Edgar Filing: AES CORP

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

Q2 2015 Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

______________________________________________________________________________________________

FORM 10-Q

(Mark One)



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

For the Quarterly Period Ended June 30, 2015



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

Commission file number 1-12291

THE AES CORPORATION

(Exact name of registrant as specified in its charter)



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

(703) 522-1315

Registrant’s telephone number, including area code:

______________________________________________________________________________________________

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

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

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

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

______________________________________________________________________________________________

The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, on August 5, 2015 was 682,826,854

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2015

TABLE OF CONTENTS



Glossary of Terms		1

PART I: FINANCIAL INFORMATION		2

ITEM 1.	FINANCIAL STATEMENTS	2
	Condensed Consolidated Balance Sheets	2
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Comprehensive Income (Loss)	4
	Condensed Consolidated Statements of Cash Flows	5
	Notes to Condensed Consolidated Financial Statements	6

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	24

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	56

ITEM 4.	CONTROLS AND PROCEDURES	58

PART II: OTHER INFORMATION		59

ITEM 1.	LEGAL PROCEEDINGS	59

ITEM 1A.	RISK FACTORS	63

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	63

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	63

ITEM 4.	MINE SAFETY DISCLOSURES	63

ITEM 5.	OTHER INFORMATION	63

ITEM 6.	EXHIBITS	63

SIGNATURES		64

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:



Adjusted EPS	Adjusted Earnings Per Share, a non-GAAP measure
Adjusted PTC	Adjusted Pretax Contribution, a non-GAAP measure of operating performance
AES	The Parent Company and its subsidiaries and affiliates
AFS	Available For Sale
AFUDC	Allowance for Funds Used During Construction
ANEEL	Brazilian National Electric Energy Agency
AOCL	Accumulated Other Comprehensive Loss
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
BNDES	Brazilian Development Bank
CA	Commercial Availability
CAA	United States Clean Air Act
CAMMESA	Wholesale Electric Market Administrator in Argentina
CCR	Coal Combustion Residuals
CDPQ	La Caisse de depot et placement du Quebec
CEEE	Companhia Estadual de Energia
CESCO	Central Electricity Supply Company of Orissa Ltd.
CFE	Federal Commission of Electricity
CO₂	Carbon Dioxide
COSO	Committee of Sponsoring Organizations of the Treadway Commission
CPCN	Certificate of Public Convenience and Necessity
DP&L	The Dayton Power & Light Company
DPL	DPL Inc.
DPLER	DPL Energy Resources, Inc.
EPA	United States Environmental Protection Agency
EPC	Engineering, Procurement, and Construction
ERC	Energy Regulatory Commission
EURIBOR	Euro Interbank Offered Rate
FASB	Financial Accounting Standards Board
FCA	Federal Court of Appeals
FX	Foreign Exchange
GAAP	Generally Accepted Accounting Principles in the United States
GHG	Greenhouse Gas
GSA	Gas Supply Agreement
GWh	Gigawatt Hours
HTA	Heads of Terms Agreement
ICC	International Chamber of Commerce
IPALCO	IPALCO Enterprises, Inc.
IPL	Indianapolis Power & Light Company
IURC	Indiana Utility Regulatory Commission
KPI	Key Performance Indicator
kWh	Kilowatt Hours
LIBOR	London Interbank Offered Rate
LNG	Liquefied Natural Gas
MATS	Mercury and Air Toxics Standards
MRE	Energy Reallocation Mechanism
MW	Megawatts
MWh	Megawatt Hours
NEK	Natsionalna Elektricheska Kompania (state-owned electricity public supplier in Bulgaria)
NOV	Notice of Violation
NO_X	Nitrogen Dioxide
NPDES	National Pollutant Discharge Elimination System
OCI	Other Comprehensive Income
O&M	Operations and Maintenance
OPGC	Odisha Power Generation Corporation
Parent Company	The AES Corporation
PIS	Partially Integrated System
PM	Particulate Matter
PPA	Power Purchase Agreement
PREPA	Puerto Rico Electric Power Authority
RSU	Restricted Stock Unit
SAIDI	System Average Interruption Duration Index
SAIFI	System Average Interruption Frequency Index
SBU	Strategic Business Unit
SEC	United States Securities and Exchange Commission
SO₂	Sulfur Dioxide
SSR	Service Stability Rider
TA	Transportation Agreement
VAT	Value-added tax
VIE	Variable Interest Entity

PART I: FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

THE AES CORPORATION

Condensed Consolidated Balance Sheets

(Unaudited)



	June 30, 2015			December 31, 2014
	(in millions, except share and per share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,022		$	1,539
Restricted cash	308			283
Short-term investments	439			709
Accounts receivable, net of allowance for doubtful accounts of $94 and $96, respectively	2,877			2,709
Inventory	734			702
Deferred income taxes	213			275
Prepaid expenses	115			175
Other current assets	1,799			1,434
Current assets of held-for-sale businesses	8			—
Total current assets	7,515			7,826
NONCURRENT ASSETS
Property, Plant and Equipment:
Land	801			870
Electric generation, distribution assets and other	30,136			30,459
Accumulated depreciation	(9,996		)	(9,962		)
Construction in progress	2,499			3,784
Property, plant and equipment, net	23,440			25,151
Other Assets:
Investments in and advances to affiliates	562			537
Debt service reserves and other deposits	403			411
Goodwill	1,473			1,458
Other intangible assets, net of accumulated amortization of $130 and $158, respectively	241			281
Deferred income taxes	571			662
Service concession assets	1,538			—
Other noncurrent assets	2,691			2,640
Noncurrent assets of held-for-sale businesses	150			—
Total other assets	7,629			5,989
TOTAL ASSETS	$	38,584		$	38,966
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	1,994		$	2,278
Accrued interest	244			260
Accrued and other liabilities	2,317			2,326
Non-recourse debt, including $220 and $240, respectively, related to variable interest entities	1,999			1,982
Recourse debt	—			151
Current liabilities of held-for-sale businesses	9			—
Total current liabilities	6,563			6,997
NONCURRENT LIABILITIES
Non-recourse debt, including $1,058 and $1,030, respectively, related to variable interest entities	13,750			13,618
Recourse debt	5,014			5,107
Deferred income taxes	1,281			1,277
Pension and other post-retirement liabilities	1,183			1,342
Other noncurrent liabilities	3,110			3,222
Noncurrent liabilities of held-for-sale businesses	61			—
Total noncurrent liabilities	24,399			24,566
Contingencies and Commitments (see Note 9)
Redeemable stock of subsidiaries	538			78
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 815,558,389 issued and 682,607,128 outstanding at June 30, 2015 and 814,539,146 issued and 703,851,297 outstanding at December 31, 2014)	8			8
Additional paid-in capital	8,705			8,409
Retained earnings	258			512
Accumulated other comprehensive loss	(3,445		)	(3,286		)
Treasury stock, at cost (132,951,261 shares at June 30, 2015 and 110,687,849 shares at December 31, 2014)	(1,662		)	(1,371		)
Total AES Corporation stockholders’ equity	3,864			4,272
NONCONTROLLING INTERESTS	3,220			3,053
Total equity	7,084			7,325
TOTAL LIABILITIES AND EQUITY	$	38,584		$	38,966

See Notes to Condensed Consolidated Financial Statements.

THE AES CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions, except per share amounts)
Revenue:
Regulated	$	2,008		$	2,116		$	4,088		$	4,258
Non-Regulated	1,850			2,195			3,754			4,315
Total revenue	3,858			4,311			7,842			8,573
Cost of Sales:
Regulated	(1,634		)	(1,844		)	(3,441		)	(3,776		)
Non-Regulated	(1,470		)	(1,648		)	(2,926		)	(3,184		)
Total cost of sales	(3,104		)	(3,492		)	(6,367		)	(6,960		)
Operating margin	754			819			1,475			1,613
General and administrative expenses	(50		)	(52		)	(105		)	(103		)
Interest expense	(310		)	(323		)	(673		)	(696		)
Interest income	133			73			223			136
Loss on extinguishment of debt	(122		)	(15		)	(145		)	(149		)
Other expense	(14		)	(17		)	(34		)	(25		)
Other income	15			33			31			45
Goodwill impairment expense	—			—			—			(154		)
Asset impairment expense	(37		)	(63		)	(45		)	(75		)
Foreign currency transaction gains (losses)	15			7			(8		)	(12		)
Other non-operating expense	—			(44		)	—			(44		)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES	384			418			719			536
Income tax expense	(120		)	(157		)	(216		)	(211		)
Net equity in earnings of affiliates	—			20			15			45
INCOME FROM CONTINUING OPERATIONS	264			281			518			370
Income from operations of discontinued businesses, net of income tax expense of $0, $8, $0 and $22, respectively	—			7			—			27
Net loss from disposal and impairments of discontinued businesses, net of income tax expense (benefit) of $0, $5, $0 and $4, respectively	—			(13		)	—			(56		)
NET INCOME	264			275			518			341
Noncontrolling interests:
Less: (Income) from continuing operations attributable to noncontrolling interests	(195		)	(139		)	(307		)	(275		)
Less: (Income) loss from discontinued operations attributable to noncontrolling interests	—			(3		)	—			9
Total net income attributable to noncontrolling interests	(195		)	(142		)	(307		)	(266		)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	69		$	133		$	211		$	75
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	69		$	142		$	211		$	95
Loss from discontinued operations, net of tax	—			(9		)	—			(20		)
Net income	$	69		$	133		$	211		$	75
BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.10		$	0.20		$	0.30		$	0.13
Loss from discontinued operations attributable to The AES Corporation common stockholders, net of tax	—			(0.02		)	—			(0.03		)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.10		$	0.18		$	0.30		$	0.10
DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.10		$	0.20		$	0.30		$	0.13
Loss from discontinued operations attributable to The AES Corporation common stockholders, net of tax	—			(0.02		)	—			(0.03		)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.10		$	0.18		$	0.30		$	0.10
DILUTED SHARES OUTSTANDING	695			728			701			728
DIVIDENDS DECLARED PER COMMON SHARE	$	0.10		$	0.05		$	0.10		$	0.05

See Notes to Condensed Consolidated Financial Statements.

THE AES CORPORATION

Condensed Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
NET INCOME	$	264		$	275		$	518		$	341
Foreign currency translation activity:
Foreign currency translation adjustments, net of income tax (expense) benefit of $0, $(7), $0 and $(8), respectively	77			24			(344		)	29
Reclassification to earnings, net of income tax (expense) benefit of $0 for all periods	—			(53		)	—			(47		)
Total foreign currency translation adjustments	77			(29		)	(344		)	(18		)
Derivative activity:
Change in derivative fair value, net of income tax (expense) benefit of $(20), $22, $(3) and $46, respectively	82			(105		)	10			(225		)
Reclassification to earnings, net of income tax (expense) benefit of $(1), $(10), $(3) and $(13), respectively	7			13			19			32
Total change in fair value of derivatives	89			(92		)	29			(193		)
Pension activity:
Change in pension adjustments due to prior service cost, net of income tax (expense) benefit of $0, $(1), $0, and $(1), respectively	—			1			—			1
Change in pension adjustments due to disposal of discontinued operations for the period, net of income tax (expense) benefit of $0, $(9), $0 and $(9), respectively	—			14			—			14
Reclassification to earnings due to amortization of net actuarial loss, net of income tax (expense) benefit of $(2), $2, $(5) and $(1), respectively	4			10			9			16
Total pension adjustments	4			25			9			31
OTHER COMPREHENSIVE INCOME (LOSS)	170			(96		)	(306		)	(180		)
COMPREHENSIVE INCOME	434			179			212			161
Less: Comprehensive (income) attributable to noncontrolling interests	(261		)	(102		)	(173		)	(227		)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	$	173		$	77		$	39		$	(66	)

See Notes to Condensed Consolidated Financial Statements.

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)



	Six Months Ended June 30,
	2015			2014
	(in millions)
OPERATING ACTIVITIES:
Net income	$	518		$	341
Adjustments to net income:
Depreciation and amortization	597			625
Impairment expenses	45			273
Deferred income taxes	17			52
Releases of contingencies	(134		)	(48		)
Loss on the extinguishment of debt	145			149
Loss on sale of assets	12			8
Loss on disposals and impairments — discontinued operations	—			51
Other	70			45
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable	(444		)	(312		)
(Increase) decrease in inventory	(54		)	(39		)
(Increase) decrease in prepaid expenses and other current assets	132			(72		)
(Increase) decrease in other assets	(815		)	(316		)
Increase (decrease) in accounts payable and other current liabilities	179			(194		)
Increase (decrease) in income tax payables, net and other tax payables	(131		)	(176		)
Increase (decrease) in other liabilities	453			66
Net cash provided by operating activities	590			453
INVESTING ACTIVITIES:
Capital expenditures	(1,168		)	(908		)
Acquisitions, net of cash acquired	(18		)	(728		)
Proceeds from the sale of businesses, net of cash sold	2			890
Proceeds from the sale of assets	1			16
Sale of short-term investments	2,460			2,198
Purchase of short-term investments	(2,270		)	(1,925		)
(Increase) decrease in restricted cash, debt service reserves and other assets	(51		)	127
Other investing	(26		)	(61		)
Net cash used in investing activities	(1,070		)	(391		)
FINANCING ACTIVITIES:
Borrowings under the revolving credit facilities	361			737
Issuance of recourse debt	575			1,525
Issuance of non-recourse debt	1,940			1,710
Repayments under the revolving credit facilities	(359		)	(607		)
Repayments of recourse debt	(915		)	(1,663		)
Repayments of non-recourse debt	(1,457		)	(1,349		)
Payments for financing fees	(40		)	(105		)
Distributions to noncontrolling interests	(113		)	(197		)
Contributions from noncontrolling interests	97			110
Proceeds from the sale of redeemable stock of subsidiaries	461			—
Dividends paid on AES common stock	(141		)	(72		)
Payments for financed capital expenditures	(84		)	(312		)
Purchase of treasury stock	(307		)	(32		)
Other financing	(29		)	5
Net cash used in financing activities	(11		)	(250		)
Effect of exchange rate changes on cash	(19		)	(14		)
(Decrease) increase in cash of discontinued and held-for-sale businesses	(7		)	75
Total decrease in cash and cash equivalents	(517		)	(127		)
Cash and cash equivalents, beginning	1,539			1,642
Cash and cash equivalents, ending	$	1,022		$	1,515
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	665		$	676
Cash payments for income taxes, net of refunds	$	247		$	332
SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
Assets received upon sale of subsidiaries	$	—		$	44
Assets acquired through capital lease	$	10		$	13

See Notes to Condensed Consolidated Financial Statements.

THE AES CORPORATION

Notes to Condensed Consolidated Financial Statements

For the Three and Six Months Ended June 30, 2015 and 2014

1. FINANCIAL STATEMENT PRESENTATION

Consolidation

In this Quarterly Report the terms “AES,” “the Company,” “us” or “we” refer to the consolidated entity including its subsidiaries and affiliates. The terms “The AES Corporation,” “the Parent” or “the Parent Company” refer only to the publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates. Furthermore, 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 GAAP, as contained in the FASB ASC, for interim financial information and Article 10 of Regulation S-X issued by the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for annual fiscal reporting periods. In the opinion of management, the interim financial information includes all adjustments of a normal recurring nature necessary for a fair presentation of the results of operations, financial position, comprehensive income and cash flows. The results of operations for the three and six months ended June 30, 2015 are not necessarily indicative of results that may be expected for the year ending December 31, 2015. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2014 audited consolidated financial statements and notes thereto, which are included in the 2014 Form 10-K filed with the SEC on February 25, 2015 (the “2014 Form 10-K”).

New Accounting Pronouncements Adopted

ASU No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

Effective July 1, 2014, the Company prospectively adopted ASU No. 2014-08, which significantly changed the previous accounting guidance on discontinued operations. Under ASU No. 2014-08, only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations. Other changes were as follows: equity method investments that were previously scoped-out of the discontinued operations accounting guidance are now included in the scope; a business can meet the criteria to be classified as held-for-sale upon acquisition and can be reported in discontinued operations; and components where an entity retains significant continuing involvement or where operations and cash flows will not be eliminated from ongoing operations as a result of a disposal transaction can meet the definition of discontinued operations. Additionally, where summarized amounts are presented on the face of the financial statements, reconciliations of those amounts to major classes of line items are also required. ASU No. 2014-08 requires additional disclosures for individually material components that do not meet the definition of discontinued operations. Under the previous accounting guidance, the UK Wind and Ebute disposals in the third and fourth quarters of 2014, respectively, would have met the discontinued operations criteria and would have been reclassified accordingly. Additionally, Armenia Mountain, which met the held-for-sale criteria in the first quarter of 2015, would have met the discontinued operations criteria under the previous accounting guidance and would have been reclassified accordingly.

ASU No. 2014-05, Service Concession Arrangements (Topic 853)

Effective January 1, 2015, the Company adopted ASU No. 2014-05, which states that certain service concession arrangements with public-sector entity grantors are not in scope of ASC 840, Leases and that entities should not recognize the related infrastructure as property, plant and equipment, but should apply other GAAP. The Company has a small number of entities that fall within the scope of this guidance, with the Company’s Mong Duong generation facility in Vietnam being the most significant.

Mong Duong is a build, operate and transfer agreement with the Vietnam government. Management concluded there were two deliverables included within the arrangement, as well as a financing element. Due to the contingent nature of the revenue stream, no amounts of revenue could be recognized during the build phase of the contract. All amounts billed during the operate phase are recognized as revenue when billed, with amounts allocated between the financing element and build and operate deliverables. The financing element is recognized as interest income using the effective interest method as payments for construction of the plant are received over the life of the contract. Costs are expensed as incurred. As the related infrastructure is no longer considered property, plant and equipment, there are no longer any capitalizable expenses beyond those related to the initial build, and accordingly these will be expensed as incurred. All cash flows, excluding those related to the debt incurred

by AES for these arrangements will be reflected in cash flows from operating activities on the Company’s Condensed Consolidated Statements of Cash Flows prospectively.

The guidance was applied on a modified retrospective basis to service concession arrangements in existence at January 1, 2015. Upon adoption of this standard, the impact to the Company’s Condensed Consolidated Balance Sheet as of January 1, 2015 resulted in a reclassification of $1.5 billion from property, plant and equipment to service concession assets, as well as a cumulative adjustment to retained earnings and cumulative translation adjustment of $(18) million, net of tax, and $13 million, respectively.

Accounting Pronouncements Issued But Not Yet Effective

The following accounting standards have been issued but are not yet effective for, nor have been adopted by AES:

ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU No. 2015-11, which simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with a lower of cost or net realizable value test. The standard is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted. The new guidance must be applied prospectively. The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.

ASU No. 2015-05, Intangibles — Goodwill and Other — Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizing to the accounting guidance on leases. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of a prospective or retrospective approach. The Company has not yet selected a transition method and is currently evaluating the impact of adopting the standard on its consolidated financial statements.

ASU No. 2015-03, Interest — Imputation of Interest (Subtopic 835-30)

In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of June 30, 2015, the Company had approximately $385 million in deferred financing costs classified in other noncurrent assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.

ASU No. 2015-02, Consolidation — Amendments to the Consolidation Analysis (Topic 810)

In February 2015, the FASB issued ASU 2015-02, which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The Company is currently assessing the impact of the standard on its consolidated financial statements.

ASU No. 2014-12, Compensation — Stock Compensation (Topic 718)

In June 2014, the FASB issued ASU No. 2014-12, which is intended to resolve the diverse accounting treatment in practice with compensation awards. The objective of the new standard is to clarify the treatment of accounting for performance targets that affect award vesting. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of either a prospective or modified retrospective approach. The Company has not yet selected a transition method and is currently evaluating the impact of the standard on its financial position and results of operations.

ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)

In May 2014, the FASB issued ASU No. 2014-09 which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when

it is recognized. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In July 2015, the FASB decided to defer the effective date by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). The standard permits the use of either a full retrospective or modified retrospective approach. The Company has not yet selected a transition method and is currently evaluating the impact of adopting the standard on its consolidated financial statements.

2. INVENTORY

The following table summarizes the Company’s inventory balances as of the periods indicated:



	June 30, 2015		December 31, 2014
	(in millions)
Fuel and other raw materials	$	391	$	357
Spare parts and supplies	343		345
Total	$	734	$	702

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 2014 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 the periods indicated:



	June 30, 2015								December 31, 2014
	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	$	—	$	332	$	—	$	332	$	—	$	501	$	—	$	501
Certificates of deposit	—		79		—		79		—		151		—		151
Government debt securities	—		33		—		33		—		57		—		57
Subtotal	—		444		—		444		—		709		—		709
Equity securities:
Mutual funds	—		18		—		18		—		25		—		25
Subtotal	—		18		—		18		—		25		—		25
Total available for sale	—		462		—		462		—		734		—		734
TRADING:
Equity securities:
Mutual funds	15		—		—		15		15		—		—		15
Total trading	15		—		—		15		15		—		—		15
DERIVATIVES:
Foreign currency derivatives	—		14		237		251		—		18		218		236
Commodity derivatives	—		44		18		62		—		37		7		44
Total derivatives	—		58		255		313		—		55		225		280
TOTAL ASSETS	$	15	$	520	$	255	$	790	$	15	$	789	$	225	$	1,029
Liabilities
DERIVATIVES:
Interest rate derivatives	$	—	$	178	$	191	$	369	$	—	$	206	$	210	$	416
Cross-currency derivatives	—		32		—		32		—		29		—		29
Foreign currency derivatives	—		38		15		53		—		43		9		52
Commodity derivatives	—		23		1		24		—		16		1		17
Total derivatives	—		271		207		478		—		294		220		514
TOTAL LIABILITIES	$	—	$	271	$	207	$	478	$	—	$	294	$	220	$	514

_____________________________


⁽¹⁾	Amortized cost approximated fair value at June 30, 2015 and December 31, 2014.

The following tables present a reconciliation of net derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and six months ended June 30, 2015 and 2014 (presented net by type of derivative). Transfers between Level 3 and Level 2 are determined as of the end of the reporting period and principally result from changes in the significance of unobservable inputs used to calculate the credit valuation adjustment.



	Three Months Ended June 30, 2015
	Interest Rate			Foreign Currency			Commodity			Cross Currency			Total
	(in millions)
Balance at the beginning of the period	$	(302	)	$	223		$	4		$	(33	)	$	(108	)
Total gains (losses) (realized and unrealized):
Included in earnings	—			7			—			—			7
Included in other comprehensive income — derivative activity	57			—			—			—			57
Included in other comprehensive income — foreign currency translation activity	(4		)	(6		)	—			—			(10		)
Included in regulatory (assets) liabilities	—			—			8			—			8
Settlements	5			(2		)	5			1			9
Transfers of (assets) liabilities out of Level 3	53			—			—			32			85
Balance at the end of the period	$	(191	)	$	222		$	17		$	—		$	48
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	$	—		$	5		$	(1	)	$	—		$	4



	Three Months Ended June 30, 2014
	Interest Rate			Foreign Currency			Commodity			Total
	(in millions)
Balance at the beginning of the period	$	(87	)	$	101		$	—		$	14
Total gains (losses) (realized and unrealized):
Included in earnings	—			10			3			13
Included in other comprehensive income — derivative activity	(30		)	—			—			(30		)
Included in other comprehensive income — foreign currency translation activity	—			(2		)	—			(2		)
Included in regulatory (assets) liabilities	—			—			15			15
Settlements	3			(2		)	(2		)	(1		)
Transfers of assets (liabilities) into Level 3	(69		)	—			—			(69		)
Balance at the end of the period	$	(183	)	$	107		$	16		$	(60	)
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	$	—		$	9		$	—		$	9



	Six Months Ended June 30, 2015
	Interest Rate			Foreign Currency			Commodity		Total
	(in millions)
Balance at the beginning of the period	$	(210	)	$	209		$	6	$	5
Total gains (losses) (realized and unrealized):
Included in earnings	—			30			2		32
Included in other comprehensive income — derivative activity	3			—			—		3
Included in other comprehensive income — foreign currency translation activity	7			(13		)	—		(6		)
Included in regulatory (assets) liabilities	—			—			8		8
Settlements	9			(4		)	1		6
Balance at the end of the period	$	(191	)	$	222		$	17	$	48
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	$	—		$	26		$	2	$	28



	Six Months Ended June 30, 2014
	Interest Rate			Foreign Currency			Commodity			Total
	(in millions)
Balance at the beginning of the period	$	(101	)	$	93		$	4		$	(4	)
Total gains (losses) (realized and unrealized):
Included in earnings	1			37			1			39
Included in other comprehensive income — derivative activity	(99		)	(1		)	—			(100		)
Included in other comprehensive income — foreign currency translation activity	—			(20		)	—			(20		)
Included in regulatory (assets) liabilities	—			—			12			12
Settlements	16			(3		)	(1		)	12
Transfers of (assets) liabilities out of Level 3	—			1			—			1
Balance at the end of the period	$	(183	)	$	107		$	16		$	(60	)
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		$	34		$	—		$	35

The table below summarizes the significant unobservable inputs used for Level 3 derivative assets (liabilities) as of June 30, 2015:



Type of Derivative	Fair Value			Unobservable Input	Amount or Range (Weighted Avg)
	(in millions)
Interest rate	$	(191	)	Subsidiaries’ credit spreads	3.75% — 7.34% (5.17%)
Foreign currency:
Derivative — Argentine Peso	220			Argentine Peso to USD currency exchange rate after one year	13.71 — 36.10 (24.25)
Embedded derivative — Euro	2			Subsidiaries’ credit spreads	4.84% — 7.34% (6.09%)
Commodity:
Other	17
Total	$	48

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 indicated and their level within the fair value hierarchy:



	Six Months Ended June 30, 2015
	Carrying Amount ₍₁₎		Fair Value⁽⁵⁾						Pretax Loss
	Carrying Amount ₍₁₎		Level 1		Level 2		Level 3		Pretax Loss
	(in millions)
Assets
Equity method investment:
Solar Spain	$	29	$	—	$	—	$	29	$	—
Long-lived assets held and used: ⁽²⁾
UK Wind (Development Projects)	38		—		1		—		37
Other	29		—		21		—		8



	Six Months Ended June 30, 2014
	Carrying Amount ₍₁₎		Fair Value⁽⁵⁾						Pretax Loss
			Level 1		Level 2		Level 3
	(in millions)
Assets
Long-lived assets held and used: ⁽²⁾
DPL (East Bend)	$	14	$	—	$	2	$	—	$	12
Ebute	99		—		—		47		52
UK Wind (Newfield)	11		—		—		—		11
Discontinued operations and held-for-sale businesses: ⁽³⁾
Cameroon	372		—		334		—		38
Equity method investments
Silver Ridge Power	317		—		—		273		44
Goodwill: ⁽⁴⁾
DPLER	136		—		—		—		136
Buffalo Gap	28		—		—		10		18

_____________________________


⁽¹⁾	Represents the carrying value at the date of measurement, before fair value adjustment.


⁽²⁾	See Note 15—Asset Impairment Expense for further information.


⁽³⁾	See Note 17—Discontinued Operations and Held-For-Sale Businesses for further information. Fair value of long-lived assets held-for-sale excludes costs to sell.


⁽⁴⁾	See Note 14—Goodwill Impairment for further information.


⁽⁵⁾	Fair value measurements were estimated at various dates within the applicable reporting period and not necessarily as of the period’s end date.

The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets during the six months ended June 30, 2015:



	Fair Value		Valuation Technique	Unobservable Input	Range (Weighted Average)
	(in millions)
Equity method investment:
Solar Spain	$	29	Discounted cash flow	Annual revenue growth	-3% to 0% (0%)
				Annual pretax operating margin	-13% to 56% (24%)
				Cost of equity	12	%

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

The following table sets forth the carrying amount, fair value and fair value hierarchy of the Company’s financial assets and liabilities that are not measured at fair value in the Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014, but for which fair value is disclosed.



	Carrying Amount		Fair Value
			Total		Level 1		Level 2		Level 3
	(in millions)
June 30, 2015
Assets
Accounts receivable — noncurrent ⁽¹⁾	$	260	$	247	$	—	$	—	$	247
Liabilities
Non-recourse debt	15,749		16,101		—		12,644		3,457
Recourse debt	5,014		5,150		—		5,150		—
December 31, 2014
Assets
Accounts receivable — noncurrent ⁽¹⁾	$	301	$	290	$	—	$	—	$	290
Liabilities
Non-recourse debt	15,600		16,008		—		12,538		3,470
Recourse debt	5,258		5,552		—		5,552		—

_____________________________


⁽¹⁾	These accounts receivable principally relate to amounts due from CAMMESA, and are included in Noncurrent assets—Other in the accompanying Condensed Consolidated Balance Sheets. The fair value and carrying amount of these receivables exclude VAT of $31 million and $36 million at June 30, 2015 and December 31, 2014, respectively.

4. INVESTMENTS IN MARKETABLE SECURITIES

The Company’s investments in marketable debt and equity securities as of June 30, 2015 and December 31, 2014 by security class and by level within the fair value hierarchy have been disclosed in Note 3—Fair Value. The security classes are determined based on the nature and risk of a security and are consistent with how the Company manages, monitors and measures its marketable securities. As of June 30, 2015, $411 million of AFS debt securities had stated maturities within one year and $33 million had stated maturities between one and two years. Gains and losses on the sale of investments are determined using the specific-identification method. For the three and six months ended June 30, 2015 and 2014, pretax realized gains and losses related to AFS and trading securities were less than $1 million, there were no unrealized losses on AFS securities, and no other-than-temporary impairments of marketable securities were recognized in earnings or OCI. The following table summarizes the gross proceeds from sale of AFS securities for the periods indicated:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Gross proceeds from sales of AFS securities	$	1,395	$	1,158	$	2,481	$	2,218

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 2014 Form 10-K.

Volume of Activity — The following three tables set forth, by type of derivative, the Company’s outstanding notional under its derivatives and the weighted average remaining term as of June 30, 2015 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:



	Current			Maximum
Interest Rate and Cross-Currency⁽¹⁾	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:
LIBOR (U.S. Dollar)	2,689	$	2,689	3,061	$	3,061	11	55	%
EURIBOR (Euro)	506	564		506	564		7	75	%
Cross-Currency Swaps:
Chilean Unidad de Fomento	4	172		4	172		13	82	%

_____________________________

⁽¹⁾

The Company’s interest rate derivative instruments primarily include accreting and amortizing notionals. The maximum derivative notional represents the largest notional at any point between June 30, 2015 and the maturity of the derivative instrument, which includes forward-starting derivative instruments. The interest rate and cross-currency derivatives range in maturity through 2033 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.



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	8	$	311	<1
Chilean Peso	80,373	126		<1
Brazilian Real	103	33		<1
Euro	107	119		<1
Colombian Peso	145,874	56		<1
Argentine Peso	2,032	224		10
British Pound	16	24		<1
Philippine Peso	751	17		<1
Embedded Foreign Currency Derivatives:
Kazakhstani Tenge	3,761	20		1

_____________________________


⁽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 2025 and 2017, respectively.



Commodity Derivatives	Notional	Weighted-Average Remaining Term⁽¹⁾
	(in millions)	(in years)
Power (MWh)	9	2
Coal (Metric tons)	1	2

_____________________________


⁽¹⁾	Represents the remaining tenor of our commodity derivatives weighted by the corresponding volume. These derivatives range in maturity through 2017.

Accounting and Reporting — Assets and Liabilities — The following tables present the fair values of the Company’s derivative instruments as of June 30, 2015 and December 31, 2014, first by whether they are designated hedging instruments, then by whether they are current or noncurrent, to the extent they are subject to master netting agreements or similar agreements (where the rights to set-off relate to settlement of amounts receivable and payable under those derivatives) and by balances no longer accounted for as derivatives.



	June 30, 2015						December 31, 2014
	Designated		Not Designated		Total		Designated		Not Designated		Total
	(in millions)
Assets
Foreign currency derivatives	$	7	$	244	$	251	$	6	$	230	$	236
Commodity derivatives	31		31		62		25		19		44
Total assets	$	38	$	275	$	313	$	31	$	249	$	280
Liabilities
Interest rate derivatives	$	369	$	—	$	369	$	416	$	—	$	416
Cross-currency derivatives	32		—		32		29		—		29
Foreign currency derivatives	32		21		53		38		14		52
Commodity derivatives	11		13		24		7		10		17
Total liabilities	$	444	$	34	$	478	$	490	$	24	$	514



	June 30, 2015						December 31, 2014
	Assets			Liabilities			Assets			Liabilities
	(in millions)
Current	$	91		$	151		$	77		$	148
Noncurrent	222			327			203			366
Total	$	313		$	478		$	280		$	514
Derivatives subject to master netting agreement or similar agreement:
Gross amounts recognized in the balance sheet	$	36		$	425		$	53		$	507
Gross amounts of derivative instruments not offset	(11		)	(11		)	(10		)	(10		)
Gross amounts of collateral received/pledged not offset	—			(31		)	—			(26		)
Net amount	$	25		$	383		$	43		$	471
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	$	153		$	173		$	161		$	180

Effective Portion of Cash Flow Hedges — The following tables set forth the pretax gains (losses) recognized in 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 periods indicated:



	Gains (Losses) Recognized in AOCL							Gains (Losses) Reclassified from AOCL into Earnings
	Three Months Ended June 30,						Classification in Condensed Consolidated Statements of Operations	Three Months Ended June 30,
Type of Derivative	2015			2014				2015			2014
	(in millions)							(in millions)
Interest rate derivatives	$	94		$	(124	)	Interest expense	$	(15	)	$	(33	)
							Non-regulated cost of sales	(1		)	—
							Net equity in earnings of affiliates	—			(2		)
Cross-currency derivatives	1			—			Interest expense	—			2
							Foreign currency transaction gains	—			4
Foreign currency derivatives	(1		)	3			Foreign currency transaction gains	2			3
Commodity derivatives	8			(6		)	Non-regulated revenue	10			6
							Non-regulated cost of sales	(4		)	(3		)
Total	$	102		$	(127	)		$	(8	)	$	(23	)



	Gains (Losses) Recognized in AOCL							Gains (Losses) Reclassified from AOCL into Earnings
	Six Months Ended June 30,						Classification in Condensed Consolidated Statements of Operations	Six Months Ended June 30,
Type of Derivative	2015			2014				2015			2014
	(in millions)							(in millions)
Interest rate derivatives	$	(4	)	$	(274	)	Interest expense	$	(39	)	$	(64	)
							Non-regulated cost of sales	(1		)	(1		)
							Net equity in earnings of affiliates	—			(3		)
Cross-currency derivatives	1			(3		)	Interest expense	(1		)	1
							Foreign currency transaction losses	—			(6		)
Foreign currency derivatives	1			(12		)	Foreign currency transaction gains	8			10
Commodity derivatives	15			18			Non-regulated revenue	15			19
							Non-regulated cost of sales	(4		)	(1		)
Total	$	13		$	(271	)		$	(22	)	$	(45	)

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 12 months as of June 30, 2015 is $(123) million for interest rate hedges, $(5) million for cross-currency swaps, $8 million for foreign currency hedges, and $12 million for commodity and other hedges.

For the three and six months ended June 30, 2014, pretax gains of $6 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 were no such reclassifications for the three and six months ended June 30, 2015.

Ineffective Portion of Cash Flow Hedges — The following table presents 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 periods indicated:



	Classification in Condensed Consolidated Statements of Operations	Three Months Ended June 30,						Six Months Ended June 30,
Type of Derivative		2015			2014			2015			2014
		(in millions)
Interest rate derivatives	Interest expense	$	(1	)	$	1		$	(1	)	$	1
Foreign currency derivatives	Foreign currency transaction losses	—			—			$	(2	)	$	—
Cross-currency derivatives	Interest expense	—			(1		)	—			(1		)
Total		$	(1	)	$	—		$	(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 periods indicated:



	Classification in Condensed Consolidated Statements of Operations	Three Months Ended June 30,						Six Months Ended June 30,
Type of Derivative		2015			2014			2015			2014
		(in millions)
Foreign currency derivatives	Foreign currency transaction gains	$	7		$	6		39			29
	Net equity in earnings of affiliates	—			9			—			5
Commodity and other derivatives	Non-regulated revenue	1			1			(4		)	4
	Regulated revenue	—			—			—			—
	Non-regulated cost of sales	—			2			1			2
	Regulated cost of sales	(1		)	2			(5		)	(6		)
	Income (loss) from operations of discontinued businesses	—			(2		)	—			(7		)
	Net loss from disposal and impairments of discontinued businesses	—			72			—			72
Total		$	7		$	90		$	31		$	99

Credit Risk-Related Contingent Features — DP&L 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 is 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 $19 million and $12 million as of June 30, 2015 and December 31, 2014, respectively, for all derivatives with credit risk-related contingent features. As of June 30, 2015 and December 31, 2014, DP&L had posted $7 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.

6. FINANCING RECEIVABLES

Financing receivables are defined as receivables that have contractual maturities of greater than one year. The Company primarily has financing receivables pursuant to amended agreements or government resolutions that are due from certain governmental bodies in Argentina. The following table presents financing receivables by country as of the periods indicated:



	June 30, 2015		December 31, 2014
	(in millions)
Argentina	$	256	$	278
Cameroon sale ⁽¹⁾	—		44
United States	20		—
Brazil	15		15
Total long-term financing receivables	$	291	$	337

_____________________________


⁽¹⁾	Represents non-contingent consideration to be received in 2016 from the sale of the Cameroon businesses in 2014. Balance is classified as short-term as of June 30, 2015. See Note 17—Discontinued Operations and Held-For-Sale Businesses.

Argentina — 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.

7. INVESTMENTS IN AND ADVANCES TO AFFILIATES

Summarized Financial Information — The following table summarizes financial information of the Company’s 50%-or-less-owned affiliates that are accounted for using the equity method.



	Six Months Ended June 30,
50%-or-less-Owned Affiliates	2015		2014
	(in millions)
Revenue	$	357	$	568
Operating margin	86		150
Net income	35		107

Guacolda — On April 11, 2014, AES Gener undertook a series of transactions, pursuant to which AES Gener acquired the interests that it did not previously own in Guacolda for $728 million and simultaneously sold the ownership interest to Global Infrastructure Partners ("GIP") for $730 million. The transaction provided GIP with substantive participating rights in Guacolda and, as a result, the Company continues to account for its investment in Guacolda using the equity method of accounting.

8. DEBT

Recourse Debt — In April 2015, the Company issued $575 million aggregate principal amount of 5.50% senior notes due 2025. Concurrent with this offering, the Company redeemed via tender offers $344 million aggregate principal of its existing 8.00% senior unsecured notes due 2017, and $156 million of its existing 8.00% senior unsecured notes due 2020. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $82 million for the three and six months ended June 30, 2015 that is included in the Condensed Consolidated Statement of Operations.

In March 2015, the Company redeemed in full the $151 million balance of its 7.75% senior unsecured notes due October 2015 and the $164 million balance of its 9.75% senior unsecured notes due April 2016. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $23 million for the six months ended June 30, 2015 that is included in the Condensed Consolidated Statement of Operations.

On May 20, 2014, the Company issued $775 million aggregate principal amount of senior unsecured floating rate notes due June 2019. The notes bear interest at a rate of 3% above three-month LIBOR, reset quarterly. Concurrent with this offering, the Company repaid $767 million of its existing senior secured term loan due 2018. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $10 million for the three and six months ended June 30, 2014 that is included in the Condensed Consolidated Statement of Operations. On June 16, 2014, the Company repaid in full the remaining balance of $29 million of its senior secured term loan due 2018.

In February 2014, the Company redeemed in full the $110 million balance of its 7.75% senior unsecured notes due March 2014. On March 7, 2014, the Company issued $750 million aggregate principal amount of 5.50% senior notes due 2024. Concurrent with this offering, the Company redeemed via tender offers $625 million aggregate principal of its existing 8.00% senior unsecured notes due 2017. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $132 million for the six months ended June 30, 2014 that is included in the Condensed Consolidated Statement of Operations.

Non-Recourse Debt — Significant transactions — During the six months ended June 30, 2015, the Company’s subsidiaries had the following significant debt transactions:


•	Sul issued new debt of $499 million, partially offset by repayments of $468 million;


•	IPALCO issued new debt of $405 million, partially offset by repayments of $384 million;


•	Panama issued new debt of $300 million, partially offset by repayments of $287 million;


•	Cochrane drew $297 million under its existing construction loans;


•	Gener drew $150 million on an existing credit facility;


•	Eletropaulo issued new debt of $118 million; and


•	Mong Duong drew $104 million under its construction loan facility.

Debt in default — The following table summarizes the Company’s subsidiary non-recourse debt in default as of June 30, 2015. Due to the defaults, these amounts are included in the current portion of non-recourse debt:



	Primary Nature of Default	June 30, 2015
Subsidiary	Primary Nature of Default	Debt in Default		Net Assets
		(in millions)
Maritza (Bulgaria)	Covenant	$	605	$	612
Kavarna (Bulgaria)	Covenant	147		78
Altai (Kazakhstan)	Covenant	$	12	16
		$	764

The above defaults are not payment defaults. All of the subsidiary non-recourse debt defaults were triggered by failure to comply with 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 applicable subsidiary.

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 Parent Company’s corporate debt agreements, there could be a cross-default to the Company’s recourse debt. Materiality is defined in the Parent’s senior secured credit facility as having provided 20% or more of the total cash distributions from businesses to the Parent Company for the four most recently completed fiscal quarters. As of June 30, 2015, none of the defaults listed above individually or in the aggregate result in or are at risk of triggering a cross-default under the recourse debt of the Parent Company. In the event the Parent Company is not in compliance with the financial covenants of its senior secured credit facility, restricted payments will be limited to regular quarterly shareholder dividends at the then-prevailing rate. Payment defaults and bankruptcy defaults would preclude the making of any restricted payments.

9. 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 subsidiaries. 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 19 years.

Amounts 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 contingent obligations of $18 million made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of its businesses. The following table summarizes the Parent Company’s contingent contractual obligations as of June 30, 2015 ($ in millions).



Contingent Contractual Obligations	Amount		Number of Agreements	Maximum Exposure Range for Each Agreement
Guarantees and commitments	$	359	14	$1 — 53
Asset sale related indemnities ⁽¹⁾	27		1	$27
Cash collateralized letters of credit	49		6	<$1 — 30
Letters of credit under the senior secured credit facility	61		7	<$1 — 29
Total	$	496	28

_____________________________


⁽¹⁾	Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal.

During the three months ended June 30, 2015, 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 June 30, 2015 and December 31, 2014, the Company had recognized liabilities of $10 million and $12 million, respectively, for projected environmental remediation costs. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation with current legislation or costs for new legislation introduced could be higher or lower than the amount currently accrued. Moreover, where no liability has been recognized, it is reasonably possible that the Company may be required to incur remediation costs or make expenditures in amounts that could be material but could not be estimated as of June 30, 2015. In aggregate, the Company estimates that the range of potential losses related to environmental matters, where estimable, to be up to $1 million. The amounts considered reasonably possible do not include amounts accrued 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 recognized aggregate liabilities for all claims of approximately $199 million as of June 30, 2015 and December 31, 2014. These amounts are reported on the Condensed Consolidated Balance Sheets within Accrued and other liabilities and Other noncurrent liabilities. A significant portion of these accrued liabilities relate to labor and employment, non-income tax and customer disputes in international jurisdictions, principally Brazil where there are 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 accrued liabilities 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 accruals 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 accrued liability has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of June 30, 2015. 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 $1.2 billion and $1.3 billion. Certain claims are in settlement negotiations. The amounts considered reasonably possible do not include amounts accrued, as discussed above. These material contingencies do not include income tax-related contingencies which are considered part of our uncertain tax positions.

Regulatory — During the fourth quarter of 2013, the Company recognized a regulatory liability of $269 million for a contingency related to an administrative ruling which required Eletropaulo to refund customers’ amounts related to the regulatory asset base. During the second half of 2014, Eletropaulo started refunding customers as part of the tariff. In January 2015, ANEEL updated the tariff to exclude any further customer refunds. On June 30, 2015, ANEEL included in the tariff reset the reimbursement to Eletropaulo of these amounts previously refunded to customers to begin in July 2015. During the second quarter of 2015, as a result of favorable events, management reassessed the contingency and determined that it no longer meets the recognition criteria under ASC 450. Management believes that it is now only reasonably possible that Eletropaulo will have to refund these amounts to customers. Accordingly, the Company reversed the remaining regulatory liability for this contingency of $161 million in the second quarter of 2015, which increased Regulated Revenue by $97 million and reduced Interest Expense by $64 million. Amounts related to this case are now included as part of our reasonably possible contingent range mentioned in the preceding paragraph.

10. PENSION PLANS

Total pension cost for the periods indicated included the following components:



	Three Months Ended June 30,												Six Months Ended June 30,
	2015						2014						2015						2014
	U.S.			Foreign			U.S.			Foreign			U.S.			Foreign			U.S.			Foreign
	(in millions)
Service cost	$	4		$	4		$	4		$	4		$	8		$	8		$	7		$	8
Interest cost	11			95			12			129			23			197			24			251
Expected return on plan assets	(17		)	(66		)	(16		)	(96		)	(34		)	(138		)	(32		)	(186		)
Amortization of prior service cost	2			—			1			1			4			—			3			2
Amortization of net loss	5			7			3			9			10			15			6			17
Total pension cost	$	5		$	40		$	4		$	47		$	11		$	82		$	8		$	92

Total employer contributions for the six months ended June 30, 2015 for the Company’s U.S. and foreign subsidiaries were $26 million and $48 million, respectively. The expected remaining scheduled employer contributions for 2015 are $0

million and $35 million for U.S. and foreign subsidiaries, respectively.

11. EQUITY

Changes in Equity — The following table provides a reconciliation of the beginning and ending equity attributable to stockholders of The AES Corporation, noncontrolling interests and total equity as of the periods indicated:



	Six Months Ended June 30, 2015									Six Months Ended June 30, 2014
	The AES Corporation Stockholders’ Equity			Noncontrolling Interests			Total Equity			The AES Corporation Stockholders’ Equity			Noncontrolling Interests			Total Equity
	(in millions)
Balance at the beginning of the period	$	4,272		$	3,053		$	7,325		$	4,330		$	3,321		$	7,651
Net income	211			307			518			75			266			341
Total foreign currency translation adjustment, net of income tax	(204		)	(140		)	(344		)	(56		)	38			(18		)
Total change in derivative fair value, net of income tax	30			(1		)	29			(99		)	(94		)	(193		)
Total pension adjustments, net of income tax	2			7			9			14			17			31
Cumulative effect of a change in accounting principle	(5		)	—			(5		)	—			—			—
Capital contributions from noncontrolling interests	—			97			97			—			113			113
Distributions to noncontrolling interests	—			(119		)	(119		)	—			(215		)	(215		)
Acquisition of business ⁽¹⁾	—			16			16			—			—			—
Disposition of businesses	—			—			—			—			(151		)	(151		)
Acquisition of treasury stock	(307		)	—			(307		)	(32		)	—			(32		)
Issuance and exercise of stock-based compensation benefit plans, net of income tax	17			—			17			16			—			16
Dividends declared on common stock	(70		)	—			(70		)	(36		)	—			(36		)
Sale of subsidiary shares to noncontrolling interests	(82		)	—			(82		)	—			—			—
Transaction between entities under common control	—			—			—			5			2			7
Acquisition of subsidiary shares from noncontrolling interests	—			—			—			(6		)	—			(6		)
Balance at the end of the period	$	3,864		$	3,220		$	7,084		$	4,211		$	3,297		$	7,508

_____________________________

⁽¹⁾Fair value of a tax equity partner’s right to preferential returns as a result of the acquisition of Solar Power PR, LLC (Solar Puerto Rico), which was previously accounted for as an equity method investment.

Equity Transactions with Noncontrolling Interests

IPALCO — On December 14, 2014, the Company executed sale and subscription agreements with CDPQ, whereby in the first quarter of 2015, CDPQ acquired a 15% noncontrolling interest in AES US Investments, Inc., a wholly-owned subsidiary, for $247 million. Prior to these agreements, AES US Investments, Inc. owned 100% of IPALCO. Under the subscription agreement, CDPQ committed to invest an additional $349 million in IPALCO through 2016 in exchange for a 17.65% equity stake, by funding existing growth and environmental projects at Indianapolis Power & Light Company. In April 2015, CDPQ invested $214 million of the $349 million in IPALCO, which resulted in CDPQ’s combined equity interest in IPALCO to be 24.90%. Upon investing the remaining commitment of $135 million, CDPQ's equity interests in IPALCO will total 30%.

As a result of these transactions, $82 million in taxes and transaction costs were recognized as a net decrease to equity. The Company also recognized an increase of $377 million to additional paid-in capital and a reduction to retained earnings of $377 million for the excess of the fair value of the shares over their book value. Since the noncontrolling interest is contingently redeemable, the fair value of the consideration received of $461 million is classified in temporary equity as redeemable stock of subsidiaries on the Condensed Consolidated Balance Sheets. No gain or loss was recognized in net income as the sale is not considered to be a sale of in-substance real estate. Any subsequent adjustments to allocate earnings and dividends to CDPQ will be classified as noncontrolling interest within permanent equity and adjustments to the amount in temporary equity will occur only if and when it is probable that the shares will become redeemable. As the Company maintained control after the sale, IPALCO continues to be accounted for as a consolidated subsidiary within the US SBU reportable segment.

Jordan — On March 15, 2015, the Company executed an agreement to sell 40% of its interest in a wholly owned subsidiary in Jordan that owns a controlling interest in the 247 MW Jordan IPP4 gas-fired plant for $30 million. The sale is expected to be completed during 2015.

Accumulated Other Comprehensive Loss — See below for the changes in AOCL by component, net of tax and noncontrolling interests, for the six months ended June 30, 2015:



	Unrealized derivative gains (losses), net			Unfunded pension obligations, net			Foreign currency translation adjustment, net			Total
	(in millions)
Balance at the beginning of the period	$	(396	)	$	(295	)	$	(2,595	)	$	(3,286	)
Other comprehensive income (loss) before reclassifications	18			—			(204		)	(186		)
Amount reclassified to earnings	12			2			—			14
Other comprehensive income (loss)	30			2			(204		)	(172		)
Cumulative effect of a change in accounting principle	—			—			13			13
Balance at the end of the period	$	(366	)	$	(293	)	$	(2,786	)	$	(3,445	)

Reclassifications out of AOCL for the periods indicated were as follows:



Details About		Three Months Ended June 30,						Six Months Ended June 30,
AOCL Components	Affected Line Item in the Condensed Consolidated Statements of Operations	2015			2014			2015			2014
Foreign currency translation adjustment, net		(in millions) ⁽¹⁾
	Net loss from disposal and impairments of discontinued businesses	—			53			—			$	47
	Net income attributable to The AES Corporation	$	—		$	53		$	—		$	47
Unrealized derivative gains (losses), net
	Non-regulated revenue	$	10		$	6		$	15		$	19
	Non-regulated cost of sales	(5		)	(3		)	(5		)	$	(2	)
	Interest expense	(15		)	(31		)	(40		)	(63		)
	Foreign currency transaction gains (losses)	2			7			8			4
	Income from continuing operations before taxes and equity in earnings of affiliates	(8		)	(21		)	(22		)	(42		)
	Income tax expense	1			10			3			13
	Net equity in earnings of affiliates	—			(2		)	—			(3		)
	Income from continuing operations	(7		)	(13		)	(19		)	(32		)
	Income from continuing operations attributable to noncontrolling interests	4			15			7			15
	Net income attributable to The AES Corporation	$	(3	)	$	2		$	(12	)	$	(17	)
Amortization of defined benefit pension actuarial loss, net
	Regulated cost of sales	$	(6	)	$	(9	)	$	(14	)	$	(17	)
	Non-regulated cost of sales	—			1			—			—
	Other income	—			(2		)	—			(2		)
	Income from continuing operations before taxes and equity in earnings of affiliates	(6		)	(10		)	(14		)	(19		)
	Income tax expense	2			(2		)	5			1
	Income from continuing operations	(4		)	(12		)	(9		)	(18		)
	Net loss from disposal and impairments of discontinued businesses	—			2			—			2
	Net income	(4		)	(10		)	(9		)	(16		)
	Income from continuing operations attributable to noncontrolling interests	3			7			7			11
	Net income attributable to The AES Corporation	$	(1	)	$	(3	)	$	(2	)	$	(5	)
Total reclassifications for the period, net of income tax and noncontrolling interests		$	(4	)	$	52		$	(14	)	$	25

_____________________________


⁽¹⁾	Amounts in parentheses indicate debits to the Condensed Consolidated Statements of Operations.

Common Stock Dividends

The Company paid dividends of $0.10 per outstanding share to its common stockholders during each of the first and second quarters of 2015 for dividends declared in December 2014 and April 2015, respectively. For information on dividends declared after the second quarter of 2015, see Note 20—Subsequent Events.

Secondary Offering and Concurrent Stock Repurchase

On May 18, 2015, the Parent Company completed an underwritten secondary public offering (the “Offering”) of 60 million shares of its common stock by the Terrific Investment Corporation (the “Selling Stockholder”), a subsidiary controlled by China Investment Corporation at a price of $13.25 per share. Of the 60 million shares, 40 million were sold to the market and 20 million were reserved to be repurchased by the Parent Company. The Parent Company did not receive any of the proceeds from the Offering and the Selling Stockholder has fully sold its stake in AES common stock. Concurrent with this offering, on May 18, 2015, the Parent Company completed the repurchase of the 20 million shares of its common stock from the Selling Stockholder at a price per share of $13.07, for an aggregate purchase price of $261 million.

Stock Repurchase Program

During the three months ended June 30, 2015, the Parent Company repurchased 20.8 million shares of its common stock (including the 20 million share repurchase in May referenced above) at a total cost of $271 million under the existing stock repurchase program (the “Program”). The cumulative repurchases from the commencement of the Program in July 2010 through June 30, 2015 totaled 129.5 million shares for a total cost of $1.6 billion, at an average price per share of $12.47 (including a nominal amount of commissions). As of June 30, 2015, $117 million remained available for repurchase under the Program. For information on stock repurchases after the second quarter of 2015, see Note 20—Subsequent Events.

12. SEGMENTS

The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the businesses internally and is organized by geographic regions which provide better socio-political-economic understanding of our business. The management reporting structure is organized along six SBUs — led by our Chief Executive Officer (“CEO”). Using the accounting guidance on segment reporting, the Company has determined that it has six reportable segments corresponding to its six SBUs:


•	US SBU;


•	Andes SBU;


•	Brazil SBU;


•	MCAC SBU;


•	Europe SBU; and


•	Asia SBU

Corporate and Other — Corporate overhead costs which are not directly associated with the operations of our six reportable segments are included in “Corporate and Other.” Also included are certain 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 pretax income from continuing operations attributable to AES excluding unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, gains or losses due to dispositions and acquisitions of business interests, losses due to impairments and costs due to the early retirement of debt. The Company has concluded that Adjusted PTC best reflects the underlying business performance of the Company and is the most relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Additionally, given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure that better assists investors in determining which businesses have the greatest impact on the overall Company results.

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.

Information about the Company’s operations by segment for the periods indicated was as follows:



Revenue	Total Revenue				Intersegment						External Revenue
Three Months Ended June 30,	2015		2014		2015			2014			2015		2014
	(in millions)
US SBU	$	831	$	893	$	—		$	—		$	831	$	893
Andes SBU	630		724		(2		)	(1		)	628		723
Brazil SBU	1,315		1,533		—			—			1,315		1,533
MCAC SBU	601		692		(1		)	—			600		692
Europe SBU	299		305		(3		)	—			296		305
Asia SBU	187		163		—			—			187		163
Corporate and Other	6		5		(5		)	(3		)	1		2
Total Revenue	$	3,869	$	4,315	$	(11	)	$	(4	)	$	3,858	$	4,311



Revenue	Total Revenue				Intersegment						External Revenue
Six Months Ended June 30,	2015		2014		2015			2014			2015		2014
	(in millions)
US SBU	$	1,828	$	1,894	$	—		$	—		$	1,828	$	1,894
Andes SBU	1,242		1,344		(4		)	(1		)	1,238		1,343
Brazil SBU	2,645		2,978		—			—			2,645		2,978
MCAC SBU	1,199		1,330		(2		)	(1		)	1,197		1,329
Europe SBU	629		696		(3		)	—			626		696
Asia SBU	306		331		—			—			306		331
Corporate and Other	10		7		(8		)	(5		)	2		2
Total Revenue	$	7,859	$	8,580	$	(17	)	$	(7	)	$	7,842	$	8,573



Adjusted PTC ⁽¹⁾	Total Adjusted PTC						Intersegment						External Adjusted PTC
Three Months Ended June 30,	2015			2014			2015			2014			2015			2014
	(in millions)
US SBU	$	56		$	80		$	3		$	3		$	59		$	83
Andes SBU	81			104			5			1			86			105
Brazil SBU	41			115			—			—			41			115
MCAC SBU	106			95			5			10			111			105
Europe SBU	41			73			(1		)	3			40			76
Asia SBU	30			23			1			—			31			23
Corporate and Other	(104		)	(150		)	(13		)	(17		)	(117		)	(167		)
Total Adjusted PTC	$	251		$	340		$	—		$	—		$	251		$	340
Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates:
Non-GAAP Adjustments:
Unrealized derivative gains													2			22
Unrealized foreign currency gains (losses)													3			(7		)
Disposition/acquisition gains (losses)													4			(2		)
Impairment losses													(30		)	(99		)
Loss on extinguishment of debt													(115		)	(13		)
Pretax contribution													115			241
Add: Income from continuing operations before taxes, attributable to noncontrolling interests													269			197
Less: Net equity in earnings of affiliates													—			20
Income from continuing operations before taxes and equity in earnings of affiliates													$	384		$	418



Adjusted PTC ⁽¹⁾	Total Adjusted PTC						Intersegment						External Adjusted PTC
Six Months Ended June 30,	2015			2014			2015			2014			2015			2014
	(in millions)
US SBU	$	162		$	155		$	6		$	6		$	168		$	161
Andes SBU	172			157			8			4			180			161
Brazil SBU	62			184			1			1			63			185
MCAC SBU	156			160			9			14			165			174
Europe SBU	126			188			2			6			128			194
Asia SBU	42			31			1			1			43			32
Corporate and Other	(217		)	(292		)	(27		)	(32		)	(244		)	(324		)
Total Adjusted PTC	$	503		$	583		$	—		$	—		$	503		$	583
Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates:
Non-GAAP Adjustments:
Unrealized derivative gains													17			32
Unrealized foreign currency losses													(44		)	(33		)
Disposition/acquisition gains (losses)													9			(1		)
Impairment losses													(36		)	(265		)
Loss on extinguishment of debt													(142		)	(147		)
Pretax contribution													307			169
Add: Income from continuing operations before taxes, attributable to noncontrolling interests													427			412
Less: Net equity in earnings of affiliates													15			45
Income from continuing operations before taxes and equity in earnings of affiliates													$	719		$	536

_____________________________


⁽¹⁾	Adjusted PTC 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.



Total Assets	June 30, 2015		December 31, 2014
	(in millions)
US SBU	$	10,089	$	10,062
Andes SBU	8,349		7,888
Brazil SBU	7,790		8,439
MCAC SBU	5,031		4,948
Europe SBU	3,497		3,525
Asia SBU	3,127		2,972
Assets of held-for-sale businesses	158		—
Corporate and Other & eliminations	543		1,132
Total Assets	$	38,584	$	38,966

13. OTHER INCOME AND EXPENSE

Other Income — Other income includes gains on asset sales and liability extinguishments, favorable judgments on contingencies, and other income from miscellaneous transactions. The components of other income are summarized as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Contingency reversal (Kazakhstan)	$	—	$	18	$	—	$	18
Gain on sale of assets	6		8		11		10
Allowance for Funds Used During Construction (IPL)	3		1		7		2
Other	6		6		13		15
Total other income	$	15	$	33	$	31	$	45

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Loss on sale and disposal of assets	$	8	$	12	$	23	$	19
Legal settlement	5		—		8		—
Other	1		5		3		6
Total other expense	$	14	$	17	$	34	$	25

14. GOODWILL IMPAIRMENT

There were no goodwill impairments for the three and six months ended June 30, 2015 or for the three months ended June 30, 2014.

DPLER — During the first quarter of 2014, the Company performed an interim impairment test on the $136 million in goodwill at its DPLER reporting unit, a competitive retail marketer selling retail electricity to customers in Ohio and Illinois. The DPLER reporting unit was identified as being “at risk” during the fourth quarter of 2013. The impairment indicators arose based on market information available regarding actual and proposed sales of competitive retail marketers, which indicated a significant decline in valuations during the first quarter of 2014.

In Step 1 of the interim impairment test, the fair value of the reporting unit was determined to be less than its carrying

amount under both the market approach and the income approach using a discounted cash flow valuation model. The significant assumptions included commodity price curves, estimated electricity to be demanded by its customers, changes in its customer base through attrition and expansion, discount rates, the assumed tax structure and the level of working capital required to operate the business.

In Step 2 of the interim impairment test, the goodwill was determined to have an implied fair value of zero after the hypothetical purchase price allocation; thus the Company accordingly recognized a full impairment of the $136 million in goodwill at the DPLER reporting unit during the three months ended March 31, 2014. DPLER is reported in the US SBU reportable segment.

Buffalo Gap — During the first quarter of 2014, the Company recognized an $18 million impairment of its goodwill at its Buffalo Gap reporting unit, which is composed of three wind projects in Texas with an aggregate generation capacity of 524 MW, and is reported in the US SBU reportable segment.

15. ASSET IMPAIRMENT EXPENSE



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
DP&L (East Bend)	$	—	$	—	$	—	$	12
Ebute	—		52		—		52
UK Wind	37		11		37		11
Other	—		—		8		$	—
Total asset impairment expense	$	37	$	63	$	45	$	75

UK Wind (Development Projects) — During the second quarter of 2015, the Company decided to no longer pursue two wind projects in the United Kingdom based on recent regulatory clarifications specific to these projects, resulting in a full impairment. Impairment indicators were also identified at four other wind projects based on their current development status and a reassessment of the likelihood that each project would be pursued given aviation concerns, regulatory changes, economic considerations and other factors. The Company determined that the carrying amounts of each of these asset groups, which totaled $38 million, were not recoverable. In aggregate, the asset groups were determined to have a fair value of $1 million using the market approach and, as a result, the Company recognized asset impairment expense of $37 million. The UK Wind projects are reported in the Europe SBU reportable segment.

DP&L (East Bend) — During the first quarter of 2014, the Company tested the recoverability of long-lived assets at East Bend, a 186 MW coal-fired plant in Ohio jointly owned by DP&L (a wholly owned subsidiary of AES). Indications during that quarter that the fair value of the asset group was less than its carrying amount were determined to be impairment indicators given how narrowly these long-lived assets had passed the recoverability test during the fourth quarter of 2013. During the first quarter of 2014, the Company determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2 million using the market approach. As a result, the Company recognized asset impairment expense of $12 million. The Company’s interest in East Bend was sold in December 2014. Prior to its sale, East Bend was reported in the US SBU reportable segment.

Ebute — During the second quarter of 2014, the Company identified impairment indicators at Ebute in Nigeria, resulting from the continued lack of gas supply and the increased likelihood of selling the asset group before the end of its useful life. The Company determined that the carrying amount of the asset group was not recoverable. The Ebute asset group was determined to have a fair value of $47 million using primarily the market approach based on indications about the proceeds that could be received from a future sale, the amount of cash flows estimated to be received until that sale under its power purchase agreement and the amount of cash on hand. As a result, the Company recognized an asset impairment expense of $52 million. In November 2014, the Company completed the sale of its interest in Ebute. Prior to its sale, Ebute was reported in the Europe SBU reportable segment.

UK Wind (Newfield) — During the second quarter of 2014, the Company tested the recoverability of long-lived assets at its Newfield wind development project in the United Kingdom after the UK government refused to grant a permit necessary for the project to continue. The Company determined that the carrying amount of the asset group was not recoverable. The Newfield asset group was determined to have no fair value using the income approach. As a result, the Company recognized an asset impairment expense of $11 million. UK Wind (Newfield) is reported in the Europe SBU reportable segment.

16. OTHER NON-OPERATING EXPENSE

There was no other non-operating expense for the three and six months ended June 30, 2015.

Silver Ridge — On June 16, 2014, the Company executed an agreement to sell its 50% ownership interest in Silver Ridge Power, LLC (“SRP”) for a purchase price of $165 million, subject to certain purchase price adjustments, and excluding the Company’s indirect ownership interests in SRP’s solar generation businesses in Italy, Puerto Rico and Spain. SRP is a solar power joint venture of AES and Riverstone Holdings LLC with each partner having a 50% ownership interest in SRP. As a

result of the Company's continuing interests and involvement in SRP's solar generation businesses in Italy, Puerto Rico, and Spain, the transaction will not result in a sale for accounting purposes until all continuing involvement by AES has been eliminated. The buyer also has an option to purchase the Company's indirect 50% interest in the Italy solar generation business for additional consideration of $42 million by August 2015.

During the second quarter of 2014, the Company determined that there was a decline in the fair value of its equity method investment in SRP that was other than temporary based on indications about the fair value of the projects in Italy and Spain that resulted from actual and proposed changes to their tariffs. As a result, the Company recognized a pretax impairment loss of $44 million in other non-operating expense in the second quarter of 2014. The sale of the 50% ownership interest in SRP closed on July 2, 2014 for $179 million, including purchase price adjustments.

17. DISCONTINUED OPERATIONS AND HELD-FOR-SALE BUSINESSES

As discussed in Note 1—Financial Statement Presentation, effective July 1, 2014, the Company prospectively adopted ASU No. 2014-08. There have been no businesses classified as a discontinued operation subsequent to the adoption of the new accounting standard.

The following table summarizes the revenue, income from operations, income tax expense, impairment and loss on disposal of all businesses classified as a discontinued operation prior to the adoption of ASU No. 2014-08 for the periods indicated:



	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
	(in millions)
Revenue	$	—	$	104		$	—	$	233
Income from operations of discontinued businesses, before income tax	$	—	$	15		$	—	$	49
Income tax expense	—		(8		)	—		(22		)
Income from operations of discontinued businesses, after income tax	$	—	$	7		$	—	$	27
Net loss from disposal & impairments of discontinued businesses, after income tax	$	—	$	(13	)	$	—	$	(56	)

U.S. wind projects — In November 2013, the Company executed an agreement for the sale of its 100% membership interests in three wind projects with an aggregate generation capacity of 234 MW: Condon in California, Lake Benton I in Minnesota and Storm Lake II in Iowa. The sale transaction closed on January 30, 2014 and net proceeds of $27 million were received. These wind projects were previously reported in the US SBU reportable segment.

Under the terms of the sale agreement, the buyer was provided an option to purchase the Company's 100% interest in Armenia Mountain, a 101 MW wind project in Pennsylvania, at a fixed price of $75 million. Approximately $3 million of the $27 million net proceeds was deferred and allocated to this option.

The buyer exercised the option on March 31, 2015 and the sale was completed on July 1, 2015. Accordingly, Armenia Mountain has been classified as held-for-sale as of June 30, 2015, but does not meet the criteria to be reported as a discontinued operation. Armenia Mountain’s results are therefore reflected within continuing operations in the Condensed Consolidated Statements of Operations. Armenia Mountain’s pretax income attributable to AES was $2 million and $6 million, respectively, for the three and six months ended June 30, 2015, and $2 million and $5 million, respectively, for the three and six months ended June 30, 2014. Armenia Mountain is reported in the US SBU reportable segment.

Saurashtra — In October 2013, the Company executed a sale agreement for the sale of its wholly owned subsidiary AES Saurashtra Private Ltd, a 39 MW wind project in India. The sale transaction closed on February 24, 2014 and net proceeds of $8 million were received. Saurashtra was previously reported in the Asia SBU reportable segment.

Cameroon — In September 2013, a subsidiary of the Company executed 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.). In June 2014, the Company sold its entire equity interest in all three businesses in Cameroon. Net proceeds from the sale transaction were $200 million with $156 million received and non-contingent consideration of $44 million to be received in 2016. The carrying amount of $44 million, which approximates fair value, and is secured by a $40 million letter of credit from a well-capitalized, multinational bank. Between meeting the held-for-sale criteria in September 2013 through the first quarter of 2014, the Company recognized impairment charges totaling $101 million, representing the difference between the aggregate carrying amount of $435 million and fair value less costs to sell of $334 million. During the second quarter of 2014, the Company recognized an additional loss on sale of $7 million. These businesses were previously reported in the Europe SBU reportable segment.

18. ACQUISITIONS

Main Street Power — On February 18, 2015, the Company completed the acquisition of the 100% of the common stock of Main Street Power Company, Inc. for approximately $25 million pursuant to the terms and condition of a definitive

agreement dated January 24, 2015. The purchase consideration was comprised of cash of $20 million and the fair value of earn-out payments of $5 million. At June 30, 2015, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. The Company is in the process of obtaining additional information to measure all assets acquired and liabilities assumed in the acquisition within the measurement period, which could be up to one year from the date of acquisition. The preliminary purchase price allocation has resulted in the recognition of $14 million of goodwill. Subsequent changes to the fair value of earn-out payments will be reflected in earnings.

19. 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 RSUs, 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 periods indicated. In the table below, income represents the numerator and weighted average shares represent the denominator:



	Three Months Ended June 30,
	2015					2014
	Income		Shares	$ per Share		Income		Shares	$ per Share
	(in millions except per share data)
BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders	$	69	693	$	0.10	$	142	725	$	0.20
EFFECT OF DILUTIVE SECURITIES
Stock options	—		—	—		—		1	—
Restricted stock units	—		2	—		—		2	—
DILUTED EARNINGS PER SHARE	$	69	695	$	0.10	$	142	728	$	0.20



	Six Months Ended June 30,
	2015					2014
	Income		Shares	$ per Share		Income		Shares	$ per Share
	(in millions except per share data)
BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders	$	211	698	$	0.30	$	95	725	$	0.13
EFFECT OF DILUTIVE SECURITIES
Stock options	—		1	—		—		1	—
Restricted stock units	—		2	—		—		2	—
DILUTED EARNINGS PER SHARE	$	211	701	$	0.30	$	95	728	$	0.13

For the three and six months ended June 30, the calculation of diluted earnings per share excluded 6 million and 7 million outstanding stock awards for 2015 and 2014, respectively, that could potentially dilute basic earnings per share in the future. Additionally, for the three and six months ended June 30, 2015 and 2014, all 15 million shares of potential common stock associated with convertible debentures were omitted from the earnings per share calculation. These were not included because the impact would have been anti-dilutive.

20. SUBSEQUENT EVENTS

Armenia Mountain Wind — On July 1, 2015, the Company completed the sale of its interest in Armenia Mountain Wind and received net proceeds of $70 million. The Company expects to recognize a gain on this transaction in the third quarter of 2015. See Note 17—Discontinued Operations and Held-for-Sale Businesses for additional information.

Stock Repurchase Program — Subsequent to June 30, 2015, the Parent Company repurchased an additional 2.2 million shares at a cost of $29 million, bringing the cumulative repurchases total from July 2010 through August 7, 2015 to 131.7 million shares for a total cost of $1.6 billion, at an average price per share of $12.48 (including a nominal amount of commissions). As of August 7, 2015, $88 million remains available under the Program. See Note 11—Equity for additional information.

Dividends — On July 10, 2015, the Parent Company’s Board of Directors declared a dividend of $0.10 per outstanding common share payable on August 17, 2015 to the shareholders of record at the close of business on August 3, 2015.

Solar Spain — On July 29, 2015, the Company signed an agreement to sell all of its 50% interest in Solar Spain, an equity method investment with 31 MW peak capacity in operations, for approximately $32 million, subject to customary closing conditions.

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”, “the Parent Company”, or “the Parent” 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 2014 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 2014 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 SBUs:


•	US (United States),


•	Andes (Chile, Colombia, and Argentina),


•	Brazil,


•	MCAC (Mexico, Central America and the Caribbean),


•	Europe (Europe and Middle East), and


•	Asia.

For additional information regarding our business, see Item 1.—Business of our 2014 Form 10-K.

Within our six SBUs listed above, we have two lines of business. The first business line is generation, where we own and/or operate power plants to generate and sell power to customers such as utilities, industrial users, and other intermediaries. The second business line is utilities, where we own and/or operate utilities to generate or purchase, distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market.

Key Topics in Management’s Discussion and Analysis — Our discussion covers the following:


•	Overview of Q2 2015 Results and Strategic Performance


•	Review of Consolidated Results of Operations


•	Non-GAAP Measures and SBU Analysis


•	Key Trends and Uncertainties


•	Capital Resources and Liquidity

Overview of Q2 2015 Results and Strategic Performance

Management’s Strategic Priorities — Management is focused on the following priorities:


•	Reducing complexity: By exiting businesses and markets where we do not have a competitive advantage, we are simplifying our portfolio and reducing risk.

•

Leveraging our platforms: Focusing our growth on platform expansions, including adjacencies, in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns. We currently have 5,859 MW under construction. These projects represent $7 billion in total capital expenditures, with the majority of AES’ $1.3 billion in equity already funded and are on track to come online from 2015 through 2018.


◦	During the second quarter, we brought on-line the 1,240 MW coal-fired Mong Duong 2 project in Vietnam, which has a 25-year PPA with EVN, the state-owned utility.


•	Performance excellence: We strive to be the low-cost manager of a portfolio of assets and to derive synergies and scale

from our businesses.

•

Expanding access to capital: By building strategic partnerships at the project and business level. Through these partnerships, we aim to optimize our risk-adjusted returns in our existing businesses and growth projects. By selling down portions of certain businesses, we can adjust our global exposure to commodity, fuel, country and other macroeconomic risks. Partial sell-downs of our assets can also serve to highlight or enhance the value of businesses in our portfolio.


◦	During the second quarter, CDPQ invested $214 million in IPALCO, the Parent Company of IPL in Indiana. We expect CDPQ to invest an additional $135 million in IPALCO by 2016. After completion of this investment, CDPQ’s direct and indirect interests in IPALCO will total 30%. There will be no change in management or operational control of IPALCO as a result of these transactions.


•	Allocating capital in a disciplined manner: Our top priority is to maximize risk-adjusted returns to our shareholders, which we achieve by investing our discretionary cash and recycling the capital we receive from asset sales and strategic partnerships.


◦	In the second quarter of 2015, we invested $271 million by repurchasing 21 million shares, including repurchasing 20 million shares from China Investment Corporation in May 2015.


◦	In the first six months of 2015, we repurchased 24 million shares for $306 million and in July and August 2015, we repurchased 2.2 million shares for $29 million. We currently have $88 million of authorization available for further buybacks.


◦	In the first six months of 2015, we paid $141 million in shareholder dividends and made $279 million of investments in our subsidiaries.

Q2 2015 Strategic Performance

Earnings Per Share Results in Q2 2015



	Three Months Ended June 30,									Six Months Ended June 30,
	2015		2014		Change			% Change		2015		2014		Change			% Change
Diluted earnings per share from continuing operations	$	0.10	$	0.20	$	(0.10	)	-50	%	$	0.30	$	0.13	$	0.17		131	%
Adjusted EPS (a non-GAAP measure)⁽¹⁾	$	0.25	$	0.28	$	(0.03	)	-11	%	$	0.50	$	0.53	$	(0.03	)	-6	%

_____________________________


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

Three Months Ended June 30, 2015

Diluted earnings per share from continuing operations decreased $0.10, or 50%, to $0.10 primarily due to the timing of planned maintenance at certain businesses, unfavorable foreign currency exchange, lower demand and contracting strategy in Brazil, the net impact from the reversal of liabilities in Brazil and Europe, and increased debt extinguishment expense of $0.11 primarily related to costs incurred to retire and refinance near-term debt maturities. These negative impacts were partially offset by lower impairment expense, improved hydrology in Panama and Colombia, lower interest expense at the Parent Company, lower share count, and a lower effective tax rate.

Adjusted EPS, a non-GAAP measure, decreased $0.03, or 11%, to $0.25 primarily due to the timing of planned maintenance at certain businesses, unfavorable foreign currency exchange, lower demand and contracting strategy in Brazil, and the net impact from the reversal of liabilities in Brazil and Europe. These negative impacts were partially offset by improved hydrology in Panama and Colombia, lower interest expense at the Parent Company, lower share count, and a lower adjusted effective tax rate.

Six Months Ended June 30, 2015

Diluted earnings per share from continuing operations increased $0.17, or 131%, to $0.30 primarily due to $0.21 of lower impairment expense, contributions from new businesses, improved hydrology in Panama and Colombia, lower interest expense at the Parent Company, lower share count, and a lower effective tax rate. These increases were partially offset by the effects of unfavorable foreign currency exchange, lower demand and contracting strategy in Brazil, and the net impact from the reversal of liabilities in Brazil and Europe.

Adjusted EPS, a non-GAAP measure, decreased $0.03, or 6%, to $0.50 primarily due to the effects of unfavorable foreign currency exchange, lower demand and contracting strategy in Brazil, and the net impact of the reversal of liabilities in Brazil and Europe. These negative impacts were partially offset by contributions from new businesses, improved hydrology in Panama and Colombia, lower interest expense at the Parent Company, lower share count, and a lower adjusted effective tax rate.

Capital Management and Allocation

We continue to focus on improving cash generation and optimizing the use of our parent discretionary cash. During the

second quarter of 2015, we generated $153 million of cash flow from operating activities. We utilized cash consistent with our strategy, as we paid a quarterly dividend of $70 million ($0.10 per share), repurchased common stock under the existing stock repurchase program at a total cost of $271 million, and refinanced $500 million of recourse debt at the Parent Company.

Safe, Reliable and Sustainable Operations

Our safety performance was down in the second quarter of 2015 for lost-time incident case rates for both employees and operational contractors. However, safety is our first value and a top priority. We consistently analyze and evaluate our safety performance in order to capture lessons learned and strengthen mitigation plans that improve our safety performance.

Generation in GWh was down 4% compared to the first six months of 2014, mainly driven by dry hydrological conditions in Brazil and higher unplanned outages at our generation plants in Indiana and Ohio.

Compared to the first half of 2014, our KPIs performance was mixed, as our generation KPIs declined while indicators for our utilities improved. Our CA and heat rate performance deteriorated, largely driven by unplanned outages at our generation plants in Ohio and longer maintenance at our generation plants in the Dominican Republic and Chile. Most of the unplanned outage events have been resolved and mitigation plans have been implemented. For utilities, our performance on SAIFI and non-technical losses improved compared to the first half of 2014. The table below presents our KPIs for the periods indicated.



	For the Six Months Ended June 30,
KPIs	2015		2014		Variance
Safety: Employee Lost-Time Incident Case Rate	0.134		0.120		-12	%
Safety: Operational Contractor Lost-Time Incident Case Rate	0.127		0.051		-149	%
Generation
Commercial Availability (CA, %)	87.9	%	91.3	%	-3.4	%
Equivalent Forced Outage Factor (EFOF, %)	3.3	%	3.9	%	0.6	%
Heat Rate (BTU/kWh)	10,058		9,796		-262
Utility
System Average Interruption Duration Index (SAIDI, hours)	5.8		5.8		—
System Average Interruption Frequency Index (SAIFI, number of interruptions)	3.3		3.7		0.4
Non-Technical Losses (%)	1.8	%	2.0	%	0.2	%

_________________________________________________

Definitions:


•	Lost-Time Incident Case Rate: Number of lost-time cases per number of full-time employees or contractors.


•	CA: Actual variable margin, as a percentage of potential variable margin if the unit had been available at full capacity during outages.


•	EFOF: The percentage of the time that a plant is not capable of producing energy due to unplanned operational reductions in production.


•	Heat Rate: The amount of energy used by an electrical generator or power plant to generate one kWh.


•	SAIDI: The total hours of interruption the average customer experiences annually. Trailing 12-month average.


•	SAIFI: The average number of interruptions the average customer experiences annually. Trailing 12-month average.


•	Non-Technical Losses: Delivered energy that was not billed due to measurement error, theft or other reasons. Trailing 12-month average.



Review of Consolidated Results of Operations	Three Months Ended June 30,											Six Months Ended June 30,
	2015			2014			$ change			% change		2015			2014			$ change			% change
	($ in millions, except per share amounts)
Revenue:
US SBU	$	831		$	893		$	(62	)	-7	%	$	1,828		$	1,894		$	(66	)	-3	%
Andes SBU	630			724			(94		)	-13	%	1,242			1,344			(102		)	-8	%
Brazil SBU	1,315			1,533			(218		)	-14	%	2,645			2,978			(333		)	-11	%
MCAC SBU	601			692			(91		)	-13	%	1,199			1,330			(131		)	-10	%
Europe SBU	299			305			(6		)	-2	%	629			696			(67		)	-10	%
Asia SBU	187			163			24			15	%	306			331			(25		)	-8	%
Corporate and Other	6			5			1			20	%	10			7			3			43	%
Intersegment eliminations	(11		)	(4		)	(7		)	175	%	(17		)	(7		)	(10		)	143	%
Total Revenue	3,858			4,311			(453		)	-11	%	7,842			8,573			(731		)	-9	%
Operating Margin:
US SBU	125			144			(19		)	-13	%	298			278			20			7	%
Andes SBU	119			148			(29		)	-20	%	250			239			11			5	%
Brazil SBU	223			270			(47		)	-17	%	400			591			(191		)	-32	%
MCAC SBU	165			146			19			13	%	268			235			33			14	%
Europe SBU	64			77			(13		)	-17	%	167			210			(43		)	-20	%
Asia SBU	47			27			20			74	%	71			37			34			92	%
Corporate and Other	12			4			8			200	%	24			26			(2		)	-8	%
Intersegment eliminations	(1		)	3			(4		)	-133	%	(3		)	(3		)	—			—	%
Total Operating Margin	754			819			(65		)	-8	%	1,475			1,613			(138		)	-9	%
General and administrative expenses	(50		)	(52		)	2			-4	%	(105		)	(103		)	(2		)	2	%
Interest expense	(310		)	(323		)	13			-4	%	(673		)	(696		)	23			-3	%
Interest income	133			73			60			82	%	223			136			87			64	%
Loss on extinguishment of debt	(122		)	(15		)	(107		)	713	%	(145		)	(149		)	4			-3	%
Other expense	(14		)	(17		)	3			-18	%	(34		)	(25		)	(9		)	36	%
Other income	15			33			(18		)	-55	%	31			45			(14		)	-31	%
Goodwill impairment expense	—			—			—			—	%	—			(154		)	154			-100	%
Asset impairment expense	(37		)	(63		)	26			-41	%	(45		)	(75		)	30			-40	%
Foreign currency transaction gains (losses)	15			7			8			114	%	(8		)	(12		)	4			-33	%
Other non-operating expense	—			(44		)	44			-100	%	—			(44		)	44			-100	%
Income tax expense	(120		)	(157		)	37			-24	%	(216		)	(211		)	(5		)	2	%
Net equity in earnings of affiliates	—			20			(20		)	-100	%	15			45			(30		)	-67	%
INCOME FROM CONTINUING OPERATIONS	264			281			(17		)	-6	%	518			370			148			40	%
Income from operations of discontinued businesses, net of income tax expense of $0, $8, $0 and $22, respectively	—			7			(7		)	-100	%	—			27			(27		)	-100	%
Net loss from disposal and impairments of discontinued businesses, net of income tax expense (benefit) of $0, $5, $0 and $4, respectively	—			(13		)	13			-100	%	—			(56		)	56			-100	%
NET INCOME	264			275			(11		)	-4	%	518			341			177			52	%
Noncontrolling interests:
Less: (Income) from continuing operations attributable to noncontrolling interests	(195		)	(139		)	(56		)	40	%	(307		)	(275		)	(32		)	12	%
Less: (Income) loss from discontinued operations attributable to noncontrolling interests	—			(3		)	3			-100	%	—			9			(9		)	-100	%
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	69		$	133		$	(64	)	-48	%	$	211		$	75		$	136		181	%
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	69		$	142		$	(73	)	-51	%	$	211		$	95		$	116		122	%
Loss from discontinued operations, net of tax	—			(9		)	9			-100	%	—			(20		)	20			-100	%
Net income	$	69		$	133		$	(64	)	-48	%	$	211		$	75		$	136		181	%
Net cash provided by operating activities	$	153		$	232		$	(79	)	-34	%	$	590		$	453		$	137		30	%
DIVIDENDS DECLARED PER COMMON SHARE	$	0.10		$	0.05		$	0.05		100	%	$	0.10		$	0.05		$	0.05		100	%

Components of Revenue, Cost of Sales and Operating Margin — Revenue includes revenue earned from the sale of energy from our utilities and the production of energy from our generation plants, which are classified as regulated and non-regulated on the Consolidated Statements of Operations, respectively. Revenue also includes the gains or losses on derivatives associated with the sale of electricity.

Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, O&M costs, depreciation and amortization expense, bad debt expense and recoveries, general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.

Operating margin is defined as revenue less cost of sales.

Three months ended June 30, 2015:

Consolidated Revenue — Revenue decreased $453 million, or 11%, to $3.9 billion in the three months ended June 30, 2015 compared with $4.3 billion in the three months ended June 30, 2014, including unfavorable foreign exchange impacts of

$657 million. The decrease in revenue was driven primarily by the key operating drivers at the following businesses:


•	US — An overall decrease of $62 million driven by:


◦	Lower wholesale volumes at IPL in Indiana due to a decrease in demand as a result of milder temperatures during 2015 compared to 2014 and lower pass-through costs;


◦	The sale of the MC² business in April 2015, which reduced volumes at DPL in Ohio;


◦	Increased customer switching at DPL, milder temperatures during 2015 compared to 2014 and lower retail prices, which were partially offset by higher capacity prices;


◦	Higher outages and lower dispatch at Hawaii; and


◦	Lower production and prices at Wind businesses.


•	Andes — An overall decrease of $94 million driven by:


◦	Unfavorable foreign exchange impacts of $52 million, primarily at Chivor in Colombia; and


◦	Lower spot and contract sales at Gener in Chile.


•	Brazil — An overall decrease of $218 million driven by:


◦	Unfavorable foreign exchange impacts of $570 million; and


◦	Higher contracted volumes sold by Tietê to Eletropaulo in 2015 compared to sales in the spot market in 2014.


◦	The results above were partially offset at Eletropaulo, driven by the reversal of a contingent regulatory liability and a higher tariff. See Key Trends and Uncertainties—Regulatory of this Form 10-Q for further information.


•	MCAC — An overall decrease of $91 million driven by:


◦	Lower LNG sales to third parties and lower PPA and spot prices in the Dominican Republic;


◦	Lower pass-through costs at El Salvador; and


◦	Lower availability, lower pass-through costs, and unfavorable foreign exchange impacts at Mexico.


•	Europe — An overall decrease of $6 million driven by:


◦	Unfavorable foreign exchange impacts of $31 million (primarily at Maritza in Bulgaria and Northern Ireland in the UK);


◦	Lower dispatch, the timing of outages, and lower prices at Kilroot in the UK;


◦	The sales of UK Wind and Ebute in Nigeria in August and November 2014, respectively; and


◦	Lower pass-through costs at Amman East in Jordan.


◦	The results above were partially offset by new operations at IPP4 in Jordan (commencing in July 2014), the timing of outages at Maritza, and higher generation and prices at Kazakhstan.


•	Asia — An overall increase of $24 million driven by:


◦	Contributions from Mong Duong in Vietnam, which commenced its principal operations in April 2015.


◦	The results above were partially offset by Kelanitissa in Sri Lanka which has not been dispatched in 2015, and Masinloc in the Philippines due to lower pass-through costs.

Consolidated Operating Margin — Operating margin decreased $65 million, or 8%, to $754 million in the three months ended June 30, 2015 compared with $819 million in the three months ended June 30, 2014, including unfavorable foreign exchange impacts of $114 million. The decrease in operating margin was driven primarily by the key operating drivers at the following businesses:


•	US — An overall decrease of $19 million driven by:


◦	Higher outages and related fixed costs at Hawaii;


◦	Lower production and prices at Wind businesses; and


◦	Lower wholesale margins at IPL.


◦	The results above were partially offset at DPL, primarily due to the impact of increased net capacity prices and lower fixed costs.


•	Andes — An overall decrease of $29 million driven by:


◦	Unfavorable foreign exchange impacts of $17 million (primarily at Chivor);


◦	The timing of planned outages and related costs at Gener;


◦	Lower contract prices in Chile and higher gas prices at TermoAndes; and


◦	The timing of planned maintenance and higher fixed costs due to inflation at Argentina.


◦	The results above were partially offset by higher generation at Chivor.


•	Brazil — An overall decrease of $47 million driven by:


◦	Unfavorable foreign exchange impacts of $88 million;


◦	Higher contracted volumes at Tietê sold to Eletropaulo in the second quarter of 2015 compared to sales in the spot market in the second quarter of 2014; and


◦	Higher fixed costs, lower volumes, and a favorable 2014 true-up of subsidies at Sul.


◦	The results above were partially offset at Eletropaulo, driven by the reversal of a contingent regulatory liability and a higher tariff.


•	MCAC — An overall increase of $19 million driven by:


◦	Improved hydrological conditions and the commencement of power barge operations at Panama, which resulted in higher generation and lower energy purchases.


◦	The results above were partially offset at the Dominican Republic, driven by lower availability arising from higher outages, and at Mexico due to higher fuel costs and lower availability.


•	Europe — An overall decrease of $13 million driven by:


◦	Unfavorable foreign exchange impacts of $9 million;


◦	Lower dispatch, lower prices and the timing of planned outages in Kilroot; and


◦	The sales of UK Wind and Ebute as discussed above.


◦	The results above were partially offset by higher volumes and prices driven by improved hydrology at Kazakhstan, new operations at IPP4 in Jordan, and the timing of planned outages at Maritza.


•	Asia — An overall increase of $20 million driven by:


◦	Better availability at Masinloc; and


◦	Mong Duong due to the commencement of its principal operations in April 2015.

Six months ended June 30, 2015:

Consolidated Revenue — Revenue decreased $731 million, or 9%, to $7.8 billion in the six months ended June 30, 2015 compared with $8.6 billion in the six months ended June 30, 2014, including unfavorable foreign exchange impacts of $1.1 billion. The decrease in revenue was driven primarily by the key operating drivers at the following businesses:


•	US — An overall decrease of $66 million driven by:


◦	Lower wholesale volumes at IPL due to higher outages, lower pass-through costs, and a decrease in demand as a result of milder temperatures during 2015 compared to 2014;


◦	The sale of the MC² business in April 2015, which reduced volumes at DPL;


◦	Increased customer switching at DPL; and


◦	Lower production and prices at Wind businesses.


◦	The results above were partially offset by higher capacity, wholesale and retail prices at DPL.


•	Andes — An overall decrease of $102 million driven by:


◦	Unfavorable foreign exchange impacts of $85 million, primarily at Chivor; and


◦	Lower spot sales and prices at Gener.


◦	The results above were partially offset by new contracts at Gener and higher generation at Chivor.


•	Brazil — An overall decrease of $333 million driven by:


◦	Unfavorable foreign exchange impacts of $898 million; and


◦	Higher contracted volumes at Tietê sold to Eletropaulo in the first half of 2015 compared to sales in the spot market in the first half of 2014.


◦	The results above were partially offset at Eletropaulo, driven by the reversal of a contingent regulatory liability and a higher tariff. Additionally, Uruguaiana benefited from a longer period of operations and higher pass-through costs.


•	MCAC — An overall decrease of $131 million driven by:


◦	Lower prices in the Dominican Republic, primarily related to lower LNG sales to third parties, lower PPA and spot prices, and lower availability;


◦	A decrease in energy pass-through costs at El Salvador; and


◦	Lower availability, lower pass-through costs, and unfavorable foreign exchange impacts at Mexico.


•	Europe — An overall decrease of $67 million driven by:


◦	Unfavorable foreign exchange impacts of $66 million (primarily at Maritza and Northern Ireland);


◦	Lower dispatch, the timing of planned outages, and prices at Kilroot;


◦	Lower pass-through costs at Amman East in Jordan; and


◦	The sale of the UK Wind business and Ebute in August and November 2014, respectively.


◦	The results above were partially offset by the commencement of operations at IPP4 in Jordan in July 2014.


•	Asia — An overall decrease of $25 million driven by:


◦	Kelanitissa not being dispatched in 2015; and


◦	Lower pass-through costs at Masinloc.


◦	The results above were partially offset by contributions from Mong Duong, which commenced its principal operations in April 2015.

Consolidated Operating Margin — Operating margin decreased $138 million, or 9%, to $1.5 billion in the six months ended June 30, 2015 compared with $1.6 billion in the six months ended June 30, 2014, including unfavorable foreign exchange impacts of $177 million. The decrease in operating margin was driven primarily by the key operating drivers at the following businesses:


•	US — An overall increase of $20 million driven by:


◦	Increased capacity prices, lower fixed costs, and higher margin at DPL, primarily due to outages and lower gas availability in the first quarter of 2014.


◦	The results above were partially offset by lower production at the US Wind businesses, lower availability and dispatch in Hawaii, and lower wholesale margin at IPL.


•	Andes — An overall increase of $11 million driven by:


◦	A new tolling agreement and higher capacity revenue in Gener related to a settlement occurring in the first quarter of 2014; and


◦	Higher prices in Argentina due to the impact of Resolution 482 in the second quarter 2015, which updated Resolution 529 passed in May 2014.


◦	The results above were partially offset by unfavorable foreign exchange impacts of $27 million (primarily at Chivor), and lower generation, higher planned outages, and higher fixed costs (driven by inflation) in Argentina.


•	Brazil — An overall decrease of $191 million driven by:


◦	Unfavorable foreign exchange impacts of $126 million;


◦	Higher contracted volumes sold by Tietê to Eletropaulo in the first half of 2015 compared to sales in the spot market in the first half of 2014; and


◦	Higher fixed costs and lower volumes at Sul.


◦	The results above were partially offset at Eletropaulo, driven by the reversal of a contingent regulatory liability and a higher tariff.


•	MCAC — An overall increase of $33 million driven by:


◦	Improved hydrological conditions and the commencement of power barge operations at Panama, which resulted in higher generation and lower energy purchases; and


◦	A one-time unfavorable adjustment in 2014 to unbilled revenue in El Salvador.


◦	The results above were partially offset by lower PPA and spot sales in the Dominican Republic triggered by higher outages and higher purchases; and higher fuel costs, lower availability, and unfavorable foreign exchange impacts in Mexico.


•	Europe — An overall decrease of $43 million driven by:


◦	Unfavorable foreign exchange impacts of $23 million;


◦	Lower dispatch, the timing of planned outages, and prices at Kilroot; and


◦	The sales of UK Wind and Ebute as discussed above.


◦	The results above were partially offset by higher volumes and prices due to improved hydrology in Kazakhstan, new operations at IPP4 in Jordan, and the timing of planned outages in Maritza.


•	Asia — An overall increase of $34 million driven by:


◦	Higher availability at Masinloc in 2015 and an unfavorable impact occurring in the first quarter of 2014 due to the market operator’s retrospective adjustment to energy prices calculated in November and December 2013; and


◦	Mong Duong due to the commencement of its principal operations in April 2015.

General and administrative expenses

General and administrative expenses decreased $2 million, or 4%, to $50 million for the three months ended June 30, 2015 primarily due to decreased professional fees partially offset by increased employee-related costs.

General and administrative expenses increased $2 million, or 2%, to $105 million for the six months ended June 30, 2015 primarily due to increased business development costs and employee-related costs partially offset by decreased professional fees.

Interest expense

Interest expense decreased $13 million, or 4%, to $310 million for the three months ended June 30, 2015. The decrease was primarily due to the reversal of $64 million in interest expense previously recognized on a contingent regulatory liability at Eletropaulo (see Key Trends and Uncertainties—Regulatory of this Form 10-Q for further information). Additionally, lower interest expense of $21 million at the Parent Company resulted from lower rates and a reduction in principal. These decreases were partially offset by an increase at Sul related to a $47 million reversal of contingent interest accruals in the prior year, and $18 million at Mong Duong as principal operations commenced in April 2015 and interest is no longer capitalized.

Interest expense decreased $23 million, or 3%, to $673 million for the six months ended June 30, 2015. The decrease was primarily due to a reversal of $64 million in interest expense at Eletropaulo discussed above. Additionally, lower interest expense of $36 million at the Parent Company resulted from lower rates and a reduction in principal. These decreases were partially offset by an increase at Sul related to a $47 million reversal of contingent interest accruals in the prior year, and $21 million at Mong Duong as principal operations commenced in April 2015 and interest is no longer capitalized.

Interest income

Interest income increased $60 million, or 82%, to $133 million for the three months ended June 30, 2015. The increase was primarily due to an increase of $34 million at Mong Duong in Vietnam associated with the financing element of its service concession arrangement, $19 million at our utilities in Brazil resulting from higher regulatory asset balances and higher interest rates, and $6 million in Argentina due to increased receivable balances earning interest.

Interest income increased $87 million, or 64%, to $223 million for the six months ended June 30, 2015. The increase was primarily due to an increase of $41 million at Mong Duong in Vietnam associated with the financing element of its service concession arrangement, $32 million at our utilities in Brazil resulting from higher regulatory asset balances and higher interest rates, and $15 million in Argentina due to increased receivable balances earning interest.

Loss on extinguishment of debt

Loss on extinguishment of debt was $122 million and $145 million for the three and six months ended June 30, 2015 and $15 million and $149 million for the three and six months ended June 30, 2014. Amounts in both periods were primarily related to debt extinguishments at the Parent Company. See Note 8—Debt in Item 1.—Financial Statements of this Form 10-Q for further information.

Other income and expense

Other income was $15 million and $31 million for the three and six months ended June 30, 2015 and $33 million and $45 million for the three and six months ended June 30, 2014, respectively.

Other expense was $14 million and $34 million for the three and six months ended June 30, 2015 and $17 million and $25 million for the three and six months ended June 30, 2014, respectively.

See discussion of other income and expense in Note 13—Other Income and Expense in Item 1.—Financial Statements of this Form 10-Q for further information.

Goodwill impairment

There was no goodwill impairment expense for the three and six months ended June 30, 2015. Goodwill impairment expense for the three and six months ended June 30, 2014 was $0 and $154 million, respectively. See Note 14—Goodwill Impairment included in Item 1.— Financial Statements of this Form 10-Q for further information.

Asset impairment expense

Asset impairment expense was $37 million and $45 million for the three and six months ended June 30, 2015 and $63 million and $75 million for the three and six months ended June 30, 2014, respectively. See Note 15—Asset Impairment Expense in Item 1.—Financial Statements of this Form 10-Q for further information.

Foreign currency transaction gains (losses)

Foreign currency transaction gains (losses) were as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Parent Company	$	14		$	(1	)	$	(19	)	$	(3	)
Argentina	2			1			17			(14		)
Other	(1		)	7			(6		)	5
Total ⁽¹⁾	$	15		$	7		$	(8	)	$	(12	)

___________________________________________


⁽¹⁾	Includes $10 million and $10 million of gains on foreign currency derivative contracts for the three months ended June 30, 2015 and 2014, respectively, and $46 million and $43 million of gains on foreign currency derivative contracts for the six months ended June 30, 2015 and 2014, respectively.

The Company recognized net foreign currency transaction gains of $15 million for the three months ended June 30, 2015 primarily due to:


•	a gain of $14 million at the Parent Company resulting from net gains on remeasurement of intercompany notes, partially offset by losses on foreign currency options.

There were no significant foreign currency transaction gains or losses for the three months ended June 30, 2014.

The Company recognized net foreign currency transaction losses of $8 million for the six months ended June 30, 2015 primarily due to:


•	a loss of $19 million at the Parent Company, which was primarily due to net remeasurement losses on intercompany notes, partially offset by gains on foreign currency options; and

•

a gain of $17 million in Argentina, which was primarily related to the favorable impact of foreign currency derivatives associated with government receivables at AES Argentina (an Argentine Peso functional currency subsidiary), partially offset by losses from the remeasurement of U.S. Dollar denominated debt, and losses from the remeasurement of local currency asset balances at Termoandes (a U.S. Dollar functional currency subsidiary).

The Company recognized foreign currency transaction losses of $12 million for the six months ended June 30, 2014 primarily due to:

•

losses of $14 million in Argentina, primarily due to the devaluation of the Argentine Peso against the U.S. Dollar, resulting in remeasurement losses at AES Argentina (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) from the remeasurement of local currency asset balances. These losses were partially offset by the favorable impact of foreign currency embedded derivatives associated with government receivables at AES Argentina.

Other non-operating expense

There was no other non-operating expense for the three and six months ended June 30, 2015. Other non-operating expense was $44 million for the three and six months ended June 30, 2014. See Note 16—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 $37 million, or 24%, to $120 million for the three months ended June 30, 2015 compared to $157 million for the three months ended June 30, 2014. The Company’s effective tax rates were 31% and 38% for the three months ended June 30, 2015 and 2014, respectively.

The net decrease in the effective tax rate for the three months ended June 30, 2015 compared to the same period in 2014 was due, in part, to certain asset impairments recorded during the second quarter of 2014 with no related tax benefit, as well as the release of the valuation allowance at our Vietnam operating subsidiary during the second quarter of 2015. See Note 15—

Asset Impairment Expense in Item 1.—Financial Statements of this Form 10-Q for further information on the asset impairments.

Income tax expense increased $5 million, or 2%, to $216 million for the six months ended June 30, 2015 compared to $211 million for the six months ended June 30, 2014. The Company’s effective tax rates were 30% and 39% for the six months ended June 30, 2015 and 2014, respectively.

The net decrease in the effective tax rate for the six months ended June 30, 2015 compared to the same period in 2014 was due, in part, to the nondeductible goodwill impairments recorded during the first quarter of 2014 and certain asset impairments recorded in the second quarter of 2014 with no related tax benefit. Further, the 2015 effective tax rate benefited from release of the valuation allowance at our Vietnam operating subsidiary. See Note 14—Goodwill Impairment and Note 15—Asset Impairment Expense in Item 1.—Financial Statements of this Form 10-Q for additional information regarding goodwill impairment and asset impairment, respectively.

Our effective tax rate reflects the tax effect of significant operations outside the U.S. which are generally taxed at lower rates than the U.S. statutory rate of 35%. 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 $20 million to zero for the three months ended June 30, 2015. The decrease was primarily due to debt retirement expense incurred at Guacolda in Chile.

Net equity in earnings of affiliates decreased $30 million to $15 million for the six months ended June 30, 2015. The decrease was primarily due to a reduction at Guacolda in Chile resulting from the prior year gain on the sale of transmission assets and the current year recognition of debt retirement expense.

Income from continuing operations attributable to noncontrolling interests

Income from continuing operations attributable to noncontrolling interests increased $56 million, or 40%, to $195 million for the three months ended June 30, 2015. The increase was primarily due to increased earnings at Eletropaulo in Brazil associated with the regulatory liability reversal, increased earnings at Mong Duong in Vietnam as operations commenced in the current year, and an increase at Masinloc in the Philippines resulting from the sale of an additional noncontrolling interest in that business in July 2014 and increased gross margin in the current year.

Income from continuing operations attributable to noncontrolling interests increased $32 million, or 12%, to $307 million for the six months ended June 30, 2015. The increase was primarily due to increased earnings at Eletropaulo in Brazil associated with the regulatory liability reversal, increased earnings at Panama due to better hydrological conditions, increased earnings at Mong Duong in Vietnam as operations commenced in the current year, and increases at Masinloc in the Philippines resulting from the sale of an additional noncontrolling interest in that business in July 2014 and increased gross margin in the current year. These increases were partially offset by decreased earnings at Tietê in Brazil due to lower hydrological production.

Discontinued operations

There were no discontinued operations for the three and six months ended June 30, 2015. Losses from discontinued operations were $6 million and $29 million for the three and six months ended June 30, 2014, respectively. See Note 17—Discontinued Operations and Held-for-Sale Businesses in Item 1.—Financial Statements of this Form 10-Q for further information.

Effective July 1, 2014, the Company prospectively adopted ASU No. 2014-08, which significantly changes the existing accounting guidance on discontinued operations. See Note 1—Financial Statement Presentation in Item 1.—Financial Statements of this Form 10-Q for further information.

Net income attributable to The AES Corporation

Net income attributable to The AES Corporation decreased $64 million to $69 million in the three months ended June 30, 2015 compared to $133 million in the three months ended June 30, 2014. The key drivers of the decrease include:


•	The timing of planned maintenance at certain businesses;


•	Unfavorable foreign currency exchange;


•	Lower demand and contracting strategy in Brazil;


•	The net impact from the reversal of liabilities in Brazil and Europe; and


•	Increased losses from debt extinguishments.

These decreases were partially offset by:


•	Lower impairment expense;


•	Improved hydrology in Panama and Colombia;


•	Lower interest expense at the Parent; and


•	A lower effective tax rate.

Net income attributable to The AES Corporation increased $136 million to $211 million in the six months ended June 30, 2015 compared to $75 million in the six months ended June 30, 2014. The key drivers of the increase include:


•	Lower impairment expense;


•	Improved hydrology in Panama and Colombia;


•	Lower interest expense at the Parent Company; and


•	A lower effective tax rate.

These increases were partially offset by:


•	Unfavorable foreign currency exchange;


•	Lower demand and contracting strategy in Brazil; and


•	The net impact from the reversal of liabilities in Brazil and Europe.

Non-GAAP Measures

Adjusted Operating Margin, Adjusted PTC, Adjusted EPS, and Proportional Free Cash Flow 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.

Adjusted Operating Margin

Operating Margin is defined as revenue less cost of sales. Cost of sales includes costs incurred directly by the businesses in the ordinary course of business, such as:


•	Electricity and fuel purchases,


•	O&M costs,


•	Depreciation and amortization expense,


•	Bad debt expense and recoveries,


•	General administrative and support costs at the businesses, and


•	Gains or losses on derivatives associated with the purchase and sale of electricity or fuel.

We define Adjusted Operating Margin as Operating Margin, adjusted for the impact of noncontrolling interests, excluding unrealized gains or losses related to derivative transactions.

The GAAP measure most comparable to Adjusted Operating Margin is Operating Margin. We believe that Adjusted Operating Margin better reflects the underlying business performance of the Company. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly owned by the Company, as well as the variability due to unrealized derivatives gains or losses. Adjusted Operating Margin should not be construed as an alternative to Operating Margin, which is determined in accordance with GAAP.

Adjusted PTC and Adjusted EPS

We define Adjusted PTC as pretax income from continuing operations attributable to The AES Corporation 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 adjusted for the same gains or losses excluded from consolidated entities.

Adjusted PTC reflects the impact of noncontrolling interests and excludes the items specified in the definition above. In addition to the revenue and cost of sales reflected in Operating Margin, Adjusted PTC includes the other components of our income statement, such as:


•	General and administrative expense in the corporate segment, as well as business development costs;


•	Interest expense and interest income;


•	Other expense and other income;


•	Realized foreign currency transaction gains and losses; and


•	Net equity in earnings of affiliates.

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

The GAAP measure most comparable to Adjusted PTC is income from continuing operations attributable to The AES Corporation. 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 The AES Corporation and diluted earnings per share from continuing operations, which are determined in accordance with GAAP.

Proportional Free Cash Flow

Refer to Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Proportional Free Cash Flow (a non-GAAP measure) for the discussion and reconciliation of Proportional Free Cash Flow to its nearest GAAP measure.

Reconciliations of Non-GAAP Measures



Adjusted Operating Margin	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
	($’s in millions)
US	$	117		$	144	$	292		$	287
Andes	90			116		189			183
Brazil	44			82		84			168
MCAC	136			126		214			223
Europe	57			68		154			195
Asia	22			26		33			36
Corp/Other	12			4		24			26
Intersegment Eliminations	(1		)	3		(3		)	(3		)
Total Adjusted Operating Margin	477			569		987			1,115
Noncontrolling Interests Adjustment	276			243		491			501
Derivatives Adjustment	1			7		(3		)	(3		)
Operating Margin	$	754		$	819	$	1,475		$	1,613



Adjusted PTC⁽¹⁾	Total Adjusted PTC						Intersegment						External Adjusted PTC
Three Months Ended June 30,	2015			2014			2015			2014			2015			2014
	(in millions)
US SBU	$	56		$	80		$	3		$	3		$	59		$	83
Andes SBU	81			104			5			1			86			105
Brazil SBU	41			115			—			—			41			115
MCAC SBU	106			95			5			10			111			105
Europe SBU	41			73			(1		)	3			40			76
Asia SBU	30			23			1			—			31			23
Corporate and Other	(104		)	(150		)	(13		)	(17		)	(117		)	(167		)
Total Adjusted PTC	$	251		$	340		$	—		$	—		$	251		$	340
Reconciliation to Income from continuing operations, net of tax, attributable to The AES Corporation:
Non-GAAP Adjustments:
Unrealized derivative gains													2			22
Unrealized foreign currency gains (losses)													3			(7		)
Disposition/acquisition gains (losses)													4			(2		)
Impairment losses													(30		)	(99		)
Loss on extinguishment of debt													(115		)	(13		)
Pretax contribution													115			241
Income tax expense attributable to The AES Corporation													(46		)	(99		)
Income from continuing operations, net of tax, attributable to The AES Corporation													$	69		$	142



Adjusted PTC ⁽¹⁾	Total Adjusted PTC						Intersegment						External Adjusted PTC
Six Months Ended June 30,	2015			2014			2015			2014			2015			2014
	(in millions)
US SBU	$	162		$	155		$	6		$	6		$	168		$	161
Andes SBU	172			157			8			4			180			161
Brazil SBU	62			184			1			1			63			185
MCAC SBU	156			160			9			14			165			174
Europe SBU	126			188			2			6			128			194
Asia SBU	42			31			1			1			43			32
Corporate and Other	(217		)	(292		)	(27		)	(32		)	(244		)	(324		)
Total Adjusted PTC	$	503		$	583		$	—		$	—		$	503		$	583
Reconciliation to Income from continuing operations, net of tax, attributable to The AES Corporation:
Non-GAAP Adjustments:
Unrealized derivative gains													17			32
Unrealized foreign currency losses													(44		)	(33		)
Disposition/acquisition gains (losses)													9			(1		)
Impairment losses													(36		)	(265		)
Loss on extinguishment of debt													(142		)	(147		)
Pretax contribution													307			169
Income tax expense attributable to The AES Corporation													(96		)	(74		)
Income from continuing operations, net of tax, attributable to The AES Corporation													$	211		$	95

_____________________________


⁽¹⁾	Adjusted PTC 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.



Adjusted EPS	Three Months Ended June 30,								Six Months Ended June 30,
	2015				2014				2015				2014
Diluted earnings per share from continuing operations	$	0.10			$	0.20			$	0.30			$	0.13
Unrealized derivative (gains) losses ⁽¹⁾	—				(0.02		)		(0.02		)		(0.03		)
Unrealized foreign currency transaction (gains) losses ⁽²⁾	—				—				0.04				0.03
Disposition/acquisition (gains) losses	(0.01		)		—				(0.01		)		—
Impairment losses	0.04			⁽³⁾	0.09			⁽⁴⁾	0.05			⁽³⁾	0.26			⁽⁵⁾
Loss on extinguishment of debt	0.12			⁽⁶⁾	0.01			⁽⁷⁾	0.14			⁽⁸⁾	0.14			⁽⁹⁾
Adjusted EPS	$	0.25			$	0.28			$	0.50			$	0.53

_____________________________


⁽¹⁾	Unrealized derivative (gains) losses were net of income tax per share of $0.00 and $(0.01) in the three months ended June 30, 2015 and 2014, and of $(0.01) and $(0.01) in the six months ended June 30, 2015 and 2014, respectively.


⁽²⁾	Unrealized foreign currency transaction (gains) losses were net of income tax per share of $(0.01) and $0.00 in the three months ended June 30, 2015 and 2014, and of $0.02 and $0.01 in the six months ended June 30, 2015 and 2014, respectively.


⁽³⁾	Amount primarily relates to the asset impairment at UK Wind of $37 million ($30 million, or $0.04 per share, net of income tax per share of $0.00).

⁽⁴⁾

Amount primarily relates to the asset impairment at Ebute of $52 million ($34 million, or $0.05 per share, net of income tax per share of $0.02) and at Newfield of $11 million ($6 million, or $0.00 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our Silver Ridge equity method investment of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02).

⁽⁵⁾

Amount primarily relates to the goodwill impairments at DPLER of $136 million ($92 million, or $0.13 per share, net of income tax per share of 0.06), at Buffalo Gap of $18 million ($18 million, or $0.03 per share, net of income tax per share of $0.00) and asset impairments at Ebute of $52 million ($34 million, or $0.05 per share, net of income tax per share of $0.02), at Newfield of $11 million ($6 million, or $0.00 per share, net of income tax per share of $0.00), at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our Silver Ridge equity method investment of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02).

⁽⁶⁾

Amount primarily relates to the loss on early retirement of debt at the Parent Company of $85 million ($58 million, or $0.08 per share, net of income tax per share of $0.04), at IPL of $19 million ($10 million, or $0.01 per share, net of income tax per share of $0.01), at Panama of $16 million ($5 million, or $0.01 per share, net of income tax per share of $0.00) and at Sul of $4 million ($3 million, or $0.00 per share, net of income tax per share of $0.00).


⁽⁷⁾	Amount primarily relates to the loss on early retirement of debt at the Parent Company of $13 million ($8 million, or $0.01 per share, net of income tax per share of $0.01).

⁽⁸⁾

Amount primarily relates to the loss on early retirement of debt at the Parent Company of $111 million ($76 million, or $0.11 per share, net of income tax per share of $0.05), at IPL of $19 million ($10 million, or $0.01 per share, net of income tax per share of $0.01), at Panama of $16 million ($5 million, or $0.01 per share, net of income tax per share of $0.00) and at Sul of $4 million ($3 million, or $0.00 per share, net of income tax per share of $0.00).


⁽⁹⁾	Amount primarily relates to the loss on early retirement of debt at the Parent Company of $145 million ($99 million, or $0.14 per share, net of income tax per share of $0.06).

Operating Margin and Adjusted PTC Analysis

US SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our US SBU for the periods indicated:



	Three Months Ended June 30,										Six Months Ended June 30,
	2015			2014		$ Change			% Change		2015			2014		$ Change		% Change
	($ in millions)
Operating Margin	$	125		$	144	$	(19	)	-13	%	$	298		$	278	$	20	7	%
Noncontrolling Interests Adjustment	(8		)	—							(10		)	—
Derivatives Adjustment	—			—							4			9
Adjusted Operating Margin	$	117		$	144	$	(27	)	-19	%	292			287		$	5	2	%
Adjusted PTC	$	56		$	80	$	(24	)	-30	%	$	162		$	155	$	7	5	%

Operating Margin for the three months ended June 30, 2015 decreased by $19 million, or 13%. The decrease in operating margin was driven primarily by the key operating drivers at the following businesses:


•	US Generation decreased by $23 million, driven by a decrease of $10 million in Hawaii primarily due to higher outages and related fixed costs, and lower production and prices across the US Wind businesses of $8 million; and


•	IPL decreased by $10 million, driven by lower wholesale margin due to outages and lower market prices of electricity.

These decreases were partially offset by:

•

DPL increased by $13 million, driven by lower fixed costs of $8 million due to decreased marketing, employee benefit related costs, and depreciation expense. Additionally, $5 million of the increase was primarily driven by higher capacity prices and decreased transmission and congestion charges. These increases were partially offset by decreased margins as a result of more of DP&L's generation being sold in the wholesale market at lower prices compared to supplying DP&L retail customers in 2014 as required for DP&Ls transition to market.

Adjusted Operating Margin decreased by $27 million for the US SBU due to the drivers above, adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 100% of its businesses in the US with the exception of IPL with ownership of 85% as of March 2015 and 75% as of June 2015. AES owned 100% of IPL in 2014.

Adjusted PTC decreased by $24 million driven by the decrease of $27 million in Adjusted Operating Margin described above.

Operating Margin for the six months ended June 30, 2015 increased by $20 million, or 7%. This increase in operating margin was driven primarily by the key operating drivers following businesses:

•

DPL increased by $58 million, primarily driven by an increase of $38 million due to outages and lower gas availability that occurred in the first quarter of 2014, as well as increased capacity prices and decreased transmission and congestion charges. In addition, fixed costs decreased $20 million driven by decreases in marketing, storm restoration, employee benefit related costs, and depreciation expense.

This increase was partially offset by:


•	US Generation decreased by $28 million, driven primarily by lower production and prices across the US Wind businesses of $19 million, and a decrease of $7 million in Hawaii primarily due to lower availability and dispatch; and


•	IPL decreased by $11 million driven by lower wholesale margin due to outages and lower market prices of electricity.

Adjusted Operating Margin increased by $5 million for the US SBU due to the drivers above, adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 100% of its businesses in the US with the exception of IPL with ownership of 85% as of March 2015 and 75% as of June 2015. AES owned 100% of IPL in 2014.

Adjusted PTC increased by $7 million, driven by the $5 million increase in Adjusted Operating Margin described above.

Andes SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Andes SBU for the periods indicated:



	Three Months Ended June 30,											Six Months Ended June 30,
	2015			2014			$ Change			% Change		2015			2014			$ Change		% Change
	($ in millions)
Operating Margin	$	119		$	148		$	(29	)	-20	%	$	250		$	239		$	11	5	%
Noncontrolling Interests Adjustment	(29		)	(32		)						(61		)	(56		)
Derivatives Adjustment	—			—								—			—
Adjusted Operating Margin	$	90		$	116		$	(26	)	-22	%	$	189		$	183		$	6	3	%
Adjusted PTC	$	81		$	104		$	(23	)	-22	%	$	172		$	157		$	15	10	%

Operating Margin for the three months ended June 30, 2015 decreased by $29 million, or 20%, including unfavorable FX and remeasurement impacts of $17 million. The decrease in operating margin was driven primarily by the key operating drivers at the following businesses:


•	Argentina decreased by $17 million, driven by the timing of planned maintenance and related costs of $11 million, and higher fixed costs of $6 million primarily due to inflation; and


•	Gener decreased by $18 million, driven by the timing of planned outages and related costs of $18 million, lower contract prices in Chile and higher gas prices for Termoandes of $13 million, and higher depreciation expense of $5 million due to new capital investment. These results were partially offset by higher volumes of $19 million due to a new tolling agreement, net of lower hydro generation.

These decreases were partially offset by:


•	Chivor increased by $5 million, driven by higher generation of $15 million primarily due to higher inflows, and lower fixed costs of $7 million due to tunnel maintenance costs that were incurred in 2014. These results were partially offset by an unfavorable FX impact of $14 million.

Adjusted Operating Margin decreased by $26 million due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.

Adjusted PTC decreased by $23 million, driven by the decrease of $26 million in Adjusted Operating Margin described above, as well as lower equity in earnings and realized FX gains in 2014. These results were partially offset by favorable interest expense and realized FX gains at Chivor and recognition of interest income on receivables in Argentina.

Operating Margin for the six months ended June 30, 2015 increased by $11 million, or 5%, including unfavorable FX and remeasurement impacts of $26 million. The increase in operating margin was driven primarily by the key operating drivers at the following businesses:

•

Gener increased by $32 million, driven by a new tolling agreement of $26 million, higher capacity revenue of $5 million driven by a settlement occurring in the first quarter of 2014, and better prices of $8 million driven primarily by lower prices on purchased power. These results were partially offset by higher fixed and other costs of $13 million, primarily related to maintenance and depreciation.

This increase was offset by:


•	Chivor decreased by $15 million, driven by unfavorable FX impacts of $25 million, partially offset by higher generation of $12 million; and


•	Argentina decreased by $7 million, driven by lower generation, higher planned outages and related costs of $12 million, and higher fixed costs of $10 million primarily due to inflation. These results were partially offset by higher prices of $16 million, primarily due to the impact of Resolution 482 in the second quarter of 2015, which updated Resolution 529 passed in May 2014.

Adjusted Operating Margin increased by $6 million due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.

Adjusted PTC increased by $15 million, driven by the increase of $6 million in Adjusted Operating Margin described above, as well as higher recognition of interest income on receivables in Argentina of $15 million and lower interest expense at Chivor. These results were partially offset by lower equity earnings of $17 million from Guacolda in Chile, primarily due to a gain on the sale of a transmission line that occurred in 2014 and a higher income tax rate.

Brazil SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Brazil SBU for the periods indicated:



	Three Months Ended June 30,											Six Months Ended June 30,
	2015			2014			$ Change			% Change		2015			2014			$ Change			% Change
	($ in millions)
Operating Margin	$	223		$	270		$	(47	)	-17	%	$	400		$	591		$	(191	)	-32	%
Noncontrolling Interests Adjustment	(179		)	(188		)						(316		)	(423		)
Derivatives Adjustment	—			—								—			—
Adjusted Operating Margin	$	44		$	82		$	(38	)	-46	%	$	84		$	168		$	(84	)	-50	%
Adjusted PTC	$	41		$	115		$	(74	)	-64	%	$	62		$	184		$	(122	)	-66	%

Operating Margin for the three months ended June 30, 2015 decreased by $47 million, or 17%, including unfavorable FX impacts of $88 million. This decrease was driven primarily by the key operating drivers at the following businesses:


•	Tietê decreased by $104 million, driven by unfavorable FX impacts of $29 million, the net impact of $71 million of higher contracted volumes sold to Eletropaulo in the second quarter of 2015 compared to sales in the spot market in the second quarter of 2014, and higher energy purchases due to lower hydrological production in the system; and


•	Sul decreased by $27 million, driven by higher fixed costs of $11 million, lower volumes of $8 million due to lower demand, and a $7 million favorable true-up of subsidies occurring in 2014.

These decreases were partially offset by:


•	Eletropaulo increased by $81 million, driven by a $97 million ($135 million excluding FX) increase due to the reversal of a contingent regulatory liability, and a higher tariff of $36 million. These results were partially offset by unfavorable FX impacts of $55 million and higher fixed costs of $31 million, primarily due to higher bad debt expense, employee-related costs, and penalties.

Adjusted Operating Margin decreased by $38 million, primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.

Adjusted PTC decreased by $74 million, due to the decrease of $38 million in Adjusted Operating Margin as described above, as well as a reversal of $47 million in contingent interest accruals at Sul in 2014. These results were offset by a reversal of accrued interest expense of $14 million related to the reversal of contingent regulatory liabilities at Eletropaulo as discussed above.

Operating Margin for the six months ended June 30, 2015 decreased by $191 million, or 32%, including unfavorable FX impacts of $126 million. The decrease in operating margin was driven primarily by the key operating drivers at the following businesses:


•	Tietê decreased by $216 million, driven by unfavorable FX impacts of $55 million, the net impact of $161 million due to higher contracted volumes sold to Eletropaulo in the first half of 2015 compared to sales in the spot market in the first half of 2014, and higher energy purchases due to lower hydrological production in the system; and


•	Sul decreased by $45 million, driven by lower volumes of $22 million due to lower demand, and higher fixed costs of $17 million.

These decreases were partially offset by:


•	Eletropaulo increased by $63 million, driven by a $97 million ($135 million excluding FX) increase due to the reversal of a contingent regulatory liability, and a higher tariff of $47 million. These results were partially offset by unfavorable FX impacts of $65 million and higher fixed costs of $60 million, primarily due to higher bad debt expense, employee-related costs, and penalties.

Adjusted Operating Margin decreased by $84 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.

Adjusted PTC decreased by $122 million, due to the decrease of $84 million in Adjusted Operating Margin as described above as well as a reversal of $47 million in contingent interest accruals at Sul in 2014. These results were offset by lower interest expense of $14 million related to the reversal of a contingent regulatory liability at Eletropaulo as discussed above.

MCAC SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our MCAC SBU for the periods indicated:



	Three Months Ended June 30,										Six Months Ended June 30,
	2015			2014			$ Change		% Change		2015			2014			$ Change			% Change
	($ in millions)
Operating Margin	$	165		$	146		$	19	13	%	$	268		$	235		$	33		14	%
Noncontrolling Interests Adjustment	(29		)	(17		)					(52		)	(10		)
Derivatives Adjustment	—			(3		)					(2		)	(2		)
Adjusted Operating Margin	$	136		$	126		$	10	8	%	$	214		$	223		$	(9	)	-4	%
Adjusted PTC	$	106		$	95		$	11	12	%	$	156		$	160		$	(4	)	-3	%

Operating Margin for the three months ended June 30, 2015 increased by $19 million, or 13%. The increase in operating margin was driven primarily by the key operating drivers at the following businesses:

•

Panama increased by $34 million, mainly driven by better hydrological conditions which resulted in higher generation and lower energy purchases of $45 million, and $7 million due to the commencement of power barge operations at the end of March 2015. These results were partially offset by lower compensation from the government of Panama of $15 million due to lower volumes of energy purchased at lower spot prices.

This increase was partially offset by:


•	Mexico decreased by $11 million, driven by higher fuel costs and lower availability; and

•

Dominican Republic decreased by $7 million, mainly related to a lower availability impact of $9 million. Results at Andres and Los Mina were essentially neutral, primarily related to lower LNG fuel costs of $32 million driven by lower commodity prices, which was offset by lower spot results of $18 million, lower frequency regulation of $6 million, and lower gas sales to third parties of $4 million.

Adjusted Operating Margin increased by $10 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 90% of Changuinola and 49% of its other generation facilities in Panama, 92% of Andres and Los Mina (compared to 100% in 2014) and 46% of Itabo (compared to 50% in 2014) in the Dominican Republic, 99% of TEG/TEP and 55% of Merida in Mexico, and a weighted average of 77% of its businesses in El Salvador (compared to 75% in 2014).

Adjusted PTC increased by $11 million, driven by the $10 million increase in Adjusted Operating Margin as described above.

Operating Margin for the six months ended June 30, 2015 increased by $33 million, or 14%, including unfavorable FX impacts of $1 million. The increase in operating margin was driven primarily by the key operating drivers at the following businesses:

•

Panama increased by $91 million, mainly driven by better hydrological conditions which resulted in higher generation and lower energy purchases of $114 million, and $7 million due to the commencement of power barge operations at the end of March 2015. These results were partially offset by lower compensation from the government of Panama of $20 million due to lower volumes of energy purchased at lower spot prices, and lower frequency regulation of $8 million; and


•	El Salvador increased by $18 million, primarily due to a 2014 one-time unfavorable adjustment to unbilled revenue of $12 million, as well as lower regulated fees and energy losses.

These increases were partially offset by:


•	Dominican Republic decreased by $59 million, mainly related to lower PPA and spot sales of $36 million, lower availability of $22 million, lower gas sales to third parties of $14 million, lower frequency regulation of $12 million, and higher fixed costs of $9 million. These results were partially offset by lower LNG fuel costs of $35 million, driven by lower commodity prices; and


•	Mexico decreased $18 million, driven by higher fuel costs and lower availability.

Adjusted Operating Margin decreased by $9 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 90% of Changuinola and 49% of its other generation facilities in Panama, 92% of Andres and Los Mina (compared to 100% in 2014) and 46% of Itabo (compared to 50% in 2014) in the Dominican Republic, 99% of TEG/TEP and 55% of Merida in Mexico, and a weighted average of 77% of its businesses in El Salvador (compared to 75% in 2014).

Adjusted PTC decreased by $4 million, driven by the decrease of $9 million in Adjusted Operating Margin as described above, partially offset by lower interest expense due to lower debt at Puerto Rico.

Europe SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Europe SBU for the periods indicated:



	Three Months Ended June 30,											Six Months Ended June 30,
	2015			2014			$ Change			% Change		2015			2014			$ Change			% Change
	($ in millions)
Operating Margin	$	64		$	77		$	(13	)	-17	%	$	167		$	210		$	(43	)	-20	%
Noncontrolling Interests Adjustment	(6		)	(5		)						(14		)	(11		)
Derivatives Adjustment	(1		)	(4		)						1			(4		)
Adjusted Operating Margin	$	57		$	68		$	(11	)	-16	%	$	154		$	195		$	(41	)	-21	%
Adjusted PTC	$	41		$	73		$	(32	)	-44	%	$	126		$	188		$	(62	)	-33	%

Operating Margin for the three months ended June 30, 2015 decreased by $13 million, or 17%, including unfavorable FX impacts of $9 million. The decrease in operating margin was driven primarily by the key operating drivers at the following businesses:


•	Kilroot decreased by $29 million, driven by lower volumes and prices of $19 million primarily due to lower dispatch, and the timing of planned outages and related costs of $11 million; and


•	Loss of operations of $8 million from the sale of UK Wind assets and Ebute in August and November 2014, respectively.

These decreases were partially offset by:


•	Kazakhstan increased by $11 million, driven by higher volumes and prices of $13 million, primarily due to better hydrology;


•	New operations at IPP4 in Jordan of $9 million, which commenced operations in July 2014; and


•	Maritza increased by $7 million, driven by the timing of planned outages of $17 million. These results were partially offset by unfavorable FX impacts of $9 million.

Adjusted Operating Margin decreased by $11 million due to the drivers above, adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89% of Kavarna in Bulgaria, and 37% and 60%, respectively, of the Amman East and IPP4 projects in Jordan.

Adjusted PTC decreased by $32 million, as a result of the decrease of $11 million in Adjusted Operating Margin described above, as well as a 2014 reversal of an $18 million liability in Kazakhstan due to the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES. These results were partially offset by lower interest expense at Kavarna and Maritza.

Operating Margin for the six months ended June 30, 2015 decreased by $43 million, or 20%, including unfavorable FX impacts of $23 million. The decrease in operating margin was driven primarily by the key operating drivers at the following businesses:


•	Kilroot decreased by $37 million, primarily driven by lower volumes and prices of $25 million related to lower dispatch, and the timing of planned outages and related costs of $11 million;


•	Loss of operations of $23 million from the sale of UK Wind assets and Ebute in August and November 2014, respectively; and


•	Maritza decreased by $7 million, driven by unfavorable FX impacts of $17 million, partially offset by the timing of planned outages of $15 million.

These decreases were partially offset by:


•	New operations at IPP4 in Jordan of $19 million, which commenced operations in July 2014; and


•	Kazakhstan increased by $8 million, driven by higher volumes and prices of $13 million due primarily to better hydrology. These results were partially offset by unfavorable FX impacts of $3 million.

Adjusted Operating Margin decreased by $41 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89% of Kavarna in Bulgaria, and 37% and 60% respectively, of the Amman East and IPP4 projects in Jordan.

Adjusted PTC decreased by $62 million as a result of the decrease of $41 million in Adjusted Operating Margin described above, as well as a 2014 reversal of an $18 million liability in Kazakhstan described above, partially offset by lower interest expense at Kavarna and Maritza.

Asia SBU

The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Asia SBU for the periods indicated:



	Three Months Ended June 30,											Six Months Ended June 30,
	2015			2014			$ Change			% Change		2015			2014			$ Change			% Change
	($ in millions)
Operating Margin	$	47		$	27		$	20		74	%	$	71		$	37		$	34		92	%
Noncontrolling Interests Adjustment	(25		)	(1		)						(38		)	(1		)
Derivatives Adjustment	—			—								—			—
Adjusted Operating Margin	$	22		$	26		$	(4	)	-15	%	$	33		$	36		$	(3	)	-8	%
Adjusted PTC	$	30		$	23		$	7		30	%	$	42		$	31		$	11		35	%

Operating margin for the three months ended June 30, 2015 increased by $20 million, or 74%. The increase in operating margin was driven primarily by the key operating drivers at the following business:


•	Mong Duong provided $10 million due to commencement of its principal operations in April 2015; and


•	Masinloc increased by $9 million, driven by better availability.

Adjusted Operating Margin decreased by $4 million due to the drivers above, adjusted for the impact of noncontrolling interests resulting primarily from the sell-down of our ownership in Masinloc from 92% to 51% in mid-July 2014. AES also owns 90% of Kelanitissa and 51% of Mong Duong.

Adjusted PTC increased by $7 million, as the decrease of $4 million in Adjusted Operating Margin described above was primarily offset by an additional net impact of $9 million at Mong Duong due to a component of service concession revenue recognized as interest income, net of higher interest expense as interest is no longer capitalized. See Note 1—Financial Statement Presentation in Item 1.—Financial Statements of this Form 10-Q for further information regarding the accounting for service concession arrangements.

Operating margin for the six months ended June 30, 2015 increased by $34 million, or 92%. The increase in operating margin was driven primarily by the key operating drivers at the following business:


•	Masinloc increased by $20 million, primarily due to higher availability of $14 million and an unfavorable impact of $15 million occurring in the first quarter of 2014 due to the market operator’s retrospective adjustment to energy prices calculated in November and December 2013; and


•	Mong Duong increased by $11 million due to the commencement of its principal operations in April 2015.

Adjusted Operating Margin decreased by $3 million due to the drivers above, adjusted for the impact of noncontrolling interests resulting primarily from the sell-down of our ownership in Masinloc from 92% to 51% in mid-July 2014. AES also owns 90% of Kelanitissa and 51% of Mong Duong.

Adjusted PTC increased by $11 million, as the decrease of $3 million in Adjusted Operating Margin described above was primarily offset by lower interest expense at Masinloc, which was partially driven by the sell-down, and an additional net impact of $10 million at Mong Duong due to a component of service concession revenue recognized as interest income, net of higher interest expense as interest is no longer capitalized. See Note 1—Financial Statement Presentation in Item 1.—Financial Statements of this Form 10-Q for further information regarding the accounting for service concession arrangements.

Key Trends and Uncertainties

During the remainder of 2015 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, a combination of factors, (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise.

Regulatory

Brazil — On June 30, 2015, ANEEL included in Eletropaulo’s tariff reset the reimbursement of amounts previously refunded to customers from July 2014 through early January 2015. These refunded amounts were related to certain disputed assets included in the regulatory asset base dating back to 2007. See additional background within the Company’s 2014 Form 10-K—Item 1—Business—Our Organization and Segments—Brazil—Brazil Utility Businesses—Regulatory Framework and Note 11—Regulatory Assets and Liabilities included in Part II.—Item 8.—Financial Statements and Supplementary Data. In addition to ANEEL’s failure thus far to suspend the injunction through the appeals process in the Brazilian courts, the tariff reset resulted in management’s reassessment of the probability of refunding customers these disputed amounts. The Company now considers it only reasonably possible that Eletropaulo will be required to refund these amounts to customers prior to the ultimate resolution of the pending court case. As a result, during the three months ended June 30, 2015, the Company reversed the remaining regulatory liability for this contingency of $161 million. Eletropaulo believes it has meritorious arguments on this matter and will continue to pursue its objections to ANEEL’s rulings vigorously, however there can be no assurance that Eletropaulo will prevail.

Chile — In June 2015, the Chilean Government published Decree N°7, which allowed the export of energy to Argentina using the transmission line which connects the SING (Chilean Northern Grid) with the SADI (Argentine Grid). The AES transmission line has a capacity of 600 MW, but will only be operated at 200 MW at present. AES Gener is in conversations with other generators in order to export electricity to Argentina.

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. Since 2013, dry hydrological conditions in Brazil, Panama, Chile and Colombia have presented challenges for our businesses in 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 hydrological conditions do not improve and 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. According to the National Oceanic and Atmospheric Administration (“NOAA”) there is a greater than 90% chance that the El Niño phenomena will continue through the Northern Hemisphere winter 2015-16, and around an 80% chance it will last through the first quarter of 2016.

Even if rainfall and water inflows return to historical averages, in some cases high market prices and low generation could persist until reservoir levels are fully recovered.

Brazil — In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels, and a mechanism known as MRE was created to share hydrological risk across all hydro generators. If the hydroelectric generation facilities in MRE generate less than the total assured energy of the mechanism, the shortfall is shared among generators, and depending on a generator's contract level, is fulfilled with spot market purchases. The consequences of unfavorable hydrology are (i) thermal plants (more expensive to the system) being dispatched, (ii) lower hydropower generation with deficits in the MRE and (iii) high spot prices. During 2014, spot prices sustained significantly high levels causing financial stress to most entities in the energy sector. From February to April 2014, the spot price was at the cap level of R$822/MWh, contributing to

the average spot price of R$689/MWh for all of 2014. During October and November 2014, ANEEL conducted a public hearing to define a new spot price cap, reducing it from R$822/MWh to R$388/MWh from January 2015 forward. The lower cap price results in a meaningful reduction of expenses for entities negatively exposed to the spot price in 2015.

We expect the system operator in Brazil to continue to pursue a more conservative reservoir management strategy going forward, including the dispatch of up to 15-17 GW of thermal generation capacity, which could result in lower dispatch of hydroelectric generation facilities and electricity prices at high levels. AES Tietê has contract obligations throughout 2015 and may need to fulfill some of these obligations with spot purchases, so they will be sensitive to generation output and spot prices for electricity during this period. In addition, the costs incurred on energy purchases by our distribution companies (AES Eletropaulo and AES Sul) are passed through to customers with adjustments on a yearly basis, so working capital will be sensitive to significant increases in energy prices. In order to reduce potential working capital needs, in February 2015, ANEEL opened two public hearings i) to discuss an Extraordinary Tariff Review (“ETR”) requested by distribution companies and ii) to discuss adjustments to a tariff flag mechanism that may change the tariff to customers on a monthly basis depending on energy prices. These items were approved by ANEEL and made effective on March 2, 2015. The ETR represented an average tariff increase of 32% in AES Eletropaulo and 39% at AES Sul. The tariff flag mechanism, a temporary measure in response to higher energy prices due to dry hydrological conditions, was improved by incorporating i) a higher tariff increase depending on the energy purchase costs and ii) resources collected by the tariff flag being centralized in an account and shared among distribution companies in proportion to their respective involuntary exposure. These mechanisms are expected to reduce working capital needs for distribution companies.

Finally, if dry conditions persist until the beginning and/or through the next rainy season starting in November 2015 and there is no sufficient load demand reduction in the system, there is a risk that the government of Brazil could implement a rationing program in 2016. If rationing were to occur, we would expect rules to be implemented that may include, but are not limited to, i) adjustments to hydroelectric generation PPAs in accordance with the overall load reduction affecting contracting position of hydroelectric generators and distribution companies; ii) reductions in energy consumption impacting hydroelectric generation and margins of distribution companies; iii) increases in costs for distribution companies to provide additional customer services, communications, and to comply with rationing decree rules; and iv) increases in losses and delinquency for distribution companies due to higher tariffs and potential penalties. As a result, if poor hydrology persists and/or Brazil implements a rationing program, we would expect there to be an adverse impact on our results of operations and cash flows of our generation and distribution businesses in Brazil.

In Brazil, economic conditions remain unfavorable, as indicated by such factors as a negative GDP growth expectation for 2015, higher interest rates and inflation, and increasing unemployment. As a consequence, our distribution businesses have experienced a decline in demand. If these economic conditions persist or worsen, there could be a material impact on our businesses and AES's results of operations, particularly in our distribution businesses in Brazil, AES Sul and AES Eletropaulo.

Panama — In Panama, dry hydrological conditions continued in 2015 especially in the Pacific river basins reducing generation output from hydroelectric facilities in those systems. This effect was partially offset by higher than historical average inflows in the Caribbean river basins. According to local hydrological forecast, the expectation is to have marginally below historical average inflows through the second half of 2015. Moreover, the effects of the El Niño phenomena could potentially intensify the dry hydrology conditions for the rest of the year and extend it to the first quarter of 2016.

AES Panama has to purchase energy on the spot market to fulfill its contract obligations when its generation output is below contract levels, and we expect this trend to continue through the second half of the year which will continue to impact our results of operations. As authorized on March 31, 2014, the Government of Panama agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70 MW reduction in contracted capacity from 2014 to 2016 by compensating AES Panama for adverse variances between spot prices and a fixed price, equivalent to the average contract price, up to a maximum of $40 million in 2014, $30 million in 2015 and $30 million in 2016, not adjusted for ownership. Compensation payments recognized through December 31, 2014 and June 30, 2015 were $40 million and $4 million, respectively, of which $7 million are pending to be collected. The lower compensation rate in 2015 is a due to spot prices falling as a result of lower oil prices. Additionally, as part of our strategy to reduce our reliance on hydrology, in September 2014, AES Panama acquired a 72 MW power barge for $27 million, financed with non-recourse debt, which became operational in March 2015. As of June 30, 2015, amounts capitalized include $49 million recorded in Electric Generation Assets and $10 million recorded in Construction in Progress related to some components still in process. The provisional commercial operation certificate was obtained in April 2015.

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, economic conditions remain unfavorable, as measured by indicators such as non-receding inflation, increased government deficits, diminished sovereign reserves, lack of foreign currency accessibility, the potential for continued devaluation of the local currency, and a decline in expectations for economic growth. 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 June 30, 2015, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank. See Note 7—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of the 2014 Form 10-K for further information on the long-term receivables. In January 2014, the Argentine Peso devalued by approximately 20%, the most rapid depreciation since 2002. While the currency stabilized in the latter part of 2014 and throughout the first semester of 2015, further weakening of the Argentine Peso and local economic activity 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.

Argentina defaulted on its public debt in 2001, when it stopped making payments on approximately $100 billion amid a deep economic crisis. In 2005 and 2010, Argentina restructured its defaulted bonds into new securities valued at about 33 cents on the dollar. Between the two transactions, 93% of the bondholders agreed to exchange their defaulted bonds for new bonds. The remaining 7% did not accept the restructured deal. Since then, a certain group of the “hold-out” bondholders have been in judicial proceedings with Argentina regarding payment. More recently, the United States District Court ruled that Argentina would need to make payment to such hold-out bondholders according to the original applicable terms. Despite intense negotiations with the hold-out bondholders through the U.S. District Court Appointed Special Master, on July 30, 2014 the parties failed to reach a settlement agreement and consequently (as referred by S&P and Fitch ratings) Argentina fell into a selective default resulting from failure to make interest payments on its Discount Bonds maturing in December 2033. Although this situation remains unresolved, it has not caused any significant changes that impact our current exposures; however, as noted above, there could be impacts on our businesses in the future.

Bulgaria — A set of changes to the Energy Law were prepared by the Energy Commission of the Parliament, voted and enacted in March 2015. Main changes include the limitation of electricity purchases from co-generators at preferential prices, the allocation of the proceeds from the sale of state CO₂ allowances to NEK, and increase of the Regulator’s independence through appointment of its members by the Parliament and not by the Council of Ministers.

Another component of the energy sector restructuring is the negotiation of an amendment of Maritza’s PPA. Maritza has engaged in negotiations with NEK and other Bulgarian state bodies concerning these matters. In April 2015, the Company signed a non-binding Heads of Terms Agreement (“HTA”) with NEK regarding proposed amendments to the existing PPA with NEK. Under the framework set forth in the HTA, both parties will endeavor to make certain changes to the PPA, under which Maritza sells its output to NEK through 2026 (“PPA Term”). Under this framework, Maritza and NEK would reduce the capacity payment to Maritza under the PPA by 14% through the PPA Term, without impacting the energy price component. In exchange, NEK would pay Maritza its overdue receivables. Payment of the overdue receivables is contingent upon NEK obtaining financing support. NEK and Maritza are seeking to enter into the binding amendment of Maritza’s PPA by the end of 2015, however, there is no guarantee that a binding agreement will be reached.

In July 2015, additional measures were voted by the Parliament to complement the first measures taken in March 2015. A new fund will be created to help NEK meet its obligations with energy producers, financed with a 5% contribution from all energy producers on their energy revenues as well as with proceeds from the sale of state CO₂ allowances. Maritza will be able to pass-through this additional contribution to NEK since it falls under a change in law provision under the PPA.

For the period April through June 2015 NEK paid in total EUR 48 million which is in line with payments from the previous year. As of June 30, 2015, Maritza’s total outstanding receivables were $281 million, of which $29 million were current and $252 million were overdue. Total receivables increased by $19 million from December 31, 2014 due to seasonality impacts during the period April through June (lower demand combined with higher renewable generation).

Unless and until a complete and binding resolution is in place, there remains a risk that we may still 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.

As of June 30, 2015, we concluded that the HTA signed with NEK in April is considered an indicator of an impairment of the long-lived assets in Bulgaria for Maritza, which were $1.1 billion and total debt of $605 million. Therefore, a test of recoverability was performed and management believes the carrying amount of the asset groups is recoverable as of June 30, 2015. Long-lived assets for Kavarna were $221 million and total debt of $147 million.

India — AES has one coal-fired project under development with a total capacity of 1,320 MW which is an expansion of our existing OPGC business. The project started construction in April 2014 and is currently expected to begin operations in

2018. In August 2014, the Supreme Court of India invalidated the allocation of coal blocks to companies with certain levels of private ownership. In order to comply with the ruling, OPGC has formed a JV company with Odisha Hydro Power Corporation Ltd. and, in March 2015, this JV company has been re-allocated the coal blocks for the OPGC expansion project.

Puerto Rico — As stated in Item 7.—Management’s discussion and analysis of financial condition and results of operations—Key Trends and Uncertainties—Puerto Rico of the Company’s 2014 Form 10-K, our subsidiaries in Puerto Rico have long term PPAs with PREPA, a state-owned entity. Due to the ongoing economic situation in the country, PREPA faces significant financial challenges.

On June 28, 2014, the Puerto Rico Public Corporation Debt Enforcement and Recovery Act (the “Recovery Act”) was signed into law, which allows public corporations, including PREPA, to adjust their debts. On July 6, 2014, PREPA entered into a Forbearance Agreement with its lenders in order to permit an opportunity for negotiation of a possible financial restructuring of PREPA. The expiration of this agreement was subsequently extended to September 15, 2015. On December 14, 2014, PREPA presented the first stage of its restructuring plan. In February 2015, the negotiating position of PREPA was weakened when the federal court deemed the Recovery Act unconstitutional. The Puerto Rican government is appealing the decision of the court. PREPA presented a restructuring plan on June 1, 2015, as announced. The plan calls for a “shared burden” among all stakeholders, contemplates capital investments, as well as a greater role for private enterprises in the utility's operations, particularly in the generation component. It also recommends revising PREPA’s price structure, including a likely hike to electricity bills. PREPA is also reportedly seeking a moratorium on some of its future debt payments, which would protect the utility from a potential default while it restructures its operations. Subsequently, several milestones have been agreed between all parties, including the execution of a Restructuring Support Agreement no later than September 1, 2015.

AES Puerto Rico’s receivables balance from PREPA as of June 30, 2015 was $81 million, of which $23 million was overdue but subsequently has been collected.

As the events pertaining to the Forbearance Agreement continued to unfold, as of June 30, 2015, we concluded that there was no indicator of an impairment of the long-lived assets in Puerto Rico, which were $637 million and total debt of $544 million. Therefore, management believes the carrying amount of the asset group is recoverable as of June 30, 2015.

Macroeconomics — Conclusion

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 could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses.

Impairments

Goodwill — In the first quarter of 2014, the Company recognized a full goodwill impairment of $136 million at DPLER and a goodwill impairment of $18 million at Buffalo Gap. During 2014, the Company recognized total goodwill impairment expense of $164 million. The Company has no reporting units considered to be “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 at risk of step 1 failure on an ongoing basis. It is possible that the Company may incur goodwill impairment charges at any reporting units containing goodwill in future periods if adverse changes in their business or operating environments occur. See Note 10—Goodwill and Other Intangible Assets included in Item 8.—Financial Statements and Supplementary Data of our 2014 Form 10-K for further information.

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 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, 2014. The following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in Item 1.—Business—Environmental and Land Use Regulations of the Company’s Form 10-K for the year ended December 31, 2014.

Update on MATS

As further discussed in Item 1.—Business—United States Environmental and Land-Use Regulations—MATS in the Company’s Form 10-K for the year ended December 31, 2014, the U.S. Supreme Court granted certiorari in several petitions for review of the decision by the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) to uphold MATS. On June 29, 2015, the U.S. Supreme Court reversed the D.C. Circuit’s decision, and remanded MATS to the D.C. Circuit for further proceedings. MATS remains in effect until the D.C. Circuit acts; however, we currently cannot predict the outcome of this litigation, or its impact, if any, on our MATS compliance planning.

Update on Waste Management

As further discussed in Item 1.—Business—United States Environmental and Land-Use Regulations—Waste Management in the Company’s Form 10-K for the year ended December 31, 2014, in December 2014, the EPA announced a final rule regulating CCR under Subtitle D of the Resource Conservation and Recovery Act. The final rule establishes nationally applicable minimum criteria for the disposal of CCR in new and currently operating landfills and surface impoundments, and may impose closure and/or corrective action requirements for existing CCR landfills and impoundments under certain specified conditions. The EPA published the final rule in the Federal Register on April 17, 2015, and it will become effective on October 19, 2015. The Company’s U.S. subsidiaries are still analyzing the potential impact and compliance cost associated with this final rule, and there can be no assurance that the Company’s businesses, financial condition or results of operations would not be materially and adversely affected by such rule.

Update on Water Discharges

On October 16, 2014, IPL filed its wastewater compliance plans with the Indiana Utility Regulatory Commission (“IURC”). On July 29, 2015, IPL received approval for a Certificate of Public Convenience and Necessity from the IURC to convert Unit 7 at the Harding Street Station from coal-fired to natural gas-fired, and also to install and operate wastewater treatment technologies at Harding Street Station and Petersburg Generation Station in southern Indiana. IPL will invest $326 million in these projects to ensure compliance with the wastewater treatment requirements by 2017. Recovery of these costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding; however, there can be no assurances that IPL will be successful in that regard.

On June 29, 2015, the EPA and the U.S. Army Corps of Engineers published a final rule defining federal jurisdiction over waters of the United States. This rule, which becomes effective on August 28, 2015, may expand or otherwise change the number and types of waters or features subject to federal permitting. Several states and industry groups have filed suit to challenge the rule. We cannot at this time determine the timing or impact of this regulation or litigation, but it could have a material impact on our business, financial condition or results of operations.

Update on GHG Emissions

Consistent with the discussion in Item 1.—Business—United States Environmental and Land-Use Regulations—Greenhouse Gas Emissions in the Company's Form 10-K for the year ended December 31, 2014, on August 3, 2015, the EPA released the final CO₂ emissions rules for existing power plants under Clean Air Act Section 111(d), called the Clean Power Plan (the “CPP”). The CPP provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates by 2030. It is too soon to determine whether the CPP will survive the expected legal challenges, and if it does survive such challenges, its potential impact on our business, operations or financial condition, but any such impact could be material.

Capital Resources and Liquidity

Overview — As of June 30, 2015, the Company had unrestricted cash and cash equivalents of $1.0 billion, of which $40 million was held at the Parent Company and qualified holding companies. The Company had $439 million in short-term investments, held primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $711 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.7 billion and $5.0 billion, respectively. Of the approximately $2.0 billion of our current non-recourse debt, $1.2 billion was presented as such because it is due in the next 12 months and $764 million relates to debt considered in default due to covenant violations. The defaults are not payment defaults, but are instead technical defaults triggered by failure to comply with other covenants and/or other conditions

such as (but not limited to) failure to meet information covenants, complete construction or other milestones in an allocated time, meet certain minimum or maximum financial ratios, or other requirements contained in the non-recourse debt documents of the Company.

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. None of our recourse debt matures within the next 12 months.

We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross-default risk to the Parent Company or other subsidiaries and affiliates. 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 unhedged exposure to variable interest rate debt relates to indebtedness under its floating rate senior unsecured notes due 2019. On a consolidated basis, of the Company’s $15.7 billion of total non-recourse debt outstanding as of June 30, 2015, approximately $3.6 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate.

In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At June 30, 2015, the Parent Company had provided outstanding financial and performance-related guarantees, indemnities or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $386 million in aggregate (excluding those collateralized by letters of credit and other obligations discussed below). These amounts exclude normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal.

As a result of the Parent Company’s below-investment-grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At June 30, 2015, we had $61 million in letters of credit outstanding, provided under our senior secured credit facility and $49 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, construction activities and subsidiary operations. During the quarter ended June 30, 2015, 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.

Financing Receivables — As of June 30, 2015, the Company had approximately $291 million and $103 million of accounts receivable classified as Noncurrent assets—other and Current assets—Accounts receivable, respectively, primarily related to certain of its generation businesses in Argentina and the United States, and its utility businesses in Brazil and Cameroon (sold in 2014). The noncurrent portion primarily consists of accounts receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond June 30, 2016, 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—Financing Receivables included in Part I Item 1.—Financial Statements of this Form 10-Q and Item 1.—Business—Regulatory Matters—Argentina included in the 2014 Form 10-K for further information.

Consolidated Cash Flows — During the three and six months ended June 30, 2015, cash and cash equivalents decreased $315 million and $517 million, respectively to $1.0 billion. The table below reflects the changes in cash flows for the comparative periods:



	Three Months Ended June 30,											Six Months Ended June 30,
	2015			2014			$ Change			% Change		2015			2014			$ Change			% Change
Cash flows provided by (used in):	(in millions)
Operating activities	$	153		$	232		$	(79	)	-34	%	$	590		$	453		$	137		30	%
Investing activities	(350		)	(65		)	(285		)	438	%	(1,070		)	(391		)	(679		)	174	%
Financing activities	(124		)	(118		)	(6		)	5	%	(11		)	(250		)	239			-96	%
Effect of exchange rate changes on cash	8			8			—			—	%	(19		)	(14		)	(5		)	36	%
Decrease in cash of discontinued and held-for sale businesses	(2		)	45			(47		)	-104	%	(7		)	75			(82		)	-109	%
Net (decrease) increase in cash and cash equivalents	(315		)	102			(417		)	-409	%	(517		)	(127		)	(390		)	307	%
Cash and cash equivalents at beginning of period	$	1,337		$	1,413		$	(76	)	-5	%	$	1,539		$	1,642		$	(103	)	-6	%
Cash and cash equivalents at end of period	$	1,022		$	1,515		$	(493	)	-33	%	$	1,022		$	1,515		$	(493	)	-33	%

Net Cash Flows from Operating Activities — Net cash provided by operating activities was driven by:



	Three Months Ended June 30,											Six Months Ended June 30,
$ in millions	2015			2014			$ Change			% Change		2015			2014			$ Change			% Change
Net Income	$	264		$	275		$	(11	)	-4	%	$	518		$	341		$	177		52	%
Depreciation and amortization	299			319			(20		)	-6	%	597			625			(28		)	-4	%
Impairment expenses	37			107			(70		)	-65	%	45			273			(228		)	-84	%
Loss on the extinguishment of debt	122			15			107			713	%	145			149			(4		)	-3	%
Other non-cash adjustments	(101		)	(43		)	(58		)	-135	%	(35		)	108			(143		)	-132	%
Net income, adjusted for non-cash items	$	621		$	673		$	(52	)	-8	%	$	1,270		$	1,496		$	(226	)	-15	%
Net change in operating assets and liabilities ⁽¹⁾	$	(468	)	$	(441	)	$	(27	)	-6	%	$	(680	)	$	(1,043	)	$	363		35	%
Net cash provided by operating activities ⁽²⁾	$	153		$	232		$	(79	)	-34	%	$	590		$	453		$	137		30	%

_____________________________


⁽¹⁾	Refer to the first four tables below for explanations by operating assets and liabilities.


⁽²⁾	Refer to the last two tables below for drivers by business.

Net change in operating assets and liabilities ($ in millions) for the three months ended June 30, 2015 and 2014 was driven by:



	Three Months Ended June 30, 2015
Increase in other assets primarily regulatory assets at Eletropaulo and Sul, and service concession assets at Mong Duong	$	(525	)
Decrease in net income tax payable and other tax payables primarily at Chivor, Alicura, Maritza and in the US	(116		)
Increase in accounts receivable primarily at Eletropaulo, Mong Duong and Maritza, partially offset by a decrease at Uruguaiana	(107		)
Increase in other liabilities primarily regulatory liabilities at Eletropaulo and Sul	329
Other operating assets and liabilities	(49		)
Net change in operating assets and liabilities	$	(468	)



	Three Months Ended June 30, 2014
Decrease in accounts payable and other current liabilities primarily at Eletropaulo, Sul and the Parent Company	$	(609	)
Increase in accounts receivable primarily at Sul and Alicura	(93		)
Decrease in other assets, primarily regulatory assets at Eletropaulo and Sul	128
Increase in other liabilities primarily regulatory liabilities at Eletropaulo and Sul	128
Other operating assets and liabilities	5
Net change in operating assets and liabilities	$	(441	)

Net change in operating assets and liabilities ($ in millions) for the six months ended June 30, 2015 and 2014 was driven by:



	Six Months Ended June 30, 2015
Increase in other assets, primarily regulatory assets at Eletropaulo and Sul, and service concession assets at Mong Duong	$	(815	)
Increase in accounts receivable primarily at Eletropaulo, Mong Duong, Sul, Alicura and Gener	(444		)
Decrease in net income tax payables and other tax payables primarily in the US and at Chivor	(131		)
Increase in inventory primarily at Mong Duong and IPALCO	(54		)
Increase in other liabilities primarily in regulatory liabilities at Eletropaulo and Sul, partially offset by IPALCO	453
Increase in accounts payable and other current liabilities primarily at Eletropaulo and Sul, partially offset by Tietê	179
Decrease in prepaid expense and other current assets primarily at Eletropaulo and DPL, partially offset by Sul	132
Net change in operating assets and liabilities	$	(680	)



	Six Months Ended June 30, 2014
Increase in other assets primarily regulatory assets at Eletropaulo and Sul	$	(316	)
Increase in accounts receivable primarily at Sul, Alicura, Gener, Uruguaiana and Maritza	(312		)
Decrease in accounts payable and other current liabilities, primarily regulatory liabilities at Eletropaulo	(194		)
Decrease in net income tax and other tax payables primarily in the US and Brazil	(176		)
Other operating assets and liabilities	(45		)
Net change in operating assets and liabilities	$	(1,043	)

Net operating activities for the three months ended June 30, 2015 compared to the three months ended June 30, 2014 decreased $79 million driven primarily by the following SBUs and key operating drivers excluding intercompany related transactions or adjustments pertaining to interest, tax sharing, charges for management fee, transfer pricing , but including timing of intercompany expenses paid on behalf of businesses ($ in millions):



	Amount
Brazil — decrease of $93 million primarily due to:
Decrease at Tietê primarily due to higher spot market energy purchases from unfavorable hydrology, higher transmission costs and lower collections	$	(160	)
Increase at Eletropaulo primarily due to higher collections mainly attributable to higher tariffs, partially offset by higher energy purchases resulting from unfavorable hydrology and higher transmission costs	59
Andes — decrease of $53 million primarily due to:
Decrease at Chivor in Colombia primarily due to higher current year tax payments resulting from higher taxable income in the prior year	(50		)
Corporate — increase of $53 million primarily due to:
Increase primarily at the Parent Company driven by lower current year interest payments, swap termination payments made in the prior year upon refinance of debt, lower benefit requirements as well as the collection of realized gains resulting from the Company’s corporate hedging program	53
Other business drivers	19
	$	(79	)

Net operating activities for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 increased $137 million driven primarily by the following SBUs and key operating drivers excluding intercompany related transactions or adjustments pertaining to interest, tax sharing, charges for management fee, transfer pricing, but including timing of intercompany expenses paid on behalf of businesses ($ in millions):



	Amount
US — increase of $116 million primarily due to:
Increase at DPL primarily due to timing of collections, collection of deferred storm costs, lower interest paid and higher collateral deposits in the prior year as a result of outages	$	119
Asia — decrease of $91 million primarily due to:
Decrease at Mong Duong primarily due to payment of service concession assets	(72		)
Decrease at Masinloc primarily attributable to timing of customer collections and payables to the wholesale market for replacement power during outages, partially offset by higher collections resulting from better plant availability in 2015	(18		)
MCAC — increase of $85 million primarily due to:
Increase in Panama primarily due to lower energy purchases resulting from favorable hydrology	77
Increase in El Salvador primarily due to lower energy purchase costs resulting from a decrease in fuel prices	50
Increase in Puerto Rico primarily due to lower energy purchase costs resulting from a decrease in commodities prices and higher collections from the offtaker	29
Decrease in the Dominican Republic primarily due to lower collections from distribution companies and higher payments for energy in the spot market	(67		)
Corporate and other business drivers	19
	$	137

Net Cash Flows from Investing Activities — Net cash used in investing activities were driven by:



	Six Months Ended June 30,
	2015			2014			$ Change			% Change
	($ in millions)
Capital expenditures ⁽¹⁾	$	(1,168	)	$	(908	)	$	(260	)	-29	%
Acquisitions, net of cash acquired:
Corporate — Main Street Power	$	(17	)	$	—		$	(17	)	NA
Andes — Gener — related to the purchase of 50% interest in our equity investment in Guacolda	—			(728		)	728			100	%
Other businesses	(1		)	—			(1		)	NA
Total acquisitions, net of cash acquired	$	(18	)	$	(728	)	$	710		100	%
Proceeds from the sale of businesses, net of cash sold:
Andes — Gener — related to the sale of 50% less one share of our interest in Guacolda	$	—		$	730		$	(730	)	-100	%
Corporate — related to the sale of businesses in Cameroon	—			132			(132		)	-100	%
Asia — related to the sale of wind projects in India	—			21			(21		)	-100	%
US — related to the sale of US wind projects	—			7			(7		)	-100	%
Other businesses	2			—			2			NA
Total proceeds from the sale of businesses, net of cash sold	$	2		$	890		$	(888	)	-100	%
Sales of short-term investments, net of purchases:
Brazil — primarily at Tietê, Sul and Eletropaulo	$	175		$	263		$	(88	)	-33	%
Other businesses	15			10			5			50	%
Total sales of short-term investments, net of purchases	$	190		$	273		$	(83	)	-30	%
Other investing activities	$	(76	)	$	82		$	(158	)	-193	%
Net cash used in investing activities	$	(1,070	)	$	(391	)	$	(679	)	-174	%

__________________


⁽¹⁾	Refer to table below for capital expenditures types and drivers by business.

Net cash used for capital expenditures were driven by:



		Six Months Ended June 30,
		2015			2014			$ Change			% Change
SBU	Growth capital expenditures:	($ in millions)
Andes	Gener — primarily related to Alto Maipo and Cochrane construction projects	$	(445	)	$	(250	)	$	(195	)	-78	%
US	IPALCO — primarily related to replacement generation projects	(116		)	(28		)	(88		)	-314	%
Brazil	Eletropaulo — primarily related to customer connection and distribution grid projects	(53		)	(83		)	30			36	%
MCAC	Dominican Republic — primarily at Los Mina	(39		)	(1		)	(38		)	NM
Brazil	Sul — primarily related to distribution grid projects	(21		)	(25		)	4			16	%
Europe	Jordan — IPP4 construction project	—			(38		)	38			100	%
Asia	Mong Duong —2014 balance related to service concession assets	—			(45		)	45			100	%
	Other businesses	(68		)	(66		)	(2		)	-3	%
	Total growth capital expenditures	$	(742	)	$	(536	)	$	(206	)	-38	%
	Maintenance and environmental capital expenditures:
US	IPALCO — primarily related to MATS project and maintenance on equipment	$	(177	)	$	(105	)	$	(72	)	-69	%
US	DPL — related to maintenance on generating units and trans/distribution equipment	(41		)	(32		)	(9		)	-28	%
Andes	Gener — primarily related to the SING and the Ventanas Unit 1 and 2 plants	(37		)	(33		)	(4		)	-12	%
Brazil	Eletropaulo — primarily related to customer connection and distribution grid projects	(34		)	(42		)	8			19	%
Brazil	Tietê — primarily related to modernization of generating units	(21		)	(40		)	19			48	%
Brazil	Sul — primarily related to distribution grid projects	(19		)	(28		)	9			32	%
	Other businesses	(97		)	(92		)	(5		)	-5	%
	Total maintenance and environmental capital expenditures	$	(426	)	$	(372	)	$	(54	)	-15	%
	Total capital expenditures	$	(1,168	)	$	(908	)	$	(260	)	-29	%

_____________________________

NM - Not Meaningful

Net Cash Flows from Financing Activities — Net cash used in financing activities were driven by:



	Six Months Ended June 30,
	2015			2014			$ Change			% Change
	($ in millions)
Issuances of recourse and non-recourse debt:
Corporate — Parent Company	$	575		$	1,525		$	(950	)	-62	%
Brazil — Sul	499			92			407			442	%
Andes — Gener	485			926			(441		)	-48	%
US — IPALCO	405			130			275			212	%
MCAC — Panama	300			50			250			500	%
Brazil — Eletropaulo	118			—			118			NA
Asia — Mong Duong	104			271			(167		)	-62	%
Brazil — Tietê	—			129			(129		)	-100	%
Other businesses	29			112			(83		)	-74	%
Total issuances of recourse and non-recourse debt	$	2,515		$	3,235		$	(720	)	-22	%
Repayments of recourse and non-recourse debt:
Corporate — Parent Company	$	(915	)	$	(1,663	)	$	748		45	%
Brazil — Sul	(468		)	(6		)	(462		)	NM
US — IPALCO	(384		)	—			(384		)	NA
MCAC — Panama	(287		)	—			(287		)	NA
Brazil — Tietê	(97		)	(132		)	35			27	%
Brazil — Eletropaulo	(63		)	(12		)	(51		)	-425	%
Europe — Maritza	(31		)	(31		)	—			—	%
MCAC — Puerto Rico	(24		)	(42		)	18			43	%
Andes — Gener	(15		)	(885		)	870			98	%
US — Shady Point	—			(51		)	51			100	%
Other businesses	(88		)	(190		)	102			54	%
Total repayments of recourse and non-recourse debt	$	(2,372	)	$	(3,012	)	$	640		21	%
Proceeds from the sale of redeemable stock of subsidiaries:
Corporate and US — IPALCO	$	461		$	—		$	461		NA
Total proceeds from the sale of redeemable stock of subsidiaries	$	461		$	—		$	461		NA
Dividends paid on The AES Corporation common stock
Corporate — Parent Company	$	(141	)	$	(72	)	$	(69	)	-96	%
Total dividends paid on The AES Corporation common stock	$	(141	)	$	(72	)	$	(69	)	-96	%
Payments for financed capital expenditures:
Andes — Gener	$	(81	)	$	(33	)	$	(48	)	-145	%
Asia — Mong Duong	—			(272		)	272			100	%
Other businesses	(3		)	(7		)	4			57	%
Total payments for financed capital expenditures	$	(84	)	$	(312	)	$	228		73	%
Purchase of treasury stock
Corporate — Parent Company	$	(307	)	$	(32	)	$	(275	)	-859	%
Total purchase of treasury stock	$	(307	)	$	(32	)	$	(275	)	-859	%
Other financing activities	$	(83	)	$	(57	)	$	(26	)	-46	%
Net cash used in financing activities	$	(11	)	$	(250	)	$	239		96	%

_____________________________

NM - Not Meaningful

Proportional Free Cash Flow (a non-GAAP measure) — We define Proportional Free Cash Flow as cash flows from operating activities less maintenance capital expenditures (including non-recoverable environmental capital expenditures), adjusted for the estimated impact of noncontrolling interests. The proportionate share of cash flows and related adjustments attributable to noncontrolling interests in our subsidiaries comprise the proportional adjustment factor presented in the reconciliation below. Upon the Company’s adoption of the accounting guidance for service concession arrangements effective January 1, 2015, capital expenditures related to service concession assets that would have been classified as investing activities on the Condensed Consolidated Statement of Cash Flows are now classified as operating activities. See Note 1—Financial Statement Presentation of this Form 10-Q for further information on the adoption of this guidance.

Beginning in the quarter ended March 31, 2015, the Company changed the definition of Proportional Free Cash Flow to exclude the cash flows for capital expenditures related to service concession assets that are now classified within net cash provided by operating activities on the Condensed Consolidated Statement of Cash Flows. The proportional adjustment factor for these capital expenditures is presented in the reconciliation below.

We exclude environmental capital expenditures that are expected to be recovered through regulatory, contractual or other mechanisms. An example of recoverable environmental capital expenditures is IPL’s investment in MATS-related environmental upgrades that are recovered through a tracker. See Item 1.—Business—US SBU—IPALCO—Environmental Matters in our 2014 Form 10-K for details of these investments.

The GAAP measure most comparable to proportional free cash flow is cash flows from operating activities. We believe that proportional free cash flow better reflects the underlying business performance of the Company, as it measures the cash

generated by the business, after the funding of maintenance capital expenditures, that may be available for investing or repaying debt or other purposes. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly owned by the Company.

The presentation of free cash flow has material limitations. Proportional free cash flow should not be construed as an alternative to cash from operating activities, which is determined in accordance with GAAP. Proportional free cash flow does not represent our cash flow available for discretionary payments because it excludes certain payments that are required or to which we have committed, such as debt service requirements and dividend payments. Our definition of proportional free cash flow may not be comparable to similarly titled measures presented by other companies.



Calculation of Proportional Free Cash Flow	Three Months Ended June 30,											Six Months Ended June 30,
	2015			2014			$ Change			% Change		2015			2014			$ Change			% Change
	(in millions)											(in millions)
Net Cash provided by operating activities	$	153		232			$	(79	)	-34	%	$	590		$	453		$	137		30	%
Add: capital expenditures related to service concession assets ⁽¹⁾	51			—			51			NA		71			—			71			NA
Adjusted Operating Cash Flow	$	204		$	232		$	(28	)	-12	%	$	661		$	453		$	208		46	%
Less: proportional adjustment factor on operating cash activities ^{(2) (3)}	(13		)	(64		)	51			80	%	(85		)	(44		)	(41		)	-93	%
Proportional Adjusted Operating Cash Flow	$	191		$	168		$	23		14	%	$	576		$	409		$	167		41	%
Less: proportional maintenance capital expenditures, net of reinsurance proceeds ⁽²⁾	(117		)	(102		)	(15		)	-15	%	(230		)	(206		)	(24		)	-12	%
Less: proportional non-recoverable environmental capital expenditures ^{(2) (4)}	(12		)	(19		)	7			37	%	(19		)	(27		)	8			30	%
Proportional Free Cash Flow	$	62		$	47		$	15		32	%	$	327		$	176		$	151		86	%

____________________________


⁽¹⁾	Service concession asset expenditures excluded from proportional free cash flow non-GAAP metric.

⁽²⁾

The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds), and proportional non-recoverable environmental capital expenditures are calculated by multiplying the percentage owned by noncontrolling interests for each entity by its corresponding consolidated cash flow metric and adding up the resulting figures. For example, the Company owns approximately 71% of AES Gener, its subsidiary in Chile. Assuming a consolidated net cash flow from operating activities of $100 from AES Gener, the proportional adjustment factor for AES Gener would equal approximately $29 (or $100 x 29%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then adds these amounts together to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to noncontrolling interests as a result of (a) non-cash items which impact income but not cash and (b) AES’ ownership interest in the subsidiary where such items occur.


⁽³⁾	Includes proportional adjustment amount for service concession asset expenditures of $26 million and $36 million for the three and six months ended June 30, 2015. The Company adopted service concession accounting effective January 1, 2015.


⁽⁴⁾	Excludes IPALCO’s proportional recoverable environmental capital expenditures of $47 million and $52 million for the three months ended June 30, 2015 and June 30, 2014, as well as, $86 million and $74 million for the six months ended June 30, 2015 and June 30, 2014, respectively.



Proportional Free Cash Flow by SBU ($ in millions)	Three Months Ended June 30,											Six Months Ended June 30,
	2015			2014			$ Change			% Change		2015			2014			$ Change			% Change
US SBU	$	104		$	105		$	(1	)	-1	%	$	259		$	186		$	73		39	%
Andes SBU	(20		)	17			(37		)	-218	%	(3		)	40			(43		)	-108	%
Brazil SBU	(20		)	(2		)	(18		)	-900	%	(67		)	(64		)	(3		)	-5	%
MCAC SBU	18			6			12			200	%	132			80			52			65	%
Europe SBU	35			32			3			9	%	174			150			24			16	%
Asia SBU	5			7			(2		)	-29	%	9			48			(39		)	-81	%
Corporate SBU	(60		)	(118		)	58			49	%	(177		)	(264		)	87			33	%
Proportional Free Cash Flow — Total SBUs	$	62		$	47		$	15		32	%	$	327		$	176		$	151		86	%

Proportional Free Cash Flow for the three months ended June 30, 2015 compared to the three months ended June 30, 2014 increased $15 million, driven primarily by the following SBUs and key operating drivers excluding intercompany related transactions or adjustments pertaining to interest, tax sharing and charges for management fee and transfer pricing, but including timing of intercompany expenses paid on behalf of the businesses ($ in millions):



US SBU	Amount
Increase at DPL primarily due to higher collections, collection of deferred storm costs and lower interest paid	$	61
Decrease at IPALCO primarily due to lower collections driven by lower wholesale margins resulting from outages and lower prices as well as an increase in maintenance capital expenditures	(31		)
Decrease at Shady Point primarily driven by increased inventory, lower collections during unit repairs and an increase in maintenance capital expenditures	(10		)
Decrease at Buffalo Gap primarily due to lower collections as a result of lower wind production	(6		)
Other business drivers	(15		)
Total	$	(1	)



Andes SBU	Amount
Decrease at Chivor in Colombia primarily due to higher current year tax payments resulting from higher taxable income in the prior year	$	(37	)
Total	$	(37	)



Brazil SBU	Amount
Decrease at Tietê primarily due to higher spot market energy purchases from unfavorable hydrology, higher transmission costs and lower collections	$	(36	)
Increase at Eletropaulo primarily due to higher collections mainly attributable to higher tariffs, partially offset by higher energy purchases resulting from unfavorable hydrology and higher transmission costs	12
Other business drivers	6
Total	$	(18	)



MCAC SBU	Amount
Increase in Panama primarily due to lower energy purchases resulting from favorable hydrology	$	22
Increase in El Salvador primarily due to lower energy purchase costs resulting from a decrease in fuel prices	12
Decrease in Puerto Rico primarily due to timing of coal payments partially offset by lower fuel purchase costs resulting from a decrease in commodities prices and higher collections from the offtaker	(18		)
Other business drivers	(4		)
Total	$	12



Europe SBU	Amount
Increase at Maritza primarily due to lower payments to fuel supplier	$	20
Increase due to operating cash provided by new operations at IPP4 in Jordan which commenced operations in July 2014	7
Decrease at Kilroot primarily due to lower collections resulting from lower volume, timing of outages and lower rates	(13		)
Decrease in operating cash at Ebute as a result of sale of business in 2014	(12		)
Other business drivers	1
Total	$	3



Asia SBU	Amount
Decrease in proportional operating cash flow at Masinloc resulting from 2014 business sell down as well as timing of customer collections, partially offset by higher collections resulting from better plant availability in 2015	$	(2	)
Other business drivers	—
Total	$	(2	)



Corporate SBU	Amount
Increase primarily at the Parent Company driven by lower current year interest payments, swap termination payments made in the prior year upon refinance of debt, lower benefit requirements as well as the collection of realized gains resulting from the Company’s corporate hedging program	$	58
Total	$	58

Proportional Free Cash Flow for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 increased $151 million, driven primarily by the following SBUs and key operating drivers excluding intercompany related transactions or adjustments pertaining to interest, tax sharing and charges for management fee and transfer pricing, but including timing of intercompany expenses paid on behalf of the businesses ($ in millions)



US SBU	Amount
Increase at DPL primarily due to higher collections, collection of deferred storm costs, lower interest paid and higher collateral deposits in the prior year as a result of outages	$	110
Decrease at Shady Point primarily driven by increases in inventory, lower collections during unit repairs, timing of collections as well as an increase in maintenance capital expenditures	(17		)
Decrease at Laurel Mountain primarily due to lower collections as a result of lower energy prices in the PJM market	(12		)
Decrease at IPALCO primarily due to lower collections driven by lower wholesale margins resulting from outages and lower prices as well as an increase in maintenance capital expenditures, partially offset by lower required pension contributions	(9		)
Other business drivers	1
Total	$	73



Andes SBU	Amount
Decrease at Chivor in Colombia primarily due to higher current year tax payments resulting from higher taxable income in the prior year	$	(44	)
Other business drivers	1
Total	$	(43	)



Brazil SBU	Amount
Decrease at Tietê primarily due to higher energy purchases in the spot market resulting from unfavorable hydrology, higher transmission costs, and decreased collections, partially offset by lower income tax payments	$	(48	)
Decrease at Cemig due to income tax refund received in the prior year	(14		)
Increase at Eletropaulo primarily due to higher collections mainly attributable to higher tariffs, partially offset by higher energy purchases resulting from unfavorable hydrology and higher transmission costs	32
Increase at Sul primarily due to higher collections mainly attributable to higher tariffs, partially offset by higher energy purchases resulting from unfavorable hydrology, higher transmission costs and higher interest on debt	21
Other business drivers	6
Total	$	(3	)



MCAC SBU	Amount
Increase in Panama primarily due to lower energy purchases resulting from favorable hydrology	$	43
Increase in El Salvador primarily due to lower energy purchase costs resulting from a decrease in fuel prices	37
Increase in Puerto Rico primarily due to lower fuel purchase costs from a decrease in commodities prices and higher collections from the offtaker	29
Decrease in the Dominican Republic due to lower collections from distribution companies, higher payments for energy in the spot market and higher maintenance capital expenditures due to higher planned outages	(53		)
Other business drivers	(4		)
Total	$	52



Europe SBU	Amount
Increase at Maritza primarily due to higher collections from the offtaker and lower payments to fuel supplier	$	61
Increase due to operating cash provided by new operations at IPP4 in Jordan which commenced operations in July 2014	13
Decrease at Kilroot primarily due to lower collections resulting from lower volume, timing of outages and lower rates	(24		)
Decrease in operating cash at Ebute as a result of sale of business in 2014	(18		)
Other business drivers	(8		)
Total	$	24



Asia SBU	Amount
Decrease in proportional operating cash flow at Masinloc resulting from 2014 business sell down as well as timing of customer collections and payables to the wholesale market for replacement power during outages, partially offset by higher collections resulting from better plant availability in 2015	$	(37	)
Other business drivers	(2		)
Total	$	(39	)



Corporate SBU	Amount
Increase primarily at the Parent Company driven by lower interest payments, the collection of realized gains resulting from the Company’s corporate hedging program, swap termination payments made in the prior year upon refinance of debt, as well as a reduction in capital expenditures and incentive payments	87
Total	$	87

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 facility; 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;


•	common stock repurchases and dividends;


•	taxes; and


•	Parent Company overhead and development costs.

The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facility. 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 the periods indicated as follows:



	June 30, 2015			December 31, 2014
	(in millions)
Consolidated cash and cash equivalents	$	1,022		$	1,539
Less: Cash and cash equivalents at subsidiaries	(982		)	(1,032		)
Parent and qualified holding companies’ cash and cash equivalents	40			507
Commitments under Parent credit facility	800			800
Less: Letters of credit under the credit facility	(61		)	(61		)
Borrowings available under Parent credit facility	739			739
Total Parent Company Liquidity	$	779		$	1,246

The Company paid a dividend of $0.10 per share to its common stockholders during the three months ended June 30, 2015. 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.

Recourse Debt — Our total recourse debt was $5.0 billion and $5.3 billion as of June 30, 2015 and December 31, 2014, respectively. See Note 8—Debt in Item 1.—Financial Statements of this Form 10-Q and Note 12—Debt in Item 8.—Financial Statements and Supplementary Data of our 2014 Form 10-K for additional detail.

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 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 2014 Form 10-K.

Various debt instruments at the Parent Company level, including our senior secured credit facility, contain certain restrictive covenants. As of June 30, 2015, the Parent Company was in compliance with these covenants which 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.

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 facility and outstanding debt securities at the Parent Company include events of default for certain bankruptcy-related events involving material subsidiaries. In addition, our senior secured credit facility 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 Sheets amounts to $2.0 billion. The portion of current debt related to such defaults was $764 million at June 30, 2015, all of which was non-recourse debt related to three subsidiaries — Maritza, Kavarna and Altai. See Note 8—Debt in Item 1.—Financial Statements of this Form 10-Q for additional detail.

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’ corporate debt agreements as of June 30, 2015 in order for such defaults to trigger an event of default or permit acceleration under AES’ 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. A material subsidiary is defined in the Company’s senior secured credit facility as any business that contributed 20% or more of the Parent Company’s total cash distributions from businesses for the four most recently completed fiscal quarters. As of June 30, 2015, none of the defaults listed above individually or in the aggregate results in or is at risk of triggering a cross-default under the recourse debt of the Company.

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 2014 Form 10-K. The Company’s critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2014 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 these remain as critical accounting policies as of and for the six months ended June 30, 2015.

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 2014 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 fuel 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 utilize contract strategies that lock in the spread per MWh between variable costs and the price at which the electricity can be sold. The portion of our sales and purchases that are not subject to such agreements or contracted businesses where indexation is not perfectly matched to business drivers will be exposed to commodity price risk.

AES businesses will see changes in variable margin performance as global commodity prices shift. As of June 30, 2015, the portfolio’s pretax earnings exposure for the remainder of 2015 to a 10% move in commodity prices would be approximately $10 million for U.S. power (DPL), $5 million for natural gas, $5 million for oil and $5 million for coal. 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. Spot power prices, contract indexation provisions and generation costs can be directly or indirectly affected by movements in the price of natural gas, oil and coal. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. Exposures are not perfectly linear or symmetric. The sensitivities are affected by a number of local or indirect market factors. Examples of these factors include hydrology, local 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 limit downside exposure by reducing dispatch in low market environments. 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 of switching; 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 some periods.

In 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 generally 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, the price of which depends on fuel pricing at the time required. 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 unhedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel.

In 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 drier 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.

In the MCAC SBU, our businesses have commodity exposure on unhedged volumes. Panama is highly 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. Additionally, the contract levels do not always match our generation availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot market to satisfy contract obligations.

In the Europe SBU, our Kilroot facility operates on a short-term sales strategy. To the extent that sales are unhedged, the commodity risk at our Kilroot business is to the clean dark spread — the difference between electricity price and our coal-based variable dispatch cost including emissions. Natural gas-fired generators set power prices for many periods, so higher natural gas prices generally expand margins and higher coal or emissions prices reduce them. Similarly, increased wind generation displaces higher cost generation, reducing Kilroot’s margins, and vice versa.

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 or shortfalls of generation relative to contract volumes settled 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. We have varying degrees of exposure 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, Kazakhstan Tenge, Mexican Peso and Philippine Peso. These

subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.

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 12-month forward-looking period stem from the following currencies: Argentine Peso, British Pound, Brazilian Real, Colombian Peso, Euro and Kazakhstani Tenge. As of June 30, 2015, assuming a 10% U.S. Dollar appreciation, adjusted pretax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Brazilian Real, Colombian Peso and Kazakhstani Tenge relative to the U.S. Dollar are projected to be reduced by $5 million for each currency for the remainder of 2015. The Argentine Peso, Euro and British Pound impacts relative to the U.S. Dollar are projected to be less than $5 million for each currency. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pretax earnings for 2015 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted pretax earnings exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility.

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

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

As of June 30, 2015, the portfolio’s pretax earnings exposure for the remainder of 2015 to a 100-basis-point increase in interest rates for our Argentine Peso, Brazilian Real, Colombian Peso, Euro, Kazakhstani Tenge and U.S. Dollar denominated debt would be approximately $15 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 CEO and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective as of June 30, 2015 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 disclosures.

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

PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of June 30, 2015.

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$1.7 billion ($536 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 of EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo’s defenses in the execution suit. On appeal, the case was remanded to the FDC for further proceedings to determine whether Eletropaulo is liable for the debt. In December 2012, the FDC issued a decision that Eletropaulo is liable for the debt. However, that decision was annulled on appeal and the case was remanded to the FDC for further proceedings. On remand at the FDC, the FDC has appointed an accounting expert who will issue a report on the amount of the alleged debt and the responsibility for its payment in light of the privatization. The parties will be entitled to take discovery and present arguments on the issues to be determined by the expert. 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$1.7 million ($538 thousand) as of December 31, 2014, or pay an indemnification amount of approximately R$15 million ($4.7 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 has been remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision. In January 2014, Eletropaulo informed the court that it intended to comply with the court’s decision by donating a green area inside a protection zone and restore watersheds, the aggregate cost of which is expected to be approximately R$1.7 million ($538 thousand). Eletropaulo also requested that the court add the current owner of the land where the Associação facilities are located, Empresa Metropolitana de Águas e Energia S.A. (“EMAE”), as a party to the lawsuit and order EMAE to perform the demolition and reforestation aspects of the court’s decision. In July 2014, the court requested the Secretary of the Environment for the State of São Paulo to notify the court of its opinion regarding the acceptability of the green areas to be donated by Eletropaulo to the State of São Paulo. In January 2015, the Secretary of the Environment for the State of São Paulo notified Eletropaulo and the court that it would not accept Eletropaulo’s proposed green areas donation. Instead of such green areas donation, the Secretary of the Environment proposed in March 2015 that Eletropaulo undertake an environmental project to offset the alleged environmental damage. The cost of such project is currently estimated to be R$1.7 million ($538 thousand). Eletropaulo is considering the Secretary of the Environment’s proposal.

In December 2001, Gridco Ltd. (“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 shareholders agreement between Gridco, the Company, AES ODPL, Jyoti and the Central Electricity Supply Company of Orissa Ltd. ("CESCO"), an affiliate of the Company. In the arbitration, 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. 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. A majority of the tribunal later awarded the respondents, including the Company, some of their costs relating to the arbitration. Gridco filed challenges of the tribunal’s awards with the local Indian court. Gridco’s challenge of the costs award has been dismissed by the court, but its challenge of the liability award remains pending. 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 into the BNDES financings provided to AES Elpa and AES Transgás, 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. The MPF 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. In April 2015, the FCA issued a decision holding that the FCSP should consider all five alleged violations. In June 2015, AES Elpa and AES Brasiliana (the successor of AES Transgás) filed a motion for clarification of the FCA’s decision. The lawsuit remains pending before the FCSP, but it will remain suspended until the interlocutory appeal before the FCA has been finally decided, including the motion for clarification. AES Elpa and AES Brasiliana 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.

Pursuant to their environmental audit, AES Sul and AES Florestal discovered 200 barrels of solid creosote waste and other contaminants at a pole factory that AES Florestal had been operating. The conclusion of the audit was that a prior operator of the pole factory, CEEE, had been using those contaminants to treat the poles that were manufactured at the factory. On their initiative, AES Sul and AES Florestal communicated with Brazilian authorities and CEEE about the adoption of containment and remediation measures. In March 2008, the State Attorney of the State of Rio Grande do Sul, Brazil filed a public civil action against AES Sul, AES Florestal and CEEE seeking an order requiring the companies to recover the contaminated area located on the grounds of the pole factory and an indemnity payment (approximately R$6 million ($2 million)) to the State’s Environmental Fund. In October 2011, the State Attorney Office filed a request for an injunction ordering the defendant companies to contain and remove the contamination immediately. The court granted injunctive relief on October 18, 2011, but determined only that defendant CEEE was required to proceed with the removal work. In May 2012, CEEE began the removal work in compliance with the injunction. The removal costs are estimated to be approximately R$60 million ($19 million) and the work was completed in February 2014. In parallel with the removal activities, a court-appointed expert investigation took place, which was concluded in May 2014. The court-appointed expert final report was presented to the State Attorneys in October 2014, and in January 2015 to the defendant companies. In March 2015, AES Sul and AES Florestal submitted comments and supplementary questions regarding the expert report. 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 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) in Brazil initiated arbitration in the ICC against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ GSA. Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Estado 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 sought 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 asserted that if it was determined that AESU was responsible for the termination of the GSA, AESU was 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 remains pending. Also, there are competing decisions of the Argentine and Uruguayan courts on whether the arbitration should be suspended, including an Argentine appellate court’s decision purporting to suspend the arbitration and a Uruguayan appellate court’s decision directing the arbitration to continue. Given the competing decisions, the Tribunal suspended the damages phase of the arbitration until February 2, 2015, at which time the Tribunal was to consider whether to lift the suspension. In April 2015, the Tribunal issued

an order lifting the suspension. The Tribunal has scheduled the damages hearing for November 16-17, 2015. 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 certain power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”). The Antimonopoly Agency determined that the Hydros had abused their market position and charged monopolistically high prices for power from January-February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT120 million ($630 thousand) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT440 million ($2.3 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 expanded the periods at issue to the entirety of 2009 for UK HPP and from January-October 2009 for Shulbinsk HPP, and sought increased damages of KZT1.2 billion ($6.4 million) from UK HPP and KZT1.3 billion ($6.9 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 opposed the request and asserted a counterclaim to confirm the award. In February 2014, the court rejected CFE's claims and granted AES Mérida's request to confirm the award. CFE has appealed the court's decision. The appeal is pending before the Mexican Supreme Court. AES Mérida believes it has meritorious grounds to defeat that action; however, there can be no assurances that it will be successful.

In October 2009, IPL received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review 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, November 2011, and October 2014, substantially similar personal injury lawsuits were filed by a total of 50 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 by-products of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The 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 six lawsuits filed between April 2010 and November 2011, and has also stayed the October 2014 lawsuit. Presently, discovery has been conducted only in the November 2009 lawsuit and only on 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 February 11, 2011, 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 ($317 thousand) and the suspension of Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities (“São Paulo EA”), 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 reduced the fine to R$757 thousand ($240 thousand) and recognized the possibility of an additional 40% reduction of the fine if Eletropaulo agrees to recover the affected area with additional vegetation. Eletropaulo did not appeal the decision and discussed 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 Eletropaulo with the terms of any possible settlement. The Park Administrator subsequently approved an area for the recovery project different from the affected area, which was no longer available. On January 23, 2015, AES Eletropaulo entered into a Recovery and Compensation Agreement with the Coordenadoria de Fiscalização Ambiental (“CFA”) to restore 3.2 hectares during the course of two years, which restoration is currently estimated to cost R$592 thousand ($187 thousand). In June 2015, the State of São Paulo Prosecutor’s Office of São Bernardo do Campo decided to close its Civil Proceeding, subject to the approval of the Superior Counsel of the Public Prosecutor’s Office. Upon completion of the recovery project as approved and established in the Recovery and Compensation Agreement, AES will be entitled to a 40% reduction (R$303 thousand or $96 thousand) of the fine as legally provided.

In June 2011, the São Paulo Municipal Tax Authority (the “Municipality”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking to collect services tax (“ISS”) that allegedly had not been paid on revenues for services rendered by Eletropaulo. Eletropaulo challenged the assessments on the ground that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$3.2 billion ($1 billion) as estimated by Eletropaulo. Eletropaulo has appealed to the Second Instance Administrative Court. No tax is due while the appeal is pending. 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 January 2012, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê paid PIS and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê challenged the assessment on the ground that the tax rate was set in the applicable legislation. In April 2013, the First Instance Administrative Court determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable for unpaid taxes, interest and penalties totaling approximately R$885 million ($280 million) as estimated by AES Tietê. AES Tietê appealed to the Second Instance Administrative Court (“SAIC”). In January 2015, the SAIC issued a decision in AES Tietê’s favor, finding that AES Tietê was not liable for unpaid taxes. The public prosecutor subsequently filed an appeal, which was denied as untimely. The Tax Authority thereafter filed a motion for clarification of the SAIC’s decision, which motion remains pending. AES Tietê believes it has meritorious defenses to the claim 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, among others, Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NC”) (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 Republic’s Camara de Cuentas (“Camara”) perform an audit of the allegations in the criminal complaint. The audit is ongoing and the Camara has not issued its final report to date. Further, in August 2012, Coastal and NC initiated an international arbitration proceeding against FONPER and the Dominican Republic (“Respondents”), seeking a declaration that Coastal and NC have acted both lawfully and in accordance with the relevant contracts with the Respondents in relation to the management of Itabo. Coastal and NC 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 NC further seek damages from the Respondents resulting from their breach of contract. The Respondents have denied the claims and challenged the jurisdiction of the arbitral Tribunal. The Tribunal has established the procedural schedule for the arbitration, but has not yet scheduled dates for the final evidentiary hearing. In February 2015, the Respondents made an application requesting that the Tribunal rule on their jurisdictional objections prior to giving any consideration to the merits of the claims of Coastal and NC. Coastal and NC have opposed the application. At the Tribunal’s direction, the parties are briefing supplemental issues relating to the Respondents’ application. The AES parties believe they have meritorious claims and defenses, which they will assert vigorously; however, there can be no assurances that they will be successful in their efforts.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2014 Form 10-K in 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 ⁽²⁾
4/1/2015 — 4/30/15	591,028	$	12.75	591,028	$	380,935,833
5/1/2015 — 5/30/15	20,000,000	13.07		20,000,000	119,535,833
6/1/2015 — 6/30/15	175,740	13.16		175,740	117,225,388
Total	20,766,768			20,766,768

_____________________________


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

⁽²⁾

The authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases, purchases by contract (including, without limitation, accelerated stock repurchase programs or 10b5-1 plans) and/or privately negotiated transactions. There is no assurance as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS



4.1		Nineteenth Supplemental Indenture, dated April 6, 2015, between The AES Corporation and Wells Fargo Bank, N.A., as Trustee is incorporated herein by reference to Exhibit 4.1 to the Company’s Form 8-K filed on April 6, 2015.
10.1		Form of Performance Unit Award Agreement Pursuant to The AES Corporation 2003 Long Term Compensation Plan (filed herewith).

10.2		Form of Restricted Stock Unit Award Agreement Pursuant to The AES Corporation 2003 Long Term Compensation Plan (filed herewith).


10.3		Form of Performance Stock Unit Award Agreement Pursuant to The AES Corporation 2003 Long Term Compensation Plan (filed herewith).

10.4		Form of Nonqualified Stock Option Award Agreement Pursuant to The AES Corporation 2003 Long Term Compensation Plan (filed herewith).

10.5		The AES Corporation Amended and Restated Executive Severance Plan dated April 23, 2015 (filed herewith).

10.6		The AES Corporation Severance Plan, as amended and restated on April 23, 2015 (filed herewith).

10.7		Form of Retroactive Consent To Provide for Double-Trigger In Change-In-Control Transactions (filed herewith).

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

31.2		Rule 13a-14(a)/15d-14(a) Certification of Thomas M. O’Flynn (filed herewith).

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

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

101.INS		XBRL Instance Document (filed herewith).

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

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

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

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

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

SIGNATURES

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



		THE AES CORPORATION (Registrant)

Date:	August 7, 2015	By:	/s/ THOMAS M. O’FLYNN
			Name:	Thomas M. O’Flynn
			Title:	Executive Vice President and Chief Financial Officer (Principal Financial Officer)

		By:	/s/ FABIAN E. SOUZA
			Name:	Fabian E. Souza
			Title:	Vice President and Controller (Principal Accounting Officer)