AES CORP - Quarter Report: 2013 September (Form 10-Q)

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

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 September 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 November 1, 2013 was 742,327,115

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 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	30

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	64

ITEM 4.	CONTROLS AND PROCEDURES	66

PART II: OTHER INFORMATION		67

ITEM 1.	LEGAL PROCEEDINGS	67

ITEM 1A.	RISK FACTORS	73

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	73

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	73

ITEM 4.	MINE SAFETY DISCLOSURES	73

ITEM 5.	OTHER INFORMATION	73

ITEM 6.	EXHIBITS	74

SIGNATURES		75

PART I: FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

THE AES CORPORATION

Condensed Consolidated Balance Sheets

(Unaudited)



	September 30, 2013			December 31, 2012
	(in millions, except share and per share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,031		$	1,909
Restricted cash	620			738
Short-term investments	898			693
Accounts receivable, net of allowance for doubtful accounts of $140 and $195, respectively	2,326			2,542
Inventory	711			722
Deferred income taxes	172			199
Prepaid expenses	199			223
Other current assets	836			1,074
Current assets of discontinued operations and held-for-sale assets	458			365
Total current assets	8,251			8,465
NONCURRENT ASSETS
Property, Plant and Equipment:
Land	952			1,005
Electric generation, distribution assets and other	30,835			30,451
Accumulated depreciation	(9,531		)	(9,195		)
Construction in progress	2,826			2,511
Property, plant and equipment, net	25,082			24,772
Other Assets:
Investments in and advances to affiliates	1,025			1,196
Debt service reserves and other deposits	485			511
Goodwill	1,941			1,999
Other intangible assets, net of accumulated amortization of $151 and $222, respectively	325			395
Deferred income taxes	821			940
Other noncurrent assets	2,169			2,190
Noncurrent assets of discontinued operations and held-for-sale assets	1,151			1,362
Total other assets	7,917			8,593
TOTAL ASSETS	$	41,250		$	41,830
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,156		$	2,547
Accrued interest	396			288
Accrued and other liabilities	2,116			2,350
Non-recourse debt, including $267 and $275, respectively, related to variable interest entities	2,385			2,495
Recourse debt	118			11
Current liabilities of discontinued operations and held-for-sale businesses	838			628
Total current liabilities	8,009			8,319
NONCURRENT LIABILITIES
Non-recourse debt, including $939 and $858, respectively, related to variable interest entities	12,981			12,286
Recourse debt	5,552			5,951
Deferred income taxes	1,116			1,192
Pension and other post-retirement liabilities	2,138			2,418
Other noncurrent liabilities	3,042			3,562
Noncurrent liabilities of discontinued operations and held-for-sale businesses	368			510
Total noncurrent liabilities	25,197			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; 813,077,875 issued and 742,245,268 outstanding at September 30, 2013 and 810,679,839 issued and 744,263,855 outstanding at December 31, 2012)	8			8
Additional paid-in capital	8,497			8,525
Retained earnings (accumulated deficit)	56			(264		)
Accumulated other comprehensive loss	(2,918		)	(2,920		)
Treasury stock, at cost (70,832,607 shares at September 30, 2013 and 66,415,984 shares at December 31, 2012)	(830		)	(780		)
Total AES Corporation stockholders’ equity	4,813			4,569
NONCONTROLLING INTERESTS	3,153			2,945
Total equity	7,966			7,514
TOTAL LIABILITIES AND EQUITY	$	41,250		$	41,830

See Notes to Condensed Consolidated Financial Statements.

THE AES CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions, except per share amounts)
Revenue:
Regulated	$	2,063		$	2,318		$	6,175		$	6,685
Non-Regulated	1,940			2,037			5,933			6,122
Total revenue	4,003			4,355			12,108			12,807
Cost of Sales:
Regulated	(1,663		)	(1,927		)	(5,082		)	(5,642		)
Non-Regulated	(1,403		)	(1,461		)	(4,423		)	(4,445		)
Total cost of sales	(3,066		)	(3,388		)	(9,505		)	(10,087		)
Gross margin	937			967			2,603			2,720
General and administrative expenses	(63		)	(64		)	(183		)	(225		)
Interest expense	(357		)	(396		)	(1,065		)	(1,182		)
Interest income	85			88			213			261
Loss on extinguishment of debt	—			—			(212		)	—
Other expense	(15		)	(15		)	(58		)	(56		)
Other income	25			7			106			39
Gain on sale of investments	3			30			26			214
Goodwill impairment expense	(58		)	(1,850		)	(58		)	(1,850		)
Asset impairment expense	(81		)	(43		)	(129		)	(71		)
Foreign currency transaction gains (losses)	32			(7		)	(16		)	(108		)
Other non-operating expense	(122		)	—			(122		)	(50		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES	386			(1,283		)	1,105			(308		)
Income tax expense	(126		)	(172		)	(285		)	(514		)
Net equity in earnings of affiliates	15			25			21			49
INCOME (LOSS) FROM CONTINUING OPERATIONS	275			(1,430		)	841			(773		)
Income from operations of discontinued businesses, net of income tax (benefit) expense of $(2), $2, $2, and $8, respectively	26			30			25			25
Net gain (loss) from disposal and impairments of discontinued businesses, net of income tax (benefit) expense of $0, $(1), $(2), and $60, respectively	(78		)	(2		)	(111		)	68
NET INCOME (LOSS)	223			(1,402		)	755			(680		)
Noncontrolling interests:
Less: Income from continuing operations attributable to noncontrolling interests	(146		)	(155		)	(431		)	(398		)
Less: Income from discontinued operations attributable to noncontrolling interests	(6		)	(11		)	(4		)	(9		)
Total net income attributable to noncontrolling interests	(152		)	(166		)	(435		)	(407		)
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	$	71		$	(1,568	)	$	320		$	(1,087	)
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income (loss) from continuing operations, net of tax	$	129		$	(1,585	)	$	410		$	(1,171	)
Income (loss) from discontinued operations, net of tax	(58		)	17			(90		)	84
Net income (loss)	$	71		$	(1,568	)	$	320		$	(1,087	)
BASIC EARNINGS PER SHARE:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.17		$	(2.12	)	$	0.55		$	(1.54	)
Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax	(0.08		)	0.02			(0.12		)	0.11
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.09		$	(2.10	)	$	0.43		$	(1.43	)
DILUTED EARNINGS PER SHARE:
Income (loss) from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.17		$	(2.12	)	$	0.55		$	(1.54	)
Income (loss) from discontinued operations attributable to The AES Corporation common stockholders, net of tax	(0.08		)	0.02			(0.12		)	0.11
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.09		$	(2.10	)	$	0.43		$	(1.43	)
DIVIDENDS DECLARED PER COMMON SHARE	$	—		$	0.04		$	0.08		$	0.04

See Notes to Condensed Consolidated Financial Statements.

THE AES CORPORATION

Condensed Consolidated Statements of Comprehensive Income

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
NET INCOME (LOSS)	$	223		$	(1,402	)	$	755		$	(680	)
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax (expense) benefit of $0, $0, $0 and $0, respectively	—			—			(1		)	1
Reclassification to earnings, net of income tax (expense) benefit of $0, $0, $0 and $0, respectively	—			—			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 $1, $(2), $3 and $(1), respectively	(6		)	14			(264		)	(227		)
Reclassification to earnings, net of income tax (expense) benefit of $0, $0, $0 and $0, respectively	—			(39		)	41			(42		)
Total foreign currency translation adjustments	(6		)	(25		)	(223		)	(269		)
Derivative activity:
Change in derivative fair value, net of income tax (expense) benefit of $(0), $7, $(28) and $27, respectively	7			(55		)	93			(167		)
Reclassification to earnings, net of income tax (expense) benefit of $(8), $(5), $(30) and $(38), respectively	27			27			112			153
Total change in fair value of derivatives	34			(28		)	205			(14		)
Pension activity:
Reclassification to earnings due to amortization of net actuarial loss, net of income tax (expense) benefit of $(6), $(4), $(20) and $(10), respectively	12			6			39			19
Total pension adjustments	12			6			39			19
OTHER COMPREHENSIVE INCOME (LOSS)	40			(47		)	21			(264		)
COMPREHENSIVE INCOME (LOSS)	263			(1,449		)	776			(944		)
Less: Comprehensive (income) attributable to noncontrolling interests	(171		)	(159		)	(454		)	(290		)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	$	92		$	(1,608	)	$	322		$	(1,234	)

See Notes to Condensed Consolidated Financial Statements.

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)



	Nine Months Ended September 30,
	2013			2012
	(in millions)
OPERATING ACTIVITIES:
Net income (loss)	$	755		$	(680	)
Adjustments to net income (loss):
Depreciation and amortization	982			1,038
Gain from sale of investments and impairment expense	313			1,802
Deferred income taxes	(82		)	101
Provisions for contingencies	33			51
Loss on the extinguishment of debt	212			—
Loss (gain) on disposals and impairments - discontinued operations	108			(130		)
Other	(26		)	10
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable	135			(191		)
(Increase) decrease in inventory	(6		)	(10		)
(Increase) decrease in prepaid expenses and other current assets	403			90
(Increase) decrease in other assets	(149		)	(379		)
Increase (decrease) in accounts payable and other current liabilities	(578		)	303
Increase (decrease) in income tax payables, net and other tax payables	(66		)	(151		)
Increase (decrease) in other liabilities	6			275
Net cash provided by operating activities	2,040			2,129
INVESTING ACTIVITIES:
Capital expenditures	(1,330		)	(1,581		)
Acquisitions - net of cash acquired	(3		)	(18		)
Proceeds from the sale of businesses, net of cash sold	167			432
Proceeds from the sale of assets	52			4
Sale of short-term investments	3,375			5,116
Purchase of short-term investments	(3,638		)	(4,764		)
Decrease in restricted cash, debt service reserves and other assets	75			35
Proceeds from government grants for asset construction	1			120
Other investing	34			(20		)
Net cash used in investing activities	(1,267		)	(676		)
FINANCING ACTIVITIES:
Repayments under the revolving credit facilities, net	(22		)	(322		)
Issuance of recourse debt	750			—
Issuance of non-recourse debt	3,082			822
Repayments of recourse debt	(1,208		)	(8		)
Repayments of non-recourse debt	(2,288		)	(759		)
Payments for financing fees	(148		)	(24		)
Distributions to noncontrolling interests	(385		)	(741		)
Contributions from noncontrolling interests	157			12
Dividends paid on AES common stock	(89		)	—
Payments for financed capital expenditures	(436		)	(30		)
Purchase of treasury stock	(63		)	(301		)
Other financing	15			8
Net cash used in financing activities	(635		)	(1,343		)
Effect of exchange rate changes on cash	(37		)	9
Decrease in cash of discontinued and held-for-sale businesses	21			140
Total increase in cash and cash equivalents	122			259
Cash and cash equivalents, beginning	1,909			1,632
Cash and cash equivalents, ending	$	2,031		$	1,891
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	923		$	1,024
Cash payments for income taxes, net of refunds	$	506		$	580

See Notes to Condensed Consolidated Financial Statements.

THE AES CORPORATION

Notes to Condensed Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 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 16 — 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 nine months ended September 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. Any impact of adopting ASU No. 2013-5 on the Company’s financial position and results of operations will depend on the nature and extent of future sales or dispositions of any entities that had created a cumulative translation adjustment.

2. INVENTORY

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



	September 30, 2013		December 31, 2012
	(in millions)
Coal, fuel oil and other raw materials	$	345	$	371
Spare parts and supplies	366		351
Total	$	711	$	722

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 September 30, 2013 and December 31, 2012:



	September 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	$	—	$	665	$	—	$	665	$	—	$	448	$	—	$	448
Certificates of deposit	—		148		—		148		—		143		—		143
Government debt securities	—		26		—		26		—		34		—		34
Subtotal	—		839		—		839		—		625		—		625
Equity securities:
Mutual funds	—		46		—		46		—		56		—		56
Subtotal	—		46		—		46		—		56		—		56
Total available-for-sale	—		885		—		885		—		681		—		681
TRADING:
Equity securities:
Mutual funds	13		—		—		13		12		—		—		12
Total trading	13		—		—		13		12		—		—		12
DERIVATIVES:
Interest rate derivatives	—		44		—		44		—		2		—		2
Cross currency derivatives	—		6		—		6		—		6		—		6
Foreign currency derivatives	—		17		97		114		—		2		79		81
Commodity derivatives	—		26		8		34		—		8		3		11
Total derivatives	—		93		105		198		—		18		82		100
TOTAL ASSETS	$	13	$	978	$	105	$	1,096	$	12	$	699	$	82	$	793
Liabilities
DERIVATIVES:
Interest rate derivatives	$	—	$	249	$	103	$	352	$	—	$	153	$	412	$	565
Cross currency derivatives	—		3		—		3		—		6		—		6
Foreign currency derivatives	—		15		6		21		—		7		7		14
Commodity derivatives	—		16		4		20		—		13		4		17
Total derivatives	—		283		113		396		—		179		423		602
TOTAL LIABILITIES	$	—	$	283	$	113	$	396	$	—	$	179	$	423	$	602

_____________________________


⁽¹⁾	Amortized cost approximated fair value at September 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 nine months ended September 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 September 30, 2013
	Interest Rate			Foreign Currency			Commodity			Total
	(in millions)
Balance at July 1	$	(63	)	$	70		$	9		$	16
Total gains (losses) (realized and unrealized):
Included in earnings	(1		)	28			(1		)	26
Included in other comprehensive income - derivative activity	7			—			—			7
Included in other comprehensive income - foreign currency translation activity	(1		)	(6		)	—			(7		)
Included in regulatory (assets) liabilities	—			—			(4		)	(4		)
Settlements	9			(1		)	—			8
Transfers of assets (liabilities) into Level 3	(84		)	—			—			(84		)
Transfers of (assets) liabilities out of Level 3	30			—			—			30
Balance at September 30	$	(103	)	$	91		$	4		$	(8	)
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	$	—		$	27		$	(1	)	$	26



	Three Months Ended September 30, 2012
	Interest Rate			Foreign Currency			Commodity			Total
	(in millions)
Balance at July 1	$	(281	)	$	47		$	13		$	(221	)
Total gains (losses) (realized and unrealized):
Included in earnings	(1		)	16			2			17
Included in other comprehensive income - derivative activity	(29		)	—			—			(29		)
Included in other comprehensive income - foreign currency translation activity	—			(2		)	—			(2		)
Included in regulatory (assets) liabilities	—			—			2			2
Settlements	12			(1		)	(5		)	6
Transfers of (assets) liabilities out of Level 3	2			—			—			2
Balance at September 30	$	(297	)	$	60		$	12		$	(225	)
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	)	$	15		$	2		$	16



	Nine Months Ended September 30, 2013
	Interest Rate			Foreign Currency			Commodity			Total
	(in millions)
Balance at January 1	$	(412	)	$	72		$	(1	)	$	(341	)
Total gains (losses) (realized and unrealized):
Included in earnings	(2		)	40			—			38
Included in other comprehensive income - derivative activity	84			—			—			84
Included in other comprehensive income - foreign currency translation activity	(3		)	(12		)	—			(15		)
Included in regulatory (assets) liabilities	—			—			5			5
Settlements	73			(3		)	—			70
Transfers of assets (liabilities) into Level 3	—			—			—			—
Transfers of (assets) liabilities out of Level 3	157			(6		)	—			151
Balance at September 30	$	(103	)	$	91		$	4		$	(8	)
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	$	—		$	40		$	—		$	40



	Nine Months Ended September 30, 2012
	Interest Rate			Cross Currency			Foreign Currency			Commodity			Total
	(in millions)
Balance at January 1	$	(128	)	$	(18	)	$	51		$	2		$	(93	)
Total gains (losses) (realized and unrealized):
Included in earnings	(1		)	—			16			8			23
Included in other comprehensive income - derivative activity	(30		)	8			—			—			(22		)
Included in other comprehensive income - foreign currency translation activity	—			—			(4		)	—			(4		)
Included in regulatory (assets) liabilities	—			—			—			9			9
Settlements	19			11			(3		)	(7		)	20
Transfers of assets (liabilities) into Level 3	(159		)	—			—			—			(159		)
Transfers of (assets) liabilities out of Level 3	2			(1		)	—			—			1
Balance at September 30	$	(297	)	$	—		$	60		$	12		$	(225	)
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	)	$	—		$	14		$	9		$	22

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



Type of Derivative	Fair Value			Unobservable Input	Amount or Range (Weighted Average)
	(in millions)
Interest rate	$	(103	)	Subsidiaries’ credit spreads	5.21	%
Foreign currency:
Embedded derivative — Argentine Peso	97			Argentine Peso to U.S. Dollar currency exchange rate after 3 years	22.14 - 39.05 (31.72)
Embedded derivative — Euro	(5		)	Subsidiaries’ credit spreads	5.21	%
Other	(1		)
Commodity:
Other	4
Total	$	(8	)

Nonrecurring Measurements

When evaluating impairment of goodwill, 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 at the evaluation date to their then-latest available 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:



	Nine Months Ended September 30, 2013
	Carrying Amount		Fair Value						Gross Loss
			Level 1		Level 2		Level 3
	(in millions)
Assets
Long-lived assets held and used:⁽¹⁾
Poland Wind projects	$	79	$	—	$	—	$	14	$	65
Itabo (San Lorenzo)	22		—		—		7		15
Beaver Valley	61		—		—		15		46
Long-lived assets held for sale:⁽¹⁾
Wind turbines	25		—		25		—		—
Discontinued operations and held-for-sale businesses:⁽²⁾
Cameroon businesses	262		—		199		—		65
Saurashtra	19		—		7		—		12
Ukraine utilities	143		—		113		—		34
Equity method investments⁽³⁾
Elsta	240		—		—		118		122
Goodwill
Ebute	58		—		—		—		58



	Nine Months Ended September 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
Wind Projects	16		—		—		—		16
Long-lived assets held for sale:⁽¹⁾
Wind turbines	45		—		—		25		20
St. Patrick	33		—		22		—		11
Equity method investments	205		—		155		—		50
Goodwill
DP&L	2,449		—		—		599		1,850

_____________________________


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


⁽²⁾	See Note 16 — 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.


⁽³⁾	See Note 15 — Other Non-Operating Expense for further information.

The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets during the nine months ended September 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	%
Poland Wind	14		Market approach	Indicative offer prices	14
Itabo (San Lorenzo)	7		Market approach	Broker quote	7
Equity method investment:
Elsta	118		Discounted cash flow	Annual revenue growth	-55% to 17% (1%)
				Annual pretax operating margin	3% to 45% (36%)
				Weighted-average cost of capital	7	%
Total	$	154

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 September 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)
September 30, 2013
Assets
Accounts receivable — noncurrent⁽¹⁾	$	297	$	164	$	—	$	—	$	164
Liabilities
Non-recourse debt	15,366		15,533		—		13,312		2,221
Recourse debt	5,670		6,108		—		6,108		—
December 31, 2012
Assets
Accounts receivable — noncurrent⁽¹⁾	$	304	$	188	$	—	$	—	$	188
Liabilities
Non-recourse debt	14,781		15,506		—		13,266		2,240
Recourse debt	5,962		6,628		—		6,628		—

_____________________________

⁽¹⁾

These accounts receivable principally relate to amounts due from CAMMESA, the administrator of the wholesale electricity market 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 $47 million and $55 million at September 30, 2013 and December 31, 2012, respectively.

4. INVESTMENTS IN MARKETABLE SECURITIES

The Company’s investments in marketable debt and equity securities as of September 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 September 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 nine months ended September 30, 2013 and 2012. Gains and losses on the sale of investments are determined using the specific-identification method. For the three and nine months ended September 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 September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
	(in millions)
Gains included in earnings that relate to trading securities held at the reporting date	$	1	$	—		$	1	$	—
Unrealized gains on available-for-sale securities included in other comprehensive income	—		(1		)	1		(1		)
Gains reclassified out of other comprehensive income into earnings	—		—			1		—
Gross proceeds from sales of available-for-sale securities	1,071		1,513			3,394		5,160
Gross realized gains on sales	—		—			—		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 September 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)	3,581	$	3,581	4,826	$	4,826	9	72	%
EURIBOR (Euro)	590	798		590	798		8	86	%
LIBOR (British Pound)	68	110		68	110		12	83	%
Cross Currency Swaps:
Chilean Unidad de Fomento	6	256		6	256		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 September 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.



	September 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	5	$	237	1
Chilean Peso	89,969	178		<1
Brazilian Real	200	90		<1
Euro	40	54		<1
Colombian Peso	215,480	113		<1
Argentine Peso	43	7		<1
British Pound	66	106		<1
Embedded Foreign Currency Derivatives:
Argentine Peso	892	154		10
Kazakhstani Tenge	816	5		4

_____________________________


⁽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 2025, respectively.



	September 30, 2013
		Weighted-Average
Commodity Derivatives	Notional	Remaining Term⁽¹⁾
	(in millions)	(in years)
Power (MWh)	9	3

_____________________________


⁽¹⁾	Represents the remaining tenor of our commodity derivatives weighted by the corresponding volume. These derivatives range in maturity through 2016.

Accounting and Reporting

Assets and Liabilities

The following tables set forth the Company’s derivative instruments as of September 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.



	September 30, 2013						December 31, 2012
	Designated		Not Designated		Total		Designated		Not Designated		Total
	(in millions)
Assets
Interest rate derivatives	$	42	$	2	$	44	$	—	$	2	$	2
Cross currency derivatives	6		—		6		6		—		6
Foreign currency derivatives	6		108		114		—		81		81
Commodity derivatives	8		26		34		2		9		11
Total assets	$	62	$	136	$	198	$	8	$	92	$	100
Liabilities
Interest rate derivatives	$	338	$	14	$	352	$	544	$	21	$	565
Cross currency derivatives	3		—		3		6		—		6
Foreign currency derivatives	13		8		21		7		7		14
Commodity derivatives	10		10		20		8		9		17
Total liabilities	$	364	$	32	$	396	$	565	$	37	$	602



	September 30, 2013						December 31, 2012
	Assets			Liabilities			Assets			Liabilities
	(in millions)
Current	$	36		$	136		$	14		$	178
Noncurrent	162			260			86			424
Total	$	198		$	396		$	100		$	602
Derivatives subject to master netting agreement or similar agreement:
Gross (which equals net) amounts recognized in the balance sheet	$	79		$	368		$	25		$	522
Gross amounts of derivative instruments not offset	(11		)	(11		)	(9		)	(9		)
Gross amounts of cash collateral received/pledged not offset	—			(4		)	—			(5		)
Net amount	$	68		$	353		$	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	$	173		$	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 nine months ended September 30, 2013 and 2012:



	Gains (Losses) Recognized in AOCL							Gains (Losses) Reclassified from AOCL into Earnings
	Three Months Ended September 30,						Classification in Condensed Consolidated Statements of Operations	Three Months Ended September 30,
Type of Derivative	2013			2012				2013			2012
	(in millions)							(in millions)
Interest rate derivatives	$	10		$	(62	)	Interest expense	$	(32	)	$	(40	)
							Non-regulated cost of sales	(1		)	(1		)
							Net equity in earnings of affiliates	(1		)	(2		)
							Asset impairment expense	—			(5		)
Cross currency derivatives	2			4			Interest expense	(4		)	(3		)
							Foreign currency transaction gains (losses)	4			15
Foreign currency derivatives	(1		)	—			Foreign currency transaction gains (losses)	3			4
Commodity derivatives	(4		)	(4		)	Non-regulated revenue	(3		)	—
							Non-regulated cost of sales	(1		)	—
Total	$	7		$	(62	)		$	(35	)	$	(32	)



	Gains (Losses) Recognized in AOCL							Gains (Losses) Reclassified from AOCL into Earnings
	Nine Months Ended September 30,						Classification in Condensed Consolidated Statements of Operations	Nine Months Ended September 30,
Type of Derivative	2013			2012				2013			2012
	(in millions)							(in millions)
Interest rate derivatives	$	131		$	(204	)	Interest expense	$	(95	)	$	(102	)
							Non-regulated cost of sales	(3		)	(4		)
							Net equity in earnings of affiliates	(5		)	(4		)
							Gain on sale of investments	(21		)	(96		)
							Asset impairment expense	—			(5		)
Cross currency derivatives	(9		)	9			Interest expense	(10		)	(9		)
							Foreign currency transaction gains (losses)	(10		)	27
Foreign currency derivatives	1			12			Foreign currency transaction gains (losses)	7			4
Commodity derivatives	(2		)	(11		)	Non-regulated revenue	(4		)	(2		)
							Non-regulated cost of sales	(1		)	—
Total	$	121		$	(194	)		$	(142	)	$	(191	)

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 September 30, 2013 is $(111) million for interest rate hedges, $10 million for cross currency swaps, $2 million for foreign currency hedges, and $(5) million for commodity and other hedges.

For the three and nine months ended September 30, 2012, pre-tax losses of $11 million, net of noncontrolling interests were reclassified into earnings as a result of the discontinuance of a cash flow hedge because it was probable that the forecasted transaction would not occur by the end of the originally specified time period (as documented at the inception of the hedging relationship) or within an additional two-month time period thereafter. There was no such item for the three and nine months ended September 30, 2013.

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 nine months ended September 30, 2013 and 2012:



		Gains (Losses) Recognized in Earnings
	Classification in Condensed Consolidated Statements of Operations	Three Months Ended September 30,						Nine Months Ended September 30,
Type of Derivative		2013			2012			2013		2012
		(in millions)
Interest rate derivatives	Interest expense	$	(1	)	$	(2	)	$	29	$	(1	)
	Net equity in earnings of affiliates	$	—		$	—		$	—	$	(1	)
Cross currency derivatives	Interest expense	—			(1		)	—		(1		)
Total		$	(1	)	$	(3	)	$	29	$	(3	)

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 nine months ended September 30, 2013 and 2012:



		Gains (Losses) Recognized in Earnings
	Classification in Condensed Consolidated Statements of Operations	Three Months Ended September 30,						Nine Months Ended September 30,
Type of Derivative		2013			2012			2013			2012
		(in millions)
Interest rate derivatives	Interest expense	$	(1	)	$	(2	)	$	1		$	(5	)
	Net equity in earnings of affiliates	—			—			(6		)	—
Foreign currency derivatives	Foreign currency transaction gains (losses)	24			(11		)	47			(87		)
	Net equity in earnings of affiliates	(7		)	—			(22		)	—
Commodity and other derivatives	Non-regulated revenue	4			(1		)	8			13
	Regulated revenue	—			(3		)	—			(2		)
	Non-regulated cost of sales	(2		)	1			(1		)	4
	Regulated cost of sales	1			(3		)	12			(20		)
	Income (loss) from operations of discontinued businesses	2			15			(10		)	2
Total		$	21		$	(4	)	$	29		$	(95	)

Credit Risk-Related Contingent Features

DP&L, a utility within our United States strategic business unit, 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 DP&L's 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 $10 million and $13 million as of September 30, 2013 and December 31, 2012, respectively, for all derivatives with credit risk-related contingent features. As of September 30, 2013 and December 31, 2012, DP&L had posted $4 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 $1 million and $2 million as of September 30, 2013 and December 31, 2012, respectively.

6. FINANCING RECEIVABLES

Financing receivables are defined as receivables that have contractual maturities of greater than one year. The Company has financing receivables pursuant to amended agreements or government resolutions that are due from certain Latin American governmental bodies, primarily in Argentina. The following table sets forth the breakdown of financing receivables by country as of September 30, 2013 and December 31, 2012:



	September 30, 2013		December 31, 2012
	(in millions)
Argentina⁽¹⁾	$	182	$	196
Dominican Republic	12		35
Brazil	23		8
Total long-term financing receivables	$	217	$	239

_____________________________

⁽¹⁾

Excludes noncurrent receivables of $127 million and $120 million, respectively, as of September 30, 2013 and December 31, 2012, which have not been converted into financing receivables and do not have contractual maturities of greater than one year. Also, excludes the foreign currency-related embedded derivative assets associated with the financing receivables which had a fair value of $97 million and $69 million, respectively, as of September 30, 2013 and December 31, 2012.

Argentina - As a result of energy market reforms in 2004 and consistent with contractual arrangements, AES Argentina entered into three agreements with the Argentine government called (as translated into English) the Fund for the Investment Needed to Increase the Supply of Electricity in the Wholesale Market (“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 receivables accrue interest and are collected in monthly installments over 10 years once the related plant begins operations. In addition, AES Argentina receives an ownership interest in these newly built plants once the receivables have been fully repaid. Collection of the principal and interest on these receivables is subject to various business risks and uncertainties including, but not limited to, the 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 monitors these risks including the credit ratings of the Argentine government on a quarterly basis to assess the collectability of these receivables. The Company accrues interest on these receivables once the recognition criteria have been met. 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 receivables under the first two FONINVEMEM Agreements are being actively collected since the related plants commenced operations in 2010. In assessing the collectability of the receivables under these agreements, the Company also considers how the collections have historically been made timely in accordance with the agreements. The receivables related to the third FONINVEMEM Agreement are not currently due as commercial operation of the two related gas-fired plants has not been achieved. In assessing the collectability of the receivables under this agreement, the Company also considers the extent to which significant milestones necessary to complete the plants have been achieved or are still probable.

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. On May 31, 2013, Resolution 95 became 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, Resolution 95 determines the portion of future outstanding receivables that shall be contributed into the new trusts to be set up by the Argentine government.

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.

On July 26, 2013, the Company entered into an amendment No. 3 to the senior secured credit facility dated as of July 29, 2010 that amended the terms and conditions of the senior secured credit facility, including the following changes:


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


•	the interest rate margin applicable to the senior secured credit facility is based on the credit rating assigned to the loans under the senior secured credit facility, with pricing currently at LIBOR + 2.25%;


•	there is an undrawn fee of 0.50% per annum; and


•	the subsidiary guarantors party to the senior secured credit facility are released from their obligations under the old senior secured credit facility and have no obligations under the amended senior secured credit facility.

The aggregate commitment for the senior secured credit facility remains $800 million.

Non-Recourse Debt

Significant transactions

During the nine months ended September 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 $40 million;


•	Mong Duong drew $339 million under its construction loan facility;


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


•	DP&L issued $445 million of first mortgage bonds to partially repay $470 million of existing bonds which were repaid at par on October 1, 2013;


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


•	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;


•	Jordan drew $138 million under its construction loan facility; and


•	Cochrane drew $120 million under its construction loan facility.

Debt in default

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



	Primary Nature of Default	September 30, 2013
Subsidiary	Primary Nature of Default	Default Amount		Net Assets
		(in millions)
Maritza	Covenant	$	836	$	684
Kavarna	Covenant	202		84
		$	1,038

_____________________________

In addition to the defaults listed in the table above, Sonel and Kribi in Cameroon and Saurashtra in India have been classified as discontinued operations. As of September 30, 2013, Sonel and Kribi had debt in default of $255 million and $256 million; and net assets of $398 million and $46 million, respectively. Although currently not in default, debt of $21 million at Saurashtra has been classified as current because a covenant violation is probable within the next twelve months. Net assets at Saurashtra as of September 30, 2013 were $2 million. For further information please see Note 16 — Discontinued Operations and Held-for-Sale Businesses.

The above defaults are not payment defaults, but are instead 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 borrower.

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 September 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, the Parent Company 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, the Parent Company 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 September 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	$	654	21	<$1 - 275
Cash collateralized letters of credit	192		11	<$1 - 132
Letters of credit under the senior secured credit facility	3		4	<$1 - 2
Total	$	849	36

During the three months ended September 30, 2013, the Company paid letter of credit fees ranging from 0.2% to 2.5% 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 September 30, 2013, the Company had recorded liabilities of $8 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 September 30, 2013. In aggregate, the Company estimates that the range of potential losses related to environmental matters, where estimable, to be from $8 million up to $46 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 $260 million and $320 million as of September 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 September 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 $889 million and $1.4 billion. The amounts considered reasonably possible do not include amounts reserved, as discussed above. These material contingencies do not include income tax-related contingencies which are considered part of our uncertain tax positions.

9. PENSION PLANS

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



	Three Months Ended September 30,												Nine Months Ended September 30,
	2013						2012						2013						2012
	U.S.			Foreign			U.S.			Foreign			U.S.			Foreign			U.S.			Foreign
	(in millions)
Service cost	$	4		$	6		$	4		$	4		$	12		$	20		$	11		$	13
Interest cost	11			122			11			123			33			394			35			390
Expected return on plan assets	(15		)	(114		)	(13		)	(107		)	(46		)	(371		)	(41		)	(340		)
Amortization of prior service cost	1			—			1			—			4			—			4			—
Amortization of net loss	7			18			6			9			21			59			18			30
Total pension cost	$	8		$	32		$	9		$	29		$	24		$	102		$	27		$	93

Total employer contributions for the nine months ended September 30, 2013 for the Company’s U.S. and foreign subsidiaries were $52 million and $109 million, respectively. The expected remaining scheduled employer contributions for 2013 are zero and $55 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 September 30, 2013 and 2012:



	Nine Months Ended September 30, 2013									Nine Months Ended September 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 (loss)	320			435			755			(1,087		)	407			(680		)
Total foreign currency translation adjustment, net of income tax	(158		)	(65		)	(223		)	(158		)	(111		)	(269		)
Total change in derivative fair value, net of income tax	151			54			205			6			(20		)	(14		)
Total pension adjustments, net of income tax	9			30			39			5			14			19
Capital contributions from noncontrolling interests	—			86			86			—			12			12
Distributions to noncontrolling interests	—			(382		)	(382		)	—			(625		)	(625		)
Disposition of businesses	—			(20		)	(20		)	—			(37		)	(37		)
Acquisition of treasury stock	(63		)	—			(63		)	(301		)	—			(301		)
Issuance and exercise of stock-based compensation benefit plans, net of income tax	39			—			39			40			—			40
Dividends declared on common stock ($0.08 per share)	(60		)	—			(60		)	(30		)	—			(30		)
Sale of subsidiary shares to noncontrolling interests	12			71			83			—			—			—
Acquisition of subsidiary shares from noncontrolling interests	(6		)	(1		)	(7		)	3			(11		)	(8		)
Balance at September 30	$	4,813		$	3,153		$	7,966		$	4,424		$	3,412		$	7,836

Equity Transactions with Noncontrolling Interests

During the nine months ended September 30, 2013, the Company completed transactions which increased noncontrolling interests in Alto Maipo and Cochrane, two projects under development in Chile. Although there was a decrease in the Company's ownership, the Company did not lose control of either project, which continue to be accounted for as consolidated subsidiaries. The difference between the fair value of the consideration received for these transactions and the corresponding adjustment to noncontrolling interest of $12 million was recognized as an equity transaction through Additional Paid-in Capital.

The following table summarizes the net income (loss) attributable to The AES Corporation and all transfers (to) from noncontrolling interests for the nine months ended September 30, 2013 and 2012.



	September 30,			September 30,
	2013			2012
	(in millions)
Net income (loss) attributable to The AES Corporation	$	320		$	(1,087	)
Transfers (to) from the noncontrolling interest:
Net increase in The AES Corporation's paid-in capital for sale of subsidiary shares	12			—
Increase (decrease) in The AES Corporation's paid-in capital for purchase of subsidiary shares	(6		)	3
Net transfers (to) from noncontrolling interest	6			3
Change from net income attributable to The AES Corporation and transfers (to) from noncontrolling interests	$	326		$	(1,084	)

Accumulated Other Comprehensive Loss

The changes in accumulated other comprehensive loss by component, net of tax and noncontrolling interests for the nine months ended September 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	54			—			(1		)	(194		)	(141		)
Amounts reclassified from accumulated other comprehensive loss	97			9			1			36			143
Net current-period other comprehensive income	151			9			—			(158		)	2
Balance at September 30	$	(330	)	$	(373	)	$	—		$	(2,215	)	$	(2,918	)

Reclassifications out of accumulated other comprehensive loss for the three and nine months ended September 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 September 30, 2013			Nine Months Ended September 30, 2013
		(in millions)
Unrealized derivative losses, net
	Non-regulated revenue	$	(3	)	$	(4	)
	Non-regulated cost of sales	(2		)	(4		)
	Interest expense	(36		)	(105		)
	Gain on sale of investments	—			(21		)
	Foreign currency transaction gains (losses)	7			(3		)
	Income from continuing operations before taxes and equity in earnings of affiliates	(34		)	(137		)
	Income tax expense	8			30
	Net equity in earnings of affiliates	(1		)	(5		)
	Income from continuing operations	(27		)	(112		)
	Income from continuing operations attributable to noncontrolling interests	2			15
	Net income attributable to the AES Corporation	$	(25	)	$	(97	)
Amortization of defined benefit pension actuarial loss, net
	Regulated cost of sales	(17		)	(56		)
	Non-regulated cost of sales	(1		)	(3		)
	Income from continuing operations before taxes and equity in earnings of affiliates	(18		)	(59		)
	Income tax expense	6			20
	Income from continuing operations	(12		)	(39		)
	Income from continuing operations attributable to noncontrolling interests	9			30
	Net income attributable to The AES Corporation	$	(3	)	$	(9	)
Available-for-sale securities, net
	Interest income	$	—		$	(1	)
	Net income attributable to The AES Corporation	$	—		$	(1	)
Foreign currency translation adjustment, net
	Gain on sale of investments	$	—		$	(1	)
	Net loss from disposal and impairments of discontinued businesses	—			(35		)
	Net income attributable to The AES Corporation	$	—		$	(36	)
Total reclassifications for the period, net of income tax and noncontrolling interests		$	(28	)	$	(143	)

_____________________________


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

Stock Repurchase Program

During the three months ended September 30, 2013, shares of common stock repurchased under the existing stock repurchase program (the "Program") totaled 3,738,142 at a total cost of $45 million. The cumulative purchases under the Program totaled 64,012,231 shares at a total cost of $743 million, which includes a nominal amount of commissions (average price per share of $11.60, including commissions). As of September 30, 2013, $237 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 70,832,607 and 66,415,984 shares were held as treasury stock at September 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 in July 2010.

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”). The Company applied the accounting guidance for segment reporting which provides certain qualitative and quantitative thresholds and aggregation criteria. In 2013, 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. Silver Ridge Power (formerly AES Solar Holding Company) 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. For the three and nine months ended September 30, 2013, the Company changed the definition of Adjusted PTC to exclude the gains or losses attributable to AES common stockholders at our equity method investments for these same types of items. Previously, these amounts were not excluded from the calculation of Adjusted PTC. Accordingly, the Company has also reflected the change in the comparative three and nine month periods ended September 30, 2012. 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 September 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 nine months ended September 30, 2013 and 2012 was as follows:



Revenue Three Months Ended September 30,	Total Revenue				Intersegment						External Revenue
Revenue Three Months Ended September 30,	2013		2012		2013			2012			2013		2012
	(in millions)
US — Generation	$	207	$	222	$	—		$	—		$	207	$	222
US — Utilities	763		796		—			—			763		796
Andes — Gener — Generation	539		568		—			(8		)	539		560
Andes — Other — Generation	89		207		—			(1		)	89		206
Brazil — Generation	272		268		(222		)	(260		)	50		8
Brazil — Utilities	1,224		1,448		—			—			1,224		1,448
MCAC — Generation	469		437		—			(1		)	469		436
EMEA — Generation	333		268		—			—			333		268
Asia — Generation	113		191		—			—			113		191
Corporate and Other	217		222		(1		)	(2		)	216		220
Total Revenue	$	4,226	$	4,627	$	(223	)	$	(272	)	$	4,003	$	4,355



Revenue Nine Months Ended September 30,	Total Revenue				Intersegment						External Revenue
Revenue Nine Months Ended September 30,	2013		2012		2013			2012			2013		2012
	(in millions)
US — Generation	$	567	$	636	$	—		$	—		$	567	$	636
US — Utilities	2,159		2,206		—			—			2,159		2,206
Andes — Gener — Generation	1,738		1,711		—			(26		)	1,738		1,685
Andes — Other — Generation	306		568		(1		)	(1		)	305		567
Brazil — Generation	937		847		(752		)	(790		)	185		57
Brazil — Utilities	3,749		4,209		—			—			3,749		4,209
MCAC — Generation	1,398		1,256		(1		)	(2		)	1,397		1,254
EMEA — Generation	970		998		—			(1		)	970		997
Asia — Generation	388		553		—			—			388		553
Corporate and Other	655		646		(5		)	(3		)	650		643
Total Revenue	$	12,867	$	13,630	$	(759	)	$	(823	)	$	12,108	$	12,807



Adjusted Pre-Tax Contribution⁽¹⁾ Three Months Ended September 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	$	44		$	40		$	3		$	11		$	47		$	51
US — Utilities	87			108			—			—			87			108
Andes — Gener — Generation	59			88			3			(4		)	62			84
Andes — Other — Generation	50			20			3			1			53			21
Brazil — Generation	37			45			(53		)	(63		)	(16		)	(18		)
Brazil — Utilities	48			40			36			42			84			82
MCAC — Generation	90			87			5			2			95			89
EMEA — Generation	68			53			3			5			71			58
Asia — Generation	30			53			1			—			31			53
Corporate and Other	(126		)	(154		)	(1		)	6			(127		)	(148		)
Total Adjusted Pre-Tax Contribution	387			380			—			—			387			380



Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates:
Non-GAAP Adjustments:
Unrealized derivative gains (losses)	7			(22		)
Unrealized foreign currency gains (losses)	22			22
Disposition/acquisition gains	4			25
Impairment losses	(236		)	(1,893		)
Pre-tax contribution	184			(1,488		)
Add: income from continuing operations before taxes, attributable to noncontrolling interests	217			230
Less: Net equity in earnings of affiliates	15			25
Income (loss) from continuing operations before taxes and equity in earnings of affiliates	$	386		$	(1,283	)



Adjusted Pre-Tax Contribution⁽¹⁾ Nine Months Ended September 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	$	150		$	118		$	7		$	31		$	157		$	149
US — Utilities	181			197			1			1			182			198
Andes — Gener — Generation	190			207			8			(14		)	198			193
Andes — Other — Generation	84			61			5			2			89			63
Brazil — Generation	143			142			(181		)	(190		)	(38		)	(48		)
Brazil — Utilities	61			105			122			128			183			233
MCAC — Generation	227			246			11			6			238			252
EMEA — Generation	236			288			6			(3		)	242			285
Asia — Generation	101			141			2			1			103			142
Corporate and Other	(427		)	(503		)	19			38			(408		)	(465		)
Total Adjusted Pre-Tax Contribution	946			1,002			—			—			946			1,002



Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates:
Non-GAAP Adjustments:
Unrealized derivative gains (losses)	46			(88		)
Unrealized foreign currency gains (losses)	(25		)	8
Disposition/acquisition gains	30			206
Impairment losses	(284		)	(1,973		)
Loss on extinguishment of debt	(207		)	—
Pre-tax contribution	506			(845		)
Add: income from continuing operations before taxes, attributable to noncontrolling interests	620			586
Less: Net equity in earnings of affiliates	21			49
Income (loss) from continuing operations before taxes and equity in earnings of affiliates	$	1,105		$	(308	)

_____________________________


⁽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 September 30, 2013 and December 31, 2012 were as follows:



	Total Assets
	September 30, 2013		December 31, 2012
	(in millions)
Assets
US — Generation	$	3,151	$	3,259
US — Utilities	7,924		7,534
Andes — Gener — Generation	5,969		5,820
Andes — Other — Generation	761		799
Brazil — Generation	1,494		1,590
Brazil — Utilities	7,300		8,120
MCAC — Generation	4,434		4,293
EMEA — Generation	4,125		4,178
Asia — Generation	2,717		2,583
Discontinued businesses	1,609		1,727
Corporate and Other & eliminations	1,766		1,927
Total Assets	$	41,250	$	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 September 30,				Nine Months Ended September 30,
	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Contract termination	$	—	$	—	$	60	$	—
Reversal of legal contingency	10		—		10		—
Gain on sale of assets	2		2		9		5
Insurance proceeds	—		—		—		10
Other	13		5		27		24
Total other income	$	25	$	7	$	106	$	39

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 September 30,				Nine Months Ended September 30,
	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Loss on sale and disposal of assets	$	12	$	13	$	36	$	48
Contract termination	—		—		7		—
Other	3		2		15		8
Total other expense	$	15	$	15	$	58	$	56

13. GOODWILL IMPAIRMENT

Ebute—During the third quarter of 2013, the Company performed an interim goodwill impairment test at the Ebute reporting unit, a 294 MW gas-fired plant in Nigeria. Ebute currently operates on leased land located within the PHCN Egbin Power Station Compound (“Egbin”) in Ijede, Ikorodu, Lagos. A controlling stake in Egbin was sold to a private investor as part of the Nigerian government privatization program in 2007, but the sale transaction did not close until the third quarter of 2013. The Company has been evaluating Ebute's future options for the continuation of the plant operation after the end of the current PPA on an ongoing basis. The viability of a number of such options is subject to the Company's ability to secure amongst other things long-term land rights, permits, gas transportation and supply agreements, and a new or extended PPA. In this evaluation, the Company has been continually assessing the probability of success of each of these options. Based on communications to and from the Nigerian government and other power sector stakeholders it interacts with to secure the required key project components and agreements, in September 2013, management determined that the prospects for Ebute's future expansion have significantly reduced. These adverse developments were considered as impairment indicators for Ebute's goodwill and long-lived assets. The long-lived assets were deemed recoverable based on the undiscounted cash flow recoverability analysis. In Step 1, the fair value of Ebute was determined using the income approach based on a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were the ability to obtain an extension to the existing land lease, permits, gas transportation and supply agreements, future PPA terms, maintenance and growth capital expenditures, and discount rates. Ebute failed Step 1 as the carrying amount of the reporting unit exceeded its fair value. Consequently, a preliminary Step 2 was performed to measure the goodwill impairment expense. In the preliminary Step 2, the fair value of the reporting unit was allocated to its identifiable assets and liabilities in accordance with the relevant accounting guidance and Ebute's goodwill did not have any value. Therefore, the entire goodwill balance of $58 million was recognized as goodwill impairment expense. At this time, management is continuing its review of the preliminary Step 2 calculations including the valuation report from an independent valuation firm. If necessary, management will record an adjustment in the fourth quarter of 2013 to finalize this estimate. Ebute is reported in EMEA Generation segment.

DPL—In connection with its acquisition of DPL in 2011, the Company recognized goodwill of approximately $2.6 billion which was allocated between the two reporting units identified during the purchase price allocation: The Dayton Power and Light Company (“DP&L”, DPL’s regulated utility in Ohio) and DPL Energy Resources, Inc. (“DPLER”, DPL’s wholly-owned competitive retail electric service provider). Of the total goodwill, approximately $2.4 billion was allocated to DP&L and the remainder was allocated to DPLER.

On October 5, 2012, DP&L filed an Electric Security Plan (“ESP”) for approval with the Public Utility Commission of Ohio (“PUCO”). Within the ESP filing, DP&L agreed to request a separation of its generation assets from its transmission and distribution assets in recognition that a restructuring of DP&L operations will be necessary, in compliance with Ohio law. Also, during 2012, North American natural gas prices fell significantly from the previous year exerting downward pressure on

wholesale electricity prices in the Ohio power market. Falling power prices compressed wholesale margins at DP&L. Furthermore, these lower power prices led to increased switching from DP&L to other competitive retail electric service (“CRES”) providers, including DPLER, who were offering retail prices lower than DP&L’s current standard service offer. Also, several municipalities in DP&L’s service territory passed ordinances allowing them to become government aggregators and some municipalities contracted with CRES providers to provide generation service to the customers located within the municipal boundaries, further contributing to the switching trend. CRES providers also became more active in DP&L’s service territory. In September 2012, management revised its cash flow forecasts based on these developments and forecasted lower profitability and operating cash flows than previously prepared forecasts. These developments reduced DP&L’s forecasted profitability, operating cash flows and liquidity. Collectively, in the third quarter of 2012, these events were considered an interim impairment indicator for DPL’s goodwill at the DP&L reporting unit. There were no interim impairment indicators identified for the goodwill at DPLER.

The Company performed an interim impairment test on the $2.4 billion of goodwill at the DP&L reporting unit level during the third quarter of 2012. In the preliminary Step 1 of the goodwill impairment test, the fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The material assumptions included within the discounted cash flow valuation model were customer switching and aggregation trends, capacity price curves, energy price curves, amount of the nonbypassable charge, commodity price curves, dispatching, transition period for the conversion to a wholesale competitive bidding structure, amount of the standard service offer charge, valuation of regulatory assets and liabilities, discount rates and deferred income taxes. The reporting unit failed the preliminary Step 1 test and a preliminary Step 2 of the goodwill impairment test was performed. For the three months ended September 30, 2012, the Company recognized a goodwill impairment expense of $1.85 billion, which represented its best estimate of the impairment loss based on the latest information then available and the results of the preliminary Step 1 and Step 2 tests. DPL is reported in the US Utilities segment.

The goodwill associated with the DPL acquisition is not deductible for tax purposes. Accordingly, there was no cash tax or financial statement tax benefit related to the impairment. The Company’s effective tax rates were impacted by the pretax impairment, however. The Company’s effective tax rates were (13)% and (167)% for the three months and nine months ended September 30, 2012. In both of these periods, the Company had worldwide tax expense on a loss from continuing operations.

14. ASSET IMPAIRMENT EXPENSE



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Poland wind projects	$	65	$	—	$	65	$	—
Beaver Valley	—		—		46		—
Itabo (San Lorenzo)	15		—		15		—
Wind turbines and projects	—		36		—		40
Kelanitissa	—		5		—		17
St. Patrick	—		—		—		11
Other	1		2		3		3
Total asset impairment expense	$	81	$	43	$	129	$	71

Poland Wind Projects —During the third quarter of 2013, the Company determined that it was more likely than not that it would dispose of its remaining Poland wind development projects through sale or abandonment which was deemed to be an impairment indicator. The Company had acquired ownership interests ranging between 61% to 89% in the entities holding these wind development projects since 2010. This decision was driven by the continued uncertainty in the tariff regime for renewable energy in Poland. The Company performed long-lived asset impairment tests considering different scenarios and determined that, based on undiscounted cash flows, the carrying amounts of the projects were not recoverable. The fair values of the projects were determined using the market approach based on an indicative offer price for all of the projects and their aggregate carrying amount of $79 million exceeded their aggregate fair value of $14 million. As a result, an asset impairment expense of $65 million was recognized. Poland Wind is reported in the EMEA Generation Segment.

Itabo (San Lorenzo)—During the third quarter of 2013, the Company tested the recoverability of long-lived assets at San Lorenzo, a 35 Megawatt ("MW") LNG fueled plant of Itabo. Itabo was informed by Super-Intendencia de Electridad (“SIE”), the system regulator in the Dominican Republic, that it would not receive capacity revenue going forward. This communication in combination with current adverse market conditions were determined to be an impairment indicator. The Company performed a long-lived asset impairment test considering different scenarios and determined that, based on undiscounted cash flows, the carrying amount of San Lorenzo was not recoverable. The fair value of San Lorenzo was determined using the market approach based on

a broker quote and it was determined that its carrying amount of $22 million exceeded the estimated fair value of $7 million. As a result, the Company recognized an asset impairment expense of $15 million. Itabo is reported in the MCAC Generation segment.

Beaver Valley — In January 2013, Beaver Valley, a wholly-owned 125 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.

Wind Turbines and Projects— During the third quarter of 2012, the Company determined that all turbines held in storage met the held-for-sale criteria due to less viable internal deployment scenarios and the ongoing receipt of offers from potential buyers. Accordingly, the Company measured the turbines at fair value less cost to sell under the market approach. The turbines with a carrying amount of $45 million were written down to their fair value less cost to sell of $25 million, which resulted in an impairment expense of $20 million. In addition, the Company determined that two early-stage wind development projects that were capitalizing certain project costs were no longer probable because of the Company’s shift in capital allocation for developing these projects. The Company assessed the value of the projects using the market approach and, after consultation with third party valuation firms and internal development staff, the fair value was determined to be zero. A full impairment of $16 million was recognized in the third quarter of 2012. These wind turbines and projects were reported in US Generation segment.

Kelanitissa—During the nine months ended September 30, 2012, the Company recognized asset impairment expense of $17 million for the long-lived assets at Kelanitissa, a diesel-fired generation plant in Sri Lanka. The Company continued to evaluate the recoverability of its long-lived assets at Kelanitissa as a result of both the requirement to transfer the plant to the government at the end of PPA and the expectation of lower future operating cash flows. The evaluations during this period indicated that the long-lived assets were no longer recoverable and, accordingly, were written down to their estimated fair value of $10 million based on a discounted cash flow analysis. The long-lived assets had a carrying amount of $22 million prior to the recognition of asset impairment expense. Kelanitissa is reported in the Asia Generation reportable segment.

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

15. OTHER NON-OPERATING EXPENSE



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Elsta	$	122	$	—	$	122	$	—
China generation	—		—		—		32
InnoVent	—		—		—		17
Other	—		—		—		1
Total other non-operating expense	$	122	$	—	$	122	$	50

Elsta—Elsta BV & Co CV ("Elsta"), a 630 MW combined cycle gas-fired plant in the Netherlands, is accounted for under the equity method of accounting. The Company evaluates its equity method investments for impairment whenever certain indicators are present suggesting that the fair value of an equity method investment is less than its carrying value and the evaluation would consider whether the decline is other-than-temporary. This analysis requires a significant amount of judgment to identify events or circumstances indicating than an equity method investment may be impaired. Once an impairment indicator is identified, the Company must determine if an impairment exists, and if so, whether the impairment is other-than-temporary in which case the equity method investment is written down to its estimated fair value. During the quarter ended September 30, 2013, the Company identified an impairment indicator resulting from initial negotiations with Elsta's offtakers for an extension of the existing power purchase agreement ("PPA") which expires during 2018, suggesting that the income earned under the existing PPA would likely be reduced upon an extension and that the resulting decline in the estimated

fair value of the Company's equity method investment in Elsta was other-than-temporary. The Company recognized an impairment of $122 million by reducing the carrying value of $240 million to the estimated fair value of $118 million. The Company estimated fair value using probability-weighted outcomes which contemplated various scenarios involving the amendments to the existing PPA.

China Generation and InnoVent—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.

16. 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 Utility businesses in Ukraine sold in April 2013 and our Utility and Generation businesses in Cameroon and our wind generation business in India which met the held-for-sale criteria in September 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 nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
Revenue	$	124		$	232		$	539		$	759
Income from operations of discontinued businesses, before income tax	$	24		$	32		$	27		$	33
Income tax benefit (expense)	2			(2		)	(2		)	(8		)
Income from operations of discontinued businesses, after income tax	$	26		$	30		$	25		$	25
Net gain (loss) from disposal and impairments of discontinued businesses, after income tax	$	(78	)	$	(2	)	$	(111	)	$	68

Cameroon—In September 2013, a subsidiary of the Company executed sale agreements for the sale of AES White Cliffs B.V. (owner of 56% of AES SONEL S.A), AES Kribi Holdings B.V. (owner of 56% of Kribi Power Development Company S.A.) and AES Dibamba Holdings B.V., (owner of 56% of Dibamba Power Development Company S.A.). The transaction is subject to the Cameroon government approval and certain conditions precedent, which should be fulfilled or waived before March 31, 2014. The transaction is expected to close in the fourth quarter of 2013 or the first quarter of 2014. Upon meeting the held-for-sale criteria, the Company recognized impairments of $65 million representing the difference between their aggregate carrying amount of $262 million and fair value less costs to sell of $197 million. These businesses were previously reported in EMEA Generation segment and "Corporate and Other".

Saurashtra—In September 2013, the Company's management approved the sale of AES Saurashtra Private Ltd, a 39 MW wind project in India. The transaction is subject to lenders' approval and customary conditions precedent and is expected to close in the fourth quarter of 2013 or the first quarter of 2014. Upon meeting the held-for-sale criteria, the Company recognized an impairment of $12 million representing the difference between its carrying amount of $19 million and fair value less costs to sell of $7 million. Saurashtra was previously reported in the Asia Generation segment.

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”.

17. 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.

18. EARNINGS PER SHARE

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

The following tables present a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation for income from continuing operations for the three and nine months ended September 30, 2013 and 2012. In the table below, income represents the numerator and weighted-average shares represent the denominator:



	Three Months Ended September 30,
	2013					2012
	Income		Shares	$ per Share		Loss			Shares	$ per Share
	(in millions except per share data)
BASIC EARNINGS PER SHARE
Income (loss) from continuing operations attributable to The AES Corporation common stockholders	$	129	742	$	0.17	$	(1,585	)	747	$	(2.12	)
EFFECT OF DILUTIVE SECURITIES
Stock options	—		1	—		—			—	—
Restricted stock units	—		4	—		—			—	—
DILUTED EARNINGS PER SHARE	$	129	747	$	0.17	$	(1,585	)	747	$	(2.12	)



	Nine Months Ended September 30,
	2013					2012
	Income		Shares	$ per Share		Loss			Shares	$ per Share
	(in millions except per share data)
BASIC EARNINGS PER SHARE
Income (loss) from continuing operations attributable to The AES Corporation common stockholders	$	410	745	$	0.55	$	(1,171	)	759	$	(1.54	)
EFFECT OF DILUTIVE SECURITIES
Restricted stock units	—		4	—		—			—	—
DILUTED EARNINGS PER SHARE	$	410	749	$	0.55	$	(1,171	)	759	$	(1.54	)

The calculation of diluted earnings per share excluded 6.1 million and 6.4 million options outstanding at September 30, 2013 and 2012, respectively, 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 2.0 million options outstanding at September 30, 2012 that could potentially dilute earnings per share in the future. These options were not included in the computation of diluted earnings per share for three and nine months ended September 30, 2012 because the potential shares would be anti-dilutive given the loss from continuing operations. Had the Company generated income from continuing operations in the three and nine months ended September 30, 2012, 1.0 million and 1.1 million, respectively, of potential common shares of common stock related to the options would have been included in diluted average shares outstanding.

The calculation of diluted earnings per share also excluded 1.4 million and 1.2 million restricted stock units outstanding at September 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. The calculation of diluted earnings per share also excluded 5.3 million restricted stock units outstanding at September 30, 2012 that could potentially dilute earnings per share in the future. These restricted units were not included in the computation of diluted earnings per share for the three and nine months ended September 30, 2012 because the potential shares would be anti-dilutive given the loss from continuing operations. Had the Company generated income from continuing operations in the three and nine months ended September 30,

2012, 3.1 million and 3.0 million, respectively, of potential common shares of common stock related to the restricted stock units would have been included in diluted average shares outstanding.

For the three and nine months ended September 30, 2013 and 2012, all 15.0 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 three and nine months ended September 30, 2012, 0.2 million and 1.3 million shares of common stock were issued upon the exercise of stock options. During the nine months ended September 30, 2013 and 2012, 1.0 million shares of common stock were issued, respectively, under the Company’s profit-sharing plan.

19. SUBSEQUENT EVENTS

Dividends

On October 4, 2013, the Company's Board of Directors declared a dividend of $0.04 per outstanding common share payable on November 15, 2013 to the shareholders of record at the close of business on November 1, 2013.

On November 4, 2013, the Company's Board of Directors voted to increase its quarterly common stock dividend from $0.04 to $0.05 per share, effective for the dividend payment to be made during the first quarter of 2014. Also, on November 4, 2013, the Company’s Board of Directors declared a dividend of $0.05 per outstanding common share payable on February 18, 2014 to the shareholders of record at the close of business on February 3, 2014.

Poland Wind Sale

On November 6, 2013, a subsidiary of the Company signed an agreement to sell all of the equity interests in its remaining wind development projects in Poland for $8 million, subject to customary closing conditions. The Company will recognize a pretax loss, net of noncontrolling interest, of approximately $3 million in the fourth quarter of 2013. Poland Wind is reported in the EMEA Generation reportable segment.

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 and Item 7: Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2012 Form 10-K and subsequent filings with the SEC. 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 MCAC utilities and 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.

Q3 2013 Performance

Despite the challenges of dry hydrological conditions in Latin America and a weaker Brazilian Real, results for the quarter improved as a result of a lower effective tax rate, reduced interest expense on recourse debt, and favorable dark spreads at the Kilroot business in the United Kingdom, as well as lower goodwill impairment expense.

Earnings Per Share Results in Q3 2013



	Three Months Ended September 30,									Nine Months Ended September 30,
	2013		2012			Change		% Change		2013		2012			Change		% Change
Diluted earnings per share from continuing operations	$	0.17	$	(2.12	)	$	2.29	108	%	$	0.55	$	(1.54	)	$	2.09	136	%
Adjusted earnings per share (a non-GAAP measure)⁽¹⁾	$	0.39	$	0.35		$	0.04	11	%	$	1.01	$	0.90		$	0.11	12	%

_____________________________


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

Three Months Ended September 30, 2013

Diluted earnings per share from continuing operations increased $2.29, or 108%, to $0.17 principally due to lower goodwill impairment expense, a lower effective tax rate, lower interest expense, and foreign currency gains, partially offset by higher asset and equity method investment impairments, and lower gross margin.

Adjusted earnings per share, a non-GAAP measure, increased by 11% primarily due to a lower effective tax rate and lower interest expense, partially offset by lower gross margin.

Nine Months Ended September 30, 2013

Diluted earnings per share from continuing operations increased $2.09, or 136%, principally due to lower goodwill impairment expense, a lower effective tax rate, lower foreign currency losses, lower interest expense, and higher other income due to the gain from the PPA termination at Beaver Valley, partially offset by losses on extinguishment of debt, lower gain on sale of investment, lower gross margin, and higher asset and equity method investment impairments.

Adjusted earnings per share, a non-GAAP measure, increased by 12% primarily due to a lower effective tax rate and lower interest expense, partially offset by lower 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 September 30, 2013 include:

Safe, Reliable and Sustainable Operations.

During the third quarter of 2013, we completed construction of two wind generation facilities in the U.K., representing a total of 36 MW. We currently have 2,231 MW under construction, expected to come on-line by 2016.

Improving Available Capital and Deployment of Discretionary Cash.

We continue to enhance our sources and uses of parent discretionary cash. During the third quarter of 2013, we generated significant cash flow from operating activities and closed an asset sale, fully exiting operations in Trinidad. In terms of uses, we deployed our discretionary cash to pay a dividend of $0.04 per share, allocated $45 million to repurchase 3.7 million shares (see Note 10. — Equity in Item 1. — Financial Statements of this Form 10-Q for further information) and invested $100 million in our subsidiaries to expand our platforms, primarily environmental upgrades at Indianapolis Power & Light facilities that will receive full recovery under tracker for qualifying costs, including return on equity.

Realigning Our Geographic Focus.

During the quarter, we made significant progress on our efforts to further streamline our portfolio. In September, we signed an agreement to sell our interests in our integrated utility and two generation businesses in Cameroon. When the sale is completed, we will exit Cameroon, further reducing our footprint to 20 countries from 28 in 2011. In October, we also signed an agreement to sell our 39 MW wind facility in India, focusing our presence in India on our OPGC facility in the state of Odisha. Finally, as we previously announced, we closed the sale of our 10% interest in the 720 MW gas-fired plant in Trinidad in July 2013.

Other Operating Highlights



	Three Months Ended September 30,							Nine Months Ended September 30,
	2013		2012			% Change		2013		2012			% Change
	($ in millions)
Revenue	$	4,003	$	4,355		-8	%	$	12,108	$	12,807		-5	%
Gross margin	$	937	$	967		-3	%	$	2,603	$	2,720		-4	%
Net income (loss) attributable to The AES Corporation	$	71	$	(1,568	)	105	%	$	320	$	(1,087	)	129	%
Adjusted pre-tax contribution (a non-GAAP measure)⁽¹⁾	$	387	$	380		2	%	$	946	$	1,002		-6	%
Net cash provided by operating activities	$	855	$	1,015		-16	%	$	2,040	$	2,129		-4	%
Dividends declared per common share	$	—	$	0.04		-100	%	$	0.08	$	0.04		100	%

_____________________________


⁽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 nine months ended September 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 September 30,											Nine Months Ended September 30,
Results of operations	2013			2012			$ change			% change		2013			2012			$ change			% change
	($ in millions, except per share amounts)
Revenue:
US — Generation	$	207		$	222		$	(15	)	-7	%	$	567		$	636		$	(69	)	-11	%
US — Utilities	763			796			(33		)	-4	%	2,159			2,206			(47		)	-2	%
Andes — Generation	628			775			(147		)	-19	%	2,044			2,279			(235		)	-10	%
Brazil — Generation	272			268			4			1	%	937			847			90			11	%
Brazil — Utilities	1,224			1,448			(224		)	-15	%	3,749			4,209			(460		)	-11	%
MCAC — Generation	469			437			32			7	%	1,398			1,256			142			11	%
EMEA — Generation	333			268			65			24	%	970			998			(28		)	-3	%
Asia — Generation	113			191			(78		)	-41	%	388			553			(165		)	-30	%
Corporate and Other⁽¹⁾	217			222			(5		)	-2	%	655			646			9			1	%
Intersegment eliminations⁽²⁾	(223		)	(272		)	49			18	%	(759		)	(823		)	64			8	%
Total Revenue	4,003			4,355			(352		)	-8	%	12,108			12,807			(699		)	-5	%
Gross Margin:
US — Generation	$	63		$	63		$	—		—	%	$	143		$	175		$	(32	)	-18	%
US — Utilities	144			173			(29		)	-17	%	361			379			(18		)	-5	%
Andes — Generation	133			165			(32		)	-19	%	416			431			(15		)	-3	%
Brazil — Generation	161			191			(30		)	-16	%	562			613			(51		)	-8	%
Brazil — Utilities	144			75			69			92	%	259			131			128			98	%
MCAC — Generation	128			127			1			1	%	338			354			(16		)	-5	%
EMEA — Generation	91			86			5			6	%	296			400			(104		)	-26	%
Asia — Generation	40			61			(21		)	-34	%	128			175			(47		)	-27	%
Corporate and Other⁽¹⁾	15			13			2			15	%	54			36			18			50	%
Intersegment eliminations⁽²⁾	18			13			5			38	%	46			26			20			77	%
Total Gross Margin	937			967			(30		)	-3	%	2,603			2,720			(117		)	-4	%
General and administrative expenses	(63		)	(64		)	1			2	%	(183		)	(225		)	42			19	%
Interest expense	(357		)	(396		)	39			10	%	(1,065		)	(1,182		)	117			10	%
Interest income	85			88			(3		)	-3	%	213			261			(48		)	-18	%
Loss on extinguishment of debt	—			—			—			NA		(212		)	—			(212		)	NA
Other expense	(15		)	(15		)	—			—	%	(58		)	(56		)	(2		)	-4	%
Other income	25			7			18			257	%	106			39			67			172	%
Gain on sale of investments	3			30			(27		)	-90	%	26			214			(188		)	-88	%
Goodwill impairment expense	(58		)	(1,850		)	1,792			97	%	(58		)	(1,850		)	1,792			97	%
Asset impairment expense	(81		)	(43		)	(38		)	-88	%	(129		)	(71		)	(58		)	-82	%
Foreign currency transaction gains (losses)	32			(7		)	39			557	%	(16		)	(108		)	92			85	%
Other non-operating expense	(122		)	—			(122		)	NA		(122		)	(50		)	(72		)	-144	%
Income tax expense	(126		)	(172		)	46			27	%	(285		)	(514		)	229			45	%
Net equity in earnings of affiliates	15			25			(10		)	-40	%	21			49			(28		)	-57	%
Income (loss) from continuing operations	275			(1,430		)	1,705			119	%	841			(773		)	1,614			209	%
Income from operations of discontinued businesses	26			30			(4		)	-13	%	25			25			—			—	%
Net gain (loss) from disposal and impairments of discontinued businesses	(78		)	(2		)	(76		)	NM		(111		)	68			(179		)	-263	%
Net income (loss)	223			(1,402		)	1,625			116	%	755			(680		)	1,435			211	%
Noncontrolling interests:
Income from continuing operations attributable to noncontrolling interests	(146		)	(155		)	9			6	%	(431		)	(398		)	(33		)	-8	%
Income from discontinued operations attributable to noncontrolling interests	(6		)	(11		)	5			45	%	(4		)	(9		)	5			56	%
Net income (loss) attributable to The AES Corporation	$	71		$	(1,568	)	$	1,639		105	%	$	320		$	(1,087	)	$	1,407		129	%
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income (loss) from continuing operations, net of tax	$	129		$	(1,585	)	$	1,714		108	%	$	410		$	(1,171	)	$	1,581		135	%
Income (loss) from discontinued operations, net of tax	(58		)	17			(75		)	-441	%	(90		)	84			(174		)	-207	%
Net income (loss)	$	71		$	(1,568	)	$	1,639		105	%	$	320		$	(1,087	)	$	1,407		129	%

_____________________________

NM — Not meaningful


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


⁽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 September 30, 2013:

Revenue decreased $352 million, or 8%, to $4.0 billion in the three months ended September 30, 2013 compared with $4.4 billion in the three months ended September 30, 2012. Excluding the unfavorable impact of foreign currency of $228 million, the key drivers of the change at each of the SBUs are as follows:


•	US — Overall unfavorable impact of $48 million, or 5%, due to customer switching at DPL, which drove lower retail sales volume and lower average retail prices, a one-time favorable settlement in 2012 at DPL, lower retail volume due to unfavorable weather at IPL, and the impact of the PPA buyout at Beaver Valley in Pennsylvania, partially offset by higher wholesale volume at DPL and IPL.

•

Andes — Overall unfavorable impact of $106 million, or 14%, due to the impact of Resolution 95 which no longer has a fuel recognition component in revenue as well as lower generation in Argentina, lower contract prices in Chile, and lower generation in Colombia due to lower water inflows, partially offset by higher spot and contract prices in Colombia and better availability in Argentina in 2013.


•	Brazil — Overall unfavorable impact of $30 million, or 2%, mainly due to lower pass-through costs at Eletropaulo and Sul and the tariff reset at Sul implemented in April 2013, partially offset by higher prices at Tietê due to the annual PPA indexation in July 2013 and higher spot prices as well as higher volume due to increased market demand at Eletropaulo.


•	MCAC — Overall favorable impact of $26 million, or 4%, due to higher sales in the Dominican Republic, higher prices in Mexico and Puerto Rico, somewhat offset by lower spot sales due to lower hydrology at Panama and lower pass-through energy sales at El Salvador.

•

EMEA — Overall favorable impact of $62 million, or 23%, due to increased net capacity factor and higher prices at Kilroot and higher volume driven by demand at Ballylumford in the U.K., higher pass-through of CO₂ allowance costs at Maritza, and higher pass-through revenue at Jordan, partially offset by non-repeated sales of heavy fuel oil and European emission allowances and receipt of insurance proceeds in 2012 at Ballylumford.


•	Asia — Overall unfavorable impact of $78 million, or 41% due to lower volume as a result of lower demand at Kelanitissa in Sri Lanka and lower prices in the Philippines.

Gross margin decreased $30 million, or 3%, to $937 million in the three months ended September 30, 2013 compared with $967 million in the three months ended September 30, 2012. Excluding the unfavorable impact of foreign currency of $44 million, the key drivers of the change at each of the SBUs are as follows:


•	US — Overall unfavorable impact of $29 million, or 12%, driven by lower retail margin and a one-time favorable settlement at DPL in 2012, as well as a mark-to-market loss on derivatives at DPL and lower retail margin at IPL, partially offset by lower amortization expense at DPL and higher wholesale volume at DPL and IPL.

•

Andes — Overall unfavorable impact of $25 million or 15%, due to lower generation in Colombia and Argentina as discussed above, as well as lower availability, loss of spot margin due to higher contract demand at lower prices, and lower coal generation in Chile, partially offset by new operations of Ventanas IV in Chile, higher spot prices in Colombia, and higher margin and better availability in Argentina.


•	Brazil — Overall favorable impact of $78 million, or 29%, due to increased demand at Brazil Utilities, higher tariff due to annual tariff readjustment in July 2013 and lower fixed costs at Eletropaulo, as well as higher prices at Tietê as discussed above, somewhat offset by seasonal demand of Eletropaulo's contract and higher energy purchases due to lower generation at Tietê.


•	MCAC — Overall favorable impact of $1 million, or 1%, due to replacement energy purchased at higher prices due to lower hydrology in Panama, partially offset by higher sales and prices as well as lower energy purchased in the Dominican Republic.


•	EMEA — Overall favorable impact of $3 million, or 3%, due to higher margin in Kilroot as discussed above as well as lower coal costs, partially offset by lower availability at Maritza in Bulgaria, higher CO₂ costs in Kilroot, and sales in 2012 not repeated at Ballylumford as discussed above.


•	Asia — Overall unfavorable impact of $21 million, or 34%, due to higher contract volume at lower prices reducing spot exposure.

Net income attributable to The AES Corporation increased $1.6 billion to $71 million in the three months ended September 30, 2013 compared to a net loss attributable of $1.6 billion in the three months ended September 30, 2012. The key drivers of the increase included:


•	lower goodwill impairment expense;


•	a lower effective tax rate;


•	lower interest expense, primarily at the Parent Company, due to a reduction in debt principal as well as the prior year de-designation of an interest rate hedge; and


•	foreign currency gains in 2013 compared to losses in 2012.

These increases were partially offset by:


•	other non-operating expense associated with an impairment at our equity method investment at Elsta in the Netherlands;


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


•	lower gross margin as described above; and


•	higher asset impairment expense due to impairments at our Polish Wind projects and Itabo (San Lorenzo) in the Dominican Republic.

Net cash provided by operating activities decreased $160 million, or 16%, to $855 million in the three months ended September 30, 2013 compared with $1 billion in the three months ended September 30, 2012.

Net cash provided by operating activities was $855 million for the three months ended September 30, 2013 and resulted primarily from net income adjusted for non-cash items, principally depreciation and amortization, gains and losses and disposals and impairment charges, as well as a net favorable change of $55 million in operating assets and liabilities. This was primarily due to the following:


•	a decrease of $348 million in prepaid expenses and other current assets primarily due to cash received from the regulator at Eletropaulo;


•	an increase of $68 million in net income tax and other tax payables primarily due to accruals for new current tax liabilities offset by payments of income taxes; partially offset by


•	a decrease of $326 million in accounts payable and other current liabilities mainly due to a decrease in current regulatory liabilities at Eletropaulo and Sul; and


•	an increase of $56 million in accounts receivable due to higher volume of energy sales at Eletropaulo and lower collections at Maritza.

Net cash provided by operating activities was $1 billion during the three months ended September 30, 2012. Operating cash flow resulted primarily from the net loss adjusted for non-cash items, principally depreciation and amortization, contingencies, deferred income taxes, gains and losses on sales and disposals and impairment charges, as well as a net favorable change of $206 million in operating assets and liabilities. This was primarily due to the following:


•	an increase of $98 million in net income tax and other tax payables primarily due to accruals for new tax liabilities offset by payment of income taxes in the quarter;


•	an increase of $75 million in accounts payable and other current liabilities primarily driven by accrued interest at the Parent Company and by higher energy, materials and services purchases, indirect taxes and accrued interest offset by lower current regulatory liabilities at Eletropaulo, as a result of refunds to consumers of prior period costs through the current tariff;


•	a decrease of $72 million in prepaid expenses and other current assets primarily due to a decrease in prepaid property taxes at DPL and decreases in current regulatory assets for the recovery of prior tariff cycle energy purchases and regulatory charges at Eletropaulo; partially offset by


•	an increase of $86 million in other assets mainly due to an increase in noncurrent regulatory assets, resulting from higher priced energy purchases, transmission costs and regulatory charges which are recoverable through future tariffs at Eletropaulo.

Nine months ended September 30, 2013:

Revenue decreased $699 million, or 5%, to $12.1 billion in the nine months ended September 30, 2013 compared with $12.8 billion in the nine months ended September 30, 2012. Excluding the unfavorable impact of foreign currency of $586 million, the key drivers of the change at each of the SBUs are as follows:

•

US — Overall unfavorable impact of $116 million, or 4%, driven by lower capacity revenue, lower average wholesale prices, lower average retail prices due to downward price pressure as a result of generating services competition and lower retail volume 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 $138 million, or 6%, driven by lower prices due to the change in regulatory framework as a result of Resolution 95, which no longer has a fuel recognition component in 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 better availability in Argentina in 2013.

•

Brazil — Overall favorable impact of $126 million, or 2%, driven by the temporary restart of operations at Uruguaiana in the first quarter of 2013, higher tariffs mainly due to the 2012 tariff reset provision and the annual tariff adjustment in July 2013 at Eletropaulo, and higher volume as well as prices at Tietê due to the annual PPA indexation in July 2013 and higher spot prices, partially offset by lower tariffs driven by lower pass-through costs and the tariff reset in April 2013 and lower demand at Sul.

•

MCAC — Overall favorable impact of $143 million, or 8%, 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, partially offset by lower contract prices in the Dominican Republic.

•

EMEA — Overall unfavorable impact of $26 million, or 2%, driven by the sale of 80% of our ownership and a non-recurring favorable arbitration settlement in Cartagena in February 2012 and reduction in capacity remuneration in line with the PPA at Ballylumford beginning in April 2012, partially offset by increased dispatch and higher prices at Kilroot and increased demand and better availability at Ballylumford in the U.K. as well as higher pass-through revenue at Jordan.


•	Asia — Overall unfavorable impact of $165 million, or 30%, driven by lower volume due to lower demand at Kelanitissa in Sri Lanka and lower contract and spot rates in the Philippines.

Gross margin decreased $117 million, or 4%, to $2.6 billion in the nine months ended September 30, 2013 compared with $2.7 billion in the nine months ended September 30, 2012. Excluding the unfavorable impact of foreign currency of $93 million, the key drivers of the change at each of the SBUs are as follows:


•	US — Overall unfavorable impact of $50 million, or 9%, driven by lower retail margin due to customer switching and lower capacity margin at DPL as discussed above, increased outages and related fixed costs at Hawaii, the PPA buyout at Beaver Valley, partially offset by lower depreciation and amortization expense at DPL and higher wholesale volume at DPL and IPL.

•

Andes — Overall was neutral to prior year driven by new operations of Ventanas IV in Chile which commenced operations in March 2013, higher spot and contract prices at Chivor, higher availability in Chile and Argentina, and higher margin in Argentina driven by the application of Resolution 95, improving variable margin, partially offset by lower generation at Chivor and Argentina as discussed above, and lower gas availability as well as lower spot sales due to higher contract demand at lower prices in Chile as discussed above, and higher fixed costs.

•

Brazil — Overall favorable impact of $159 million, or 21%, driven by the tariff impact as discussed above and higher demand at Eletropaulo, 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 discussed above, and lower generation as well as lower water inflows in the system resulting in higher energy purchased at higher spot prices due to shared hydrologic risk requirement among all hydro generators at Tietê.


•	MCAC — Overall unfavorable impact of $2 million, or 1%, driven by higher replacement purchased energy at higher spot prices in Panama caused by lower hydrology, partially offset by higher contract and spot sales in the

Dominican Republic as discussed above, 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 $106 million, or 27%, 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 better availability at Ballylumford in the U.K.


•	Asia —Overall unfavorable impact of $47 million, or 27%, driven by lower prices in the Philippines as a result of higher contract levels at lower prices to reduce spot exposures and the favorable impact of a mark-to-market commodity derivative adjustment in 2012.

Net income attributable to The AES Corporation increased $1.4 billion to $320 million in the nine months ended September 30, 2013 compared to net loss attributable of $1.1 billion in the nine months ended September 30, 2012. The key drivers of the increase included:


•	lower goodwill impairment expense;


•	a lower effective tax rate;


•	lower foreign currency losses;


•	lower interest expense due to gains resulting from ineffectiveness on interest rate swaps at Puerto Rico as well as a reduction in debt principal and the prior year de-designation of an interest rate hedge at the Parent Company; and


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

These increases were partially offset by:


•	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;


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


•	lower gross margin as described above;


•	other non-operating expense associated with an impairment at our equity method investment at Elsta in the Netherlands; and


•	higher asset impairment expense due to impairments at Polish Wind Projects and Itabo (San Lorenzo) in the Dominican Republic.

Net cash provided by operating activities decreased $89 million, or 4%, to $2.0 billion in the nine months ended September 30, 2013 compared with $2.1 billion in the nine months ended September 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.

For the three and nine months ended September 30, 2013, the Company changed the definition of Adjusted PTC and Adjusted EPS to exclude the gains or losses attributable to AES common stockholders at our equity method investments for these same types of items. Previously, these amounts were not excluded from the calculation of adjusted EPS and adjusted PTC because the company did not have a controlled process for obtaining this information from our equity method investments. Accordingly, the Company has also reflected the change in the comparative three and nine month periods ended September 30, 2012.

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.

For the three months ended September 30, 2012, the Company reported a loss from continuing operations of $2.12 per share. For purposes of measuring diluted loss per share under GAAP, common stock equivalents were excluded from weighted-average shares as their inclusion would be anti-dilutive. However, for purposes of computing adjusted EPS (a non-GAAP measure), the Company has included the impact of dilutive common stock equivalents as the inclusion of the defined adjustments result in income for adjusted EPS. The table below reconciles the weighted-average shares used in GAAP diluted earnings per share to the weighted-average shares used in calculating the non-GAAP measure of adjusted EPS.



	Three Months Ended September 30, 2012
	Loss			Shares	$ per share
	(in millions except per share data)
Reconciliation of Denominator Used For Adjusted Earnings Per Share
GAAP DILUTED (LOSS) PER SHARE
Loss from continuing operations attributable to The AES Corporation common stockholders	$	(1,585	)	747	$	(2.12	)
EFFECT OF DILUTIVE SECURITIES
Stock options	—			1	—
Restricted stock units	—			3	0.01
NON-GAAP DILUTED (LOSS) PER SHARE	$	(1,585	)	751	$	(2.11	)

The table below reconciles our GAAP measure pre-tax contribution to our non-GAAP measures of adjusted PTC and adjusted EPS:



	Three Months Ended September 30, 2013							Three Months Ended September 30, 2012							Nine Months Ended September 30, 2013							Nine Months Ended September 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 (loss) from continuing operations attributable to AES and Diluted EPS	$	129		$	0.17			$	(1,585	)	$	(2.11	)		$	410		$	0.55			$	(1,171	)	$	(1.54	)
Add back income tax expense from continuing operations attributable to AES	55							97							96							326
Pre-tax contribution	$	184						$	(1,488	)					$	506						$	(845	)
Adjustments
Unrealized derivative (gains) losses⁽²⁾	$	(7	)	$	—			$	22		$	0.01			$	(46	)	$	(0.04	)		$	88		$	0.08
Unrealized foreign currency transaction (gains) losses⁽³⁾	(22		)	(0.03		)		(22		)	(0.01		)		25			0.04				(8		)	—
Disposition/acquisition (gains)	(4		)	—				(25		)	(0.04		)	⁽⁴⁾	(30		)	(0.03		)	⁽⁵⁾	(206		)	(0.18		)	⁽⁶⁾
Impairment losses	236			0.25			⁽⁷⁾	1,893			2.50			⁽⁸⁾	284			0.29			⁽⁹⁾	1,973			2.54			⁽¹⁰⁾
Loss on extinguishment of debt	—			—				—			—				207			0.20			⁽¹¹⁾	—			—
Adjusted pre-tax contribution and Adjusted EPS	$	387		$	0.39			$	380		$	0.35			$	946		$	1.01			$	1,002		$	0.90

_____________________________


⁽¹⁾	NCI is defined as Noncontrolling Interests.


⁽²⁾	Unrealized derivative (gains) losses were net of income tax per share of $(0.01) and $0.02 in the three months ended September 30, 2013 and 2012, and of $(0.03) and $0.04 in the nine months ended September 30, 2013 and 2012, respectively.


⁽³⁾	Unrealized foreign currency transaction (gains) losses were net of income tax per share of $(0.01) and $(0.01) in the three months ended September 30, 2013 and 2012, and of $0.01 and $(0.01) in the nine months ended September 30, 2013 and 2012, respectively.


⁽⁴⁾	Amount primarily relates to the gain from the sale of our interest in China for $24 million ($28 million, or $0.04 per share including an income tax credit of $4 million, or $0.00 per share).

⁽⁵⁾

Amount primarily relates to the gain from the sale of the remaining 20% of our interest in Cartagena for $20 million ($14 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), the gain from the sale of Trinidad 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).


⁽⁶⁾	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) and the sale of our interest in China for $24 million ($28 million, or $0.04 per share including an income tax credit of $4 million, or $0.00 per share).

⁽⁷⁾

Amount primarily relates to other-than-temporary impairment of our equity method investment at Elsta in the Netherlands of $122 million ($89 million, or $0.12 per share, net of income tax per share of $0.04). Amount also includes asset impairments at Poland wind projects of $65 million ($47 million, or $0.06 per share, net of noncontrolling interest of $18 million and of income tax per share of $0.00), asset impairment at Itabo (San Lorenzo) of $15 million ($6 million, or $0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02).

⁽⁸⁾

Amount primarily relates to the goodwill impairment at DPL of $1.85 billion ($1.85 billion, or $2.46 per share, net of income tax per share of $0.00), asset impairment of Wind turbines and projects of $36 million ($25 million, or $0.03 per share, net of income tax per share of $0.01) and Kelanitissa of $5 million ($3 million, or $0.00 per share, net of noncontrolling interest and income tax per share of $0.00).


⁽⁹⁾	Amount primarily relates to other-than-temporary impairment of our equity method investment at Elsta in the Netherlands of $122 million ($89 million, or $0.12 per share, net of income tax per share of $0.04). Amount also

includes asset impairments at Poland wind projects of $65 million ($47 million, or $0.06 per share, net of noncontrolling interest of $18 million and of income tax per share of $0.00), asset impairment at Beaver Valley of $46 million ($33 million, or $0.04 per share, net of income tax per share of $0.02), asset impairment at Itabo (San Lorenzo) of $15 million ($6 million, or $0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02).

⁽¹⁰⁾

Amount primarily relates to the goodwill impairment at DPL of $1.85 billion ($1.85 billion, or $2.42 per share, net of income tax per share of $0.00). Amount also includes 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), as well as asset impairments of Wind turbines and projects of $40 million ($28 million, or $0.04 per share, net of income tax per share of $0.02) and asset impairments at Kelanitissa of $17 million ($11 million, or $0.01 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.01) and at St. Patrick of $11 million ($8 million or $0.01 per share, net of income tax per share of $0.00).


⁽¹¹⁾	Amount primarily relates to the loss on early retirement of debt at Corporate of $165 million ($120 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 September 30,						For the Nine Months Ended September 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	207	$	222	-7	%	$	567	$	636	-11	%
Gross Margin	$	63	$	63	—	%	$	143	$	175	-18	%

Generation revenue for the three months ended September 30, 2013 decreased $15 million, or 7%, compared to the three months ended September 30, 2012.


•	a decrease of $15 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 $7 million at Southland in California, primarily due to the short-term restart of two generating units at Huntington Beach from May through October 2012.

These decreases were partially offset by


•	a net increase in revenue of $6 million at Deepwater in Texas as a result of higher energy prices and volumes offset by the sale of the emission allowances surplus that occurred in July and August 2012.

Generation gross margin for the three months ended September 30, 2013 remained flat at $63 million, compared to the three months ended September 30, 2012.

For the three months ended September 30, 2013, revenue decreased 7%, while gross margin remained flat, primarily due to lower fuel related costs relating to the conversion of two generating units at Huntington Beach to synchronous condensers resulting in an increase in gross margin.

Generation revenue for the nine months ended September 30, 2013 decreased $69 million, or 11%, compared to the nine months ended September 30, 2012 primarily due to:


•	a decrease of $47 million at Beaver Valley, as a result of the early termination of the PPA with the offtaker in January 2013;


•	a decrease of $19 million at Southland, primarily due to the temporary restart of two generating units at Huntington Beach from May through October 2012; and


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

These decreases were partially offset by a net increase in revenue of $6 million at Deepwater in Texas as a result of higher energy prices and volumes, offset by the sale of the emission allowances surplus that occurred in July and August 2012.

Generation gross margin for the nine months ended September 30, 2013 decreased $32 million, or 18%, compared to the nine months ended September 30, 2012 primarily due to:


•	a decrease of $22 million at Hawaii, primarily due to lower availability and increased fixed costs as a result of outages;


•	a decrease of $13 million at Beaver Valley as discussed above; and


•	a decrease of $7 million at Southland as discussed above.

These decreases were partially offset by an increase across all of the wind farms gross margin of $15 million as a result of an increase in revenues due to higher winds and lower fixed costs, primarily relating to development and maintenance.

For the nine months ended September 30, 2013, revenue decreased 11% while gross margin decreased 18%, primarily due to higher fixed costs relating to outages at Hawaii resulting in a decrease in 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 September 30,						For the Nine Months Ended September 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	763	$	796	-4	%	$	2,159	$	2,206	-2	%
Gross Margin	$	144	$	173	-17	%	$	361	$	379	-5	%

Utilities revenue for the three months ended September 30, 2013 decreased $33 million, or 4%, compared to the three months ended September 30, 2012 primarily due to:


•	lower retail sales volumes of $33 million at DPL due to customer switching to other generation service providers at DP&L and unfavorable temperatures in 2013 compared to 2012, net of volume increases at DPLER, DPL’s competitive service provider;


•	lower prices of $20 million at DPL, in Ohio, primarily due to lower average retail prices due to downward price pressure as a result of generation services competition;


•	favorable one-time settlement revenue at DPL in September 2012 of $13 million; and


•	lower retail sales volume of $12 million at IPL due to unfavorable temperatures in 2013.

These decreases were partially offset by:


•	higher wholesale volume of $33 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; and


•	higher wholesale volume of $9 million at IPL, primarily due to higher natural gas prices, which improved IPL's ability to compete in the wholesale market, as well as the decrease in retail demand, which made more energy available for wholesale sales.

Utilities gross margin for the three months ended September 30, 2013 decreased $29 million, or 17%, compared to the three months ended September 30, 2012 primarily due to:


•	lower retail margin at DPL and IPL of $41 million and $6 million, respectively, primarily due to DP&L customers switching to DPL Inc.'s competitive retail supplier or other third parties and the decreased volumes at IPL described above;


•	a decrease of $7 million at DPL due to the unfavorable impact of mark-to-market adjustments on derivative contracts; and


•	favorable one-time revenue at DPL in September 2012 of $13 million.

These decreases were partially offset by:


•	lower depreciation and amortization expense of $13 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 $24 million and $2 million, respectively, primarily due to increased volumes as described above.

For the three months ended September 30, 2013, revenue decreased 4%, while gross margin decreased 17%, primarily due to the lower margins realized by DPL on energy sold on the wholesale market that was previously sold to regulated retail customers; partially offset by the unfavorable impact on gross margin in 2012 from the amortization of intangible assets of $13 million related to the DPL acquisition.

Utilities revenue for the nine months ended September 30, 2013 decreased $47 million, or 2%, compared to the nine months ended September 30, 2012 primarily due to:


•	lower prices of $147 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;


•	lower retail sales volumes of $33 million at DPL due to customer switching to other generation service providers at DP&L net of volume increases at DPLER, DPL’s competitive service provider;


•	lower retail sales volume of $9 million at IPL primarily due to lower demand from commercial and industrial customers of $10 million, which we believe is attributable to IPL's customers implementing energy efficiency initiatives; and


•	favorable one-time settlement revenue at DPL in September 2012 of $13 million.

These decreases were partially offset by:


•	higher wholesale volume of $122 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;


•	higher wholesale volume of $28 million at IPL, primarily due to higher natural gas prices, which improved IPL's ability to compete in the wholesale market; and


•	favorable wholesale prices at IPL of $9 million.

Utilities gross margin for the nine months ended September 30, 2013 decreased $18 million, or 5%, compared to the nine months ended September 30, 2012 primarily due to:


•	lower retail margin at DPL and IPL of $129 million and $8 million, primarily due to DP&L customers switching to DPL Inc.'s competitive retail supplier or other third parties and the decreased volumes at IPL described above;


•	favorable one-time revenue at DPL in September 2012 of $13 million; and


•	lower capacity margins at DPL of $11 million primarily due to lower capacity prices in the PJM market in 2013.

These decreases were partially offset by:


•	higher wholesale margins at DPL and IPL of $76 million and $12 million, respectively, primarily due to increased volumes as described above; and


•	lower depreciation and amortization expense of $62 million at DPL primarily because DPL's ESP intangible asset was fully amortized at the end of 2012.

For the nine months ended September 30, 2013, revenue decreased 2%, while gross margin decreased 5%, primarily due to the lower margins realized by DPL on energy sold on the wholesale market that was previously sold to regulated retail customers; partially offset by the unfavorable impact on gross margin in 2012 from the amortization of intangible assets of $62 million related to the DPL acquisition.

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 September 30,						For the Nine Months Ended September 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	628	$	775	-19	%	$	2,044	$	2,279	-10	%
Gross Margin	$	133	$	165	-19	%	$	416	$	431	-3	%

Excluding the unfavorable impact of foreign currency translation and remeasurement of $41 million, generation revenue for the three months ended September 30, 2013 decreased $106 million, or 14%, compared to the three months ended September 30, 2012 primarily due to:


•	lower prices in Argentina of $97 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 for further information;


•	lower contract prices in the SIC market at Gener of $36 million;


•	lower generation at Chivor in Colombia of $33 million as a result of lower inflows; and


•	lower generation at Argentina of $19 million driven by lower dispatch.

These decreases were partially offset by:


•	higher contract and spot prices at Chivor of $43 million due to pressure from lower water inflows; and


•	lower outages in Argentina of $32 million.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $7 million, generation gross margin for the three months ended September 30, 2013 decreased $25 million, or 15%, compared to the three months ended September 30, 2012 primarily due to:


•	lower generation at Chivor and Argentina of $62 million and $8 million driven by lower inflows and lower dispatch, respectively;


•	lower margin in Chile of $26 million mainly driven by lower spot margin as a result of higher contract sales at a lower price and lower coal generation;


•	lower availability in Chile of $21 million mainly driven by a planned maintenance at Ventanas III during September 2013; and


•	lower prices in Chile of $9 million mainly driven by lower contract prices in the SIC market.

These decreases were partially offset by:


•	higher prices at Chivor of $39 million as discussed above;


•	new business in Chile of $35 million due to the commencement of operations at Ventanas IV in March 2013;


•	higher margin of $17 million in Argentina driven by the application of Resolution 95 improving variable margin; and


•	higher availability of our plants in Argentina of $8 million.

For the three months ended September 30, 2013, revenues and gross margin decreased by 19%.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $97 million, generation revenue for the nine months ended September 30, 2013 decreased $138 million, or 6%, compared to the nine months ended September 30, 2012 primarily due to:


•	lower prices in Argentina of $182 million primarily due to a change in the regulatory framework as a result of Resolution 95;


•	lower contract and spot prices in the SIC market at Gener of $90 million;


•	lower generation in Argentina of $72 million driven by lower dispatch; and


•	lower generation at Chivor of $62 million as a result of lower inflows.

These decreases were partially offset by:


•	higher contract and spot prices at Chivor of $142 million due to pressure from lower water inflows;


•	fewer outages in Argentina of $77 million; and


•	higher volume in Chile of $50 million due to higher spot and contract sales in the SIC market.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $15 million, generation gross margin for the nine months ended September 30, 2013 remained neutral compared to the nine months ended September 30, 2012 primarily due to:


•	new business in Chile of $102 million due to the commencement of operations at Ventanas IV in March 2013;


•	higher prices in Chivor of $82 million as discussed above;


•	higher availability of our plants in Chile and Argentina by $18 million; and $25 million, respectively; and


•	higher margin in Argentina of $10 million driven by the application of Resolution 95, improving variable margin.

These increases were partially offset by:


•	lower generation of $186 million mainly driven by $112 million at Chivor due to lower inflows and $74 million in Chile primarily due to lower gas availability and lower spot sales due to higher contract demand at a lower price;


•	lower prices in Chile of $22 million as a result of lower contract prices and higher spot purchase prices in the SIC market;


•	lower generation in Argentina of $17 million as discussed above; and


•	higher fixed costs and depreciation of $14 million mainly driven by higher maintenance expense.

For the nine months ended September 30, 2013, revenues decreased by 10%, while gross margin decreased by 3%. This was primarily due to the gross margin provided by 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 September 30,						For the Nine Months Ended September 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	272	$	268	1	%	$	937	$	847	11	%
Gross Margin	$	161	$	191	-16	%	$	562	$	613	-8	%

Excluding the unfavorable impact of foreign currency translation of $35 million, generation revenue for the three months ended September 30, 2013 increased $39 million, or 15%, compared to the three months ended September 30, 2012 primarily due to:


•	higher prices of $36 million at Tietê mainly due to a $15 million impact of PPA annual indexation in July 2013 and higher spot prices of $12 million.

Excluding the unfavorable impact of foreign currency translation of $21 million, generation gross margin for the three months ended September 30, 2013 decreased $9 million, or 5%, compared to the three months ended September 30, 2012 primarily due to:


•	negative impact of $35 million at Tietê mainly driven by seasonal demand of Eletropaulo's contract and higher energy purchases due to lower generation.

This decrease was partially offset by:


•	the positive impact of $21 million at Tietê driven by PPA annual indexation in July 2013 and lower energy purchase prices from third parties contracts.

Excluding the unfavorable impact of foreign currency translation, for the three months ended September 30, 2013, revenue increased 15%, while gross margin decreased by 5%, primarily due to higher energy purchases at Tietê.

Excluding the unfavorable impact of foreign currency translation of $100 million, generation revenue for the nine months ended September 30, 2013 increased $190 million, or 22%, compared to the nine months ended September 30, 2012 primarily due to:


•	higher volume of $120 million mainly from $96 million from generation at Uruguaiana due to the temporary restart of operations during February and March of 2013 and $24 million of higher energy sales at Tietê and


•	higher prices of $70 million at Tietê in energy sold mainly due to a $43 million impact of the PPA annual indexation in July 2013 and higher spot market prices of $45 million, partially offset by $19 million in lower prices on third-party contracts.

Excluding the unfavorable impact of foreign currency translation of $54 million, generation gross margin for the nine months ended September 30, 2013 increased $3 million, or less than 1%, compared to the nine months ended September 30, 2012 primarily due to:


•	$65 million of gross margin at Uruguaiana mainly from the reversal of YPF liability of $57 million and temporary restart of operations as mentioned above; and


•	lower operation and maintenance costs of $12 million at Tietê.

These increases were partially offset by:


•	higher energy costs of $12 million at Tietê driven by higher prices on the spot market, partially offset by higher prices in energy sold, and


•	higher energy purchases of $58 million at Tietê mainly due to hydrologic risk requirement among all generators at higher spot prices and lower generation.

Excluding the unfavorable impact of foreign currency translation, for the nine months ended September 30, 2013, revenue increased 22%, primarily due to Uruguaiana operations in the first quarter and higher energy prices at Tietê, while gross margin remained flat mainly due to the reversal of YPF liability at Uruguaiana; partially offset by higher energy purchases 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 September 30,						For the Nine Months Ended September 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	1,224	$	1,448	-15	%	$	3,749	$	4,209	-11	%
Gross Margin	$	144	$	75	92	%	$	259	$	131	98	%

Excluding the unfavorable impact of foreign currency translation of $156 million, utilities revenue for the three months ended September 30, 2013 decreased $68 million, or 5%, compared to the three months ended September 30, 2012 primarily due to:


•	lower tariffs of $77 million at Eletropaulo and Sul mainly due to lower pass through costs and the tariff reset at Sul implemented in April 2013; partially offset by the annual tariff readjustment at Eletropaulo.

This decrease was partially offset by:


•	higher volume of $10 million at Eletropaulo due to increased market demand.

Excluding the unfavorable impact of foreign currency translation of $18 million, utilities gross margin for the three months ended September 30, 2013 increased $87 million, or 116%, compared to the three months ended September 30, 2012 primarily due to:


•	higher volume of $41 million at Eletropaulo and Sul mainly due to increased market demand;


•	higher tariffs of $26 million at Eletropaulo mainly due to the annual tariff readjustment in July 2013; and


•	lower fixed costs of $19 million at Eletropaulo mainly driven by operation and maintenance costs and lower contingencies.

Excluding the unfavorable impact of foreign currency translation, for the three months ended September 30, 2013, revenue decreased 5%, while gross margin increased 116% primarily due to lower pass through energy which has no impact on gross margin and the positive impact on gross margin of higher volume and lower operation and maintenance costs at Eletropaulo.

Excluding the unfavorable impact of foreign currency translation of $396 million, utilities revenue for the nine months ended September 30, 2013 decreased $64 million, or 2%, compared to the nine months ended September 30, 2012 primarily due to:


•	lower tariffs of $104 million at Sul mainly driven by lower pass through costs and the tariff reset in April 2013; and


•	lower volume of $36 million mainly due to decreased market demand at Sul.

These decreases were partially offset by:


•	higher tariffs of $77 million at Eletropaulo mainly due to the 2012 tariff reset provision and the annual tariff adjustment in July 2013.

Excluding the unfavorable impact of foreign currency translation of $28 million, utilities gross margin for the nine months ended September 30, 2013 increased $156 million, or 119%, compared to the nine months ended September 30, 2012 primarily due to:


•	higher tariffs of $131 million at Eletropaulo as discussed above;


•	lower fixed costs of $45 million at Eletropaulo mainly driven by the reversal of bad debt allowance, partially offset by higher pension costs; and


•	higher volume of $41 million at Eletropaulo mainly due to increased market demand.

These increases were partially offset by:


•	lower tariffs of $35 million at Sul due to the tariff reset compared to 2012 and cumulative adjustment to regulatory assets and liabilities; and


•	lower volume $21 million at Sul due to a decreased market demand.

Excluding the unfavorable impact of foreign currency translation, for the nine months ended September 30, 2013 revenue decreased 2% while gross margin increased 119% primarily due to lower pass through costs which have no impact on gross margin and the positive impact on gross margin of higher tariffs and lower operation and maintenance costs at Eletropaulo.

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 September 30,						For the Nine Months Ended September 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	469	$	437	7	%	$	1,398	$	1,256	11	%
Gross Margin	$	128	$	127	1	%	$	338	$	354	-5	%

Excluding the favorable impact of foreign currency translation of $1 million, primarily in Mexico, generation revenue for the three months ended September 30, 2013 increased $31 million, or 7%, compared to the three months ended September 30, 2012 primarily due to:


•	the positive impact of $20 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


•	an increase of $18 million at Merida, TEG/TEP and Puerto Rico, mainly due to higher fuel prices.

These increases were partially offset by:


•	lower spot sales of $8 million at Panama, primarily related to lower generation caused by lower hydrology.

Gross margin for the three months ended September 30, 2013 was flat compared to the three months ended September 30, 2012 primarily due to:


•	a decrease in Panama of $26 million mainly due to replacement energy purchases at higher prices caused by lower hydrology.

This decrease was partially offset by:


•	an increase of $19 million at Andres - Los Mina mainly from higher contract energy prices, higher spot and contract sales and higher gas sales to third parties as discussed above; and


•	an increase of $6 million at Itabo due to lower replacement energy purchases due to higher generation.

Excluding the favorable impact of foreign currency translation, for the three months ended September 30, 2013, revenue increased 7%, while gross margin remained flat, primarily due to higher energy purchases in Panama, partially offset by higher spot and contract sales in Andres - Los Mina and lower purchases in Itabo.

Excluding the favorable impact of foreign currency translation of $9 million, primarily in Mexico, generation revenue for the nine months ended September 30, 2013 increased $133 million, or 11%, compared to the nine months ended September 30, 2012 primarily due to:


•	the positive impact of $89 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 $63 million in Merida and Puerto Rico primarily due to higher volume and rates.

These increases were partially offset by:


•	lower contract prices of $17 million at Itabo, primarily related to lower fuel prices.

Excluding the favorable impact of foreign currency translation of $2 million, generation gross margin for the nine months ended September 30, 2013 decreased $18 million, or 5%, compared to the nine months ended September 30, 2012 primarily due to:


•	a decrease in Panama of $66 million mainly due to replacement energy purchases at higher prices caused by lower hydrology;


•	higher fixed costs across the segment of $13 million mainly due to maintenance performed at Itabo;


•	a decrease of $10 million at Andres - Los Mina mainly due to higher energy purchases due to outages; and


•	higher depreciation and amortization expense of $9 million primarily due to the capitalization of the Esti tunnel project since June 2012.

These decreases were partially offset by:


•	an increase of $51 million at Andres - Los Mina mainly from higher contract energy and spot sales and higher volume of gas sales to third parties as discussed above; 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 nine months ended September 30, 2013, revenue increased 11%, while gross margin decreased by 5% primarily due to higher energy purchases in Panama, partially offset by the Esti tunnel reimbursement.

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 September 30,						For the Nine Months Ended September 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	333	$	268	24	%	$	970	$	998	-3	%
Gross Margin	$	91	$	86	6	%	$	296	$	400	-26	%

Excluding the favorable impact of foreign currency translation of $3 million, generation revenue for the three months ended September 30, 2013 increased $62 million, or 23%, compared to the three months ended September 30, 2012 primarily due to:


•	higher results of $33 million at our plants in the U.K. driven by higher capacity factor and higher electricity prices in Kilroot and higher volume due to demand at Ballylumford;


•	$24 million mainly due to higher pass-through of CO₂ allowance costs for our Maritza plant in Bulgaria; and


•	$13 million in Jordan driven mainly by higher pass-through fuel revenue.

These increases were partially offset by:


•	$7 million at Ballylumford in the U.K. primarily from non-repeated sales of heavy fuel oil and European emission allowances and receipt of insurance proceeds in 2012; and


•	$4 million at Maritza due to lower availability.

Excluding the favorable impact of foreign currency translation of $2 million, generation gross margin for the three months ended September 30, 2013 increased $3 million, or 3%, compared to the three months ended September 30, 2012 primarily due to:


•	higher results of $18 million at our plants in the U.K. as discussed above, as well as lower coal prices at Kilroot, partially offset by higher cost of CO₂ emissions, which were free in 2012.

The increase was partially offset by:


•	$7 million at Ballylumford primarily from sales in 2012 not repeated as discussed above; and


•	$4 million in Maritza due to lower availability as discussed above.

Excluding the favorable impact of foreign currency translation, for the three months ended September 30, 2013, revenue increased 23%, while gross margin increased 3% primarily due to the contribution from U.K. and Jordan businesses partially offset by higher cost of fuel and higher cost of CO₂ emissions.

Excluding the unfavorable impact of foreign currency translation of $2 million, generation revenue for the nine months ended September 30, 2013 decreased $26 million, or 3%, compared to the nine months ended September 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


•	a decrease of $29 million primarily as a result of reduction in capacity remuneration at Ballylumford in the U.K.

These decreases were partially offset by:


•	higher results of $84 million at our plants in the U.K. driven by higher prices and higher dispatch at Kilroot and better reliability and demand at Ballylumford;


•	$20 million primarily due to pass-through revenue in Jordan;


•	$11 million higher revenue in Maritza mainly driven by higher pass-through of CO₂ allowance costs, partially offset by lower capacity and availability; and


•	an increase of $6 million in Kazakhstan mainly driven by higher rates and increased capacity.

Excluding the favorable impact of foreign currency translation of $2 million, generation gross margin for the nine months ended September 30, 2013 decreased $106 million, or 27%, compared to the nine months ended September 30, 2012 primarily due to:


•	a decrease of $105 million at Cartagena as discussed above; and


•	a decrease of $47 million at Ballylumford primarily as a result of reduction in capacity remuneration as discussed above as well as unfavorable gas prices.

These decreases were partially offset by:


•	an increase of $57 million at our plants in the U.K. driven by the items discussed above, as well as lower coal prices at Kilroot partially offset by higher cost of CO₂ emissions, which were free in 2012.

Excluding the unfavorable impact of foreign currency translation, for the nine months ended September 30, 2013, revenue decreased 3%, while gross margin decreased 27% primarily due to the non-recurring favorable arbitration settlement at Cartagena.

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 September 30,						For the Nine Months Ended September 30,
	2013		2012		% Change		2013		2012		% Change
	($’s in millions)
Revenue	$	113	$	191	-41	%	$	388	$	553	-30	%
Gross Margin	$	40	$	61	-34	%	$	128	$	175	-27	%

Generation revenue for the three months ended September 30, 2013 decreased $78 million, or 41%, compared to the three months ended September 30, 2012 primarily due to:


•	lower volume of $49 million at Kelanitissa in Sri Lanka attributable to lower off-taker demand as a result of higher hydrology; and


•	lower rates of $26 million at Masinloc in the Philippines resulting from lower fuel tariff indexation due to decrease in coal prices, lower bilateral contract rates reducing previous spot exposure and lower spot prices due to higher grid availability.

Generation gross margin for the three months ended September 30, 2013 decreased $21 million, or 34%, compared to the three months ended September 30, 2012 primarily due to:


•	a decrease of $14 million at Masinloc attributable to lower margins from higher contract demand at lower rates.

Generation revenue for the nine months ended September 30, 2013 decreased $165 million, or 30%, compared to the nine months ended September 30, 2012 primarily due to:


•	lower volume of $98 million at Kelanitissa, attributable to lower off-taker demand as a result of higher hydrology;


•	lower rates of $77 million at Masinloc resulting from lower fuel tariff indexation due to decrease in coal prices, lower bilateral contract rates reducing previous spot exposure and lower spot prices due to higher grid availability; and


•	a decrease of $11 million at Masinloc due to favorable impact of mark-to-market adjustment on inflation-related embedded derivative in the nine months ended September 30, 2012.

These decreases were partially offset by:


•	higher volume of $23 million at Masinloc, due to higher contract demand.

Generation gross margin for the nine months ended September 30, 2013 decreased $47 million, or 27%, compared to the nine months ended September 30, 2012 primarily due to:


•	a decrease of $26 million largely attributable to lower margins from higher contract demand at lower rates and lower spot sales at Masinloc; and


•	a decrease of $11 million at Masinloc due to the favorable impact of mark-to-market adjustment on inflation-related embedded derivative in the nine months ended September 30, 2012.

Corporate and Other

Corporate and other includes the net operating results from our utility businesses in El Salvador, 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 September 30,							For the Nine Months Ended September 30,
	2013		2012			% Change		2013			2012			% Change
	($’s in millions)
Revenue
El Salvador Utilities	$	215	$	220		-2	%	$	649		$	639		2	%
Corporate/Other	2		2			—	%	6			7			-14	%
Total Corporate and Other	$	217	$	222		-2	%	$	655		$	646		1	%
Gross Margin
El Salvador Utilities	$	15	$	15		—	%	$	59		$	43		37	%
Corporate/Other	—		(2		)	100	%	(5		)	(7		)	29	%
Total Corporate and Other	$	15	$	13		15	%	$	54		$	36		50	%

Revenue for the three months ended September 30, 2013 decreased $5 million, or 2%, compared to the three months ended September 30, 2012, primarily due to:


•	the impact of lower pass through energy sales of $6 million in El Salvador.

Gross margin for the three months ended September 30, 2013 increased by $2 million, or 15%, compared to the three months ended September 30, 2012.

Revenue for the nine months ended September 30, 2013 increased $9 million, or 1%, compared to the nine months ended September 30, 2012, primarily due to:


•	higher rates and volume of $9 million in El Salvador mainly due to the tariff increase approved by the regulator at the beginning of 2013.

Gross margin for the nine months ended September 30, 2013 increased by $18 million, or 50%, compared to the nine months ended September 30, 2012, primarily due to:


•	higher rates and volume of $19 million in El Salvador mainly due to the tariff increase discussed above.

This increase was partially offset by:


•	higher fixed costs of $6 million in El Salvador.

General and administrative expenses

General and administrative expenses decreased $1 million, or 2%, to $63 million for the three months ended September 30, 2013 primarily due to Company restructuring efforts that resulted in decreased business development costs.

General and administrative expenses decreased $42 million, or 19%, to $183 million for the nine months ended September 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 $39 million, or 10%, to $357 million for the three months ended September 30, 2013. The decrease was primarily due to reduced debt principal and the prior year de-designation of an interest rate hedge at the Parent Company, as well as favorable foreign currency translation in Brazil.

Interest expense decreased $117 million, or 10%, to $1.1 billion for the nine months ended September 30, 2013. The decrease was primarily due to the debt principal reduction and interest-rate hedge de-designation at the Parent Company, as mentioned above, favorable foreign currency translation and lower interest rates in Brazil, as well as gains resulting from ineffectiveness on interest rate swaps in Puerto Rico that continue to qualify for hedge accounting.

Interest income

Interest income decreased $3 million, or 3%, to $85 million for the three months ended September 30, 2013. The decrease was primarily due to lower interest-bearing assets and unfavorable foreign currency translation in Brazil, as well as one-time interest payments received at DPL and Bulgaria in the prior year. The decrease was partially offset by an increase in FONINVEMEM III receivables in Argentina.

Interest income decreased $48 million, or 18%, to $213 million for the nine months ended September 30, 2013. The decrease was primarily in Brazil, due to lower interest-bearing assets, lower investment balances, lower interest rates and unfavorable foreign currency translation. The decrease was partially offset by the FONINVEMEM III receivables in Argentina as mentioned above.

Loss on extinguishment of debt

There was no loss on extinguishment of debt for the three months ended September 30, 2013. Loss on extinguishment of debt was $212 million for the nine months ended September 30, 2013. This loss was primarily related to the loss on the early retirement of recourse debt at the Parent Company and the loss on the early extinguishment of debt at Masinloc. See Note 7. — Debt included in Item 1. — Financial Statements of this Form 10-Q for further information.

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.

Gain on sale of investments

Gain on sale of investments for the three months ended September 30, 2013 was $3 million, which is primarily related to the sale of our 10% equity interest in Trinidad Generation Unlimited. Gain on sale of investments for the three months ended

September 30, 2012 was $30 million, of which $24 million related to the sale of our coal-fired and wind generation facilities in China.

Gain on sale of investments for the nine months ended September 30, 2013 was $26 million, which is primarily related to the sale of our remaining 20% interest in Cartagena as well as the sale of our investment in Trinidad, as mentioned above. Gain on sale of investments for the nine months ended September 30, 2012 was $214 million, of which $178 million related to the sale of 80% of our interest in Cartagena as well as the sale of our investments in China, as mentioned above. See Note 17. — Dispositions included in Item 1. — Financial Statements of this Form 10-Q for further information.

Goodwill impairment

Goodwill impairment expense was $58 million for the three and nine months ended September 30, 2013. Goodwill impairment expense was $1.85 billion for the three and nine months ended September 30, 2012. See Note 13 — Goodwill Impairment included in Item 1. — Financial Statements of this Form 10-Q for further information.

Asset impairment expense

Asset impairment expense was $81 million and $129 million, respectively, for the three and nine months ended September 30, 2013, and $43 million and $71 million, respectively, for the three and nine months ended September 30, 2012. See Note 14 — Asset Impairment Expense 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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	($ in millions)
Chile	$	(1	)	$	6		$	(15	)	$	9
Brazil	—			(5		)	(10		)	(11		)
Philippines	—			(25		)	(6		)	(91		)
AES Corporation	20			12			(2		)	(3		)
Argentina	16			6			13			(6		)
Other	(3		)	(1		)	4			(6		)
Total⁽¹⁾	$	32		$	(7	)	$	(16	)	$	(108	)

___________________________________________


⁽¹⁾	Includes $23 million in gains and $21 million in losses on foreign currency derivative contracts for the three months ended September 30, 2013 and 2012, respectively, and $42 million in gains and $101 million in losses on foreign currency derivative contracts for the nine months ended September 30, 2013 and 2012, respectively.

The Company recognized net foreign currency transaction gains of $32 million for the three months ended September 30, 2013 primarily due to:


•	gains of $20 million at The AES Corporation were primarily due to increases in the valuation of intercompany notes receivable denominated in foreign currency, resulting from the strengthening of the Euro and British Pound, partially offset by losses related to foreign currency derivatives; and

•

gains of $16 million in Argentina were primarily due to a gain on a foreign currency embedded derivative related to government receivables, partially offset by losses related to the 8% devaluation of the Argentine Peso, 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 accounts receivables in local currency.

The Company recognized foreign currency transaction losses of $7 million for the three months ended September 30, 2012 primarily due to:


•	losses of $25 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


•	gains of $12 million at The AES Corporation were primarily due to increases in the valuation of intercompany notes receivable denominated in foreign currency, resulting from the strengthening of the Euro and British Pound during the quarter, partially offset by losses related to foreign currency option purchases.

The Company recognized foreign currency transaction losses of $16 million for the nine months ended September 30, 2013 primarily due to:


•	losses of $15 million in Chile which were primarily due to a 5% devaluation of the Chilean Peso during the third quarter of 2013, 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 foreign currency derivatives;


•	losses of $10 million in Brazil which were mainly related to commercial liabilities denominated in the U.S. Dollar due to the 9% devaluation of the Brazilian Real versus the U.S. Dollar; and

•

gains of $13 million in Argentina which were primarily due to a gain on a foreign currency embedded derivative related to government receivables, partially offset by losses due to the 18% devaluation of the Argentine Peso which resulted 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 accounts receivables in local currency.

The Company recognized foreign currency transaction losses of $108 million for the nine months ended September 30, 2012 primarily due to:


•	losses of $91 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 $11 million in Brazil were primarily due to devaluation of the Brazilian Real of 8.3%, mainly related to commercial liabilities denominated in the U.S. Dollar.

Other non-operating expense

Total other non-operating expense was $122 million for the three and nine months ended September 30, 2013. Total other non-operating expense was $50 million for the nine months ended September 30, 2012.

See Note 15 — Other Non-Operating Expense included in Item 1. — Financial Statements of this Form 10-Q for further information.

Income tax expense

Income tax expense decreased $46 million, or 27%, to $126 million for the three months ended September 30, 2013 compared to $172 million for the three months ended September 30, 2012. The Company’s effective tax rates were 33% and (13%) for the three months ended September 30, 2013 and 2012, respectively.

The net decrease in the effective tax rate for the three months ended September 30, 2013 compared to the same period in 2012 was principally due to a 2012 nondeductible impairment of goodwill at one of our U.S. subsidiaries offset by the impact of impairments recorded in the current period. See Note 13—Goodwill Impairment and Note 14—Asset Impairment Expense.

Income tax expense decreased $229 million, or 45%, to $285 million for the nine months ended September 30, 2013 compared to $514 million for the nine months ended September 30, 2012. The Company’s effective tax rates were 26% and (167%) for the nine months ended September 30, 2013 and 2012, respectively.

The net decrease in the effective tax rate for the nine months ended September 30, 2013 compared to the same period in 2012 was principally due to a 2012 nondeductible impairment of goodwill at one of our U.S. subsidiaries, and 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 $10 million, or 40%, to $15 million for the three months ended September 30, 2013. The decrease was primarily due to the sale of Yangcheng in China in the third quarter of 2012 as well as decreased earnings at Entek in Turkey resulting from a loss on an embedded foreign currency derivative.

Net equity in earnings of affiliates decreased $28 million, or 57%, to $21 million for the nine months ended September 30, 2013. The decrease was primarily related to the sale of Yangcheng in China in the third quarter of 2012 as well as decreased earnings at Entek in Turkey resulting from a loss on an embedded foreign currency derivative. This was partially offset by higher generation profits at Guacolda.

Income from continuing operations attributable to noncontrolling interests

Income from continuing operations attributable to noncontrolling interests decreased $9 million, or 6%, to $146 million for the three months ended September 30, 2013. The decrease was primarily due to lower operating income at Tietê and Panama related to lower water inflows in the system resulting in a higher allocation of energy purchases at higher spot prices, as well as an impairment at our Poland wind projects. This was partially offset by increased earnings at Eletropaulo due to a higher tariff as a result of the annual tariff readjustment in July 2013 and lower fixed costs.

Income from continuing operations attributable to noncontrolling interests increased $33 million, or 8%, to $431 million for the nine months ended September 30, 2013. The increase was primarily due to higher tariffs at Eletropaulo resulting from the 2012 tariff reset provision and the annual tariff readjustment in July 2013 along with lower fixed costs. This was partially offset by lower operating income at Tietê 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 loss of $52 million and net income of $28 million for the three months ended September 30, 2013 and 2012, respectively. Total discontinued operations was a net loss of $86 million and net income of $93 million for the nine months ended September 30, 2013 and 2012, respectively. See Note 16 — 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

DP&L — In 2012, DP&L filed an Electric Security Plan (“ESP”) with the Public Utility Commission of Ohio (“PUCO”) to establish Standard Service Offer (“SSO”) rates that were to be in effect starting January 2013. SSO rates apply to customers that take both generation and distribution electric services from DP&L, but certain charges are non-bypassable and apply to all DP&L retail customers. An order was issued by the PUCO on September 4 and a corrected order was issued September 6, 2013(the “ESP Order”), which states that DP&L’s next ESP begins January 2014 and extends through May 31, 2017. DP&L’s current rate structure remains in place until January 1. The primary provisions of the ESP Order are as follows:

•

DP&L may collect a non-bypassable Service Stability Rider (“SSR”) equal to $110 million per year for 2014 through 2016. DP&L has the opportunity to seek an additional $46 million through a five-month extension of the SSR, provided it meets certain regulatory filing obligations. Such obligations include, but are not limited to: (a) filing a divestiture plan with the PUCO by December 31, 2013 to separate DP&L’s generation assets from the utility, and (b) filing a distribution rate case no later than July 1, 2014;


•	DP&L must divest its generation assets no later than May 31, 2017;


•	DP&L’s significantly excessive earnings test threshold was set at a 12% return on equity. Earnings in excess of this threshold are subject to refund to customers;


•	DP&L must phase-in a competitive bidding structure with 10% of DP&L’s SSO load sourced through the competitive bid starting in January 2014, 40% in 2015, 70% in 2016 and 100% by June 2017;


•	the ESP Order approved DP&L’s rate proposal to bifurcate its transmission charges into a non-bypassable component and a bypassable component; and


•	the ESP Order requires DP&L to establish a $2 million per year shareholder-funded economic development fund.

DP&L and others filed applications for rehearing on October 4, 2013. On October 23, 2013, the PUCO issued an entry on rehearing denying applications for rehearing related to the competitive bid. The Commission reaffirmed its position that economic development load should be included in the competitive bid auction and that DP&L affiliates are permitted to bid in the auction.

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 had 2013 debt maturities of approximately $470 million that were due in October. The debt refinancing was completed in September 2013 with $470 million paid on October 1, 2013. Any of the above-referenced conditions, events or factors could have a material impact on the Company or its results of operations.

Eletropaulo — As discussed in Item 1. — Business — Brazil SBU Businesses — Electricity Regulation included in the 2012 Form 10-K, Eletropaulo has ongoing discussions with the regulator in the administrative level regarding the parameters of the tariff reset applied in July 2012, retroactive to July 2011. The main discussions involve the shielded regulatory asset base and whether adjustments should be made to it, the amount of investments made by the Company that were not included in the tariff and the benchmark used for regulatory losses. The Company continues to monitor the situation.

Operational

Sensitivity to Dry Hydrological Conditions

Our hydroelectric generation facilities are sensitive to changes in the weather, particularly the level of water inflows into generation facilities. This year Brazil, Panama, Colombia and Chile have experienced lower than expected rainfall, while Chile also recorded lower snowpack relative to historical levels. Through early October 2013, water inflows have been approximately 24% to 31% below historical levels across these markets. Low rainfall and water inflows have caused reservoir levels to be below historical levels, reduced generation output, and increased prices for electricity. If our hydroelectric generation facilities cannot generate sufficient energy to meet contractual arrangements, we may need to purchase energy to fulfill our obligations, which could have a material adverse impact on our results of operations. We expect hydrological volatility to continue for the remainder of the year and are monitoring the weather patterns for potential impacts to results in 2014.

In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels and manages an Energy Reallocation Mechanism to share hydrological risk across all generators. The Energy Reallocation Mechanism helps to manage our exposure to spot market prices in below-average hydrology scenarios. We expect the system operator in Brazil to pursue a more conservative reservoir management strategy going forward, including the dispatch of 9.5 GW of thermal generation capacity, which could result in electricity prices higher than historical levels.

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.

Argentina — In Argentina, the deterioration of certain economic indicators such as non-receding inflation, increased government deficits and foreign currency accessibility combined with the gradual 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. Many of these economic conditions in conjunction with the restrictions to freely access the foreign exchange currency established by the Argentine Government since 2012, have contributed to the development of a limited parallel unofficial foreign exchange market that is less favorable than the official exchange. At September 30, 2013, all transactions at our businesses in Argentina were translated using the official exchange

rate published by the Argentine Central Bank. 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 September 30, 2013, Maritza had an outstanding receivables balance of $135 million with the offtaker, which represents 133 days sales outstanding. 91% of these receivables are overdue by less than 90 days. Although Maritza continued to collect past due receivables during the third 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 $1.7 billion and net equity of $643 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 political situation in the country remains unstable with daily street protests against the new government and difficulties to conduct normal debates in the Parliament. 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 and regulatory changes 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. During the fourth quarter of 2013, NEK requested a consent from Maritza for a restructuring and Maritza is currently evaluating the request. 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 Silver Ridge Power (formerly known as AES Solar Holding Company) attributable to AES Solar Energy Ltd., whose primary operations are in Europe, was $127 million at September 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 — 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%. The Company monitors its reporting units for the risk of step 1 failure on an ongoing basis. Such evaluations continued for goodwill at Ebute during the first half of 2013. During the three months ended September 30, 2013, the Company performed an interim impairment test of goodwill at Ebute and recognized the entire balance of $58 million as goodwill impairment expense. See Note 13 — Goodwill Impairment included in Item 1. — Financial Statements of this Form 10-Q for further information. For DPL, the Company continued to monitor the developments in business environment and the pending ESP case with the PUCO. During September 2013, the PUCO issued an order for DPL's ESP and it was determined that there were no impairment indicators during the three months ended September 30, 2013 related to goodwill at DPL. It is possible that we may incur goodwill impairment at DPL, 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 as of September 30, 2013 was approximately $759 million. In 2012, the Company had recognized goodwill impairment of $1.85 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 2. - Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Environmental in the Company's Form 10-Q for the fiscal quarter ended June 30, 2013, the President of the United States directed the EPA to issue a new proposed rule establishing New Source Performance Standards for CO₂ emissions for newly constructed fossil-fueled electric utility steam generating units (EUSGUs) larger than 25 MW by September 30, 2013, and to issue a final rule in a timely fashion after considering all public comments. On September 20, 2013, the EPA issued such new proposed rule. Such proposed rules set separate standards for natural gas-fired and coal-fired units, which standards are measured in pounds of CO₂ per MW/h. The proposed rule does not cover other GHGs, nor does it apply to existing EUSGUs, including the Company's subsidiaries' existing power plants. The EPA is currently accepting comments on this proposed rule.

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 1. — Business — Regulatory Matters — United States — Other United States Environmental and Land Use 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 expenditures that IPL estimates are necessary

through 2016 for environmental controls for its baseload generating units related to the Mercury and Air Toxics Standards (MATS) rule, excluding demolition costs. On August 14, 2013, the Indiana Utility Regulatory Commission (IURC) approved IPL’s MATS plan, which includes investing up to $511 million in the installation of new pollution control equipment on IPL’s five largest base load generating units. These coal-fired units are located at IPL’s Petersburg and Harding Street generating stations. The IURC also approved IPL’s request to recover operating and construction costs for this equipment (including a return) through a rate adjustment mechanism, with certain stipulations. As part of the Order, the IURC stipulated that if the Harding Street unit is retired before IPL has fully depreciated the new controls (which have a 20-year depreciable life), IPL shall not continue to collect depreciation expense on the clean energy projects included in the MATS Order for that unit. Management is currently evaluating the impact of this recent Order.

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, a consortium of industry petitioners challenged the EPA’s Endangerment Finding, Tailoring Rule and the Motor Vehicle Rule in the United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”), and the D.C. Circuit rejected the appeal. On October 15, 2013, the U.S. Supreme Court granted the industry petitioners petition for certiorari and will consider the limited question of “[w]hether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases. If the Supreme Court were to conclude that EPA’s regulation of mobile sources under Section 202 does not subject stationary sources to review and permitting under the prevention of significant deterioration (“PSD”) provisions and Title V of the Clean Air Act, it would eliminate the risk that the Company’s power plants might trigger PSD review for CO2 emissions as a result of projects undertaken during outages to repair, replace or maintain components of a unit.

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 September 30, 2013, AES Gener has spent approximately $138 million, and the remaining $192 million will be invested between the remainder of 2013 and 2016 in order to comply within the required time frame.

Capital Resources and Liquidity

Overview

As of September 30, 2013, the Company had unrestricted cash and cash equivalents of $2.0 billion, of which approximately $196 million was held at the Parent Company and qualified holding companies, and approximately $898 million was held in short term investments primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $1.1 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 $2.4 billion of our current non-recourse debt, $1.4 billion was presented as such because it is due in the next twelve months and $1.0 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/or 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 September 30, 2013, approximately $4.0 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 September 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 $654 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 September 30, 2013, we had $3 million in letters of credit outstanding, provided under our senior secured credit facility, and $192 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 September 30, 2013, the Company paid letter of credit fees ranging from 0.2% to 2.5% 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 September 30, 2013, the Company had approximately $344 million and $26 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 September 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 nine months ended September 30, 2013, cash and cash equivalents increased $122 million to $2.0 billion. The increase in cash and cash equivalents was due to $2.0 billion of cash provided by operating activities, $1.3 billion of cash used in investing activities, $635 million of cash used in financing activities, an unfavorable effect of foreign currency exchange rates on cash of $37 million and a $21 million decrease in cash of discontinued and held-for-sale businesses.

Operating Activities — Net cash provided by operating activities decreased $89 million to $2.0 billion during the nine months ended September 30, 2013 compared to $2.1 billion during the nine months ended September 30, 2012.

Operating cash flow for the nine months ended September 30, 2013 resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization, gain from sale of investments and impairment expense and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $255 million in operating assets and liabilities. This was primarily due to the following:


•	a decrease of $578 million in accounts payable and other current liabilities primarily at Eletropaulo and Sul due to lower costs and a decrease in regulatory liabilities as well as at Uruguaiana primarily related to the extinguishment of a liability based on a favorable arbitration decision;


•	an increase of $149 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo and Sul, resulting from higher priced energy purchases which are recoverable through future tariffs; partially offset by


•	a decrease of $403 million in prepaid expenses and other current assets primarily due to a decrease in current regulatory assets, for the recovery of prior-period tariff cycle energy purchases and transportation costs at Eletropaulo and Sul; and


•	a decrease of $135 million in accounts receivable primarily related to lower tariffs in 2013 at Eletropaulo combined with lower tariffs and reduced consumption at Sul, partially offset by lower collections at Maritza.

Net cash provided by operating activities was $2.1 billion during the nine months ended September 30, 2012. Operating cash flow for the nine months ended September 30, 2012 resulted primarily from net income adjusted for non-cash items, principally depreciation and amortization, contingencies, deferred income taxes, gains and losses on sales and disposals and impairment charges, partially offset by a net use of cash for operating activities of $63 million for operating assets and liabilities. This was primarily due to:


•	an increase of $379 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo, resulting from higher priced energy purchases, regulatory charges and transmission costs which are recoverable through future tariffs and the establishment of a long-term note receivable at Cartagena in Spain following the arbitration settlement;


•	an increase of $191 million in accounts receivable primarily driven by lower collection rates at Maritza, Sonel, Kelanitissa and Eletropaulo;


•	a decrease of $151 million in net income tax and other tax payables primarily for the payment of income taxes in excess of the accrual of new tax liabilities; partially offset by


•	an increase of $303 million in accounts payable and other current liabilities primarily at Eletropaulo due to an increase in current regulatory liabilities driven by the tariff reset, offset by a decrease in other current liabilities arising from value-added tax payables;


•	an increase of $275 million in other liabilities primarily explained by an increase in noncurrent regulatory liabilities at Eletropaulo related to the tariff reset; and


•	a decrease of $90 million in prepaid expenses and other current assets mainly due to amortization of prepaid property taxes at DPL and recovery of value-added tax on a construction project in Chile.

This net decrease of cash flows from operating activities of $89 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 was primarily the result of the following:


•	US — an increase of $43 million primarily driven by the $60 million proceeds from the PPA termination at Beaver Valley in January 2013.


•	Andes — a decrease of $156 million at our generation businesses primarily due to higher working capital requirements.


•	MCAC — an increase of $38 million primarily due to lower working capital requirements.

Investing Activities — Net cash used in investing activities was $1.3 billion during the nine months ended September 30, 2013. This was primarily attributable to capital expenditures of $1.3 billion consisting of $690 million of growth capital expenditures and $640 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Eletropaulo of $188 million, Gener of $166 million, Jordan of $95 million, Sul of $57 million, DPL of $28 million, Mong Duong of $27 million, Yelvertoft of $20 million, Kribi of $17 million and Altai of $16 million. Maintenance and environmental capital expenditures included amounts at IPL of $164 million, Eletropaulo of $103 million, DPL of $63 million, Gener of $61 million, Tietê of $53 million, Sul of $50 million, Altai of $21 million and Itabo of $15 million. Purchase of short-term investments, net of sales of $263 million included amounts at Eletropaulo of $212 million, Sul of $32 million and Tietê of $29 million. These uses of cash were partially offset by proceeds from the sale of businesses, net of cash sold of $167 million including $113 million for the sale of the Ukraine businesses, $31 million for the sale of our 10% equity interest in Trinidad and $24 million for the sale of our remaining interest in Cartagena.

Net cash used in investing activities was $676 million during the nine months ended September 30, 2012. This was primarily attributable to capital expenditures of $1.6 billion consisting of $864 million of growth capital expenditures and $717 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Gener of $219 million, Eletropaulo of $164 million, Sul of $91 million, Mong Duong of $76 million, DPL of $59 million, Kribi of $49 million, Maritza of $28 million and Drone Hill of $20 million. Maintenance and environmental capital expenditures included amounts at Eletropaulo of $141 million, DPL of $95 million, IPL of $86 million, Gener of $70 million, Sul of $66 million, Panama of $63 million, Tietê of $32 million and Altai of $19 million. These uses of cash were partially offset by sales of short-term investments, net of purchases of $352 million which included amounts at Eletropaulo of $148 million, Brasiliana Energia of $113 million, Gener of $98 million and Sul of $21 million, partially offset by purchases of $14 million at Andres. Proceeds from the sale of businesses, net of cash sold of $432 million included amounts at Red Oak of $144 million, the China equity method investments of $90 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 $120 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 $591 million to $1.3 billion during the nine months ended September 30, 2013 compared to net cash used in investing activities of $676 million during the nine months ended September 30, 2012. This net increase was primarily due to an increase in purchases of short-term investments, net of sales of $615 million and a decrease in proceeds from the sale of businesses, net of cash sold of $265 million, partially offset by a decrease in capital expenditures of $251 million.

Financing Activities — Net cash used in financing activities was $635 million during the nine months ended September 30, 2013. Repayments of recourse and non-recourse debt of $3.5 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 $93 million, Puerto Rico of $65 million, Maritza of $57 million, Sonel of $46 million and Sul of $40 million. Payments for financed capital expenditures were $436 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 $385 million included amounts at Tietê of $154 million, Brasiliana of $96 million, Gener of $39 million and Buffalo Gap of $19 million. Payments for financing fees of $148 million included amounts at Cochrane of $42 million, Eletropaulo of $25 million, Mong Duong of $20 million and the Parent Company of $17 million. This was partially offset by issuances of recourse and non-recourse debt of $3.8 billion including amounts at the Parent Company for $750 million, DPL of $645 million, Masinloc of $500 million, Tietê of $496 million, Mong Duong of $339 million, El Salvador of $310 million, IPL of $170 million, Sul of $150 million, Jordan of $138 million, Cochrane of $120 million, Warrior Run of $74 million and Kribi of $63 million as well as contributions from noncontrolling interests of $157 million including amounts at Mong Duong of $55 million, Alto Maipo of $50 million and Cochrane of $34 million.

Net cash used in financing activities was $1.3 billion during the nine months ended September 30, 2012. Repayments of recourse and non-recourse debt of $767 million included amounts at Kribi of $181 million, Eletropaulo of $126 million, Maritza of $47 million, Sonel of $46 million, Kilroot of $40 million, Masinloc of $40 million, Puerto Rico of $35 million, Bulgaria Wind of $28 million, Warrior Run of $26 million and Southland of $25 million. Distributions to noncontrolling interests of $741 million included amounts at Brasiliana of $227 million, Eletropaulo of $203 million, Tietê of $191 million and Gener of $72 million. Net repayments under the revolving credit facilities of $322 million included amounts at the Parent Company of $295 million and Alicura of $33 million. The purchase of treasury stock at the Parent Company was $301 million. This was partially offset by issuances of non-recourse debt of $822 million including amounts at Eletropaulo of $339 million, Kribi of $245 million, Mong Duong of $71 million, Alicura of $35 million, our European wind projects of $28 million and Panama of $25 million.

Net cash used in financing activities decreased $708 million to $635 million during the nine months ended September 30, 2013 compared to net cash used in financing activities of $1.3 billion during the nine months ended September 30, 2012. This net decrease was primarily due to an increase in the issuance of recourse and non-recourse debt of $3.0 billion, decreases in distributions to noncontrolling interests of $356 million, net repayments under revolving credit facilities of $300 million, purchase of treasury stock of $238 million and an increase in contributions from noncontrolling interests of $145 million. This was partially offset by an increase in the repayments of recourse and non-recourse debt of $2.7 billion, payments for financed capital expenditures of $406 million and payments for financings fees of $124 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 September 30, 2013 and December 31, 2012 as follows:



Parent Company Liquidity	September 30, 2013			December 31, 2012
	(in millions)
Consolidated cash and cash equivalents	$	2,031		$	1,909
Less: Cash and cash equivalents at subsidiaries	1,835			1,598
Parent and qualified holding companies’ cash and cash equivalents	196			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	$	993		$	1,106

The Company paid a dividend of $0.04 per share to its common stockholders during the three months ended September 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 September 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 $2.4 billion. The portion of current debt related to such defaults was $1.0 billion at September 30, 2013, all of which was non-recourse debt related to two subsidiaries — Maritza and Kavarna. In addition, discontinued operations at Sonel and Kribi had debt in default of $255 million and $256 million, respectively; and discontinued operations at Saurashtra had debt of $21 million that is classified as current because a covenant violation is probable within the next twelve months.

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 September 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 nine months ended September 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 our 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 oil and less than $5 million for either coal or natural gas. Our estimates exclude correlation of oil with coal or natural gas. 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. 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.

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 driven by the cost of thermal generation.

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.

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, 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 over a twelve-month forward-looking period are stemming from the following currencies: Argentine Peso, Brazilian Real, Colombian Peso, and Euro determined based on historic volatility over the preceding twelve-month period. As of September 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, Colombian Peso, and Euro relative to the U.S. Dollar are projected to be reduced by approximately $5 million, $5 million, less than $5 million, and less than $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 September 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, Kazakhstani Tenge, and U.S. Dollar denominated debt would be approximately $5 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 September 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 September 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 ($611 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 ($576 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 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. That challenge is pending. The arbitral Tribunal temporarily suspended the next phase of the arbitration on damages issues, but the Tribunal subsequently lifted that suspension. The Tribunal will establish the schedule for the damages phase of the arbitration in the near future. 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 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 ($324 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 ($443 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 Bernardo 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 February 2011, a consumer protection group, S.O.S. Consumidores (“SOSC”), filed a lawsuit in the State of São Paulo Federal Court against Eletropaulo and all other distribution companies in the State of São 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 ($379 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 May 2011, a putative class action was filed in the Mississippi federal court against the Company and numerous unrelated companies. The lawsuit alleges that greenhouse gas emissions contributed to alleged global warming which, in turn, allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert claims for public and private nuisance, trespass, negligence, and declaratory judgment. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. These and other plaintiffs previously brought a substantially similar lawsuit in the federal court but failed to obtain relief. In October 2011, the Company and other defendants filed motions to dismiss the lawsuit. In March 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 plaintiffs did not seek further review and therefore the litigation has ended.

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 ($531 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 ($930 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 April 2013, the East Kazakhstan Ecology Department (“ED”) issued an order directing AES Ust-Kamenogorsk CHP ("UK CHP") to pay approximately KZT 720 million ($4.6 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. That ruling was upheld on appeal. The ED also has a lawsuit in the Economic Court that is 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
7/1/2013 - 7/31/13	3,738,142	11.91		3,738,142	$	237,465,694
8/1/2013 - 8/31/13	—	—		—	237,465,694
9/1/2013 - 9/30/13	—	—		—	237,465,694
Total	3,738,142	$	11.91	3,738,142

_____________________________


⁽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

On October 7, 2013, the Company filed a Form 8-K with the SEC disclosing that Charles L. Harrington had been appointed to the Board of Directors effective November 1, 2013. The Board subsequently determined that the effective date for Mr. Harrington’s appointment will be December 1, 2013.

ITEM 6. EXHIBITS




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:	November 6, 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)