Edgar Filing: AES CORP

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

Q2 2013 Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

______________________________________________________________________________________________

FORM 10-Q

(Mark One)



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

For the Quarterly Period Ended June 30, 2013



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

Commission file number 1-12291

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 August 2, 2013 was 741,577,577.

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2013

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	27

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	61

ITEM 4.	CONTROLS AND PROCEDURES	63

PART II: OTHER INFORMATION		64

ITEM 1.	LEGAL PROCEEDINGS	64

ITEM 1A.	RISK FACTORS	70

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	70

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	70

ITEM 4.	MINE SAFETY DISCLOSURES	70

ITEM 5.	OTHER INFORMATION	70

ITEM 6.	EXHIBITS	71

SIGNATURES		72

PART I: FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

THE AES CORPORATION

Condensed Consolidated Balance Sheets

(Unaudited)



	June 30, 2013			December 31, 2012
	(in millions, except share and per share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,611		$	1,966
Restricted cash	765			748
Short-term investments	703			696
Accounts receivable, net of allowance for doubtful accounts of $287 and $306, respectively	2,417			2,671
Inventory	763			766
Deferred income taxes	207			222
Prepaid expenses	187			230
Other current assets	1,157			1,103
Current assets of discontinued operations and held for sale assets	—			63
Total current assets	7,810			8,465
NONCURRENT ASSETS
Property, Plant and Equipment:
Land	957			1,007
Electric generation, distribution assets and other	32,058			31,656
Accumulated depreciation	(9,747		)	(9,645		)
Construction in progress	2,600			2,783
Property, plant and equipment, net	25,868			25,801
Other Assets:
Investments in and advances to affiliates	1,177			1,196
Debt service reserves and other deposits	495			565
Goodwill	1,999			1,999
Other intangible assets, net of accumulated amortization of $200 and $276, respectively	408			429
Deferred income taxes	896			996
Other noncurrent assets	2,183			2,240
Noncurrent assets of discontinued operations and held for sale assets	—			139
Total other assets	7,158			7,564
TOTAL ASSETS	$	40,836		$	41,830
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,622		$	2,631
Accrued interest	275			295
Accrued and other liabilities	2,335			2,505
Non-recourse debt, including $287 and $282, respectively, related to variable interest entities	2,923			2,829
Recourse debt	118			11
Current liabilities of discontinued operations and held for sale businesses	—			48
Total current liabilities	8,273			8,319
NONCURRENT LIABILITIES
Non-recourse debt, including $1,172 and $1,076, respectively, related to variable interest entities	12,476			12,554
Recourse debt	5,553			5,951
Deferred income taxes	1,195			1,237
Pension and other post-retirement liabilities	2,203			2,455
Other noncurrent liabilities	3,251			3,705
Noncurrent liabilities of discontinued operations and held for sale businesses	—			17
Total noncurrent liabilities	24,678			25,919
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; 812,248,090 issued and 745,144,098 outstanding at June 30, 2013 and 810,679,839 issued and 744,263,855 outstanding at December 31, 2012)	8			8
Additional paid-in capital	8,481			8,525
Accumulated deficit	(15		)	(264		)
Accumulated other comprehensive loss	(2,939		)	(2,920		)
Treasury stock, at cost (67,103,992 shares at June 30, 2013 and 66,415,984 shares at December 31, 2012)	(786		)	(780		)
Total AES Corporation stockholders’ equity	4,749			4,569
NONCONTROLLING INTERESTS	3,058			2,945
Total equity	7,807			7,514
TOTAL LIABILITIES AND EQUITY	$	40,836		$	41,830

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,
	2013			2012			2013			2012
	(in millions, except per share amounts)
Revenue:
Regulated	$	2,093		$	2,105		$	4,339		$	4,589
Non-Regulated	1,975			1,984			3,994			4,086
Total revenue	4,068			4,089			8,333			8,675
Cost of Sales:
Regulated	(1,738		)	(1,869		)	(3,632		)	(3,925		)
Non-Regulated	(1,412		)	(1,527		)	(3,028		)	(2,985		)
Total cost of sales	(3,150		)	(3,396		)	(6,660		)	(6,910		)
Gross margin	918			693			1,673			1,765
General and administrative expenses	(59		)	(74		)	(120		)	(161		)
Interest expense	(346		)	(384		)	(723		)	(800		)
Interest income	63			82			129			173
Loss on extinguishment of debt	(165		)	—			(212		)	—
Other expense	(18		)	(15		)	(46		)	(43		)
Other income	13			14			81			32
Gain on sale of investments	20			5			23			184
Asset impairment expense	—			(18		)	(48		)	(28		)
Foreign currency transaction losses	(17		)	(101		)	(49		)	(102		)
Other non-operating expense	—			(1		)	—			(50		)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES	409			201			708			970
Income tax expense	(81		)	(75		)	(163		)	(343		)
Net equity in earnings of affiliates	2			11			6			24
INCOME FROM CONTINUING OPERATIONS	330			137			551			651
Income (loss) from operations of discontinued businesses, net of income tax (benefit) expense of $1, $3, $0, and $5, respectively	—			(5		)	14			1
Net gain (loss) from disposal and impairments of discontinued businesses, net of income tax (benefit) expense of $(1), $61, $(2), and $61, respectively	3			75			(33		)	70
NET INCOME	333			207			532			722
Noncontrolling interests:
Less: Income from continuing operations attributable to noncontrolling interests	(166		)	(67		)	(281		)	(240		)
Less: Income from discontinued operations attributable to noncontrolling interests	—			—			(2		)	(1		)
Total net income attributable to noncontrolling interests	(166		)	(67		)	(283		)	(241		)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	167		$	140		$	249		$	481
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	164		$	70		$	270		$	411
Income (loss) from discontinued operations, net of tax	3			70			(21		)	70
Net income	$	167		$	140		$	249		$	481
BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.22		$	0.09		$	0.36		$	0.54
Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax	—			0.09			(0.03		)	0.09
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.22		$	0.18		$	0.33		$	0.63
DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.22		$	0.09		$	0.36		$	0.54
Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax	—			0.09			(0.03		)	0.09
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.22		$	0.18		$	0.33		$	0.63
DIVIDENDS DECLARED PER COMMON SHARE	$	0.08		$	—		$	0.08		$	—

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,
	2013			2012			2013			2012
	(in millions)
NET INCOME	$	333		$	207		$	532		$	722
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax (expense) benefit of $0, $0, $1 and $0, respectively	(1		)	1			(1		)	1
Reclassification to earnings, net of income tax (expense) benefit of $0, $0, $0 and $0, respectively	1			(1		)	1			(1		)
Total change in fair value of available-for-sale securities	—			—			—			—
Foreign currency translation activity:
Foreign currency translation adjustments, net of income tax (expense) benefit of $2, $2, $2 and $1, respectively	(226		)	(383		)	(258		)	(241		)
Reclassification to earnings, net of income tax (expense) benefit of $0, $0, $0 and $0, respectively	44			(2		)	41			(3		)
Total foreign currency translation adjustments	(182		)	(385		)	(217		)	(244		)
Derivative activity:
Change in derivative fair value, net of income tax (expense) benefit of $(28), $24, $(28) and $20, respectively	102			(133		)	86			(112		)
Reclassification to earnings, net of income tax (expense) benefit of $(15), $(5), $(22) and $(33), respectively	61			40			85			126
Total change in fair value of derivatives	163			(93		)	171			14
Pension activity:
Reclassification to earnings due to amortization of net actuarial loss, net of income tax (expense) benefit of $(7), $(3), $(14) and $(6), respectively	13			7			27			13
Total pension adjustments	13			7			27			13
OTHER COMPREHENSIVE (LOSS)	(6		)	(471		)	(19		)	(217		)
COMPREHENSIVE INCOME (LOSS)	327			(264		)	513			505
Less: Comprehensive (income) loss attributable to noncontrolling interests	(147		)	114			(283		)	(131		)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	$	180		$	(150	)	$	230		$	374

See Notes to Condensed Consolidated Financial Statements.

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)



	Six Months Ended June 30,
	2013			2012
	(in millions)
OPERATING ACTIVITIES:
Net income	$	532		$	722
Adjustments to net income:
Depreciation and amortization	661			706
Gain from sale of investments and impairment expense	46			(71		)
Deferred income taxes	(46		)	72
Provisions for contingencies	36			35
Loss on the extinguishment of debt	212			—
(Gain) loss on disposals and impairments - discontinued operations	31			(131		)
Other	23			50
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable	191			(175		)
(Increase) decrease in inventory	(12		)	(43		)
(Increase) decrease in prepaid expenses and other current assets	55			18
(Increase) decrease in other assets	(147		)	(293		)
Increase (decrease) in accounts payable and other current liabilities	(252		)	228
Increase (decrease) in income tax payables, net and other tax payables	(134		)	(249		)
Increase (decrease) in other liabilities	(11		)	245
Net cash provided by operating activities	1,185			1,114
INVESTING ACTIVITIES:
Capital expenditures	(866		)	(1,071		)
Acquisitions - net of cash acquired	(3		)	(13		)
Proceeds from the sale of businesses, net of cash sold	135			332
Proceeds from the sale of assets	43			2
Sale of short-term investments	2,311			3,605
Purchase of short-term investments	(2,381		)	(3,261		)
Decrease (increase) in restricted cash	14			(73		)
Decrease in debt service reserves and other assets	18			26
Proceeds from government grants for asset construction	1			117
Other investing	22			(16		)
Net cash used in investing activities	(706		)	(352		)
FINANCING ACTIVITIES:
Borrowings (repayments) under the revolving credit facilities, net	33			(310		)
Issuance of recourse debt	750			—
Issuance of non-recourse debt	2,383			579
Repayments of recourse debt	(1,206		)	(5		)
Repayments of non-recourse debt	(2,169		)	(328		)
Payments for financing fees	(127		)	(17		)
Distributions to noncontrolling interests	(211		)	(578		)
Contributions from noncontrolling interests	76			12
Dividends paid on AES common stock	(60		)	—
Financed capital expenditures	(257		)	(12		)
Purchase of treasury stock	(18		)	(231		)
Other financing	7			28
Net cash used in financing activities	(799		)	(862		)
Effect of exchange rate changes on cash	(39		)	3
Decrease in cash of discontinued and held for sale businesses	4			97
Total decrease in cash and cash equivalents	(355		)	—
Cash and cash equivalents, beginning	1,966			1,688
Cash and cash equivalents, ending	$	1,611		$	1,688
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	700		$	783
Cash payments for income taxes, net of refunds	$	432		$	525

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, 2013 and 2012

1. FINANCIAL STATEMENT PRESENTATION

The prior-period condensed consolidated financial statements in this Quarterly Report on Form 10-Q (“Form 10-Q”) have been reclassified to reflect the businesses held for sale and discontinued operations as discussed in Note 14 — Discontinued Operations and Held for Sale Businesses.

Consolidation

In this Quarterly Report the terms “AES,” “the Company,” “us” or “we” refer to the consolidated entity including its subsidiaries and affiliates. The terms “The AES Corporation,” “the Parent” or “the Parent Company” refer only to the publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates. Furthermore, variable interest entities (“VIEs”) in which the Company has 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.

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, 2013 are not necessarily indicative of results that may be expected for the year ending December 31, 2013. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2012 audited consolidated financial statements and notes thereto, which are included in the 2012 Form 10-K filed with the SEC on February 26, 2013 (the “2012 Form 10-K”).

Accounting Pronouncements Issued But Not Yet Effective

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

ASU No. 2013-11, Income Taxes (Topic 740), "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (a consensus of the FASB Emerging Issues Task Force)."

In July 2013, the FASB issued ASU No. 2013-11, which requires the netting of unrecognized tax benefits (“UTBs”) against a deferred tax asset for a loss or other carryforward that would apply in settlement of uncertain tax positions. Under the new standard, UTBs will be netted against all available same-jurisdiction loss or other tax carryforwards that would be utilized, rather than only against carryforwards that are created by the UTBs. ASU No. 2013-11 is effective for annual reporting periods beginning after December 15, 2013 and interim periods therein. The new standard requires prospective adoption, but allows optional retrospective adoption. Early adoption is permitted. The Company is currently evaluating the method of adoption and the impact of adopting ASU No. 2013-11 on the Company's financial position. It will have no impact on the results of operations and cash flows.

ASU No. 2013-7, Presentation of Financial Statements (Topic 205), "Liquidation Basis of Accounting"

In April 2013, the FASB issued ASU No. 2013-7, which requires an entity to prepare financial statements on a liquidation basis when liquidation is imminent, unless the liquidation is the same as the plan specified in an entity's governing documents created at its inception. Under the liquidation basis of accounting, an entity will measure and present assets at the estimated amount of cash proceeds or other consideration that it expects to collect in settling or disposing of those assets in carrying out its plan for liquidation. This includes assets the entity previously had not recognized under U.S. GAAP, but expects to either sell in liquidation or use in settling liabilities (for example, trademarks). An entity will recognize and measure its liabilities in accordance with U.S. GAAP that otherwise applies to those liabilities. An entity should not anticipate it will be legally released from being the primary obligor under those liabilities, either judicially or by creditors. An entity will also accrue and separately present the costs it expects to incur and the income it expects to earn during the course of the liquidation, including any costs

associated with the disposal or settlement of its assets and liabilities. ASU No. 2013-7 also requires additional disclosures. ASU No. 2013-7 is effective for annual reporting periods beginning after December 15, 2013. Early adoption is permitted. The adoption of ASU No, 2013-7 is not expected to have a significant impact on the Company's consolidated financial position, results of operations and cash flows.

ASU No. 2013-5, Foreign Currency Matters (Topic 830), “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity.”

In March 2013, the FASB issued ASU No. 2013-5, which requires an entity to release any related cumulative translation adjustment into net income when it ceases to have a controlling financial interest in a subsidiary or group of assets that is a business (other than a sale of in-substance real estate) within a foreign entity. Accordingly, the cumulative translation adjustment should be released into net income only if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided. For an equity method investment that is a foreign entity, the partial sale guidance still applies. As such, a pro rata portion of the cumulative translation adjustment should be released into net income upon a partial sale of such an equity method investment. In those instances, the cumulative adjustment is released into net income only if the partial sale represents a complete or substantially complete liquidation of the foreign entity that contains the equity method investment. The amendments are effective prospectively for fiscal years (and interim reporting periods within those years) beginning after December 15, 2013. Early adoption is permitted. The Company is currently evaluating the impact of adopting ASU No. 2013-5 on the Company’s financial position and results of operations.

2. INVENTORY

The following table summarizes the Company’s inventory balances as of June 30, 2013 and December 31, 2012:



	June 30, 2013		December 31, 2012
	(in millions)
Coal, fuel oil and other raw materials	$	363	$	373
Spare parts and supplies	400		393
Total	$	763	$	766

3. FAIR VALUE

The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The estimated fair value 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. There were no changes in fair valuation techniques during the period and the Company continues to follow the valuation techniques described in Note 4. — Fair Value in Item 8. — Financial Statements and Supplementary Data of its 2012 Form 10-K.

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, 2013 and December 31, 2012:



	June 30, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)
Assets
AVAILABLE-FOR-SALE:⁽¹⁾
Debt securities:
Unsecured debentures	$	—	$	415	$	—	$	415	$	—	$	448	$	—	$	448
Certificates of deposit	—		196		—		196		—		143		—		143
Government debt securities	—		25		—		25		—		34		—		34
Subtotal	—		636		—		636		—		625		—		625
Equity securities:
Mutual funds	—		52		—		52		—		56		—		56
Subtotal	—		52		—		52		—		56		—		56
Total available-for-sale	—		688		—		688		—		681		—		681
TRADING:
Equity securities:
Mutual funds	13		—		—		13		12		—		—		12
Total trading	13		—		—		13		12		—		—		12
DERIVATIVES:
Interest rate derivatives	—		40		—		40		—		2		—		2
Cross currency derivatives	—		5		—		5		—		6		—		6
Foreign currency derivatives	—		26		78		104		—		2		79		81
Commodity derivatives	—		27		12		39		—		8		3		11
Total derivatives	—		98		90		188		—		18		82		100
TOTAL ASSETS	$	13	$	786	$	90	$	889	$	12	$	699	$	82	$	793
Liabilities
DERIVATIVES:
Interest rate derivatives	$	—	$	326	$	63	$	389	$	—	$	153	$	412	$	565
Cross currency derivatives	—		8		—		8		—		6		—		6
Foreign currency derivatives	—		16		8		24		—		7		7		14
Commodity derivatives	—		17		68		85		—		13		59		72
Total derivatives	—		367		139		506		—		179		478		657
TOTAL LIABILITIES	$	—	$	367	$	139	$	506	$	—	$	179	$	478	$	657

_____________________________


⁽¹⁾	Amortized cost approximated fair value at June 30, 2013 and December 31, 2012.

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, 2013 and 2012 (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). Transfers between Level 3 and Level 2 are determined as of the end of the reporting period and principally result from changes in the significance of unobservable inputs used to calculate the credit valuation adjustment.



	Three Months Ended June 30, 2013
	Interest Rate			Foreign Currency			Commodity			Total
	(in millions)
Balance at April 1	$	(72	)	$	71		$	(68	)	$	(69	)
Total gains (losses) (realized and unrealized):
Included in earnings	(4		)	9			—			5
Included in other comprehensive income	13			—			—			13
Included in regulatory (assets) liabilities	—			—			11			11
Settlements	4			(1		)	1			4
Transfers of assets (liabilities) into Level 3	(42		)	—			—			(42		)
Transfers of (assets) liabilities out of Level 3	38			(9		)	—			29
Balance at June 30	$	(63	)	$	70		$	(56	)	$	(49	)
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	$	—		$	11		$	1		$	12



	Three Months Ended June 30, 2012
	Interest Rate			Foreign Currency			Commodity			Total
	(in millions)
Balance at April 1	$	(124	)	$	48		$	(46	)	$	(122	)
Total gains (losses) (realized and unrealized):
Included in earnings	—			—			(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	(105		)	—			—			(105		)
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	)



	Six Months Ended June 30, 2013
	Interest Rate			Foreign Currency			Commodity			Total
	(in millions)
Balance at January 1	$	(412	)	$	73		$	(57	)	$	(396	)
Total gains (losses) (realized and unrealized):
Included in earnings	(4		)	8			(11		)	(7		)
Included in other comprehensive income	83			—			—			83
Included in regulatory (assets) liabilities	—			—			10			10
Settlements	48			(2		)	2			48
Transfers of assets (liabilities) into Level 3	—			—			—			—
Transfers of (assets) liabilities out of Level 3	222			(9		)	—			213
Balance at June 30	$	(63	)	$	70		$	(56	)	$	(49	)
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	$	—		$	7		$	(9	)	$	(2	)



	Six Months Ended June 30, 2012
	Interest Rate			Cross Currency			Foreign Currency			Commodity			Total
	(in millions)
Balance at January 1	$	(128	)	$	(18	)	$	51		$	(53	)	$	(148	)
Total gains (losses) (realized and unrealized):
Included in earnings	(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	(146		)	—			—			—			(146		)
Transfers of (assets) liabilities out of Level 3	—			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	)

The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) as of June 30, 2013:



Type of Derivative	Fair Value			Unobservable Input	Amount or Range (Weighted Average)
	(in millions)
Interest rate	$	(63	)	Subsidiaries’ credit spreads	3.13% - 5.95% (4.47%)
Foreign currency:
Embedded derivative — Argentine Peso	77			Argentine Peso to U.S. Dollar currency exchange rate after 3 years	18.15 - 31.85 (25.68)
Other	(7		)
Commodity:
Embedded derivative — Aluminum	(65		)	Market price of power for customer in Cameroon (per KWh)	$0.06 - $0.14 ($0.12)
Other	9
Total	$	(49	)

Nonrecurring Measurements

When evaluating impairment of long-lived assets, discontinued operations and held for sale businesses, and equity method investments the Company measures fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value of asset groups at the evaluation date to their carrying amount. 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, 2013
	Carrying Amount		Fair Value						Gross Loss
	Carrying Amount		Level 1		Level 2		Level 3		Gross Loss
	(in millions)
Assets
Long-lived assets held and used:⁽¹⁾
Beaver Valley	$	61	$	—	$	—	$	15	$	46
Long-lived assets held for sale:⁽¹⁾
Wind turbines	25		—		25		—		—
Discontinued operations and held for sale businesses:⁽²⁾
Ukraine utilities	143		—		113		—		34



	Six Months Ended June 30, 2012
	Carrying Amount		Fair Value						Gross Loss
	Carrying Amount		Level 1		Level 2		Level 3		Gross Loss
	(in millions)
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	205		—		155		—		50

_____________________________


⁽¹⁾	See Note 13 — Asset Impairment Expense for further information.


⁽²⁾	See Note 14 — Discontinued Operations and Held For Sale Businesses for further information. Also, the gross loss equals the carrying amount of the disposal group less its fair value less costs to sell.

The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets during the six months ended June 30, 2013:



	Fair Value		Valuation Technique	Unobservable Input	Range (Weighted Average)
	(in millions)				($ in millions)
Long-lived assets held and used:
Beaver Valley	$	15	Discounted cash flow	Annual revenue growth	3% to 45% (19%)
				Annual pretax operating margin	-42% to 41% (25%)
				Weighted-average cost of capital	7	%

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

The following table sets forth the carrying amount, fair value and fair value hierarchy 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, 2013 and December 31, 2012, but for which fair value is disclosed.



	Carrying Amount		Fair Value
	Carrying Amount		Total		Level 1		Level 2		Level 3
	(in millions)
June 30, 2013
Assets
Accounts receivable — noncurrent⁽¹⁾	$	300	$	163	$	—	$	—	$	163
Liabilities
Non-recourse debt	15,399		16,394		—		14,096		2,298
Recourse debt	5,671		6,032		—		6,032		—
December 31, 2012
Assets
Accounts receivable — noncurrent⁽¹⁾	$	304	$	188	$	—	$	—	$	188
Liabilities
Non-recourse debt	15,383		16,110		—		13,811		2,299
Recourse debt	5,962		6,628		—		6,628		—

_____________________________


⁽¹⁾	These accounts receivable principally relate to amounts due from the independent system operator in Argentina and are included in “Noncurrent assets — Other” in the accompanying condensed consolidated balance sheets. The fair value of these accounts receivable excludes value-added tax of $52 million and $55 million at June 30, 2013 and December 31, 2012, respectively.

4. INVESTMENTS IN MARKETABLE SECURITIES

The Company’s investments in marketable debt and equity securities as of June 30, 2013 and December 31, 2012 by security class and by level within the fair value hierarchy have been disclosed in Note 3 — Fair Value. 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. As of June 30, 2013, all available-for-sale debt securities had stated maturities within one year.

The following table summarizes the pretax gains and losses related to available-for-sale and trading securities for the three and six months ended June 30, 2013 and 2012. Gains and losses on the sale of investments are determined using the specific identification method. For the three and six months ended June 30, 2013 and 2012, 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,
	2013		2012		2013		2012
	(in millions)
Gains included in earnings that relate to trading securities held at the reporting date	$	—	$	—	$	1	$	—
Unrealized gains on available-for-sale securities included in other comprehensive income	1		—		1		—
Gains reclassified out of other comprehensive income into earnings	1		—		1		—
Gross proceeds from sales of available-for-sale securities	619		2,080		2,323		3,603
Gross realized gains on sales	—		1		—		1

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

There have been no changes to the information disclosed under “Derivatives and Hedging Activities” in Note 1 — General and Summary of Significant Accounting Policies included in Item 8. — Financial Statements and Supplementary Data in the 2012 Form 10-K.

Volume of Activity

The following tables set forth, by type of derivative, the Company’s outstanding notional under its derivatives and the weighted-average remaining term as of June 30, 2013 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:



	Current			Maximum
Interest Rate and Cross Currency	Derivative Notional	Derivative Notional Translated to USD		Derivative Notional	Derivative Notional Translated to USD		Weighted- Average Remaining Term	% of Debt Currently Hedged by Index⁽²⁾
	(in millions)						(in years)
Interest Rate Derivatives:⁽¹⁾
LIBOR (U.S. Dollar)	3,539	$	3,539	5,043	$	5,043	9	73	%
EURIBOR (Euro)	591	769		592	770		13	65	%
LIBOR (British Pound)	68	104		68	104		7	83	%
Cross Currency Swaps:
Chilean Unidad de Fomento	6	252		6	252		8	85	%

_____________________________

⁽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, 2013 and the maturity of the derivative instrument, which includes forward-starting derivative instruments. The interest rate and cross currency derivatives range in maturity through 2030 and 2028, respectively.


⁽²⁾	The percentage of variable-rate debt currently hedged is based on the related index and excludes forecasted issuances of debt and variable-rate debt tied to other indices where the Company has no interest rate derivatives.



	June 30, 2013
Foreign Currency Derivatives	Notional⁽¹⁾	Notional Translated to USD		Weighted- Average Remaining Term⁽²⁾
	(in millions)			(in years)
Foreign Currency Options and Forwards:
Chilean Unidad de Fomento	6	$	255	1
Chilean Peso	46,233	91		<1
Brazilian Real	104	47		<1
Euro	35	45		<1
Colombian Peso	179,416	97		<1
Argentine Peso	83	15		<1
British Pound	28	43		<1
Embedded Foreign Currency Derivatives:
Argentine Peso	821	152		11
Kazakhstani Tenge	811	5		4
Euro	1	2		10

_____________________________


⁽¹⁾	Represents contractual notionals. The notionals for options have not been probability adjusted, which generally would decrease them.


⁽²⁾	Represents the remaining tenor of our foreign currency derivatives weighted by the corresponding notional. These options and forwards and these embedded derivatives range in maturity through 2016 and 2026, respectively.



	June 30, 2013
Commodity Derivatives	Notional	Weighted-Average Remaining Term⁽¹⁾
	(in millions)	(in years)
Aluminum (MWh)⁽²⁾	13	7
Power (MWh)	9	2

_____________________________


⁽¹⁾	Represents the remaining tenor of our commodity derivatives weighted by the corresponding volume. These derivatives range in maturity through 2019.


⁽²⁾	Our exposure is to fluctuations in the price of aluminum while the notional is based on the amount of power we sell under the power purchase agreement ("PPA").

Accounting and Reporting

Assets and Liabilities

The following tables set forth the Company’s derivative instruments as of June 30, 2013 and December 31, 2012, first by whether or not they are designated hedging instruments, then by whether they are current or noncurrent to the extent they are subject to master netting agreements or similar agreements (where the rights to set-off relate to settlement of amounts receivable and payable under those derivatives) and by balances no longer accounted for as derivatives.



	June 30, 2013						December 31, 2012
	Designated		Not Designated		Total		Designated		Not Designated		Total
	(in millions)
Assets
Interest rate derivatives	$	38	$	2	$	40	$	—	$	2	$	2
Cross currency derivatives	5		—		5		6		—		6
Foreign currency derivatives	10		94		104		—		81		81
Commodity derivatives	7		32		39		2		9		11
Total assets	$	60	$	128	$	188	$	8	$	92	$	100
Liabilities
Interest rate derivatives	$	374	$	15	$	389	$	544	$	21	$	565
Cross currency derivatives	8		—		8		6		—		6
Foreign currency derivatives	15		9		24		7		7		14
Commodity derivatives	10		75		85		8		64		72
Total liabilities	$	407	$	99	$	506	$	565	$	92	$	657



	June 30, 2013						December 31, 2012
	Assets			Liabilities			Assets			Liabilities
	(in millions)
Current	$	50		$	182		$	14		$	186
Noncurrent	138			324			86			471
Total	$	188		$	506		$	100		$	657
Derivatives subject to master netting agreement or similar agreement:
Gross (which equals net) amounts recognized in the balance sheet	$	82		$	392		$	25		$	522
Gross amounts of derivative instruments not offset	(16		)	(16		)	(9		)	(9		)
Gross amounts of cash collateral received/pledged not offset	—			(5		)	—			(5		)
Net amount	$	66		$	371		$	16		$	508
Other balances that had been, but are no longer, accounted for as derivatives that are to be amortized to earnings over the remaining term of the associated PPA	$	177		$	190		$	186		$	191

Effective Portion of Cash Flow Hedges

The following tables set forth the pretax 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 (including amounts that were reclassified from AOCL as interest expense related to interest rate derivative instruments that previously, but no longer, qualify for cash flow hedge accounting), as defined in the accounting standards for derivatives and hedging, for the three and six months ended June 30, 2013 and 2012:



	Gains (Losses) Recognized in AOCL							Gains (Losses) Reclassified from AOCL into Earnings
	Three Months Ended June 30,						Classification in Condensed Consolidated Statements of Operations	Three Months Ended June 30,
Type of Derivative	2013			2012				2013			2012
	(in millions)							(in millions)
Interest rate derivatives	$	134		$	(153	)	Interest expense	$	(31	)	$	(30	)
							Non-regulated cost of sales	(1		)	(1		)
							Net equity in earnings of affiliates	(2		)	(1		)
							Gain on sale of investments	(21		)	(4		)
Cross currency derivatives	(12		)	(9		)	Interest expense	(3		)	(3		)
							Foreign currency transaction gains (losses)	(19		)	(6		)
Foreign currency derivatives	1			6			Foreign currency transaction gains (losses)	2			—
Commodity derivatives	7			(1		)	Non-regulated revenue	(1		)	—
Total	$	130		$	(157	)		$	(76	)	$	(45	)



	Gains (Losses) Recognized in AOCL							Gains (Losses) Reclassified from AOCL into Earnings
	Six Months Ended June 30,						Classification in Condensed Consolidated Statements of Operations	Six Months Ended June 30,
Type of Derivative	2013			2012				2013			2012
	(in millions)							(in millions)
Interest rate derivatives	$	121		$	(142	)	Interest expense	$	(63	)	$	(62	)
							Non-regulated cost of sales	(2		)	(3		)
							Net equity in earnings of affiliates	(4		)	(2		)
							Gain on sale of investments	(21		)	(96		)
Cross currency derivatives	(11		)	5			Interest expense	(6		)	(6		)
							Foreign currency transaction gains (losses)	(14		)	12
Foreign currency derivatives	2			12			Foreign currency transaction gains (losses)	4			—
Commodity derivatives	2			(7		)	Non-regulated revenue	(1		)	(2		)
Total	$	114		$	(132	)		$	(107	)	$	(159	)

The pretax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes over the next twelve months as of June 30, 2013 is $(130) million for interest rate hedges, $6 million for cross currency swaps, $10 million for foreign currency hedges, and $(4) million for commodity and other hedges.

Ineffective Portion of Cash Flow Hedges

The following table sets forth the pretax 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, 2013 and 2012:



		Gains (Losses) Recognized in Earnings
	Classification in Condensed Consolidated Statements of Operations	Three Months Ended June 30,					Six Months Ended June 30,
Type of Derivative		2013		2012			2013		2012
		(in millions)
Interest rate derivatives	Interest expense	$	31	$	2		$	30	$	1
	Net equity in earnings of affiliates	—		(1		)	—		(1		)
Total		$	31	$	1		$	30	$	—

Not Designated for Hedge Accounting

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 and the amortization of balances that had been, but are no longer, accounted for as derivatives, for the three and six months ended June 30, 2013 and 2012:



		Gains (Losses) Recognized in Earnings
	Classification in Condensed Consolidated Statements of Operations	Three Months Ended June 30,						Six Months Ended June 30,
Type of Derivative		2013			2012			2013			2012
		(in millions)
Interest rate derivatives	Interest expense	$	1		$	(1	)	$	2		$	(3	)
	Net equity in earnings of affiliates	—			—			(6		)	—
Foreign currency derivatives	Foreign currency transaction gains (losses)	17			(38		)	23			(76		)
	Net equity in earnings of affiliates	(12		)	—			(15		)	—
Commodity and other derivatives	Non-regulated revenue	13			(13		)	(8		)	1
	Regulated revenue	3			(3		)	—			1
	Non-regulated cost of sales	—			—			1			3
	Regulated cost of sales	11			(5		)	11			(17		)
Total		$	33		$	(60	)	$	8		$	(91	)

Credit Risk-Related Contingent Features

DP&L, our utility in Ohio, has certain over-the-counter commodity derivative contracts under master netting agreements that contain provisions that require DP&L to maintain an investment-grade issuer credit rating from credit rating agencies. Since their rating has fallen below investment grade, certain of the counterparties to the derivative contracts have requested immediate and ongoing full overnight collateralization of the mark-to-market loss (fair value excluding credit valuation adjustments), which was $14 million and $13 million as of June 30, 2013 and December 31, 2012, respectively, for all derivatives with credit risk-related contingent features. As of June 30, 2013 and December 31, 2012, DP&L had posted $5 million and $5 million, respectively, of cash collateral directly with third parties and in a broker margin account and DP&L held no cash collateral from counterparties to its derivative instruments that were in an asset position. After consideration of the netting of counterparty assets, DP&L could have been required to, but did not, provide additional collateral of $3 million and $2 million as of June 30, 2013 and December 31, 2012.

6. LONG-TERM FINANCING RECEIVABLES

Long-term financing receivables represent receivables from certain Latin American governmental bodies, primarily in Argentina, that have contractual maturities of greater than one year pursuant to amended agreements or government resolutions. These financing receivables are included in “Noncurrent assets — other” in the Condensed Consolidated Balance Sheets.

As a result of energy market reforms in 2004 and consistent with contractual arrangements, certain of our subsidiaries entered into three agreements with the Argentine government called Fondos de inversion Mercado Electrico Mayorista (“Foninvemem Agreements”) to contribute a portion of their accounts receivable into a fund for financing the construction of

combined cycle and gas-fired plants. These financing receivables accrue interest and are collected in monthly installments over 10 years once the related plant begins operations. In addition, these subsidiaries receive an ownership interest in these newly built plants once the receivables have been fully repaid. The financing receivables under the first two Foninvemem Agreements are being actively collected since the related plants commenced operations in 2010. However, the financing receivables related to the third Foninvemem Agreement are not currently due as commercial operation of the two related gas-fired turbines has not been achieved. In June 2013, receivables relating to the 2008-2009 period, which were previously covered under Resolution 724/2008 were contributed to FONINVEMEM III project when the Execution Committee of Central Térmica Guillermo Brown Trust instructed that the EPC contract negotiations be initiated on the two gas turbines simultaneously. The construction of the second gas turbine represents an expansion of the original FONINVEMEM III project, and consequently, the Secretary of Energy formally accepted the contribution of Resolution 724/2008 receivables to fund the expansion.

On March 26, 2013, the Argentine government passed Resolution No. 95/2013 ("Resolution 95") to develop a new energy regulatory framework that would apply to all generation companies with certain exceptions. The new regulatory framework remunerates fixed and variable costs plus a margin that will depend on both the technology and fuel used to generate the electricity. To qualify, each generator needs to adhere to the preconditions under Resolution 95. On May 31, 2013, these subsidiaries sent a letter to adhere to such preconditions which made Resolution 95 effective retroactively to February 1, 2013. During June 2013, CAMMESA, the administrator of the wholesale electricity market in Argentina, started the implementation by billing the transactions according to the Resolution 95 procedures. In addition, according to Resolution 95 any outstanding receivables which have not been previously committed for the execution of other projects and/or for the maintenance of existing facilities shall be contributed into the new trusts. This would affect 2012-2013 receivables and may also impact outstanding receivables from 2011.

Collection of these financing receivables is subject to various business risks and uncertainties including timely payment of principal and interest, completion and operation of power plants which generate cash for payments of these receivables, regulatory changes that could impact the timing and amount of collections and economic conditions in Argentina. The Company periodically analyzes each of these factors and assesses collectability of the related financing receivables. The Company’s collection estimates are based on assumptions that it believes to be reasonable but are inherently uncertain. Actual future cash flows could differ from these estimates.

The following table sets forth the breakdown of financing receivables by country as of June 30, 2013 and December 31, 2012. The increase in long-term financing receivables from December 31, 2012 is primarily due to the incorporation of Resolution 724/ 2008 receivables in FONINVEMEM III project as mentioned above partially offset by a decrease due to the impact of foreign currency translation.



	June 30, 2013		December 31, 2012
	(in millions)
Argentina⁽¹⁾	$	247	$	196
Dominican Republic	27		35
Brazil	16		8
Total long-term financing receivables	$	290	$	239

_____________________________


⁽¹⁾	Excludes noncurrent receivables of $63 million and $120 million, respectively, as of June 30, 2013 and December 31, 2012, which have not been converted into long-term financing receivables and currently have no due date.

7. DEBT

Recourse Debt — On April 30, 2013, the Company issued $500 million aggregate principal amount of 4.875% senior notes due 2023. On May 17, 2013, the Company issued an additional $250 million aggregate principal amount of 4.875% senior notes due 2023 to form a single series with the notes issued on April 30, 2013. After this offering, the Company completed the redemption of $928 million aggregate principal of its existing 7.75% senior notes due 2014, 7.75% senior notes due 2015, 9.75% senior notes due 2016, and 8.0% senior notes due 2017 through respective tender offers in May 2013. In June 2013, the Company redeemed an additional $122 million of its 7.75% senior notes due 2014 as per the optional redemption provisions of the senior note indentures. As a result of these transactions, the Company voluntarily reduced outstanding principal by $300 million and extended maturities of an additional $750 million to 10 years. The Company recognized a loss on extinguishment of debt of $163 million on these transactions that is included in the Condensed Consolidated Statement of Operations.

Non-Recourse Debt

Significant transactions

During the six months ended June 30, 2013, we had the following significant debt transactions at our subsidiaries:


•	Tietê issued new debt of $496 million partially offset by repayments of $396 million;


•	El Salvador issued new debt of $310 million partially offset by repayments of $301 million;


•	Sul issued new debt of $150 million partially offset by repayments of $37 million;


•	Mong Duong drew $210 million under its construction loan facility;


•	DPL terminated its $425 million term loan and replaced it with a new $200 million term loan;


•	IPL issued new debt of $170 million partially offset by repayments of $110 million; and


•	Masinloc refinanced its senior debt facility of $500 million and incurred a loss on extinguishment of debt of $43 million. See Note 12-Other Income and Expense for further information.

Debt in default

The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of June 30, 2013 and is classified as current non-recourse debt unless otherwise indicated:



	Primary Nature of Default	June 30, 2013
Subsidiary	Primary Nature of Default	Default Amount		Net Assets
		(in millions)
Maritza	Covenant	$	832	$	620
Changuinola	Covenant	372		231
Sonel	Covenant	268		375
Kavarna	Covenant	197		82
Saurashtra	Covenant	22		13
		$	1,691

The above defaults are not payment defaults, but are instead technical defaults triggered by failure to comply with other covenants and/or other conditions such as (but not limited to) failure to meet information covenants, complete construction or other milestones in an allocated time, meet certain minimum or maximum financial ratios, or other requirements contained in the non-recourse debt documents of the Company.

In addition, in the event that there is a default, bankruptcy or maturity acceleration at a subsidiary or group of subsidiaries that meets the applicable definition of materiality under the corporate debt agreements of The AES Corporation, there could be a cross-default to the Company’s recourse debt. As of June 30, 2013, none of the defaults listed above individually or in the aggregate results in a cross-default under the recourse debt of the Company.

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 21 years.

The following table summarizes the Parent Company’s contingent contractual obligations as of June 30, 2013. 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 and commitments	$	640	20	<$1 - 265
Cash collateralized letters of credit	231		13	$1 - 154
Letters of credit under the senior secured credit facility	3		4	<$1 - 2
Total	$	874	37

During the three months ended June 30, 2013, the Company paid letter of credit fees ranging from 0.25% to 3.25% per annum on the outstanding amounts of letters of credit.

Environmental

The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of June 30, 2013, the Company had recorded liabilities of $12 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. Moreover, where no reserve has been recognized, it is reasonably possible that the Company may be required to incur remediation costs or make expenditures in amounts that could be material but could not be estimated as of June 30, 2013. In aggregate, the Company estimates that the range of potential losses related to environmental matters, where estimable, to be up to $22 million. The amounts considered reasonably possible do not include amounts reserved as discussed above.

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 $320 million and $321 million as of June 30, 2013 and December 31, 2012, respectively. These reserves are reported on the condensed 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, 2013. 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 matters with tax authorities; and regulatory matters. In aggregate, the Company estimates that the range of potential losses, where estimable, related to these reasonably possible material contingencies to be between $883 million and $1.6 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. PENSION PLANS

Total pension cost for the three and six months ended June 30, 2013 and 2012 included the following components:



	Three Months Ended June 30,												Six Months Ended June 30,
	2013						2012						2013						2012
	U.S.			Foreign			U.S.			Foreign			U.S.			Foreign			U.S.			Foreign
	(in millions)
Service cost	$	4		$	7		$	3		$	3		$	8		$	14		$	7		$	10
Interest cost	11			135			12			126			22			274			24			267
Expected return on plan assets	(16		)	(127		)	(14		)	(111		)	(31		)	(257		)	(28		)	(233		)
Amortization of prior service cost	2			—			2			—			3			—			3			—
Amortization of net loss	7			21			6			11			14			42			12			21
Total pension cost	$	8		$	36		$	9		$	29		$	16		$	73		$	18		$	65

Total employer contributions for the six months ended June 30, 2013 for the Company’s U.S. and foreign subsidiaries were $50 million and $47 million, respectively. The expected remaining scheduled employer contributions for 2013 are $2 million and $124 million for U.S. and foreign subsidiaries, respectively.

10. 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, 2013 and 2012:



	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	The AES Corporation Stockholders’ Equity			Noncontrolling Interests			Total Equity			The AES Corporation Stockholders’ Equity			Noncontrolling Interests			Total Equity
	(in millions)
Balance at January 1	$	4,569		$	2,945		$	7,514		$	5,946		$	3,783		$	9,729
Net income	249			283			532			481			241			722
Total foreign currency translation adjustment, net of income tax	(148		)	(69		)	(217		)	(134		)	(110		)	(244		)
Total change in derivative fair value, net of income tax	123			48			171			23			(9		)	14
Total pension adjustments, net of income tax	6			21			27			4			9			13
Capital contributions from noncontrolling interests	—			55			55			—			12			12
Distributions to noncontrolling interests	—			(226		)	(226		)	—			(507		)	(507		)
Disposition of businesses	(1		)	(20		)	(21		)	—			(37		)	(37		)
Acquisition of treasury stock	(18		)	—			(18		)	(231		)	—			(231		)
Issuance and exercise of stock-based compensation benefit plans, net of income tax	24			—			24			34			—			34
Dividends declared on common stock ($0.08 per share)	(60		)	—			(60		)	—			—			—
Sale of subsidiary shares to noncontrolling interests	11			22			33			—			—			—
Acquisition of subsidiary shares from noncontrolling interests	(6		)	(1		)	(7		)	—			(4		)	(4		)
Balance at June 30	$	4,749		$	3,058		$	7,807		$	6,123		$	3,378		$	9,501

Accumulated Other Comprehensive Loss

The changes in accumulated other comprehensive loss by component, net of tax and noncontrolling interests for the six months ended June 30, 2013 were as follows:



	Unrealized derivative losses, net			Unfunded pension obligations, net			Available for sale securities, net			Foreign currency translation adjustment, net			Total
	(in millions)
Balance at January 1	$	(481	)	$	(382	)	$	—		$	(2,057	)	$	(2,920	)
Other comprehensive income before reclassifications	51			—			(1		)	(184		)	(134		)
Amounts reclassified from accumulated other comprehensive loss	72			6			1			36			115
Net current-period other comprehensive income	123			6			—			(148		)	(19		)
Balance at June 30	$	(358	)	$	(376	)	$	—		$	(2,205	)	$	(2,939	)

Reclassifications out of accumulated other comprehensive loss for the three and six months ended June 30, 2013 were as follows:



Details About Accumulated Other Comprehensive Loss Components	Affected Line Item in the Condensed Consolidated Statement of Operations	Three Months Ended June 30, 2013			Six Months Ended June 30, 2013
		(in millions)
Unrealized derivative losses, net
	Non-regulated revenue	$	(1	)	$	(1	)
	Interest expense	(34		)	(69		)
	Gain on sale of investments	(21		)	(21		)
	Foreign currency transaction gains (losses)	(17		)	(10		)
	Non-regulated cost of sales	(1		)	(2		)
	Income from continuing operations before taxes and equity in earnings of affiliates	(74		)	(103		)
	Income tax expense	15			22
	Net equity in earnings of affiliates	(2		)	(4		)
	Income from continuing operations	(61		)	(85		)
	Income from continuing operations attributable to noncontrolling interests	11			13
	Net income attributable to the AES Corporation	$	(50	)	$	(72	)
Amortization of defined benefit pension actuarial loss, net
	Non-regulated cost of sales	$	(1	)	$	(2	)
	Regulated cost of sales	(19		)	(39		)
	Income from continuing operations before taxes and equity in earnings of affiliates	(20		)	(41		)
	Income tax expense	7			14
	Income from continuing operations	(13		)	(27		)
	Income from continuing operations attributable to noncontrolling interests	10			21
	Net income attributable to the AES Corporation	$	(3	)	$	(6	)
Available-for-sale securities, net
	Interest income	$	(1	)	$	(1	)
	Net income attributable to The AES Corporation	$	(1	)	$	(1	)
Foreign currency translation adjustment, net
	Gain on sale of investment	$	(4	)	$	(1	)
	Net loss from disposal and impairments of discontinued businesses	(35		)	(35		)
	Net income attributable to the AES Corporation	$	(39	)	$	(36	)
Total reclassifications for the period, net of income tax and noncontrolling interests		$	(93	)	$	(115	)

_____________________________


⁽¹⁾	Amounts in parentheses indicate debits to the condensed consolidated statement of operations.

Stock Repurchase Program

During the three months ended June 30, 2013, shares of common stock repurchased under the existing stock repurchase program (the "Program") totaled 1,558,900 at a total cost of $18 million. The cumulative total purchases under the Program totaled 60,274,089 shares at a total cost of $698 million, which includes a nominal amount of commissions (average of $11.58 per share including commissions). As of June 30, 2013, $282 million was available under the Program.

The common stock repurchased has been classified as treasury stock and accounted for using the cost method. A total of 67,103,992 and 66,415,984 shares were held as treasury stock at June 30, 2013 and December 31, 2012, respectively. Restricted stock units under the Company’s employee benefit plans are issued from treasury stock. The Company has not retired any common stock repurchased since it began the Program.

Subsequent to June 30, 2013, the Company, repurchased an additional 3,738,142 shares at a cost of $45 million, bringing the cumulative total through August 7, 2013 to 64,012,231 shares at a total cost of $743 million (average price of $11.60 per share including commissions).

11. SEGMENTS

The segment reporting structure 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. The management reporting structure is organized along six strategic business units (“SBUs”) — led by our Chief Operating Officer (“COO”), who in turn reports to our Chief Executive Officer (“CEO”). For the three and six months ended June 30, 2013, the Company applied the accounting guidance for segment reporting which provides certain qualitative and quantitative thresholds and aggregation criteria. The Company concluded that the Gener operating segment met the quantitative threshold to require separate presentation. As such, an additional reportable segment, which consists solely of the results of Gener, is now reported as Andes — Gener — Generation. Gener was previously included as part of the Andes — Generation reportable segment. All of the remaining businesses that were formerly part of the Andes — Generation reportable segment are now reported as Andes — Other — Generation. All prior-period results have been retrospectively revised to reflect the new segment reporting structure. The Company has increased from eight to the following nine reportable segments based on the six strategic business units:


•	US — Generation;


•	US — Utilities;


•	Andes — Gener — Generation;


•	Andes — Other — Generation;


•	Brazil — Generation;


•	Brazil — Utilities;


•	MCAC — Generation;


•	EMEA — Generation; and


•	Asia — Generation.

Corporate and Other — The Company’s EMEA and MCAC Utilities operating segments are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under the 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 Consolidated Statements of Operations, not in revenue or Adjusted pre-tax contribution (“Adjusted PTC”). “Corporate and Other” also includes corporate overhead costs which are not directly associated with the operations of our nine reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

The Company uses Adjusted PTC as its primary segment performance measure. Adjusted PTC, a non-GAAP measure, is defined by the Company as pre-tax income from continuing operations attributable to AES excluding unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, gains or losses due to dispositions and acquisitions of business interests, losses due to impairments and costs due to the early retirement of debt. The Company has concluded that Adjusted PTC best reflects the underlying business performance of the Company and is the most relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Additionally, given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure that better assists the investor in determining which businesses have the greatest impact on the overall Company results.

Total revenue includes inter-segment revenue primarily related to the transfer of electricity from generation plants to utilities within Brazil. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain self-insurance activities which are reflected within segment adjusted PTC. All intra-segment activity has been eliminated with respect to revenue and adjusted PTC 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, 2013 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, 2013 and 2012 was as follows:



Revenue Three Months Ended June 30,	Total Revenue				Intersegment						External Revenue
Revenue Three Months Ended June 30,	2013		2012		2013			2012			2013		2012
	(in millions)
US — Generation	$	190	$	216	$	—		$	—		$	190	$	216
US — Utilities	674		678		—			—			674		678
Andes — Gener — Generation	612		547		—			(9		)	612		538
Andes — Other — Generation	112		223		(1		)	—			111		223
Brazil — Generation	279		274		(250		)	(248		)	29		26
Brazil — Utilities	1,202		1,230		—			—			1,202		1,230
MCAC — Generation	471		426		—			—			471		426
EMEA — Generation	314		269		(20		)	(8		)	294		261
Asia — Generation	143		182		—			—			143		182
Corporate and Other	343		310		(1		)	(1		)	342		309
Total Revenue	$	4,340	$	4,355	$	(272	)	$	(266	)	$	4,068	$	4,089



Revenue Six Months Ended June 30,	Total Revenue				Intersegment						External Revenue
Revenue Six Months Ended June 30,	2013		2012		2013			2012			2013		2012
	(in millions)
US — Generation	$	360	$	414	$	—		$	—		$	360	$	414
US — Utilities	1,396		1,410		—			—			1,396		1,410
Andes — Gener — Generation	1,198		1,143		—			(18		)	1,198		1,125
Andes — Other — Generation	217		361		(1		)	—			216		361
Brazil — Generation	665		579		(530		)	(530		)	135		49
Brazil — Utilities	2,525		2,761		—			—			2,525		2,761
MCAC — Generation	929		819		(1		)	(1		)	928		818
EMEA — Generation	665		746		(28		)	(17		)	637		729
Asia — Generation	277		364		—			—			277		364
Corporate and Other	663		646		(2		)	(2		)	661		644
Total Revenue	$	8,895	$	9,243	$	(562	)	$	(568	)	$	8,333	$	8,675



Adjusted Pre-Tax Contribution⁽¹⁾ Three Months Ended June 30,	Total Adjusted Pre-tax Contribution						Intersegment						External Adjusted Pre-tax Contribution
	Total Adjusted Pre-tax Contribution						Intersegment						External Adjusted Pre-tax Contribution
	2013			2012			2013			2012			2013			2012
	(in millions)
US — Generation	$	41		$	42		$	2		$	9		$	43		$	51
US — Utilities	24			32			1			1			25			33
Andes — Gener — Generation	57			24			3			(4		)	60			20
Andes — Other — Generation	28			25			1			—			29			25
Brazil — Generation	66			45			(61		)	(59		)	5			(14		)
Brazil — Utilities	11			9			41			40			52			49
MCAC — Generation	89			88			3			2			92			90
EMEA — Generation	64			55			(9		)	(2		)	55			53
Asia — Generation	40			55			—			1			40			56
Corporate and Other	(149		)	(169		)	19			12			(130		)	(157		)
Total Adjusted Pre-Tax Contribution	271			206			—			—			271			206



Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates:
Non-GAAP Adjustments:
Unrealized derivative gains (losses)	65			(42		)
Unrealized foreign currency gains (losses)	(15		)	(41		)
Disposition/acquisition gains	23			4
Impairment losses	—			(17		)
Loss on extinguishment of debt	(164		)	—
Pre-tax contribution	180			110
Add: income from continuing operations before taxes, attributable to noncontrolling interests	231			102
Less: Net equity in earnings of affiliates	2			11
Income from continuing operations before taxes and equity in earnings of affiliates	$	409		$	201



Adjusted Pre-Tax Contribution⁽¹⁾ Six Months Ended June 30,	Total Adjusted Pre-tax Contribution						Intersegment						External Adjusted Pre-tax Contribution
	Total Adjusted Pre-tax Contribution						Intersegment						External Adjusted Pre-tax Contribution
	2013			2012			2013			2012			2013			2012
	(in millions)
US — Generation	$	106		$	78		$	4		$	20		$	110		$	98
US — Utilities	94			89			1			1			95			90
Andes — Gener — Generation	131			119			5			(10		)	136			109
Andes — Other — Generation	34			41			2			1			36			42
Brazil — Generation	106			97			(128		)	(127		)	(22		)	(30		)
Brazil — Utilities	13			65			86			86			99			151
MCAC — Generation	137			159			6			4			143			163
EMEA — Generation	158			242			(11		)	(16		)	147			226
Asia — Generation	71			87			1			1			72			88
Corporate and Other	(314		)	(358		)	34			40			(280		)	(318		)
Total Adjusted Pre-Tax Contribution	$	536		$	619		—			—			536			619



Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates:
Non-GAAP Adjustments:
Unrealized derivative gains (losses)	52			(72		)
Unrealized foreign currency gains (losses)	(42		)	(12		)
Disposition/acquisition gains	26			182
Impairment losses	(48		)	(75		)
Loss on extinguishment of debt	(207		)	—
Pre-tax contribution	317			642
Add: income from continuing operations before taxes, attributable to noncontrolling interests	397			352
Less: Net equity in earnings of affiliates	6			24
Income from continuing operations before taxes and equity in earnings of affiliates	$	708		$	970

_____________________________


⁽¹⁾	Adjusted Pre-tax contribution in each segment before intersegment eliminations includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees and the write-off of intercompany balances.

Assets by segment as of June 30, 2013 and December 31, 2012 were as follows:



	Total Assets
	June 30, 2013		December 31, 2012
	(in millions)
Assets
US — Generation	$	3,157	$	3,259
US — Utilities	7,427		7,534
Andes — Gener — Generation	5,871		5,820
Andes — Other — Generation	754		799
Brazil — Generation	1,446		1,590
Brazil — Utilities	7,566		8,120
MCAC — Generation	4,434		4,293
EMEA — Generation	4,634		4,578
Asia — Generation	2,708		2,625
Discontinued businesses	—		202
Corporate and Other & eliminations	2,839		3,010
Total Assets	$	40,836	$	41,830

12. OTHER INCOME AND EXPENSE

Other Income

Other income generally includes contract terminations, gains on asset sales and extinguishments of liabilities, favorable judgments on contingencies, and other income from miscellaneous transactions. The components of other income are summarized as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in millions)
Contract termination	$	—	$	—	$	60	$	—
Gain on sale of assets	4		1		5		3
Other	9		13		16		29
Total other income	$	13	$	14	$	81	$	32

Other Expense

Other expense generally includes losses on asset sales, legal contingencies and losses from other miscellaneous transactions. The components of other expense are summarized as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in millions)
Loss on sale and disposal of assets	$	10	$	11	$	25	$	35
Contract termination	—		—		7		—
Other	8		4		14		8
Total other expense	$	18	$	15	$	46	$	43

13. ASSET IMPAIRMENT EXPENSE



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in millions)
Beaver Valley	$	—	$	—	$	46	$	—
Kelanitissa	—		7		—		12
St. Patrick	—		11		—		11
Other	—		—		2		5
Total asset impairment expense	$	—	$	18	$	48	$	28

Beaver Valley — In January 2013, Beaver Valley, a wholly-owned 125 Megawatt (“MW”) coal-fired plant in Pennsylvania, entered into an agreement to early terminate its PPA with the offtaker in exchange for a lump-sum payment of $60 million which was received on January 9, 2013. The termination was effective January 8, 2013. Beaver Valley also terminated its fuel supply agreement. Under the PPA termination agreement, annual capacity agreements between the offtaker and PJM Interconnection, LLC (“PJM”) (a regional transmission organization) for 2013 — 2016 have been assigned to Beaver Valley. The termination of the PPA resulted in a significant reduction in the future cash flows of the asset group and was considered an impairment indicator. The carrying amount of the asset group was not recoverable. The carrying amount of the asset group exceeded the fair value of the asset group, resulting in an asset impairment expense of $46 million. Beaver Valley is reported in the US Generation segment.

14. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

In addition to the businesses reported as discontinued operations in the 2012 Form 10-K, discontinued operations include the results of our Ukraine Utility businesses sold in April 2013. The following table summarizes the revenue, income from operations, income tax expense, impairment and loss on disposal of all discontinued operations for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in millions)
Revenue	$	40		$	113		$	187		$	304
Income (loss) from operations of discontinued businesses, before income tax	$	1		$	(2	)	$	14		$	6
Income tax benefit (expense)	(1		)	(3		)	—			(5		)
Income (loss) from operations of discontinued businesses, after income tax	$	—		$	(5	)	$	14		$	1
Net loss (gain) from disposal and impairments of discontinued businesses, after income tax	$	3		$	75		$	(33	)	$	70

Ukraine Utilities sale — On April 29, 2013, the Company completed the sale of its two utility businesses in Ukraine to VS Energy International and received net proceeds of $113 million after working capital adjustments. The Company sold its 89.1% equity interest in AES Kyivoblenergo, which serves 881,000 customers in the Kiev region, and its 84.6% percent equity interest in AES Rivneoblenergo, which serves 412,000 customers in the Rivne region. The Company had recognized an impairment of $38 million upon fair value measurement during the first quarter of 2013. In the second quarter of 2013, an after- tax gain of $3 million was recognized upon the completion of the sale transaction. These businesses were previously reported in “Corporate and Other.”

15. DISPOSITIONS

Cartagena — On April 26, 2013, the Company sold its remaining interest in AES Energia Cartagena S.R.L. (“AES Cartagena”), a 1,199 MW gas-fired generation business in Spain upon the exercise of a purchase option included in the 2012 sale agreement where the Company sold its majority interest in the business. Net proceeds from the exercise of the option were approximately $24 million and the Company recognized a pretax gain of $20 million during the second quarter of 2013. In 2012, the Company had sold 80% of its 70.81% equity interest in Cartagena and had recognized a pretax gain of $178 million. Under the terms of the 2012 sale agreement, the buyer was granted an option to purchase the Company’s remaining 20% interest during a five-month period beginning March 2013, which was exercised on April 26, 2013 as described above.

Due to the Company’s continued ownership interest, which extended beyond one year from the completion of the sale of its 80% interest in February 2012, the prior-period operating results of AES Cartagena were not reclassified as discontinued operations.

16. 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, 2013 and 2012. In the table below, income represents the numerator and weighted-average shares represent the denominator:



	Three Months Ended June 30,
	2013					2012
	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	$	164	747	$	0.22	$	70	764	$	0.09
EFFECT OF DILUTIVE SECURITIES
Stock options	—		—	—		—		1	—
Restricted stock units	—		4	—		—		3	—
DILUTED EARNINGS PER SHARE	$	164	751	$	0.22	$	70	768	$	0.09



	Six Months Ended June 30,
	2013					2012
	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	$	270	746	$	0.36	$	411	765	$	0.54
EFFECT OF DILUTIVE SECURITIES
Stock options	—		1	—		—		1	—
Restricted stock units	—		3	—		—		3	—
DILUTED EARNINGS PER SHARE	$	270	750	$	0.36	$	411	769	$	0.54

The calculation of diluted earnings per share excluded 7 million options outstanding at June 30, 2013 and 2012, that could potentially dilute basic earnings per share in the future. These options were not included in the computation of diluted earnings per share because the exercise price of these options exceeded the average market price during the related period.

The calculation of diluted earnings per share also excluded 1 million and 2 million restricted stock units outstanding at June 30, 2013 and 2012, respectively, that could potentially dilute basic earnings per share in the future. These restricted stock units were not included in the computation of diluted earnings per share because the average amount of compensation cost per share attributed to future service and not yet recognized exceeded the average market price during the related period and thus to include the restricted units would have been anti-dilutive.

For the three and six months ended June 30, 2013 and 2012, all 15 million shares of potential common stock associated with convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive.

During the six months ended June 30, 2013, 1 million shares of common stock were issued under the Company’s profit-sharing plan.

17. SUBSEQUENT EVENTS

Stock Repurchase Program —The Company continued stock repurchases after June 30, 2013 under its stock repurchase program. For additional information on stock repurchases after the quarter, see Note 10.—Equity.

Trinidad Generation Unlimited—On July 10, 2013, the Company completed the sale of its 10% equity interest in Trinidad Generation Unlimited, an equity method investment, to the government of Trinidad and received net proceeds of $31 million. The carrying amount of the investment was $28 million and a gain of $3 million will be recognized in the third quarter of 2013.

Recourse Debt—On July 26, 2013, the Company entered into an Amendment No. 3 (the “Amendment No. 3”) to the Fifth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2010, among the Company, various subsidiary guarantors and various lending institutions (as amended by Amendment No. 1, dated as of January 13, 2012, and Amendment No. 2, dated as of January 2, 2013, the “Existing Credit Agreement”) that amends and restates the Existing Credit Agreement (as so amended and restated by the Amendment No. 3, the “Sixth Amended and Restated Credit Agreement”). The Sixth Amended and Restated Credit Agreement adjusts the terms and conditions of the Existing Credit Agreement, including the following changes:


•	the final maturity date of the revolving credit loan facility is extended to July 26, 2018 from January 29, 2015;


•	the interest rate margin applicable to the revolving credit loan facility is based on the credit rating assigned to the loans under the credit agreement, with pricing currently at LIBOR + 2.25%, a 0.75% decrease;


•	there is an un-drawn fee of 0.50% per annum; and


•	the subsidiary guarantors party to the Existing Credit Agreement are released from their obligations under the Existing Credit Agreement and have no obligations under the Sixth Amended and Restated Credit Agreement.

The aggregate commitment for the revolving credit loan facility remains $800 million.

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 2012 Form 10-K.

FORWARD-LOOKING INFORMATION

The following discussion may contain forward-looking statements regarding us, our business, prospects and our results of operations that are subject to certain risks and uncertainties posed by many factors and events that could cause our actual business, prospects and results of operations to differ materially from those that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those described in Item 1A. — Risk Factors of our 2012 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 diversified power generation and utility company organized into six market-oriented Strategic Business Units (“SBUs”): US (United States), Andes (Chile, Colombia, and Argentina), Brazil, MCAC (Mexico, Central America and the Caribbean), EMEA (Europe, Middle East and Africa), and Asia. For additional information regarding our business, see Item 1. —Business of our 2012 Form 10-K.

Our Organization — The management reporting structure is organized along six SBUs led by our Chief Operating Officer (“COO”), who in turn reports to our Chief Executive Officer (“CEO”). Our CEO and COO are based in Arlington, Virginia. Management’s discussion and analysis of revenue and gross margin is organized according to the SBU structure and further disaggregated along the Generation and Utilities lines of business as follows:


•	US SBU


•	US — Generation


•	US — Utilities


•	Andes SBU


•	Andes — Generation


•	Brazil SBU


•	Brazil — Generation


•	Brazil — Utilities


•	MCAC SBU


•	MCAC — Generation


•	EMEA SBU


•	EMEA — Generation


•	Asia SBU


•	Asia — Generation

Corporate and Other — The Company’s EMEA and MCAC utilities as well as Corporate are reported within “Corporate and Other” because they do not require separate disclosure under segment reporting accounting guidance.

Gener is reported as a separate segment for purposes of the required segment accounting disclosures, but is included as part of Andes — Generation within the discussion of operating results for revenue and gross margin in management's discussion and analysis as it is managed with the other Andes — Generation businesses. See Note 11 — Segments included in Item 1. — Financial Statements for further discussion of the Company’s segment structure used for financial reporting purposes.

Management’s Priorities

Management is focused on the following priorities:


•	Management of our portfolio of generation and utility businesses to create value for our stakeholders, including customers and shareholders, through safe, reliable, and sustainable operations and effective cost management;


•	Driving our operating business to manage capital more effectively and to increase the amount of discretionary cash available for deployment into debt repayment, growth investments, shareholder dividends and share buybacks;


•	Realignment of our geographic focus. To this end, we will continue to exit markets where we do not have a competitive advantage or where we are unable to earn a fair risk-adjusted return relative to monetization alternatives. In addition, we will focus our growth investments on platform expansions or opportunities to expand our existing operations; and


•	Reduce the cash flow and earnings volatility of our businesses by proactively managing our currency, commodity and political risk exposures, mostly through contractual and regulatory mechanisms, as well as commercial hedging activities. We also will continue to limit our risk by utilizing non-recourse project financing for the majority of our businesses.

Q2 2013 Performance

Results for the quarter were driven by a lower effective tax rate, the addition of new capacity and higher availability in Chile, cost reductions and capital allocation decisions, including share repurchases.

Earnings Per Share Results in Q2 2013



	Three Months Ended June 30,								Six Months Ended June 30,
	2013		2012		Change		% Change		2013		2012		Change		% Change
Diluted earnings per share from continuing operations	$	0.22	$	0.09	$	0.13	144	%	$	0.36	$	0.54	$	-0.18	-33	%
Adjusted earnings per share (a non-GAAP measure)⁽¹⁾	$	0.32	$	0.18	$	0.14	78	%	$	0.58	$	0.55	$	0.03	5	%

_____________________________


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

Three Months Ended June 30, 2013

Diluted earnings per share from continuing operations increased $0.13, or 144%, to $0.22 principally due to higher gross margin, lower foreign currency losses, a lower effective tax rate, and lower interest expense, partially offset by the loss on extinguishment of debt at the Parent Company.

Adjusted earnings per share, a non-GAAP measure, increased by 78% primarily due to a lower effective tax rate, higher gross margin, and lower general and administrative expenses in 2013 compared to 2012.

Six Months Ended June 30, 2013

Diluted earnings per share from continuing operations decreased $0.18, or 33%, principally due to the loss on the early extinguishment of debt at the Parent Company and Masinloc, a lower gain on sale of investments in 2013 from the sale of our remaining 20% interest in Cartagena compared to the prior gain from the sale of 80% of our interest in Cartagena in the first quarter 2012 and lower gross margin, partially offset by lower tax expense, and lower interest expense.

Adjusted earnings per share, a non-GAAP measure, increased by 5% primarily due to lower tax expense, lower interest expense, higher other income due to the PPA termination at Beaver Valley and lower general and administrative expenses in 2013 compared to 2012, partially offset by the decrease in gross margin.

We continued to execute on our strategic objectives of safe, reliable and sustainable operations, improvement of available capital and deployment of discretionary cash and realignment of our geographic focus. Key highlights of our progress during the three months ended June 30, 2013 include:

Safe, Reliable and Sustainable Operations.

During the second quarter of 2013, we completed construction of the 216 MW gas-fired Kribi plant in Cameroon, and we commenced construction of our 532 MW coal-fired Cochrane platform expansion project in Chile. This brings our total projects under construction to 2,227 MW, expected to come on-line from 2013-2016.

Improving Available Capital and Deployment of Discretionary Cash.

We continue to enhance our sources and uses of parent discretionary cash. During the second quarter of 2013, we generated significant cash flow from operating activities and closed asset sales, fully exiting operations in Spain and Ukraine. In terms of uses, we deployed our discretionary cash to pay a dividend of $0.04 per share, allocated $458 million to reduce recourse debt and extend near-term maturities at the Parent Company and invested $12 million in our subsidiaries to expand our platforms. Additionally, beginning in June and extending into the third quarter of 2013, we repurchased shares of AES common stock. For further details on the share repurchase, please see Note 10. — Equity in Item 1. — Financial Statements of this Form 10-Q.

Realigning Our Geographic Focus.

Continuing on our efforts to further streamline our portfolio, as we previously announced, we closed the sales of our businesses in the Ukraine and in Spain and fully exited operations in those countries during the quarter. Recently, we completed two additional transactions. We closed the sale of our interest in the 720 MW gas-fired plant in Trinidad in July 2013 and the sale of our wind turbine inventory in June 2013. These two transactions resulted in total equity proceeds to AES of $56 million.

Other Operating Highlights



	Three Months Ended June 30,						Six Months Ended June 30,
	2013		2012		% Change		2013		2012		% Change
	($ in millions)
Revenue	$	4,068	$	4,089	-1	%	$	8,333	$	8,675	-4	%
Gross margin	$	918	$	693	32	%	$	1,673	$	1,765	-5	%
Net income attributable to The AES Corporation	$	167	$	140	19	%	$	249	$	481	-48	%
Adjusted pre-tax contribution (a non-GAAP measure)⁽¹⁾	$	271	$	206	32	%	$	536	$	619	-13	%
Net cash provided by operating activities	$	567	$	580	-2	%	$	1,185	$	1,114	6	%
Dividends declared per common share	$	0.08	$	—	N/A		$	0.08	$	—	N/A

_____________________________


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

The following briefly describes the key changes in our reported revenue, gross margin, net income attributable to The AES Corporation and net cash provided by operating activities, for the three and six months ended June 30, 2013 and 2012, and should be read in conjunction with our Consolidated Results of Operations and Segment Analysis discussion within Management’s Discussion and Analysis of Financial Condition below.

Consolidated Results of Operations



	Three Months Ended June 30,											Six Months Ended June 30,
Results of operations	2013			2012			$ change			% change		2013			2012			$ change			% change
	($ in millions, except per share amounts)
Revenue:
US — Generation	$	190		$	216		$	(26	)	-12	%	$	360		$	414		$	(54	)	-13	%
US — Utilities	674			678			(4		)	-1	%	1,396			1,410			(14		)	-1	%
Andes — Generation	724			770			(46		)	-6	%	1,415			1,504			(89		)	-6	%
Brazil — Generation	279			274			5			2	%	665			579			86			15	%
Brazil — Utilities	1,202			1,230			(28		)	-2	%	2,525			2,761			(236		)	-9	%
MCAC — Generation	471			426			45			11	%	929			819			110			13	%
EMEA — Generation	314			269			45			17	%	665			746			(81		)	-11	%
Asia — Generation	143			182			(39		)	-21	%	277			364			(87		)	-24	%
Corporate and Other⁽¹⁾	343			310			33			11	%	663			646			17			3	%
Intersegment eliminations⁽²⁾	(272		)	(266		)	(6		)	-2	%	(562		)	(568		)	6			1	%
Total Revenue	4,068			4,089			(21		)	-1	%	8,333			8,675			(342		)	-4	%
Gross Margin:
US — Generation	$	49		$	59		$	(10	)	-17	%	$	80		$	112		$	(32	)	-29	%
US — Utilities	99			92			7			8	%	217			206			11			5	%
Andes — Generation	149			99			50			51	%	283			266			17			6	%
Brazil — Generation	238			197			41			21	%	401			422			(21		)	-5	%
Brazil — Utilities	75			(27		)	102			378	%	115			56			59			105	%
MCAC — Generation	123			122			1			1	%	210			227			(17		)	-7	%
EMEA — Generation	102			83			19			23	%	223			330			(107		)	-32	%
Asia — Generation	48			59			(11		)	-19	%	89			113			(24		)	-21	%
Corporate and Other⁽¹⁾	20			(3		)	23			767	%	27			20			7			35	%
Intersegment eliminations⁽²⁾	15			12			3			25	%	28			13			15			115	%
Total Gross Margin	918			693			225			32	%	1,673			1,765			(92		)	-5	%
General and administrative expenses	(59		)	(74		)	15			20	%	(120		)	(161		)	41			25	%
Interest expense	(346		)	(384		)	38			10	%	(723		)	(800		)	77			10	%
Interest income	63			82			(19		)	-23	%	129			173			(44		)	-25	%
Loss on extinguishment of debt	(165		)	—			(165		)	NA		(212		)	—			(212		)	NA
Other expense	(18		)	(15		)	(3		)	-20	%	(46		)	(43		)	(3		)	-7	%
Other income	13			14			(1		)	-7	%	81			32			49			153	%
Gain on sale of investments	20			5			15			300	%	23			184			(161		)	-88	%
Asset impairment expense	—			(18		)	18			100	%	(48		)	(28		)	(20		)	-71	%
Foreign currency transaction losses	(17		)	(101		)	84			83	%	(49		)	(102		)	53			52	%
Other non-operating expense	—			(1		)	1			100	%	—			(50		)	50			100	%
Income tax expense	(81		)	(75		)	(6		)	-8	%	(163		)	(343		)	180			52	%
Net equity in earnings of affiliates	2			11			(9		)	-82	%	6			24			(18		)	-75	%
Income from continuing operations	330			137			193			141	%	551			651			(100		)	-15	%
Income (loss) from operations of discontinued businesses	—			(5		)	5			100	%	14			1			13			NM
Net gain (loss) from disposal and impairments of discontinued businesses	3			75			(72		)	-96	%	(33		)	70			(103		)	-147	%
Net income	333			207			126			61	%	532			722			(190		)	-26	%
Noncontrolling interests:
Income from continuing operations attributable to noncontrolling interests	(166		)	(67		)	(99		)	-148	%	(281		)	(240		)	(41		)	-17	%
Income from discontinued operations attributable to noncontrolling interests	—			—			—			NA		(2		)	(1		)	(1		)	-100	%
Net income attributable to The AES Corporation	$	167		$	140		$	27		19	%	$	249		$	481		$	(232	)	-48	%
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	164		$	70		$	94		134	%	$	270		$	411		$	(141	)	-34	%
Income (loss) from discontinued operations, net of tax	3			70			(67		)	-96	%	(21		)	70			(91		)	-130	%
Net income	$	167		$	140		$	27		19	%	$	249		$	481		$	(232	)	-48	%

_____________________________

NM — Not meaningful


⁽¹⁾	Corporate and other includes revenue and gross margin from our utility businesses in El Salvador and Africa.


⁽²⁾	Represents intersegment eliminations of revenue and gross margin primarily related to transfers of electricity from Tietê (Brazil — Generation) to Eletropaulo (Brazil — Utilities).

Three months ended June 30, 2013:

Revenue decreased $21 million, or 1%, to $4.1 billion in the three months ended June 30, 2013 compared with $4.1 billion in the three months ended June 30, 2012. Excluding the unfavorable impact of foreign currency of $115 million, the key drivers of the change at each of the SBUs are as follows:

•

US — Overall unfavorable impact of $30 million, or 3%, driven by lower capacity revenue, lower average wholesale prices, and lower average retail prices due to downward price pressure as a result of generating services competition at DPL in Ohio, the impact of the PPA buyout at Beaver Valley in Pennsylvania, and the temporary operations of two generating units at Huntington Beach at Southland in 2012 that did not recur in 2013, partially offset by higher wholesale volume at DPL driven by switching of regulated customers as well as increased generation available from DPL's co-owned and operated plants.

•

Andes — Overall unfavorable impact of $8 million, or 1%, driven by lower prices due to the change in regulatory framework as a result of Resolution 95 whereby alternate fuel costs are no longer recognized as revenue as well as lower generation in Argentina, lower spot prices in Chile, and lower generation at Chivor in Colombia due to lower water inflows, partially offset by higher spot and contract sales in Chile, higher spot and contract prices at Chivor, and lower outages in Argentina.


•	Brazil — Overall favorable impact of $60 million, or 4%, primarily driven by higher tariffs compared to the 2012 tariff reset provision at Eletropaulo and higher prices at Tietê due to the annual PPA indexation in July 2012, partially offset by lower tariffs at Sul mainly driven by lower pass through of energy and other costs.


•	MCAC — Overall favorable impact of $46 million, or 7%, driven by higher spot and contract sales in the Dominican Republic due to increased demand and higher volume of gas sales to third parties, and higher prices at Puerto Rico and Merida in Mexico primarily due to favorable fuel prices.

•

EMEA — Overall favorable impact of $72 million, or 20%, driven by the favorable impact of a mark-to-market adjustment primarily due to a derivative loss in 2012 at Sonel, new business at Kribi in Cameroon which commenced operations in May 2013, increased volume and higher prices at Kilroot and Ballylumford in the U.K., and higher electricity sales in Kazakhstan as a result of higher inflows and increased capacity.


•	Asia — Overall unfavorable impact of $39 million, or 21%, driven by lower prices in the Philippines and lower volume at Kelanitissa in Sri Lanka, partially offset by higher contract demand in the Philippines.

Gross margin increased $225 million, or 32%, to $918 million in the three months ended June 30, 2013 compared with $693 million in the three months ended June 30, 2012. Excluding the unfavorable impact of foreign currency of $22 million, the key drivers of the change at each of the SBUs are as follows:


•	US — Overall unfavorable impact of $3 million, or 2%, driven by lower retail margin due to customer switching and lower capacity margin at DPL as well as the temporary operations at Southland as discussed above, partially offset by lower depreciation and amortization expense as well as higher wholesale volume and the favorable impact of mark-to-market adjustments on derivative contracts at DPL.

•

Andes — Overall favorable impact of $56 million, or 57%, driven by the commencement of operations at Ventanas IV in March 2013 in Chile, higher availability in Chile and Argentina, and higher spot prices at Chivor, partially offset by lower generation at Chivor as a result of lower water inflows and in Chile due to lower gas availability, lower prices in Chile and Argentina as discussed above and higher fixed costs.


•	Brazil — Overall favorable impact of $161 million, or 94%, driven by the tariff impact as discussed above as well as lower fixed costs due primarily to the reversal of bad debt allowance at Eletropaulo and the extinguishment of a liability at Uruguaiana, partially offset by lower tariffs at Sul.

•

MCAC — Overall favorable impact of $13 million, or 10%, driven by higher spot sales and higher contract prices in the Dominican Republic, reimbursement costs in Panama resulting from a settlement with the EPC contractor over the Esti tunnel collapse, and higher rates at El Salvador mainly due to a tariff reset approved by the regulator at the beginning of 2013, partially offset by an increase in purchases of replacement energy at higher prices in Panama due to lower hydrology.


•	EMEA — Overall favorable impact of $29 million, or 42%, driven by the favorable impact of a mark-to-market derivative adjustment at Sonel and new operations at Kribi in Cameroon as discussed above, as well as lower outages and lower fixed costs at Ballylumford and higher energy prices at Kilroot in the U.K.


•	Asia — Overall unfavorable impact of $11 million, or 19%, driven by lower contract and spot prices in the Philippines, partially offset by higher contract demand.

Net income attributable to The AES Corporation increased $27 million to $167 million in the three months ended June 30, 2013 compared to $140 million in the three months ended June 30, 2012. The key drivers of the increase included:


•	the increase in gross margin as described above;


•	lower foreign currency losses;


•	a lower effective tax rate; and


•	lower interest expense due to gains resulting from ineffectiveness on interest rate swaps at Puerto Rico.

These increases were partially offset by:


•	the loss on the early extinguishment of debt at the Parent Company; and


•	the 2012 gain from the disposal of the discontinued Red Oak and Ironwood businesses.

Net cash provided by operating activities decreased $13 million, or 2%, to $567 million in three months ended June 30, 2013 compared with $580 million in three months ended June 30, 2012.

Operating cash flow of $567 million for the three months ended June 30, 2013 resulted primarily from net income adjusted for non-cash items, principally depreciation and amortization and loss on extinguishment of debt partially offset by a net use of cash for operating activities of $161 million in operating assets and liabilities. This was primarily due to the following:


•	a decrease of $426 million in accounts payable and other current liabilities, primarily due to reduced operations and the extinguishment of a liability based on a favorable arbitration decision at Uruguaiana, a decrease in current regulatory liabilities at Eletropaulo, higher interest payments at the Parent Company and DPL and higher energy purchases at Tietê;


•	an increase of $102 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo, resulting from higher priced energy purchases which are recoverable through future tariffs; partially offset by


•	a decrease of $247 million in prepaid expenses and other current assets due to a decrease in current regulatory assets, for the recovery of prior period tariff cycle energy purchases and regulatory charges at Eletropaulo and in a receivable from the regulator at Sul; and


•	a decrease of $149 million in accounts receivable due to the reduced operations at Uruguaiana and a lower tariff at Eletropaulo.

Net cash provided by operating activities was $580 million during the three months ended June 30, 2012. Operating cash flow 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. This was primarily due to the following:


•	an increase of $204 million in other liabilities primarily due to an increase in long-term regulatory liabilities related to the tariff reset at Eletropaulo;


•	a decrease of $135 million in prepaid expenses and other current assets, 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; partially offset by


•	an increase of $137 million in 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


•	a decrease of $88 million primarily for the payment of income taxes in excess of the accrual of new tax liabilities.

Six months ended June 30, 2013:

Revenue decreased $342 million, or 4%, to $8.3 billion in the six months ended June 30, 2013 compared with $8.7 billion in the six months ended June 30, 2012. Excluding the unfavorable impact of foreign currency of $354 million, the key drivers of the change at each of the SBUs are as follows:

•

US — Overall unfavorable impact of $68 million, or 4%, driven by lower capacity revenue, lower average wholesale prices, and lower average retail prices due to downward price pressure as a result of generating services competition at DPL in Ohio, the impact of the PPA buyout at Beaver Valley in Pennsylvania, increased outages at Hawaii, and the temporary operations of two generating units at Huntington Beach at Southland in 2012 that did not recur in 2013, partially offset by higher wholesale volume at DPL in Ohio and IPL in Indiana.

•

Andes — Overall unfavorable impact of $33 million, or 2%, driven by lower prices due to the change in regulatory framework as a result of Resolution 95, whereby alternate fuel costs are no longer recognized as revenue as well as lower generation in Argentina, lower contract and spot prices in Chile, and lower generation at Chivor in Colombia due to lower water inflows, partially offset by higher spot and contract prices at Chivor, higher spot and contract sales in Chile, and lower outages in Argentina in 2013.

•

Brazil — Overall favorable impact of $155 million, or 5%, driven by the temporary restart of operations at Uruguaiana in the first quarter of 2013, higher tariffs mainly due to higher energy pass through costs and higher tariffs compared to the 2012 tariff reset provision at Eletropaulo, and higher prices at Tietê due to the annual PPA indexation in July 2012, partially offset by lower tariffs at Sul and overall lower demand and volume at our Brazil Utilities.


•	MCAC — Overall favorable impact of $117 million, or 9%, driven by higher contract and spot sales in the Dominican Republic from increased demand and higher international gas prices and gas sales to third parties, higher volume and rates at Merida in Mexico and Puerto Rico, as well as higher rates in El Salvador mainly due to a tariff increase approved by the regulator in the beginning of 2013.

•

EMEA — Overall unfavorable impact of $76 million, or 8%, driven by the sale of 80% of our ownership and a non-recurring favorable arbitration settlement in Cartagena in February 2012, reduction in capacity remuneration in line with the PPA at Ballylumford beginning in April 2012, and lower volume at Maritza mainly due to lower net capacity factor, partially offset by increased volume and higher prices at Kilroot and lower outages at Ballylumford in the U.K., as well as higher electricity sales from higher inflows and increased capacity in Kazakhstan.


•	Asia — Overall unfavorable impact of $87 million, or 24%, driven by lower volume at Kelanitissa in Sri Lanka and lower rates in the Philippines, partially offset by higher contract demand.

Gross margin decreased $92 million, or 5%, to $1.7 billion in the six months ended June 30, 2013 compared with $1.8 billion in the six months ended June 30, 2012. Excluding the unfavorable impact of foreign currency of $50 million, the key drivers of the change at each of the SBUs are as follows:


•	US — Overall unfavorable impact of $21 million, or 7%, driven by lower retail margin due to customer switching and lower capacity margin at DPL, increased outages and related fixed costs at Hawaii, the PPA buyout at Beaver Valley, partially offset by lower depreciation and amortization expense and higher wholesale volume at DPL and IPL.

•

Andes — Overall favorable impact of $25 million, or 9%, driven by new operations of Ventanas IV in Chile which commenced operations in March 2013, higher spot and contract prices at Chivor, and higher availability in Chile and Argentina, partially offset by lower generation at Chivor as a result of lower water inflows and in Chile due to lower gas availability, lower prices in Chile and Argentina as discussed above and higher fixed costs.

•

Brazil — Overall favorable impact of $82 million, or 17%, driven by the tariff impact at Eletropaulo as discussed above, the temporary restart of operations in the first quarter of 2013 and extinguishment of a liability at Uruguaiana, and lower fixed costs across the region, partially offset by lower tariff and demand at Sul as well as lower water inflows in the system resulting in higher energy purchases at higher spot prices due to shared hydrologic risk requirement among all hydro generators at Tietê.

•

MCAC — Overall unfavorable impact of $3 million, or 1%, driven by higher replacement purchase energy at higher spot prices in Panama caused by lower hydrology, partially offset by higher contract and spot sales in the Dominican Republic as a result of increased demand and higher international gas prices and gas sales to third parties, reimbursement costs in Panama resulting from a settlement with the EPC contractor over the Esti tunnel collapse and higher tariff in El Salvador as discussed above.

•

EMEA — Overall unfavorable impact of $115 million, or 35%, driven by the sale of 80% of our ownership and a non-recurring favorable arbitration settlement in Cartagena in February 2012 as well as lower capacity prices at Ballylumford as discussed above, partially offset by increased volume and higher prices at Kilroot and lower outages at Ballylumford in the U.K. as well as new operations at Kribi in Cameroon.


•	Asia — Overall unfavorable impact of $24 million, or 21%, driven by lower prices in the Philippines and the favorable impact of a mark-to-market commodity derivative adjustment in 2012, partially offset by higher contract demand.

Net income attributable to The AES Corporation decreased $232 million to $249 million in the six months ended June 30, 2013 compared to $481 million in the six months ended June 30, 2012. The key drivers of the decrease included:


•	the loss on the early extinguishment of debt at the Parent Company and at Masinloc;


•	lower gain on sale of investments recorded in 2013 on the sale of our remaining 20% interest in Cartagena compared to the prior year gain recorded from the sale of 80% of our interest in Cartagena in the first quarter of 2012;


•	the decrease in gross margin as described above; and


•	losses in 2013 from the disposal and impairment of the discontinued Ukraine Utility businesses compared to the gain in 2012 from the disposal of the discontinued Red Oak and Ironwood businesses.

These decreases were partially offset by:


•	lower tax expense in 2013 due to lower income before tax and a decrease in the effective tax rate from 35% to 23%;


•	lower interest expense primarily due to gains resulting from ineffectiveness on interest rate swaps at Puerto Rico;


•	lower foreign currency losses;


•	a decrease in other non-operating expense due to the prior year other-than-temporary impairments of equity method investments in China and France;


•	higher other income due to the gain arising from the termination of the PPA at Beaver Valley; and


•	lower general and administrative expenses.

Net cash provided by operating activities increased $71 million, or 6%, to $1.2 billion in the six months ended June 30, 2013 compared with $1.1 billion in the six months ended June 30, 2012. Please refer to Consolidated Cash Flows -- Operating Activities for further discussion.

Non-GAAP Measure

Adjusted pre-tax contribution (“adjusted PTC”) and Adjusted earnings per share (“adjusted EPS”) are non-GAAP supplemental measures that are used by management and external users of our consolidated financial statements such as investors, industry analysts and lenders.

We define adjusted PTC as pre-tax income from continuing operations attributable to AES excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis.

We define adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt.

The GAAP measure most comparable to adjusted PTC is income from continuing operations attributable to AES. The GAAP measure most comparable to adjusted EPS is diluted earnings per share from continuing operations. We believe that adjusted PTC and adjusted EPS better reflect the underlying business performance of the Company and are considered in the Company’s internal evaluation of financial performance. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose of or acquire business interests or retire debt, which affect results in a given period or periods. In addition, for adjusted PTC, earnings before tax represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. Adjusted PTC and adjusted EPS should not be construed as alternatives to income from continuing operations attributable to AES and diluted earnings per share from continuing operations, which are determined in accordance with GAAP.



	Three Months Ended June 30, 2013							Three Months Ended June 30, 2012						Six Months Ended June 30, 2013							Six Months Ended June 30, 2012
	Net of NCI⁽¹⁾			Per Share (Diluted) Net of NCI⁽¹⁾ and Tax				Net of NCI⁽¹⁾			Per Share (Diluted) Net of NCI⁽¹⁾ and Tax			Net of NCI⁽¹⁾			Per Share (Diluted) Net of NCI⁽¹⁾ and Tax				Net of NCI⁽¹⁾			Per Share (Diluted) Net of NCI⁽¹⁾ and Tax
	(In millions, except per share amounts)
Income from continuing operations attributable to AES and Diluted EPS	$	164		$	0.22			$	70		$	0.09		$	270		$	0.36			$	411		$	0.54
Add back income tax expense from continuing operations attributable to AES	16							40						47							231
Pre-tax contribution	$	180						$	110					$	317						$	642
Adjustments
Unrealized derivative (gains) losses⁽²⁾	$	(65	)	$	(0.06	)		$	42		$	0.04		$	(52	)	$	(0.05	)		$	72		$	0.07
Unrealized foreign currency transaction (gains) losses⁽³⁾	15			0.02				41			0.04			42			0.04				12			0.01
Disposition/ acquisition (gains)	(23		)	(0.03		)	⁽⁴⁾	(4		)	—		⁽⁵⁾	(26		)	(0.03		)	⁽⁶⁾	(182		)	(0.14		)	⁽⁷⁾
Impairment losses	—			—				17			0.01		⁽⁸⁾	48			0.05			⁽⁹⁾	75			0.07			⁽¹⁰⁾
Loss on extinguishment of debt	164			0.17			⁽¹¹⁾	—			—			207			0.21			⁽¹²⁾	—			—
Adjusted pre-tax contribution and Adjusted EPS	$	271		$	0.32			$	206		$	0.18		$	536		$	0.58			$	619		$	0.55

_____________________________


⁽¹⁾	NCI is defined as Noncontrolling Interests


⁽²⁾	Unrealized derivative (gains) losses were net of income tax per share of $(0.02) and $0.02 in the three months ended June 30, 2013 and 2012, and of $(0.02) and $0.03 in the six months ended June 30, 2013 and 2012, respectively.


⁽³⁾	Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.00 and $0.02 in the three months ended June 30, 2013 and 2012, and of $0.02 and $0.00 in the six months ended June 30, 2013 and 2012, respectively.


⁽⁴⁾	Amount primarily relates to the gain from the sale of the remaining 20% interest in Cartagena for $20 million ($15 million, or $0.02 per share, net of income tax per share of $0.01).


⁽⁵⁾	Amount primarily relates to the gain from the sale of St. Patrick, for $4 million ($4 million, or $0.00 per share, net of income tax per share of $0.00).

⁽⁶⁾

Amount primarily relates to the gain from the sale of the remaining 20% interest in Cartagena for $20 million ($15 million, or $0.02 per share, net of income tax per share of $0.01), the gain from the sale of wind turbines for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00) as well as the gain from the sale of Chengdu, an equity method investment in China for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00).


⁽⁷⁾	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).


⁽⁸⁾	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 noncontrolling interest of $1 million and income tax per share of $0.00).


⁽⁹⁾	Amount primarily relates to asset impairments at Beaver Valley of $46 million ($34 million, or $0.05 per share, net of income tax per share of $0.02).

⁽¹⁰⁾

Amount primarily relates to the other-than-temporary impairment 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 of $1 million and income tax per share of $0.00).


⁽¹¹⁾	Amount primarily relates to the loss on early retirement of debt at Corporate of $163 million ($121 million, or $0.16 per share, net of income tax per share of $0.06).


⁽¹²⁾	Amount primarily relates to the loss on early retirement of debt at Corporate of $165 million ($123 million, or $0.16 per share, net of income tax per share of $0.06), and loss on early retirement of debt at Masinloc of $43 million ($29 million, or $0.04 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01).

Revenue and Gross Margin Analysis

US SBU

US — Generation

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



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	190	$	216	-12	%	$	360	$	414	-13	%
Gross Margin	$	49	$	59	-17	%	$	80	$	112	-29	%

Generation revenue for the three months ended June 30, 2013 decreased $26 million, or 12%, compared to the three months ended June 30, 2012 primarily due to:


•	a decrease of $17 million at Beaver Valley in Pennsylvania, as a result of the early termination of the PPA with the offtaker in January 2013; and


•	a decrease of $11 million at Southland in California, primarily due to the short-term restart of two generating units at Huntington Beach in May 2012.

Generation gross margin for the three months ended June 30, 2013 decreased $10 million, or 17%, compared to the three months ended June 30, 2012 primarily due to:


•	a decrease of $9 million at Southland as discussed above; and


•	a decrease of $4 million at Beaver Valley as discussed above.

For the three months ended June 30, 2013, revenue decreased 12%, while gross margin decreased by 17%, primarily due to increased fixed costs at Southland that had a negative impact on gross margin.

Generation revenue for the six months ended June 30, 2013 decreased $54 million, or 13%, compared to the six months ended June 30, 2012 primarily due to:


•	a decrease of $32 million at Beaver Valley, as a result of the early termination of the PPA with the offtaker in January 2013;


•	a decrease of $12 million at Southland, primarily due to the short-term restart of two generating units at Huntington Beach in May 2012; and


•	a decrease of $11 million at Hawaii, primarily due to lower availability as a result of outages.

Generation gross margin for the six months ended June 30, 2013 decreased $32 million, or 29%, compared to the six months ended June 30, 2012 primarily due to:


•	a decrease of $19 million at Hawaii, primarily due to lower availability and increased fixed costs as a result of outages;


•	a decrease of $11 million at Beaver Valley as discussed above; and


•	a decrease of $5 million at Southland as discussed above.

For the six months ended June 30, 2013, revenue decreased 13% while gross margin decreased 29%, primarily due to higher fuel costs at Hawaii and increased fixed costs at Hawaii and Southland that had a negative impact on gross margin.

US — Utilities

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



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	674	$	678	-1	%	$	1,396	$	1,410	-1	%
Gross Margin	$	99	$	92	8	%	$	217	$	206	5	%

Utilities revenue for the three months ended June 30, 2013 decreased $4 million, or 1%, compared to the three months ended June 30, 2012 primarily due to:


•	lower prices of $58 million at DPL, in Ohio, primarily due to lower average wholesale prices, lower capacity revenues, and lower average retail prices due to downward price pressure as a result of generation services competition.

These decreases were partially offset by:


•	higher volume of $50 million at DPL, primarily due to increased energy available for wholesale sales caused by switching of regulated customers to other suppliers as well as increased generation available from DPL's co-owned and operated plants.

Utilities gross margin for the three months ended June 30, 2013 increased $7 million, or 8%, compared to the three months ended June 30, 2012 primarily due to:


•	lower depreciation and amortization expense of $23 million at DPL primarily because DPL's ESP intangible asset was fully amortized at the end of 2012;


•	higher wholesale margins at DPL and IPL of $23 million and $7 million, respectively, primarily due to increased volumes as described above; and


•	an increase of $13 million at DPL due to the favorable impact of mark-to-market adjustments on derivative contracts.

These increases were partially offset by:


•	lower retail margin at IPL of $7 million primarily due to the mild early summer temperatures in 2013;


•	lower capacity margins at DPL of $9 million primarily due to lower capacity prices in the PJM market in 2013; and


•	lower retail margin at DPL of $37 million primarily due to DP&L customers switching to DPL Inc.'s competitive retail supplier or other third parties.

Utilities revenue for the six months ended June 30, 2013 decreased $14 million, or 1%, compared to the six months ended June 30, 2012 primarily due to:


•	lower prices of $127 million at DPL, primarily due to lower capacity revenues, lower average wholesale prices, and lower average retail prices due to downward price pressure as a result of generation services competition.

These decreases were partially offset by:


•	higher volume of $89 million at DPL, primarily due to increased wholesale volumes due to more energy available for wholesale sales caused by switching of regulated customers to other suppliers as well as increased generation available from DPL's co-owned and operated plants; and


•	higher volume of $24 million at IPL, due to increased wholesale volumes resulting from increases in natural gas prices, which improved IPL's ability to compete in the wholesale market.

Utilities gross margin for the six months ended June 30, 2013 increased $11 million, or 5%, compared to the six months ended June 30, 2012 primarily due to:


•	lower depreciation and amortization expense of $49 million at DPL primarily because DPL's ESP intangible asset was fully amortized at the end of 2012; and


•	higher wholesale margins at DPL and IPL of $45 million and $10 million, respectively, primarily due to increased volumes as described above.

These increases were partially offset by:


•	lower retail margin at DPL of $78 million primarily due to DP&L customers switching to DPL Inc.'s competitive retail supplier or other third parties; and


•	lower capacity margins at DPL of $15 million primarily due to lower capacity prices in the PJM market in 2013.

For the six months ended June 30, 2012, revenue decreased 1%, while gross margin increased 5%, primarily due to the unfavorable impact on gross margin in 2012 from the amortization of intangible assets of $44 million related to the DPL acquisition, partially offset by the lower margins realized by DPL on energy sold on the wholesale market that was previously sold to regulated retail customers.

Andes SBU

Andes — Generation

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



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	724	$	770	-6	%	$	1,415	$	1,504	-6	%
Gross Margin	$	149	$	99	51	%	$	283	$	266	6	%

Excluding the unfavorable impact of foreign currency translation and remeasurement of $38 million, generation revenue for the three months ended June 30, 2013 decreased $8 million, or 1%, compared to the three months ended June 30, 2012 primarily due to:


•	lower prices in Argentina of $79 million primarily due to a change in the regulatory framework as a result of Resolution 95 whereby alternate fuel costs are no longer recognized as revenue, See Note 6— Long-term Financing Receivables;


•	lower generation at Argentina of $53 million driven by lower dispatch;


•	lower spot prices in the SIC market at Gener of $35 million; and


•	lower generation at Chivor in Colombia of $7 million as a result of lower inflows.

These decreases were partially offset by:


•	higher volume in Chile of $57 million due to higher spot and contract sales in the SIC market;


•	higher contract and spot prices at Chivor in Colombia of $55 million due to pressure from lower water inflows; and


•	lower outages at Argentina of $54 million.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $6 million, generation gross margin for the three months ended June 30, 2013 increased $56 million, or 57%, compared to the three months ended June 30, 2012 primarily due to:


•	new business in Chile of $58 million due to the commencement of operations at Ventanas IV in March 2013 due to efficiently generating energy to cover existing contracts rather than having to purchase energy on the spot market;


•	higher availability of our plants in Chile and Argentina by $37 million and $19 million respectively; and


•	higher prices at Chivor of $26 million as discussed above.

These increases were partially offset by:


•	lower generation of $49 million mainly driven by $30 million at Chivor due to lower inflows and $16 million at Chile primarily due to lower gas generation;


•	lower prices in Chile of $16 million as a result of lower contract and spot prices in the SIC market;


•	higher fixed costs and depreciation of $14 million mainly driven by higher maintenance expenses; and


•	lower prices in Argentina of $6 million as discussed above.

Excluding the unfavorable impact of foreign currency translation and remeasurement, for the three months ended June 30, 2013, revenue decreased 1%, while gross margin increased by 57%. This was primarily due to the gross margin provided by the increased generation at our new business, Ventanas IV, in Chile and the change in the regulatory framework in Argentina having a larger impact on revenues than gross margin.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $56 million, generation revenue for the six months ended June 30, 2013 decreased $33 million, or 2%, compared to the six months ended June 30, 2012 primarily due to:


•	lower prices in Argentina of $85 million primarily due to the change in the regulatory framework

as a result of Resolution 95;


•	lower generation at Argentina of $54 million driven by lower dispatch;


•	lower contract and spot prices in the SIC market at Gener of $55 million; and


•	lower generation at Chivor of $29 million as a result of lower inflows.

These decreases were partially offset by:


•	higher volume in Chile of $45 million due to higher spot and contract sales in the SIC market;


•	higher contract and spot prices at Chivor of $98 million due to pressure from lower water inflows; and


•	lower outages at Argentina of $45 million.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $8 million, generation gross margin for the six months ended June 30, 2013 increased $25 million, or 9%, compared to the six months ended June 30, 2012 primarily due to:


•	new business in Chile of $66 million due to the commencement of operations at Ventanas IV, as discussed above.


•	higher availability of our plants in Chile and Argentina by $39 million and $17 million respectively; and


•	higher prices at Chivor of $43 million as discussed above.

These increases were partially offset by:


•	lower generation of $107 million mainly driven by $50 million at Chivor due to lower inflows and $48 million at Chile primarily due to lower gas availability;


•	lower prices in Chile of $13 million as a result of lower contract and spot prices in the SIC market;


•	higher fixed costs and depreciation of $15 million mainly driven by higher maintenance expenses; and


•	lower prices in Argentina of $8 million as discussed above.

Excluding the unfavorable impact of foreign currency translation and remeasurement, for the six months ended June 30, 2013, revenue decreased 2%, while gross margin increased 9%. This was primarily due to the gross margin provided by the increased generation at our new business, Ventanas IV, and the change in the regulatory framework in Argentina having a larger impact on revenues than gross margin.

Brazil SBU

Brazil — Generation

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



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	279	$	274	2	%	$	665	$	579	15	%
Gross Margin	$	238	$	197	21	%	$	401	$	422	-5	%

Excluding the unfavorable impact of foreign currency translation of $16 million, generation revenue for the three months ended June 30, 2013 increased $21 million, or 8%, compared to the three months ended June 30, 2012 primarily due to:


•	higher prices of $17 million at Tietê mainly due to $13 million of PPA annual indexation in July 2012 and higher spot prices of $9 million; and


•	positive impact of $8 million at Tietê driven by higher energy sold to Eletropaulo and third party contracts, offset by the spot market.

Excluding the unfavorable impact of foreign currency translation of $14 million, generation gross margin for the three months ended June 30, 2013 increased $55 million, or 28%, compared to the three months ended June 30, 2012 primarily due to:


•	$50 million of gross margin mainly from the extinguishment of a liability at Uruguaiana of $57 million in June 2013 based on the favorable decision issued by an arbitration panel in which Uruguaiana was legally released of this obligation; and


•	positive impact of $20 million at Tietê driven by the higher prices of energy sold, offset by higher energy costs on the spot market.

These increases were partially offset by:


•	higher energy purchases of $15 million at Tietê mainly driven by hydrologic risk requirement among hydro generators at higher spot prices.

Excluding the unfavorable impact of foreign currency translation, for the three months ended June 30, 2013, revenue increased 8%, while gross margin increased by 28%, primarily due to the extinguishment of a liability at Uruguaiana due to a favorable arbitration decision offset by higher energy purchased at Tietê.

Excluding the unfavorable impact of foreign currency translation of $65 million, generation revenue for the six months ended June 30, 2013 increased $151 million, or 26%, compared to the six months ended June 30, 2012 primarily due to:


•	higher volume of $117 million mainly driven by $93 million from generation at Uruguaiana due to the temporary restart of operations during February and March of 2013; and


•	higher prices of $34 million at Tietê mainly due to $29 million of PPA annual indexation in July 2012.

Excluding the unfavorable impact of foreign currency translation of $34 million, generation gross margin for the six months ended June 30, 2013 increased $13 million, or 3%, compared to the six months ended June 30, 2012 primarily due to:


•	the reversal of a liability of $57 million and temporary restart of operations at Uruguaiana as mentioned above; and


•	lower operating and maintenance costs of $6 million at Tietê.

These increases were partially offset by:


•	negative impact of $34 million at Tietê driven mainly by higher energy costs on the spot market, offset by higher prices in energy sold; and


•	higher energy purchases at Tietê of $23 million mainly due to hydrologic risk requirement among hydro generators at higher spot prices.

Excluding the unfavorable impact of foreign currency translation, for the six months ended June 30, 2013, revenue increased 26%, while gross margin increased by 3% mainly due to the higher energy costs at Tietê.

Brazil — Utilities

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



	For the Three Months Ended June 30,							For the Six Months Ended June 30,
	2013		2012			% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	1,202	$	1,230		-2	%	$	2,525	$	2,761	-9	%
Gross Margin	$	75	$	(27	)	-378	%	$	115	$	56	105	%

Excluding the unfavorable impact of foreign currency translation of $67 million, utilities revenue for the three months ended June 30, 2013 increased $39 million, or 3%, compared to the three months ended June 30, 2012 primarily due to:


•	higher tariffs of $67 million at Eletropaulo compared to the 2012 tariff reset provision, partially offset by lower pass through of energy and other costs.

These increases were partially offset by:


•	lower tariffs of $34 million at Sul mainly driven by lower pass through of energy and other operational costs.

Excluding the unfavorable impact of foreign currency translation of $4 million, utilities gross margin for the three months ended June 30, 2013 increased $106 million, or 393%, compared to the three months ended June 30, 2012 primarily due to:


•	higher tariffs of $85 million at Eletropaulo compared to the 2012 tariff reset provision;


•	lower fixed costs of $29 million mainly driven by the reversal of bad debt allowance; and


•	higher volume at Sul of $9 million due to the increase in market demand.

These increases were partially offset by:


•	lower tariffs of $22 million at Sul mainly driven by lower other operational costs included in the tariff.

Excluding the unfavorable impact of foreign currency translation, for the three months ended June 30, 2013, revenue increased 3%, while gross margin increased 393% primarily due to lower pass through costs at Eletropaulo which have no impact on gross margin and the reversal of bad debt allowance.

Excluding the unfavorable impact of foreign currency translation of $240 million, utilities revenue for the six months ended June 30, 2013 increased $4 million, or remained flat, compared to the six months ended June 30, 2012 primarily due to:


•	higher tariffs of $125 million at Eletropaulo mainly due to higher energy pass through costs and higher tariffs compared to the 2012 tariff reset provision.

These increases were partially offset by:


•	lower tariffs of $75 million at Sul mainly driven by lower energy pass through costs and a cumulative adjustment to regulatory assets and liabilities; and


•	lower volume of $46 million due to decreased market demand.

Excluding the unfavorable impact of foreign currency translation of $10 million, utilities gross margin for the six months ended June 30, 2013 increased $69 million, or 123%, compared to the six months ended June 30, 2012 primarily due to:


•	higher tariffs of $105 million at Eletropaulo compared to the 2012 tariff reset provision; and


•	lower fixed costs of $20 million mainly driven by the reversal of bad debt allowance, partially offset by higher pension costs and other.

These increases were partially offset by:


•	lower tariffs of $34 million at Sul mainly driven by a cumulative adjustment to regulatory assets and liabilities; and


•	lower volume of $20 million due to decreased market demand.

Excluding the unfavorable impact of foreign currency translation, for the six months ended June 30, 2013, revenue remained flat, while gross margin increased 123% primarily due to higher tariffs at Eletropaulo and the reversal of bad debt allowance.

MCAC SBU

MCAC — Generation

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



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	471	$	426	11	%	$	929	$	819	13	%
Gross Margin	$	123	$	122	1	%	$	210	$	227	-7	%

Excluding the favorable impact of foreign currency translation of $6 million, primarily in Mexico, generation revenue for the three months ended June 30, 2013 increased $39 million, or 9%, compared to the three months ended June 30, 2012 primarily due to:


•	the positive impact of $27 million at Andres - Los Mina in the Dominican Republic mainly due to higher spot and contract sales from increased demand and higher volume of gas sales to third parties; and


•	higher rates of $20 million at Merida and Puerto Rico, mainly due to higher fuel prices.

These increases were partially offset by:

• lower contract prices of $7 million at Itabo in the Dominican Republic, primarily related to lower fuel costs.

Excluding the favorable impact of foreign currency translation of $2 million, gross margin for the three months ended June 30, 2013 decreased $1 million, or 1%, compared to the three months ended June 30, 2012 primarily due to:


•	a decrease in Panama of $50 million mainly due to replacement energy purchases at higher prices caused by lower hydrology.

These decreases were partially offset by:


•	reimbursement costs in Panama of $31 million resulting from a settlement with the EPC contractor over the Esti tunnel collapse; and


•	an increase of $21 million at Andres - Los Mina mainly from higher contract energy prices and higher spot sales as discussed above.

Excluding the favorable impact of foreign currency translation, for the three months ended June 30, 2013, revenue increased 9%, while gross margin decreased 1% primarily due to higher energy purchases in Panama partially offset by the reimbursement of Esti costs.

Excluding the favorable impact of foreign currency translation of $8 million, primarily in Mexico, generation revenue for the six months ended June 30, 2013 increased $102 million, or 12%, compared to the six months ended June 30, 2012 primarily due to:


•	the positive impact of $69 million at Andres - Los Mina mainly due to higher spot and contract sales from increased demand and higher international gas prices and volume of gas sales to third parties; and


•	an increase of $45 million in Merida and Puerto Rico primarily due to higher volume and rates.

These increases were partially offset by:


•	lower contract prices of $14 million at Itabo, primarily related to lower fuel costs.

Excluding the favorable impact of foreign currency translation of $2 million, generation gross margin for the six months ended June 30, 2013 decreased $19 million, or 8%, compared to the six months ended June 30, 2012 primarily due to:


•	a decrease in Panama of $50 million mainly due to replacement energy purchases at higher prices caused by lower hydrology;


•	higher fixed costs across the segment of $14 million mainly due to maintenance performed at Itabo; and


•	a decrease of $12 million at Andres-Los Mina mainly due to higher energy purchases caused by outages.

These decreases were partially offset by:


•	an increase of $37 million at Andres -Los Mina mainly from higher contract energy and spot sales and higher volume of gas sales to third parties; and


•	reimbursement costs in Panama of $31 million, resulting from a settlement with the EPC contractor over the Esti tunnel collapse.

Excluding the favorable impact of foreign currency translation, for the six months ended June 30, 2013, revenue increased 12%, while gross margin decreased by 8% primarily due to higher energy purchases in Panama and in the Dominican Republic, partially offset by the reimbursement of Esti costs.

EMEA SBU

EMEA — Generation

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



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	314	$	269	17	%	$	665	$	746	-11	%
Gross Margin	$	102	$	83	23	%	$	223	$	330	-32	%

Excluding the unfavorable impact of foreign currency translation of $2 million, generation revenue for the three months ended June 30, 2013 increased $47 million, or 17%, compared to the three months ended June 30, 2012 primarily due to:


•	higher revenue of $21 million at our plants in the U.K. driven by higher volume and prices at Kilroot and higher prices and volume along with better reliability at Ballylumford;


•	new business impact of $12 million for the commencement of operations at Kribi in Cameroon in May 2013; and


•	higher volume of $9 million in Kazakhstan mainly driven by higher electricity sales from higher inflows and increased capacity.

Generation gross margin for the three months ended June 30, 2013 increased $19 million, or 23%, compared to the three months ended June 30, 2012 primarily due to:


•	higher margin of $12 million at our plants in the U.K. driven by the items discussed above, lower coal costs and fixed costs, partially offset by higher gas costs related to higher demand, higher cost of CO₂ emissions which were free in 2012, and insurance proceeds in prior year; and


•	new business impact of $9 million in Africa driven by new operations at Kribi as discussed above.

Excluding the unfavorable impact of foreign currency translation, for the three months ended June 30, 2013, revenue increased 17%, while gross margin increased 23% primarily due to the contribution from Kribi partially offset by higher cost of gas and higher cost of CO₂ emissions.

Excluding the unfavorable impact of foreign currency translation of $4 million, generation revenue for the six months ended June 30, 2013 decreased $77 million, or 10%, compared to the six months ended June 30, 2012 primarily due to:


•	a decrease of $119 million as a result of the sale of 80% of our ownership of Cartagena, in Spain, in February 2012 and a non-recurring favorable arbitration settlement in the first quarter of 2012; and


•	lower volumes of $10 million at Maritza in Bulgaria mainly due to a lower net capacity factor.

These decreases were partially offset by:


•	higher revenue of $28 million at our plants in the U.K. driven by higher prices and higher dispatch at Kilroot and better reliability partially offset by lower prices primarily due to reduction in capacity remuneration in line with the PPA at Ballylumford;


•	new business impact of $12 million in Africa for the commencement of operations at Kribi in Cameroon; and


•	an increase of $7 million in Kazakhstan mainly driven by higher electricity sales from higher inflows and increased capacity.

Generation gross margin for the six months ended June 30, 2013 decreased $107 million, or 32%, compared to the six months ended June 30, 2012 primarily due to:


•	a decrease of $105 million at Cartagena as a result of the sale of 80% or our ownership in February 2012 and from a non-recurring favorable arbitration settlement in Q1 2012;


•	lower prices of $40 million at Ballylumford as a result of reduced capacity as discussed above, 2012 insurance proceeds, and unfavorable gas prices.

These decreases were partially offset by:


•	impact of $21 million due to better reliability at Ballylumford in U.K. due to lower forced outages in 2013 and planned outages that occurred in 2012;


•	higher rates and volume of $18 million at Kilroot due to an increase in electricity prices in 2013, lower fuel costs and higher dispatch, partially offset by higher cost of CO₂ allowances which were free in 2012; and


•	new business impact of $9 million in Africa for the commencement of operations at Kribi in Cameroon.

Excluding the unfavorable impact of foreign currency translation, for the six months ended June 30, 2013, revenue decreased 10%, while gross margin decreased 32% primarily due to the sale of 80% of our ownership in Cartagena in February 2012.

Asia SBU

Asia — Generation

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,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	143	$	182	-21	%	$	277	$	364	-24	%
Gross Margin	$	48	$	59	-19	%	$	89	$	113	-21	%

Generation revenue for the three months ended June 30, 2013 decreased $39 million, or 21%, compared to the three months ended June 30, 2012 primarily due to:


•	lower prices of $29 million at Masinloc in the Philippines as a result of lower bilateral contract rates reducing previous spot exposure and, lower spot prices due to higher grid availability; and


•	lower volume of $25 million at Kelanitissa in Sri Lanka attributable to lower off-taker demand as a result of higher hydrology.

These decreases were partially offset by:


•	higher volume of $13 million at Masinloc due to higher contract customer demand.

Generation gross margin for the three months ended June 30, 2013 decreased $11 million, or 19%, compared to the three months ended June 30, 2012 primarily due to decrease of $13 million attributable to lower margins resulting from lower rates, partially offset by higher contract demand at Masinloc.

Generation revenue for the six months ended June 30, 2013 decreased $87 million, or 24%, compared to the six months ended June 30, 2012 primarily due to:


•	lower volume of $50 million at Kelanitissa attributable to lower off-taker demand as a result of higher hydrology;


•	lower prices of $50 million at Masinloc as discussed above; and


•	a decrease of $8 million at Masinloc due to the favorable impact of a mark-to-market inflation-related derivative adjustment in the six months ended June 30, 2012.

These decreases were partially offset by:


•	higher volume of $21 million at Masinloc due to higher contract customer demand.

Generation gross margin for the six months ended June 30, 2013 decreased $24 million, or 21%, compared to the six months ended June 30, 2012 primarily due to:


•	a decrease of $15 million largely attributable to lower margins from lower rates and lower spot sales, partially offset by higher contract demand at Masinloc; and


•	a decrease of $8 million at Masinloc due to the favorable impact of a mark-to-market inflation-related derivative adjustment in the six months ended June 30, 2012.

Corporate and Other

Corporate and other includes the net operating results from our utility businesses in El Salvador and Africa, which are immaterial for purposes of separate segment disclosure. The following table includes 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,
	2013			2012			% Change		2013			2012			% Change
	($’s in millions)
Revenue
El Salvador Utilities	$	223		$	216		3	%	$	434		$	419		4	%
Africa Utilities	119			92			29	%	226			222			2	%
Corporate/Other	1			2			-50	%	3			5			-40	%
Total Corporate and Other	$	343		$	310		11	%	$	663		$	646		3	%
Gross Margin
El Salvador Utilities	$	26		$	12		117	%	$	44		$	28		57	%
Africa Utilities	(5		)	(15		)	67	%	(13		)	(5		)	-160	%
Corporate/Other	(1		)	—			NA		(4		)	(3		)	-33	%
Total Corporate and Other	$	20		$	(3	)	767	%	$	27		$	20		35	%

Excluding the favorable impact of foreign currency translation of $2 million, revenue for the three months ended June 30, 2013 increased $31 million, or 10%, compared to the three months ended June 30, 2012, primarily due to:


•	the favorable impact of a mark-to-market derivative adjustment of $16 million at Sonel in Cameroon driven by a derivative loss in the second quarter of 2012; and


•	higher rates and volume of $7 million in El Salvador mainly due to a tariff increase approved by the regulator at the beginning of 2013.

Gross margin for the three months ended June 30, 2013 increased by $23 million, or 767%, compared to the three months ended June 30, 2012, primarily due to:


•	the favorable impact of a mark-to-market derivative adjustment of $16 million at Sonel as discussed above; and


•	higher rates of $15 million in El Salvador due to the tariff increase as discussed above.

These increases were partially offset by:


•	higher energy purchases of $11 million at Sonel due to the delay in the Kribi plant commissioning.

Excluding the favorable impact of foreign currency translation, for the three months ended June 30, 2013, revenue increased 10%, while gross margin increased by 767% primarily due to the impact of higher pass-through energy costs in El Salvador.

Excluding the favorable impact of foreign currency translation of $3 million, revenue for the six months ended June 30, 2013 increased $14 million, or 2%, compared to the six months ended June 30, 2012, primarily due to:


•	higher rates and volume of $15 million in El Salvador due to the tariff increase as discussed above; and


•	higher volume of $5 million at Sonel mainly due to increased demand.

These increases were partially offset by:


•	lower rates at Sonel of $6 million mainly due to a favorable 2011 tariff compensation adjustment in the first quarter 2012.

Gross margin for the six months ended June 30, 2013 increased by $7 million, or 35%, compared to the six months ended June 30, 2012, primarily due to:


•	higher rates and volume of $18 million in El Salvador mainly due to the tariff increase as discussed above.

These increases were partially offset by:


•	lower rates at Sonel of $7 million mainly due to a favorable 2011 tariff compensation adjustment in the first quarter 2012 as discussed above.

Excluding the favorable impact of foreign currency translation, for the six months ended June 30, 2013, revenue increased 2%, while gross margin increased by 35% primarily due to higher rates in El Salvador.

General and administrative expenses

General and administrative expenses decreased $15 million, or 20%, to $59 million for the three months ended June 30, 2013 primarily due to Company restructuring efforts, resulting in a decrease in employee related costs and professional fees.

General and administrative expenses decreased $41 million, or 25%, to $120 million for the six months ended June 30, 2013 primarily due to Company restructuring efforts, resulting in a decrease in employee related costs, professional fees and business development costs.

Interest expense

Interest expense decreased $38 million, or 10%, to $346 million for the three months ended June 30, 2013. The decrease was primarily due to gains resulting from ineffectiveness on interest rate swaps in Puerto Rico that continue to qualify for hedge accounting.

Interest expense decreased $77 million, or 10%, to $723 million for the six months ended June 30, 2013. The decrease was primarily due to gains resulting from ineffectiveness on interest rate swaps in Puerto Rico, as discussed above, as well as lower interest rates and favorable foreign currency translation in Brazil. These decreases were partially offset by interest on regulatory liabilities following the tariff reset in Brazil.

Interest income

Interest income decreased $19 million, or 23%, to $63 million for the three months ended June 30, 2013. The decrease was primarily in Brazil, due to lower average short-term investment balances, lower interest rates and unfavorable foreign currency translation.

Interest income decreased $44 million, or 25%, to $129 million for the six months ended June 30, 2013. The decrease was primarily in Brazil, due to lower average short-term investment balances, lower interest rates and unfavorable foreign currency translation.

Loss on extinguishment of debt

Loss on extinguishment of debt was $165 million for the three months ended June 30, 2013. This loss was primarily related to the early retirement of recourse debt at the Parent Company. See Note 7. — Debt included in Item 1. — Financial Statements of this Form 10-Q for further information.

Loss on extinguishment of debt was $212 million for the six months ended June 30, 2013. This loss was primarily related to the loss on the early retirement of recourse debt discussed above and the loss on the early extinguishment of debt at Masinloc.

Other income and expense

See discussion of the components of other income and expense in Note 12 — Other Income and Expense included in Item 1. — Financial Statements of this Form 10-Q for further information.

Asset impairment expense

Asset impairment expense was $0 million and $48 million, respectively, for the three and six months ended June 30, 2013, and $18 million and $28 million, respectively for the three and six months ended June 30, 2012. See Note 13 — 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, 2013 was $20 million, which is primarily related to the sale of our remaining 20% interest in Cartagena. 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 investments for the six months ended June 30, 2013 was $23 million, which is primarily related to the sale of our remaining 20% interest in Cartagena, as discussed above. 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. See Note 15. — Dispositions included in Item 1. — Financial Statements of this Form 10-Q for further information.

Foreign currency transaction gains (losses)

Foreign currency transaction gains (losses) were as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	($ in millions)
AES Corporation	$	8		$	(34	)	$	(23	)	$	(16	)
Chile	(10		)	(6		)	(14		)	3
Brazil	(7		)	(9		)	(10		)	(6		)
Philippines	(7		)	(42		)	(7		)	(66		)
Argentina	1			(6		)	(3		)	(12		)
Other	(2		)	(4		)	8			(5		)
Total⁽¹⁾	$	(17	)	$	(101	)	$	(49	)	$	(102	)

___________________________________________


(1)	Includes $17 million in gains and $41 million in losses on foreign currency derivative contracts for the three months ended June 30, 2013 and 2012, respectively, and $19 million in gains and $80 million in losses on foreign currency derivative contracts for the six months ended June 30, 2013 and 2012, respectively.

The Company recognized net foreign currency transaction losses of $17 million for the three months ended June 30, 2013 primarily due to:


•	losses of $10 million in Chile were primarily due to a 5% weakening of the Chilean Peso, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos, primarily cash, accounts receivables and VAT receivables. These losses were partially offset by income on foreign currency derivatives.

The Company recognized foreign currency transaction losses of $101 million for the three months ended June 30, 2012 primarily due to:


•	losses of $34 million at The AES Corporation were primarily due to decreases in the valuation of intercompany 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 of $42 million 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; and


•	losses of $9 million in Brazil that were 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 losses of $49 million for the six months ended June 30, 2013 primarily due to:


•	losses of $23 million at The AES Corporation were primarily due to decreases in the valuation of intercompany notes receivable denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the year, partially offset by gains related to foreign currency options;


•	losses of $14 million in Chile which were primarily due to a 6% weakening of the Chilean Peso, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos, primarily cash, accounts receivables and VAT receivables. Additional losses were related to foreign currency derivatives; and


•	losses of $10 million in Brazil which were 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 losses of $102 million for the six months ended June 30, 2012 primarily due to:


•	losses of $16 million at The AES Corporation which were primarily due to decreases in the valuation of intercompany 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 of $66 million in the Philippines which 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; and

•

losses of $12 million in Argentina which were primarily related to losses due to the weakening of the Argentine Peso by 5%, resulting in losses at AES Argentina Generacion (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.

Other non-operating expense

There was no other non-operating expense for the three and six months ended June 30, 2013. Total other non-operating expense was $1 million and $50 million for the three and six months ended months ended June 30, 2012.

In the first quarter of 2012 the Company concluded that it was more likely than not that it would sell its interest in its equity method investments in China and France and recorded other-than-temporary impairments of $32 million and $17 million respectively.

Income tax expense

Income tax expense increased $6 million, or 8%, to $81 million for the three months ended June 30, 2013 compared to $75 million for the three months ended June 30, 2012. The Company’s effective tax rates were 20% and 37% for the three months ended June 30, 2013 and 2012, respectively.

The net decrease in the effective tax rate for the three months ended June 30, 2013 compared to the same period in 2012 was due, in part, to a decrease in U.S. taxes applicable to certain non-U.S. subsidiaries, net favorable resolution of various uncertain tax positions, and lower tax expense from certain higher tax jurisdictions.

Income tax expense decreased $180 million, or 52%, to $163 million for the six months ended June 30, 2013 compared to $343 million for the six months ended June 30, 2012. The Company’s effective tax rates were 23% and 35% for the six months ended June 30, 2013 and 2012, respectively.

The net decrease in the effective tax rate for the six months ended June 30, 2013 compared to the same period in 2012 was due, in part, to the extension of a favorable U.S. tax law in the first quarter of 2013 impacting distributions from certain non-U.S. subsidiaries, net favorable resolution of various uncertain tax positions, and lower tax expense from certain higher tax jurisdictions.

We anticipate that our effective tax rate in 2014 and beyond will be higher than our reported effective tax rate for 2013. This is due, in part, to one-time factors positively influencing the 2013 rate as well as an anticipated increase beyond 2013 in U.S. taxes on distributions from certain non-U.S. subsidiaries and the lapse of a tax holiday at one of our subsidiaries in Asia.

Our effective tax rate reflects the tax effect of significant operations outside the United States, which are generally taxed at rates lower than the U.S. statutory rate of 35 percent. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate.

Net equity in earnings of affiliates

Net equity in earnings of affiliates decreased $9 million, or 82%, to $2 million for the three months ended June 30, 2013. The decrease was primarily due to decreased earnings at Entek in Turkey resulting from a loss on an embedded foreign currency derivative.

Net equity in earnings of affiliates decreased $18 million, or 75%, to $6 million for the six months ended June 30, 2013. The decrease was primarily related to a loss on an embedded foreign currency derivative at Entek as well as the sale of Yangcheng in China during the third quarter of 2012. This was partially offset by increased earnings from higher generation revenue at Elsta in the Netherlands due to fewer planned outages.

Income from continuing operations attributable to noncontrolling interests

Income from continuing operations attributable to noncontrolling interests increased $99 million, or 148%, to $166 million for the three months ended June 30, 2013. The increase was primarily due to higher distribution revenue at Eletropaulo as a result of the tariff reset adjustment in 2012, increased gross margin at Uruguaiana caused by a favorable arbitration settlement and the commencement of operations at Ventanas IV in Chile.

Income from continuing operations attributable to noncontrolling interests increased $41 million, or 17%, to $281 million for the six months ended June 30, 2013. The increase was primarily due to higher distribution revenue at Eletropaulo as a result of the tariff reset adjustment in 2012 and increased gross margin at Uruguaiana caused by a favorable arbitration settlement and the temporary restart of operations in the first quarter of 2013. This was partially offset by a decrease in operating income at Tietê in 2013 related to lower water inflows in the system resulting in a higher allocation of energy purchases at higher spot prices and a reduction in income at Cartagena which was deconsolidated in February 2012 as a result of the sale of 80% of our interest.

Discontinued operations

Total discontinued operations was a net income of $3 million and net income of $70 million for the three months ended June 30, 2013 and 2012, respectively. Total discontinued operations was a net loss of $19 million and net income of $71 million for the six months ended June 30, 2013 and 2012, respectively. See Note 14 — Discontinued Operations and Held for Sale Businesses included in Item 1. — Financial Statements of this Form 10-Q for further information.

Key Trends and Uncertainties

During the remainder of 2013 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below 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. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1. — Business and Item 1A. — Risk Factors of the 2012 Form 10-K.

Regulatory

Rate Case Proceedings

DP&L, our utility business in Ohio, is in the process of its regulated rate case review by the regulator. The outcome of the rate case will determine the amount that DP&L can charge to customers for electricity.

DP&L — On October 5, 2012, DP&L filed an Electric Security Plan ("ESP") with the Public Utilities Commission of Ohio (“PUCO”) to establish Standard Service Offer ("SSO") rates that were to be in effect starting January 1, 2013. The plan was refiled on December 12, 2012 to correct for certain projected costs. The plan requested approval of a non-bypassable charge that is designed to recover $138 million per year for five years from all customers. DP&L also requested approval of a switching tracker that would measure the incremental amount of switching over a base case and defer the lost value into a regulatory asset which would be recovered from all customers beginning January 2014. The ESP states that DP&L plans to file on or before December 31, 2013 its plan for legal separation of its generation assets. The ESP proposes a three year, five month transition to market, whereby a wholesale competitive bidding structure will be phased in to supply generation service to customers located in DP&L’s service territory that have not chosen an alternative generation supplier. As a result of this filing, DP&L’s overall SSO generation revenue is projected to decrease by approximately $46 million for the first year, due to a portion of DP&L’s SSO load being sourced through a competitive bid and other adjustments that were made to the SSO generation rates. As more SSO supply is sourced through a competitive bid, DP&L will continue to experience a decrease in SSO generation revenue each year throughout the blending period. DP&L’s retail transmission rates will increase as a retail, non-bypassable transmission charge will be implemented; however, this revenue will be offset slightly by a decrease in wholesale transmission revenue from Competitive Retail Electric Service Providers operating in DP&L’s service territory. An evidentiary hearing on this case was held March 18, 2013 through April 3, 2013. An order is expected to be issued by the PUCO in the third quarter of 2013. The PUCO authorized that the rates being collected prior to December 31, 2012 would continue until the new ESP rates go into effect. The final order could have a material adverse impact on our results of operations and cash flows. See Item 1. — Business — US SBU Businesses — U.S. Utilities, DPL Inc. included in the 2012 Form 10-K for further information. In addition, as also noted in the 2012 Form 10-K (see preceding reference), DPL has 2013 Debt maturities of approximately $470 million that are due in October. DPL is evaluating its options with regard to refinancing this debt, including through the issuance of long or short-term debt securities or through a syndicated term or other bank loan, or a combination of debt instruments. DP&L also faces a number of additional uncertainties related to the impact of customer switching and low power prices which could impact DP&L’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 remaining goodwill. Any of the above-referenced conditions, events or factors could have a material impact on the Company or its results of operations.

Operational

Fluctuations in Foreign Exchange Rates—The Company is sensitive to changes in political and economic conditions and market rates, including foreign exchange rates. In many countries AES operates in, weakening of economic indicators, such as slowing growth, increased inflation and deficits, devaluation of the local currency, and currency convertibility restrictions could have material impacts on the Company. Potential outcomes can include negative impacts in our gross margin and cash flows, and create an inability of the business to pay dividends or obtain currency to service foreign obligations, all of which can negatively impact the value of our assets. See Item 3 — Quantitative and Qualitative Disclosures about Market Risk of this Form 10-Q for more information.

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 2012 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.” If the current foreign currency exchange rate volatility continues, our gross margin and other financial metrics could continue to be affected.

Fluctuations in Commodity Prices —The Company is sensitive to changes in fuel prices. High coal prices relative to natural gas creates pressure at some of our businesses, which may affect the results of certain of our coal plants, particularly those which are merchant plants that are exposed to market risk and to a lesser extent those that contracted with limited fuel price pass-through. See Item 3 — Quantitative and Qualitative Disclosures About Market Risk of this Form 10-Q for more information.

Sensitivity to Weather Conditions

Brazil—Given that approximately two-thirds of Brazil’s electric supply is dependent upon hydroelectric generation, changes in weather conditions can have a significant impact on reservoir levels and electricity prices. Lower than expected rainfall during the spring and summer has caused reservoir levels to be lower than their historical levels and affected the availability of hydroelectric generation facilities. Higher thermal dispatch has been maintained in order to recover the reservoir levels. If reservoir levels are not able to recover, or deteriorate further, it is expected that higher thermal dispatch will cause more volatility in spot prices. Although the purchased energy cost is a pass-through for AES’s distribution businesses in Brazil, gaps between the purchase of energy and recovery in the tariff could cause temporary cash flow constraints on those businesses, except in 2013 when these gaps are being recovered on a monthly basis due to a special regulation. Our hydroelectric generation facilities may be required to purchase energy even if they have sufficient water to cover their contractual commitments if the overall system does not have adequate supply, since the water is treated as a shared resource among all hydroelectric generators. To the extent that a hydroelectric generation facility needs to purchase energy to meet its contractual requirements, rather than generate, purchasing can be more expensive, thereby creating negative margin on part of those contracts, which could have a material adverse impact on our results of operations.

Panama—Given that approximately 61% of Panama's electric supply is dependent upon hydroelectric generation based on rainfalls with a balanced mix of conventional and run-of-the-river hydro plants (50%/50%), changes in weather conditions can have a significant impact in the hydroelectric production, reservoir levels and electricity prices. Lower than expected rainfall during the spring and summer has affected the hydroelectric generation. In Panama there are two distinct seasons: (i) the dry season, which is between December and April when stored water in the reservoirs is used; and (ii) the rainy season which is the remainder of the months, when the reservoirs are filled. The latest weather forecast from Hidromet (the local weather authority) is showing that rainfalls will be lower than historical average for the rest of the year. Expectations of returning to a normal pattern are only anticipated to occur by December. Meanwhile, the AES Panama Business, which is 100% hydroelectric generation, is expected to experience a reduction in production and sales as a consequence of lower inflows. Although we expect to have sufficient water inflows to cover our contractual commitments, we are highly dependent upon the anticipated rainfall. We continue to monitor the situation. If we do not have sufficient rainfall, we would need to purchase energy to fulfill our contractual commitments which could have a material adverse impact on our results of operations.

Colombia—Colombia's Interconnected System (SIN) is dependent on weather conditions given that approximately two-thirds of Colombia's installed capacity comes from hydroelectric generation. Therefore, variations in weather conditions have a significant impact in the levels of the reservoirs and electricity prices. In Colombia there are two seasons: (i) the dry season, which is between December and April when reservoirs use the stored water; and (ii) the rainy season, for the period between May and November, when the reservoirs are filled. The hydrological conditions that have been experienced during the first six

months of 2013 have been drier than what has been historically experienced. This has caused the reservoir levels and the inflows to be lower than normal. We continue to monitor the situation. Although we have seen an improvement in July 2013, if we do not receive sufficient rainfall to refill the reservoir levels, we would need to purchase energy to fulfill our contractual commitments which could have a material adverse impact to our results of operations.

Chile — Chile's Central Interconnected System (SIC) is dependent on hydrological conditions, rainfall and snowpack during the winter months in South America to determine reservoir levels and snow melting in the spring and summer months to determine inflows, both of which determine the dispatch of hydroelectric vs. thermal generation and electricity prices. The SIC has experienced dry conditions during the first half of the year and hydrology has been volatile since the beginning of the wet season which starts in April. If the system does not experience significant rainfall and conditions prevail through the end of rainy season which is August, electricity prices are expected to remain high through the beginning of next year driven by the need for increased dispatch of thermal generation. Although our portfolio in the SIC is primarily contracted and our run-of-the-river hydroelectric generation is more stable than the rest of the system, revenues from our hydroelectric facilities may suffer temporary declines as a result of drier conditions. To the extent that we are required to purchase spot energy during periods of dry hydrological conditions in case of lower production of energy from our own plants (less water for our hydroelectric plants or temporary outages in our thermal plants), we may be required to purchase energy at a higher cost than contract prices to meet our contractual requirements, which could have a material adverse impact on our results of operations and cash flows.

Macroeconomic and Political

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, several European Union countries continue to face uncertain economic environments, 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.

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 2012 Form 10-K and Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk of this Form 10-Q, the Company’s U. S. businesses continue to face pressure as a result of low natural gas prices, which is the marginal price-setting fuel in most U. S. markets. 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. The impact was reduced in 2013 as some of the U.S. markets in which we operate have experienced increased natural gas prices, which has resulted in increased wholesale energy prices as compared to 2012. IPL in Indiana benefits from high wholesale power prices in periods where our available generation exceeds our captive load obligations. At DPL in Ohio, where retail competition exists, our coal-fired generating assets sell excess power into the deregulated market and are subject to greater sensitivity to changes in power prices. Businesses that have a PPA in place, but purchase fuel at market prices or under short term contracts may not be fully hedged against changes in either power or fuel prices.

Argentina — In Argentina, the deterioration of certain economic indicators such as non-receding inflation, increased government deficits and foreign currency accessibility combined with the potential devaluation of the local currency and the potential fall in export commodity prices could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to the Parent Company, and the value of our assets. At June 30, 2013, AES had noncurrent assets of $556 million in Argentina, including long-term receivables of $309 million. See Note 6 — Long-term Financing Receivables in Item 1. — Financial Statements of this Form 10-Q for further information on the long-term receivables.

Bulgaria — Our investments in Bulgaria rely on offtaker contracts with NEK, the state-owned national electricity distribution company. Maritza, a coal-fired generation facility, has experienced ongoing delays in the collection of outstanding receivables from its offtaker. As of June 30, 2013, Maritza had an outstanding receivables balance of $104 million with the offtaker, which represents 106 days sales outstanding. Although Maritza continued to collect past due receivables during the second quarter of 2013, there can be no assurance that the business will continue making collections, which could result in a write-off of the remaining 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 another default of its loan covenants. The Company has long-lived assets in Bulgaria of $1.8 billion and net equity of $587 million. See Note 7 — Debt for further information on current existing debt defaults. Further, Maritza is in litigation related to construction delays and related matters. For further information on the litigation see Item 1 — Legal Proceedings. In addition, as disclosed in Note 29 — Subsequent Events to our consolidated financial statements included in Item 8. — Financial Statements and Supplementary Data of the 2012 Form

10-K, earlier this year, there were protests in Bulgaria related to power prices. The prime minister resigned and following the preliminary elections in May 2013, the political situation in the country remains unstable. Energy legislation was amended in the beginning of July 2013 and the Bulgarian Regulator is currently developing the new energy sector rules and regulations. At this time, it is difficult to predict the impact of these political conditions on our businesses in Bulgaria. Furthermore, as noted in Item 1. — Business — Bulgaria in our 2012 Form 10-K, certain regulators are reviewing the impact on competition of NEK's long-term contracts. Other events, such as NEK's efforts to comply with the EU's Third Energy Package, nonpayment of receivables or other events could also result in a termination of the PPA, in which case substantial amounts may be owed by NEK to Maritza. For further information regarding a potential restructuring of NEK to comply with the EU's Third Energy package, see Item 1. - Business - Bulgaria in our 2012 Form 10-K. 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 2012 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 (or be unable to exercise remedies for a breach of the PPA) and may 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.

Euro Zone — 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. 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 2012 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. The carrying value of our investment in AES Solar Energy Ltd., whose primary operations are in Europe, was $122 million at June 30, 2013. 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.

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 pursuant to 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

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. In the fourth quarter of 2012, the Company completed its annual October 1 goodwill impairment evaluation and identified two reporting units, DPL and Ebute, which 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%. During the three months ended June 30, 2013, the Company performed an interim impairment test of goodwill at Ebute, but no adjustment was necessary as the reporting unit passed step 1 of the test. While there were no potential impairment indicators during the three months ended June 30, 2013 related to DPL that could result in the recognition of goodwill impairment, it is possible that we may incur goodwill impairment at DPL, Ebute or any of our reporting units in future periods if adverse changes in their business or operating environments occur. The carrying amount of the goodwill at DPL and Ebute as of June 30, 2013 was approximately $759 million and $58 million, respectively. In 2012, the Company had recognized goodwill impairment of $1.82 billion at the DP&L reporting unit.

Environmental

The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to

these environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts), and certain air emissions, such as SO₂, NO_x, particulate matter and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. 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, 2012. The following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in Item 1. — Business — Regulatory Matters — Environmental and Land Use Regulations of the Company’s Form 10-K for the year ended December 31, 2012 and in Item 2. — Management's Discussion and Analysis of Financial Condition and Results of Operations - Key Trends and Uncertainties - Regulatory - Environmental. For further information about environmental laws and regulations impacting the Company, including a discussion of U.S. and international legislation and regulation of GHG emissions, 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, 2012 and Item 2. — Management's Discussion and Analysis of Financial Condition and Results of Operations - Key Trends and Uncertainties - Regulatory - Environmental.

Update on Greenhouse Gas Regulation

As further described in Item 1. — Business - Regulatory Matters - United States - Federal Greenhouse Gas Legislation and Regulation in the Company's Form 10-K for the year ended December 31, 2012, the EPA proposed a rule on March 27, 2012 that would establish new source performance standards (“NSPS”) for greenhouse gas (“GHG”) emissions from newly constructed fossil-fueled electric utility steam generating units (“EUSGUs”) larger than 25 megawatts. The period for public comments on such proposed rule expired on June 12, 2012. On June 25, 2013, the President of the United States directed the EPA to issue a new proposed rule establishing NSPS for CO₂ emissions for newly constructed fossil-fueled EUSGUs larger than 25 MW by September 30, 2013, and to issue a final rule in a timely fashion after considering all public comments. The EPA subsequently indicated its intention to issue a new proposed rule to address GHGs from newly constructed fossil-fueled power plants by September 2013. Any such proposed rule would not apply to existing EUSGUs, including the Company's subsidiaries' existing power plants.

In his June 25, 2013 announcement, the President also directed the EPA to issue new standards, regulations, or guidelines, as appropriate, that address CO₂ emissions from existing power plants. The President directed the EPA to:


•	issue a proposed rule by June 1, 2014;


•	issue a final rule by June 1, 2015; and


•	require that States submit their implementation plans to the EPA by no later than June 30, 2016.

It is impossible to estimate the impact and compliance costs associated with any future EPA regulations applicable to new, modified or existing EUSGUs until such regulations are finalized; however, the impact, including the compliance costs, could be material to our consolidated financial condition or results of operations.

Update on Air Emissions Regulations and Legislation

As further discussed in Item 2. — Management's Discussion and Analysis of Financial Condition and Results of Operations - Key Trends and Uncertainties - Regulatory - Environmental - Update on Air Emissions Regulations and Legislation in the Company's Form 10-Q for the quarterly period ended March 31, 2013, primarily as a result of existing and expected environmental regulations, including the Mercury Air Toxics Standards ("MATS"), IPL plans to have retired several generating units fueled by either coal or oil (approximately 640 MW total net generating capacity) by April 2017 and to expend significant capital expenditures on environmental controls and upgrades. In accordance with this plan, in the second quarter of 2013 IPL retired in place five oil-fired peaking units with an average life of approximately 61 years and a total generating capacity of 168 MW (leaving approximately 472 MW to be retired). Although these units represented approximately 5% of IPL's generating capacity, they were seldom dispatched by Midcontinent Independent System Operator, Inc. in recent years due to their relatively higher production cost and in some instances repairs were needed. In order to replace the generation capacity loss resulting from the recent and future retirement of the generating units discussed above, in April 2013 IPL filed a petition and case-in-chief with the Indiana Utility Regulatory Commission seeking a Certificate of Public Convenience and Necessity to

build a 550 to 725 MW combined cycle gas turbine at its Eagle Valley Station site and to refuel Harding Street Station Units 5 and 6 from coal to natural gas (106 MW each). The total estimated cost of these projects is $667 million.

As further discussed in Item 1. — Business - Regulatory Matters - United States - Other United States Environmental and Land Use Legislation and Regulations in the Company's Form 10-K for the year ended December 31, 2012, IPL filed a request for a Certificate of Public Convenience and Necessity in June 2012 for $511 million (including supplemental testimony), which is the amount of expenditures that IPL estimates is necessary through 2016 for environmental controls for its baseload generating units related to the MATS rule, excluding demolition costs. A hearing with the Indiana Utility Regulatory Commission ("IURC") was held on this matter in April 2013, and IPL expects to receive an order from the IURC within the next month.

In Item 2. — Management's Discussion and Analysis of Financial Condition and Results of Operations - Key Trends and Uncertainties - Regulatory - Environmental - Additional Environmental Regulatory Events Occurring During Quarter in the Company's Form 10-Q for the quarterly period ended March 31, 2013, the Company stated that the EPA and environmental and health organizations filed writs of certiorari with the U.S. Supreme Court requesting review of the decision by United States Circuit Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) vacating the EPA's Cross-State Air Pollution Rule. On June 24, 2013, the U.S. Supreme Court granted the EPA's and such environmental and health organizations' petitions for review of the D.C. Circuit's decision vacating the CSAPR. If the U.S. Supreme Court reinstates the CSAPR, the Company anticipates an increase in capital costs and other expenditures and the operational restrictions that would be required to comply with the CSAPR could have a material impact on the Company's business, financial condition and results of operations. If the U.S. Supreme Court affirms the D.C. Circuit's ruling vacating the CSAPR, the EPA may subsequently promulgate a replacement transport rule. At this time, we cannot predict the impact that such a replacement transport rule would have on the Company. However, such replacement rule could have a material impact on the Company's business, financial condition and results of operations.

As discussed in Item 1. — Business - Andes Businesses - Chile - Regulatory Framework - Other Regulatory Considerations in the Company's Form 10-K for the year ended December 31, 2012, a 2011 Chilean regulation provides for stringent limits on emission by thermoelectric power plants of particulate matter and gases produced by the combustion of solid and liquid fuels, particularly coal. For existing plants, including those currently under construction, the new limits for particulate matter emission will go into effect by the end of 2013 and the new limits for SO₂ (sulfur dioxide), NOx (nitrogen dioxide) and mercury emission will begin to apply in mid-2016, except for those plants operating in zones declared saturated or latent zones (areas at risk of or affected by excessive air pollution), where these emission limits will become effective by June 2015. In order to comply with these emission standards, AES Gener in Chile will invest approximately $330 million, at its older coal facilities, including its proportional investment in an equity-method investee, Guacolda. Through June 30, 2013, AES Gener has spent approximately $118 million, and the remaining $212 million will be invested between the remainder of 2013 and 2016 in order to comply within the required time frame.

Additional Environmental Regulatory Events Occurring During Quarter

Please see Item 2. — Management's Discussion and Analysis of Financial Condition and Results of Operations - Key Trends and Uncertainties - Regulatory - Environmental set forth in the Company’s Form 10-Q for the quarterly period ended March 31, 2013 for further information about the following events that occurred during the quarterly period ended June 30, 2013 and relate to the impact of environmental laws and regulations on the Company and its subsidiaries:


•	In April 2013, the EPA announced proposed rules to reduce pollutants discharged into waterways by power plants. These rules are updates to the existing rules and identify four preferred options for controlling the discharge of these pollutants. The EPA is required to finalize these rules by May 2014.

•

In April 2013, IPL received a two-year extension, through September 2017, of the compliance deadline required by the National Pollutant Discharge Elimination System ("NPDES") permits that the Indiana Department of Environmental Management issued to the IPL Petersburg, and Harding Street generating stations by the Indiana Department of Environmental Management. NPDES permits regulate specific industrial wastewater and storm water discharges to the waters of Indiana under Sections 402 and 405 of the U.S. Clean Water Act. These permits set new levels of acceptable metal effluent water discharge, as well as monitoring and other requirements designed to protect aquatic life.

•

In June 2013, DP&L's Hutchings generation station's Unit 4 was retired as part of DP&L's plan to retire by June 2015 the six coal-fired units aggregating approximately 360 MW at such generation station. DP&L is retiring these units as a result of existing and expected environmental regulations. Conversion of the coal-fired units to natural gas was investigated, but the cost of investment exceeded the expected return. In addition, DP&L owns approximately 207 MW of coal-fired generation at Beckjord Unit 6, which is operated by Duke Energy Ohio.

The co-owners of Beckjord Unit 6 have notified PJM that they plan to retire Beckjord Unit 6 by June 1, 2015. At this time, DP&L does not have plans to replace the units that will be retired.

Capital Resources and Liquidity

Overview

As of June 30, 2013, the Company had unrestricted cash and cash equivalents of $1.6 billion, of which approximately $111 million was held at the Parent Company and qualified holding companies, and approximately $703 million was held in short term investments primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $1.3 billion. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.4 billion and $5.7 billion, respectively. Of the approximately $2.9 billion of our current non-recourse debt, $1.2 billion was presented as such because it is due in the next twelve months and $1.7 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 $118 million of our recourse debt matures within the next twelve months, which we expect to repay using a combination of cash on hand at the Parent Company, net cash provided by operating activities and net proceeds from the issuance of new debt at the Parent Company.

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 $15.4 billion of total non-recourse debt outstanding as of June 30, 2013, approximately $4.1 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, 2013, 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 $640 million in aggregate (excluding 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, 2013, we had $3 million in letters of credit outstanding, provided under our senior secured credit facility, and $231 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, 2013, 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, 2013, the Company had approximately $353 million and $32 million of accounts receivable related to certain of its generation businesses in Argentina and the Dominican Republic, and its utility businesses in Brazil classified as “Noncurrent assets — other” and “Current assets — Accounts receivable,” respectively. The noncurrent portion primarily consists of accounts receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond June 30, 2014, or one year from the latest balance sheet date. The majority of Argentinian receivables have been converted into long-term financing for the construction of power plants. See Note 6 — Long-term Financing Receivables included in Item 1. — Financial Statements of this Form 10-Q and Item 1. — Business — Regulatory Matters — Argentina included in the 2012 Form 10-K for further information.

Consolidated Cash Flows

During the six months ended June 30, 2013, cash and cash equivalents decreased $355 million to $1.6 billion. The decrease in cash and cash equivalents was due to $1.2 billion of cash provided by operating activities, $706 million of cash used in investing activities, $799 million of cash used in financing activities, an unfavorable effect of foreign currency exchange rates on cash of $39 million and a $4 million decrease in cash of discontinued and held for sale businesses.

Operating Activities — Net cash provided by operating activities increased $71 million to $1.2 billion during the six months ended June 30, 2013 compared to $1.1 billion during the six months ended June 30, 2012.

Operating cash flow for the six months ended June 30, 2013 resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $310 million in operating assets and liabilities. This was primarily due to the following:


•	a decrease of $252 million in accounts payable and other current liabilities primarily at Eletropaulo due to a decrease in regulatory liabilities and a decrease in value added taxes payables due to the lower tariff in 2013 and at Uruguaiana primarily related to the extinguishment of a liability based on a favorable arbitration decision;


•	an increase of $147 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo, resulting from higher priced energy purchases which are recoverable through future tariffs;


•	a decrease of $134 million in net income tax and other tax payables primarily from payment of income taxes exceeding accruals for the tax liability on 2013 income, partially offset by an accrual of indirect taxes in Brazil; partially offset by


•	a decrease of $191 million in accounts receivable primarily due to lower tariffs at Eletropaulo and higher collections combined with lower tariffs and reduced consumption at Sul, partially offset by lower collections at Maritza.

Net cash provided by operating activities was $1.1 billion during the six months ended June 30, 2012. 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. This was primarily due to:


•	an increase of $293 million in other assets 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;


•	a decrease of $249 million in net income tax and other tax payables primarily due to the payment of income taxes in excess of accruals for new current tax liabilities;


•	an increase of $175 million in accounts receivable primarily due to lower collection rates at Maritza, Sonel and Itabo; partially offset by


•	an increase 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; and


•	an increase of $228 million in accounts payable and other current liabilities 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 payables.

This net increase of cash flows from operating activities of $71 million for the six months ended June 30, 2013 compared to the six months ended June 30, 2012 was primarily the result of the following:


•	US — an increase of $49 million at our generation businesses primarily due to proceeds of $60 million from the PPA termination at Beaver Valley in January 2013.


•	Andes — a decrease of $104 million at our generation businesses primarily due to higher working capital requirements at Gener.

•

Brazil — an increase of $138 million at our utility businesses primarily driven by the recovery of deferred costs from the regulator, lower transmission costs and regulatory charges partially offset by higher priced energy purchases and lower collections at Eletropaulo, as well as a decrease of $87 million at our generation businesses primarily due to higher purchases on spot market and income taxes payments, offset by higher energy sales.


•	MCAC — an increase of $97 million at our generation businesses primarily due to lower working capital requirements.


•	Asia — a decrease of $44 million at our generation businesses primarily due to higher working capital requirements at Masinloc.

Investing Activities — Net cash used in investing activities was $706 million during the six months ended June 30, 2013. This was primarily attributable to capital expenditures of $866 million consisting of $454 million of growth capital expenditures and $412 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Eletropaulo of $138 million, Gener of $81 million, Jordan of $54 million, Sul of $44 million, Sixpenny Wood of $22 million, Mong Duong of $19 million and Yelvertoft of $19 million. Maintenance and environmental capital expenditures included amounts at IPL of $87 million, Eletropaulo of $72 million, Gener of $47 million, DPL of $46 million, Sul of $39 million and Tietê of $30 million. This use of cash was partially offset by proceeds from the sale of business, net of cash sold of $135 million including $113 million for the sale of the Ukraine businesses and $24 million for the sale of our remaining interest in Cartagena.

Net cash used in investing activities was $352 million during the six months ended June 30, 2012. This was primarily attributable to capital expenditures of $1.1 billion consisting of $587 million of growth capital expenditures and $484 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Gener of $131 million, Eletropaulo of $114 million, Mong Duong of $70 million, Sul of $55 million, DPL of $44 million, Maritza of $23 million, Mountain View 4 of $18 million and Drone Hill of $17 million. Maintenance and environmental capital expenditures included amounts at Eletropaulo of $90 million, DPL of $66 million, IPL of $59 million, Sul of $47 million, Panama of $44 million, Gener of $41 million and Tietê of $20 million. These uses of cash were partially offset by sales of short-term investments, net of purchases of $344 million which included amounts at Gener of $121 million, Brasiliana of $106 million, Eletropaulo of $73 million and Tietê of $56 million offset by purchases of $14 million at Andres. Proceeds from the sale of businesses, net of cash sold of $332 million included amounts at Red Oak of $142 million, Ironwood of $84 million, Cartagena of $63 million and the sale of St. Patrick and Innovent of $42 million. Proceeds from government grants for asset construction of $117 million were mainly due to funds received at our wind projects, including $82 million at Laurel Mountain and $30 million at Mountain View 4.

Net cash used in investing activities increased $354 million to $706 million during the six months ended June 30, 2013 compared to net cash used in investing activities of $352 million during the six months ended June 30, 2012. This net increase

was primarily due to an increase in purchases of short-term investments, net of sales of $414 million and a decrease in proceeds from the sale of businesses, net of cash sold of $197 million, partially offset by a decrease in capital expenditures of $205 million.

Financing Activities — Net cash used in financing activities was $799 million during the six months ended June 30, 2013. Repayments of recourse and non-recourse debt of $3.4 billion included amounts at the Parent Company of $1.2 billion, Masinloc of $546 million, DPL of $425 million, Tietê of $396 million, El Salvador of $301 million, IPL of $110 million, Warrior Run of $87 million, Puerto Rico of $52 million, Sul of $37 million and Maritza of $29 million. Financed capital expenditures were $257 million primarily at Mong Duong for payments to the contractors which took place more than three months after the associated equipment was purchased or work performed. Distributions to noncontrolling interests of $211 million included amounts at Tietê of $98 million, Brasiliana of $34 million, Buffalo Gap of $25 million and Gener of $18 million. Payments for financing fees of $127 million included amounts at Cochrane of $41 million, Eletropaulo of $25 million and Mong Duong of $13 million. This was partially offset by issuances of recourse and non-recourse debt of $3.1 billion including amounts at the Parent Company for $750 million, Masinloc of $500 million, Tietê of $496 million, El Salvador of $310 million, Mong Duong of $210 million, DPL of $200 million, IPL of $170 million, Sul of $150 million, Cochrane of $82 million, Warrior Run of $74 million, Kribi of $63 million and Jordan of $61 million.

Net cash used in financing activities was $862 million during the six months ended June 30, 2012. Distributions to noncontrolling interests of $578 million included amounts at Eletropaulo of $203 million, Brasiliana of $189 million, Tietê of $132 million and Gener of $28 million. Repayments of recourse and non-recourse debt of $333 million included amounts at Gener of $29 million, Eletropaulo of $27 million, Southland of $25 million, Maritza of $25 million, Sonel of $24 million, Puerto Rico of $23 million, Bulgaria Wind of $22 million, Masinloc of $20 million, Kribi of $19 million, Warrior Run of $17 million and Kilroot of $14 million. Net repayments under the revolving credit facilities of $310 million included $295 million at the Parent Company and $33 million at Alicura. The purchase of treasury stock at the Parent Company was $231 million. This was partially offset by issuance of non-recourse debt of $579 million including amounts at Eletropaulo of $339 million, Mong Duong of $71 million, Kribi of $41 million, Alicura of $35 million, Panama of $25 million and Drone Hill of $17 million.

Net cash used in financing activities decreased $63 million to $799 million during the six months ended June 30, 2013 compared to net cash used in financing activities of $862 million during the six months ended June 30, 2012. This net decrease was primarily due to increases in repayments of recourse and non-recourse debt of $3 billion, financed capital expenditures of $245 million and payments for financings fees of $110 million, partially offset by an increase in the issuance of recourse and non-recourse debt of $2.6 billion as well as decreases in distributions to noncontrolling interests of $367 million, net repayments under revolving credit facilities of $343 million and purchase of treasury stock of $213 million.

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:


•	interest;


•	principal repayments of debt;


•	acquisitions;


•	construction commitments;


•	other equity commitments;


•	equity repurchases;


•	taxes;


•	Parent Company overhead and development costs; and


•	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, 2013 and December 31, 2012 as follows:



Parent Company Liquidity	June 30, 2013			December 31, 2012
	(in millions)
Consolidated cash and cash equivalents	$	1,611		$	1,966
Less: Cash and cash equivalents at subsidiaries	1,500			1,655
Parent and qualified holding companies’ cash and cash equivalents	111			311
Commitments under Parent credit facilities	800			800
Less: Letters of credit under the credit facilities	(3		)	(5		)
Borrowings available under Parent credit facilities	797			795
Total Parent Company Liquidity	$	908		$	1,106

The Company paid a dividend of $0.04 per share to its common stockholders during the three months ended June 30, 2013. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance we will be able to continue the payment of dividends.

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 Considerations in this Item 2), 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 2012 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:


•	limitations on other indebtedness, liens, investments and guarantees;


•	limitations on dividends, stock repurchases and other equity transactions;


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


•	maintenance of certain financial ratios; and


•	financial and other reporting requirements.

As of June 30, 2013, 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:


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


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


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


•	triggering defaults in our outstanding debt at the Parent 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 $2.9 billion. The portion of current debt related to such defaults was $1.7 billion at June 30, 2013, all of which was non-recourse debt related to five subsidiaries — Changuinola, Maritza, Sonel, Kavarna 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, 2013 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 revenue 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 our 2012 Form 10-K. The Company’s critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2012 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that those policies remain the Company’s critical accounting policies as of and for the six months ended June 30, 2013.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks

Our generation and utility businesses are exposed to and proactively manage market risk. 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 varying degrees 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 effects may differ. 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 2012 Form 10-K.

Commodity Price Risk

Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term sales or under contract sales that leave an un-hedged exposure on some of capacity, or through imperfect pass throughs. In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations, and sharing or pass through mechanisms. 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 contract sales 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 changes in variable margin performance as global commodity prices shift. For the balance of 2013, we project pretax earnings exposure on a 10% move in commodity prices would be approximately $5 million for coal, $5 million for oil and $5 million for 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, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some of our businesses.

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 the US SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. 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; DPL sells generation in excess of its retail demand under short-term sales; and the outcome of the DPL regulatory filing may affect our level of commodity price exposure over time. 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.

For the Andes SBU, our business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. In the central region, the contract sales cover the efficient generation from our coal-fired and hydroelectric assets. Any residual spot price risk will primarily be driven by the amount of hydrological inflows. In the case of low hydroelectric generation, spot price exposure is capped by the ability to dispatch our natural gas/diesel assets. There is a small amount of coal generation in the northern region that is not covered by the portfolio of contract sales and therefore subject to spot price risk. In both regions, generators with oil or oil-linked fuel generally set power prices. In Colombia we operate under a short-term sales strategy and have commodity exposure to un-hedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel.

The businesses in the MCAC SBU have commodity exposure on un-hedged volumes. Panama is largely contracted under a portfolio of fixed volume contract sales. To the extent hydrological inflows are greater than or less than the contract sales volume, the business will be sensitive to changes in spot power prices which may be driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices.

For the Brazil SBU, the hydroelectric generating facility is covered by contract sales. Under normal hydrological volatility, spot price risk is mitigated through a regulated sharing mechanism across all hydroelectric generators in the country. Under more extreme hydrological conditions, the sharing mechanism may not be sufficient to cover the business' contract position, and therefore it may have to purchase power at spot prices linked to the cost of thermal generation. Spot prices in Brazil are generally not directly linked to global commodity prices.

In the EMEA SBU, our Kilroot facility operates on a short-term sales strategy. The commodity risk at our Kilroot business is due to the dark spread, the difference between electricity price and our coal based variable dispatch cost, 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 contract, 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.

In the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume sold in the spot market. 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, Dominican Peso, Euro, Indian Rupee, Kazakhstani 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. The largest foreign exchange risks are stemming from the following currencies: Argentine Peso, Brazilian Real, and Euro, determined based on historic volatility over the preceding twelve-month period. As of June 30, 2013, assuming a 10% U.S. Dollar appreciation, adjusted pretax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine Peso, Brazilian Real, 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 be reduced by approximately $5 million, $5 million, and $5 million, respectively, for the balance of 2013. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pretax earnings for the balance of 2013 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 are

unwound. Additionally, updates to the forecasted pretax 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. Most of our interest rate risk is related to non-recourse financings at our businesses.

As of June 30, 2013, the portfolio’s pretax earnings exposure for the balance of 2013 to a 100 basis point increase in interest rates for our Argentine Peso, Brazilian Real, British Pound, Chilean Peso, Columbian Peso, Euro, Indian Rupee, Kazakhstani Tenge, and U.S. Dollar denominated debt would be approximately $10 million based on the impact of a one-time, 100 basis point upward shift in interest rates on interest expense for the debt denominated in these currencies. 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 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, 2013 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Controls over Financial Reporting

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

PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is involved in certain claims, suits and legal proceedings in the normal course of business. 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, 2013.

In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro (“FDC”) 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 FDC found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$1.38 billion ($617 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 FDC 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 FDC for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the FDC. Eletropaulo’s subsequent appeals were dismissed. In February 2010, the FDC 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. 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 directed the FDC to proceed accordingly. However, in December 2012, the FDC disregarded the AC’s decision that the parties were entitled to full discovery and an expert appraisal of the issues prior to the resolution of the case and, instead, issued a decision finding Eletropaulo liable for the debt. The AC subsequently granted Eletropaulo’s request to suspend the execution suit in the FDC and thereafter annulled the FDC’s decision. The case has returned to the FDC for proceedings in accordance with the AC’s April 2010 decision. If the FDC again finds Eletropaulo liable for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the FDC 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 FDC against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 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 ($581 thousand) as of December 31, 2012, 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 2010, a 2-to-1 majority of the arbitral tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified 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 (“FCSP”) 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 (“SCJ”) challenging the transfer. In November 2012, the SCJ ruled that the lawsuit must be returned to the FCSP. 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. 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. 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. As required by the injunction, CEEE has started the removal and disposal of the contaminants, which is ongoing, and Sul is not at risk to bear any of such remediation costs, which are estimated to be approximately R$60 million ($27 million). In November 2012, the inspections performed by the court expert and supervised by Sul confirmed that CEEE is fulfilling the injunction by removing the contaminants. The case is in the evidentiary stage awaiting the production of the court’s expert opinion on several matters, including which of the parties had utilized the products found in the area.

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 remains 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 contributed to alleged global warming which, in turn, allegedly led to the erosion of the plaintiffs’ alleged land. The plaintiffs asserted 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 sought 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 appealed to the U.S. Court of Appeals for the Ninth Circuit. In September 2012, the Ninth Circuit affirmed the District Court’s decision. The plaintiffs’ subsequent petition for en banc review was denied by the Ninth Circuit. The plaintiffs thereafter filed a petition requesting review by the Supreme Court, which was denied in June 2013.

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. The hearing on liability issues took place in December 2011. In May 2013, the arbitral Tribunal issued a liability award in AESU's favor. YPF thereafter challenged the award in Argentine court. Given the challenge, the arbitral Tribunal is considering whether to suspend the next phase of the arbitration on damages issues. 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 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) from UK HPP and KZT 1.3 billion ($8 million) from 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 requested a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputed the claims. Although it did not assert counterclaims, in its closing brief CFE asserted that it is entitled to a partial refund of the capacity charge payments that it made for power generated with the out-of-specification gas. In July 2012, the arbitral Tribunal issued an award in AES Mérida’s favor. In December 2012, CFE initiated an action in Mexican court seeking to nullify the award. AES Mérida has opposed the request and asserted a counterclaim to confirm the award. AES Mérida believes it has meritorious defenses in that action; however, there can be no assurances that it will be successful.

In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the Clean Air Act (“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 and the Company is not able to estimate damages, if any, at this time. 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. In November 2011, the AES defendants again moved for partial dismissal of those amended complaints, and in both lawsuits, the Superior Court dismissed the plaintiffs' claims for future medical monitoring expenses but declined to dismiss their claims under Dominican Republic Law 64-00. 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. 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 ($312 million) in the arbitration, unspecified damages for alleged injury to reputation, and other relief. The arbitral hearing on the merits is scheduled for November 27-December 6, 2013 and January 6-17, 2014. 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 ($447 thousand) 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. AES Eletropaulo has had several meetings and field inspections to settle the details of the recovery project. AES Eletropaulo was informed by the Park Administrator that the area where the recovery project was to be located was no longer available. AES Eletropaulo has requested approval for a new area from the Park Administrator and will then present a new recovery project.

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. The Company is unable to estimate the alleged damages at this time. 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 2012, the federal court granted the motion and dismissed the lawsuit. The plaintiffs appealed to the U.S. Court of Appeals for the Fifth Circuit. In May 2013, the Fifth Circuit affirmed the dismissal. 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 February 2011, a consumer protection group, S.O.S. Consumidores (“SOSC”), filed a lawsuit in the State of Săo Paulo Federal Court against Eletropaulo and all other distribution companies in the State of Săo Paulo, claiming that the distribution companies had overcharged customers for electricity. SOSC asserts that the distribution companies’ tariffs had been incorrectly calculated by the Brazilian Regulatory Agency (“ANEEL”). ANEEL corrected the alleged error in May 2010. There are separate proceedings against ANEEL to determine whether the tariffs had been properly calculated. SOSC has moved for an injunction requiring tariffs to be corrected from the effective dates of the relevant concession contracts. Eletropaulo has opposed that request on the ground that it did not wrongfully collect amounts from its customers, since its tariff was calculated in accordance with the concession contract with the Federal Government and ANEEL’s rules. At ANEEL’s request, the Superior Court of Justice has suspended the lawsuit and similar cases against third parties and determined that all such cases shall be transferred to the Federal Court of Belo Horizonte. If Eletropaulo does not prevail in the lawsuit, Eletropaulo estimates that its liability to customers could be approximately R$855 million ($382 million). Eletropaulo 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 ($537 million) in services tax (“ISS”) that allegedly had not been collected on revenues for services rendered by Eletropaulo. Eletropaulo estimates that, with interest, the amount at issue has increased to approximately R$2.1 billion ($939 million). 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 August 2012, Fondo Patrimonial de las Empresas Reformadas (“FONPER”) (the Dominican instrumentality that holds the Dominican Republic’s shares in Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”)) filed a criminal complaint against certain current and former employees of AES. The criminal proceedings include a related civil component initiated against Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NCI”) (the AES affiliate that manages Itabo). FONPER asserts claims relating to the alleged mismanagement of Itabo and seeks approximately $270 million in damages. The Dominican District Attorney (“DA”) has admitted the criminal complaint and is investigating the allegations set forth therein. In September 2012, one of the individual defendants responded to the criminal complaint, denying the charges and seeking an immediate dismissal of same. In April 2013, the DA requested that the Dominican Camara de Cuentas perform an audit of the allegations in the criminal complaint. Further, in August 2012, Coastal and NCI initiated an international arbitration proceeding against FONPER and the Dominican Republic, seeking a declaration that Coastal and NCI have acted both lawfully and in accordance with the relevant contracts with FONPER and the Dominican Republic in relation to the management of Itabo. Coastal and NCI also seek a declaration that the criminal complaint is a breach of the relevant contracts between the parties, including the obligation to arbitrate disputes. Coastal and NCI further seek damages from FONPER and the Dominican Republic resulting from their breach of contract. FONPER and the Dominican Republic have denied the claims. The AES defendants believe they have meritorious claims and defenses, which they will assert vigorously; however, there can be no assurance that they will be successful in their efforts.

In March 2013, an arbitral Tribunal issued a “Partial Final Award” and thereafter a “Revised Partial Final Award” (the “Award”), ordering a wind subsidiary of the Company to pay a net amount of approximately $17 million to its EPC Contractor. The Contractor and certain of its subcontractors thereafter asserted additional claims seeking interest, fees, and costs totaling approximately $13 million, as well as relief relating to certain liens. Also, there were judicial proceedings concerning the Award and a guaranty issued to the Contractor by another wind subsidiary of the Company. The parties settled their disputes in July 2013.

In April 2013, the East Kazakhstan Ecology Department (“ED”) issued an order directing AES Ust-Kamenogorsk CHP ("UK CHP") to pay approximately 720 million KZT ($4.7 million) in damages (“ED's April 2013 Order”) . The ED claimed that UK CHP was illegally operating without an emissions permit for 27 days in February - March 2013, which UK CHP contests. In June 2013, the ED filed a lawsuit with the Specialized Interregional Economic Court (the “Economic Court”) seeking to require UK CHP to pay the assessed damages. UK CHP thereafter filed a separate lawsuit with the Economic Court challenging the ED's April 2013 Order and ED's allegations. On August 1, 2013, the Economic Court ruled in favor of UK CHP in the lawsuit filed by UK CHP and required the ED to vacate the ED's April 2013 Order. The lawsuit filed in the Economic Court by the ED is still pending. UK CHP believes it has meritorious claims and defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurance that it will be successful in its efforts.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2012 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 Purchase Plan ⁽¹⁾	Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan
4/1/2013 - 4/30/13	—	—		—	$	300,000,000
5/1/2013 - 5/31/13	—	—		—	300,000,000
6/1/2013 - 6/30/13	1,558,900	11.50		1,558,900	282,055,544
Total	1,558,900	$	11.50	1,558,900

_____________________________


⁽¹⁾	See Note 10 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS



10.1		Amendment No. 3, dated as of July 26, 2013, to the Fifth Amended and Restated Credit and Reimbursement agreement dated as of July 29, 2010 is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on July 29, 2013.

10.1.A		Sixth Amended and Restated Credit and Reimbursement Agreement dated as of July 26, 2013 among The AES Corporation, a Delaware corporation, the Banks listed on the signature pages thereof, Citibank, N.A., as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc., as Lead Arranger and Book Runner, Banc of America Securities LLC, as Lead Arranger and Book Runner and Co-Syndication Agent, Barclays Capital, as Lead Arranger and Book Runner and Co-Syndication Agent, RBS Securities Inc., as Lead Arranger and Book Runner and Co-Syndication Agent and Union Bank, N.A., as Lead Arranger and Book Runner and Co-Syndication Agent is incorporated herein by reference to Exhibit 10.1.A of the Company's Form 8-K filed on July 29, 2013.

10.1.B		Appendices and Exhibits to the Sixth Amended and Restated Credit and Reimbursement Agreement, dated as of July 26, 2013 is incorporated herein by reference to Exhibit 10.1.B of the Company's Form 8-K filed on July 29, 2013.

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 Thomas M. O’Flynn (filed herewith).

32.1		Section 1350 Certification of Andrés Gluski (filed herewith).

32.2		Section 1350 Certification of Thomas M. O’Flynn (filed herewith).

101.INS		XBRL Instance Document (filed herewith).

101.SCH		XBRL Taxonomy Extension Schema Document (filed herewith).

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith).

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document (filed herewith).

101.LAB		XBRL Taxonomy Extension Label Linkbase Document (filed herewith).

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith).

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 7, 2013	By:	/s/ THOMAS M. O’FLYNN
			Name:	Thomas M. O’Flynn
			Title:	Executive Vice President and Chief Financial Officer (Principal Financial Officer)

		By:	/s/ SHARON A. VIRAG
			Name:	Sharon A. Virag
			Title:	Vice President and Controller (Principal Accounting Officer)