10-Q 1 d531783d10q.htm FORM 10-Q

##### Table of Contents

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 March 31, 2013

or

| ¨ | 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):

Large accelerated filer x |  | Accelerated filer ¨ |  | Non-accelerated filer ¨ |  | Smaller reporting company ¨
|  |  |  | (Do not check if a smaller reporting company) |  |

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

The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, on May 3, 2013 was 746,540,903.

##### Table of Contents

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2013

TABLE OF CONTENTS

PART I: FINANCIAL INFORMATION |  |  | 1 |
ITEM 1. |  | FINANCIAL STATEMENTS |  |  | 1 |
|  | Condensed Consolidated Balance Sheets |  |  | 1 |
|  | Condensed Consolidated Statements of Operations |  |  | 2 |
|  | Condensed Consolidated Statements of Comprehensive Income |  |  | 3 |
|  | Condensed Consolidated Statements of Cash Flows |  |  | 4 |
|  | Notes to Condensed Consolidated Financial Statements |  |  | 5 |
ITEM 2. |  | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |  |  | 29 |
ITEM 3. |  | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |  |  | 59 |
ITEM 4. |  | CONTROLS AND PROCEDURES |  |  | 62 |
PART II: OTHER INFORMATION |  |  | 63 |
ITEM 1. |  | LEGAL PROCEEDINGS |  |  | 63 |
ITEM 1A. |  | RISK FACTORS |  |  | 71 |
ITEM 2. |  | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |  |  | 71 |
ITEM 3. |  | DEFAULTS UPON SENIOR SECURITIES |  |  | 71 |
ITEM 4. |  | MINE SAFETY DISCLOSURES |  |  | 71 |
ITEM 5. |  | OTHER INFORMATION |  |  | 71 |
ITEM 6. |  | EXHIBITS |  |  | 71 |
SIGNATURES |  |  | 72 |

##### Table of Contents

PART I: FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

THE AES CORPORATION

Condensed Consolidated Balance Sheets

(Unaudited)

|  | March 31, 2013 |  |  | December 31, 2012 |
|  | (in millions, except share and per share data) |
ASSETS |  |  |  |  |  |  |  |
CURRENT ASSETS |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 2,301 |  |  | $ | 1,966 |
Restricted cash |  |  | 760 |  |  |  | 748 |
Short-term investments |  |  | 851 |  |  |  | 696 |
Accounts receivable, net of allowance for doubtful accounts of $314 and $306, respectively |  |  | 2,633 |  |  |  | 2,671 |
Inventory |  |  | 755 |  |  |  | 766 |
Deferred income taxes |  |  | 231 |  |  |  | 222 |
Prepaid expenses |  |  | 256 |  |  |  | 230 |
Other current assets |  |  | 1,403 |  |  |  | 1,103 |
Current assets of discontinued operations and held for sale assets |  |  | 68 |  |  |  | 63 |
Total current assets |  |  | 9,258 |  |  |  | 8,465 |
NONCURRENT ASSETS |  |  |  |  |  |  |  |
Property, Plant and Equipment: |  |  |  |  |  |  |  |
Land |  |  | 1,019 |  |  |  | 1,007 |
Electric generation, distribution assets and other |  |  | 32,210 |  |  |  | 31,656 |
Accumulated depreciation |  |  | (9,745 | ) |  |  | (9,645 | )
Construction in progress |  |  | 2,528 |  |  |  | 2,783 |
Property, plant and equipment, net |  |  | 26,012 |  |  |  | 25,801 |
Other Assets: |  |  |  |  |  |  |  |
Investments in and advances to affiliates |  |  | 1,195 |  |  |  | 1,196 |
Debt service reserves and other deposits |  |  | 593 |  |  |  | 565 |
Goodwill |  |  | 1,999 |  |  |  | 1,999 |
Other intangible assets, net of accumulated amortization of $193 and $276, respectively |  |  | 417 |  |  |  | 429 |
Deferred income taxes |  |  | 986 |  |  |  | 996 |
Other noncurrent assets |  |  | 2,153 |  |  |  | 2,240 |
Noncurrent assets of discontinued operations and held for sale assets |  |  | 105 |  |  |  | 139 |
Total other assets |  |  | 7,448 |  |  |  | 7,564 |
TOTAL ASSETS |  | $ | 42,718 |  |  | $ | 41,830 |
LIABILITIES AND EQUITY |  |  |  |  |  |  |  |
CURRENT LIABILITIES |  |  |  |  |  |  |  |
Accounts payable |  | $ | 2,951 |  |  | $ | 2,631 |
Accrued interest |  |  | 415 |  |  |  | 295 |
Accrued and other liabilities |  |  | 2,251 |  |  |  | 2,505 |
Non-recourse debt, including $424 and $282, respectively, related to variable interest entities |  |  | 3,108 |  |  |  | 2,829 |
Recourse debt |  |  | 507 |  |  |  | 11 |
Current liabilities of discontinued operations and held for sale businesses |  |  | 54 |  |  |  | 48 |
Total current liabilities |  |  | 9,286 |  |  |  | 8,319 |
NONCURRENT LIABILITIES |  |  |  |  |  |  |  |
Non-recourse debt, including $1,118 and $1,076, respectively, related to variable interest entities |  |  | 12,815 |  |  |  | 12,554 |
Recourse debt |  |  | 5,454 |  |  |  | 5,951 |
Deferred income taxes |  |  | 1,239 |  |  |  | 1,237 |
Pension and other post-retirement liabilities |  |  | 2,389 |  |  |  | 2,455 |
Other noncurrent liabilities |  |  | 3,713 |  |  |  | 3,705 |
Noncurrent liabilities of discontinued operations and held for sale businesses |  |  | 3 |  |  |  | 17 |
Total noncurrent liabilities |  |  | 25,613 |  |  |  | 25,919 |
Contingencies and Commitments (see Note 8) |  |  |  |  |  |  |  |
Cumulative preferred stock of subsidiaries |  |  | 78 |  |  |  | 78 |
EQUITY |  |  |  |  |  |  |  |
THE AES CORPORATION STOCKHOLDERS’ EQUITY |  |  |  |  |  |  |  |
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 812,021,363 issued and 746,474,449 outstanding at March 31, 2013 and 810,679,839 issued and 744,263,855 outstanding at December 31, 2012) |  |  | 8 |  |  |  | 8 |
Additional paid-in capital |  |  | 8,527 |  |  |  | 8,525 |
Accumulated deficit |  |  | (182 | ) |  |  | (264 | )
Accumulated other comprehensive loss |  |  | (2,952 | ) |  |  | (2,920 | )
Treasury stock, at cost (65,546,914 shares at March 31, 2013 and 66,415,984 shares at December 31, 2012) |  |  | (768 | ) |  |  | (780 | )
Total AES Corporation stockholders’ equity |  |  | 4,633 |  |  |  | 4,569 |
NONCONTROLLING INTERESTS |  |  | 3,108 |  |  |  | 2,945 |
Total equity |  |  | 7,741 |  |  |  | 7,514 |
TOTAL LIABILITIES AND EQUITY |  | $ | 42,718 |  |  | $ | 41,830 |

See Notes to Condensed Consolidated Financial Statements

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THE AES CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
|  | (in millions, except per share amounts) |
Revenue: |  |  |  |  |  |  |  |
Regulated |  | $ | 2,246 |  |  | $ | 2,484 |
Non-Regulated |  |  | 2,019 |  |  |  | 2,102 |
Total revenue |  |  | 4,265 |  |  |  | 4,586 |
Cost of Sales: |  |  |  |  |  |  |  |
Regulated |  |  | (1,894 | ) |  |  | (2,056 | )
Non-Regulated |  |  | (1,616 | ) |  |  | (1,458 | )
Total cost of sales |  |  | (3,510 | ) |  |  | (3,514 | )
Gross margin |  |  | 755 |  |  |  | 1,072 |
General and administrative expenses |  |  | (61 | ) |  |  | (87 | )
Interest expense |  |  | (377 | ) |  |  | (416 | )
Interest income |  |  | 66 |  |  |  | 91 |
Other expense |  |  | (75 | ) |  |  | (28 | )
Other income |  |  | 68 |  |  |  | 18 |
Gain on sale of investments |  |  | 3 |  |  |  | 179 |
Asset impairment expense |  |  | (48 | ) |  |  | (10 | )
Foreign currency transaction losses |  |  | (32 | ) |  |  | (1 | )
Other non-operating expense |  |  | - |  |  |  | (49 | )
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES |  |  | 299 |  |  |  | 769 |
Income tax expense |  |  | (82 | ) |  |  | (268 | )
Net equity in earnings of affiliates |  |  | 4 |  |  |  | 13 |
INCOME FROM CONTINUING OPERATIONS |  |  | 221 |  |  |  | 514 |
Income from operations of discontinued businesses, net of income tax (benefit) expense of $(1) and $2, respectively |  |  | 14 |  |  |  | 6 |
Net loss from disposal and impairments of discontinued businesses, net of income tax (benefit) expense of $(1) and $0, respectively |  |  | (36 | ) |  |  | (5 | )
NET INCOME |  |  | 199 |  |  |  | 515 |
Noncontrolling interests: |  |  |  |  |  |  |  |
Less: Income from continuing operations attributable to noncontrolling interests |  |  | (115 | ) |  |  | (173 | )
Less: Income from discontinued operations attributable to noncontrolling interests |  |  | (2 | ) |  |  | (1 | )
Total net income attributable to noncontrolling interests |  |  | (117 | ) |  |  | (174 | )
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION |  | $ | 82 |  |  | $ | 341 |
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS: |  |  |  |  |  |  |  |
Income from continuing operations, net of tax |  | $ | 106 |  |  | $ | 341 |
Loss from discontinued operations, net of tax |  |  | (24 | ) |  |  | - |
Net income |  | $ | 82 |  |  | $ | 341 |
BASIC EARNINGS PER SHARE: |  |  |  |  |  |  |  |
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax |  | $ | 0.14 |  |  | $ | 0.45 |
Loss from discontinued operations attributable to The AES Corporation common stockholders, net of tax |  |  | (0.03 | ) |  |  | - |
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS |  | $ | 0.11 |  |  | $ | 0.45 |
DILUTED EARNINGS PER SHARE: |  |  |  |  |  |  |  |
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax |  | $ | 0.14 |  |  | $ | 0.44 |
Loss from discontinued operations attributable to The AES Corporation common stockholders, net of tax |  |  | (0.03 | ) |  |  | - |
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS |  | $ | 0.11 |  |  | $ | 0.44 |

See Notes to Condensed Consolidated Financial Statements

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THE AES CORPORATION

Condensed Consolidated Statements of Comprehensive Income

(Unaudited)

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
|  | (in millions) |
NET INCOME |  | $ | 199 |  |  | $ | 515 |
Foreign currency translation activity: |  |  |  |  |  |  |  |
Foreign currency translation adjustments, net of income tax (expense) benefit of $0 and $(1), respectively |  |  | (32 | ) |  |  | 142 |
Reclassification to earnings, net of income tax (expense) benefit of $0 and $0, respectively |  |  | (3 | ) |  |  | (1 | )
Total foreign currency translation adjustments |  |  | (35 | ) |  |  | 141 |
Derivative activity: |  |  |  |  |  |  |  |
Change in derivative fair value, net of income tax (expense) benefit of $0 and $(4), respectively |  |  | (16 | ) |  |  | 21 |
Reclassification to earnings, net of income tax (expense) benefit of $(7) and $(28), respectively |  |  | 24 |  |  |  | 86 |
Total change in fair value of derivatives |  |  | 8 |  |  |  | 107 |
Pension activity: |  |  |  |  |  |  |  |
Reclassification to earnings due to amortization of net actuarial loss, net of income tax (expense) benefit of $(7) and $(3), respectively |  |  | 14 |  |  |  | 6 |
Total pension adjustments |  |  | 14 |  |  |  | 6 |
OTHER COMPREHENSIVE INCOME (LOSS) |  |  | (13 | ) |  |  | 254 |
COMPREHENSIVE INCOME |  |  | 186 |  |  |  | 769 |
Less: Comprehensive income attributable to noncontrolling interests |  |  | (136 | ) |  |  | (245 | )
COMPREHENSIVE INCOME ATTRIBUTABLE TO THE AES CORPORATION |  | $ | 50 |  |  | $ | 524 |

See Notes to Condensed Consolidated Financial Statements

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THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
|  | (in millions) |
OPERATING ACTIVITIES: |  |  |  |  |  |  |  |
Net income |  | $ | 199 |  |  | $ | 515 |
Adjustments to net income: |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 329 |  |  |  | 360 |
Gain from sale of investments and impairment expense |  |  | 59 |  |  |  | (92 | )
Deferred income taxes |  |  | 13 |  |  |  | 101 |
Provisions for contingencies |  |  | 26 |  |  |  | 17 |
Loss on the extinguishment of debt |  |  | 47 |  |  |  | - |
Loss on disposals and impairments - discontinued operations |  |  | 38 |  |  |  | - |
Other |  |  | 56 |  |  |  | (40 | )
Changes in operating assets and liabilities |  |  |  |  |  |  |  |
(Increase) decrease in accounts receivable |  |  | 42 |  |  |  | (189 | )
(Increase) decrease in inventory |  |  | (4 | ) |  |  | (11 | )
(Increase) decrease in prepaid expenses and other current assets |  |  | (192 | ) |  |  | (117 | )
(Increase) decrease in other assets |  |  | (45 | ) |  |  | (156 | )
Increase (decrease) in accounts payable and other current liabilities |  |  | 174 |  |  |  | 266 |
Increase (decrease) in income tax payables, net |  |  | (123 | ) |  |  | (161 | )
Increase (decrease) in other liabilities |  |  | (1 | ) |  |  | 41 |
Net cash provided by operating activities |  |  | 618 |  |  |  | 534 |
INVESTING ACTIVITIES: |  |  |  |  |  |  |  |
Capital expenditures |  |  | (546 | ) |  |  | (579 | )
Proceeds from the sale of businesses, net of cash sold |  |  | 1 |  |  |  | 63 |
Proceeds from the sale of assets |  |  | 6 |  |  |  | 4 |
Sale of short-term investments |  |  | 1,335 |  |  |  | 1,505 |
Purchase of short-term investments |  |  | (1,492 | ) |  |  | (1,855 | )
(Increase) decrease in restricted cash |  |  | (35 | ) |  |  | 28 |
(Increase) decrease in debt service reserves and other assets |  |  | (10 | ) |  |  | 20 |
Proceeds from government grants for asset construction |  |  | 1 |  |  |  | 85 |
Other investing |  |  | 14 |  |  |  | 4 |
Net cash used in investing activities |  |  | (726 | ) |  |  | (725 | )
FINANCING ACTIVITIES: |  |  |  |  |  |  |  |
Borrowings (repayments) under the revolving credit facilities, net |  |  | 15 |  |  |  | (281 | )
Issuance of non-recourse debt |  |  | 1,491 |  |  |  | 503 |
Repayments of recourse debt |  |  | (2 | ) |  |  | (3 | )
Repayments of non-recourse debt |  |  | (1,007 | ) |  |  | (151 | )
Payments for financing fees |  |  | (33 | ) |  |  | (12 | )
Distributions to noncontrolling interests |  |  | (31 | ) |  |  | (19 | )
Contributions from noncontrolling interests |  |  | 55 |  |  |  | 5 |
Dividends paid on AES common stock |  |  | (30 | ) |  |  | - |
Financed capital expenditures |  |  | (7 | ) |  |  | (6 | )
Other financing |  |  | 4 |  |  |  | 1 |
Net cash provided by financing activities |  |  | 455 |  |  |  | 37 |
Effect of exchange rate changes on cash |  |  | (8 | ) |  |  | 25 |
(Increase) decrease in cash of discontinued and held for sale businesses |  |  | (4 | ) |  |  | 99 |
Total increase (decrease) in cash and cash equivalents |  |  | 335 |  |  |  | (30 | )
Cash and cash equivalents, beginning |  |  | 1,966 |  |  |  | 1,688 |
Cash and cash equivalents, ending |  | $ | 2,301 |  |  | $ | 1,658 |
SUPPLEMENTAL DISCLOSURES: |  |  |  |  |  |  |  |
Cash payments for interest, net of amounts capitalized |  | $ | 234 |  |  | $ | 291 |
Cash payments for income taxes, net of refunds |  | $ | 295 |  |  | $ | 325 |

See Notes to Condensed Consolidated Financial Statements

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THE AES CORPORATION

Notes to Condensed Consolidated Financial Statements

For the Three Months Ended March 31, 2013 and 2012

1. FINANCIAL STATEMENT PRESENTATION

The prior period condensed consolidated financial statements in this Quarterly Report on Form 10-Q (“Form 10-Q”) have been reclassified to reflect the businesses held for sale and discontinued operations as discussed in Note 15 — Discontinued Operations and Held for Sale Businesses.

Consolidation

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

Interim Financial Presentation

The accompanying unaudited condensed consolidated financial statements and footnotes have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”), as contained in the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification, for interim financial information and Article 10 of Regulation S-X issued by the U.S. Securities and Exchange Commission (“SEC”). Accordingly, they do not include all the information and footnotes required by U.S. GAAP for annual fiscal reporting periods. In the opinion of management, the interim financial information includes all adjustments of a normal recurring nature necessary for a fair presentation of the results of operations, financial position, comprehensive income and cash flows. The results of operations for the three months ended March 31, 2013 are not necessarily indicative of results that may be expected for the year ending December 31, 2013. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2012 audited consolidated financial statements and notes thereto, which are included in the 2012 Form 10-K filed with the SEC on February 26, 2013 (the “2012 Form 10-K”).

Accounting Pronouncements Issued But Not Yet Effective

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

ASU No. 2013-05, Foreign Currency Matters (Topic 830), “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity.”

In March 2013, the FASB issued ASU No. 2013-05, which requires an entity to release any related cumulative translation adjustment into net income when it ceases to have a controlling financial interest in a subsidiary or group of assets that is a business (other than a sale of in-substance real estate) within a foreign entity. Accordingly, the cumulative translation adjustment should be released into net income only if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided. For an equity method investment that is a foreign entity, the partial sale guidance still applies. As such, a pro rata portion of the cumulative translation adjustment should be released into net income upon a partial sale of such an equity method investment. In those instances, the cumulative translation

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adjustment is released into net income only if the partial sale represents a complete or substantially complete liquidation of the foreign entity that contains the equity method investment. The amendments are effective prospectively for fiscal years (and interim reporting periods within those years) beginning after December 15, 2013. Early adoption is permitted. The Company is currently evaluating the impact of adopting ASU No. 2013-05 on the Company’s financial position, results of operations, and cash flows.

2. INVENTORY

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

|  | March 31, 2013 |  |  | December 31, 2012 |
|  | (in millions) |
Coal, fuel oil and other raw materials |  | $ | 363 |  |  | $ | 373 |
Spare parts and supplies |  |  | 392 |  |  |  | 393 |
Total |  | $ | 755 |  |  | $ | 766 |

3. FAIR VALUE

The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. By virtue of these amounts being estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. There were no changes in fair valuation techniques during the period and the Company continues to follow the valuation techniques described in Note 4. — Fair Value in Item 8. — Financial Statements and Supplementary Data of its 2012 Form 10-K.

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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 March 31, 2013 and December 31, 2012:

|  | March 31, 2013 |  |  | December 31, 2012 |
|  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |
|  | (in millions) |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AVAILABLE-FOR-SALE:(1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Debt securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unsecured debentures |  | $ | - |  |  | $ | 615 |  |  | $ | - |  |  | $ | 615 |  |  | $ | - |  |  | $ | 448 |  |  | $ | - |  |  | $ | 448 |
Certificates of deposit |  |  | - |  |  |  | 137 |  |  |  | - |  |  |  | 137 |  |  |  | - |  |  |  | 143 |  |  |  | - |  |  |  | 143 |
Government debt securities |  |  | - |  |  |  | 28 |  |  |  | - |  |  |  | 28 |  |  |  | - |  |  |  | 34 |  |  |  | - |  |  |  | 34 |
Subtotal |  |  | - |  |  |  | 780 |  |  |  | - |  |  |  | 780 |  |  |  | - |  |  |  | 625 |  |  |  | - |  |  |  | 625 |
Equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mutual funds |  |  | - |  |  |  | 57 |  |  |  | - |  |  |  | 57 |  |  |  | - |  |  |  | 56 |  |  |  | - |  |  |  | 56 |
Subtotal |  |  | - |  |  |  | 57 |  |  |  | - |  |  |  | 57 |  |  |  | - |  |  |  | 56 |  |  |  | - |  |  |  | 56 |
Total available-for-sale |  |  | - |  |  |  | 837 |  |  |  | - |  |  |  | 837 |  |  |  | - |  |  |  | 681 |  |  |  | - |  |  |  | 681 |
TRADING: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mutual funds |  |  | 12 |  |  |  | - |  |  |  | - |  |  |  | 12 |  |  |  | 12 |  |  |  | - |  |  |  | - |  |  |  | 12 |
Total trading |  |  | 12 |  |  |  | - |  |  |  | - |  |  |  | 12 |  |  |  | 12 |  |  |  | - |  |  |  | - |  |  |  | 12 |
DERIVATIVES: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives |  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | 2 |  |  |  | - |  |  | $ | 2 |  |  | $ | - |  |  |  | 2 |
Cross currency derivatives |  |  | - |  |  |  | 8 |  |  |  | - |  |  |  | 8 |  |  |  | - |  |  |  | 6 |  |  |  | - |  |  |  | 6 |
Foreign currency derivatives |  |  | - |  |  |  | 6 |  |  |  | 82 |  |  |  | 88 |  |  |  | - |  |  |  | 2 |  |  |  | 79 |  |  |  | 81 |
Commodity derivatives |  |  | - |  |  |  | 6 |  |  |  | 1 |  |  |  | 7 |  |  |  | - |  |  |  | 8 |  |  |  | 3 |  |  |  | 11 |
Total derivatives |  |  | - |  |  |  | 22 |  |  |  | 83 |  |  |  | 105 |  |  |  | - |  |  |  | 18 |  |  |  | 82 |  |  |  | 100 |
TOTAL ASSETS |  | $ | 12 |  |  | $ | 859 |  |  | $ | 83 |  |  | $ | 954 |  |  | $ | 12 |  |  | $ | 699 |  |  | $ | 82 |  |  | $ | 793 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
DERIVATIVES: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives |  | $ | - |  |  | $ | 469 |  |  | $ | 72 |  |  | $ | 541 |  |  | $ | - |  |  | $ | 153 |  |  | $ | 412 |  |  | $ | 565 |
Cross currency derivatives |  |  | - |  |  |  | 3 |  |  |  | - |  |  |  | 3 |  |  |  | - |  |  |  | 6 |  |  |  | - |  |  |  | 6 |
Foreign currency derivatives |  |  | - |  |  |  | 7 |  |  |  | 11 |  |  |  | 18 |  |  |  | - |  |  |  | 7 |  |  |  | 7 |  |  |  | 14 |
Commodity derivatives |  |  | - |  |  |  | 24 |  |  |  | 69 |  |  |  | 93 |  |  |  | - |  |  |  | 13 |  |  |  | 59 |  |  |  | 72 |
Total derivatives |  |  | - |  |  |  | 503 |  |  |  | 152 |  |  |  | 655 |  |  |  | - |  |  |  | 179 |  |  |  | 478 |  |  |  | 657 |
TOTAL LIABILITIES |  | $ | - |  |  | $ | 503 |  |  | $ | 152 |  |  | $ | 655 |  |  | $ | - |  |  | $ | 179 |  |  | $ | 478 |  |  | $ | 657 |

(1) | Amortized cost approximated fair value at March 31, 2013 and December 31, 2012. As of March 31, 2013, all available-for-sale debt securities had stated maturities within one year.

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##### Table of Contents

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 months ended March 31, 2013 and 2012 (presented net by type of derivative where any foreign currency impacts are presented as part of gains (losses) in earnings or other comprehensive income as appropriate). Transfers between Level 3 and Level 2 are determined as of the end of the reporting period and principally result from changes in significance of unobservable inputs used to calculate the credit valuation adjustment.

|  | Three Months Ended March 31, 2013 |
|  | Interest Rate |  |  | Foreign Currency |  |  | Commodity |  |  | Total |
|  | (in millions) |
Balance at January 1 |  | $ | (412 | ) |  | $ | 73 |  |  | $ | (57 | ) |  | $ | (396 | )
Total gains (losses) (realized and unrealized): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Included in earnings |  |  | - |  |  |  | (1 | ) |  |  | (10 | ) |  |  | (11 | )
Included in other comprehensive income |  |  | (17 | ) |  |  | - |  |  |  | - |  |  |  | (17 | )
Included in regulatory (assets) liabilities |  |  | - |  |  |  | - |  |  |  | (1 | ) |  |  | (1 | )
Settlements |  |  | 23 |  |  |  | (1 | ) |  |  | - |  |  |  | 22 |
Transfers of (assets) liabilities out of Level 3 |  |  | 334 |  |  |  | - |  |  |  | - |  |  |  | 334 |
Balance at March 31 |  | $ | (72 | ) |  | $ | 71 |  |  | $ | (68 | ) |  | $ | (69 | )
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period |  | $ | - |  |  | $ | (2 | ) |  | $ | (10 | ) |  | $ | (12 | )

|  | Three Months Ended March 31, 2012 |
|  | Interest Rate |  |  | Cross Currency |  |  | Foreign Currency |  |  | Commodity |  |  | Total |
|  | (in millions) |
Balance at January 1 |  | $ | (128 | ) |  | $ | (18 | ) |  | $ | 51 |  |  | $ | (53 | ) |  | $ | (148 | )
Total gains (losses) (realized and unrealized): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Included in earnings |  |  | (1 | ) |  |  | - |  |  |  | (2 | ) |  |  | 8 |  |  |  | 5 |
Included in other comprehensive income |  |  | 1 |  |  |  | 14 |  |  |  | - |  |  |  | - |  |  |  | 15 |
Included in regulatory (assets) liabilities |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Settlements |  |  | 6 |  |  |  | 4 |  |  |  | (1 | ) |  |  | (1 | ) |  |  | 8 |
Transfers of assets (liabilities) into Level 3 |  |  | (28 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (28 | )
Transfers of (assets) liabilities out of Level 3 |  |  | 26 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 26 |
Balance at March 31 |  | $ | (124) |  |  | $ | - |  |  | $ | 48 |  |  | $ | (46 | ) |  | $ | (122 | )
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period |  | $ | - |  |  | $ | - |  |  | $ | (3 | ) |  | $ | 9 |  |  | $ | 6 |

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##### Table of Contents

The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) at March 31, 2013:

Type of Derivative |  | Fair Value |  |  | Unobservable Input |  | Amount or Range (Weighted Average) |
|  | (in millions) |  |  |  |  |  |
Interest rate |  | $ | (72 | ) |  | Subsidiaries’ credit spreads |  |  | 2.15% - 9.03%(4.35%) |
Foreign currency: |  |  |  |  |  |  |  |  |  |
Embedded derivative — Argentine Peso |  |  | 70 |  |  | Argentine Peso to U.S. Dollar currency exchange rate after 3 years |  |  | 14.4 - 21.2(17.7) |
Commodity: |  |  |  |  |  |  |  |  |  |
Embedded derivative — |  |  |  |  |  |  |  |  |  |
Aluminum |  |  | (65 | ) |  | Market price of power for customer in Cameroon (per KWh) |  |  | $0.06 - $0.14($0.12) |
Other |  |  | (2 | ) |  |  |  |  |  |
Total |  | $ | (69 | ) |  |  |  |  |  |

Nonrecurring Measurements

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

|  | Three Months Ended March 31, 2013 |
|  | Carrying Amount |  |  | Fair Value |  |  | Gross Loss |
|  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |
|  | (in millions) |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-lived assets held and used:(1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Beaver Valley |  | $ | 61 |  |  | $ | - |  |  | $ | - |  |  | $ | 15 |  |  | $ | 46 |
Long-lived assets held for sale:(1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Wind turbines |  |  | 25 |  |  |  | - |  |  |  | - |  |  |  | 25 |  |  |  | - |
Discontinued operations and held for sale businesses:(2) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Ukraine utilities |  |  | 143 |  |  |  | - |  |  |  | 109 |  |  |  | - |  |  |  | 38 |

|  | Three Months Ended March 31, 2012 |
|  | Carrying Amount |  |  | Fair Value |  |  | Gross Loss |
|  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |
|  | (in millions) |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-lived assets held and used:(1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Kelanitissa |  |  | 22 |  |  |  | - |  |  |  | - |  |  |  | 17 |  |  |  | 5 |
Equity method investments(3) |  |  | 204 |  |  |  | - |  |  |  | 155 |  |  |  | - |  |  |  | 49 |

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

(2) | See Note 15 — Discontinued Operations and Held For Sale Businesses for further information. Also, the gross loss equals the carrying amount of the disposal group less its fair value less costs to sell.

(3) | See Note 14 — Other Non-Operating Expense for further information.

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##### Table of Contents

The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets during the three months ended March 31, 2013:

|  | Fair Value |  |  | Valuation Technique |  | Unobservable Input |  | Range (Weighted Average) |
|  | (in millions) |  |  |  |  |  |  | ($ in millions) |
Long-lived assets held and used: |  |  |  |  |  |  |  |  |  |  |  |
Beaver Valley |  | $ | 15 |  |  | Discounted cash flow |  | Annual revenue growth |  |  | 3% to 45% (19%) |
|  |  |  |  |  |  |  | Annual pretax operating margin |  |  | -42% to 41% (25%) |
|  |  |  |  |  |  |  | Weighted average cost of capital |  |  | 7% |
Long-lived assets held for sale: |  |  |  |  |  |  |  |  |  |  |  |
Wind turbines |  |  | 25 |  |  | Market Approach |  | Indicative offer prices |  |  | $12 to $38 ($25) |
Total |  | $ | 40 |  |  |  |  |  |  |  |  |

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 March 31, 2013 and December 31, 2012, but for which fair value is disclosed.

|  | Carrying Amount |  |  | Fair Value |
|  |  | Total |  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |
|  | (in millions) |
March 31, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable — noncurrent(1) |  | $ | 295 |  |  | $ | 167 |  |  | $ | - |  |  | $ | - |  |  | $ | 167 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Non-recourse debt |  |  | 15,923 |  |  |  | 16,416 |  |  |  | - |  |  |  | 14,212 |  |  |  | 2,204 |
Recourse debt |  |  | 5,961 |  |  |  | 6,724 |  |  |  | - |  |  |  | 6,724 |  |  |  | - |
December 31, 2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable — noncurrent(1) |  | $ | 304 |  |  | $ | 188 |  |  | $ | - |  |  | $ | - |  |  | $ | 188 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Non-recourse debt |  |  | 15,383 |  |  |  | 16,110 |  |  |  | - |  |  |  | 13,811 |  |  |  | 2,299 |
Recourse debt |  |  | 5,962 |  |  |  | 6,628 |  |  |  | - |  |  |  | 6,628 |  |  |  | - |

(1) | These accounts receivable principally relate to amounts due from the independent system operator in Argentina and are included in “Noncurrent assets — Other” in the accompanying condensed consolidated balance sheets. The fair value of these accounts receivable excludes value added tax of $53 million and $55 million at March 31, 2013 and December 31, 2012, respectively.

4. INVESTMENTS IN MARKETABLE SECURITIES

The Company’s investments in marketable debt and equity securities as of March 31, 2013 and December 31, 2012 by security class and by level within the fair value hierarchy have been disclosed in Note 3 — Fair Value. The security classes are determined based on the nature and risk of a security and are consistent with how the Company manages, monitors and measures its marketable securities. As of March 31, 2013, all available-for-sale debt securities had stated maturities within one year.

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##### Table of Contents

The following table summarizes the pre-tax gains and losses related to available-for-sale and trading securities for the three months ended March 31, 2013 and 2012. Gains and losses on the sale of investments are determined using the specific identification method. For the three months ended March 31, 2013 and 2012, there were no realized losses on the sale of available-for-sale securities and no other-than-temporary impairment of marketable securities recognized in earnings or other comprehensive income.

|  | 2013 |  |  | 2012 |
|  | (in millions) |
Gains included in earnings that relate to trading securities held at the reporting date |  | $ | 1 |  |  | $ | - |
Gross proceeds from sales of available-for-sale securities |  |  | 1,704 |  |  |  | 1,523 |
Gross realized gains on sales |  |  | - |  |  |  | 1 |

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

Volume of Activity

The following tables set forth, by type of derivative, the Company’s outstanding notional under its derivatives and the weighted average remaining term as of March 31, 2013 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:

|  | March 31, 2013 |
|  | Current |  |  | Maximum |  |  |  |  |  |  |
Interest Rate and Cross Currency |  | Derivative Notional |  |  | Derivative Notional Translated to USD |  |  | Derivative Notional |  |  | Derivative Notional Translated to USD |  |  | Weighted Average Remaining Term |  |  | % of Debt Currently Hedged by Index(2) |
|  | (in millions) |  |  | (in years) |  |  |  |
Interest Rate Derivatives:(1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
LIBOR (U.S. Dollar) |  |  | 3,451 |  |  | $ | 3,451 |  |  |  | 4,226 |  |  | $ | 4,226 |  |  |  | 9 |  |  |  | 70 | %
EURIBOR (Euro) |  |  | 605 |  |  |  | 776 |  |  |  | 605 |  |  |  | 776 |  |  |  | 9 |  |  |  | 67 | %
LIBOR (British Pound) |  |  | 69 |  |  |  | 105 |  |  |  | 69 |  |  |  | 105 |  |  |  | 13 |  |  |  | 83 | %
Cross Currency Swaps: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Chilean Unidad de Fomento |  |  | 6 |  |  |  | 271 |  |  |  | 6 |  |  |  | 271 |  |  |  | 9 |  |  |  | 85 | %

(1) | The Company’s interest rate derivative instruments primarily include accreting and amortizing notionals. The maximum derivative notional represents the largest notional at any point between March 31, 2013 and the maturity of the derivative instrument, which includes forward starting derivative instruments. The interest rate and cross currency derivatives range in maturity through 2030 and 2028, respectively.

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

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##### Table of Contents

|  | March 31, 2013 |
Foreign Currency Derivatives |  | Notional(1) |  |  | Notional Translated to USD |  |  | Weighted Average Remaining Term(2) |
|  | (in millions) |  |  | (in years) |
Foreign Currency Options and Forwards: |  |  |  |  |  |  |  |  |  |  |  |
Chilean Peso |  |  | 80,558 |  |  | $ | 166 |  |  |  | <1 |
Brazilian Real |  |  | 240 |  |  |  | 118 |  |  |  | <1 |
Euro |  |  | 29 |  |  |  | 41 |  |  |  | <1 |
Colombian Peso |  |  | 53,208 |  |  |  | 28 |  |  |  | <1 |
Argentine Peso |  |  | 83 |  |  |  | 14 |  |  |  | <1 |
British Pound |  |  | 3 |  |  |  | 5 |  |  |  | <1 |
Embedded Foreign Currency Derivatives |  |  |  |  |  |  |  |  |  |  |  |
Argentine Peso |  |  | 829 |  |  |  | 169 |  |  |  | 11 |
Kazakhstani Tenge |  |  | 1,009 |  |  |  | 7 |  |  |  | 5 |
Euro |  |  | 2 |  |  |  | 2 |  |  |  | 10 |

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

(2) | Represents the remaining tenor of our foreign currency derivatives weighted by the corresponding notional. These options and forwards and these embedded derivatives range in maturity through 2014 and 2026, respectively.

|  | March 31, 2013 |
Commodity Derivatives |  | Notional |  |  | Weighted Average Remaining Term(1) |
|  | (in millions) |  |  | (in years) |
Aluminum (MWh)(2) |  |  | 14 |  |  |  | 7 |
Power (MWh) |  |  | 6 |  |  |  | 3 |

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

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

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##### Table of Contents

Accounting and Reporting

Assets and Liabilities

The following tables set forth the Company’s derivative instruments as of March 31, 2013 and December 31, 2012, first by whether or not they are designated hedging instruments, then by whether they are current or non-current, by the extent to which 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.

|  | March 31, 2013 |  |  | December 31, 2012 |
|  | Designated |  |  | Not Designated |  |  | Total |  |  | Designated |  |  | Not Designated |  |  | Total |
|  | (in millions) |  |  | (in millions) |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives |  | $ | - |  |  | $ | 2 |  |  | $ | 2 |  |  | $ | - |  |  | $ | 2 |  |  |  | 2 |
Cross currency derivatives |  |  | 8 |  |  |  | - |  |  |  | 8 |  |  |  | 6 |  |  |  | - |  |  |  | 6 |
Foreign currency derivatives |  |  | 1 |  |  |  | 87 |  |  |  | 88 |  |  |  | - |  |  |  | 81 |  |  |  | 81 |
Commodity derivatives |  |  | - |  |  |  | 7 |  |  |  | 7 |  |  |  | 2 |  |  |  | 9 |  |  |  | 11 |
Total assets |  | $ | 9 |  |  | $ | 96 |  |  | $ | 105 |  |  | $ | 8 |  |  | $ | 92 |  |  | $ | 100 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives |  | $ | 523 |  |  | $ | 18 |  |  | $ | 541 |  |  | $ | 544 |  |  | $ | 21 |  |  |  | 565 |
Cross currency derivatives |  |  | 3 |  |  |  | - |  |  |  | 3 |  |  |  | 6 |  |  |  | - |  |  |  | 6 |
Foreign currency derivatives |  |  | 7 |  |  |  | 11 |  |  |  | 18 |  |  |  | 7 |  |  |  | 7 |  |  |  | 14 |
Commodity derivatives |  |  | 11 |  |  |  | 82 |  |  |  | 93 |  |  |  | 8 |  |  |  | 64 |  |  |  | 72 |
Total liabilities |  | $ | 544 |  |  | $ | 111 |  |  | $ | 655 |  |  | $ | 565 |  |  | $ | 92 |  |  | $ | 657 |

|  | March 31, 2013 |  |  | December 31, 2012 |
|  | Assets |  |  | Liabilities |  |  | Assets |  |  | Liabilities |
|  | (in millions) |  |  | (in millions) |
Current |  | $ | 18 |  |  | $ | 175 |  |  | $ | 14 |  |  | $ | 186 |
Noncurrent |  |  | 87 |  |  |  | 480 |  |  |  | 86 |  |  |  | 471 |
Total |  | $ | 105 |  |  | $ | 655 |  |  | $ | 100 |  |  | $ | 657 |
Derivatives subject to master netting agreement or similar agreement: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gross (which equals net) amounts recognized in the balance sheet |  | $ | 19 |  |  | $ | 520 |  |  | $ | 25 |  |  | $ | 522 |
Gross amounts of derivative instruments not offset |  |  | (8 | ) |  |  | (8 | ) |  |  | (9 | ) |  |  | (9 | )
Gross amounts of cash collateral received/pledged not offset |  |  | - |  |  |  | (14 | ) |  |  | - |  |  |  | (5 | )
Net amount |  | $ | 11 |  |  | $ | 498 |  |  | $ | 16 |  |  | $ | 508 |
Other balances that had been, but no longer need to be, accounted for as derivatives at fair value that are to be amortized to earnings over the remaining term of the associated PPA |  | $ | 181 |  |  | $ | 191 |  |  | $ | 186 |  |  | $ | 191 |

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Effective Portion of Cash Flow Hedges

The following tables set forth the pre-tax gains (losses) recognized in accumulated other comprehensive loss (“AOCL”) and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships (including amounts that were reclassified from AOCL as interest expense related to interest rate derivative instruments that previously, but no longer, qualify for cash flow hedge accounting), as defined in the accounting standards for derivatives and hedging, for the three months ended March 31, 2013 and 2012:

|  | Gains (Losses) Recognized in AOCL |  |  | Classification in Condensed Consolidated Statements of Operations |  | Gains (Losses) Reclassified from AOCL into Earnings |
Type of Derivative |  | 2013 |  |  | 2012 |  |  |  | 2013 |  |  | 2012 |
|  | (in millions) |  |  |  |  | (in millions) |
Interest rate derivatives |  | $ | (13 | ) |  | $ | 11 |  |  | Interest expense |  | $ | (32 | ) |  | $ | (32 | )
|  |  |  |  |  |  |  |  |  | Non-regulated cost of sales |  |  | (1 | ) |  |  | (2 | )
|  |  |  |  |  |  |  |  |  | Net equity in earnings of affiliates |  |  | (2 | ) |  |  | (1 | )
|  |  |  |  |  |  |  |  |  | Gain on sale of investments |  |  | - |  |  |  | (92 | )
Cross currency derivatives |  |  | 1 |  |  |  | 14 |  |  | Interest expense |  |  | (3 | ) |  |  | (3 | )
|  |  |  |  |  |  |  |  |  | Foreign currency transaction gains (losses) |  |  | 5 |  |  |  | 18 |
Foreign currency derivatives |  |  | 1 |  |  |  | 6 |  |  | Foreign currency transaction gains (losses) |  |  | 2 |  |  |  | - |
Commodity derivatives |  |  | (5 | ) |  |  | (6 | ) |  | Non-regulated revenue |  |  | - |  |  |  | (2 | )
Total |  | $ | (16 | ) |  | $ | 25 |  |  |  |  | $ | (31 | ) |  | $ | (114 | )

The pre-tax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes over the next twelve months as of March 31, 2013 is $(146) million for interest rate hedges, $(11) million for cross currency swaps, $(6) million for foreign currency hedges, and $(9) million for commodity and other hedges.

Ineffective Portion of Cash Flow Hedges

The following table sets forth the pre-tax gains (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the three months ended March 31, 2013 and 2012:

|  | Classification in Condensed Consolidated Statements of Operations |  | Gains (Losses) Recognized in Earnings |
Type of Derivative |  |  | 2013 |  |  | 2012 |
|  |  |  | (in millions) |
Interest rate derivatives |  | Interest expense |  | $ | (1 | ) |  | $ | (1 | )
Total |  |  |  | $ | (1 | ) |  | $ | (1 | )

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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 no longer need to be, accounted for as derivatives at fair value, for the three months ended March 31, 2013 and 2012:

|  | Classification in Condensed Consolidated Statements of Operations |  | Gains (Losses) Recognized in Earnings |
Type of Derivative |  |  | 2013 |  |  | 2012 |
|  |  |  | (in millions) |
Interest rate derivatives |  | Interest expense |  | $ | 1 |  |  | $ | (2 | )
|  | Net equity in earnings of affiliates |  |  | (6 | ) |  |  | - |
Foreign currency derivatives |  | Foreign currency transaction gains (losses) |  |  | 6 |  |  |  | (38 | )
|  | Net equity in earnings of affiliates |  |  | (3 | ) |  |  | - |
Commodity and other derivatives |  | Non-regulated revenue |  |  | (21 | ) |  |  | 14 |
|  | Regulated revenue |  |  | (3 | ) |  |  | (4 | )
|  | Non-regulated cost of sales |  |  | 1 |  |  |  | 3 |
|  | Regulated cost of sales |  |  | - |  |  |  | (4 | )
Total |  |  |  | $ | (25 | ) |  | $ | (31 | )

Credit Risk-Related Contingent Features

DP&L, our utility in Ohio, has certain over-the-counter commodity derivative contracts under master netting agreements that contain provisions that require DP&L to maintain an investment-grade issuer credit rating from credit rating agencies. Since their rating has fallen below investment grade, certain of the counterparties to the derivative contracts have requested immediate and ongoing full overnight collateralization of the mark-to-market loss (fair value excluding credit valuation adjustments), which was $23 million and $13 million as of March 31, 2013 and December 31, 2012, respectively, for all derivatives with credit risk-related contingent features. As of March 31, 2013 and December 31, 2012, DP&L had posted $14 million and $5 million, respectively, of cash collateral directly with third parties and in a broker margin account and DP&L held $0 million and $0 million of cash collateral that it received from counterparties to its derivative instruments that were in an asset position. After consideration of the netting of counterparty assets, DP&L could have been required to provide additional collateral of $5 million and $2 million as of March 31, 2013 and December 31, 2012.

6. LONG-TERM FINANCING RECEIVABLES

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

Argentina — As a result of energy market reforms in 2004 and consistent with contractual arrangements, our subsidiaries entered into three agreements with the Argentine government called Fondos de inversion Mercado Electrico Mayorista (“Foninvemem Agreements”) to contribute a portion of their accounts receivable into a fund for financing the construction of combined cycle and gas-fired plants. These financing receivables accrue interest and are collected in monthly installments over 10 years once the related plant begins operations. In addition, the Company also receives an ownership interest in these newly built plants once the receivables have been fully repaid. The financing receivables under the first two Foninvemem Agreements are being actively collected since the related plants commenced operations in 2010. However, the financing receivables related to the third Foninvemem Agreement are not currently due as commercial operations of the related gas-fired turbine

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have not been achieved. Collection of these financing receivables is subject to various business risks and uncertainties including timely payment of principal and interest, completion and operation of power plants which generate cash for payments of these receivables, regulatory changes that could impact the timing and amount of collections and economic conditions in Argentina. The Company periodically analyzes each of these factors and assesses collectability of the related financing receivables. The Company’s collection estimates are based on assumptions that it believes to be reasonable but are inherently uncertain. Actual future cash flows could differ from these estimates.

Additionally, our subsidiaries are currently working with the Argentine government to include outstanding receivables of $122 million covered under government resolutions into the third Foninvemem Agreement. On March 26, 2013, the Argentine government passed a resolution to develop a new energy regulatory framework that would apply to all generation companies with certain exceptions. However, as of March 31, 2013 the resolution was not legally binding for our subsidiaries given that certain conditions precedent had not been met. The new regulatory framework will remunerate fixed and variable costs plus a margin that will depend on both the technology and fuel used to generate the electricity. The Company is currently analyzing the impact that this resolution will have on its subsidiaries in future periods, once it is effective.

The following table sets forth the breakdown of financing receivables by country as of March 31, 2013 and December 31, 2012. The decrease in the long-term financing receivables from December 31, 2012 is primarily related to the impact of foreign currency translation.

|  | March 31, 2013 |  |  | December 31, 2012 |
|  | (in millions) |
Argentina(1) |  | $ | 187 |  |  | $ | 196 |
Dominican Republic |  |  | 31 |  |  |  | 35 |
Brazil |  |  | 8 |  |  |  | 8 |
Total long-term financing receivables |  | $ | 226 |  |  | $ | 239 |

(1) | Excludes noncurrent receivables of $122 million and $120 million, respectively, as of March 31, 2013 and December 31, 2012, which have not been converted into long-term financing receivables and currently have no due date.

7. NON-RECOURSE DEBT

Significant transactions

During the three months ended March 31, 2013, we had the following significant debt transactions at our subsidiaries:

| • |  | Tietê issued new debt of $251 million partially offset by repayments of $60 million;

| • |  | El Salvador issued new debt of $310 million partially offset by repayments of $150 million;

| • |  | Sul issued new debt of $150 million partially offset by repayments of $34 million;

| • |  | Mong Duong drew $119 million under its construction loan facility; and

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

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Debt in default

The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of March 31, 2013 and is classified as current non-recourse debt unless otherwise indicated:

|  | Primary Nature of Default |  | March 31, 2013 |
Subsidiary |  |  | Default Amount |  |  | Net Assets |
|  |  |  | (in millions) |
Maritza |  | Covenant |  | $ | 819 |  |  | $ | 576 |
Sonel |  | Covenant |  |  | 264 |  |  |  | 361 |
Kavarna |  | Covenant |  |  | 196 |  |  |  | 82 |
Saurashtra |  | Covenant |  |  | 25 |  |  |  | 15 |
Total |  |  |  | $ | 1,304 |  |  |  |  |

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

In addition, in the event that there is a default, bankruptcy or maturity acceleration at a subsidiary or group of subsidiaries that meets the applicable definition of materiality under the corporate debt agreements of The AES Corporation, there could be a cross-default to the Company’s recourse debt. At March 31, 2013 none of the defaults listed above individually or in the aggregate results in a cross-default under the recourse debt of the Company.

8. CONTINGENCIES AND COMMITMENTS

Guarantees, Letters of Credit and Commitments

In connection with certain project financing, acquisition, power purchase and other agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, AES has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations relate to future performance commitments which the Company or its businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 21 years.

The following table summarizes the Parent Company’s contingent contractual obligations as of March 31, 2013. Amounts presented in the table below represent the Parent Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of its businesses of $24 million.

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Contingent Contractual Obligations |  | Amount |  |  | Number of Agreements |  |  | Maximum Exposure Range for Each Agreement
|  | (in millions) |  |  |  |  |  | (in millions)
Guarantees and commitments |  | $ | 577 |  |  |  | 20 |  |  | <$1 - $231
Cash collateralized letters of credit |  |  | 254 |  |  |  | 13 |  |  | <$1 - $169
Letters of credit under the senior secured credit facility |  |  | 3 |  |  |  | 5 |  |  | <$1 - $2
Total |  | $ | 834 |  |  |  | 38 |  |  |

During the three months ended March 31, 2013, the Company paid letter of credit fees ranging from 0.25% to 3.25% per annum on the outstanding amounts of letters of credit.

Environmental

The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of March 31, 2013, the Company had recorded liabilities of $14 million for projected environmental remediation costs. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Based on currently available information and analysis, the Company believes that it is reasonably possible that costs associated with such liabilities, or as yet unknown liabilities, may exceed current reserves in amounts that could be material but cannot be estimated as of March 31, 2013.

Litigation

The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and, accordingly, has recorded aggregate reserves for all claims of approximately $345 million and $321 million as of March 31, 2013 and December 31, 2012, respectively. These reserves are reported on the condensed consolidated balance sheets within “accrued and other liabilities” and “other noncurrent liabilities.” A significant portion of the reserves relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company’s subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that these reserves will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

The Company believes, based upon information it currently possesses and taking into account established reserves for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company’s consolidated financial statements. However, where no reserve has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of March 31, 2013. The material contingencies where a loss is reasonably possible primarily include: claims under financing agreements; disputes with offtakers, suppliers and EPC contractors; alleged violation of monopoly laws and regulations; income tax and non-income tax assessments by tax authorities; and environmental and regulatory matters. In aggregate, the Company estimates that the range of potential losses, where estimable, related to these reasonably possible material contingences to be between $944 million and $1.6 billion. The amounts considered reasonably possible do not include amounts reserved, as discussed above. These material contingencies do not include income tax related contingencies which are considered part of our uncertain tax positions.

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9. PENSION PLANS

Total pension cost for the three months ended March 31, 2013 and 2012 included the following components:

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
|  | U.S. |  |  | Foreign |  |  | U.S. |  |  | Foreign |
|  | (in millions) |
Service cost |  | $ | 4 |  |  | $ | 7 |  |  | $ | 4 |  |  | $ | 7 |
Interest cost |  |  | 11 |  |  |  | 139 |  |  |  | 12 |  |  |  | 141 |
Expected return on plan assets |  |  | (15 | ) |  |  | (130 | ) |  |  | (14 | ) |  |  | (122 | )
Amortization of prior service cost |  |  | 1 |  |  |  | - |  |  |  | 1 |  |  |  | - |
Amortization of net loss |  |  | 7 |  |  |  | 21 |  |  |  | 6 |  |  |  | 10 |
Total pension cost |  | $ | 8 |  |  | $ | 37 |  |  | $ | 9 |  |  | $ | 36 |

Total employer contributions for the three months ended March 31, 2013 for the Company’s U.S. and foreign subsidiaries were $50 million and $37 million, respectively. The expected remaining scheduled employer contributions for 2013 are $2 million and $132 million for U.S. and foreign subsidiaries, respectively.

10. EQUITY

Changes in Equity

The following table provides a reconciliation of the beginning and ending equity attributable to stockholders of The AES Corporation, noncontrolling interests and total equity as of March 31, 2013 and 2012:

|  | Three Months Ended March 31, 2013 |  |  | Three Months Ended March 31, 2012 |
|  | The AES Corporation Stockholders’ Equity |  |  | Noncontrolling Interests |  |  | Total Equity |  |  | The AES Corporation Stockholders’ Equity |  |  | Noncontrolling Interests |  |  | Total Equity |
|  | (in millions) |  |  | (in millions) |
Balance at January 1 |  | $ | 4,569 |  |  | $ | 2,945 |  |  | $ | 7,514 |  |  | $ | 5,946 |  |  | $ | 3,783 |  |  | $ | 9,729 |
Net income |  |  | 82 |  |  |  | 117 |  |  |  | 199 |  |  |  | 341 |  |  |  | 174 |  |  |  | 515 |
Total foreign currency translation adjustment, net of income tax |  |  | (42 | ) |  |  | 7 |  |  |  | (35 | ) |  |  | 92 |  |  |  | 49 |  |  |  | 141 |
Total change in derivative fair value, net of income tax |  |  | 7 |  |  |  | 1 |  |  |  | 8 |  |  |  | 90 |  |  |  | 17 |  |  |  | 107 |
Total pension adjustments, net of income tax |  |  | 3 |  |  |  | 11 |  |  |  | 14 |  |  |  | 1 |  |  |  | 5 |  |  |  | 6 |
Capital contributions from noncontrolling interests |  |  | - |  |  |  | 55 |  |  |  | 55 |  |  |  | - |  |  |  | 6 |  |  |  | 6 |
Distributions to noncontrolling interests |  |  | - |  |  |  | (27 | ) |  |  | (27 | ) |  |  | - |  |  |  | (14 | ) |  |  | (14 | )
Disposition of businesses |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (37 | ) |  |  | (37 | )
Issuance and exercise of stock-based compensation benefit plans, net of income tax |  |  | 14 |  |  |  | - |  |  |  | 14 |  |  |  | 19 |  |  |  | - |  |  |  | 19 |
Acquisition of subsidiary shares from noncontrolling interests |  |  | - |  |  |  | (1 | ) |  |  | (1 | ) |  |  | - |  |  |  | (1 | ) |  |  | (1 | )
Balance at March 31 |  | $ | 4,633 |  |  | $ | 3,108 |  |  | $ | 7,741 |  |  | $ | 6,489 |  |  | $ | 3,982 |  |  | $ | 10,471 |

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Accumulated Other Comprehensive Loss

The changes in accumulated other comprehensive loss by component, net of tax and noncontrolling interests for the three months ended March 31, 2013 were as follows:

|  | Unrealized derivative losses, net |  |  | Unfunded pension obligations, net |  |  | Foreign currency translation adjustment, net |  |  | Total |
|  | (in millions) |
Balance at January 1 |  | $ | (481 | ) |  | $ | (382 | ) |  | $ | (2,057 | ) |  | $ | (2,920 | )
Other comprehensive income before reclassifications |  |  | (15 | ) |  |  | - |  |  |  | (39 | ) |  |  | (54 | )
Amounts reclassified from accumulated other comprehensive loss |  |  | 22 |  |  |  | 3 |  |  |  | (3 | ) |  |  | 22 |
Net current-period other comprehensive income |  |  | 7 |  |  |  | 3 |  |  |  | (42 | ) |  |  | (32 | )
Balance at March 31 |  | $ | (474 | ) |  | $ | (379 | ) |  | $ | (2,099 | ) |  | $ | (2,952 | )

Reclassifications out of accumulated other comprehensive loss for the three months ended March 31, 2013 were as follows:

Details About Accumulated Other Comprehensive Loss Components |  | Affected Line Item in the Condensed Consolidated Statement of Operations |  | Three Months Ended March 31, 2013 (1) |
|  |  |  | (in millions) |
Unrealized derivative losses, net |
|  | Interest expense |  | $ | (35 | )
|  | Foreign currency transaction gains (losses) |  |  | 7 |
|  | Non-regulated cost of sales |  |  | (1 | )
|  | Income from continuing operations before taxes and equity in earnings of affiliates |  |  | (29 | )
|  | Income tax expense |  |  | 7 |
|  | Net equity in earnings of affiliates |  |  | (2 | )
|  | Income from continuing operations |  |  | (24 | )
|  | Income from continuing operations attributable to noncontrolling interests |  |  | 2 |
|  | Net income attributable to the AES Corporation |  | $ | (22 | )
Amortization of defined benefit pension actuarial loss, net |
|  | Non-regulated cost of sales |  | $ | (1 | )
|  | Regulated cost of sales |  |  | (20 | )
|  | Income from continuing operations before taxes and equity in earnings of affiliates |  |  | (21 | )
|  | Income tax expense |  |  | 7 |
|  | Income from continuing operations |  |  | (14 | )
|  | Income from continuing operations attributable to noncontrolling interests |  |  | 11 |
|  | Net income attributable to the AES Corporation |  | $ | (3 | )
Foreign currency translation adjustment, net |
|  | Gain on sale of investment |  | $ | 3 |
|  | Net income attributable to the AES Corporation |  | $ | 3 |
Total reclassifications for the period, net of income tax and noncontrolling interests |  | $ | (22 | )

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

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Dividend

The Company paid a dividend of $0.04 per outstanding share to its common stockholders on February 15, 2013.

Stock Repurchase Program

The Company’s Board of Directors has approved a stock repurchase program (the “Program”). The Program does not have an expiration date and it can be modified or terminated by the Company’s Board at any time. Under the Program, the Company may repurchase stock through a variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. As of March 31, 2013, $300 million was available under the Program.

There were no common stock repurchases under the Program during the three months ended March 31, 2013. The cumulative total purchases under the Program totaled 58,715,189 shares at a total cost of $680 million, which includes a nominal amount of commissions (average of $11.58 per share including commissions).

The common stock repurchased has been classified as treasury stock and accounted for using the cost method. A total of 65,546,914 and 66,415,984 shares were held as treasury stock at March 31, 2013 and December 31, 2012, respectively. Restricted stock units under the Company’s employee benefit plans are issued from treasury stock. The Company has not retired any common stock repurchased since it began the Program.

11. SEGMENTS

The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally with further aggregation by geographic regions to provide better socio-political-economic understanding of our business. The management reporting structure is organized along six strategic business units (“SBUs”) — led by our Chief Operating Officer (“COO”), who in turn reports to our Chief Executive Officer (“CEO”). Upon the application of the accounting guidance for segment reporting, the Company has identified eight reportable segments based on the six strategic business units:

| • |  | US — Generation;

| • |  | US — Utilities;

| • |  | Andes — Generation;

| • |  | Brazil — Generation;

| • |  | Brazil — Utilities;

| • |  | MCAC — Generation;

| • |  | EMEA — Generation; and

| • |  | Asia — Generation.

Corporate and Other — The Company’s EMEA and MCAC Utilities operating segments are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under the segment

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reporting accounting guidance. None of these operating segments are currently material to our presentation of reportable segments, individually or in the aggregate. AES Solar and certain other unconsolidated businesses are accounted for using the equity method of accounting; therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Consolidated Statements of Operations, not in revenue or Adjusted pre-tax contribution (“Adjusted PTC”). “Corporate and Other” also includes corporate overhead costs which are not directly associated with the operations of our eight reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

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

Total revenue includes inter-segment revenue related to the transfer of electricity from generation plants to utilities within Brazil. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain self-insurance activities which are reflected within segment adjusted PTC. All intra-segment activity has been eliminated with respect to revenue and adjusted PTC within the segment. Inter-segment activity has been eliminated within the total consolidated results. Asset information for businesses that were discontinued or classified as held for sale as of March 31, 2013 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.

Information about the Company’s operations by segment for the three months ended March 31, 2013 and 2012 was as follows:

Revenue Three Months Ended March 31, |  | Total Revenue |  |  | Intersegment |  |  | External Revenue |
| 2013 |  |  | 2012 |  |  | 2013 |  |  | 2012 |  |  | 2013 |  |  | 2012 |
|  | (in millions) |
US — Generation |  | $ | 170 |  |  | $ | 198 |  |  | $ | - |  |  | $ | - |  |  | $ | 170 |  |  | $ | 198 |
US — Utilities |  |  | 722 |  |  |  | 732 |  |  |  | - |  |  |  | - |  |  |  | 722 |  |  |  | 732 |
Andes — Generation |  |  | 691 |  |  |  | 734 |  |  |  | - |  |  |  | (9 | ) |  |  | 691 |  |  |  | 725 |
Brazil — Generation |  |  | 386 |  |  |  | 305 |  |  |  | (280 | ) |  |  | (282 | ) |  |  | 106 |  |  |  | 23 |
Brazil — Utilities |  |  | 1,323 |  |  |  | 1,531 |  |  |  | - |  |  |  | - |  |  |  | 1,323 |  |  |  | 1,531 |
MCAC — Generation |  |  | 458 |  |  |  | 393 |  |  |  | (1 | ) |  |  | (1 | ) |  |  | 457 |  |  |  | 392 |
EMEA — Generation |  |  | 351 |  |  |  | 477 |  |  |  | (8 | ) |  |  | (9 | ) |  |  | 343 |  |  |  | 468 |
Asia — Generation |  |  | 134 |  |  |  | 182 |  |  |  | - |  |  |  | - |  |  |  | 134 |  |  |  | 182 |
Corporate and Other |  |  | 320 |  |  |  | 336 |  |  |  | (1 | ) |  |  | (1 | ) |  |  | 319 |  |  |  | 335 |
Total Revenue |  | $ | 4,555 |  |  | $ | 4,888 |  |  | $ | (290 | ) |  | $ | (302 | ) |  | $ | 4,265 |  |  | $ | 4,586 |

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Adjusted Pre-Tax Contribution(1) Three Months Ended March 31, |  | Total Adjusted Pre-tax Contribution |  |  | Intersegment |  |  | External Adjusted Pre-tax Contribution |
| 2013 |  |  | 2012 |  |  | 2013 |  |  | 2012 |  |  | 2013 |  |  | 2012 |
|  | (in millions) |
US — Generation |  | $ | 65 |  |  | $ | 36 |  |  | $ | 2 |  |  | $ | 11 |  |  | $ | 67 |  |  | $ | 47 |
US — Utilities |  |  | 70 |  |  |  | 57 |  |  |  | - |  |  |  | - |  |  |  | 70 |  |  |  | 57 |
Andes — Generation |  |  | 80 |  |  |  | 111 |  |  |  | 3 |  |  |  | (5 | ) |  |  | 83 |  |  |  | 106 |
Brazil — Generation |  |  | 40 |  |  |  | 52 |  |  |  | (67 | ) |  |  | (68 | ) |  |  | (27 | ) |  |  | (16 | )
Brazil — Utilities |  |  | 2 |  |  |  | 56 |  |  |  | 45 |  |  |  | 46 |  |  |  | 47 |  |  |  | 102 |
MCAC — Generation |  |  | 48 |  |  |  | 71 |  |  |  | 3 |  |  |  | 2 |  |  |  | 51 |  |  |  | 73 |
EMEA — Generation |  |  | 94 |  |  |  | 187 |  |  |  | (2 | ) |  |  | (14 | ) |  |  | 92 |  |  |  | 173 |
Asia — Generation |  |  | 31 |  |  |  | 32 |  |  |  | 1 |  |  |  | - |  |  |  | 32 |  |  |  | 32 |
Corporate and Other |  |  | (165 | ) |  |  | (189 | ) |  |  | 15 |  |  |  | 28 |  |  |  | (150 | ) |  |  | (161 | )
Total |  |  | 265 |  |  |  | 413 |  |  |  | - |  |  |  | - |  |  |  | 265 |  |  |  | 413 |

Reconciliation to Income from Continuing Operations before Taxes and Equity earnings of Affiliates: |
Non-GAAP Adjustments: |  |  |  |  |  |  |  |
Unrealized derivative losses |  |  | (13 | ) |  |  | (30 | )
Unrealized foreign currency gains (losses) |  |  | (27 | ) |  |  | 29 |
Disposition/acquisition gains |  |  | 3 |  |  |  | 178 |
Impairment losses |  |  | (48 | ) |  |  | (58 | )
Debt retirement losses |  |  | (43 | ) |  |  | - |
Pre-tax contribution |  |  | 137 |  |  |  | 532 |
Add: income from continuing operations before taxes, attributable to noncontrolling interests |  |  | 166 |  |  |  | 250 |
Less: Net equity in earnings of affiliates |  |  | 4 |  |  |  | 13 |
Income from continuing operations before taxes and equity in earnings of affiliates |  | $ | 299 |  |  | $ | 769 |

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

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

|  | Total Assets |
|  | March 31, 2013 |  |  | December 31, 2012 |
|  | (in millions) |
Assets |  |  |  |  |  |  |  |
US — Generation |  | $ | 3,184 |  |  | $ | 3,259 |
US — Utilities |  |  | 7,576 |  |  |  | 7,534 |
Andes — Generation |  |  | 6,554 |  |  |  | 6,619 |
Brazil — Generation |  |  | 1,867 |  |  |  | 1,590 |
Brazil — Utilities |  |  | 8,424 |  |  |  | 8,120 |
MCAC — Generation |  |  | 4,440 |  |  |  | 4,293 |
EMEA — Generation |  |  | 4,568 |  |  |  | 4,578 |
Asia — Generation |  |  | 2,702 |  |  |  | 2,625 |
Discontinued businesses |  |  | 173 |  |  |  | 202 |
Corporate and Other & eliminations |  |  | 3,230 |  |  |  | 3,010 |
Total assets |  | $ | 42,718 |  |  | $ | 41,830 |

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12. OTHER INCOME AND EXPENSE

Other Income

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

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
|  | (in millions) |
Contract termination |  | $ | 60 |  |  | $ | - |
Gain on sale of assets |  |  | 1 |  |  |  | 2 |
Other |  |  | 7 |  |  |  | 16 |
Total other income |  | $ | 68 |  |  | $ | 18 |

Other income of $68 million for the three months ended March 31, 2013 was primarily due to the termination of the PPA at Beaver Valley.

Other income of $18 million for the three months ended March 31, 2012 was primarily due to the release of a reserve recorded against inventory at Ballylumford and the receipt of dividends from a cost method investment at Gener.

Other Expense

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

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
|  | (in millions) |
Loss on extinguishment of debt |  | $ | 47 |  |  | $ | - |
Loss on sale and disposal of assets |  |  | 15 |  |  |  | 24 |
Contract termination |  |  | 7 |  |  |  | - |
Other |  |  | 6 |  |  |  | 4 |
Total other expense |  | $ | 75 |  |  | $ | 28 |

Other expense for the three months ended March 31, 2013 of $75 million was primarily due to the loss on the early extinguishment of debt at Masinloc, the loss on disposal of assets at Eletropaulo and the termination of a coal contract at Beaver Valley.

Other expense for the three months ended March 31, 2012 of $28 million was primarily due to losses on the disposal of assets at Eletropaulo.

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13. ASSET IMPAIRMENT EXPENSE

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
|  | (in millions) |
Beaver Valley |  | $ | 46 |  |  | $ | - |
Kelanitissa |  |  | - |  |  |  | 5 |
Other |  |  | 2 |  |  |  | 5 |
Total asset impairment expense |  | $ | 48 |  |  | $ | 10 |

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

14. OTHER NON-OPERATING EXPENSE

There was no other non-operating expense for the three months ended March 31, 2013. Other non-operating expense for the three months ended March 31, 2012 consisted of the other-than-temporary impairment of the following equity method investments:

|  | Three Months Ended March 31, |
|  | 2012 |
|  | (in millions) |
China generation |  | $ | 31 |
InnoVent |  |  | 17 |
Other |  |  | 1 |
Total other-non operating expense |  | $ | 49 |

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

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

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15. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

In addition to the businesses reported as discontinued operations in the 2012 Form 10-K, discontinued operations include the results of the following businesses classified as held for sale in March of 2013:

| • |  | Ukraine Utilities businesses

The following table summarizes the revenue, income from operations, income tax expense, impairment and loss on disposal of all discontinued operations for the three months ended March 31, 2013 and 2012:

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
|  | (in millions) |
Revenue |  | $ | 147 |  |  | $ | 191 |
Income from operations of discontinued businesses, before income tax |  | $ | 13 |  |  | $ | 8 |
Income tax benefit (expense) |  |  | 1 |  |  |  | (2 | )
Income from operations of discontinued businesses, after income tax |  | $ | 14 |  |  | $ | 6 |
Net loss from disposal and impairments of discontinued businesses, after income tax |  | $ | (36 | ) |  | $ | (5 | )

Ukraine Utilities sale — On January 29, 2013, the Company agreed to sell its two power distribution businesses in Ukraine to VS Energy International. Under the agreement, the Company sold its 89.1% equity interest in AES Kyivoblenergo, which serves 881,000 customers in the Kiev region, and its 84.6% percent equity interest in AES Rivneoblenergo, which serves 412,000 customers in the Rivne region. The Company recognized an asset impairment of $38 million upon fair value measurement during the three months ended March 31, 2013. The transaction closed on April 29, 2013 and net proceeds of $109 million were received. These businesses were previously reported in “Corporate and Other.”

16. DISPOSITIONS

Cartagena — On February 9, 2012, a subsidiary of the Company completed the sale of 80% of its interest in the wholly-owned holding company of AES Energia Cartagena S.R.L. (“AES Cartagena”), a 1,199 MW gas-fired generation business in Spain. The Company owned approximately 70.81% of AES Cartagena through this holding company structure, as well as 100% of a related operations and maintenance company. During the first quarter of 2012, net proceeds from the sale of the 80% interest were approximately $229 million and the Company recognized a pretax gain of $178 million. Under the terms of the sale agreement, the buyer had an option to purchase the Company’s remaining 20% interest at a fixed price of $36 million during a five month period beginning March 2013. Of the total proceeds received in February 2012, approximately $9 million was deferred and allocated to the buyer’s option to purchase the Company’s remaining interest. The buyer exercised the option to purchase the Company’s remaining 20% interest in AES Cartagena on April 26, 2013. Net proceeds from the exercise of the option were approximately $24 million and the Company will recognize a pretax gain of $20 million in the second quarter of 2013.

Due to the Company’s continuing ownership interest extending beyond one year from the completion of the sale of its 80% interest, the prior period operating results of AES Cartagena were not reclassified as discontinued operations.

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17. EARNINGS PER SHARE

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

The following tables present a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation for income from continuing operations for the three months ended March 31, 2013 and 2012. In the table below, income represents the numerator and weighted-average shares represent the denominator:

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
|  | Income |  |  | Shares |  |  | $ per Share |  |  | Income |  |  | Shares |  |  | $ per Share |
|  | (in millions except per share data) |
BASIC EARNINGS PER SHARE |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income from continuing operations attributable to The AES Corporation common stockholders |  | $ | 106 |  |  |  | 745 |  |  | $ | 0.14 |  |  | $ | 341 |  |  |  | 766 |  |  | $ | 0.45 |
EFFECT OF DILUTIVE SECURITIES |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Convertible securities |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 6 |  |  |  | 15 |  |  |  | - |
Stock options |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | 1 |  |  |  | - |
Restricted stock units |  |  | - |  |  |  | 3 |  |  |  | - |  |  |  | - |  |  |  | 3 |  |  |  | (0.01 | )
DILUTED EARNINGS PER SHARE |  | $ | 106 |  |  |  | 749 |  |  | $ | 0.14 |  |  | $ | 347 |  |  |  | 785 |  |  | $ | 0.44 |

The calculation of diluted earnings per share excluded 8 and 7 million options outstanding at March 31, 2013 and 2012, respectively, that could potentially dilute basic earnings per share in the future. These options were not included in the computation of diluted earnings per share because the exercise price of those options exceeded the average market price during the related period.

The calculation of diluted earnings per share also excluded 1 and 2 million restricted stock units outstanding at March 31, 2013 and 2012, respectively, that could potentially dilute basic earnings per share in the future. These restricted stock units were not included in the computation of diluted earnings per share because the average amount of compensation cost per share attributed to future service and not yet recognized exceeded the average market price during the related period and thus to include the restricted units would have been anti-dilutive.

For the three months ended March 31, 2013 all 15 million convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. For the three months ended March 31, 2012, all convertible debentures were included in the earnings per share calculation.

During the three months ended March 31, 2013, 1 million shares of common stock were issued under the Company’s profit sharing plan.

18. SUBSEQUENT EVENTS

Dividend — On April 18, 2013, the Company’s Board of Directors declared a dividend of $0.04 per outstanding share payable on May 15, 2013 to the shareholders of record at the close of business on May 1, 2013.

Cartagena — On April 26, 2013, the Company’s remaining 20% interest held in AES Cartagena was sold upon the exercise of the purchase option by the buyer. See Note 16 — Dispositions for further information.

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Ukraine Utilities Sale — The sale transaction of Ukraine utilities was closed on April 29, 2013. See Note 15 — Discontinued Operations and Held for Sale Businesses for further information.

Recourse Debt — On April 30, 2013, the Company issued $500 million aggregate principal amount of 4.875% senior notes due 2023 (the “Notes”). In connection with this offering, the Company has commenced the tender offers (the “Tender Offers”) to purchase for cash up to $800 million aggregate principal amount of four series of our outstanding senior notes, including any and all of our outstanding 7.75% senior notes due 2014 (the “2014 Notes”), of which $500 million are currently outstanding; up to $100 million of our outstanding 7.75% senior notes due 2015 (the “2015 Notes”), of which $500 million are currently outstanding; up to $100 million of our outstanding 9.75% senior notes due 2016 (the “2016 Notes”), of which $535 million are currently outstanding; and up to $100 million of our outstanding 8.00% senior notes due 2017 (the “2017 Notes” and, together with the 2014 Notes, the 2015 Notes and the 2016 Notes, the “Outstanding Notes”), of which $1,500 million are currently outstanding. We intend to use the net proceeds from this offering, as well as, if necessary, other available funds, to fund the Tender Offers and to pay certain related fees and expenses. If any net proceeds from this offering remain after completion of the Tender Offers, we intend to use such proceeds for general corporate purposes.

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

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

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

FORWARD-LOOKING INFORMATION

The following discussion may contain forward-looking statements regarding us, our business, prospects and our results of operations that are subject to certain risks and uncertainties posed by many factors and events that could cause our actual business, prospects and results of operations to differ materially from those that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those described in Item 1A. — Risk Factors of our 2012 Form 10-K. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We undertake no obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise of the risks and factors that may affect our business.

Overview of Our Business

We are a diversified power generation and utility company organized into six market-oriented Strategic Business Units (“SBUs”): US (United States), Andes (Chile, Colombia, and Argentina), Brazil, MCAC (Mexico, Central America and the Caribbean), EMEA (Europe, Middle East and Africa), and Asia. For additional information regarding our business, see Item 1. — Business of our 2012 Form 10-K.

Our Organization — The management reporting structure is organized along six SBUs led by our Chief Operating Officer (“COO”), who in turn reports to our Chief Executive Officer (“CEO”). Our CEO and COO are based in Arlington, Virginia. For financial reporting purposes, the Company has identified eight reportable segments based on the six SBUs. Accordingly, management’s discussion and analysis of revenue and gross margin is organized as follows:

| • |  | US SBU

| • |  | US — Generation segment

| • |  | US — Utilities segment

| • |  | Andes SBU

| • |  | Andes — Generation segment

| • |  | Brazil SBU

| • |  | Brazil — Generation segment

| • |  | Brazil — Utilities segment

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| • |  | MCAC SBU

| • |  | MCAC — Generation segment

| • |  | EMEA SBU

| • |  | EMEA — Generation segment

| • |  | Asia SBU

| • |  | Asia — Generation segment

Corporate and Other — The Company’s EMEA and MCAC utilities as well as Corporate are reported within “Corporate and Other” because they do not require separate disclosure under segment reporting accounting guidance. See Note 11 — Segments included in Item 1. — Financial Statements for further discussion of the Company’s segment structure used for financial reporting purposes.

Management’s Priorities

Management is focused on the following priorities:

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

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

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

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

Q1 2013 Performance

During the first quarter of 2013, Adjusted EPS declined $0.11 to $0.26. This decline was anticipated and was primarily driven by a one-time arbitration settlement at Cartagena in Spain recorded in the first quarter of 2012, the impact of low hydrology in Panama and Brazil, and unfavorable movements in foreign currency exchange rates, predominantly the Brazilian Real.

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

Safe, Reliable and Sustainable Operations.

During the first quarter of 2013, we commenced commercial operations at our 270 MW coal-fired Ventanas IV plant in Chile. To supplement our future growth, we commenced construction of our 532 MW coal-fired Cochrane platform expansion project in Chile. This brings our total projects under construction to 2,443 MW, expected to come on-line 2013-2016.

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Improving Available Capital and Deployment of Discretionary Cash.

Building on actions that commenced in 2012, during the first quarter 2013, we deployed our discretionary cash to pay a dividend of $0.04 per share and invested $75 million in our subsidiaries to expand our existing facilities. Additionally, in April 2013, we initiated certain transactions to reduce debt and extend near-term maturities at the Parent Company. For further details please see Note 18 — Subsequent Events.

Realigning Our Geographic Focus.

Continuing on our efforts to further streamline our portfolio, we announced or closed the sale of three assets, for a total of $133 million in equity proceeds to AES, exiting our operations in Spain and the Ukraine.

Earnings Per Share Results in Q1 2013

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
Diluted earnings per share from continuing operations |  | $ | 0.14 |  |  | $ | 0.44 |
Adjusted earnings per share (a non-GAAP measure)(1) |  | $ | 0.26 |  |  | $ | 0.37 |

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

During the three months ended March 31, 2013, diluted earnings per share from continuing operations decreased principally due to lower gross margin and a decrease in the gain on sale of investments resulting from the sale of 80% of our interest in Cartagena in the first quarter of 2012, as well as the other drivers described below in other operating highlights.

Adjusted earnings per share, a non-GAAP measure, decreased by 30% primarily due to lower gross margin, partially offset by higher other income due to the PPA termination at Beaver Valley.

Other Operating Highlights

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |  |  | % Change |
|  | (in millions) |
Revenue |  | $ | 4,265 |  |  | $ | 4,586 |  |  |  | -7 | %
Gross margin |  | $ | 755 |  |  | $ | 1,072 |  |  |  | -30 | %
Net income attributable to The AES Corporation |  | $ | 82 |  |  | $ | 341 |  |  |  | -76 | %
Adjusted pre-tax contribution (a non-GAAP measure)(1) |  | $ | 265 |  |  | $ | 413 |  |  |  | -36 | %
Net cash provided by operating activities |  | $ | 618 |  |  | $ | 534 |  |  |  | 16 | %

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

The following briefly describes the key changes in our reported revenue, gross margin, net income attributable to The AES Corporation, net cash provided by operating activities, diluted earnings per share from continuing operations and adjusted earnings per share (a non-GAAP measure) for the three months ended March 31, 2012 and 2011 and should be read in conjunction with our Consolidated Results of Operations and Segment Analysis discussion within Management’s Discussion and Analysis of Financial Condition below.

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Three months ended March 31, 2013:

Revenue decreased $321 million, or 7%, to $4.3 billion in the three months ended March 31, 2013 compared with $4.6 billion in the three months ended March 31, 2012. Excluding the impact of foreign currency of $239 million, the key drivers of the change at each of the SBU’s are as follows:

| • |  | US — Overall unfavorable impact of $38 million due to lower capacity revenue and lower average retail and average wholesale prices at DPL in Ohio, the impact of the PPA buyout at Beaver Valley in Pennsylvania, partially offset by higher wholesale volume at DPL and higher retail and wholesale volume at IPL in Indiana.

| • |  | Andes — Overall unfavorable impact of $16 million due to lower prices and volumes in Chile and impact of outage in Argentina during the first quarter of 2013 partially offset by higher prices in Colombia due to lower water inflows.

| • |  | Brazil — Overall favorable impact of $97 million due to the temporary restart of operations at Uruguaiana during February and March of 2013 and higher tariff at Eletropaulo compared to the 2012 tariff reset provision, partially offset by overall lower demand and lower volumes in our Brazil utilities.

| • |  | MCAC — Overall favorable impact of $71 million due to higher sales in the Dominican Republic, higher volume at Merida in Mexico and impact of tariff reset in El Salvador.

| • |  | EMEA — Overall unfavorable variance of $147 million due to the sale of 80% of our ownership and a non-recurring favorable arbitration settlement in Cartagena in the first quarter of 2012, lower capacity prices at Ballylumford in line with PPA beginning April 2012, and a mark-to-market loss on an embedded derivative at Sonel in Cameroon partially offset by lower outages in 2013.

| • |  | Asia — Overall unfavorable variance of $48 million due to lower volume in Sri Lanka, lower prices in the Philippines and the impact of a mark-to-market gain on a derivative in 2012 in the Philippines, partially offset by higher demand.

Gross margin decreased $317 million, or 30%, to $755 million in the three months ended March 31, 2013 compared with $1.1 billion in the three months ended March 31, 2012. Excluding the impact of foreign currency of $28 million, the key drivers of the change at each of the SBU’s are as follows:

| • |  | US — Overall unfavorable variance of $18 million driven by lower rates as discussed above at DPL and the PPA buyout at Beaver Valley, partially offset by lower amortization expense at DPL and higher retail and wholesale volume at IPL.

| • |  | Andes — Overall unfavorable impact of $30 million due to lower gas availability and coal generation in Chile, lower generation and prices in Argentina, partially offset by new operations of Ventanas IV in Chile.

| • |  | Brazil — Overall unfavorable impacts of $79 million due to lower water inflows in the system resulting in a higher allocation of energy purchases to Tietê partially offset by the temporary restart of operations at Uruguaiana as discussed above and lower volumes at Brazil utilities.

| • |  | MCAC — Overall unfavorable variance of $16 million due to higher purchased energy in Panama due to low hydrology, higher fuel costs and higher outages in Dominican Republic partially offset by higher volume in the Dominican Republic.

| • |  | EMEA — Overall unfavorable variance of $135 million due to the sale of 80% of our ownership and a non-recurring favorable arbitration settlement in Cartagena in the first quarter of 2012, lower capacity prices at Ballylumford, and a mark-to-market loss on an embedded derivative at Sonel in Cameroon, partially offset by lower outages in 2013.

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| • |  | Asia — Overall unfavorable impact of $12 million due to the impact of the mark-to-market gain on a derivative in 2012 and lower prices in the Philippines.

Net income attributable to The AES Corporation decreased $259 million to $82 million in the three months ended March 31, 2013 compared to $341 million in the three months ended March 31, 2012. The key drivers of the decrease included:

| • |  | the decrease in gross margin as described above;

| • |  | a decrease in gains on the sale of investments due to the prior year gain recorded on the sale of 80% of our interest in Cartagena in the first quarter of 2012;

| • |  | higher other expenses primarily due to the early extinguishment of debt at Masinloc;

| • |  | an increase in asset impairment expense due to impairment at Beaver Valley in Pennsylvania; and

| • |  | higher foreign currency transaction losses in 2013 compared to 2012.

These decreases were partially offset by:

| • |  | lower tax expense in the first quarter of 2013 due to lower income before tax and a decrease in the effective tax rate from 35% to 27%;

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

| • |  | a decrease in other non-operating expense due to the prior year other-than-temporary impairment losses of equity method investments in China and France.

Net cash provided by operating activities increased $84 million, or 16%, to $618 million in the three months ended March 31, 2013 compared with $534 million in the three months ended March 31, 2012. This net increase was primarily the result of the following:

| • |  | US — an increase of $67 million at our generation businesses primarily due to proceeds of $60 million from the PPA termination at Beaver Valley in January 2013.

| • |  | Andes — a decrease of $59 million at our generation businesses primarily driven by income tax payments at Chivor.

| • |  | MCAC — an increase of $75 million at our generation businesses primarily due to the prepayment of gas in 2012 at Andres and higher collections and lower payments at Itabo.

Non-GAAP Measure

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

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

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

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

|  | Three Months Ended March 31, 2013 |  |  | Three Months Ended March 31, 2012 |
|  | Net of NCI* |  |  | Per Share (Diluted) Net of NCI* and Tax |  |  | Net of NCI* |  |  | Per Share (Diluted) Net of NCI* and Tax |
|  | (In millions, except per share amounts) |
Income from continuing operations attributable to AES and Diluted EPS |  | $ | 106 |  |  | $ | 0.14 |  |  | $ | 341 |  |  | $ | 0.44 |
Add back income tax expense from continuing operations attributable to AES |  |  | 31 |  |  |  |  |  |  |  | 191 |  |  |  |  |
Pre-tax contribution |  |  | 137 |  |  |  |  |  |  |  | 532 |  |  |  |  |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unrealized derivative losses(1) |  |  | 13 |  |  |  | 0.01 |  |  |  | 30 |  |  |  | 0.03 |
Unrealized foreign currency transaction (gains)/ losses(2) |  |  | 27 |  |  |  | 0.02 |  |  |  | (29 | ) |  |  | (0.02 | )
Disposition/ acquisition (gains) |  |  | (3 | ) |  |  | - | (3) |  |  | (178 | ) |  |  | (0.14 | )(4)
Impairment losses |  |  | 48 |  |  |  | 0.05 | (5) |  |  | 58 |  |  |  | 0.06 | (6)
Debt retirement losses |  |  | 43 |  |  |  | 0.04 | (7) |  |  | - |  |  |  | - |
Adjusted pre-tax contribution and Adjusted EPS |  | $ | 265 |  |  | $ | 0.26 |  |  | $ | 413 |  |  | $ | 0.37 |

* | NCI is defined as Noncontrolling Interests

(1) | Unrealized derivative losses were net of income tax per share of $0.01 and $0.01 in the three months ended March 31, 2013 and 2012, respectively.

(2) | Unrealized foreign currency transaction (gains)/losses were net of income tax per share of $0.01 and $(0.01) in the three months ended March 31, 2013 and 2012, respectively.

(3) | Amount primarily relates to the gain from the sale of Chengdu, an equity method investment in China for $3 million ($2 million, or $0.00 per share, net of income tax of $0.00 per share).

(4) | Amount primarily relates to the gain from the sale of 80% of our interest in Cartagena for $178 million ($107 million, or $0.14 per share, net of income tax of $0.09 per share).

(5) | Amount primarily relates to asset impairments at Beaver Valley of $46 million ($32 million, or $0.04 per share, net of income tax of $0.02 per share).

(6) | Amount primarily relates to the other-than-temporary impairment of equity method investments in China of $32 million ($26 million, or $0.03 per share, net of income tax of $0.01 per share), and at InnoVent of $17 million ($12 million, or $0.02 per share, net of income tax of $0.01 per share).

(7) | Amount primarily relates to the loss on early retirement of debt at Masinloc of $43 million ($28 million, or $0.04 per share, net of noncontrolling interest of $3 million and of income tax of $0.01 per share).

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Consolidated Results of Operations

|  | Three Months Ended March 31, |
Results of operations |  | 2013 |  |  | 2012 |  |  | $ change |  |  | % change |
|  | (in millions, except per share amounts) |
Revenue: |  |  |  |
US — Generation |  | $ | 170 |  |  | $ | 198 |  |  | $ | (28 | ) |  | $ | -14 | %
US — Utilities |  |  | 722 |  |  |  | 732 |  |  |  | (10 | ) |  |  | -1 | %
Andes — Generation |  |  | 691 |  |  |  | 734 |  |  |  | (43 | ) |  |  | -6 | %
Brazil — Generation |  |  | 386 |  |  |  | 305 |  |  |  | 81 |  |  |  | 27 | %
Brazil — Utilities |  |  | 1,323 |  |  |  | 1,531 |  |  |  | (208 | ) |  |  | -14 | %
MCAC — Generation |  |  | 458 |  |  |  | 393 |  |  |  | 65 |  |  |  | 17 | %
EMEA — Generation |  |  | 351 |  |  |  | 477 |  |  |  | (126 | ) |  |  | -26 | %
Asia — Generation |  |  | 134 |  |  |  | 182 |  |  |  | (48 | ) |  |  | -26 | %
Corporate and Other(1) |  |  | 320 |  |  |  | 336 |  |  |  | (16 | ) |  |  | -5 | %
Intersegment eliminations(2) |  |  | (290 | ) |  |  | (302 | ) |  |  | 12 |  |  |  | 4 | %
Total Revenue |  | $ | 4,265 |  |  | $ | 4,586 |  |  | $ | (321 | ) |  | $ | -7 | %
Gross Margin: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
US — Generation |  | $ | 31 |  |  | $ | 53 |  |  | $ | (22 | ) |  | $ | -42 | %
US — Utilities |  |  | 118 |  |  |  | 114 |  |  |  | 4 |  |  |  | 4 | %
Andes — Generation |  |  | 134 |  |  |  | 167 |  |  |  | (33 | ) |  |  | -20 | %
Brazil — Generation |  |  | 163 |  |  |  | 225 |  |  |  | (62 | ) |  |  | -28 | %
Brazil — Utilities |  |  | 40 |  |  |  | 83 |  |  |  | (43 | ) |  |  | -52 | %
MCAC — Generation |  |  | 87 |  |  |  | 105 |  |  |  | (18 | ) |  |  | -17 | %
EMEA — Generation |  |  | 121 |  |  |  | 247 |  |  |  | (126 | ) |  |  | -51 | %
Asia — Generation |  |  | 41 |  |  |  | 54 |  |  |  | (13 | ) |  |  | -24 | %
Corporate and Other(1) |  |  | 7 |  |  |  | 23 |  |  |  | (16 | ) |  |  | -70 | %
Intersegment eliminations(2) |  |  | 13 |  |  |  | 1 |  |  |  | 12 |  |  |  | NM |
General and administrative expenses |  |  | (61 | ) |  |  | (87 | ) |  |  | 26 |  |  |  | 30 | %
Interest expense |  |  | (377 | ) |  |  | (416 | ) |  |  | 39 |  |  |  | 9 | %
Interest income |  |  | 66 |  |  |  | 91 |  |  |  | (25 | ) |  |  | -27 | %
Other expense |  |  | (75 | ) |  |  | (28 | ) |  |  | (47 | ) |  |  | -168 | %
Other income |  |  | 68 |  |  |  | 18 |  |  |  | 50 |  |  |  | 278 | %
Gain on sale of investments |  |  | 3 |  |  |  | 179 |  |  |  | (176 | ) |  |  | -98 | %
Asset impairment expense |  |  | (48 | ) |  |  | (10 | ) |  |  | (38 | ) |  |  | -380 | %
Foreign currency transaction losses |  |  | (32 | ) |  |  | (1 | ) |  |  | (31 | ) |  |  | NM |
Other non-operating expense |  |  | - |  |  |  | (49 | ) |  |  | 49 |  |  |  | 100 | %
Income tax expense |  |  | (82 | ) |  |  | (268 | ) |  |  | 186 |  |  |  | 69 | %
Net equity in earnings of affiliates |  |  | 4 |  |  |  | 13 |  |  |  | (9 | ) |  |  | -69 | %
Income from continuing operations |  |  | 221 |  |  |  | 514 |  |  |  | (293 | ) |  |  | -57 | %
Income from operations of discontinued businesses |  |  | 14 |  |  |  | 6 |  |  |  | 8 |  |  |  | 133 | %
Net loss from disposal and impairments of discontinued businesses |  |  | (36 | ) |  |  | (5 | ) |  |  | (31 | ) |  |  | -620 | %
Net income |  |  | 199 |  |  |  | 515 |  |  |  | (316 | ) |  |  | -61 | %
Noncontrolling interests: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income from continuing operations attributable to noncontrolling interests |  |  | (115 | ) |  |  | (173 | ) |  |  | 58 |  |  |  | 34 | %
Income from discontinued operations attributable to noncontrolling interests |  |  | (2 | ) |  |  | (1 | ) |  |  | (1 | ) |  |  | -100 | %
Net income attributable to The AES Corporation |  | $ | 82 |  |  | $ | 341 |  |  | $ | (259 | ) |  | $ | -76 | %
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income from continuing operations, net of tax |  | $ | 106 |  |  | $ | 341 |  |  | $ | (235 | ) |  | $ | -69 | %
Loss from discontinued operations, net of tax |  |  | (24 | ) |  |  | - |  |  |  | (24 | ) |  |  | N/A |
Net income |  | $ | 82 |  |  | $ | 341 |  |  | $ | (259 | ) |  | $ | -76 | %

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NM — Not meaningful

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

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

Key Trends and Uncertainties

During the remainder of 2013 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may impact our gross margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1. — Business and Item 1A. — Risk Factors of the 2012 Form 10-K.

Regulatory

Rate Case Proceedings

Two of our utility businesses, DP&L in the United States and AES Sul in Brazil, are in the process of their regulated tariff review and/or reset by the applicable regulatory agency. The tariff outcome will determine the amount that our utility businesses can charge to customers for electricity.

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

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Sul — On April 16, 2013, the Brazilian energy regulator (the “Regulator”) approved the periodic tariff reset of AES Sul which occurs every five years. As part of the current tariff reset, the Regulator adjusted certain amounts Sul charged its customers in the period prior to the tariff reset. As a result of these adjustments, Sul has recorded regulatory liabilities for excess maintenance costs and disallowed capital expenditure of $21 million and $7 million, respectively, as of March 31, 2013. These regulatory liabilities were offset by a regulatory asset representing an additional tariff of $18 million related to energy purchases.

Other

The Government of Brazil recently announced an Energy Cost Reduction Program, which targets a 20 percent reduction in electricity prices. About one-third of this planned reduction is expected to be driven by lowering sector charges (indirect taxes). The remaining two-thirds of this reduction is being targeted through re-negotiations of new conditions with various generators and transmission and distribution companies, whose concession contracts are up for renewal between 2015 and 2017. The Government of Brazil issued Provision Measure 579 (PM 579) and other related rules. PM 579 was converted into Law 12.783 in January 2013 and the implementation of the Energy Cost Reduction Program was completed in February of 2013 with an average discount of 18% for residential customers and 32% for industrial ones. In order to ensure the discount rate announced by Government, MP 605 and Decree 7.891 were published in January 2013, removing tariff cross-subsidies by an increase of Treasury annual intake to Energy Development Account (CDE) of R$ 8.8 billion, instead of R$ 3.3 billion. The concession at Tietê, our generation business in Brazil, was granted after 1995 and expires in 2029 and thus is not subject to this regulation. Furthermore, we are insulated in the short-term, as 100 percent of Tietê’s output is contracted with Eletropaulo through December of 2015. Beyond 2015, any developments will be a function of the supply-demand and new investment dynamics in Brazil. With regard to our two distribution businesses in Brazil, Eletropaulo and Sul, both utilities also have concessions granted after 1995 and valid until 2028 and 2027, respectively, and thus are not expected to be affected by PM 579. These distribution businesses earn a return on the regulated asset base and energy purchases are treated as a pass-through cost. The final rule did not result in a material impact to our Brazilian businesses or on our results of operations.

Operational

Fluctuations in Foreign Exchange Rates

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

Due to our global presence, the Company has significant exposure to foreign currency fluctuations. The exposure is primarily associated with the impact of the translation of our foreign subsidiaries’ operating results from their local currency to U.S. dollars that is required for the preparation of our consolidated financial statements. Additionally, there is a risk of transaction exposure when an entity enters into transactions, including debt agreements, in currencies other than their functional currency. These risks are further described in Item 1A. — Risk Factors of the 2012 Form 10-K, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.” In the three months ended March 31, 2013, changes in foreign currency exchange rates have had a significant impact on our operating results. If the current foreign currency exchange rate volatility continues, our gross margin and other financial metrics could continue to be affected.

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Fluctuations in Commodity Prices

The Company is sensitive to changes in natural gas prices. High coal prices relative to natural gas creates pressure at our U.S. businesses, which may affect the results of certain of our coal plants, particularly those which are merchant plants that are exposed to market risk and those that have hybrid merchant risk, meaning those businesses that have a PPA in place, but purchase fuel at market prices or under short term contracts. See Item 3 — Quantitative and Qualitative Disclosures About Market Risk of this Form 10-Q for more information.

Sensitivity to Weather Conditions

Brazil — Given that approximately two-thirds of Brazil’s electric supply is dependent upon hydroelectric generation, changes in weather conditions can have a significant impact on reservoir levels and electricity prices. Lower than expected rainfall during the spring and summer has caused reservoir levels to be lower than their historical levels and affected the availability of hydroelectric generation facilities. If reservoir levels are not able to recover, or deteriorate further, it is expected that higher thermal dispatch will cause more volatility in spot prices. Although the purchased energy cost is a pass-through for AES’s distribution businesses in Brazil, gaps between the purchase of energy and recovery in the tariff could cause temporary cash flow constraints on those businesses. Additionally, if the overall system is short of water, our hydroelectric generation facilities are required to purchase a portion of their contracted energy from the spot market even though such facilities may have enough water to meet their contractual requirements. To the extent that a hydroelectric generation facility needs to purchase energy to meet its contractual requirements, rather than generate, purchasing can be more expensive, thereby creating losses on those contracts, which could have a material adverse impact on our results of operations.

Macroeconomic and Political

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

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

United States — As noted in Item 1A — Risk Factors — ”We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” of the 2012 Form 10-K and Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk of this Form 10-Q, the Company’s U. S. businesses continue to face pressure as a result of low natural gas prices, which is the marginal price-setting fuel in most U. S. markets. This has affected the results of certain of our coal-fired plants in the region, including our coal-fired generating assets within our utility businesses. IPL in Indiana benefits from high wholesale power prices in periods where our available generation exceeds our captive load obligations. At DPL in Ohio, where retail competition exists, our coal-fired generating assets sell excess power into the deregulated market and are subject to greater sensitivity to changes in power prices. Businesses that have a PPA in place, but purchase fuel at market prices or under short term contracts may not be fully hedged against changes in either power or fuel prices.

Argentina — In Argentina, the deterioration of certain economic indicators such as non-receding inflation, increased government deficits and foreign currency accessibility combined with the potential devaluation of the local currency and the potential fall in export commodity prices could cause significant volatility in our results of

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operations, cash flows, the ability to pay dividends to the Parent Company, and the value of our assets. At March 31, 2013, AES had noncurrent assets of $562 million in Argentina, including long-term receivables of $309 million. See Note 6 — Long-term Financing Receivables in Item 1. — Financial Statements of this Form 10-Q for further information on the long-term receivables.

Bulgaria — Our investments in Bulgaria rely on offtaker contracts with NEK, the state-owned national electricity distribution company. Maritza, a coal-fired generation facility, has experienced ongoing delays in the collection of outstanding receivables from its offtaker. As of March 31, 2013, Maritza had an outstanding receivables balance of $51 million with the offtaker. Although Maritza continued to collect past due receivables during the first quarter of 2013, there can be no assurance that the business will succeed in making these collections, which could result in a write-off of the receivables. In addition, depending on NEK’s ability to honor its obligations and other factors, the value of other assets could also be impaired, or the business may be in default of its loan covenants. The Company has long-lived assets in Bulgaria of $1.6 billion. Any of the above items could have a material impact on our results of operations. For further information on the importance of long-term contracts and our counterparty credit risk, see Item 1A. — Risk Factors — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations…” of the 2012 Form 10-K. Additionally, the country is scheduled to hold general elections in May 2013 and the new government will need to address several economic challenges faced by the country including higher electricity tariff. At this time, it is difficult to predict the effects of change in the political situation. See Note 29 — Subsequent Events to our consolidated financial statements included in Item 8. — Financial Statements and Supplementary Data of the 2012 Form 10-K for further information. As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.

Euro Zone — During the past few years, certain European Union countries have continually faced a sovereign debt crisis and it is possible that this crisis could spread to other countries. This crisis has resulted in an increased risk of default by governments and the implementation of austerity measures in certain countries. If the crisis continues, worsens, or spreads, there could be a material adverse impact on the Company. Our businesses may be impacted if they are unable to access the capital markets, face increased taxes or labor costs, or if governments fail to fulfill their obligations to us or adopt austerity measures which adversely impact our projects. As discussed in Item 1A. — Risk Factors — “Our renewable energy projects and other initiatives face considerable uncertainties including development, operational and regulatory challenges” of the 2012 Form 10-K, our renewables businesses are dependent on favorable regulatory incentives, including subsidies, which are provided by sovereign governments, including European governments. If these subsidies or other incentives are reduced or repealed, or sovereign governments are unable or unwilling to fulfill their commitments or maintain favorable regulatory incentives for renewables, in whole or in part, this could impact the ability of the affected businesses to continue to sustain and/or grow their operations and could result in losses or asset impairments for these businesses which could be material. The carrying value of our investment in AES Solar Energy Ltd., whose primary operations are in Europe, was $114 million at March 31, 2013. In addition, any of the foregoing could also impact contractual counterparties of our subsidiaries in core power or renewables. If such counterparties are adversely impacted, then they may be unable to meet their commitments to our subsidiaries.

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

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Impairments

Goodwill — The Company seeks business acquisitions as one of its growth strategies. We have achieved significant growth in the past as a result of several business acquisitions, which also resulted in the recognition of goodwill. In the fourth quarter of 2012, the Company completed its annual October 1 goodwill impairment evaluation and identified two reporting units, DPL and Ebute, which were considered “at risk”. A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. While there were no potential impairment indicators during the three months ended March 31, 2013 related to DPL and Ebute that could result in the recognition of goodwill impairment, it is possible that we may incur goodwill impairment at any of our reporting units in future periods if adverse changes in their business or operating environments occur. The carrying amount of the goodwill at DPL and Ebute as of March 31, 2013 was approximately $759 million and $58 million, respectively. In 2012, the Company had recognized goodwill impairment of $1.82 billion at the DP&L reporting unit.

Environmental

The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts), and certain air emissions, such as SO 2, NO x, particulate matter and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A. — Risk Factors, “Our businesses are subject to stringent environmental laws and regulations,” “Our businesses are subject to enforcement initiatives from environmental regulatory agencies,” and “Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows” set forth in the Company’s Form 10-K for the year ended December 31, 2012. The following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in Item 1. Business — Regulatory Matters — Environmental and Land Use Regulations of the Company’s Form 10-K for the year ended December 31, 2012. For further information about environmental laws and regulations impacting the Company, including a discussion of U.S. and international legislation and regulation of GHG emissions, see Item 1. Business — Regulatory Matters — Environmental and Land Use Regulations set forth in the Company’s Form 10-K for the year ended December 31, 2012.

Update on Air Emissions Regulations and Legislation

As further described in Item 1. Business — Regulatory Matters — Environmental and Land Use Regulations in the Company’s Form 10-K for the year ended December 31, 2012, as a result of existing and expected environmental regulations, including the Mercury and Air Toxics Standard (“MATS”), IPL expects to retire several generating units fueled by either coal or oil (approximately 620 MW in total) by April 2016 and to expend significant capital expenditures on environmental controls and upgrades. The units to be retired are not equipped with the advanced environmental control technologies needed to comply with existing and expected regulations, and collectively make up less than 15% of IPL’s net electricity generation over the past five years. In order to replace this generation capacity, IPL filed in April 2013 a petition and case-in-chief with its regulator (the Indiana Utility Regulatory Commission) seeking a Certificate of Public Convenience and Necessity to build a 550 to 725 MW combined cycle gas turbine at its Eagle Valley Station site in Indiana and to refuel Harding Street Station Units 5 and 6 from coal to natural gas (106 MW each). The total estimated cost of these projects is $667 million. IPL is seeking regulatory authority to accrue allowance for debt and equity funds used during construction, and to defer the recognition of depreciation expense on the projects until such time that IPL is

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allowed to collect a return and depreciation expense on the projects. The combined cycle gas turbine, if approved, is expected to be placed into service in April 2017 and the refueling project is expected to be complete by April 2016. If the Harding Street Units are not refueled, they will likely need to be retired because it is not economical to install controls on those units to comply with MATS. IPL believes recovery of these costs is likely, but not guaranteed and will likely require IPL to file a base rate case.

As a result of existing and expected environmental regulations, including MATS, DP&L has notified PJM that it plans to retire the six coal-fired units aggregating approximately 360 MW at its wholly-owned Hutchings Generation Station. Hutchings Unit 4 is currently out of service with damage to its turbine and will be retired by June 2013. DP&L plans to retire Hutchings Units 1, 2, 3, 5 and 6 by June 2015. Conversion of the coal-fired units to natural gas was investigated, but the cost of investment exceeded the expected return. In addition, DP&L owns approximately 207 MW of coal-fired generation at Beckjord Unit 6, which is operated by Duke Energy Ohio. The co-owners of Beckjord Unit 6 have notified PJM that they plan to retire Beckjord Unit 6 by June 1, 2015. At this time, DP&L does not have plans to replace the units that will be retired.

Update on Regulations Related to Water Discharges

In April 2013, the United States Environmental Protection Agency (“EPA”) announced proposed rules to reduce toxic pollutants discharged into waterways by power plants. The proposed rules are intended to update the existing technology-based rules for controlling the discharge of pollutants from various waste streams associated with steam electric generating facilities. The proposed rules identify four preferred options for controlling the discharge of these pollutants, and EPA believes that over half of existing power plants will comply with these rules, if they become final, without incurring costs. However, it is too early to determine whether the impacts of this rule, if and when it becomes final, will materially impact the Company or its subsidiaries. EPA is required to finalize these rules by May 2014.

In Item 1. Business — Regulatory Matters — Environmental and Land Use Regulations in the Company’s Form 10-K for the year ended December 31, 2012, the Company disclosed that the Indiana Department of Environmental Management (“IDEM”) issued National Pollutant Discharge Elimination System (“NPDES”) permits to the IPL Petersburg, Harding Street and Eagle Valley generating stations, which became effective in October 2012, and that IPL was seeking a two-year extension of the compliance deadline required by the permits. In April 2013, IPL received such two-year extension, through September 2017, as part of an agreed order with IDEM.

Additional Environmental Regulatory Events Occurring During Quarter

Please see Item 1. Business — Regulatory Matters — Environmental and Land Use Regulations set forth in the Company’s Form 10-K for the year ended December 31, 2012 for further information about the following events that occurred during the three months ended March 31, 2013 and relate to the impact of environmental laws and regulations on the Company and its subsidiaries:

| • |  | On January 7, 2013, the Ohio Environmental Protection Agency issued a NPDES permit for J.M. Stuart Station relating to its wastewater discharges, various aspects of which DP&L subsequently appealed; and

| • |  | On January 24, 2013 the United States Circuit Court of Appeals for the District of Columbia Circuit denied petitions for a rehearing of its decision vacating EPA’s Cross-State Air Pollution Rule that were filed by EPA and environmental and health organizations, which organizations subsequently filed petitions for writs of certiorari with the U.S. Supreme Court.

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Revenue and Gross Margin Analysis

US SBU

US — Generation

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

|  | For the Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |  |  | % Change |
|  | ($’s in millions) |
Revenue |  | $ | 170 |  |  | $ | 198 |  |  |  | -14 | %
Gross Margin |  | $ | 31 |  |  | $ | 53 |  |  |  | -42 | %

Generation revenue for the three months ended March 31, 2013 decreased $28 million, or 14%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | a decrease of $16 million at Beaver Valley in Pennsylvania, as a result of the early termination of the PPA with the offtaker in January 2013; and

| • |  | a decrease of $12 million at Hawaii, primarily due to lower availability as a result of a combination of forced and scheduled outages.

Generation gross margin for the three months ended March 31, 2013 decreased $22 million, or 42%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | a decrease of $18 million at Hawaii, primarily due to lower availability and increased fixed costs as a result of a combination of forced and scheduled outages; and

| • |  | a decrease of $8 million at Beaver Valley as discussed above.

For the three months ended March 31, 2013, revenue decreased 14%, while gross margin decreased by 42%, primarily due to higher fuel costs and increased fixed costs at Hawaii that had a negative impact on gross margin.

US — Utilities

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

|  | For the Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |  |  | % Change |
|  | ($’s in millions) |
Revenue |  | $ | 722 |  |  | $ | 732 |  |  |  | -1 | %
Gross Margin |  | $ | 118 |  |  | $ | 114 |  |  |  | 4 | %

Utilities revenue for the three months ended March 31, 2013 decreased $10 million, or 1%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | lower prices of $69 million at DPL, in Ohio, primarily due to lower capacity revenues of $31 million, lower average retail prices of $23 million due to downward price pressure as a result of generation services competition, and lower average wholesale prices of $18 million; and

| • |  | a decrease of $6 million at DPL due to the unfavorable impact of mark-to-market adjustments on derivative contracts.

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These decreases were partially offset by:

| • |  | higher volume of $38 million at DPL, primarily due to increased energy available for wholesale sales caused by switching of regulated customers to other suppliers as well as increased generation available from DPL’s co-owned and operated plants;

| • |  | higher volume of $18 million at IPL in Indiana, primarily due to colder winter weather in 2013 which increased both retail and wholesale electricity demand; and

| • |  | higher prices of $8 million at IPL, primarily due to higher fuel adjustment and other pass-through charges.

Utilities gross margin for the three months ended March 31, 2013 increased $4 million, or 4%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | lower depreciation and amortization expense of $26 million at DPL primarily because DPL’s ESP intangible asset was fully amortized at the end of 2012;

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

| • |  | higher retail and wholesale margins at IPL of $7 million primarily due to the colder winter weather in 2013, which increased demand.

These increases were partially offset by:

| • |  | lower retail margin at DPL of $41 million primarily due to DP&L customers switching to DPL Inc.’s competitive retail supplier or other third parties; and

| • |  | decrease of $9 million at DPL due to the unfavorable impact of mark-to-market adjustments on derivative contracts.

Andes SBU

Andes — Generation

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

|  | For the Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |  |  | % Change |
|  | ($’s in millions) |
Revenue |  | $ | 691 |  |  | $ | 734 |  |  |  | -6 | %
Gross Margin |  | $ | 134 |  |  | $ | 167 |  |  |  | -20 | %

Excluding the unfavorable impact of foreign currency translation and remeasurement of $18 million, generation revenue for the three months ended March 31, 2013 decreased $25 million, or 3%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | lower contract and spot prices in Chile of $19 million and lower generation of $13 million mainly due to lower dispatch from gas-fired generation;

| • |  | higher outages in Argentina of $10 million, and lower prices in CTSN due to lower coal consumption of $5 million

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These decreases were partially offset by:

| • |  | higher revenue of $22 million at Chivor in Colombia mainly driven by higher contract and spot prices due to pressure on prices from lower water inflows.

Excluding the unfavorable impact of foreign currency translation and remeasurement of $2 million, generation gross margin for the three months ended March 31, 2013 decreased $31 million, or 19%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | lower margin of $25 million in Chile mainly driven by lower dispatch from gas-fired and coal generation;

| • |  | lower revenue in Argentina of $9 million mainly driven by lower generation and lower prices; and

| • |  | lower inflows in Chivor partially offset by higher spot and contract price of $3 million.

These decreases were partially offset by:

| • |  | new business of $8 million due to the commencement of operations at Ventanas IV in Chile.

For the three months ended March 31, 2013, revenue decreased 6%, while gross margin decreased by 20%. This was primarily due to lower inflows at Chivor equally affecting revenue and gross margin and higher energy costs at Gener impacting gross margin.

Brazil SBU

Brazil — Generation

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

|  | For the Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |  |  | % Change |
|  | ($’s in millions) |
Revenue |  | $ | 386 |  |  | $ | 305 |  |  |  | 27 | %
Gross Margin |  | $ | 163 |  |  | $ | 225 |  |  |  | -28 | %

Excluding the unfavorable impact of foreign currency translation of $50 million, generation revenue for the three months ended March 31, 2013 increased $131 million, or 43%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | higher volume of $113 million mainly driven by $97 million from generation at Uruguaiana due to the temporary restart of operations during February and March of 2013; and

| • |  | higher contract prices of $15 million at Tietê as a result of PPA annual indexation in July of each year.

Excluding the unfavorable impact of foreign currency translation of $20 million, generation gross margin for the three months ended March 31, 2013 decreased $42 million, or 19%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | higher energy costs of $60 million at Tietê mainly driven by lower water inflows in the system resulting in higher energy purchases to Tietê due to shared hydrologic risk requirement among all generators at higher spot prices.

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These decreases were partially offset by:

| • |  | $13 million of gross margin at Uruguaiana from the temporary restart of operations as mentioned above; and

| • |  | lower maintenance costs of $5 million at Tietê.

For the three months ended March 31, 2013, revenue increased 27%, while gross margin decreased by 28% primarily due to Uruguaiana operations from February 2013 offset by higher energy costs in Tietê due to lower water inflows in the system.

Brazil — Utilities

The following table summarizes revenue and gross margin for our Brazil Utilities segment which includes Sul which is 100% owned and Eletropaulo which has an economic ownership of 16% for the periods indicated:

|  | For the Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |  |  | % Change |
|  | ($’s in millions) |
Revenue |  | $ | 1,323 |  |  | $ | 1,531 |  |  |  | -14 | %
Gross Margin |  | $ | 40 |  |  | $ | 83 |  |  |  | -52 | %

Excluding the unfavorable impact of foreign currency translation of $173 million, utilities revenue for the three months ended March 31, 2013 decreased $35 million, or 2%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | lower volume of $52 million due to decreased market demand; and

| • |  | lower tariff of $41 million at Sul mainly driven by lower energy pass through costs and cumulative adjustment to regulatory assets and liabilities.

These decreases were partially offset by:

| • |  | higher tariff of $58 million at Eletropaulo mainly due to higher energy pass through costs and higher tariff compared to the 2012 tariff reset provision.

Excluding the unfavorable impact of foreign currency translation of $6 million in Brazil, utilities gross margin for the three months ended March 31, 2013 decreased $37 million, or 45%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | lower volume of $34 million due to decreased market demand;

| • |  | lower tariff of $12 million at Sul mainly driven by the cumulative adjustment to regulatory assets and liabilities; and

| • |  | higher fixed costs of $8 million mainly driven by higher salaries and contingencies.

These decreases were partially offset by:

| • |  | higher tariff of $20 million at Eletropaulo compared to the 2012 tariff reset provision.

For the three months ended March 31, 2013, revenue decreased 14%, while gross margin decreased 52% primarily due to lower demand and higher fixed costs, offset by higher pass through costs.

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MCAC SBU

MCAC — Generation

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

|  | For the Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |  |  | % Change |
|  | ($’s in millions) |
Revenue |  | $ | 458 |  |  | $ | 393 |  |  |  | 17 | %
Gross Margin |  | $ | 87 |  |  | $ | 105 |  |  |  | -17 | %

Excluding the favorable impact of foreign currency translation of $2 million, primarily in Mexico, generation revenue for the three months ended March 31, 2013 increased $63 million, or 16%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | the positive impact of $42 million at Andres — Los Mina in the Dominican Republic mainly due to higher spot and PPA sales from increased demand and higher international gas prices and volume of gas sales to third parties;

| • |  | an increase of $14 million at Merida in Mexico primarily due to higher volume; and

| • |  | an increase of $9 million at Panama mainly due to higher volume of PPA energy sales and higher spot sales due to the Esti plant being back on-line from June 2012.

These increases were partially offset by:

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

Generation gross margin for the three months ended March 31, 2013 decreased $18 million, or 17%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | a decrease in Panama of $20 million mainly due to higher replacement energy purchases caused by lower hydrology at the Changuinola plant;

| • |  | a decrease of $9 million at Andres-Los Mina mainly due to higher fuel costs and higher energy purchases due to increased outages; and

| • |  | higher fixed costs across the segment of $9 million mainly due to increased maintenance expenses.

These decreases were partially offset by:

| • |  | an increase of $10 million at Andres — Los Mina mainly from higher international gas prices and volume of gas sales to third parties as described above; and

| • |  | the positive impact of $10 million at Panama due to the Esti plant as described above.

For the three months ended March 31, 2013, revenue increased 17%, while gross margin decreased by 17% primarily due to higher energy purchases in Panama and the Dominican Republic.

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EMEA SBU

EMEA — Generation

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

|  | For the Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |  |  | % Change |
|  | ($’s in millions) |
Revenue |  | $ | 351 |  |  | $ | 477 |  |  |  | -26 | %
Gross Margin |  | $ | 121 |  |  | $ | 247 |  |  |  | -51 | %

Excluding the unfavorable impact of foreign currency translation of $2 million, generation revenue for the three months ended March 31, 2013 decreased $124 million, or 26%, compared to the three months ended March 31, 2012 primarily due to:

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

| • |  | decrease of $10 million at Maritza mainly due to a lower net capacity factor in the first quarter of 2013 versus 2012; and

| • |  | net decrease of $9 million at Ballylumford in Northern Ireland, mainly due to lower capacity prices in line with the PPA starting from April 2012 that was partially offset by improved reliability in 2013.

These decreases were partially offset by:

| • |  | increase of $17 million at Kilroot due to increased dispatch of the plant and higher electricity prices in Northern Ireland.

Excluding the unfavorable impact of foreign currency translation of $1 million, generation gross margin for the three months ended March 31, 2013 decreased $125 million, or 51%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | decrease of $105 million from AES Cartagena as discussed above;

| • |  | net decrease of $23 million at Ballylumford as discussed above;

These decreases were partially offset by:

| • |  | increase of $9 million at Kilroot mainly due to increased dispatch, increased electricity prices in Northern Ireland and a reduction in the cost of coal.

For the three months ended March 31, 2013, revenue decreased 26%, while gross margin decreased 51% primarily due to the non-recurring arbitration settlement in Cartagena in February 2012.

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Asia SBU

Asia — Generation

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

|  | For the Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |  |  | % Change |
|  | ($’s in millions) |
Revenue |  | $ | 134 |  |  | $ | 182 |  |  |  | -26 | %
Gross Margin |  | $ | 41 |  |  | $ | 54 |  |  |  | -24 | %

Generation revenue for the three months ended March 31, 2013 decreased $48 million, or 26%, compared to the three months ended March 31, 2012 primarily due to:

| • |  | lower generation volume of $24 million at Kelanitissa in Sri Lanka attributable to higher hydrology in the system resulting in lower pass-through revenue;

| • |  | decrease of $12 million at Masinloc in the Philippines primarily due to lower rates offset by higher generation; and

| • |  | decrease of $10 million at Masinloc due to the non-recurring favorable impact of a mark-to-market adjustment on an embedded derivative in 2012.

Generation gross margin for the three months ended March 31, 2013 decreased $13 million, or 24%, compared to the three months ended March 31, 2012 primarily due to the decrease of $10 million at Masinloc for the non-recurring favorable impact of the mark-to-market derivative adjustment as discussed above.

Corporate and Other

Corporate and other includes the net operating results from our utility businesses in El Salvador, Africa and Europe, which are immaterial for the purposes of separate segment disclosure. The following table includes inter-segment activity and summarizes revenue and gross margin for Corporate and Other entities for the periods indicated:

|  | For the Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |  |  | % Change |
|  | ($’s in millions) |
Revenue |  |  |  |  |  |  |  |  |  |  |  |
El Salvador Utilities |  | $ | 211 |  |  | $ | 203 |  |  |  | 4 | %
Africa Utilities |  |  | 107 |  |  |  | 130 |  |  |  | -18 | %
Corporate/Other |  |  | 2 |  |  |  | 3 |  |  |  | -33 | %
Total Corporate and Other |  | $ | 320 |  |  | $ | 336 |  |  |  | -5 | %
Gross Margin |  |  |  |  |  |  |  |  |  |  |  |
El Salvador Utilities |  | $ | 18 |  |  | $ | 16 |  |  |  | 13 | %
Africa Utilities |  |  | (8 | ) |  |  | 10 |  |  |  | -180 | %
Corporate/Other |  |  | (3 | ) |  |  | (3 | ) |  |  | 0 | %
Total Corporate and Other |  | $ | 7 |  |  | $ | 23 |  |  |  | -70 | %

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Excluding the favorable impact of foreign currency translation of $1 million, revenue for the three months ended March 31, 2013 decreased $17 million, or 5%, compared to the three months ended March 31, 2012, primarily due to:

| • |  | the unfavorable impact of a mark-to-market derivative adjustment of $15 million at Sonel in Cameroon; and

| • |  | lower rates at Sonel of $10 million mainly due to a favorable 2011 tariff compensation adjustment in the first quarter 2012 not recurring in the first quarter 2013.

These decreases were partially offset by:

| • |  | higher rates of $10 million in El Salvador due to the tariff increase and higher pass-through energy costs.

Corporate and Other gross margin for the three months ended March 31, 2013 decreased by $16 million, or 70%, compared to the three months ended March 31, 2012, primarily due to:

| • |  | the unfavorable impact of $15 million at Sonel of a mark-to-market derivative adjustment as discussed above.

These decreases were partially offset by:

| • |  | an increase of $8 million at Sonel due to a decrease in fuel consumption as a result of better hydrology.

For the three months ended March 31, 2013, revenue decreased 5%, while gross margin decreased by 70% primarily due to the impact of a mark-to-market adjustment at Sonel and higher pass -through energy costs in El Salvador.

General and administrative expenses

General and administrative expenses decreased $26 million, or 30%, to $61 million for the three months ended March 31, 2013 primarily due to Company restructuring efforts, resulting in a decrease in employee related and business development costs.

Interest expense

Interest expense decreased $39 million, or 9%, to $377 million for the three months ended March 31, 2013. The decrease was primarily due to lower interest rates and lower debt principal in Brazil and the Philippines, favorable foreign currency translation in Brazil, as well as lower interest expense for Cartagena, which was deconsolidated following the sale of 80% of our interest in the first quarter of 2012. These decreases were partially offset by interest on regulatory liabilities following the tariff reset in Brazil.

Interest income

Interest income decreased $25 million, or 27%, to $66 million for the three months ended March 31, 2013. The decrease was primarily in Brazil, due to a reduction in interest-bearing assets, unfavorable foreign currency translation and lower interest rates.

Other income and expense

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

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Asset impairment expense

Asset impairment expense was $48 million for the three months ended March 31, 2013 which is primarily related to the impairment at Beaver Valley. See Note 13 — Asset Impairment Expense included in Item 1. — Financial Statements of this Form 10-Q for further information. Asset impairment expense was $10 million for the three months ended March 31, 2012.

Gain on sale of investments

Gain on sale of investments for the three months ended March 31, 2013 was $3 million, which is primarily related to the sale of Chengdu, an equity method investment in China. Gain on sale of investments for the three months ended March 31, 2012 was $179 million, of which $178 million related to the sale of 80% of our interest in Cartagena. See Note 16. — Dispositions included in Item 1. — Financial Statements of this Form 10-Q for further information.

Foreign currency transaction gains (losses)

Foreign currency transaction gains (losses) were as follows:

|  | Three Months Ended March 31, |
|  | 2013 |  |  | 2012 |
|  | ($’s in millions) |
AES Corporation |  | $ | (31 | ) |  | $ | 18 |
Chile |  |  | (4 | ) |  |  | 9 |
Philippines |  |  | - |  |  |  | (24 | )
Other |  |  | 3 |  |  |  | (4 | )
Total(1) |  | $ | (32 | ) |  | $ | (1 | )

(1) | Includes $2 million in gains and $39 million in losses on foreign currency derivative contracts for the three months ended March 31, 2013 and 2012, respectively.

The Company recognized net foreign currency transaction losses of $32 million for the three months ended March 31, 2013 primarily due to:

| • |  | losses of $31 million at the AES Corporation were primarily related to intercompany notes receivable denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the period.

The Company recognized foreign currency transaction losses of $1 million for the three months ended March 31, 2012 primarily due to:

| • |  | gains of $18 million at The AES Corporation were primarily related to intercompany notes receivable denominated in foreign currency, resulting from the strengthening of the Euro and British Pound during the quarter, partially offset by mark-to-market losses on foreign currency derivatives;

| • |  | gains of $9 million in Chile primarily related to Chilean Pesos denominated working capital at Gener (a U.S. Dollar functional currency subsidiary) resulting from a 6% appreciation of the Chilean Peso during the period. These gains were partially offset by mark-to-market losses on foreign currency derivatives; and

| • |  | losses of $24 million in the Philippines were primarily due to embedded foreign currency derivatives in PPAs. This was partially offset by unrealized foreign currency exchange gains of $5 million due to the 2% appreciation of the Philippine Peso.

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Other non-operating expense

There was no other non-operating expense for the three months ended March 31, 2013. Total other non-operating expense was $49 million for the three months ended March 31, 2012. See Note 14 — 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 $186 million, or 69%, to $82 million for the three months ended March 31, 2013 compared to $268 million for the three months ended March 31, 2012. The Company’s effective tax rates were 27% and 35% for the three months ended March 31, 2013 and 2012, respectively.

The net decrease in the effective tax rate for the three months ended March 31, 2013 compared to the same period in 2012 was principally due to the extension of a favorable U.S. tax law in the first quarter of 2013 impacting distributions from certain non-U.S. subsidiaries and the partial sale of AES Cartagena in the first quarter of 2012. See Note 16 — Dispositions regarding the sale of AES Cartagena included in Item 1. — Financial Statements of this Form 10-Q for further information.

Net equity in earnings of affiliates

Net equity in earnings of affiliates decreased $9 million, or 69%, to $4 million for the three months ended March 31, 2013. The decrease was primarily related to our share of a mark-to-market derivative adjustment along with operational losses at our AES Solar equity investment.

Income from continuing operations attributable to noncontrolling interests

Income from continuing operations attributable to noncontrolling interests decreased $58 million, or 34%, to $115 million for the three months ended March 31, 2013. The decrease was primarily due to a decrease in operating income at Tietê in 2013 related to spot market energy allocation at high prices due to drier hydrology in the system and a reduction in income of non-controlling interests at Cartagena which was deconsolidated in February 2012 as a result of the sale of 80% of our interest.

Discontinued operations

Total discontinued operations was a net loss of $22 million and net income of $1 million for the three months ended March 31, 2013 and 2012, respectively. See Note 15 — Discontinued Operations and Held for Sale Businesses included in Item 1. — Financial Statements of this Form 10-Q for further information.

Capital Resources and Liquidity

Overview

As of March 31, 2013, the Company had unrestricted cash and cash equivalents of $2.3 billion, of which approximately $425 million was held at the Parent Company and qualified holding companies, and approximately $851 million was held in short term investments primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $1.4 billion. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.9 billion and $6.0 billion, respectively. Of the approximately $3.1 billion of our current non-recourse debt, $1.8 billion was presented as such because it is due in the next twelve months and $1.3 billion relates to debt considered in default due to covenant violations. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. Approximately $507 million of our recourse debt matures within the next twelve months, which we expect to repay using a combination of cash on hand at the Parent Company, net cash provided by operating activities and net proceeds

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from the issuance of new debt at the Parent Company. We expect to repay a portion of this amount prior to maturity as part of the tender offers commenced on April 30, 2013. See Note 18 — Subsequent Events included in Item 1. — Financial Statements of this Form 10-Q for further information. See further discussion of Parent Company Liquidity below.

We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks.

Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company’s only material un-hedged exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility. On a consolidated basis, of the Company’s $15.9 billion of total non-recourse debt outstanding as of March 31, 2013, approximately $4.6 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 March 31, 2013, the Parent Company had provided outstanding financial and performance-related guarantees or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $577 million in aggregate (excluding those collateralized by letters of credit and other obligations discussed below).

As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At March 31, 2013, we had $3 million in letters of credit outstanding, provided under our senior secured credit facility, and $254 million in cash collateralized letters of credit outstanding outside of our senior

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secured credit facility. These letters of credit operate to guarantee performance relating to certain project development activities and business operations. During the quarter ended March 31, 2013, the Company paid letter of credit fees ranging from 0.25% to 3.25% per annum on the outstanding amounts.

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

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

As of March 31, 2013, the Company had approximately $348 million and $26 million of accounts receivable related to certain of its generation businesses in Argentina and the Dominican Republic, and its utility businesses in Brazil classified as “Noncurrent assets — other” and “Current assets — Accounts receivable,” respectively. The noncurrent portion primarily consists of accounts receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond March 31, 2014, or one year from the latest balance sheet date. See Note 6 — Long-term Financing Receivables included in Item 1. — Financial Statement of this Form 10-Q and Item 1. — Business — Regulatory Matters — Argentina included in the 2012 Form 10-K for further information.

Consolidated Cash Flows

During the three months ended March 31, 2013, cash and cash equivalents increased $335 million to $2.3 billion. The increase in cash and cash equivalents was due to $618 million of cash provided by operating activities, $726 million of cash used in investing activities, $455 million of cash provided by financing activities, an unfavorable effect of foreign currency exchange rates on cash of $8 million and a $4 million increase in cash of discontinued and held for sale businesses.

Operating Activities — Net cash provided by operating activities increased $84 million to $618 million during the three months ended March 31, 2013 compared to $534 million during the three months ended March 31, 2012.

Operating cash flow for the three months ended March 31, 2013 resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization and gain from sale of investments and impairment charges, partially offset by a net use of cash for operating activities of $149 million in operating assets and liabilities. Prepaid expenses and other current assets increased $192 million primarily due to a receivable from the regulator to reduce the impacts of higher thermoelectric energy costs and involuntary exposure to high spot market prices at Eletropaulo and Sul. Net income tax payables decreased $123 million primarily from payments of income taxes exceeding accruals for the first quarter 2013 tax liability. These uses of operating cash flows were partially offset by an increase of $174 million in accounts payable and other current liabilities primarily due to the return of operations at Uruguaiana in February 2013, higher energy purchases in the spot market at Tietê, an increase in accrued interest at the Parent Company, an increase in the coal purchases

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accrual at Kilroot, partially offset by a decrease in other current liabilities at Eletropaulo arising from lower value added tax payments due to the lower tariff in 2013 less an increase in accounts payable due to the higher price of energy purchases.

Net cash provided by operating activities was $534 million during the three months ended March 31, 2012. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization, deferred income taxes and gain on sales of investments and impairment expense, partially offset by a net use of cash for operating activities of $327 million in operating assets and liabilities. Accounts receivable increased $189 million primarily due to lower collections at Itabo, Los Mina and Maritza as well as an increase in revenue at Kelanitissa, Sul and Sonel. Net income tax payables decreased $161 million primarily from payments of income taxes exceeding accruals for new current tax liabilities. Other assets increased $156 million primarily due to an increase in noncurrent regulatory assets at Eletropaulo, resulting from higher priced energy purchases and regulatory charges which are recoverable through future tariff and the establishment of a noncurrent note receivable at Cartagena in Spain following the arbitration settlement, prior to its deconsolidation. Prepaid expenses and other current assets increased $117 million primarily due to an increase in current regulatory assets at Eletropaulo reflecting higher subsidies to free consumers and higher priced energy purchases as well as a prepayment for gas at Andres. These uses of operating cash flows were partially offset by an increase of $266 million in accounts payable and accrued liabilities primarily due to an increase in regulatory liabilities driven by the tariff reset at Eletropaulo and an increase of Esti tunnel repair liabilities at Panama.

This net increase of cash flows from continuing operations of $84 million for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 was primarily the result of the following:

| • |  | US — an increase of $67 million at our generation businesses primarily due to proceeds of $60 million from the PPA termination at Beaver Valley in January 2013.

| • |  | Andes — a decrease of $59 million at our generation businesses primarily driven by income tax payments at Chivor.

| • |  | MCAC — an increase of $75 million at our generation businesses primarily due to the prepayment of gas in 2012 at Andres and higher collections and lower payments at Itabo.

Investing Activities — Net cash used in investing activities was $726 million during the three months ended March 31, 2013. This was primarily attributable to capital expenditures of $546 million consisting of $334 million of growth capital expenditures and $212 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Mong Duong of $147 million, Eletropaulo of $72 million, Gener of $27 million, Sul of $17 million and Jordan of $11 million. Maintenance and environmental capital expenditures included amounts at IPALCO of $42 million, Eletropaulo of $33 million, Gener of $27 million, Sul of $27 million, DPL of $24 million and Tietê of $17 million. Purchases of short-term investments, net of sales, were $157 million primarily at Sul of $111 million and Tietê of $80 million offset by sales of $20 million at Eletropaulo.

Net cash used for investing activities was $725 million during the three months ended March 31, 2012. This was primarily attributable to capital expenditures of $579 million consisting of $338 million of growth capital expenditures and $241 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Gener of $77 million, Eletropaulo of $66 million, Mong Duong of $40 million, DPL of $26 million, Sul of $24 million, Maritza of $18 million and Mountain View 4 of $16 million. Maintenance and environmental capital expenditures included amounts at Eletropaulo of $50 million, IPL of $31 million, DPL of $27 million, Panama of $25 million and Sul of $23 million. Purchases of short-term investments, net of sales were $350 million primarily at Eletropaulo of $365 million offset by sales of $21 million at Gener. These uses of cash were partially offset by proceeds from government grants for asset construction of $85 million primarily for funds received at our wind project Laurel Mountain and proceeds from the sale of businesses, net of cash sold of $63 million for the sale of 80% of our interest in Cartagena in February.

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Net cash used in investing activities increased $1 million to $726 million during the three months ended March 31, 2013 compared to $725 million during the three months ended March 31, 2012. This net increase was primarily due to decreases in proceeds from government grants of $84 million, increases of restricted cash of $63 million and decreases in proceeds from the sale of business of $62 million offset by a decrease of purchases of short-term investments, net of sales of $193 million.

Financing Activities — Net cash provided by financing activities was $455 million during the three months ended March 31, 2013. Proceeds from the issuances of non-recourse debt of $1.5 billion included amounts at Masinloc of $500 million, El Salvador of $310 million, Tietê of $251 million, Sul of $150 million, Mong Duong of $119 million, Warrior Run of $74 million, Kribi of $31 million, Puerto Rico of $25 million and Jordan of $18 million. This was partially offset by repayments of non-recourse debt of $1 billion primarily at Masinloc of $531 million, El Salvador of $150 million, Warrior Run of $80 million, Tietê of $60 million, Puerto Rico of $38 million, Sul of $34 million, Maritza of $29 million, Sonel of $22 million and Angamos of $21 million.

Net cash provided by financing activities was $37 million during the three months ended March 31, 2012. Proceeds from the issuances of non-recourse debt of $503 million included amounts at Eletropaulo of $339 million, Kribi of $41 million, Mong Duong of $37 million and Alicura in Argentina of $34 million. This was partially offset by net repayments under revolving credit facilities of $281 million primarily at the Parent Company and $151 million for the repayments of non-recourse debt primarily at Maritza for $25 million, Sonel for $23 million, our European wind projects for $22 million and Masinloc for $20 million.

Net cash provided by financing activities increased $418 million to $455 million during the three months ended March 31, 2013 compared to net cash provided by financing of $37 million during the three months ended March 31, 2012. This net increase was primarily due to increases in proceeds from issuance of non-recourse debt of $988 million and increases in net borrowings under revolving credit facilities of $296 million, partially offset by increases in repayments of non-recourse debt of $856 million.

Parent Company Liquidity

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

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

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

| • |  | proceeds from asset sales.

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

| • |  | interest;

| • |  | principal repayments of debt;

| • |  | acquisitions;

| • |  | construction commitments;

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| • |  | other equity commitments;

| • |  | equity repurchases;

| • |  | taxes;

| • |  | Parent Company overhead and development costs; and

| • |  | dividends on common stock.

The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents,” at March 31, 2013 and December 31, 2012 as follows:

Parent Company Liquidity |  | March 31, 2013 |  |  | December 31, 2012 |
|  | (in millions) |
Consolidated cash and cash equivalents |  | $ | 2,301 |  |  | $ | 1,966 |
Less: Cash and cash equivalents at subsidiaries |  |  | (1,876 | ) |  |  | (1,655 | )
Parent and qualified holding companies’ cash and cash equivalents |  |  | 425 |  |  |  | 311 |
Commitments under Parent credit facilities |  |  | 800 |  |  |  | 800 |
Less: Letters of credit under the credit facilities |  |  | (3 | ) |  |  | (5 | )
Borrowings available under Parent credit facilities |  |  | 797 |  |  |  | 795 |
Total Parent Company Liquidity |  | $ | 1,222 |  |  | $ | 1,106 |

The Company paid a dividend of $0.04 per share to its common stockholders during the three months ended March 31, 2013. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance we will be able to continue the payment of dividends.

While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets (see Key Trends and Uncertainties and Global Economic Considerations in this Item 2), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured credit facility. See Item 1A. — Risk Factors, “The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.” of the Company’s 2012 Form 10-K.

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

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

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

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

| • |  | maintenance of certain financial ratios; and

| • |  | financial and other reporting requirements.

As of March 31, 2013, the Parent Company was in compliance with these covenants.

Non-Recourse Debt

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

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

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

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

| • |  | triggering defaults in our outstanding debt at the Parent Company.

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

Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying condensed consolidated balance sheet amounts to $3.1 billion. The portion of current debt related to such defaults was $1.3 billion at March 31, 2013, all of which was non-recourse debt related to four subsidiaries — Maritza, Sonel, Kavarna, and Saurashtra.

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’s corporate debt agreements as of March 31, 2013 in order for such defaults to trigger an event of default or permit acceleration under AES’s indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities.

Critical Accounting Policies and Estimates

The condensed consolidated financial statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. The Company’s significant accounting policies are described in Note 1 — General and Summary of Significant Accounting Policies to the consolidated financial statements included in our 2012 Form 10-K. The Company’s critical accounting estimates are described in Management’s Discussion and

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Analysis of Financial Condition and Results of Operations included in the 2012 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that those policies remain the Company’s critical accounting policies as of and for the three months ended March 31, 2013.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks

Our generation and utility businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal and environmental credits. We operate in multiple countries and as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between our functional currency, the U.S. Dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments.

These disclosures set forth in this Item 3 are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 3. For further information regarding market risk, see Item 1A. — Risk Factors, Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations, Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance, and We may not be adequately hedged against our exposure to changes in commodity prices or interest rates of the 2012 Form 10-K.

Commodity Price Risk

Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term sales or under contract sales that leave an un-hedged exposure on some of capacity, or through imperfect pass throughs. In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations, and sharing or pass through mechanisms. These businesses subject our operational results to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options.

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

AES businesses will see changes in variable margin performance as global commodity prices shift. For the balance of 2013, we project pretax earnings exposure on a 10% move in commodity prices would be approximately $10 million for coal, $10 million for oil and $15 million for natural gas. Our estimates exclude correlation. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some of our businesses.

Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Generation costs can be directly affected by movements in the price of natural gas, oil and coal. Spot power prices and contract indexation provisions are affected by the same commodity price movements. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. Offsets are not perfectly linear or symmetric. The sensitivities are affected by a number of non-market, or indirect market factors. Examples of these factors include hydrology,

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energy market supply/demand balances, regional fuel supply issues, regional competition, bidding strategies and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, certain power plants may reduce dispatch in low market environments limiting downside exposure. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices.

In the US SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Additionally, at DPL, open access allows our retail customers to switch to alternative suppliers; falling energy prices may increase the rate at which our customers switch to alternative suppliers; DPL sells generation in excess of its retail demand under short-term sales; and the outcome of the DPL regulatory filing may affect our level of commodity price exposure over time. Given that natural gas-fired generators set power prices for many markets, higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during peak periods.

For the Andes SBU, our business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. While we have been adding coal-fired generation to our portfolio in Chile, a small amount of efficient generation is sold into the spot market. Other assets in Chile include natural gas/diesel, hydroelectric and biomass generation facilities. Generators with oil or oil-linked fuel generally set power prices in these markets impacting spot power margins. In Colombia we operate under a short-term sales strategy and have commodity exposure to un-hedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel.

The businesses in the MCAC SBU have commodity exposure on un-hedged volumes. Panama is largely contracted under a portfolio of contract sales, and the un-hedged portion of our hydroelectric assets in Panama is sensitive to changes in spot power prices which may be driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices.

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

In the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume sold in the spot market. Low oil prices may be a driver of margin compression since oil affects spot power sale prices.

Foreign Exchange Rate Risk

In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the

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fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in the U.S. Dollar or currencies other than their own functional currencies. Primarily, we are exposed to changes in the exchange rate between the U.S. Dollar and the following currencies: Argentine Peso, Brazilian Real, British Pound, Cameroonian Franc, Chilean Peso, Colombian Peso, Dominican Peso, Euro, Indian Rupee, Kazakhstani Tenge, Philippine Peso, and Ukrainian Hryvnia. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.

We have entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. The largest foreign exchange risks are stemming from the following currencies: Argentine Peso, Brazilian Real, Colombian Peso and Euro, determined based on historic volatility over the preceding twelve-month period. As of March 31, 2013, assuming a 10% U.S. Dollar appreciation, adjusted pretax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine Peso, Brazilian Real, Colombian Peso and Euro (the earnings attributable to the subsidiaries exposed to the Cameroonian Franc movements are included under Euro due to the fixed exchange rate of the Cameroonian Franc to the Euro) relative to the U.S. Dollar are projected to be reduced by approximately $10 million, $15 million, $10 million, and $10 million, respectively, for the balance of 2013. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pretax earnings for the balance of 2013 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted pretax earnings exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility.

Interest Rate Risks

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

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

As of March 31, 2013, the portfolio’s pretax earnings exposure for the balance of 2013 to a 100 basis point increase in interest rates for our Argentine Peso, Brazilian Real, Columbian Peso, British Pound, Euro, Indian Rupee, Philippine Peso, Kazakhstani Tenge, and U.S. Dollar denominated debt would be approximately $20 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.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company, under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective as of March 31, 2013 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Controls over Financial Reporting

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

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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 March 31, 2013.

In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro (“FDC”) against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the FDC found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$1.35 billion ($667 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo’s defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro (“AC”) ruled that Eletropaulo was not a proper party to the litigation because any alleged liability had been transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the FDC for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the FDC. Eletropaulo’s subsequent appeals were dismissed. In February 2010, the FDC appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization, in accordance with the methodology proposed by Eletrobrás. Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo’s arguments and directed the FDC to proceed accordingly. However, in December 2012, the FDC disregarded the AC’s decision that the parties were entitled to full discovery and an expert appraisal of the issues prior to the resolution of the case and, instead, issued a decision finding Eletropaulo liable for the debt. The AC subsequently granted Eletropaulo’s request to suspend the execution suit in the FDC and thereafter annulled the FDC’s decision. The case has returned to the FDC for proceedings in accordance with the AC’s April 2010 decision. If the FDC again finds Eletropaulo liable for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the FDC grants such request, Eletropaulo’s results of operations may be materially adversely affected and, in turn the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the FDC against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of São Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1 million ($593 thousand) as of December 31, 2012, or pay an indemnification amount of approximately R$15 million ($7 million). Eletropaulo has appealed this decision to the Supreme Court and the

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Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court’s decision, the case is being remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision.

In August 2001, the Grid Corporation of Orissa, India, now Gridco Ltd. (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and seeking interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. In September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2010, a 2-to-1 majority of the arbitral tribunal awarded the Company some of its costs relating to the arbitration. In August 2010, Gridco filed a challenge of the cost award with the local Indian court. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC’s existing PPA with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC’s jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court’s decision to the Supreme Court and sought stays of both the High Court’s decision and the underlying OERC proceedings regarding the PPA’s terms. In April 2005, the Supreme Court granted OPGC’s requests and ordered stays of the High Court’s decision and the OERC proceedings with respect to the PPA’s terms. In December 2012, the parties executed a settlement agreement amending the PPA and resolving the dispute. Pursuant to the settlement, the appeal in the Supreme Court has been withdrawn. The amended PPA is subject to regulatory approval.

In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgás and the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo and the quality of service provided by Eletropaulo to its customers, and requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FCSP”) alleging that BNDES violated Law 8429/92 (the Administrative

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Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal with the FCA, which was subsequently consolidated with the MPF’s interlocutory appeal, seeking a transfer of venue and to enjoin the FCSP from considering any of the alleged violations. In June 2009, the FCA granted the injunction sought by AES Elpa and AES Transgás and transferred the case to the Federal Court of Rio de Janeiro. In May 2010, the MPF filed an appeal with the Superior Court of Justice (“SCJ”) challenging the transfer. In November 2012, the SCJ ruled that the lawsuit must be returned to the FCSP. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney’s Office then requested an injunction which the judge rejected on September 26, 2008, and the Public Attorney’s office no longer has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a “Technical Cooperation Protocol” pursuant to which they requested a new deadline from FEPAM in order to present a proposal. In March 2008, the State Prosecution office filed a Class Action against AES Florestal, AES Sul and CEEE, requiring an injunction for the removal of the alleged sources of contamination and the payment of an indemnity in the amount of R$6 million ($3 million). The injunction was rejected. The above-referenced proposal to FEPAM with respect to containing and remediating the contamination was delivered on April 8, 2008. FEPAM responded by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response, Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE’s operations. In October 2011, the State Prosecution Office presented a new request to the court of Triunfo for an injunction against Florestal, Sul and CEEE for the removal of the alleged sources of contamination and remediation, and the court granted the injunction against CEEE but did not grant injunctive relief against Florestal or Sul. CEEE appealed such decision, and the State of Rio Grande do Sul Court of Appeals upheld the decision. As required by

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the injunction, CEEE has started the removal and disposal of the contaminants, which is ongoing, and Sul is not at risk to bear any of such remediation costs, which are estimated to be approximately R$49.0 million ($24 million). In November 2012, the inspections performed by the court expert and supervised by Sul confirmed that CEEE is fulfilling the injunction by removing the contaminants. The case is in the evidentiary stage awaiting the production of the court’s expert opinion on several matters, including which of the parties had utilized the products found in the area.

In January 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. (“Este”)) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court’s decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity’s appeal remains pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska, filed a complaint in the U.S. District Court for the Northern District of California against the Company and numerous unrelated companies, claiming that the defendants’ alleged GHG emissions have contributed to alleged global warming which, in turn, allegedly has led to the erosion of the plaintiffs’ alleged land. The plaintiffs assert nuisance and concert of action claims against the Company and the other defendants, and a conspiracy claim against a subset of the other defendants. The plaintiffs seek to recover relocation costs, indicated in the complaint to be from $95 million to $400 million, and other unspecified damages from the defendants. The Company filed a motion to dismiss the case, which the District Court granted in October 2009. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit. In September 2012, the Ninth Circuit affirmed the District Court’s decision. The plaintiffs’ subsequent petition for en banc review was denied by the Ninth Circuit. The plaintiffs have filed a petition requesting review by the Supreme Court, which the defendants have opposed. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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

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

In October 2009, AES Mérida III, S. de R.L. de C.V. (AES Mérida), one of our businesses in Mexico, initiated arbitration against its fuel supplier and electricity offtaker, Comisión Federal de Electricidad (“CFE”), seeking a declaration that CFE breached the parties’ power purchase agreement (“PPA”) by supplying gas that did not comply with the PPA’s specifications. Alternatively, AES Mérida requested a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputed the claims. Although it did not assert counterclaims, in its closing brief CFE asserted that it is entitled to a partial refund of the capacity charge payments that it made for power generated with the out-of-specification gas. In July 2012, the arbitral Tribunal issued an award in AES Mérida’s favor. In December 2012, CFE initiated an action in Mexican court seeking to nullify the award. AES Mérida has opposed the request and asserted a counterclaim to confirm the award. AES Mérida believes it has meritorious defenses in that action; however, there can be no assurances that it will be successful.

In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the Clean Air Act (“CAA”) Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review (“NSR”) requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.

In November 2009, April 2010, December 2010, April 2011, June 2011, August 2011, and November 2011, substantially similar personal injury lawsuits were filed by a total of 49 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit, the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages and the Company is not able to estimate damages, if any, at this time. The AES defendants moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court

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granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. The AES defendants again moved for partial dismissal of those amended complaints, and in May 2012, the Superior Court ruled on the motion in the November 2009 lawsuit, dismissing the plaintiffs’ claims for future medical monitoring expenses but declining to dismiss their claims under Dominican Republic Law 64-00. The Superior Court has not yet ruled on the motion for partial dismissal of the April 2010 lawsuit. The AES defendants filed an answer to the November 2009 lawsuit in June 2012. The Superior Court has stayed the remaining six lawsuits, as well as any subsequently filed similar lawsuits. The Superior Court has also ordered that, for the present, discovery will proceed only in the November 2009 lawsuit and will be limited to causation and exposure issues. The AES defendants believe they have meritorious defenses and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.

On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns a 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million. The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units, allegedly because of the purported characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor’s claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately €240 million ($308 million) in the arbitration, unspecified damages for alleged injury to reputation, and other relief. The arbitral hearing on the merits is scheduled for November 25-December 6, 2013 and January 6-17, 2014. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

On February 11, 2011 AES Eletropaulo received a notice of violation from São Paulo State’s Environmental Authorities for allegedly destroying 0.32119 hectares of native vegetation at the Conservation Park of Serra do Mar (“Park”), without previous authorization or license. The notice of violation asserted a fine of approximately R$1 million ($516,436) and the suspension of AES Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities (“São Paulo EA”), AES Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the notice of violation or reduce the fine. In December 2011, the São Paulo EA declined to vacate the notice of violation but recognized the possibility of 40% reduction in the fine if AES Eletropaulo agrees to recover the affected area with additional vegetation. AES Eletropaulo has not appealed the decision and is now discussing the terms of a possible settlement with the São Paulo EA, including a plan to recover the affected area by primarily planting additional trees. In March 2012, the State of São Paulo Prosecutor’s Office of São Bernando do Campo initiated a Civil Proceeding to review the compliance by AES Eletropaulo with the terms of any possible settlement. AES Eletropaulo has had several meetings and field inspections to settle the details of the recovery project. AES Eletropaulo is currently awaiting the approval of the recovery project by the Park Administrator.

In May 2011, a putative class action was filed in the Mississippi federal court against the Company and numerous unrelated companies. The lawsuit alleges that greenhouse gas emissions contributed to alleged global warming which, in turn, allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert claims for public and private nuisance, trespass, negligence, and declaratory judgment. The plaintiffs seek

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damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. The Company is unable to estimate the alleged damages at this time. These and other plaintiffs previously brought a substantially similar lawsuit in the federal court but failed to obtain relief. In October 2011, the Company and other defendants filed motions to dismiss the lawsuit. In March 2012, the federal court granted the motion and dismissed the lawsuit. The plaintiffs appealed to the U.S. Court of Appeals for the Fifth Circuit. The appeal is fully briefed and oral argument occurred on May 1, 2013. The Company believes it has meritorious defenses and will defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.

In February 2011, a consumer protection group, S.O.S. Consumidores (“SOSC”), filed a lawsuit in the State of Săo Paulo Federal Court against Eletropaulo and all other distribution companies in the State of Săo Paulo, claiming that the distribution companies had overcharged customers for electricity. SOSC asserts that the distribution companies’ tariffs had been incorrectly calculated by the Brazilian Regulatory Agency (“ANEEL”). ANEEL corrected the alleged error in May 2010. There are separate proceedings against ANEEL to determine whether the tariffs had been properly calculated. SOSC has moved for an injunction requiring tariffs to be corrected from the effective dates of the relevant concession contracts. Electropaulo has opposed that request on the ground that it did not wrongfully collect amounts from its customers, since its tariff was calculated in accordance with the concession contract with the Federal Government and ANEEL’s rules. At ANEEL’s request, the Superior Court of Justice has suspended the lawsuit and similar cases against third parties and determined that all such cases shall be transferred to the Federal Court of Belo Horizonte. If Eletropaulo does not prevail in the lawsuit, Eletropaulo estimates that its liability to customers could be approximately R$855 million ($422 million). Electropaulo believes it has meritorious defenses and will defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.

In June 2011, the São Paulo Municipal Tax Authority (the “Municipality”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking approximately R$1.2 billion ($593 million) in services tax (“ISS”) that allegedly had not been collected on revenues for services rendered by Eletropaulo. Eletropaulo estimates that, with interest, the amount at issue has increased to approximately R$1.9 billion ($1.0 billion). Eletropaulo has challenged the assessments on the ground that the revenues at issue were not subject to ISS. Eletropaulo believes it has meritorious defenses to the assessments and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In August 2012, Fondo Patrimonial de las Empresas Reformadas (“FONPER”) (the Dominican instrumentality that holds the Dominican Republic’s shares in Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”)) filed a criminal complaint against certain current and former employees of AES. The criminal proceedings include a related civil component initiated against Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NCI”) (the AES affiliate that manages Itabo). FONPER asserts claims relating to the alleged mismanagement of Itabo and seeks approximately $270 million in damages. The Dominican District Attorney (“DA”) has admitted the criminal complaint and is investigating the allegations set forth therein. In September 2012, one of the individual defendants responded to the criminal complaint, denying the charges and seeking an immediate dismissal of same. In April 2013, the DA requested that the Dominican Camara de Cuentas perform an audit of the allegations in the criminal complaint. Further, in August 2012, Coastal and NCI initiated an international arbitration proceeding against FONPER and the Dominican Republic, seeking a declaration that Coastal and NCI have acted both lawfully and in accordance with the relevant contracts with FONPER and the Dominican Republic in relation to the management of Itabo. Coastal and NCI also seek a declaration that the criminal complaint is a breach of the relevant contracts between the parties, including the obligation to arbitrate disputes. Coastal and NCI further seek damages from FONPER and the Dominican Republic resulting from their breach of contract. FONPER and the Dominican Republic have denied the claims. The AES defendants believe they have meritorious claims and defenses, which they will assert vigorously; however there can be no assurance that they will be successful in their efforts.

In March 2013, an arbitral Tribunal issued a “Partial Final Award” and thereafter a “Revised Partial Final Award” (the “Award”), ordering a wind subsidiary of the Company to pay a net amount of approximately $17

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million to its EPC Contractor. The arbitration is ongoing, and the Contractor and certain of its subcontractors have asserted additional claims seeking interest, fees, and costs totaling approximately $13 million, as well as relief relating to certain liens. Also, there are judicial proceedings concerning the Award and a guaranty issued to the Contractor by another wind subsidiary of the Company. The wind subsidiaries will assert their respective defenses and claims vigorously; however, there can be no assurances that they will prevail.

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ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2012 Form 10-K under Part 1 — Item 1A. — Risk Factors.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

4.1 |  | Sixteenth Supplemental Indenture, dated April 30, 2013 between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company’s Form 8-K filed on April 30, 2013.
10.1 |  | Amendment No. 1, dated February 27, 2013, to the Credit Agreement dated as of May 27, 2011 among The AES Corporation, as borrower, the banks listed therein and Bank of America, N.A., as administrative agent (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).

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##### Table of Contents

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: May 8, 2013 |  | By: |  | /s/ THOMAS M. O’FLYNN |  |
|  |  |  | Name: |  | Thomas M. O’Flynn |  |
|  |  |  | Title: |  | Executive Vice President and Chief Financial Officer (Principal Financial Officer) |  |
|  | By: |  | /s/ MICHAEL RAMBERG |  |
|  |  |  | Name: |  | Michael Ramberg |  |
|  |  |  | Title: |  | Vice President and Interim Controller (Principal Accounting Officer) |  |

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