Edgar Filing: AES CORP

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended March 31, 2012

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

Commission file number 1-12291

LOGO

THE AES CORPORATION

(Exact name of registrant as specified in its charter)


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

(703) 522-1315

Registrant’s telephone number, including area code:

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

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

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

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

The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, on April 26, 2012 was 767,489,830.

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2012

TABLE OF CONTENTS


PART I: FINANCIAL INFORMATION		1

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

*ITEM 2.*	*MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*	33

*ITEM 3.*	*QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK*	65

*ITEM 4.*	*CONTROLS AND PROCEDURES*	67

PART II: OTHER INFORMATION		69

*ITEM 1.*	*LEGAL PROCEEDINGS*	69

*ITEM 1A.*	*RISK FACTORS*	76

*ITEM 2.*	*UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS*	76

*ITEM 3.*	*DEFAULTS UPON SENIOR SECURITIES*	76

*ITEM 4.*	*MINE SAFETY DISCLOSURES*	76

*ITEM 5.*	*OTHER INFORMATION*	76

*ITEM 6.*	*EXHIBITS*	76

SIGNATURES		77

PART I: FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

THE AES CORPORATION

Condensed Consolidated Balance Sheets

(Unaudited)


	March 31, 2012			December 31, 2011
	(in millions, except share and per share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,688		$	1,704
Restricted cash		448			478
Short-term investments		1,740			1,356
Accounts receivable, net of allowance for doubtful accounts of $300 and $273, respectively		2,735			2,534
Inventory		799			785
Deferred income taxes		480			454
Prepaid expenses		238			157
Other current assets		1,394			1,569
Current assets of discontinued and held for sale businesses		37			191

Total current assets		9,559			9,228

NONCURRENT ASSETS
Property, Plant and Equipment:
Land		1,113			1,090
Electric generation, distribution assets and other		31,774			31,143
Accumulated depreciation		(9,290	)		(8,944	)
Construction in progress		1,992			1,833

Property, plant and equipment, net		25,589			25,122

Other Assets:
Investments in and advances to affiliates		1,430			1,422
Debt service reserves and other deposits		880			876
Goodwill		3,732			3,733
Other intangible assets, net of accumulated amortization of $201 and $164, respectively		550			566
Deferred income taxes		736			715
Other		2,273			2,331
Noncurrent assets of discontinued and held for sale businesses		682			1,340

Total other assets		10,283			10,983

TOTAL ASSETS	$	45,431		$	45,333

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,014		$	2,014
Accrued interest		433			327
Accrued and other liabilities		3,114			3,398
Non-recourse debt, including $296 and $259, respectively, related to variable interest entities		2,194			2,123
Recourse debt		21			305
Current liabilities of discontinued and held for sale businesses		202			279

Total current liabilities		7,978			8,446

NONCURRENT LIABILITIES
Non-recourse debt, including $1,173 and $1,156, respectively, related to variable interest entities		13,841			13,412
Recourse debt		6,179			6,180
Deferred income taxes		1,445			1,328
Pension and other post-retirement liabilities		1,755			1,729
Other noncurrent liabilities		3,132			3,083
Noncurrent liabilities of discontinued and held for sale businesses		552			1,348

Total noncurrent liabilities		26,904			27,080

Contingencies and Commitments (see Note 8)
Cumulative preferred stock of subsidiaries		78			78
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 809,082,637 issued and 767,434,120 outstanding at March 31, 2012 and 807,573,277 issued and 765,186,316 outstanding at December 31, 2011		8			8
Additional paid-in capital		8,516			8,507
Retained earnings		1,019			678
Accumulated other comprehensive loss		(2,575	)		(2,758	)
Treasury stock, at cost (41,648,517 shares at March 31, 2012 and 42,386,961 shares at December 31, 2011, respectively)		(479	)		(489	)

Total AES Corporation stockholders’ equity		6,489			5,946
NONCONTROLLING INTERESTS		3,982			3,783

Total equity		10,471			9,729

TOTAL LIABILITIES AND EQUITY	$	45,431		$	45,333

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)


	Three Months Ended March 31,
	2012			2011
	(in millions, except per share amounts)
Revenue:
Regulated	$	2,620		$	2,349
Non-Regulated		2,120			1,807

Total revenue		4,740			4,156

Cost of Sales:
Regulated		(2,182	)		(1,773	)
Non-Regulated		(1,480	)		(1,390	)

Total cost of sales		(3,662	)		(3,163	)

Gross margin		1,078			993

General and administrative expenses		(87	)		(95	)
Interest expense		(416	)		(338	)
Interest income		91			95
Other expense		(29	)		(15	)
Other income		18			16
Gain on sale of investments		179			6
Asset impairment expense		(11	)		-
Foreign currency transaction gains (losses)		(1	)		33
Other non-operating expense		(49	)		-

INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES		773			695
Income tax expense		(267	)		(215	)
Net equity in earnings of affiliates		13			10

INCOME FROM CONTINUING OPERATIONS		519			490
Income (loss) from operations of discontinued businesses, net of income tax (benefit) expense of $2 and $(3), respectively		1			(7	)
Net gain (loss) from disposal and impairments of discontinued businesses, net of income tax expense of $0 and $0, respectively		(5	)		-

NET INCOME		515			483
Noncontrolling interests:
Less: Income from continuing operations attributable to noncontrolling interests		(174	)		(253	)
Less: Income from discontinued operations attributable to noncontrolling interests		-			(6	)

Total net income attributable to noncontrolling interests		(174	)		(259	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	341		$	224

BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.45		$	0.30
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		-			(0.02	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.45		$	0.28

DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.44		$	0.30
Discontinued operations attributable to The AES Corporation common stockholders, net of tax		-			(0.02	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.44		$	0.28

AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	345		$	237
Discontinued operations, net of tax		(4	)		(13	)

Net income	$	341		$	224

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statements of Comprehensive Income

(Unaudited)


	Three Months Ended March 31,
	2012			2011
	(in millions)
NET INCOME	$	515		$	483

Available-for-sale securities activity:

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

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


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

Foreign currency translation activity:

Foreign currency translation adjustments, net of income tax (expense) of $(1) and $(4), respectively		142			131

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


Total foreign currency translation adjustments		141			128

Derivative activity:

Change in derivative fair value, net of income tax (expense) of $(4) and $(9), respectively		21			41

Reclassification to earnings, net of income tax (expense) of $(28) and $(8), respectively		86			30


Total change in fair value of derivatives		107			71

Pension activity:

Reclassification to earnings, due to amortization of prior service cost and net gains (losses), net of income tax (expense) of $(3) and $(2), respectively		6			3


Total pension adjustments		6			3


OTHER COMPREHENSIVE INCOME		254			201


COMPREHENSIVE INCOME		769			684

Less: Comprehensive income attributable to noncontrolling interests		(245	)		(325	)


COMPREHENSIVE INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	524		$	359

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	Three Months Ended March 31,
	2012			2011
	(in millions)
OPERATING ACTIVITIES:
Net income	$	515		$	483
Adjustments to net income:
Depreciation and amortization		360			305
(Gain) loss from sale of investments and impairment expense		(92	)		3
Provision for deferred taxes		101			17
Contingencies		17			22
Other		(40	)		(84	)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(189	)		(112	)
(Increase) decrease in inventory		(11	)		(69	)
(Increase) decrease in prepaid expenses and other current assets		(117	)		13
(Increase) decrease in other assets		(156	)		11
Increase (decrease) in accounts payable and other current liabilities		266			(41	)
Increase (decrease) in income taxes and other income tax payables, net		(161	)		(105	)
Increase (decrease) in other liabilities		41			59

Net cash provided by operating activities		534			502

INVESTING ACTIVITIES:
Capital expenditures		(579	)		(479	)
Acquisitions — net of cash acquired		-			(138	)
Proceeds from the sale of businesses, net of cash sold		63			8
Proceeds from the sale of assets		4			4
Sale of short-term investments		1,505			1,241
Purchase of short-term investments		(1,855	)		(1,181	)
Decrease in restricted cash		28			11
(Increase) decrease in debt service reserves and other assets		20			(7	)
Affiliate advances and equity investments		-			(40	)
Proceeds from government grants for asset construction		85			1
Other investing		4			(21	)

Net cash used in investing activities		(725	)		(601	)

FINANCING ACTIVITIES:
(Repayments) borrowings under the revolving credit facilities, net		(281	)		24
Issuance of non-recourse debt		503			115
Repayments of recourse debt		(3	)		(268	)
Repayments of non-recourse debt		(151	)		(201	)
Payments for financing fees		(12	)		(5	)
Distributions to noncontrolling interests		(19	)		(43	)
Contributions from noncontrolling interests		5			-
Financed capital expenditures		(6	)		(17	)
Purchase of treasury stock		-			(63	)
Other financing		1			(5	)

Net cash provided by (used in) financing activities		37			(463	)
Effect of exchange rate changes on cash		25			15
Decrease in cash of discontinued and held for sale businesses		113			7

Total decrease in cash and cash equivalents		(16	)		(540	)
Cash and cash equivalents, beginning		1,704			2,522

Cash and cash equivalents, ending	$	1,688		$	1,982

SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	291		$	229
Cash payments for income taxes, net of refunds	$	325		$	304

See Notes to Condensed Consolidated Financial Statements

THE AES CORPORATION

Notes to Condensed Consolidated Financial Statements

For the Three Months Ended March 31, 2012 and 2011

1. FINANCIAL STATEMENT PRESENTATION

The prior period condensed consolidated financial statements in this Quarterly Report on Form 10-Q (“Form 10-Q”) have been reclassified to reflect the businesses held for sale and discontinued operations as discussed in Note 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, changes in equity and cash flows. The results of operations for the three months ended March 31, 2012 are not necessarily indicative of results that may be expected for the year ending December 31, 2012. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2011 audited consolidated financial statements and notes thereto, which are included in the 2011 Form 10-K filed with the SEC on February 24, 2012 (the “2011 Form 10-K”).

New Accounting Policies Adopted

ASU No. 2011-4, Fair Value Measurements (Topic 820), “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS”

In May 2011, the FASB issued ASU No. 2011-4, which among other requirements, prohibits the use of the block discount factor for all fair value level hierarchies; permits an entity to measure the fair value of its financial instruments on a net basis when the related market risks are managed on a net basis; states the highest and best use concept is no longer relevant in the measurement of financial assets and liabilities; clarifies that a reporting entity should disclose quantitative information about the unobservable inputs used in Level 3 measurements and that the application of premiums and discounts is related to the unit of account for the asset or liability being measured at fair value; and requires expanded disclosures to describe the valuation process used for Level 3 measurements and the sensitivity of Level 3 measurements to changes in unobservable inputs. In addition, entities are required to disclose the hierarchy level for items which are not measured at fair value in the statement of financial position, but for which fair value is required to be disclosed. AES adopted ASU No. 2011-4 on January 1, 2012. The adoption did not have a material impact on the Company’s financial position, results of operations or cash flows.

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

2. INVENTORY

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


	March 31, 2012		December 31, 2011
	(in millions)
Coal, fuel oil and other raw materials	$	432	$	444
Spare parts and supplies		367		341

Total	$	799	$	785

3. FAIR VALUE

The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The fair value of non-recourse debt is estimated differently based upon the type of loan. In general, the carrying amount of variable rate debt is a close approximation of its fair value. For fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow analyses. See Note 7 — Debt for additional information on the fair value and carrying value of debt. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards, swaps and options, and energy derivatives is the estimated net amount that the Company would receive or pay to sell or transfer the agreements as of the balance sheet date.

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

Valuation Techniques

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

to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the determination of the fair value of the assets and liabilities and their placement within the fair value hierarchy levels.

Investments

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

Derivatives

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

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

For each derivative, with the exception of those classified as Level 1, the income approach is used to estimate the cash flows over the remaining term of the contract. Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR or EURIBOR) plus a spread that reflects the credit or nonperformance risk. This risk is estimated by the Company using credit spreads and risk premiums that are observable in the market, whenever possible, or estimated borrowing costs based on bank quotes, industry

publications and/or information on financing closed on similar projects. To the extent that management can estimate the fair value of these assets or liabilities without the use of significant unobservable inputs, the fair value of these derivatives are classified as Level 2.

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

The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) at March 31, 2012:


	Fair Value			Unobservable Input	Amount or Range (Weighted Average)
	(in millions)
Interest rate	$	(124	)	Own credit risk		3.3% - 4.1% (3.5%)
Foreign currency:
Embedded derivative — Argentine Peso		48		Argentine Peso to U.S. Dollar currency exchange rate after 2 years		6.13
Other		-
Commodity & other:
Embedded derivative — Aluminum		(54	)	Market price of power for customer in Cameroon (per KWh)		$0.06 - $0.18 ($0.13)
Embedded derivative — Philippine Peso		10		U.S. Producer Price Index after 5 years (where base year of 2005 = 100)		143 - 174 (157)
Other		(2	)

Total	$	(122	)

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

The only Level 1 derivative instruments as of March 31, 2012 are exchange-traded commodity futures for which the pricing is observable in active markets, and as such, these are not expected to transfer to other levels. There have been no transfers between Level 1 and Level 2.

Nonfinancial Assets and Liabilities

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

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

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

Fair Value Considerations

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

Sources of market assumptions

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

Market liquidity

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

Nonperformance risk

Nonperformance risk refers to the risk that an obligation will not be fulfilled and affects the value at which a liability is transferred or an asset is sold. Nonperformance risk includes, but may not be limited to, the Company

or its counterparty’s credit and settlement risk. Nonperformance risk adjustments are dependent on credit spreads, letters of credit, collateral, other arrangements available and the nature of master netting arrangements. The Company and its subsidiaries are parties to various interest rate swaps and options; foreign currency options and forwards; and derivatives and embedded derivatives, which subject the Company to nonperformance risk. The financial and physical instruments held at the subsidiary level are generally non-recourse to the Parent Company.

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

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

Recurring Measurements

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


	Fair Value
	Total		Level 1		Level 2		Level 3
	(in millions)
March 31, 2012
Assets
Available-for-sale securities	$	1,717	$	2	$	1,715	$	-
Trading securities		12		12		-		-
Derivatives		109		2		41		66

Total assets	$	1,838	$	16	$	1,756	$	66

Liabilities
Derivatives	$	648	$	-	$	460	$	188

Total liabilities	$	648	$	-	$	460	$	188


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

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

Liabilities
Derivatives	$	690	$	-	$	476	$	214

Total liabilities	$	690	$	-	$	476	$	214

The following tables present a reconciliation of net derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three months ended March 31, 2012 and 2011 (presented net by type of derivative):


	Three Months Ended March 31, 2012
	Interest Rate			Cross Currency			Foreign Currency			Commodity and Other			Total
	(in millions)
Balance at January 1	$	(128	)	$	(18	)	$	51		$	(53	)	$	(148	)
Total gains (losses) (realized and unrealized):
Included in earnings⁽¹⁾		(1	)		-			(2	)		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⁽²⁾		(28	)		-			-			-			(28	)
Transfers of (assets) liabilities out of Level 3⁽²⁾		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


	Three Months Ended March 31, 2011
	Interest Rate			Cross Currency			Foreign Currency			Commodity and Other			Total
	(in millions)
Balance at January 1	$	(1	)	$	10		$	22		$	18		$	49
Total gains (losses) (realized and unrealized):
Included in earnings⁽¹⁾		-			2			1			8			11
Included in other comprehensive income		(4	)		(8	)		-			-			(12	)
Included in regulatory (assets) liabilities		-			-			-			(1	)		(1	)
Settlements		-			1			1			-			2
Transfers of assets (liabilities) into Level 3⁽²⁾		(2	)		-			(1	)		(1	)		(4	)

Balance at March 31	$	(7	)	$	5		$	23		$	24		$	45

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		$	-		$	8		$	10

⁽¹⁾

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

⁽²⁾

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

The following table presents a reconciliation of available-for-sale securities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
	2012		2011
	(in millions)
Balance at beginning of period	$	-	$	42
Settlements		-		(2	)

Balance at March 31	$	-	$	40

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

Nonrecurring Measurements

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


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

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

⁽²⁾	See Note 14 — Other Non-Operating Expense for further information.

There were no nonrecurring measurements in the three months ended March 31, 2011.

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

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


	Carrying Amount		Fair Value
	Carrying Amount		Total		Level 1		Level 2		Level 3
March 31, 2012	(in millions)
Assets
Trade receivables	$	408	$	454	$	-	$	-	$	454

Liabilities
Non-recourse debt		16,035		16,369		-		15,339		1,030
Recourse debt		6,200		6,809		-		6,809

December 31, 2011
Assets
Trade receivables	$	386	$	401

Liabilities
Non-recourse debt		15,535		15,862
Recourse debt		6,485		6,640

4. INVESTMENTS IN MARKETABLE SECURITIES

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


	March 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)
AVAILABLE-FOR-SALE:⁽¹⁾
Debt securities:
Unsecured debentures⁽²⁾	$	-	$	975	$	-	$	975	$	-	$	665	$	-	$	665
Certificates of deposit⁽²⁾		-		645		-		645		-		576		-		576
Government debt securities		-		28		-		28		-		31		-		31

Subtotal		-		1,648		-		1,648		-		1,272		-		1,272
Equity securities:
Mutual funds		1		67		-		68		-		67		-		67
Common stock		1		-		-		1		1		-		-		1

Subtotal		2		67		-		69		1		67		-		68

Total available-for-sale		2		1,715		-		1,717		1		1,339		-	$	1,340

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

Total trading		12		-		-		12		12		-		-		12

TOTAL	$	14	$	1,715	$	-	$	1,729	$	13	$	1,339	$	-	$	1,352

Held-to-maturity securities								11								4

Total marketable securities							$	1,740							$	1,356

⁽¹⁾

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

⁽²⁾

Unsecured debentures are instruments similar to certificates of deposit that are held primarily by our subsidiaries in Brazil. The unsecured debentures and certificates of deposit included here do not qualify as cash equivalents and meet the definition of a security under the relevant guidance and are therefore classified as available-for-sale securities.

As of March 31, 2012, all available-for-sale debt securities had stated maturities within one year.

The following table summarizes the pre-tax gains and losses related to available-for-sale and trading securities for the three months ended March 31, 2012 and 2011. Gains and losses on the sale of investments are determined using the specific identification method. For the three months ended March 31, 2012 and 2011, there were no realized losses on the sale of available-for-sale securities and no other-than-temporary impairment of marketable securities recognized in earnings or other comprehensive income.


	Three Months Ended March 31,
	2012		2011
	(in millions)
Gains included in earnings that relate to trading securities held at the reporting date	$	-	$	1
Unrealized gains (losses) on available-for-sale securities included in other comprehensive income		-		(2	)
Proceeds from sales of available-for-sale securities		1,523		1,237
Gross realized gains on sales		1		1

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Risk Management Objectives

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

Interest Rate Risk

AES and its subsidiaries utilize variable rate debt financing for construction projects and operations, resulting in an exposure to interest rate risk. Interest rate swap, cap and floor agreements are entered into to manage interest rate risk by effectively fixing or limiting the interest rate exposure on the underlying financing. These interest rate contracts range in maturity through 2030, and are typically designated as cash flow hedges. The following table sets forth, by underlying type of interest rate index, the Company’s current and maximum outstanding notional under its interest rate derivative instruments, the weighted average remaining term and the percentage of variable-rate debt hedged that is based on the related index as of March 31, 2012 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:


	March 31, 2012
	Current				Maximum⁽¹⁾
Interest Rate Derivatives	Derivative Notional		Derivative Notional Translated to USD		Derivative Notional		Derivative Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾		% of Debt Currently Hedged by Index⁽²⁾
	(in millions)								(in years)
Libor (U.S. Dollar)		3,657	$	3,657		4,668	$	4,668		10		71	%
Euribor (Euro)		668		891		668		891		10		65	%
Libor (British Pound Sterling)		67		107		83		132		13		92	%

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

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

Cross currency swaps are utilized in certain instances to manage the risk related to fluctuations in both interest rates and certain foreign currencies. These cross currency contracts range in maturity through 2028. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notional amount under its cross currency derivative instruments as of March 31, 2012, which are all in qualifying cash flow hedge relationships. These swaps are amortizing and therefore the notional amount represents the maximum outstanding notional amount as of March 31, 2012:


	March 31, 2012
Cross Currency Swaps	Notional		Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾		% of Debt Currently Hedged by Index⁽²⁾
	(in millions)				(in years)
Chilean Unidad de Fomento (CLF)		6	$	253		14		85	%

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

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

Foreign Currency Risk

We are exposed to foreign currency risk as a result of our investments in foreign subsidiaries and affiliates. AES operates businesses in many foreign countries and such operations may be impacted by significant fluctuations in foreign currency exchange rates. Foreign currency options and forwards are utilized, where deemed appropriate, to manage the risk related to fluctuations in certain foreign currencies. These foreign currency contracts range in maturity through 2015. The following tables set forth, by type of foreign currency denomination, the Company’s outstanding notional amounts over the remaining terms of its foreign currency derivative instruments as of March 31, 2012 regardless of whether the derivative instruments are in qualifying hedging relationships:


	March 31, 2012
Foreign Currency Options	Notional		Notional Translated to USD⁽¹⁾		Probability Adjusted Notional⁽²⁾		Weighted Average Remaining Term⁽³⁾
	(in millions)						(in years)
Euro (EUR)		62	$	83	$	44		<1
Brazilian Real (BRL)		110		63		53		<1
Philippine Peso (PHP)		1,285		30		18		<1
Argentine Peso (ARS)		18		4		-		<1
British Pound (GBP)		1		2		2		<1

⁽¹⁾	Represents contractual notionals at inception of trade.

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

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


	March 31, 2012
Foreign Currency Forwards	Notional		Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾
	(in millions)				(in years)
Chilean Peso (CLP)		84,974	$	169		<1
Euro (EUR)		95		133		2
Colombian Peso (COP)		137,722		77		<1
British Pound (GBP)		18		29		<1
Argentine Peso (ARS)		31		7		<1
Hungarian Forint (HUF)		402		1		<1

⁽¹⁾

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

In addition, certain of our subsidiaries have entered into contracts which contain embedded derivatives that require separate valuation and accounting due to the fact that the item that is being purchased or sold is denominated in a currency other than the functional currency of the subsidiary or the currency of the item. These contracts range in maturity through 2026. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notional over the remaining terms of its foreign currency embedded derivative instruments as of March 31, 2012:


	March 31, 2012
Embedded Foreign Currency Derivatives	Notional		Notional Translated to USD		Weighted Average Remaining Term⁽¹⁾
	(in millions)				(in years)
Philippine Peso (PHP)⁽²⁾		53,591	$	1,247		11
Argentine Peso (ARS)		943		215		11
Kazakhstani Tenge (KZT)		29,023		196		9
Euro (EUR)		2		3		9

⁽¹⁾

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

⁽²⁾

Notional also relates to an embedded derivative related to inflation.

Commodity Price Risk

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

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

Nonetheless, certain of the PPAs and fuel supply agreements entered into by certain of the Company’s subsidiaries are derivatives or contain embedded derivatives requiring separate valuation and accounting. These contracts range in maturity through 2024. The following table sets forth, by type of commodity, the Company’s outstanding notionals for the remaining term of its commodity derivatives and embedded derivative instruments as of March 31, 2012:


	March 31, 2012
Commodity Derivatives	Notional			Weighted Average Remaining Term⁽¹⁾
	(in millions)			(in years)
Natural gas (MMBTU)		31			11
Aluminum (MWh)		15	⁽²⁾		8
Petcoke (Metric tons)		12			12
Coal (Metric tons)		3			1
Heating Oil (Gallons)		2			<1

⁽¹⁾

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

⁽²⁾	The embedded derivative relates to fluctuations in the price of aluminum versus fluctuations in the price of electricity, where the notional is based on the amount of power we sell under the PPA.

Accounting and Reporting

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


	March 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in millions)								(in millions)
Assets
Current assets:
Foreign currency derivatives	$	-	$	11	$	4	$	15	$	-	$	24	$	4	$	28
Commodity and other derivatives		2		16		2		20		2		16		3		21

Total current assets		2		27		6		35		2		40		7		49

Noncurrent assets:
Cross currency derivatives		-		5		-		5		-		-		1		1
Foreign currency derivatives		-		4		51		55		-		3		58		61
Commodity and other derivatives		-		5		9		14		-		9		-		9

Total noncurrent assets		-		14		60		74		-		12		59		71

Total assets	$	2	$	41	$	66	$	109	$	2	$	52	$	66	$	120

Liabilities
Current liabilities:
Interest rate derivatives	$	-	$	96	$	17	$	113	$	-	$	97	$	22	$	119
Cross currency derivatives		-		4		-		4		-		-		5		5
Foreign currency derivatives		-		8		1		9		-		5		1		6
Commodity and other derivatives		-		27		4		31		-		17		6		23

Total current liabilities		-		135		22		157		-		119		34		153

Noncurrent liabilities:
Interest rate derivatives		-		284		107		391		-		334		106		440
Cross currency derivatives		-		1		-		1		-		-		14		14
Foreign currency derivatives		-		27		7		34		-		10		10		20
Commodity and other derivatives		-		13		52		65		-		13		50		63

Total noncurrent liabilities		-		325		166		491		-		357		180		537

Total liabilities	$	-	$	460	$	188	$	648	$	-	$	476	$	214	$	690

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


	March 31, 2012						December 31, 2011
	Designated as Hedging Instruments		Not Designated as Hedging Instruments		Total		Designated as Hedging Instruments		Not Designated as Hedging Instruments		Total
	(in millions)						(in millions)
Assets
Current assets:
Foreign currency derivatives	$	5	$	10	$	15	$	10	$	18	$	28
Commodity and other derivatives		1		19		20		2		19		21

Total current assets		6		29		35		12		37		49

Noncurrent assets:
Cross currency derivatives		5		-		5		1		-		1
Foreign currency derivatives		4		51		55		3		58		61
Commodity and other derivatives		-		14		14		-		9		9

Total noncurrent assets		9		65		74		4		67		71

Total assets	$	15	$	94	$	109	$	16	$	104	$	120

Liabilities
Current liabilities:
Interest rate derivatives	$	105	$	8	$	113	$	110	$	9	$	119
Cross currency derivatives		4		-		4		5		-		5
Foreign currency derivatives		5		4		9		1		5		6
Commodity and other derivatives		1		30		31		-		23		23

Total current liabilities		115		42		157		116		37		153

Noncurrent liabilities:
Interest rate derivatives		376		15		391		425		15		440
Cross currency derivatives		1		-		1		14		-		14
Foreign currency derivatives		-		34		34		-		20		20
Commodity and other derivatives		5		60		65		3		60		63

Total noncurrent liabilities		382		109		491		442		95		537

Total liabilities	$	497	$	151	$	648	$	558	$	132	$	690

The Company has elected not to offset derivative positions in the financial statements. Accordingly, the Company does not offset such derivative positions against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements. At March 31, 2012 and December 31, 2011, we held $2 million and $3 million, respectively, of cash collateral that we received from counterparties to our derivative positions. Beyond the cash collateral held by us, our derivative assets are exposed to the credit risk of the respective counterparty and, due to this credit risk, the fair value of our derivative assets (as shown in the above two tables) have been reduced by a credit valuation adjustment. Also, at March 31, 2012 and December 31, 2011, there was $26 million and $16 million, respectively, of cash collateral posted with (held by) counterparties to our derivative positions.

The table below sets forth the pre-tax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes (in millions) over the next twelve months as of March 31, 2012 for the following types of derivative instruments:


Interest rate derivatives	$	(99	)
Cross currency derivatives	$	9
Foreign currency derivatives	$	(2	)
Commodity and other derivatives	$	(1	)

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

The following tables set forth the gains (losses) recognized in accumulated other comprehensive loss (“AOCL”) and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the three months ended March 31, 2012 and 2011:


	Gains (Losses) Recognized in AOCL						Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Reclassified from AOCL into Earnings
	2012			2011				2012			2011
	(in millions)							(in millions)
Interest rate derivatives	$	11		$	52		Interest expense	$	(32	)⁽¹⁾	$	(26	)⁽¹⁾
							Non-regulated cost of sales		(2	)⁽¹⁾		(1	)⁽¹⁾
							Net equity in earnings of affiliates		(1	)		(1	)
							Gain on sale of investments		(92	)		-
Cross currency derivatives		14			(8	)	Interest expense		(3	)		(5	)
							Foreign currency transaction gains (losses)		18			(5	)
Foreign currency derivatives		6			5		Foreign currency transaction gains (losses)		-			(2	)
Commodity and other derivatives		(6	)		1		Non-regulated revenue		(2	)		-

Total	$	25		$	50			$	(114	)	$	(40	)

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

The following table sets forth the pre-tax gains (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the three months ended March 31, 2012 and 2011:


	Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Recognized in Earnings
		2012			2011
		(in millions)
Interest rate derivatives	Interest expense	$	(1	)	$	(7	)
	Net equity in earnings of affiliates		-	⁽¹⁾		-	⁽¹⁾
Cross currency derivatives	Interest expense		-	⁽¹⁾		-	⁽¹⁾
Foreign currency derivatives	Foreign currency transaction gains (losses)		-	⁽¹⁾		-	⁽¹⁾

Total		$	(1	)	$	(7	)

⁽¹⁾	De minimis amount.

The following table sets forth the gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging, for the three months ended March 31, 2012 and 2011:


	Classification in Condensed Consolidated Statements of Operations	Gains (Losses) Recognized in Earnings
		2012			2011
		(in millions)
Interest rate derivatives	Interest expense	$	(2	)	$	-
Foreign exchange derivatives	Foreign currency transaction gains		(38	)		7
Commodity and other derivatives	Non-regulated revenue		14			4
	Regulated revenue		(4	)		-
	Non-regulated cost of sales		3			1
	Regulated cost of sales		(4	)		-

Total		$	(31	)	$	12

In addition, DPL and IPL have derivative instruments for which the gains and losses are accounted for in accordance with accounting standards for regulated operations, as regulatory assets or liabilities. Gains and losses due to changes in the fair value of these derivatives are probable of recovery through future rates and are initially recognized as an adjustment to the regulatory asset or liability and recognized through earnings when the related costs are recovered through rates. Therefore, these gains and losses are excluded from the above table. The following table sets forth the change in regulatory assets and liabilities resulting from the change in the fair value of these derivatives for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
	2012		2011
	(in millions)
(Increase) decrease in regulatory assets	$	3	$	-
Increase (decrease) in regulatory liabilities	$	-	$	(1	)

Credit Risk-Related Contingent Features

Gener, our generation business in Chile, has cross currency swap agreements with counterparties to swap Chilean inflation indexed bonds issued in December 2007 into U.S. Dollars. The derivative agreements contain credit contingent provisions which would permit the counterparties with which Gener is in a net liability position to require collateral credit support when the fair value of the derivatives exceeds the unsecured thresholds established in the agreements. These thresholds vary based on Gener’s credit rating. If Gener’s credit rating were to fall below the minimum threshold established in the swap agreements, the counterparties can demand immediate collateralization of the entire mark-to-market loss of the swaps (excluding credit valuation adjustments), which was $5 million at March 31, 2012. The mark-to-market value of the swaps was $18 million at December 31, 2011. As of March 31, 2012 and December 31, 2011, Gener had not posted collateral to support these swaps.

DPL, our utility in Ohio, has certain over-the-counter commodity derivative contracts under master netting agreements that contain provisions that require its debt to maintain an investment-grade credit rating from credit rating agencies. If its debt were to fall below investment grade, the business would be in violation of these provisions, and the counterparties to the derivative contracts could request immediate payment or demand immediate and ongoing full overnight collateralization of the mark-to-market loss (excluding credit valuation adjustments), which was $38 million as of March 31, 2012. As of March 31, 2012, DPL had posted $26 million of cash collateral directly with third parties and in a broker margin account and held $2 million of cash collateral that it received from counterparties to its derivative instruments that were in an asset position. As of December 31, 2011, DPL had posted $16 million of cash collateral directly with third parties and in a broker margin account and held $3 million of cash collateral that it received from counterparties to its derivative instruments that were in an asset position.

6. FINANCING RECEIVABLES

Accounts and notes receivable are carried at amortized cost. The Company periodically assesses the collectability of accounts receivable by considering factors such as specific evaluation of collectability, historical collection experience, age and other available evidence of the collectability, and records an allowance for doubtful accounts for the estimated uncollectable amount as appropriate. Certain of our businesses charge interest on accounts receivable under contractual terms or where charging interest is a customary business practice. In such cases, interest income is recognized on an accrual basis. In situations where the collection of interest is uncertain, interest income is recognized as cash is received. Individual accounts and notes receivable are written off when they are no longer deemed collectable.

Included in “Noncurrent other assets” on the condensed consolidated balance sheets as of March 31, 2012 and December 31, 2011 are long-term financing receivables of $288 million and $295 million, respectively, primarily with certain Latin American governmental bodies. These receivables have contractual maturities of greater than one year and are being actively collected. Of the total $288 million as of March 31, 2012, $228 million and $47 million relate to our businesses in Argentina and the Dominican Republic, respectively. The remaining amounts relate to our distribution businesses in Brazil.

7. DEBT

The Company has two types of debt reported on its condensed consolidated balance sheets: non-recourse and recourse debt. Non-recourse debt is used to fund investments and capital expenditures for the construction and acquisition of electric power plants, wind projects, distribution companies and other project-related investments at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. Absent guarantees, intercompany loans or other credit support, the default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries, though the Company’s equity investments and/or subordinated loans to projects (if any) are at risk. Recourse debt is direct borrowings by the Parent Company and is used to fund development, construction or acquisitions, including serving as funding for equity investments or loans to the affiliates. The Parent Company’s debt is, among other things, recourse to the Parent Company and is structurally subordinated to the affiliates’ debt.

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

The fair value was determined using available market information as of March 31, 2012. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to March 31, 2012.

Non-Recourse Debt

The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of March 31, 2012 and is in the current portion of non-recourse debt unless otherwise indicated:


Subsidiary	Primary Nature of Default	March 31, 2012
Subsidiary	Primary Nature of Default	Default Amount		Net Assets
		(in millions)
Maritza	Covenant	$	907	$	228
Sonel	Covenant		318		318
Kelanitissa	Covenant		16		50
Saurashtra	Covenant		28		16

Total		$	1,269

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’ corporate debt agreements as of March 31, 2012 in order to trigger an event of default or permit acceleration under such indebtedness. The bankruptcy or acceleration of material amounts of debt at such subsidiaries would cause a cross default under the recourse senior secured credit facility. It is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position or results of operations of an individual subsidiary, and thereby a bankruptcy or an acceleration of its non-recourse debt could trigger an event of default and possible acceleration of the indebtedness under the AES Parent Company’s outstanding debt securities.

8. CONTINGENCIES AND COMMITMENTS

Guarantees, Letters of Credit and Commitments

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

The following table summarizes the Parent Company’s contingent contractual obligations as of March 31, 2012. Amounts presented in the table below represent the Parent Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of businesses of $25 million.


Contingent contractual obligations	Amount		Number of Agreements		Maximum Exposure Range for Each Agreement
	(in millions)				(in millions)
Guarantees	$	352		21	<$1 - $53
Letters of credit under the senior secured credit facility		12		11	<$1 - $7
Cash collateralized letters of credit		254		13	<$1 - $215

Total	$	618		45

As of March 31, 2012, the Company had $9 million of commitments to invest in subsidiaries under construction and to purchase related equipment that were not included in the letters of credit discussed above. The Company expects to fund these net investment commitments in 2012. The exact payment schedules will be dictated by the construction milestones.

Environmental

The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of March 31, 2012, the Company had recorded liabilities of $25 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, 2012.

Litigation

The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and accordingly, has recorded aggregate reserves for all claims of approximately $380 million and $363 million as of March 31, 2012 and December 31, 2011, respectively. These reserves are reported on the consolidated balance sheets within “accrued and other liabilities” and “other noncurrent liabilities.” A significant portion of the reserves relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company’s subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that these reserves will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

The Company believes, based upon information it currently possesses and taking into account established reserves for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company’s consolidated financial statements. However, where no reserve has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of March 31, 2012. The material contingencies where a loss is reasonably possible primarily include: claims under financing agreements; disputes with offtakers, suppliers and EPC contractors; alleged violation of monopoly laws and regulations; income tax and non-income tax assessments by tax authorities; and environmental and regulatory matters. In aggregate, the Company estimates that the range of potential losses, where estimable, related to these material contingences to be in the range of $364 million to $1.7 billion. The amounts considered reasonably possible do not include amounts reserved, as discussed above. These material contingencies do not include income tax related contingencies which are considered part of our uncertain tax positions.

9. PENSION PLANS

Total pension cost for the three months ended March 31, 2012 and 2011 included the following components:


	2012						2011
	U.S.			Foreign			U.S.			Foreign
	(in millions)
Service cost	$	4		$	7		$	2		$	5
Interest cost		12			141			8			142
Expected return on plan assets		(14	)		(122	)		(8	)		(128	)
Amortization of prior service cost		1			-			1			-
Amortization of net loss		6			10			3			6
Loss on curtailment		-			-			-			4

Total pension cost	$	9		$	36		$	6		$	29

Total employer contributions for the three months ended March 31, 2012 for the Company’s U.S. and foreign subsidiaries were $7 million and $41 million, respectively. The expected remaining scheduled employer contributions for 2012 are $41 million for U.S. subsidiaries and $139 million for foreign subsidiaries.

10. EQUITY

Changes in Equity

The following table provides a reconciliation of the beginning and ending carrying amounts of equity attributable to stockholders of The AES Corporation, noncontrolling interests and total equity as of March 31, 2012 and 2011:


	Three Months Ended March 31, 2012
	The AES Corporation Stockholders’ Equity		Noncontrolling Interest			Total Equity
	(in millions)
Balance at January 1, 2012	$	5,946	$	3,783		$	9,729
Net income		341		174			515
Foreign currency translation adjustment, net of income tax		92		49			141
Actuarial gains and losses and amortization of prior service costs, net of income tax		1		5			6
Change in derivative fair value, net of income tax		90		17			107
Capital contributions from noncontrolling interests		-		6			6
Distributions to noncontrolling interests		-		(14	)		(14	)
Disposition of businesses		-		(37	)		(37	)
Issuance and exercise of stock-based compensation benefit plans, net of income tax		19		-			19
Acquisition of subsidiary shares from noncontrolling interests		-		(1	)		(1	)

Balance at March 31, 2012	$	6,489	$	3,982		$	10,471


	Three Months Ended March 31, 2011
	The AES Corporation Stockholders’ Equity			Noncontrolling Interest			Total Equity
	(in millions)
Balance at January 1, 2011	$	6,473		$	3,940		$	10,413
Net income		224			259			483
Change in fair value of available-for-sale securities, net of income tax		(1	)		-			(1	)
Foreign currency translation adjustment, net of income tax		74			54			128
Actuarial gains and losses and amortization of prior service costs, net of income tax		1			2			3
Change in derivative fair value, net of income tax		61			10			71
Capital contributions from noncontrolling interests		-			1			1
Distributions to noncontrolling interests		-			(16	)		(16	)
Acquisition of treasury stock		(63	)		-			(63	)
Issuance and exercise of stock-based compensation benefit plans, net of income tax		23			-			23

Balance at March 31, 2011	$	6,792		$	4,250		$	11,042

Accumulated Other Comprehensive Loss

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


	March 31, 2012		December 31, 2011
	(in millions)
Foreign currency translation adjustment	$	1,875	$	1,967
Unrealized derivative losses, net		444		534
Unfunded pension obligation		256		257

Accumulated other comprehensive loss	$	2,575	$	2,758

11. SEGMENTS

During the first quarter of 2012, the Company completed its operational management and reporting restructuring. The management reporting structure is organized along two lines of business – Generation and Utilities, each led by a Chief Operating Officer. The segment reporting structure primarily uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally with further aggregation by geographic regions to provide better socio-political-economic understanding of our business. For the three months ended March 31, 2012, the Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria. The Company concluded that Tietê, our 2,663 MW hydro generation business in Brazil, met the quantitative thresholds to require separate presentation. As such, an additional reportable segment which consists solely of the results of Tietê is now reported as Generation — Tietê. Tietê was formerly reported within the Latin America — Generation segment. The previously disclosed Latin America — Generation segment is now reported as Generation — Latin America — Other and, with the exception of Tietê, includes the results of all remaining businesses as previously reported. All prior period results have been retrospectively revised to reflect the new segment reporting structure. The Company has increased from six to the following seven reportable segments:

•

Generation — Latin America — Other;

•

Generation — Tietê;

•

Generation — North America;

•

Generation — Europe;

•

Generation — Asia;

•

Utilities — Latin America;

•

Utilities — North America.

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

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

Total revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No material inter-segment revenue relationships exist between other segments. Corporate allocations include certain self-insurance activities which are reflected within segment adjusted gross margin. All intra-segment activity has been eliminated with respect to revenue and adjusted gross margin within the segment. Inter-segment activity has been eliminated within the total consolidated results. Asset information for businesses that were discontinued or classified as held for sale as of March 31, 2012 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.

Information about the Company’s operations by segment for the three months ended March 31, 2012 and 2011 was as follows:


Three months ended March 31,	Total Revenue				Intersegment						External Revenue
Three months ended March 31,	2012		2011		2012			2011			2012		2011
	(in millions)
Generation — Latin America — Other	$	959	$	878	$	(10	)	$	(9	)	$	949	$	869
Generation — Tietê		305		253		(282	)		(242	)		23		11
Generation — North America		317		334		-			-			317		334
Generation — Europe		450		400		-			(1	)		450		399
Generation — Asia		181		115		-			-			181		115
Utilities — Latin America		1,734		1,840		-			-			1,734		1,840
Utilities — North America		732		289		-			-			732		289
Corp and Other		347		293		7			6			354		299

Total Revenue	$	5,025	$	4,402	$	(285	)	$	(246	)	$	4,740	$	4,156


Three months ended March 31,	Total Adjusted Gross Margin				Intersegment						External Adjusted Gross Margin
Three months ended March 31,	2012		2011		2012			2011			2012			2011
	(in millions)
Generation — Latin America — Other	$	287	$	268	$	4		$	3		$	291		$	271
Generation — Tietê		239		202		(282	)		(242	)		(43	)		(40	)
Generation — North America		106		106		2			4			108			110
Generation — Europe		237		106		(7	)		1			230			107
Generation — Asia		58		45		-			1			58			46
Utilities — Latin America		167		320		285			245			452			565
Utilities — North America		213		90		-			-			213			90
Corp and Other & eliminations		35		42		(2	)		(12	)		33			30
Reconciliation to Income from Continuing Operations before Taxes
Depreciation and amortization												(351	)		(281	)
Interest expense												(416	)		(338	)
Interest income												91			95
Other expense												(29	)		(15	)
Other income												18			16
Gain on sale of investments												179			6
Asset impairment expense												(11	)		-
Foreign currency transaction gains (losses)												(1	)		33
Other non-operating expense												(49	)		-

Income from continuing operations before taxes and equity in earnings of affiliates											$	773		$	695

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


	Total Assets
	March 31, 2012		December 31, 2011
	(in millions)
Assets
Generation — Latin America — Other	$	9,271	$	9,067
Generation — Tietê		1,670		1,645
Generation — North America		3,627		3,625
Generation — Europe		3,456		3,276
Generation — Asia		1,769		1,717
Utilities — Latin America		9,987		9,468
Utilities — North America		9,338		9,384
Discontinued businesses		719		1,531
Corp and Other & eliminations		5,594		5,620

Total Assets	$	45,431	$	45,333

12. OTHER INCOME (EXPENSE)

Other income was $18 million and $16 million for the three months ended March 31, 2012 and 2011 respectively, and generally includes gains on asset sales and extinguishments of liabilities, favorable judgments on contingencies and income from miscellaneous transactions.

The components of other expense for the three months ended March 31, 2012 and 2011 were as follows:


	Three Months Ended March 31,
	2012		2011
	(in millions)
Loss on sale and disposal of assets	$	24	$	10
Other		5		5

Total other expense	$	29	$	15

Other expense for the three months ended March 31, 2012 and 2011 of $29 million and $15 million, respectively, was primarily comprised of losses on the disposal of assets at Eletropaulo. Other expense generally includes losses on asset sales, losses on the extinguishment of debt, contingencies and losses from miscellaneous transactions.

13. ASSET IMPAIRMENT EXPENSE

Asset impairment expense was $11 million for the three months ended March 31, 2012.

We continue to evaluate the recoverability of our long-lived assets at Kelanitissa, our diesel-fired generation plant in Sri Lanka, as a result of both the requirement to transfer the plant to the government at end of our PPA and the current expectation of lower future operating cash flows. During the current quarter, the Company recognized asset impairment expense of $5 million for the long-lived assets of Kelanitissa. Our evaluation during the quarter indicated that the long-lived assets were no longer recoverable and accordingly they were written down to their estimated fair value of $17 million based on a discounted cash flow analysis. The long-lived assets had a carrying amount of $22 million prior to the recognition of asset impairment expense. Kelanitissa is reported in the Asia Generation reportable segment.

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

14. OTHER NON-OPERATING EXPENSE

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)
InnoVent	$	17
China generation		31
Other		1

Total Other-non operating expense	$	49

InnoVent — During the quarter, 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.

China — During the quarter, 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.

There was no other non-operating expense for the three months ended March 31, 2011.

15. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

In addition to the businesses reported as discontinued operations in the 2011 Form 10-K, discontinued operations include the results of the following businesses classified as held for sale in March 2012:

•

Red Oak, an 832 MW gas-fired generation plant in New Jersey; and

•

Ironwood, a 710 MW gas-fired generation plant in Pennsylvania.

The following table summarizes the revenue, income from operations, income tax expense, impairment and gain on sale of all discontinued operations for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
	2012			2011
	(in millions)
Revenue	$	37		$	197

Income (loss) from operations of discontinued businesses	$	3		$	(10	)
Income tax (expense) benefit		(2	)		3

Income (loss) from operations of discontinued businesses, net of tax	$	1		$	(7	)

Net gain/(loss) on sale and impairments of discontinued operations, net of tax	$	(5	)	$	-

Red Oak — In February 2012, a subsidiary of the Company signed a sale agreement with a newly-formed portfolio company of Energy Capital Partners II, LP for the sale of 100% of its membership interest in AES Red Oak, LLC and AES Sayreville, two wholly-owned subsidiaries, that hold the Company’s interest in Red Oak for $147 million, subject to customary purchase price adjustments. The transaction closed on April 12, 2012 and the Company expects to recognize a pretax gain in the range of $60 million to $70 million in the second quarter of 2012. Red Oak was reported in the North America Generation segment.

Ironwood — In February 2012, a subsidiary of the Company signed a sale agreement with an indirect wholly-owned subsidiary of PPL Corporation for the sale of 100% of its equity interest in AES Ironwood, Inc., a wholly-owned subsidiary, that holds the Company’s interest in Ironwood for $87 million, subject to customary purchase price adjustments. The transaction closed on April 13, 2012 and the Company expects to recognize a pretax gain in the range of $65 million to $75 million in the second quarter of 2012. Ironwood was reported in the North America Generation segment.

16. ACQUISITIONS AND DISPOSITIONS

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

The assets acquired and liabilities assumed in the acquisition have been recorded at provisional amounts based on the preliminary purchase price allocation. The Company is in the process of obtaining additional

information to identify and measure all assets acquired and liabilities assumed in the acquisition within the measurement period, which could be up to one year from the date of acquisition. Such provisional amounts will be retrospectively adjusted to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. Additionally, key input assumptions and their sensitivity to the valuation of assets acquired and liabilities assumed are currently being reviewed by management. It is likely that the value of the generation business related property, plant and equipment, the intangible asset related to the Electric Security Plan with its regulated customers and long-term coal contracts, the 4.9% equity ownership interest in the Ohio Valley Electric Corporation, and deferred taxes could change as the valuation process is finalized. DPL Energy Resource, Inc. (i.e., DPL’s wholly-owned Competitive Retail Electric Service (“CRES”) provider) will also likely have changes in its initial purchase price allocation for the valuation of its intangible assets for the trade name, and customer relationships and contracts.

The unaudited actual DPL revenue and net income attributable to The AES Corporation included in AES’s Condensed Consolidated Statement of Operations for the three months ended March 31, 2012, and the unaudited pro forma revenue and net income attributable to The AES Corporation, of the combined entity for the three months ended March 31, 2012 and 2011, as if the acquisition had occurred January 1, 2011, are as follows:


	Revenue		Net Income (Loss) Attributable to The AES Corporation
	(in millions)
Actual for the three months ended March 31, 2012	$	431	$	22
Pro forma for the three months ended March 31, 2012		4,740		351
Pro forma for the three months ended March 31, 2011		4,623		220

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

Net income attributable to The AES Corporation in the table above has been increased by pro forma adjustments of $10 million, net of tax, for the three months ended March 31, 2012 and reduced by $48 million, net of tax, for the three months ended March 31, 2011. These pro forma adjustments primarily include: the amortization of fair value adjustment of DPL’s generation plant and equipment and intangible assets subject to amortization and interest expense on additional borrowings used to finance the acquisition.

Dispositions

Cartagena — On February 9, 2012, a subsidiary of the Company completed the sale of 80% of its interest in the wholly-owned holding company of AES Energia Cartagena S.R.L. (“AES Cartagena”), a 1,199 MW gas-fired generation business in Spain. The Company owned approximately 70.81% of AES Cartagena through this holding company structure, as well as 100% of a related operations and maintenance company. Net proceeds from the sale were approximately €172 million ($229 million) and during the three months ended March 31, 2012, the Company recognized a pretax gain of $178 million on the transaction. Under the terms of the sale agreement, the buyer, Electrabel International Holdings B.V. (“Electrabel”), a subsidiary of GDF SUEZ S.A. or “GDFS”, has an option to purchase the Company’s remaining 20% interest at a fixed price of €28 million ($37 million) during a five month period beginning March 2013. Of the total proceeds received, approximately $9 million was deferred and allocated to Electrabel’s option to purchase the Company’s remaining interest. Concurrent with the sale, GDFS settled the outstanding arbitration between the parties regarding certain emissions costs and other taxes that AES Cartagena sought to recover from GDFS as energy manager under the existing commercial arrangements. GDFS agreed to pay €71 million ($95 million) to AES Cartagena for such costs incurred by AES Cartagena for the 2008 — 2010 period and for 2011 through the date of sale close, of which €28 million ($38 million) was paid at closing. Due to the Company’s expected continuing ownership interest extending beyond one year from the completion of the sale of its 80% interest, prior period operating results of AES Cartagena have not been reclassified as discontinued operations.

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, 2012 and 2011. In the table below, income represents the numerator and weighted-average shares represent the denominator:


	2012							2011
	Income		Shares		$ per Share			Income		Shares		$ per Share
	(in millions except per share data)
BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders	$	345		766	$	0.45		$	237		787	$	0.30
EFFECT OF DILUTIVE SECURITIES
Convertible securities		6		15		-			-		-		-
Stock options		-		1		-			-		2		-
Restricted stock units		-		3		(0.01	)		-		3		-

DILUTED EARNINGS PER SHARE	$	351		785	$	0.44		$	237		792	$	0.30

The calculation of diluted earnings per share excluded 6,599,286 and 16,253,344 options outstanding at March 31, 2012, and 2011, respectively, that could potentially dilute basic earnings per share in the future. Those options were not included in the computation of diluted earnings per share because the exercise price of those options exceeded the average market price during the related period. For the three months ended March 31, 2012, all convertible debentures were included in the earnings per share calculation. For the three months ended March 31 2011, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. In arriving at income attributable to AES Corporation common stockholders in computing basic earnings per share, dividends on preferred stock of our subsidiaries were deducted.

18. REGULATORY LIABILITIES

In July 2011, the Brazilian energy regulator (the “Regulator”) postponed the periodic review and reset of a component of Eletropaulo’s regulated tariff which determines the margin to be earned by Eletropaulo. The review and reset of this tariff component is performed every four years. The primary factor in the ongoing discussions between Eletropaulo and the Regulator that causes the estimate to be sensitive to change is the regulatory asset base which will be used by the Regulator to determine the return included in the revised tariff. From July 2011 through March 2012, Eletropaulo continued to invoice customers under the existing tariff rate, as required by the Regulator. Management believes that it is probable that the new tariff rate will be lower than the existing tariff rate, resulting in future refunds to customers. Accordingly, since the third quarter of 2011, Eletropaulo has been recognizing a regulatory liability for such future refunds and updating this estimate as the periodic review and tariff reset process has progressed with the Regulator. As of March 31, 2012, Eletropaulo recognized a regulatory liability of $352 million. This includes a cumulative increase of $29 million relating to the estimated regulatory liability recognized in the second half of 2011 based on the new information available in the first quarter of 2012. It is at least reasonably possible that future events confirming the final amount of the regulatory liability or a change in the estimated amount of the liability will occur in the near term and the final amount of the regulatory liability may differ from the estimated amount recognized as of March 31, 2012.

19. SUBSEQUENT EVENTS

Stock Repurchase Program — On April 19, 2012, the Company’s Board of Directors approved an increase to the stock repurchase program, bringing the total amount authorized for purchases from $500 million to $680 million. There were no repurchases of common stock under the program during the three months ended March 31, 2012.

Red Oak and Ironwood — The Red Oak and Ironwood sale transactions closed on April 12, 2012 and April 13, 2012, respectively. See Note 15 — Discontinued Operations and Held for Sale Businesses for further information.

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

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

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

FORWARD-LOOKING INFORMATION

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

Overview of Our Business

We are a global power company. We operate two primary lines of business. The first is our Generation business, where we own and/or operate power plants to generate and sell power to wholesale customers such as utilities, other intermediaries and certain end-users. The second is our Utilities business, where we own and/or operate utilities which distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area and in certain circumstances, generate and sell electricity on the wholesale market. For the three months ended March 31, 2012, our Generation and Utilities businesses comprised approximately 45% and 55% of our consolidated revenue, respectively.

Our wind and solar businesses are not material contributors to our operating results. For additional information regarding our business, see Item 1. — Business of the 2011 Form 10-K.

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

•

Generation — Latin America;

•

Generation — North America;

•

Generation — Europe;

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Generation — Asia;

•

Utilities — Latin America;

•

Utilities — North America;

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Corporate and Other

As discussed in Note 11 — Segments, based on application of the segment accounting guidance, Tietê is reported as a separate segment for purposes of the required segment accounting disclosures, but is included in Generation — Latin America within the discussion of operating results for revenue and gross margin in management’s discussion and analysis as is it managed with the other Latin American generation businesses.

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

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

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

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

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

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

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

Due to our global presence, the Company has significant exposure to foreign currency fluctuations. The exposure is primarily associated with the impact of the translation of our foreign subsidiaries’ operating results from their local currency to U.S. dollars that is required for the preparation of our consolidated financial statements. Additionally, there is a risk of transaction exposure when an entity enters into transactions, including debt agreements, in currencies other than their functional currency. These risks are further described in Item 1A. — Risk Factors of the 2011 Form 10-K, “Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations.” In the three months ended March 31, 2012, changes in foreign currency exchange rates have had a significant impact on our operating results. If the current foreign currency exchange rate volatility continues, our gross margin and other financial metrics will continue to be affected.

Another key driver of our results is our ability to bring new businesses into commercial operations successfully and to integrate acquisitions. We currently have approximately 2,248 MW of projects under construction in eleven countries. Our prospects for increased operating results and cash flows are dependent upon successful completion of these projects on time and within budget. However, as disclosed in Item 1A. — Risk Factors of the 2011 Form 10-K, “Our business is subject to substantial development uncertainties,” construction is subject to a number of risks, including risks associated with site identification, financing and permitting and our ability to meet construction deadlines. Delays or the inability to complete projects and commence commercial operations can result in increased costs, impairment of assets and other challenges involving partners and counterparties to our construction agreements, PPAs and other agreements. Similarly, failure to integrate

acquisitions and manage market risk, including the Company’s recent acquisition of DPL, could impact our future operating results as disclosed in Item 1A. — Risk Factors of the 2011 Form 10-K, “After completion of the DPL acquisition, the Company, may fail to realize the anticipated benefits and cost savings of the acquisition, which could adversely affect the value of the Company’s common stock” and Key Trends and Uncertainties — Goodwill, below.

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

Management’s Priorities

Management is focused on the following priorities:

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

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platform expansion in Brazil, Chile and the United States,

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

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corporate debt reduction, and

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a return of capital to shareholders, including share repurchases and our intent to initiate a dividend in the third quarter of 2012;

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Prudently exiting select non-strategic markets;

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Optimizing profitability of operations in the existing portfolio;

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

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

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Integration of new projects. The following projects commenced commercial operations during the three months ended March 31, 2012:


Project	Location	Fuel	Gross MW		AES Equity Interest (Percent, Rounded)
Chen Qi⁽¹⁾	China	Wind		49		49	%
Quincieux⁽¹⁾	France	Solar		9		50	%
Jodhpur⁽¹⁾	India	Solar		5		50	%
Saurashtra	India	Wind		39		100	%
Nepi⁽¹⁾	Italy	Solar		3		100	%
Panevino⁽¹⁾	Italy	Solar		5		50	%
Siracusa 4-6⁽¹⁾	Italy	Solar		3		50	%
Mountain View IV	US-CA	Wind		49		100	%
Sao Jose	Brazil	Hydro		4		24	%

⁽¹⁾	Projects owned by investments accounted for under the equity method of accounting.

Key Trends and Uncertainties

We continue to face many risks as discussed in Item 1A.—Risk Factors of the 2011 Form 10-K. Some of these challenges are also described below in “Key Drivers of Results in the Three Months Ended March 31, 2012”. We continue to monitor our operations and address challenges as they arise.

Operations

In August 2010, the Esti power plant, a 120 MW run-of-river hydroelectric power plant in Panama, was taken offline due to damage to its tunnel infrastructure. AES Panama is partially covered for business interruption losses and property damage under existing insurance programs. The majority of the repairs have been completed and the Esti power plant is projected to resume operations early in the second half of 2012. However, due to the inherent uncertainties associated with construction, it is possible that commercial operations may resume after this timeframe which could impact our results for 2012.

Regulatory tariff revisions have a potential to adversely impact the results of our utility businesses. For example, Eletropaulo, our utility business in Brazil, is currently billing its customers under the pre-existing tariff as required by Brazilian energy regulator (the “Regulator”). In July 2011, the regulator postponed the review and reset of Eletropaulo’s regulated tariff, which includes a tariff component that determines the margin Eletropaulo is allowed to earn. The review and reset of the regulated tariff is performed every four years. Management believes that it is probable that the new tariff rate will be lower than the current tariff rate, resulting in future refunds to customers, and based on its best estimate continues to record the amount of estimated future refunds as a reduction of revenue and a regulatory liability. The estimate is sensitive to the key assumption regarding the regulatory asset base that will be used by the Regulator to determine the return included in the revised tariff. The Regulator has asserted that the regulatory asset base is less than Eletropaulo’s estimate of the regulatory asset base, which was used to estimate the regulatory liability recognized at March 31, 2012. While discussions are ongoing and the Company believes its estimates are reasonable, it is possible that the final amount of the regulatory liability may differ from the estimated amount recognized as of March 31, 2012.

On April 2, 2012, Eletropaulo received an infraction notice from the Regulator relating to the financial audit of its fixed assets, which occurred from December 2010 to February 2011. The notice alleges non-conformities in the regulatory accounting applied by Eletropaulo to the fixed assets, which impact the regulatory asset base used by the Regulator to calculate the tariff charged to customers. Management has submitted a formal response to the Regulator contesting the non-conformities and fine imposed and expects the Regulator to issue a final decision. Management believes that there is a probable likelihood of loss for certain issues listed in the infraction notice and has estimated and recorded a contingent liability as of March 31, 2012 in accordance with the accounting standards on contingencies.

On March 30, 2012, DP&L, our regulated utility in Ohio, filed with the Public Utilities Commission of Ohio (“PUCO”) for approval of its next Standard Service Offer to replace the existing Electric Security Plan that expires on December 31, 2012. The filing requested approval of a five-year and five month Market Rate Option, which will be effective January 1, 2013, and would phase in market rates over this period. The PUCO is currently reviewing the filing and no decision has been made. The outcome of the proceeding is uncertain and could have a material impact on our results. See Item 1 — Business — Regulatory Matters — United States — The Dayton Power and Light Company included in the 2011 Form 10-K for further information.

Global Economic Considerations

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

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

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

Our subsidiaries are subject to credit risk, which includes risk related to the ability of counterparties (such as parties to our PPAs, fuel supply agreements, hedging agreements and other contractual arrangements) to deliver contracted commodities or services at the contracted price or to satisfy their financial or other contractual obligations. The Company has not suffered any material effects related to its counterparties during the three months ended March 31, 2012. However, if macroeconomic conditions impact our counterparties, they may be unable to meet their commitments which could result in the loss of favorable contractual positions, which could have a material impact on our business.

Euro Zone Debt Crisis. During the past year, certain European Union countries have continually faced a sovereign debt crisis and it is possible that this crisis could spread to other countries. This crisis has resulted in an increased risk of default by governments and the implementation of austerity measures in certain countries. If the crisis continues, worsens, or spreads, there could be a material adverse impact on the Company. Our businesses may be impacted if they are unable to access the capital markets, face increased taxes or labor costs, or if governments fail to fulfill their obligations to us or adopt austerity measures which adversely impact our projects. At March 31, 2012, the Company had unfunded commitments from European banks for our corporate revolver and for certain project finance debt totaling $222 million and $710 million, respectively. Approximately 10% of the non-recourse debt held by subsidiaries was denominated in Euros and 15% of our variable rate debt was indexed to Euribor at March 31, 2012. In addition, as discussed in Item 1A. — Risk Factors — Our renewable energy projects and other initiatives face considerable uncertainties including development, operational and regulatory challenges of the 2011 Form 10-K, our renewables businesses are dependent on favorable regulatory incentives, including subsidies, which are provided by sovereign governments, including European governments. If these subsidies or other incentives are reduced or repealed, or sovereign governments are unable or unwilling to fulfill their commitments or maintain favorable regulatory incentives for renewables, in whole or in part, this could impact the ability of the affected businesses to continue to sustain and/or grow their operations. For

example, in 2011, tariffs for certain of our European solar businesses were reduced, and could be reduced further. The Company’s investment in AES Solar Energy Ltd., whose primary operations are in Europe, was $231 million at March 31, 2012. In addition, any of the foregoing could also impact contractual counterparties of our subsidiaries in core power or renewables. If such counterparties are adversely impacted, then they may be unable to meet their commitments to our subsidiaries. For example, our investments in Bulgaria rely on offtaker contracts with NEK, the fully state-owned national electricity distribution company. The Company has long-lived assets in Bulgaria and receivables from NEK of $1.8 billion. For further information on the importance of long-term contracts and our counterparty credit risk, see Item 1A. — Risk Factors — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations…” of the 2011 Form 10-K. As a result of any of the foregoing events, we may 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.

In Argentina, potential deteriorating economic indicators such as falling commodity prices on exports, increased inflation, devaluation of the local currency and large government deficits could cause significant volatility in our results of operations, cash flows and the value of our assets. AES’s long-lived assets in Argentina, including our long-term receivables, were $572 million at March 31, 2012. In addition, recent actions by the Argentinean government may indicate deeper government intervention in the local economy. For example, on April 16, 2012, the Argentinean government expropriated 51% of the country’s largest oil company’s assets. The statute used to expropriate the oil company is not applicable to our businesses in Argentina. However, potential deteriorating economic conditions or further government action could have a material impact on the Company or its financial statements.

As noted in Item 1A — Risk Factors — “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” of the 2011 Form 10-K and Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk of this Form 10-Q, the Company’s North American businesses continue to face pressure as a result of high coal prices relative to natural gas, which has affected the results of certain of our coal plants in the region, particularly those businesses that have a PPA in place, but purchase fuel at market prices or under short term contracts. In 2011, Eastern Energy, our coal-fired plants in New York, filed for bankruptcy and is no longer in our portfolio of businesses. In connection with the recent Eastern Energy bankruptcy filing, it is possible that creditors may attempt to bring claims against Eastern Energy and or directly against The AES Corporation. While we believe Eastern Energy and The AES Corporation would have meritorious defenses against any such claims, there can be no assurance that Eastern Energy or The AES Corporation would prevail in such claims. In 2011, AES Deepwater was idled to mitigate operating risks caused by high fuel costs and other competitive pressures. If the conditions described above continue or worsen, our North American businesses with market exposure may need to restructure their obligations or seek additional funding (including from the Parent) or face the possibility that they may be unable to meet their obligations and continue operations, which could result in the loss of earnings or cash flow or result in a write down in the value of these assets, any of which could have a material impact on the Company. For further discussion of the risks associated with commodity prices, see Item 1A. — Risk Factors “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates.” of the 2011 Form 10-K.

If global economic conditions worsen, 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 as PPAs, concession agreements or other contracts as they come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual price or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses.

Impairments.

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

•

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

•

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

•

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

•

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

We continue to evaluate the recoverability of our long-lived assets at Kelanitissa, our diesel-fired generation plant in Sri Lanka, as a result of both the requirement to transfer the plant to the government at end of our PPA and the current expectation of lower future operating cash flows. These evaluations resulted in the recognition of asset impairment expense of $42 million in 2011. During the current quarter, our evaluations indicated that the long-lived assets were not recoverable and, accordingly, were written down by an additional $5 million to their estimated fair value of $17 million based on a discounted cash flow analysis. Kelanitissa is a Build-operate-transfer (“BOT”) generation facility and payments under its PPA are scheduled to decline over the PPA term. It is likely that further impairment charges will be required in the future as Kelanitissa gets closer to the BOT date.

Goodwill. The Company seeks business acquisitions as one of its growth strategies. We have achieved significant growth in the past as a result of several business acquisitions, which also resulted in the recognition of goodwill. As noted in Item 1A. — Risk Factors of the 2011 Form 10-K, there is always a risk that “Our acquisitions may not perform as expected.” One of the primary factors contributing to goodwill is the synergies expected from an acquisition that follow the integration of the acquired business with the existing operations of an entity. Thus, an entity’s ability to realize benefits of goodwill depends on the successful integration of the acquired business. If such integration efforts are not successful, it could be difficult to realize the benefits of goodwill, which could result in impairment of goodwill. As described in Note 16 — Acquisitions and Dispositions included in Item 1. — Financial Statements of this Form 10-Q, the Company completed the acquisition of DPL on November 28, 2011, which resulted in the provisional recognition of $2.5 billion of goodwill. The Company’s ability to realize the benefit of DPL’s goodwill will depend on our ability to realize the expected operating synergies and manage the market risks of DPL as further described in Item 1A. — Risk Factors of the 2011 Form 10-K “After completion of the DPL acquisition, the Company may fail to realize the anticipated benefits and cost savings of the acquisition, which could adversely affect the value of the Company’s common stock.” Additionally, utilities in Ohio continue to face downward pressure on operating margins due to the evolving regulatory environment, which is moving towards a market-based competitive pricing mechanism. At the same time, the declining energy prices are also reducing operating margins across the utility industry. These competitive forces could adversely impact the future operating performance of DPL and may result in impairment of its goodwill.

The value of goodwill is also positively correlated with the economic environments in which our acquired businesses operate and a severe economic downturn could negatively impact the value of goodwill. Also, the evolving environmental regulations, including GHG regulations, around the world continue to increase the operating costs of our generation businesses. In extreme situations, environmental regulations could even make a

once profitable business uneconomical. In addition, most of our generation businesses have a finite life and as the acquired businesses reach the end of their finite lives, the carrying amount of goodwill is gradually realized through their periodic operating results. The accounting guidance, however, prohibits the systematic amortization of goodwill and rather requires an annual impairment evaluation. Thus, as some of our acquired businesses approach the end of their finite lives, they may incur goodwill impairment charges even if there are no discrete adverse changes in the economic environment.

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

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

Legislation and Regulation of GHG Emissions

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

Potential U.S. Federal GHG Legislation Federal legislation passed the United States House of Representatives in 2009 that, if adopted, would have imposed a nationwide cap-and-trade program to reduce

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

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

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

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

A consortium of industry petitioners has challenged the Endangerment Finding, Tailoring Rule and the Motor Vehicle Rule in the United States Court of Appeals for the District of Columbia Circuit. These challenges were consolidated and oral argument took place on February 28 and 29, 2012. A decision on these lawsuits is expected from the court before the end of June 2012. We cannot predict the outcome of this litigation.

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

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

Other U.S. Air Emissions Regulations and Legislation

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

The EPA is obligated under Section 112 of the CAA to develop a rule requiring pollution controls for hazardous air pollutants, including mercury, hydrogen chloride, hydrogen fluoride, and nickel species from coal and oil-fired power plants. In connection with such rule, the CAA requires the EPA to establish Maximum Achievable Control Technology (“MACT”). MACT is defined as the emission limitation achieved by the “best performing 12%” of sources in the source category. Pursuant to Section 112 of the CAA, the EPA promulgated a final rule on December 16, 2011, called the Mercury Air Toxics Standards (“MATS” or the “Utility MACT”) establishing national emissions standards for hazardous air pollutants (“NESHAP”) from coal and oil-fired electric utility steam generating units. These emission standards reflect the EPA’s application of Utility MACT standards for each pollutant regulated under the rule. The rule requires all coal-fired power plants to comply with the applicable Utility MACT standards within three years, with the possibility of obtaining an additional year, if needed, to complete the installation of necessary controls. To comply with the rule, many coal-fired power plants may need to install additional control technology to control acid gases, mercury or particulate matter, or they may need to repower with an alternate fuel or retire operations. Most of the Company’s U.S. coal-fired plants operated by its subsidiaries have acid gas scrubbers or comparable control technologies, but there are other improvements to such control technologies that may be needed at some of the Company’s plants to assure compliance with the Utility MACT standards. Older coal-fired facilities that do not currently have a SO₂ scrubber installed are particularly at risk.

On July 15, 2011, Duke Energy, co-owner with DP&L at the Beckjord Unit 6 facility, a 414 MW power plant, filed their Long-term Forecast Report with the Public Utilities Commission of Ohio (“PUCO”). The report indicated that Duke Energy plans to cease production at the Beckjord Station, including the jointly-owned Unit 6, in December 2014. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. DP&L is considering options for its Hutchings Station, a six unit power plant with 365MW of total capacity, to comply with the Utility MACT standards.

The combination of existing and expected environmental regulations, including the Utility MACT, make it likely that IPL will temporarily or permanently retire several of its existing, primarily coal-fired, smaller and older generating units within the next several years. These units are not equipped with the advanced environmental control technologies needed to comply with existing and expected regulations, and collectively make up less than 15% of IPL’s net electricity generation over the past five years. IPL is continuing to evaluate options for replacing this generation. IPL is currently reviewing the impact of the new Utility MACT rule and estimates total additional expenditures for IPL related to this rule to be approximately $500 million to $900 million through approximately 2016. 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 IPL would be successful in that regard.

Several lawsuits challenging the Utility MACT rule have been filed and consolidated into a single proceeding before the United States Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this litigation. The aggregate capital costs, other expenditures or operational restrictions necessary to comply with the rule cannot be specified at this time. The Company anticipates that the rule may have a material impact on the Company’s business, financial condition and results of operations.

The EPA promulgated the “Clean Air Interstate Rule” (“CAIR”) on March 10, 2005, which required allowance surrender for SO₂ and NO_x emissions from existing power plants located in 28 eastern states and the District of Columbia. CAIR contemplated two implementation phases. The first phase was to begin in 2009 and 2010 for NO_x and SO₂, respectively. A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015. To implement the required emission reductions for this rule, the states were to establish emission allowance based “cap-and-trade” programs. CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the EPA.

In response to the D.C. Circuit’s opinion, on July 7, 2011, the EPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, the CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered s