. 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, 2012.

In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the Fifth District Court found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$1.3 billion ($626 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the Fifth District Court rejected Eletropaulo’s defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro (“AC”) ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the Fifth District Court. Eletropaulo’s subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil were dismissed. Eletrobrás later requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo consented to the appointment of such an expert, subject to a reservation of rights. In February 2010, the Fifth District Court appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization, in accordance with the methodology proposed by Eletrobrás. Pursuant to its reservation of rights, Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo’s arguments and directing the Fifth District Court to proceed accordingly. Eletrobrás has restarted the accounting proceedings at the Fifth District Court, which will proceed in accordance with the AC’s April 2010 decision. The parties are briefing the issues. In the Fifth District Court proceedings, the expert’s conclusions will be subject to the Fifth District Court’s review and approval. If Eletropaulo is determined to be responsible for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo will be required to provide security in the amount of its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the Fifth District Court grants such request, Eletropaulo’s results of operations may be materially adversely affected and, in turn the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the Fifth District Court against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. The parties are disputing the proper venue for the CTEEP lawsuit. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In July 1993, the Public Attorney’s office filed a claim against Eletropaulo, the São Paulo State Government, SABESP (a state-owned company), CETESB (the Environmental Agency of São Paulo State) and DAEE (the Municipal Water and Electric Energy Department) alleging that they were liable for pollution of the

Billings Reservoir as a result of pumping water from the Pinheiros River into the Billings Reservoir. The events in question occurred while Eletropaulo was a state-owned company. An initial lower court decision in 2007 found the parties liable for the payment of approximately R$871 million ($419 million) for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of São Paulo, which reversed the lower court decision. In 2009, the Public Attorney’s Office filed appeals to both the Superior Court of Justice and the Supreme Court and such appeals were answered by Eletropaulo in the fourth quarter of 2009. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of São Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1 million ($482 thousand) as of June 30, 2011, or pay an indemnification amount of approximately R$15 million ($7 million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court’s decision, the case is being remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision.

In August 2001, the Grid Corporation of Orissa, India, now Gridco Ltd. (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and seeking interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. In September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in Orissa Power Generation Corporation Ltd. (“OPGC”), an equity method investment of the Company, and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco’s challenge to the arbitration award is resolved. In June 2010, a 2-to-1 majority of the arbitral

tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. In November 2011, the Indian court rejected Gridco’s June 2008 application for injunctive relief. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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

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

AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment

and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney’s Office then requested an injunction which the judge rejected on September 26, 2008, and the Public Attorney’s office no longer has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a “Technical Cooperation Protocol” pursuant to which they requested a new deadline from FEPAM in order to present a proposal. In March 2008, the State Prosecution office filed a Class Action against AES Florestal, AES Sul and CEEE, requiring an injunction for the removal of the alleged sources of contamination and the payment of an indemnity in the amount of R$6 million ($3 million). The injunction was rejected and the case is in the evidentiary stage awaiting the production of the court’s expert opinion. However, in October 2011, the State Prosecution Office presented a new request to the court of Triunfo for an injunction against Florestal, Sul and CEEE for the removal of the alleged sources of contamination and remediation, and the court granted the injunction against CEEE but did not grant injunctive relief against Florestal or Sul. CEEE appealed such decision, and the State of Rio Grande do Sul Court of Appeals upheld the decision. The above-referenced proposal to FEPAM with respect to containing and remediating the contamination was delivered on April 8, 2008. FEPAM responded by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response, Sul indicated that such step 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 million).

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 February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska, filed a complaint in the U.S. District Court for the Northern District of California against the Company and numerous unrelated companies, claiming that the defendants’ alleged GHG emissions have contributed to alleged global warming which, in turn, allegedly has led to the erosion of the plaintiffs’ alleged land. The plaintiffs assert nuisance and concert of action claims against the Company and the other defendants, and a conspiracy claim against a subset of the other defendants. The plaintiffs seek to recover relocation costs, indicated in the complaint to be from $95 million to $400 million, and other unspecified damages from the defendants. The Company filed a motion to dismiss the case, which the District Court granted in October 2009. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit. The Ninth Circuit heard oral arguments on November 28, 2011, and

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

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

In October 2009, AES Mérida III, S. de R.L. de C.V. (AES Mérida), one of our businesses in Mexico, initiated arbitration against its fuel supplier and electricity offtaker, Comisión Federal de Electricidad (“CFE”), seeking a declaration that CFE breached the parties’ power purchase agreement (“PPA”) by supplying gas that did not comply with the PPA’s specifications. Alternatively, AES Mérida requests a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputes the claims. Although it has not asserted counterclaims, in its closing brief CFE asserts that it is entitled to a partial refund of the capacity charge payments that were made for power generated with the out-of-specification gas. In July 2012, the arbitral Tribunal issued an award in AES Mérida’s favor. It is unclear whether CFE will seek to challenge the award.

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

coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.

In November 2009, April 2010, December 2010, April 2011, June 2011, August 2011, and November 2011, substantially similar personal injury lawsuits were filed by a total of 49 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit, the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The AES defendants moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. The AES defendants again moved for partial dismissal of those amended complaints, and in May 2012, the Superior Court ruled on the motion in the November 2009 lawsuit, dismissing the plaintiff’s claims for future medical monitoring expenses but declining to dismiss their claims under Dominican Republic Law 64-00. The Superior Court has not yet ruled on the motion for partial dismissal of the April 2010 lawsuit. The AES defendants filed an answer to the November 2009 lawsuit in June 2012. The Superior Court has stayed the remaining six lawsuits, as well as any subsequently filed similar lawsuits. The Superior Court has also ordered that, for the present, discovery will proceed only in the November 2009 lawsuit and will be limited to causation and exposure issues. The AES defendants believe they have meritorious defenses and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.

On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns a 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million ($195 million). The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units, allegedly because of the purported characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor’s claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately €240 million ($302 million) in the arbitration, unspecified damages for alleged injury to reputation, and other relief. The arbitral hearing on the merits has been rescheduled and now will take place in March 2013. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

On February 11, 2011 AES Eletropaulo received a notice of violation from São Paulo State’s Environmental Authorities for allegedly destroying 0.32119 hectares of native vegetation at the Conservation Park of Serra do Mar (“Park”), without previous authorization or license. The notice of violation asserted a fine of approximately

R$1 million ($503,687) and the suspension of AES Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities (“São Paulo EA”), AES Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the notice of violation or reduce the fine. In December 2011, the São Paulo EA declined to vacate the notice of violation but recognized the possibility of 40% reduction in the fine if AES Eletropaulo agrees to recover the affected area with additional vegetation. AES Eletropaulo has not appealed the decision and is now discussing the terms of a possible settlement with the São Paulo EA, including a plan to recover the affected area by primarily planting additional trees. In March 2012, the State of São Paulo Prosecutor’s Office of São Bernando do Campo initiated a Civil Proceeding to review the compliance by AES Eletropaulo with the terms of any possible settlement.

In May 2011, a putative class action was filed in the Mississippi federal court against the Company and numerous unrelated companies. The lawsuit alleges that greenhouse gas emissions contributed to alleged global warming which, in turn, allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert claims for public and private nuisance, trespass, negligence, and declaratory judgment. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. These and other plaintiffs previously brought a substantially similar lawsuit in the federal court but failed to obtain relief. In October 2011, the Company and other defendants filed motions to dismiss the lawsuit. In March 2011, the federal court granted the motion and dismissed the lawsuit. The plaintiffs have appealed. The Company believes it has meritorious defenses and will defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.

In June 2011, the São Paulo Municipal Tax Authority (the “Municipality”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking approximately R$1.2 billion ($578 million) in services tax (“ISS”) that allegedly had not been collected on revenues for services rendered by Eletropaulo. In its public records, the Municipality has updated the amount assessed to approximately R$1.9 billion ($1.0 billion). Eletropaulo has challenged the assessments on the ground that the revenues at issue were not subject to ISS. Eletropaulo believes it has meritorious defenses to the assessments and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In June 2011, the Supreme Court rejected federal common law nuisance claims initially brought in 2004 by eight states, the City of New York, and three land trusts, which sought injunctive relief and limitations on the GHG emissions of American Electric Power Company, Inc. (“AEP”), one of AEP’s subsidiaries, Cinergy Corp. (a subsidiary of Duke Energy Corporation (“Duke Energy”)), and four other electric power companies. The Supreme Court remanded the lawsuit for consideration of the plaintiffs’ state law claims. Although it is not named as a party to this lawsuit, DP&L is a co-owner of coal-fired plants with Duke Energy and AEP (or their subsidiaries), which could be affected by the outcome of this lawsuit. DP&L believes that there are meritorious defenses to the plaintiffs’ claims; however, there can be no assurances that the defendants will prevail in this lawsuit.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2011 Form 10-K under Part 1 — Item 1A. — Risk Factors.

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

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


Repurchase Period	Total Number of Shares Purchased			Average Price Paid per Share		Total Number of Shares Repurchased as Part of a Publicly Announced Repurchase Plan⁽¹⁾		Dollar Value of Maximum Number of Shares To Be Purchased Under the Plan⁽¹⁾
4/1/12 - 4/30/12		-		$	-		-	$	302,158,079
5/1/12 - 5/31/12		4,813,930	⁽²⁾	$	12.25		4,772,263	$	243,712,153
6/1/12 - 6/30/12		13,972,100		$	12.30		13,972,100	$	71,879,755

Total		18,786,030		$	12.28		18,744,363

⁽¹⁾	See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program.

⁽²⁾	Includes 41,667 shares purchased by an executive of the Company in May 2012 that were not under the publicly announced stock repurchase program.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION

Chief Financial Officer

On August 1, 2012, the Board of Directors (“Board”) of The AES Corporation (“AES” or the “Company”) approved the appointment of Mr. Thomas O’Flynn as Executive Vice President and Chief Financial Officer of the Company. The appointment is effective as of September 4, 2012 (the “Effective Date”).

Mr. O’Flynn, 52, is a Senior Advisor to the Private Equity Group of Blackstone, an investment and advisory group and has held this position since 2010. Since 2009, Mr. O’Flynn has held the position of Chief Operating Officer and Chief Financial Officer of Transmission Developers, Inc. (TDI), a Blackstone-controlled company that develops innovative power transmission projects in an environmentally responsible manner. Mr. O’Flynn has 25 years of experience in the power and utility industry. From 2001 to 2009, he served as the Chief Financial Officer of PSEG, a New Jersey-based merchant power and utility company. He also served as President of PSEG Energy Holdings from 2007 to 2009. From 1986 to 2001, Mr. O’Flynn was in the Global Power and Utility Group of Morgan Stanley. He served as a Managing Director for his last five years and as Head of the North American Power Group from 2000 to 2001. He was responsible for senior client relationships and led a number of large merger, financing, restructuring and advisory transactions. Mr. O’Flynn has a BA in economics from

Northwestern University and an MBA in Finance from the University of Chicago. Mr. O’Flynn served as a member of the Board of Directors of Nuclear Electric Insurance Limited from 2003 to 2009. He is currently on the Board of Directors of BrightSource Energy and the New Jersey Performing Arts Center.

In connection with his appointment, the Board also approved compensation arrangements for Mr. O’Flynn which shall be in effect on the Effective Date. The new compensation arrangements include the following:

•

Annual Base salary of $650,000;

•

Annual performance incentive plan target opportunity of 100% of then-current base salary, which will be subject to pre-established performance targets;

•

Annual long-term compensation target opportunity of 250% of then-current base salary, which will be subject to AES’ annual review of market compensation data and individual performance; and

•

Equity grants made in connection with his appointment valued at $1 million, which consist of $500,000 in the form of stock options and $500,000 in the form of restricted stock units granted under the Company’s 2003 Long Term Compensation Plan. The options and restricted stock units generally vest ratably over a three-year period with the first vesting date being approximately one year from the award date. The awards are subject to the same terms and conditions in AES’ standard forms of agreements for option and restricted stock unit awards.

Mr. O’Flynn will be eligible for benefits similar to those of existing AES executives, including, without limitation, participation in The AES Corporation Amended and Restated Executive Severance Plan (the “Executive Plan”) effective on the Effective Date as described below.

In connection with the above-reference appointment, as of the Effective Date, Ms. Mary E. Wood will no longer serve as Interim Chief Financial Officer. Ms. Wood will remain Vice-President and Corporate Controller of the Company.

Changes to Participants in the Severance Plans

On August 1, 2012, the Board approved that Messrs. Edward Hall, the Company’s Executive Vice President and Chief Operating Officer — Global Generation, Andrew Vesey, the Company’s Executive Vice President and Chief Operating Officer — Global Utilities, and Brian Miller, the Company’s Executive Vice President, General Counsel and Corporate Secretary, cease participation in The AES Corporation Severance Plan (the “Severance Plan”) and be added, with Mr. O’Flynn as noted above, to the Executive Plan (collectively, the “Officers”). Mr. Andres Gluski, the Company’s President and Chief Executive Officer (the “CEO”), among others, was already a participant in the Executive Plan.

Under the Executive Plan, the Officers will be entitled to certain severance benefits in the event of a qualifying “involuntary termination” (as defined in the Executive Plan) or termination for “good reason” (as defined in the Executive Plan) in connection with a “change in control” (as defined in the Executive Plan) of the Company (each a “Qualifying Termination”):

•

One times base salary and target bonus for the year of termination in the event of an involuntary termination unrelated to a change in control (if the Officer executes a general release of claims against the Company);

•

In the event of a Qualifying Termination in connection with a change in control, each Officer will receive two times base salary and target bonus for the year of termination (if the Officer executes a general release of claims against the Company);

•

Health benefits for up to 12 months (in the event of a Qualifying Termination in connection with a change in control, each Officer will receive up to 18 months of health benefits);

•

Accrued amounts;

•

Outplacement assistance;

•

Prorated bonus for the year of termination;

•

No excise tax gross-up in the event of a Qualifying Termination in connection with a change in control of the Company. Under the Severance Plan, certain Officers were entitled to excise tax gross-up payments in the event of a qualifying termination of employment in connection with a change in control. The Executive Plan does not provide for the payment of excise tax gross-up payments by AES. The benefits schedules of the Executive Plan provide that any payments due to the CEO and Officers upon a change in control of the Company will be reduced to the extent necessary to avoid such excise taxes, unless it is determined that the net after tax benefits to such participant would be greater if such reductions were not imposed;

•

The Executive Plan includes that, in order to receive benefits under the Executive Plan, each participant adhere to confidentiality and non-disparagement obligations and generally provides that during employment and for 12 months following employment with the Company and its subsidiaries, such participants will not compete with AES or solicit its employees, customers, suppliers and other persons set forth therein.

The foregoing description of the Executive Plan and the Officers’ rights and benefits thereunder does not purport to be complete and is qualified in its entirety by reference to the Executive Plan (Exhibit 10.1 to this Quarterly Report on Form 10-Q) and incorporated herein by reference.

ITEM 6. EXHIBITS


10.1		Separation Agreement, dated April 27, 2012, between the Company and Victoria D. Harker (filed herewith)

10.2		The AES Corporation Amended and Restated Executive Severance Plan, dated August 1, 2012 (filed herewith)

31.1		Rule13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith)

31.2		Rule 13a-14(a)/15d-14(a) Certification of Mary E. Wood (filed herewith)

32.1		Section 1350 Certification of Andrés Gluski (filed herewith)

32.2		Section 1350 Certification of Mary E. Wood (filed herewith)

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

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


	THE AES CORPORATION (Registrant)

Date: August 3, 2012	By:	/s/ MARY E. WOOD
		Name:	Mary E. Wood
		Title:	Vice President and Controller (Principal Accounting Officer), and Interim Chief Financial Officer (Principal Financial Officer)