Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

(Mark One)

 

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

For the Quarterly Period Ended March 31, 2010

or

 

  ¨ 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):

 

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

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

 

 

The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, on April 30, 2010, was 795,378,395.

 

 

 


Table of Contents

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010

TABLE OF CONTENTS

 

PART I: FINANCIAL INFORMATION

   3

ITEM 1.

  FINANCIAL STATEMENTS    3
  Condensed Consolidated Statements of Operations    3
  Condensed Consolidated Balance Sheets    4
  Condensed Consolidated Statements of Cash Flows    5
  Condensed Consolidated Statements of Changes in Equity    6
  Notes to Condensed Consolidated Financial Statements    7

ITEM 2.

  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS    43

ITEM 3.

  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    70

ITEM 4.

  CONTROLS AND PROCEDURES    73

PART II: OTHER INFORMATION

   74

ITEM 1.

  LEGAL PROCEEDINGS    74

ITEM 1A.

  RISK FACTORS    74

ITEM 2.

  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS    74

ITEM 3.

  DEFAULTS UPON SENIOR SECURITIES    74

ITEM 4.

  REMOVED AND RESERVED    75

ITEM 5.

  OTHER INFORMATION    75

ITEM 6.

  EXHIBITS    75

 

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Table of Contents

PART I: FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

THE AES CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)

 

     Three Months Ended
March 31,
 
         2010             2009      
    

(in millions, except per

share amounts)

 

Revenue:

    

Regulated

   $ 2,241     $ 1,666  

Non-Regulated

     1,871       1,603  
                

Total revenue

     4,112       3,269  
                

Cost of Sales:

    

Regulated

     (1,666     (1,220

Non-Regulated

     (1,446     (1,193
                

Total cost of sales

     (3,112     (2,413
                

Gross margin

     1,000       856  
                

General and administrative expenses

     (82     (84

Interest expense

     (393     (380

Interest income

     109       93  

Other expense

     (12     (22

Other income

     9       222  

Gain on sale of investments

     -        13  

Foreign currency transaction gains (losses) on net monetary position

     (51     (39

Other non-operating expense

     -        (10
                

INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES

     580       649  

Income tax expense

     (196     (174

Net equity in earnings of affiliates

     14       7  
                

INCOME FROM CONTINUING OPERATIONS

     398       482  

Income from operations of discontinued businesses, net of income tax expense of $1 and $1, respectively

     17       19  

Loss from disposal of discontinued businesses, net of income tax benefit of $— and $—, respectively

     (13     -   
                

NET INCOME

     402       501  

Noncontrolling interests:

    

Less: Income from continuing operations attributable to noncontrolling interests

     (213     (274

Less: Income from discontinued operations attributable to noncontrolling interests

     (2     (9
                

Total net income attributable to noncontrolling interests

     (215     (283
                

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION

   $ 187     $ 218  
                

BASIC EARNINGS PER SHARE:

    

Income from continuing operations attributable to The AES Corporation common stockholders, net of tax

   $ 0.27     $ 0.31  

Discontinued operations attributable to The AES Corporation common stockholders,
net of tax

     -        0.02  
                

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS

   $ 0.27     $ 0.33  
                

DILUTED EARNINGS PER SHARE:

    

Income from continuing operations attributable to The AES Corporation common stockholders, net of tax

   $ 0.27     $ 0.31  

Discontinued operations attributable to The AES Corporation common stockholders,
net of tax

     -        0.02  
                

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS

   $ 0.27     $ 0.33  
                

AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:

    

Income from continuing operations, net of tax

   $ 185     $ 208  

Discontinued operations, net of tax

     2       10  
                

Net income

   $         187     $         218  
                

See Notes to Condensed Consolidated Financial Statements

 

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THE AES CORPORATION

Condensed Consolidated Balance Sheets

 

    March 31,
2010
    December 31,
2009
 
    (in millions except share
and per share data)
 
    (unaudited)        

ASSETS

   

CURRENT ASSETS

   

Cash and cash equivalents

  $ 3,392     $ 1,809  

Restricted cash

    565       407  

Short-term investments

    1,731       1,648  

Accounts receivable, net of allowance for doubtful accounts of $293 and $290, respectively

    2,244       2,152  

Inventory

    575       569  

Receivable from affiliates

    15       24  

Deferred income taxes—current

    235       218  

Prepaid expenses

    221       162  

Other current assets

    1,215       1,558  

Current assets of discontinued and held for sale businesses

    267       240  
               

Total current assets

    10,460       8,787  
               

NONCURRENT ASSETS

   

Property, Plant and Equipment:

   

Land

    1,095       1,111  

Electric generation, distribution assets and other

    29,057       27,462  

Accumulated depreciation

    (9,205     (8,920

Construction in progress

    3,880       4,644  
               

Property, plant and equipment, net

    24,827       24,297  
               

Other Assets:

   

Deferred financing costs, net of accumulated amortization of $310 and $297, respectively

    389       384  

Investments in and advances to affiliates

    1,175       1,157  

Debt service reserves and other deposits

    695       595  

Goodwill

    1,297       1,299  

Other intangible assets, net of accumulated amortization of $227 and $223, respectively

    508       510  

Deferred income taxes—noncurrent

    639       604  

Other

    1,556       1,551  

Noncurrent assets of discontinued and held for sale businesses

    336       351  
               

Total other assets

    6,595       6,451  
               

TOTAL ASSETS

  $ 41,882     $ 39,535  
               

LIABILITIES AND EQUITY

   

CURRENT LIABILITIES

   

Accounts payable and other accrued liabilities

  $ 4,057     $ 4,234  

Accrued interest

    351       271  

Non-recourse debt—current

    1,863       1,759  

Recourse debt—current

    473       214  

Current liabilities of discontinued and held for sale businesses

    150       143  
               

Total current liabilities

    6,894       6,621  
               

LONG-TERM LIABILITIES

   

Non-recourse debt—noncurrent

    13,271       12,642  

Recourse debt—noncurrent

    5,035       5,301  

Deferred income taxes—noncurrent

    1,130       1,090  

Pension and other post-retirement liabilities

    1,285       1,322  

Other long-term liabilities

    3,253       3,208  

Long-term liabilities of discontinued and held for sale businesses

    418       411  
               

Total long-term liabilities

    24,392       23,974  
               

Contingencies and Commitments (see Note 7)

   

Cumulative preferred stock of subsidiary

    60       60  

EQUITY

   

THE AES CORPORATION STOCKHOLDERS’ EQUITY

   

Common stock ($0.01 par value, 1,200,000,000 shares authorized; 804,079,027 issued and 795,174,732 outstanding at March 31, 2010 and 677,214,493 issued and 667,679,913 outstanding at December 31, 2009

    8       7  

Additional paid-in capital

    8,447       6,868  

Retained earnings

    791       650  

Accumulated other comprehensive loss

    (2,881     (2,724

Treasury stock, at cost (8,904,295 shares at March 31, 2010 and 9,534,580 shares at December 31, 2009, respectively)

    (118     (126
               

Total The AES Corporation stockholders’ equity

    6,247       4,675  

NONCONTROLLING INTERESTS

    4,289       4,205  
               

Total equity

    10,536       8,880  
               

TOTAL LIABILITIES AND EQUITY

  $         41,882     $         39,535  
               

See Notes to Condensed Consolidated Financial Statements

 

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THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

 

     Three Months Ended
March 31,
 
         2010             2009      
     (in millions)  

OPERATING ACTIVITIES:

    

Net income

   $ 402     $ 501  

Adjustments to net income:

    

Depreciation and amortization

     293       245  

Loss (gain) from sale of investments and impairment expense

     4       (12

Loss on disposal and impairment write-down—discontinued operations

     13       -   

Provision for deferred taxes

     29       (25

Contingencies

     46       (102

(Gain) loss on the extinguishment of debt

     -        14  

Other

     (20     41  

Changes in operating assets and liabilities:

    

(Increase) decrease in accounts receivable

     (64     80  

Decrease in inventory

     3       47  

Decrease (increase) in prepaid expenses and other current assets

     47       (124

Increase in other assets

     (70     (73

Increase (decrease) in accounts payable and accrued liabilities

     56       (192

Decrease in income taxes and other income tax payables, net

     (97     (9

Increase (decrease) in other liabilities

     42       (34
                

Net cash provided by operating activities

     684       357  
                

INVESTING ACTIVITIES:

    

Capital expenditures

     (493     (574

Acquisitions—net of cash acquired

     (34     -   

Proceeds from the sale of businesses

     99       -   

Sale of short-term investments

     1,006       999  

Purchase of short-term investments

     (1,102     (686

(Increase) decrease in restricted cash

     (46     293  

(Increase) decrease in debt service reserves and other assets

     (61     73  

Affiliate advances and equity investments

     (23     (30

Other investing

     59       2  
                

Net cash (used in) provided by investing activities

     (595     77  
                

FINANCING ACTIVITIES:

    

Issuance of common stock

     1,570       -   

Borrowings (repayments) under the revolving credit facilities, net

     26       (153

Issuance of non-recourse debt

     216       244  

Repayments of non-recourse debt

     (182     (169

Payments for deferred financing costs

     (13     (22

Distributions to noncontrolling interests

     (72     (12

Contributions from noncontrolling interests

     -        73  

Financed capital expenditures

     (30     (49

Other financing

     -        1  
                

Net cash provided by (used in) financing activities

     1,515       (87

Effect of exchange rate changes on cash

     (21     (2
                

Total increase in cash and cash equivalents

     1,583       345  

Cash and cash equivalents, beginning

     1,809       881  
                

Cash and cash equivalents, ending

   $ 3,392     $ 1,226  
                

SUPPLEMENTAL DISCLOSURES:

    

Cash payments for interest, net of amounts capitalized

   $ 284     $ 271  

Cash payments for income taxes, net of refunds

   $ 260     $ 200  

See Notes to Condensed Consolidated Financial Statements

 

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THE AES CORPORATION

Condensed Consolidated Statement of Changes in Equity

(Unaudited)

 

    THE AES CORPORATION STOCKHOLDERS     Noncontrolling
Interests
    Consolidated
Comprehensive
Income
 
    Common
Stock
  Treasury
Stock
    Additional
Paid-In
Capital
  Retained
Earnings
    Accumulated
Other
Comprehensive
Loss
     
    (in millions)  

Balance at January 1, 2010

  $ 7   $ (126   $ 6,868   $ 650     $ (2,724   $ 4,205     $     

Net income

    -     -        -     187       -        215       402  

Change in fair value of available-for-sale securities, net of income tax

    -     -        -     -        (4     -        (4

Foreign currency translation adjustment, net of income tax

    -     -        -     -        (88     (46     (134

Change in unfunded pensions obligation, net of income tax

    -     -        -     -        1       1       2  

Change in derivative fair value, including a reclassification to earnings, net of income tax

    -     -        -     -        (28     (6     (34
                   

Other comprehensive income

                (170
                   

Total comprehensive income

              $         232  
                   

Cumulative effect of consolidation of entities under variable interest entity accounting guidance

    -     -        -     (47     (38     15    

Cumulative effect of deconsolidation of entities under variable interest entity accounting guidance

    -     -        -     1       -        -     

Capital contributions from noncontrolling interests

    -     -        -     -        -        2    

Dividends declared to noncontrolling interests

    -     -        -     -        -        (97  

Issuance of common stock

    1     -        1,566     -        -        -     

Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax

    -     8       6     -        -        -     

Stock compensation

    -     -        7     -        -        -     
                                             

Balance at March 31, 2010

  $             8   $     (118)      $     8,447   $         791     $     (2,881)      $     4,289    
                                             

 

    THE AES CORPORATION STOCKHOLDERS     Noncontrolling
Interests
    Consolidated
Comprehensive
Income
 
    Common
Stock
  Treasury
Stock
    Additional
Paid-In
Capital
  (Accumulated
Deficit) /
Retained
Earnings
    Accumulated
Other
Comprehensive
Loss
     
    (in millions)  

Balance at January 1, 2009

  $ 7   $ (144   $ 6,832   $ (8   $ (3,018   $ 3,358     $     

Net income

    -     -        -     218       -        283       501  

Foreign currency translation adjustment, net of income tax

    -     -        -     -        (72     3       (69

Change in unfunded pensions obligation, net of income tax

    -     -        -     -        1       -        1  

Change in derivative fair value, including a reclassification to earnings, net of income tax

    -     -        -     -        80       14       94  
                   

Other comprehensive income

                26  
                   

Total comprehensive income

              $         527  
                   
Capital contributions from noncontrolling interests     -     -        -     -        -        73    

Dividends declared to noncontrolling interests

    -     -        -     -        -        (9  

Issuance of common stock under benefit plans and exercise of stock options and warrants, net of income tax

    -     17       -     -        -        -     

Stock compensation

    -     -        2     -        -        -     
                                             

Balance at March 31, 2009

  $             7   $     (127)      $     6,834   $         210     $     (3,009)      $     3,722    
                                             

See Notes to Condensed Consolidated Financial Statements

 

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THE AES CORPORATION

Notes to Condensed Consolidated Financial Statements

For the Three Months Ended March 31, 2010 and 2009

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 12 — Discontinued Operations. In addition, certain immaterial prior period amounts have been reclassified within the condensed consolidated financial statements to conform to current period presentation.

Consolidation

In this Quarterly Report the terms “AES”, “the Company”, “us” or “we” refer to the consolidated entity including its subsidiaries and affiliates. The terms “The AES Corporation”, “the Parent” or “the Parent Company” refer only to the publicly-held holding company, The AES Corporation, excluding its subsidiaries and affiliates. Furthermore, variable interest entities (“VIEs”) in which the Company has an 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 (the “Codification” or “ASC”) for interim financial information and Article 10 of Regulation S-X issued by the 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, 2010 are not necessarily indicative of results that may be expected for the year ending December 31, 2010. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2009 audited consolidated financial statements and notes thereto, which are included in the 2009 Form 10-K filed with the SEC on February 25, 2010.

Significant New Accounting Policies

Accounting Standards Update (“ASU”) No. 2009-16, Accounting for Transfers of Financial Assets (former Financial Accounting Standard (“FAS”) No. 166, Accounting for Transfers of Financial Assets, an Amendment of FASB Statement No. 140)

Effective January 1, 2010, the Company prospectively adopted the new accounting guidance on transfers of financial assets, which among other things: removes the concept of a qualifying special purpose entity; introduces the concept of participating interests and specifies that in order to qualify for sale accounting a partial transfer of a financial asset or a group of financial assets should meet the definition of a participating interest; clarifies that an entity should consider all arrangements made contemporaneously with or in contemplation of a transfer and requires enhanced disclosures to provide financial statement users with greater transparency about transfers of financial assets and a transferor’s continuing involvement with transfers of financial assets accounted for as sales. Upon adoption on January 1, 2010, the Company recognized $50 million as accounts receivable and an associated secured borrowing on its condensed consolidated balance sheet. IPL, the Company’s integrated utility in Indianapolis, had securitized these accounts receivable through IPL Funding, a special purpose entity,

 

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and previously recognized the transaction as a sale and had not recognized the accounts receivable and secured borrowing on its balance sheet. Under the facility, interest in these accounts receivable is transferred to unrelated parties (the Purchasers) up to the lesser of $50 million or an amount determinable under the facility agreement. The Purchasers assume the risk of collection on the interest sold without recourse to IPL, which retains the servicing rights for the interest sold. Under the new accounting guidance, the retained interest in these securitized accounts receivable does not meet the definition of a participating interest, thereby requiring the Company to recognize on its condensed consolidated balance sheet the portion transferred and the proceeds received as accounts receivable and a secured borrowing, respectively.

ASU No. 2009-17, Consolidations, Improvements to Financial Reporting by Enterprises involved with Variable Interest Entities (former FAS No. 167, Amendments to FASB Interpretation No. 46(R))

Effective January 1, 2010, the Company prospectively adopted the new accounting guidance on the consolidation of VIEs. The new guidance requires an entity to qualitatively, rather than quantitatively, assess the determination of the primary beneficiary of a VIE. This determination should be based on whether the entity has the power to direct the activities that most significantly impact the economic performance of the VIE and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Other key changes include: a requirement for the ongoing reconsideration of the primary beneficiary, the criteria for determining whether service provider or decision maker contracts are variable interests, the consideration of kick-out and removal rights in determining whether an entity is a VIE, the types of events that trigger the reassessment of whether an entity is a VIE and the expansion of the disclosures previously required.

The determination of the entity that has the power to direct the activities that most significantly impact the economic performance of the VIE required significant judgment and assumptions for certain of the Company’s businesses. That determination considered the purpose and design of the businesses, the risks that the businesses were designed to create and pass along to other entities, the activities of the businesses that could be directed and which entity could direct them, and the expected relative impact of those activities on the economic performance of the businesses through their life. The businesses for which significant judgment and assumptions were required were primarily certain generation businesses who have power purchase agreements (“PPAs”) to sell energy exclusively or primarily to a single counterparty for the term of those agreements. For these generation businesses, the counterparty has the power to dispatch energy and, in some instances, to make decisions regarding the sale of excess energy. As such, the counterparty has power to direct certain activities that significantly impact the economic performance of the business. However, the counterparty usually does not have the power to direct any of the other activities that could significantly impact the economic performance, primarily through the cash flows and gross margin (if any) earned by the business from the sale of energy to the counterparty and sometimes through the absorption of fuel price risk by the counterparty. These other activities include: daily operation and management, maintenance and repairs and capital expenditures, plant expansion, decisions regarding overall financing of ongoing operations and budgets and, in some instances, decisions regarding sale of excess energy. As such, the AES generation business has power to direct some activities of the business that significantly impact its economic performance, primarily through the cash flows and gross margin earned from capacity payments received from being available to produce energy and from any sale of energy to other entities (particularly during any period beyond the end of the power purchase agreement). For these VIEs, the determination as to which set of activities most significantly impact the economic performance of the business required significant judgment and assumptions and resulted in the conclusion that the activities directed by the counterparty were less significant than those directed by the AES business.

The adoption of the new guidance resulted in the deconsolidation of certain immaterial VIEs previously consolidated. Additionally, assets, liabilities and operating results of two of our VIEs, previously accounted for under the equity method of accounting, were required to be consolidated. Cartagena, a 71% owned generation business in Spain, and Cili, a 51% owned generation business in China, were consolidated under the new guidance resulting in a cumulative effect adjustment of $47 million to retained earnings as of January 1, 2010. The cumulative effect adjustment is primarily comprised of losses that were not recognized while the equity

 

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method of accounting was suspended for Cartagena. As of March 31, 2010 total assets and total liabilities, related to these VIEs were $851 million and $946 million, respectively. In addition, revenue for the three months ended March 31, 2010 included $102 million of revenue from these VIEs. Prior period operating results of these VIEs are reflected in “Net equity in earnings of affiliates” except for those prior periods during which the equity method of accounting was suspended.

2. INVENTORY

The following table summarizes the Company’s inventory balances as of March 31, 2010 and December 31, 2009:

 

     March 31,
2010
   December 31,
2009
     (in millions)

Coal, fuel oil and other raw materials

   $ 295    $ 293

Spare parts and supplies

     280      276
             

Total

   $         575    $         569
             

3. FAIR VALUE DISCLOSURES

The following table summarizes the carrying and fair value of certain of the Company’s financial assets and liabilities as of March 31, 2010 and December 31, 2009:

 

     March 31, 2010      December 31, 2009  
     Carrying
Amount
   Fair Value      Carrying
Amount
   Fair Value  
     (in millions)  

Assets

           

Marketable securities

   $ 1,773    $ 1,773        $ 1,691    $ 1,691    

Derivatives

     177      177          141      141    
                               

Total assets

   $ 1,950    $ 1,950        $ 1,832    $ 1,832    
                               

Liabilities

           

Debt

   $ 20,642    $ 21,012        $ 19,916    $ 20,387    

Derivatives

     429      429          350      350    
                               

Total liabilities

   $     21,071    $     21,441        $     20,266    $     20,737    
                               

Additionally, the Company’s nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis include goodwill; intangible assets, such as sales concessions, land rights and emissions allowances; and long-lived tangible assets including property, plant and equipment. The Company recognized impairment charges of $13 million before taxes and noncontrolling interests related to nonfinancial assets and liabilities at our Pakistan businesses currently reflected as held for sale during the three months ended March 31, 2010. See further discussion of these adjustments in Note 12 – Discontinued Operations and Held for Sale Businesses.

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

 

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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 the value indicated by current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace an asset. The Company does not currently determine the fair value of any of our financial assets and liabilities using the cost approach. Financial assets and liabilities that are measured at fair value on a recurring basis at AES fall into two broad categories: investments and derivatives.

Our investments are generally measured at fair value using the market approach and our derivatives are valued using the income approach.

Investments

The Company’s investments measured at fair value generally consist of marketable debt and equity securities. Equity securities are adjusted to 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 LIBOR) or Selic (overnight borrowing rate) rates in Brazil and are adjusted based on the banks’ assessment of the specific businesses. Fair value is determined based on comparisons to market data obtained for similar assets and are considered Level 2 inputs. 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 financial and physical derivative instruments. The Company’s 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 fluctuations in commodity prices, and embedded derivatives associated with commodity contracts. The Company’s subsidiaries are counterparties to various interest rate swaps, interest rate options, foreign currency swaps and commodity and embedded derivatives in certain agreements, generally PPAs. The fair value of our derivative portfolio was determined using internal valuation models, most of which are based on observable market inputs including interest rate curves and forward and spot prices for currencies and commodities. The primary pricing inputs used in determining the fair value of our interest rate swaps and our foreign currency exchange swaps are forward LIBOR/EURIBOR curves and forward foreign exchange curves with the same duration as the instrument from published information provided by pricing services. For each derivative, the projected forward curves are used to determine the stream of cash flows over the remaining term of the contract. The cash flows are then discounted using a spot discount rate to determine the fair value. To the extent that management can estimate the fair value of these assets or liabilities without the use of significant unobservable inputs, these derivatives are considered Level 2.

In certain instances, the published curve may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve which result in the use of unobservable inputs. In certain instances, the financial or physical instrument is traded in an inactive market requiring us to use unobservable inputs. Additionally, in certain instances the nonperformance risk or credit risk adjustment for contracts is based on unobservable inputs. Where the use of such unobservable inputs is significant, these contracts are classified as Level 3.

 

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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, 2010 and December 31, 2009. Financial assets and liabilities have been 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.

 

     Total
March  31,
2010
   Quoted Market
Prices in Active
Market for
Identical Assets
(Level 1)
   Significant
Other
Observable
Inputs

(Level 2)
   Significant
Unobservable
Inputs

(Level 3)
     (in millions)

Assets

           

Available-for-sale securities

   $             1,760    $             85    $             1,633    $             42

Trading securities

     7      7      -      -

Derivatives

     177      -      154      23
                           

Total assets

   $ 1,944    $ 92    $ 1,787    $ 65
                           

Liabilities

           

Derivatives

   $ 429    $ -    $ 398    $ 31
                           

Total liabilities

   $ 429    $ -    $ 398    $ 31
                           
     Total
December  31,
2009
   Quoted Market
Prices in Active
Market for
Identical Assets
(Level 1)
   Significant
Other
Observable
Inputs

(Level 2)
   Significant
Unobservable
Inputs

(Level 3)
     (in millions)

Assets

           

Available-for-sale securities

   $ 1,676    $ 133    $ 1,501    $ 42

Trading securities

     7      7      -      -

Derivatives

     141      -      111      30
                           

Total assets

   $ 1,824    $ 140    $ 1,612    $ 72
                           

Liabilities

           

Derivatives

   $ 350    $ -    $ 320    $ 30
                           

Total liabilities

   $ 350    $ -    $ 320    $ 30
                           

 

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The following table presents a reconciliation of 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, 2010 (by type of derivative) and 2009:

 

     Three Months Ended March 31,  
     2010     2009  
     Interest
Rate
    Cross
Currency
    Foreign
Exchange
    Fuel
Commodity
    Total     Total  
     (in millions)  

Balance at January 1 (1)

   $ (12   $ (12   $ -      $ 24     $ -      $ (69

Total gains (losses) (realized and unrealized): (1)

            

Included in earnings (2)

     -        6        -        3        9        (19

Included in other comprehensive income

     (3     (2 )     -        -       (5 )                 63  

Included in regulatory assets

     (1     -        -                    -        (1     1  

Purchases, issuances and settlements (1)

     1        1                    -        (8     (6     (10

Assets transferred in (out) of
Level 3

     -        -        -        -        -        (187

Liabilities transferred (in) out of Level 3 (3)

     (3     -        (1     -        (4     4  
                                                

Balance at March 31 (1)

   $ (18 )   $ (7   $ (1   $ 19     $ (7 )   $ (217
                                                

Total gains/(losses) for the period included in earnings attributable to the change in unrealized gains/(losses) relating to assets held at both the beginning and end of the period (1)

   $ -      $ 6      $ -      $ 3     $ 9     $ (19
                                                

 

(1)

Derivative assets and (liabilities) are presented on a net basis.

(2)

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.

(3)

Transfers in and out of Level 3 are determined as of the end of the reporting period and are from and to Level 2, except as noted below, as the Company has no Level 1 derivative assets or liabilities. The assets transferred out of Level 3 during the three months ended March 31, 2009 relates to a PPA that was dedesignated as a cash flow hedge because the normal purchase normal sale scope exception from derivative accounting was elected as of December 31, 2008. As such, the agreement was measured at fair value using significant unobservable inputs at December 31, 2008, but is subsequently being amortized and is no longer adjusted for subsequent changes in fair value.

 

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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, 2010 and 2009:

 

     Three Months Ended March 31,  
             2010                    2009          
     (in millions)  

Balance at January 1 (1)

   $ 42    $ 42  

Purchases, issuances and settlements

                   -      (29
               

Balance at March 31

   $ 42    $ 13  
               

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

   $ -    $               -   
               

 

(1)

Available-for-sale securities in Level 3 are auction rate securities and variable rate demand notes which have failed remarketing or are not actively trading and for which there are no longer adequate observable inputs available to measure the fair value.

4. INVESTMENTS IN MARKETABLE SECURITIES

The following table sets forth the Company’s investments in marketable debt and equity securities reported at fair value as of March 31, 2010 and December 31, 2009 by security class and by level within the fair value hierarchy. The security classes are determined based on the nature and risk of the security and are consistent with how the Company manages, monitors and measures its marketable securities. These securities have been 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 securities and their placement within the fair value hierarchy levels.

 

    March 31, 2010   December 31, 2009
    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)

  $ -   $ 709   $ -   $ 709   $ -   $ 667   $ -   $ 667

Certificates of deposit (2)

                -     730     -     730     -     652     -                 652

Government debt securities

    -     145     -     145     -     152     -     152

Other debt securities

    -                 -     42     42     -     -     42     42
                                               

Subtotal

    -     1,584     42     1,626                 -     1,471     42     1,513

Equity securities:

               

Mutual funds

    75     -                 -                 75     117                 -                 -     117

Common stock

    10     -     -     10     16     -     -     16

Money market funds

    -     49     -     49     -     30     -     30
                                               

Subtotal

    85     49     -     134     133     30     -     163
                                               

Total available-for-sale

  $ 85   $ 1,633   $ 42   $ 1,760   $ 133   $ 1,501   $ 42   $ 1,676
                                               

TRADING:

               

Equity securities:

               

Mutual funds

    7     -     -     7     7     -     -     7
                                               

Total trading

    7     -     -     7     7     -     -     7
                                               

TOTAL

  $ 92   $ 1,633   $ 42   $ 1,767   $ 140   $ 1,501   $ 42   $ 1,683
                                               

Held-to-maturity securities (3)

          6           8
                       

Total marketable securities

        $ 1,773         $ 1,691
                       

 

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(1)

Amortized cost approximated fair value at March 31, 2010 and December 31, 2009, with the exception of a common stock investment with a cost basis of $5 million carried at its fair value of $10 million and $16 million as of March 31, 2010 and December 31, 2009, respectively.

(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, but meet the definition of a security under the relevant guidance and are therefore classified as available-for-sale securities.

(3)

Held-to-maturity securities are carried at amortized cost and not measured at fair value on a recurring basis. These investments consist primarily of certificates of deposit and investments in government debt securities. The amortized cost approximated fair value of the held-to-maturity securities at March 31, 2010 and December 31, 2009. As of March 31, 2010, all held-to-maturity debt securities had stated maturities within one year.

As of March 31, 2010, all available-for-sale debt securities had stated maturities within one year, with the exception of $42 million of auction rate securities and variable rate demand notes held by IPL. These securities, classified as other debt securities in the table above, had stated maturities of greater than ten years as of March 31, 2010.

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, 2010 and 2009. There were no realized gains or losses on the sale of available-for-sale securities or gains or losses included in earnings that relate to trading securities held at the reporting date. Gains and losses on the sale of investments are determined using the specific identification method. There was no other-than-temporary impairment recognized in earnings or other comprehensive income for the three months ended March 31, 2010 and 2009.

 

     Three Months Ended
March 31,
     2010     2009
     (in millions)

Gains (losses) included in other comprehensive income

   $ (6   $ -

Proceeds from sales

   $         962     $         908

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 applies hedge accounting for all contracts as long as they are eligible under the accounting standards for derivatives and hedging. Derivative transactions are not entered into for trading purposes.

 

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Table of Contents

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 2027, and are typically designated as cash flow hedges. The following table sets forth, by type of interest rate derivative, 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, 2010 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:

 

    March 31, 2010  
    Current   Maximum (1)     Weighted
Average
Remaining

Term (1)
    % of Debt
Currently Hedged
by Index (2)
 

Interest Rate Derivatives

  Derivative
Notional
  Derivative
Notional
Translated
to USD
  Derivative
Notional
  Derivative
Notional
Translated
to USD
     
    (in millions)     (in years)        

Libor (U.S. Dollar)

  2,868   $ 2,868   3,155   $ 3,155      10      71

Euribor (Euro)

  1,203     1,625   1,230     1,661      14      74

Libor (British Pound Sterling)

  49             74   49             74      8      66

City of Petersburg, IN Pollution Control Refunding Revenue Bonds Adjustable Rate (U.S. Dollar)

  40     40   40     40      13      NA (3) 

Bubor (Hungarian Forint)

  1,841     9   1,841     9      <1      62

 

(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, 2010 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 in USD.

(2)

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

(3)

The debt that was being hedged is no longer exposed to variable interest payments.

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 notionals of its cross currency derivative instruments as of March 31, 2010 which are all in qualifying cash flow hedge relationships. These swaps are amortizing and therefore the notional amount represents the maximum outstanding notional as of March 31, 2010:

 

     March 31, 2010  

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    $ 224      16      82

Euro (EUR)

   2      3      <1      <1

 

(1)

Represents the remaining tenor of our cross currency swaps weighted by the corresponding notional in USD.

(2)

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

 

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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 environments and such operations in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. Foreign currency forwards, swaps and options are utilized, where possible, to manage the risk related to fluctuations in certain foreign currencies. These foreign currency contracts range in maturity through 2011. The following tables set forth, by type of foreign currency denomination, the Company’s outstanding notionals over the remaining terms of its foreign currency derivative instruments as of March 31, 2010 regardless of whether the derivative instruments are in qualifying hedging relationships:

 

     March 31, 2010  

Foreign Currency Options

   Notional    Notional Translated
to USD (1)
     Probability  Adjusted
Notional (2)
     Weighted Average
Remaining  Term (3)
 
     (in millions)      (in years)  

Brazilian Real (BRL)

   102    $             56       $ 25       <1   

Euro (EUR)

   10      13                     8       <1   

Philippine Peso (PHP)

   380      8         2       <1   

British Pound (GBP)

   4      6         5       <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 in USD.

 

     March 31, 2010  

Foreign Currency Forwards

   Notional    Notional Translated
to USD
   Weighted Average
Remaining  Term (1)
 
     (in millions)    (in years)  

Chilean Peso (CLP)

   59,968    $ 116    <1   

Columbian Peso (COP)

   77,403                  39    <1   

Argentine Peso (ARS)

   61      14    1   

 

  (1)

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

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 being purchased or sold is denominated in a currency other than their own functional currency or the currency of the item. These contracts range in maturity through 2025. The following table sets forth, by type of foreign currency denomination, the Company’s outstanding notionals over the remaining terms of its foreign currency embedded derivative instruments as of March 31, 2010:

 

     March 31, 2010  

Embedded Foreign Currency Derivatives

   Notional    Notional Translated
to USD
   Weighted Average
Remaining  Term (1)
 
     (in millions)    (in years)  

Kazakhstani Tenge (KZT)

   44,071    $         300    11   

Philippine Peso (PHP)

   12,093      268    3   

Euro (EUR)

   11      15    3   

Argentine Peso (ARS)

   42      11    2   

Hungarian Forint (HUF)

   1,913      10    1   

Brazilian Real (BRL)

   1      <1    1   

 

  (1)

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

 

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Commodity Price Risk

We are exposed to the impact of market fluctuations in the price of electricity, fuel and environmental credits. Although we primarily consist of businesses with 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 implementation of this strategy can involve the use of commodity forward contracts, futures, swaps and options. Some of our businesses hedge certain aspects of their commodity risks using financial hedging instruments.

We also enter into short-term contracts for the supply of electricity and fuel in other competitive markets in which we operate. When hedging the output of our generation assets, we have power purchase agreements or other hedging instruments that lock in the spread in dollars per MWh between the cost of fuel to generate a unit of electricity and the price at which the electricity can be sold (“Dark Spread” where the fuel is coal). The portion of our sales and fuel purchases that are not subject to such agreements will be exposed to commodity price risk. Eastern Energy, a North America generation business, sells electricity into the power pools managed by the New York Independent System Operator (“NYISO”). In addition, Eastern Energy has hedged a portion of its power exposure for 2010 by entering into hedges of natural gas prices, as movements in natural gas prices affect power prices. While there is a strong relationship between natural gas and power prices, the natural gas hedges do not currently qualify for hedge accounting treatment. The following table sets forth the Company’s current notionals under its commodity derivative instruments at Eastern Energy and the percentage of forecasted electricity sales hedged as of March 31, 2010 for 2010 and 2011:

 

     2010     2011  

Commodity Hedges

   Notional    % of
Forecasted
Sales Hedged
    Notional    % of
Forecasted
Sales Hedged
 
     (in millions)          (in millions)       

Natural gas swaps (MMBTU)

   24    41   -    0

NYISO electricity swaps (MWh)

   1    9   <1    <1

In addition, certain of our subsidiaries have entered into PPAs and fuel supply agreements that are derivatives or contain embedded features that are considered embedded derivatives. 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 (excluding Eastern Energy, which is presented in the above table) and embedded derivative instruments as of March 31, 2010:

 

     March 31, 2010  

Commodity Derivatives

   Notional    Weighted Average
Remaining  Term (1)
 
     (in millions)    (in years)  

Natural gas (MMBTU)

   97    8   

Petcoke (Metric tons)

   15    14   

Coal (Metric tons)

   1    1   

Log wood (Tons)

   <1    3   

 

  (1)

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

 

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Accounting and Reporting

The following table sets forth the Company’s derivative instruments as of March 31, 2010 and December 31, 2009 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 consolidated balance sheets: current derivative assets in other current assets, noncurrent derivative assets in other noncurrent assets, current derivative liabilities in accounts payable and accrued liabilities, and noncurrent derivative liabilities in other long-term liabilities. Derivative assets and liabilities have been classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessments 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.

 

    March 31, 2010   December 31, 2009
    Level 1   Level 2     Level 3   Total   Level 1   Level 2   Level 3   Total
    (in millions)   (in millions)

Assets

               

Current assets:

               

Foreign exchange derivatives

  $             -   $ 6   (1)    $ -   $ 6   $ -   $ 6   $ -   $ 6

Commodity derivatives

               

Electricity

    -     22        -     22     -     22     -     22

Natural gas

    -     36        10     46     -     -     11     11

Other fuel

    -     -        13     13     -     -     17     17
                                                 

Total current assets

    -     64        23     87     -     28     28     56
                                                 

Noncurrent assets:

               

Interest rate derivatives

    -     83        -     83     -     83     2     85

Foreign exchange derivatives

    -     7   (1)      -     7     -     -     -     -
                                                 

Total noncurrent assets

    -     90        -     90     -     83     2     85
                                                 

Total assets

  $ -   $ 154      $ 23   $ 177   $ -   $ 111   $ 30   $ 141
                                                 

Liabilities

               

Current liabilities:

               

Interest rate derivatives

  $ -   $ 137   (1)    $ 8   $ 145   $ -   $ 135   $ 7   $ 142

Cross currency derivatives

    -                 -        4     4     -                 -                 -                 -

Foreign exchange derivatives

    -     3                    -     3                 -     3     -     3

Commodity derivatives

               

Electricity

    -     -        -                 -     -     2     -     2

Natural gas

    -     -        -     -     -     5     -     5

Other fuel

    -     -        2     2     -     -     2     2
                                                 

Total current liabilities

    -     140        14     154     -     145     9     154
                                                 

Noncurrent liabilities:

               

Interest rate derivatives

    -     254   (1)      10     264     -     173     7     180

Cross currency derivatives

    -     -        4     4     -     -     12     12

Foreign exchange derivatives

    -     4   (1)      1     5     -     2     -     2

Commodity derivatives

               

Natural gas

    -     -        -     -     -     -     2     2

Other fuel

    -     -        2     2     -     -     -     -
                                                 

Total noncurrent liabilities

    -     258        17     275     -     175     21     196
                                                 

Total liabilities

  $ -   $ 398      $ 31   $ 429   $ -   $ 320   $ 30   $ 350
                                                 

 

(1)

Includes the impact of consolidating Cartagena as of January 1, 2010 under variable interest entity accounting guidance as follows: $1 million of current assets, $6 million of noncurrent assets and $1 million in noncurrent liabilities on foreign exchange derivatives and $21 million of current liabilities and $44 million of noncurrent liabilities for interest rate derivatives as of March 31, 2010.

 

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The following table sets forth the fair value and balance sheet classification of derivative instruments as of March 31, 2010 and December 31, 2009:

 

    March 31, 2010   December 31, 2009
    Designated as
Hedging
Instruments
    Not Designated as
Hedging
Instruments
    Total   Designated as
Hedging
Instruments
  Not Designated as
Hedging
Instruments
  Total
    (in millions)

Assets

           

Other current assets

           

Foreign exchange derivatives

  $ -      $ 6 (1)    $ 6   $ -   $ 6   $ 6

Commodity derivatives:

           

Electricity

        22        -        22         22     -         22

Natural gas

    -        46        46     -     11     11

Other fuel

    -            13            13     -         17     17
                                       

Total other current assets

    22        65        87     22     34     56
                                       

Other assets

           

Interest rate derivatives

    83        -        83     85     -     85

Foreign exchange derivatives

    -        7   (1)      7     -     -     -
                                       

Total other assets — noncurrent

    83        7        90     85     -     85
                                       

Total assets

  $ 105      $ 72      $ 177   $ 107   $ 34   $ 141
                                       

Liabilities

           

Accounts payable and other accrued liabilities

           

Interest rate derivatives

  $ 137   (1)    $ 8      $ 145   $ 132   $ 10   $ 142

Cross currency derivatives

    4        -        4     -     -     -

Foreign exchange derivatives

    2        1        3     2     1     3

Commodity derivatives:

           

Electricity

    -        -        -     2     -     2

Natural gas

    -        -        -     -     5     5

Other fuel

    -        2        2     -     2     2
                                       

Total accounts payable and other accrued liabilities — current

    143        11        154     136     18     154
                                       

Other long-term liabilities

           

Interest rate derivatives

    247   (1)      17        264     164     16     180

Cross currency derivatives

    4        -        4     12     -     12

Foreign exchange derivatives

    -        5   (1)      5     -     2     2

Commodity derivatives

           

Natural gas

    -        -        -     -     2     2

Other fuel

    -        2        2     -     -     -
                                       

Total other long-term liabilities

    251        24        275     176     20     196
                                       

Total liabilities

  $ 394      $ 35      $ 429   $ 312   $ 38   $ 350
                                       

 

(1)

Includes the impact of consolidating Cartagena as of January 1, 2010 under variable interest entity accounting guidance as follows: $1 million of current assets, $6 million of noncurrent assets and $1 million in noncurrent liabilities on foreign exchange derivatives and $21 million of current liabilities and $44 million of noncurrent liabilities for interest rate derivatives as of March 31, 2010.

The Company has elected not to offset net 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, 2010 and December 31, 2009, we held $52 million and $8 million, respectively, of cash collateral that we received from counterparties to our derivative positions, which is classified as restricted cash and accrued and other liabilities in the condensed consolidated balance sheets. Also, at March 31, 2010 and December 31, 2009, we had no cash collateral posted with (held by) counterparties to our derivative positions.

 

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The table below sets forth the pre-tax accumulated other comprehensive income (loss) expected to be recognized as a increase (decrease) to income from continuing operations before income taxes over the next twelve months as of March 31, 2010:

 

     Accumulated
Other Comprehensive
Income (Loss)
     (in millions)

Interest rate derivative instruments

   $     (105)

Cross currency derivative instruments

   $ (2)

Foreign currency derivative instruments

   $ (3)

Commodity derivative instruments

   $ 22 

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, as depreciation is recognized for interest rate hedges during construction, as foreign currency 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 condensed consolidated statements of cash flows as operating and/or investing activities based on the nature of the underlying transaction. Additionally, $1 million of pre-tax accumulated other comprehensive (loss) income is expected to be recognized as an increase to income from continuing operations before income taxes over the next twelve months. This amount relates to a PPA that was dedesignated as a cash flow hedge because the normal purchase normal sale scope exception from derivative accounting was elected as of December 31, 2008.

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, 2010 and 2009:

 

      Gains (Losses)
Recognized in AOCL
   

Classification in Condensed
Consolidated Statement of Operations

   Gains (Losses) Reclassified
from AOCL into
Earnings
 
   Three Months Ended
March 31,
       Three Months Ended
March 31,
 
      2010      2009        2010      2009   
      (in millions)          (in millions)  

Interest rate derivatives

   $     (78 )  (3)    $         50     Interest expense    $ (38 )  (1)    $          (1 )  (1) 

Cross currency
derivatives

     (3     6      Interest expense      (1     -   
      

Foreign currency transaction gains (losses)

     -        -   

Foreign currency derivatives

     - (2)      -     

Foreign currency transaction gains (losses)

     -        -   

Commodity derivatives — electricity

     12        81     Non-regulated revenue      8        30   
                                   

Total

   $ (69   $ 137        $     (31   $ 29   
                                   

 

(1)

Excludes $5 million and $12 million of losses for the three months ended March 31, 2010 and March 31, 2009, respectively, reclassified from AOCL related to derivative instruments that previously, but no longer, qualify for cash flow hedge accounting.

(2)

De minimis amount.

(3)

Includes $20 million related to Cartagena, which was consolidated as of January 1, 2010 under variable interest entity accounting guidance.

 

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The following table sets forth the 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, 2010 and 2009:

 

         Gains (Losses)
Recognized in Earnings
 
   

Classification in Condensed
Consolidated Statement of Operations

   Three Months Ended
March 31,
 
     2010     2009   
         (in millions)  

Interest rate derivatives

  Interest expense    $ (4   $ (1

Cross currency derivatives

  Interest expense      6                   2   

Foreign currency derivatives

 

Foreign currency transaction gains (losses)

     - (1)      -   

Commodity derivatives - electricity

  Non-regulated revenue      -        (2
                  

Total

     $             2     $ (1
                  

 

  (1)

De minimis amount of ineffectiveness recognized.

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, 2010 and 2009, respectively:

 

          Gains (Losses)
Recognized in Earnings
 
    

Classification in Condensed
Consolidated Statement of Operations

   Three Months Ended
March 31,
 
      2010      2009  
          (in millions)  

Interest rate derivatives

   Interest expense    $             (4   $             (5

Foreign exchange derivatives

   Non-regulated cost of sales      2   (1)      -   
  

Foreign currency transaction gains (losses)

     (1     7  

Commodity derivatives - PPA embedded

   Non-regulated revenue      -        (5

Commodity derivatives - natural gas

   Non-regulated revenue      43        -   
   Non-regulated cost of sales      5        (2

Commodity derivatives - other fuel

   Non-regulated cost of sales      -   (2)      (11
                   

Total

      $ 45      $ (16
                   

 

  (1)

Includes $5 million related to Cartagena, which was consolidated as of January 1, 2010 under variable interest entity accounting guidance.

  (2)

De minimis amount.

In addition, IPL has two 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 on these derivatives due to changes in their fair value 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 IPL’s rates. Therefore, these gains and losses are excluded from the above table. For the three months ended March 31, 2010, the change in the fair value of these derivatives resulted in a decrease in regulatory assets of $1 million and an increase in regulatory liabilities of $1 million on the accompanying condensed consolidated balance sheet. For the three months ended March 31, 2009, the change in the fair value of these derivatives resulted in a decrease in regulatory assets of $1 million and a decrease in regulatory liabilities of $4 million on the accompanying condensed consolidated balance sheet.

 

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Credit Risk-Related Contingent Features

The following businesses have derivative agreements that contain credit contingent provisions which would permit the counterparties with which we are 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 our subsidiaries’ credit ratings and as their credit ratings are lowered the thresholds decrease, requiring more collateral support.

Eastern Energy, our generation business in New York, enters into commodity derivative transactions with several counterparties who have market exposure limits defined in their transaction agreements. Pursuant to the aforementioned credit contingent provisions, if Eastern Energy’s credit rating were to fall below the minimum thresholds established in each of the respective transaction agreements, the counterparties could demand immediate collateralization of the entire mark-to-market value of the derivatives (excluding credit valuation adjustments) if the derivatives were in a net liability position. As of March 31, 2010, Eastern Energy had no net liability positions and so it had posted no collateral. As of December 31, 2009, Eastern Energy had net liability positions of $2 million and had posted a nominal amount of collateral to support these positions based on its current credit rating and the related thresholds in the agreements.

In December 2007, Gener entered into cross currency swap agreements with a counterparty to swap Chilean inflation indexed bonds issued in December 2007 into U.S. Dollars. Pursuant to the aforementioned credit contingent provisions, if Gener’s credit rating were to fall below the minimum threshold established in the swap agreements, the counterparty can demand immediate collateralization of the entire mark-to-market value of the swaps (excluding credit valuation adjustments) if Gener is in a net liability position, which was $7 million and $12 million, respectively at March 31, 2010 and December 31, 2009. As of March 31, 2010 and December 31, 2009, Gener had posted zero and $25 million, respectively, in the form of a letter of credit to support these swaps.

6. DEBT

The Company has two types of debt reported on its condensed consolidated balance sheet: 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 and distribution companies at our subsidiaries. Non-recourse debt is generally secured by the capital stock, physical assets, contracts and cash flows of the related subsidiary. The default risk is limited to the respective business and is without recourse to the Parent Company and other subsidiaries. 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 following table summarizes the carrying amount and fair value of the Company’s recourse and non-recourse debt as of March 31, 2010 and December 31, 2009:

 

     March 31, 2010    December 31, 2009
     Carrying
Amount
   Fair Value    Carrying
Amount
   Fair Value
     (in millions)

Non-recourse debt

   $ 15,134    $ 15,437    $ 14,401    $ 14,784

Recourse debt

     5,508      5,575      5,515      5,603
                           

Total debt

   $         20,642    $         21,012    $         19,916    $         20,387
                           

 

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The fair value of non-recourse debt is estimated differently based upon the type of loan. The fair value of fixed rate loans is estimated using 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 subsidiaries or The AES Corporation. For subsidiaries located in countries with credit ratings lower than The AES Corporation, we used the appropriate country specific yield curve. For variable rate loans, carrying value approximates fair value. 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, 2010. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to March 31, 2010.

Non-Recourse Debt

Subsidiary non-recourse debt in default or accelerated, including any temporarily waived default for which a cure is not probable, is classified as current debt in the accompanying condensed consolidated balance sheets. The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of March 31, 2010:

 

Subsidiary

   Primary Nature
of Default
   March 31, 2010
      Default    Net Assets
          (in millions)

Sonel

   Covenant    $ 326    $             251

Jordan

   Covenant      209      66

Kelanitissa

   Covenant      39      17

Ebute (1)

   Covenant      6      151
            

Total

      $             580   
            

 

  (1)

Ebute, our subsidiary in Nigeria, has received a waiver of default which gives Ebute until December 31, 2010 to cure the breached covenants; however, as this waiver does not extend beyond the Company’s current reporting cycle and the probability of curing the default cannot be determined, the debt was classified as current.

None of the subsidiaries that are currently in default is a material subsidiary under the Parent Company’s corporate debt agreements which would trigger an event of default or permit acceleration under such indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact the Company’s financial position and results of operations, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary”, and thereby, upon an acceleration of its non-recourse debt, trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt agreements.

7. CONTINGENCIES AND COMMITMENTS

Environmental

The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of March 31, 2010, the Company had recorded liabilities of $44 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, 2010.

 

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The Company faces certain risks and uncertainties related to numerous 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 by-products), and certain air emissions, such as SO2 , NOx , 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, 2009.

Legislation and Regulation of GHG Emissions

Regional Greenhouse Gas Initiative.    As noted in the Company’s 2009 Form 10-K, to date, the primary regulation of GHG emissions affecting the Company’s U.S. plants has been through the Regional Greenhouse Gas Initiative (“RGGI”). Under RGGI, ten Northeastern States have coordinated to establish rules that require reductions in CO2 emissions from power plant operations within those states through a cap-and-trade program. States in which our subsidiaries have generating facilities include Connecticut, Maryland, New York and New Jersey. Under RGGI, power plants must acquire one carbon allowance through auction or in the emission trading markets for each ton of CO2 emitted. As noted in the Company’s 2009 Form 10-K, we have estimated the costs to the Company of compliance with RGGI could be approximately $17.5 million per year for 2010 and 2011.

Potential U.S. Federal GHG Legislation.    As noted in the Company’s 2009 Form 10-K, federal legislation passed the U.S. House of Representatives in 2009 that contemplates a nationwide cap-and-trade program to reduce GHG emissions. New and similar legislation may be considered in the U.S. Senate in the coming weeks and months. It is uncertain whether any such legislation will be voted on or passed by the Senate. If any such legislation is passed by the Senate, it is uncertain whether such legislation will be reconciled with the House of Representatives’ legislation and ultimately enacted into law. However, if any such legislation is enacted, the impact could be material to the Company.

EPA GHG Regulation.    As noted in the Company’s 2009 Form 10-K, the U.S. Environmental Protection Agency (“EPA”) has proposed to regulate GHG emissions under the U.S. Clean Air Act (“CAA”). The EPA has proposed a rule that would require certain existing stationary sources, such as power plants, that are planning physical changes that would increase their GHG emissions, or new sources of GHG emissions, to obtain “new source review” permits from the EPA prior to construction. In February of 2010, the EPA announced that it will not require stationary sources of GHG emissions to seek CAA permits prior to 2011. After January 2011, major sources of GHG emissions may be required to obtain or amend their Title V operating permits to reflect GHG emissions and any applicable emission limitations.

International GHG Regulation.    As noted in the Company’s 2009 Form 10-K, the primary international agreement concerning GHG emissions is the Kyoto Protocol which became effective on February 16, 2005 and requires the industrialized countries that have ratified it to significantly reduce their GHG emissions. The vast majority of the developing countries which have ratified the Kyoto Protocol have no GHG reduction requirements. Many of the countries in which the Company’s subsidiaries operate have no reduction obligations under the Kyoto Protocol. In addition, of the 29 countries in which the Company’s subsidiaries operate, all but one — the United States (including Puerto Rico) — have ratified the Kyoto Protocol. The Kyoto Protocol is currently expected to expire at the end of 2012, and countries have been unable to agree on a successor agreement. The next annual United Nations conference to develop a successor international agreement is scheduled for December 2010 in Cancun, Mexico. It currently appears unlikely that a successor agreement will be reached at such conference; however, if a successor agreement is reached the impact could be material to the Company.

 

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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 new international agreement to succeed the Kyoto Protocol will be reached. There is additional uncertainty regarding the final provisions and implementation of any potential U.S. federal or foreign country GHG legislation, the EPA’s rules regulating GHG emissions and any 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 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.

Waste Management

In the course of operations, many of the Company’s facilities generate coal combustion byproducts (“CCB”), including fly ash, requiring disposal or processing. On May 4, 2010 the EPA issued two proposed options for regulation of CCB under the Resource Conservation and Recovery Act (“RCRA”). Each option would allow for the continued beneficial use of CCB. These proposed options are subject to a 90-day period for public comment, and any such public comments will be considered by the EPA prior to promulgating a final rule. While the exact impact and compliance cost associated with future regulations of CCB cannot be established until such regulations are finalized, there can be no assurance that the Company’s business, financial condition or results of operations would not be materially and adversely affected by such regulations.

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 credits, 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 primarily 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 20 years.

The following table summarizes the Parent Company’s contingent contractual obligations as of March 31, 2010. 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 our businesses of $112 million.

 

Contingent contractual obligations

   Amount    Number of
Agreements
   Maximum Exposure Range for
Each Agreement
     (in millions)         (in millions)

Guarantees

   $         464    32    < $1 - $63

Letters of credit under the senior secured credit facility

     175    25    < $1 - $119
              

Total

   $ 639    57   
              

 

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As of March 31, 2010, The AES Corporation had $47 million of commitments to invest in subsidiaries under construction and to purchase related equipment, excluding approximately $138 million of such obligations already included in the letters of credit discussed above. The Company expects to fund these net investment commitments over time according to the following schedule: $30 million in 2010 and $17 million in 2011. The exact payment schedule will be dictated by construction milestones.

Litigation

The Company is involved in certain claims, suits and legal proceedings in the normal course of business, some of which are described below. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information currently available and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be reasonably estimated as of March 31, 2010.

In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the Fifth District Court found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the Fifth District Court to collect approximately R$1.0 billion ($559 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off from EEDSP pursuant to its privatization in 1998). In November 2002, the Fifth District Court rejected Eletropaulo’s defenses in the execution suit. Eletropaulo appealed and in September 2003, the Appellate Court of the State of Rio de Janeiro ruled that Eletropaulo was not a proper party to the litigation because any alleged liability was transferred to CTEEP pursuant to the privatization. In June 2006, the Superior Court of Justice (“SCJ”) reversed the Appellate Court’s decision and remanded the case to the Fifth District Court for further proceedings, holding that Eletropaulo’s liability, if any, should be determined by the Fifth District Court. Eletropaulo’s subsequent appeals to the Special Court (the highest court within the SCJ) and the Supreme Court of Brazil have been dismissed. Eletrobrás later requested that the amount of Eletropaulo’s alleged debt be determined by an accounting expert appointed by the Fifth District Court. Eletropaulo consented to the appointment of such an expert, subject to a reservation of rights. In February 2010, the Fifth District Court appointed an accounting expert to determine the amount of the alleged debt and the responsibility for its payment in light of the privatization. The expert’s determination will be subject to the Fifth District Court’s review and approval. If Eletropaulo is determined to be responsible for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the Fifth District Court at any time. If Eletrobrás does so, Eletropaulo will be required to provide security in the amount of its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the Fifth District Court grants such request, Eletropaulo’s results of operations may be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the Fifth District Court against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. The parties are disputing the proper venue for the CTEEP lawsuit. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 1999, a state appellate court in Minas Gerais, Brazil, granted a temporary injunction suspending the effectiveness of a shareholders’ agreement between Southern Electric Brasil Participacoes, Ltda. (“SEB”) and the state of Minas Gerais concerning CEMIG, an integrated utility in Minas Gerais. The Company’s investment in CEMIG is through SEB. This shareholders’ agreement granted SEB certain rights and powers with respect to the management of CEMIG (“Special Rights”). In March 2000, a lower state court in Minas Gerais held the shareholders’ agreement invalid where it purported to grant SEB the Special Rights and enjoined the exercise of the Special Rights. In August 2001, the state appellate court denied an appeal of the decision and

 

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extended the injunction. In October 2001, SEB filed appeals against the state appellate court’s decision with the SCJ and the Supreme Court. The state appellate court denied access of these appeals to the higher courts, and in August 2002 SEB filed interlocutory appeals against such denial with the SCJ and the Supreme Court. In December 2004, the SCJ declined to hear SEB’s appeal. In December 2009, the Supreme Court also declined to hear SEB’s appeal. In February 2010, SEB filed an appeal with the Supreme Court Collegiate. There can be no assurances that SEB will be successful in any such appeal. Failure to prevail in this matter will preclude SEB from obtaining management control of CEMIG under the Special Rights.

In August 2000, the FERC announced an investigation into the organized California wholesale power markets in order to determine whether rates were just and reasonable. Further investigations involved alleged market manipulation. FERC requested documents from each of the AES Southland, LLC plants and AES Placerita, Inc. AES Southland and AES Placerita have cooperated fully with the FERC investigations. AES Southland was not subject to refund liability because it did not sell into the organized spot markets due to the nature of its tolling agreement. After hearings at FERC, AES Placerita was found subject to refund liability of $588,000 plus interest for spot sales to the California Power Exchange from October 2, 2000 to June 20, 2001. As FERC investigations and hearings progressed, numerous appeals on related issues were filed with the U.S. Court of Appeals for the Ninth Circuit. Over the past five years, the Ninth Circuit issued several opinions that had the potential to expand the scope of the FERC proceedings and increase refund exposure for AES Placerita and other sellers of electricity. Following remand of one of the Ninth Circuit appeals in March 2009, FERC started a new hearing process involving AES Placerita and other sellers. In May 2009, AES Placerita entered into a settlement, subject to FERC approval, concerning the claims before FERC against AES Placerita relating to the California energy crisis of 2000-2001, including the California refund proceeding. Pursuant to the settlement, AES Placerita paid $6 million and assigned a receivable of $168,119 due to it from the California Power Exchange in return for a release of all claims against it at FERC by the settling parties and other consideration. In July 2009, FERC approved the settlement as submitted. In excess of 97% of the buyers in the market elected to join the settlement. A small amount of AES Placerita’s settlement payment was placed in escrow for buyers that did not join the settlement (“non-settling parties”). It is unclear whether the escrowed funds will be enough to satisfy any additional sums that might be determined to be owed to non-settling parties at the conclusion of the FERC proceedings concerning the California energy crisis. However, any such additional sums are expected to be immaterial to the Company’s consolidated financial statements. In November 2009, one non-settling party, the Sacramento Municipal Utility District (“SMUD”), filed an appeal of the FERC’s approval of the settlement with the U.S. Court of Appeals for the District of Columbia Circuit, which was later transferred to the Ninth Circuit. SMUD’s appeal has been consolidated with other appeals from FERC orders relating to the California energy crisis and stayed pending further order of the court. The settlement agreement is still effective and will continue to remain effective unless it is vacated by the Ninth Circuit.

In August 2001, the Grid Corporation of Orissa, India, now Gridco Ltd (“Gridco”), filed a petition against the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company, with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO had defaulted on its obligations as an OERC-licensed distribution company, that CESCO management abandoned the management of CESCO, and asking for interim measures of protection, including the appointment of an administrator to manage CESCO. Gridco, a state-owned entity, is the sole wholesale energy provider to CESCO. Pursuant to the OERC’s August 2001 order, the management of CESCO was replaced with a government administrator who was appointed by the OERC. The OERC later held that the Company and other CESCO shareholders were not necessary or proper parties to the OERC proceeding. In August 2004, the OERC issued a notice to CESCO, the Company and others giving the recipients of the notice until November 2004 to show cause why CESCO’s distribution license should not be revoked. In response, CESCO submitted a business plan to the OERC. In February 2005, the OERC issued an order rejecting the proposed business plan. The order also stated that the CESCO distribution license would be revoked if an acceptable business plan for CESCO was not submitted to and approved by the OERC prior to March 31, 2005. In its April 2, 2005 order, the OERC revoked the CESCO distribution license. CESCO has filed an appeal against the April 2, 2005 OERC order and that appeal remains pending in the Indian courts. In addition, Gridco asserted that a comfort letter issued by the Company in

 

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connection with the Company’s indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO’s financial obligations to Gridco. In December 2001, Gridco served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the CESCO Shareholders Agreement between Gridco, the Company, AES ODPL, Jyoti and CESCO (the “CESCO arbitration”). In the arbitration, Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. The Company subsequently filed an application to recover its costs of the arbitration, which is under consideration by the tribunal. In addition, in September 2007, Gridco filed a challenge of the arbitration award with the local Indian court. In June 2008, Gridco filed a separate application with the local Indian court for an order enjoining the Company from selling or otherwise transferring its shares in Orissa Power Generation Corporation Ltd’s (“OPGC”), and requiring the Company to provide security in the amount of the contested damages in the CESCO arbitration until Gridco’s challenge to the arbitration award is resolved. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In early 2002, Gridco made an application to the OERC requesting that the OERC initiate proceedings regarding the terms of OPGC’s existing PPA with Gridco. In response, OPGC filed a petition in the Indian courts to block any such OERC proceedings. In early 2005, the Orissa High Court upheld the OERC’s jurisdiction to initiate such proceedings as requested by Gridco. OPGC appealed that High Court’s decision to the Supreme Court and sought stays of both the High Court’s decision and the underlying OERC proceedings regarding the PPAs terms. In April 2005, the Supreme Court granted OPGC’s requests and ordered stays of the High Court’s decision and the OERC proceedings with respect to the PPA’s terms. The matter is awaiting further hearing. Unless the Supreme Court finds in favor of OPGC’s appeal or otherwise prevents the OERC’s proceedings regarding the PPA’s terms, the OERC will likely lower the tariff payable to OPGC under the PPA, which would have an adverse impact on OPGC’s financials. OPGC believes that it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified AES Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgás and the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo and the quality of service provided by Eletropaulo to its customers, and requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of Sao Paulo (“FSCP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. (“Light”) and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. Also, in July 2006, AES Elpa and AES Transgás filed an interlocutory appeal with the FCA, which was subsequently consolidated with the MPF’s interlocutory appeal, seeking a transfer of venue and to enjoin the FCSP from considering any of the alleged violations. In June 2009, the FCA granted the injunction sought by AES Elpa and AES Transgás and transferred the case to the Federal Court of Rio de Janeiro. MPF likely will appeal. The MPF’s lawsuit before the FCSP has been stayed pending a final decision on the interlocutory appeals. AES Elpa and AES Brasiliana (the successor of AES Transgás)

 

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believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.

AES Florestal, Ltd. (“Florestal”), had been operating a pole factory and had other assets, including a wooded area known as “Horto Renner,” in the State of Rio Grande do Sul, Brazil (collectively, “Property”). Florestal had been under the control of AES Sul (“Sul”) since October 1997, when Sul was created pursuant to a privatization by the Government of the State of Rio Grande do Sul. After it came under the control of Sul, Florestal performed an environmental audit of the entire operational cycle at the pole factory. The audit discovered 200 barrels of solid creosote waste and other contaminants at the pole factory. The audit concluded that the prior operator of the pole factory, Companhia Estadual de Energia Elétrica (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. Sul and Florestal subsequently took the initiative of communicating with Brazilian authorities, as well as CEEE, about the adoption of containment and remediation measures. The Public Attorney’s Office has initiated a civil inquiry (Civil Inquiry n. 24/05) to investigate potential civil liability and has requested that the police station of Triunfo institute a police investigation (IP number 1041/05) to investigate potential criminal liability regarding the contamination at the pole factory. The parties filed defenses in response to the civil inquiry. The Public Attorney’s Office then requested an injunction which the judge rejected on September 26, 2008. The Public Attorney’s office has a right to appeal the decision. The environmental agency (“FEPAM”) has also started a procedure (Procedure n. 088200567/059) to analyze the measures that shall be taken to contain and remediate the contamination. Also, in March 2000, Sul filed suit against CEEE in the 2nd Court of Public Treasure of Porto Alegre seeking to register in Sul’s name the Property that it acquired through the privatization but that remained registered in CEEE’s name. During those proceedings, AES subsequently waived its claim to re-register the Property and asserted a claim to recover the amounts paid for the Property. That claim is pending. In November 2005, the 7th Court of Public Treasure of Porto Alegre ruled that the Property must be returned to CEEE. CEEE has had sole possession of Horto Renner since September 2006 and of the rest of the Property since April 2006. In February 2008, Sul and CEEE signed a “Technical Cooperation Protocol” pursuant to which they requested a new deadline from FEPAM in order to present a proposal. In March 2008, the State Prosecution office filed a Public Class Action against AES Florestal, AES Sul and CEEE, requiring an injunction for the removal of the alleged sources of contamination and the payment of an indemnity in the amount of R$6 million ($3 million). The injunction was rejected and the case is in the evidentiary stage awaiting the judge’s determination concerning the production of expert evidence. The above referenced proposal was delivered on April 8, 2008. FEPAM responded by indicating that the parties should undertake the first step of the proposal which would be to retain a contractor. In its response Sul indicated that such step should be undertaken by CEEE as the relevant environmental events resulted from CEEE’s operations. It is estimated that remediation could cost approximately R$14.7 million ($8 million). Discussions between Sul and CEEE are ongoing.

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

 

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In April 2004, BNDES filed a collection suit against SEB, a subsidiary of the Company, to obtain the payment of R$3.8 billion ($2.1 billion), which includes principal, interest and penalties under the loan agreement between BNDES and SEB, the proceeds of which were used by SEB to acquire shares of CEMIG. In May 2004, the 15th Federal Circuit Court (“Circuit Court”) ordered the attachment of SEB’s CEMIG shares, which were given as collateral for the loan, as well as dividends paid by CEMIG to SEB. At the time of the attachment, the shares were worth approximately R$762 million ($426 million). In December 2006, SEB’s defense was ruled groundless by the Circuit Court. The Federal Court of Appeals affirmed that decision in February 2009. SEB intends to file further appeals. BNDES has seized a total of approximately R$760 million ($424 million) in attached dividends to date, with the approval of the Circuit Court, and is seeking to recover additional attached dividends. Also, BNDES has filed a plea to seize the attached CEMIG shares. The Circuit Court will consider BNDES’s request to seize the attached CEMIG shares after the net value of the alleged debt is recalculated in light of BNDES’s seizure of dividends. SEB believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In July 2004, the Corporación Dominicana de Empresas Eléctricas Estatales (“CDEEE”) filed lawsuits against Itabo, an affiliate of the Company, in the First and Fifth Chambers of the Civil and Commercial Court of First Instance for the National District. CDEEE alleges in both lawsuits that Itabo spent more than was necessary to rehabilitate two generation units of an Itabo power plant and, in the Fifth Chamber lawsuit, that those funds were paid to affiliates and subsidiaries of AES Gener and Coastal Itabo, Ltd. (“Coastal”), a former shareholder of Itabo, without the required approval of Itabo’s board of administration. In the First Chamber lawsuit, CDEEE seeks an accounting of Itabo’s transactions relating to the rehabilitation. In November 2004, the First Chamber dismissed the case for lack of legal basis. On appeal, in October 2005 the Court of Appeals of Santo Domingo ruled in Itabo’s favor, reasoning that it lacked jurisdiction over the dispute because the parties’ contracts mandated arbitration. The Supreme Court of Justice is considering CDEEE’s appeal of the Court of Appeals’ decision. In the Fifth Chamber lawsuit, which also names Itabo’s former president as a defendant, CDEEE seeks $15 million in damages and the seizure of Itabo’s assets. In October 2005, the Fifth Chamber held that it lacked jurisdiction to adjudicate the dispute given the arbitration provisions in the parties’ contracts. The First Chamber of the Court of Appeal ratified that decision in September 2006. In a related proceeding, in May 2005, Itabo filed a lawsuit in the U.S. District Court for the Southern District of New York seeking to compel CDEEE to arbitrate its claims. The petition was denied in July 2005. Itabo’s appeal of that decision to the U.S. Court of Appeals for the Second Circuit has been stayed since September 2006. Further, in September 2006, in an International Chamber of Commerce arbitration, an arbitral tribunal determined that it lacked jurisdiction to decide arbitration claims concerning these disputes. Itabo believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In April 2006, a putative class action complaint was filed in the U.S. District Court for the Southern District of Mississippi (“District Court”) on behalf of certain individual plaintiffs and all residents and/or property owners in the State of Mississippi who allegedly suffered harm as a result of Hurricane Katrina, and against the Company and numerous unrelated companies, whose alleged greenhouse gas emissions contributed to alleged global warming which, in turn, allegedly increased the destructive capacity of Hurricane Katrina. The plaintiffs assert unjust enrichment, civil conspiracy/aiding and abetting, public and private nuisance, trespass, negligence, and fraudulent misrepresentation and concealment claims against the defendants. The plaintiffs seek damages relating to loss of property, loss of business, clean-up costs, personal injuries and death, but do not quantify their alleged damages. In August 2007, the District Court dismissed the case. The plaintiffs subsequently appealed to the U.S. Court of Appeals for the Fifth Circuit, which heard oral arguments in November 2008. In October 2009, the Fifth Circuit affirmed the District Court’s dismissal of the plaintiffs’ unjust enrichment, fraudulent misrepresentation, and civil conspiracy claims. However, the Fifth Circuit reversed the District Court’s dismissal of the plaintiffs’ public and private nuisance, trespass, and negligence claims, and remanded those claims to the District Court for further proceedings. In March 2010, the Fifth Circuit granted the petitions for en banc rehearing filed by the Company and other defendants. In April 2010, the Fifth Circuit issued an order cancelling the May 24, 2010 en banc hearing because the Court believed it had lost its quorum for en banc review due to a recusal. The Fifth Circuit stated that further notification to the parties would follow, but the parties have not received such notification to date. The

 

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Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In July 2007, the Competition Committee of the Ministry of Industry and Trade of the Republic of Kazakhstan (the “Competition Committee”) ordered Nurenergoservice, an AES subsidiary, to pay approximately 18 billion KZT ($124 million) for alleged antimonopoly violations in 2005 through the first quarter of 2007. The Competition Committee’s order was affirmed by the economic court in April 2008 (“April 2008 Decision”). The economic court also issued an injunction to secure Nurenergoservice’s alleged liability, freezing Nurenergoservice’s bank accounts and prohibiting Nurenergoservice from transferring or disposing of its property. Nurenergoservice’s subsequent appeals to the court of appeals were rejected. In February 2009, the Antimonopoly Agency (the Competition Committee’s successor) seized approximately 783 million KZT ($5 million) from a frozen Nurenergoservice bank account in partial satisfaction of Nurenergoservice’s alleged damages liability. However, on appeal to the Kazakhstan Supreme Court, in October 2009, the Supreme Court annulled the decisions of the lower courts because of procedural irregularities and remanded the case to the economic court for reconsideration. On remand, in January 2010, the economic court reaffirmed its April 2008 Decision. Nurenergoservice has appealed. In separate but related proceedings, in August 2007, the Competition Committee ordered Nurenergoservice to pay approximately 1.8 billion KZT ($12 million) in administrative fines for its alleged antimonopoly violations. Nurenergoservice’s appeal to the administrative court was rejected in February 2009. Given the adverse court decisions against Nurenergoservice, the Antimonopoly Agency may attempt to seize Nurenergoservice’s remaining assets, which are immaterial to the Company’s consolidated financial statements. The Antimonopoly Agency has not indicated whether it intends to assert claims against Nurenergoservice for alleged antimonopoly violations post first quarter 2007. Nurenergoservice believes it has meritorious claims and defenses; however, there can be no assurances that it will prevail in these proceedings.

In December 2007, an arbitral tribunal determined that Sociedad Electrica Santiago S.A.’s (“ESSA”) gas supply contracts with members of the Sierra Chata Consortium had been properly terminated by those members in light of the restrictions that had been placed on the export of gas by the Argentine Republic. ESSA thereafter terminated its gas transportation contracts with Transportadora de Gas del Norte S.A. (“TGN”), Gasoducto GasAndes (Argentina) S.A. (“GasAndes Argentina”), and Gasoducto GasAndes S.A. (“GasAndes Chile”). The terminations of those gas transportation contracts are the subject of ongoing dispute resolution proceedings, where TGN, GasAndes Argentina, and GasAndes Chile, respectively, are claiming wrongful termination and seeking contract payments. If ESSA fails to prevail in the dispute resolution proceedings, the Company may have to record an impairment of certain of ESSA’s assets, which could be material but cannot yet be quantified. In addition, if ESSA’s terminations are determined to be wrongful, ESSA may be required to pay certain charges imposed by the Argentine Republic relating to gas supply infrastructure, which is the subject of ongoing administrative proceedings with the Argentine Republic.

In April 2009, the Antimonopoly Agency initiated an investigation of the power sales of UK HPP and Shulbinsk HPP, another hydroelectric plant under AES concession (collectively, the “Hydros”), in January through February 2009. The investigation has been suspended pending the outcome of judicial proceedings concerning the inclusion of the Hydros on the list of dominant suppliers in Eastern Kazakhstan and the legality of the underlying Antimonopoly Agency investigation. If the Hydros fail to prove in those proceedings that they are not dominant suppliers and/or that the Antimonopoly Agency’s investigation is groundless, the Antimonopoly Agency’s investigation will resume. The Hydros believe they have meritorious defenses and will assert them vigorously in any formal proceeding concerning the investigation; however, there can be no assurances that they will be successful in their efforts.

In April 2009, the Antimonopoly Agency initiated an investigation of Ust-Kamenogorsk TETS LLP’s (“UKT”) power sales in 2008 through February 2009. The Antimonopoly Agency subsequently concluded that UKT abused its market position and charged monopolistically high prices for power and should pay an administrative fine of approximately KZT 136 million ($1 million). The Antimonopoly Agency later sought an order from the administrative court requiring UKT to pay the fine. The administrative court proceedings have been suspended pending the outcome of judicial proceedings concerning UKT’s challenge of the underlying Antimonopoly Agency investigation. Those judicial proceedings are ongoing. If UKT fails to prevail in those

 

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proceedings, the administrative court likely will proceed to order UKT to pay the administrative fine and disgorge the profits from the sales at issue, estimated by the Antimonopoly Agency to be approximately 514 million KZT ($4 million). UKT believes it has meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In November 2007, the International Brotherhood of Electrical Workers, Local Union No. 1395, and sixteen individual retirees, (the “Complainants”), filed a complaint at the Indiana Utility Regulatory Commission (“IURC”) seeking enforcement of their interpretation of the 1995 final order and associated settlement agreement resolving IPL’s basic rate case. The Complainants requested that the IURC conduct an investigation of IPL’s failure to fund the Voluntary Employee Beneficiary Association Trust (“VEBA Trust”) at a level of approximately $19 million per year. The VEBA Trust was spun off to an independent trustee in 2001. The complaint sought an IURC order requiring IPL to make contributions to place the VEBA Trust in the financial position in which it allegedly would have been had IPL not ceased making annual contributions to the VEBA Trust after its spin off. The complaint also sought an IURC order requiring IPL to resume making annual contributions to the VEBA Trust. IPL filed a motion to dismiss and both parties sought summary judgment in the IURC proceeding. In May 2009, the IURC issued an order granting summary judgment in favor of IPL and in June 2009, the Complainants filed an appeal of the IURC’s May 2009 order with the Indiana Court of Appeals. On January 29, 2010, the appellate court affirmed the IURC’s determination. The Complainants filed a petition for rehearing, which was denied by the Court of Appeals in April 2010. The Complainants now have until May 10, 2010, to further appeal to the Indiana Supreme Court. IPL believes it has meritorious defenses to the Complainants’ claims and it will continue to assert them vigorously in all proceedings; however, there can be no assurances that it will be successful in its efforts.

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

A public civil action has been asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of Sao Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$817,000 ($456,000), or pay an indemnification amount of approximately R$ 9.35 million ($5 million). Eletropaulo has appealed this decision to the Supreme Court and is awaiting a decision.

In 2007, a lower court issued a decision related to a 1993 claim that was filed by the Public Attorney’s office against Eletropaulo, the São Paulo State Government, SABESP (a state owned company), CETESB (a state owned company) and DAEE (the municipal Water and Electric Energy Department), alleging that they were liable for pollution of the Billings Reservoir as a result of pumping water from Pinheiros River into Billings Reservoir. The events in question occurred while Eletropaulo was a state owned company. An initial lower court decision in 2007 found the parties liable for the payment of approximately R$ 583 million ($326 million) for remediation. Eletropaulo subsequently appealed the decision to the Appellate Court of the State of Sao Paulo which reversed the lower court decision. The Public Attorney’s Office has filed appeals to both Superior Court of Justice (“SCJ”) and the Supreme Court (“SC”) and such appeals were answered by Eletropaulo in the fourth quarter of 2009. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

 

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In November 2007, the U.S. Department of Justice (“DOJ”) notified AES Thames, LLC (“AES Thames”) that the EPA had requested that the DOJ file a federal court action against AES Thames for alleged violations of the CAA, the CWA, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and the Emergency Planning and Community Right-to-Know Act (“EPCRA”), in particular alleging that AES Thames had violated (i) the terms of its Prevention of Significant Deterioration (“PSD”) air permits in the calculation of its steam load permit limit; and (ii) the CWA, CERCLA and EPCRA in connection with two spills of chlorinating agents that occurred in 2006. The DOJ subsequently indicated that it would like to settle this matter prior to filing a suit and a consent decree has been finalized. During settlement negotiations, the DOJ and EPA agreed that a minor modification to AES Thames’ PSD permit would be acceptable to clarify AES Thames’ method of operation and the Connecticut Department of Environmental Protection issued the modified permit in April 2009. A Consent Decree, pursuant to which AES Thames will pay a $140,000 civil penalty and implement a training program designed to minimize the potential for future spills of chlorinating agents was lodged with the federal district court in Connecticut on February 26, 2010. Following consideration of any public comments on the Consent Decree, it is anticipated that the Consent Decree will be signed by the Court and become effective.

In December 2008, the National Electricity Regulatory Entity of Argentina (“ENRE”) filed a criminal action in the National Criminal and Correctional Court of Argentina against the board of directors and administrators of EDELAP. ENRE’s action concerns certain bank cancellations of EDELAP debt in 2006 and 2007, which were accomplished through transactions between the banks and related AES companies. ENRE claims that EDELAP should have reflected in its accounts the alleged benefits of the transactions that were allegedly obtained by the related companies. EDELAP believes that the allegations lack merit; however, there can be no assurances that its board and administrators will prevail in the action.

In February 2009, a CAA Section 114 information request from the EPA regarding Cayuga and Somerset was received. The request seeks various operating and testing data and other information regarding certain types of projects at the Cayuga and Somerset facilities, generally for the time period from January 1, 2000 through the date of the information request. This type of information request has been used in the past to assist the EPA in determining whether a plant is in compliance with applicable standards under the CAA. Cayuga and Somerset responded to the EPA’s information request in June 2009, and they are awaiting a response from the EPA regarding their submittal. At this time it is not possible to predict what impact, if any, this request may have on Cayuga and/or Somerset, their results of operation or their financial position.

On February 2, 2009, the Cayuga facility received a Notice of Violation from the New York State Department of Environmental Conservation (“NYSDEC”) that the facility had exceeded the permitted volume limit of coal ash that can be disposed of in the on-site landfill. Cayuga has met with NYSDEC and submitted a Landfill Liner Demonstration Report to them. Such report found that the landfill has adequate engineering integrity to support the additional coal ash and there is no inherent environmental threat. NYSDEC has indicated they accept the finding of the report. A permit modification is being sought by Cayuga that would allow for closure of this approximately 10-acre portion of the landfill, and such a permit is expected to be issued shortly. While at this time it is not possible to predict what impact, if any, this matter may have on Cayuga, its results of operation or its financial position, based upon the discussions to date, the Company does not believe the impact will be material.

In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Esado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF seeks an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA

 

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should be terminated without a finding of liability against YPF because of the allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF arbitration, TGM asserts that if it is determined that AESU is responsible for the termination of the GSA, AESU is liable for TGM’s alleged losses, including losses under the TA. The procedural schedules for the arbitrations have not been established to date. AESU believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously; however, there can be no assurances that it will be successful in its efforts.

In June 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals that the environmental permit for Empresa Electrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant has stopped as a consequence of the Supreme Court’s decision. In September 2009, the Municipality of Puchuncaví issued an order to demolish the Plant on the basis of other permitting issues. In October 2009, EEC and AES Gener filed a judicial claim against the Municipality of Puchuncaví before the Civil Judge of the City of Quintero, seeking to revoke the demolition order and asking for an immediate stay of said order. At the request of EEC and AES Gener, the Civil Judge of Quintero agreed to suspend the demolition order until a final decision on the order is issued. In December 2009, Chilean authorities approved new land use regulations that entitle EEC to apply for a new environmental permit. The new land use regulations were challenged by local groups but this challenge was declared inadmissible by the Court of Appeals of Santiago. Local groups filed a motion to reconsider this decision in the same Court but this motion was dismissed. EEC applied for a new environmental permit on January 14, 2010 and permit approval was granted by the Environmental Authority on February 26, 2010. On April 1, 2010, EEC requested the construction permits required to resume the Plant’s construction. On March 24, 2010 the Mayor of Puchuncaví and another third party challenged the environmental permit of Campiche before the Court of Appeals of Valparaiso. Subsequently, on April 12, 2010 the Mayor of Puchuncaví requested an immediate stay to the issuance of the construction permits. The Court granted the petition of the Mayor on April 13, 2010. On April 20, 2010, EEC and AES Gener filed a motion in the same court to reconsider this decision. The Court, on April 22, 2010, issued its decision releasing the stay with respect to the construction permits but maintaining the stay as to the final reception certificate, which is required to commence commercial operations. EEC and the construction contractor have agreed on a path forward while construction work suspension is ongoing and once construction is reinitiated. However, if EEC is unable to complete the project, AES may be required to record an impairment of the Campiche project proportional to its indirect ownership, which could have a material impact on earnings in the period in which it is recorded. Based on cash investments through March 31, 2010 and potential termination costs, AES could incur an impairment of approximately $188 million. In the event an impairment charge is recognized with regard to the project, the amount of such impairment will depend on a number of factors, including EEC’s ability to recover project costs.

In June 2009, the Inter-American Commission on Human Rights of the Organization of American States (“IACHR”) requested that the Republic of Panama suspend the construction of AES Changuinola S.A.’s hydroelectric project (“Project”) until the bodies of the Inter-American human rights system can issue a final decision on a petition (286/08) claiming that the construction violates the human rights of alleged indigenous communities. In July 2009, Panama responded by informing the IACHR that it would not suspend construction of the Project and requesting that the IACHR revoke its request. The IACHR heard arguments by the communities and Panama on the merits of the petition in November 2009, but has not issued a decision to date. The Company cannot predict Panama’s response to any determination on the merits of the petition by the bodies of the Inter-American human rights system.

In July 2009, AES Energía Cartagena S.R.L. (“AES Cartagena”) received notices from the Spanish national energy regulator, Comisión Nacional de Energía (“CNE”), stating that AES Cartagena’s revenues should be reduced by roughly the value of the free CO2 allowances granted to AES Cartagena for 2007, 2008, and the first half of 2009. In particular, the notices stated that CNE intended to invoice AES Cartagena to recover that value, which CNE calculated as approximately €20 million ($27 million) for 2007-2008 and an amount to be determined for the first half of 2009. In September 2009, AES Cartagena received invoices for €523,548 (approximately $704,000) for 2007 and €19,907,248 (approximately $27 million) for 2008. In October 2009,

 

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AES Cartagena filed an administrative appeal against both such invoices with the Spanish Ministry of Industry and also applied for a stay of its obligation to pay the invoices pending the hearing of that appeal. In November 2009, the appeal was unsuccessful and the application for stay was rejected. AES Cartagena subsequently paid the sums claimed by CNE and filed an appeal with the Spanish Court. There can be no assurances that the judicial appeal will be successful. AES Cartagena has demanded indemnification from GDF-Suez in relation to the CNE invoices and any future such invoices under the long-term energy agreement (the “Energy Agreement”) with GDF-Suez. However, GDF-Suez has disputed that it is responsible for the CNE invoices under the Energy Agreement. Therefore, in September 2009, AES Cartagena initiated arbitration against GDF-Suez, seeking to recover the payments made to CNE and a determination that GDF-Suez is responsible for procuring and bearing the cost of CO2 allowances that are required to offset the emissions of AES Cartagena’s power plant, which is also in dispute between the parties. If AES Cartagena does not prevail in the arbitration and is required to bear the cost of carbon compliance, its results of operations could be materially adversely affected. AES Cartagena believes it has meritorious claims and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In September 2009, the Public Defender’s Office of the State of Rio Grande do Sul (“PDO”) filed a class action against AES Sul in the 16th District Court of Porto Alegre, Rio Grande do Sul (“District Court”), claiming that AES Sul has been illegally passing PIS and COFINS taxes (taxes based on AES Sul’s income) to consumers. According to ANEEL’s Order No. 93/05, the federal laws of Brazil, and the Brazilian Constitution, energy companies such as AES Sul are entitled to highlight PIS and COFINS taxes in power bills to final consumers, as the cost of those taxes is included in the energy tariffs that are applicable to final consumers. Before AES Sul had been served with the action, the District Court dismissed the lawsuit in October 2009 on the ground that AES Sul had been properly highlighting PIS and COFINS taxes in consumer bills in accordance with Brazilian law. In April 2010, the PDO appealed to the Appellate Court of the State of Rio Grande do Sul. If the dismissal is reversed and AES Sul does not prevail in the lawsuit and is ordered to cease recovering PIS and COFINS taxes pursuant to its energy tariff, its potential prospective losses could be approximately R$9.6 million ($5 million) per month, as estimated by AES Sul. In addition, if AES Sul is ordered to reimburse consumers, its potential retrospective liability could be approximately R$1.2 billion ($670 million), as estimated by AES Sul. AES Sul believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings if it is served with the action; however, there can be no assurances that it would be successful in its efforts. Furthermore, if AES Sul does not prevail in the litigation it will seek to adjust its energy tariff to compensate it for its losses, but there can be no assurances that it would be successful in obtaining an adjusted energy tariff.

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

In November 2009 and April 2010, substantially similar personal injury lawsuits were filed by a total of 22 residents and estates of the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In both lawsuits the plaintiffs allege that the coal combustion byproducts of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic in October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs do not quantify their alleged

 

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damages, but generally allege that they are entitled to compensatory and punitive damages. The AES defendants have moved for partial dismissal of the November 2009 lawsuit on various grounds. The AES defendants have not been served with the April 2010 lawsuit to date. If they are served, the AES defendants will evaluate whether to seek dismissal of some or all of the claims alleged in that lawsuit. The AES defendants believe they have meritorious defenses to the claims asserted against them and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.

In May 2010, Lakefield Wind Project, LLC initiated arbitration against IPL, alleging that IPL had wrongfully terminated a PPA executed in June 2009, and seeking approximately $190 million in damages. Previously, in January 2010, the Indiana Utility Regulatory Commission had approved IPL’s petition for recovery of costs associated with this PPA, via a cost recovery mechanism similar to IPL’s fuel adjustment charge mechanism. However, the approval included certain limitations, restrictions, and/or conditions which IPL did not find acceptable and, therefore, it exercised its right to terminate the PPA. IPL believes it has meritorious defenses and will assert them vigorously in the arbitration; however, there can be no assurances that it will be successful in that proceeding.

8. PENSION PLANS

Total pension cost for the three months ended March 31, 2010 and 2009 included the following components:

 

     Three Months Ended March 31,  
     2010     2009  
     U.S.     Foreign     U.S.     Foreign  
     (in millions)  

Service cost

   $             2     $             5     $             2     $             3  

Interest cost

     8       125       8       100  

Expected return on plan assets

     (8     (105     (7     (81

Amortization of initial net asset

     -        -        -        (1

Amortization of prior service cost

     1       -        1       -   

Amortization of net loss

     3       3       4       1  
                                

Total pension cost

   $ 6     $ 28     $ 8     $ 22  
                                

Total employer contributions for the three months ended March 31, 2010 for the Company’s U.S. and foreign subsidiaries were $5 million and $36 million, respectively. The expected remaining scheduled annual employer contributions for 2010 are $24 million for U.S. subsidiaries and $116 million for foreign subsidiaries.

9. EQUITY

STOCK PURCHASE AGREEMENT

On March 15, 2010, the Company completed the sale of 125,468,788 shares of common stock to Terrific Investment Corporation (“Investor”), a wholly-owned subsidiary of China Investment Corporation. The shares were sold for $12.60 per share, for an aggregate purchase price of $1.58 billion. Investor’s ownership in the Company’s common stock is now approximately 15% percent of the Company’s total outstanding shares of common stock on a fully diluted basis.

On March 12, 2010, the Company and Investor entered into a stockholder agreement (the “Stockholder Agreement”). Under the Stockholder Agreement, as long as Investor holds more than 5% of the outstanding shares of common stock of the Company, Investor will have the right to designate one nominee, who must be reasonably acceptable to the Board, for election to the Board of Directors of the Company. In addition, until such

 

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time as Investor holds 5% or less of the outstanding shares of common stock, Investor has agreed to vote its shares in accordance with the recommendation of the Company on any matters submitted to a vote of the stockholders of the Company relating to the election of directors and compensation matters. Otherwise, Investor may vote its shares in its discretion. Further, under the Stockholder Agreement, Investor will be subject to a standstill restriction which generally prohibits Investor from purchasing additional securities of the Company beyond the level acquired by it under the stock purchase agreement entered into between Investor and the Company on November 6, 2009. In addition, Investor has agreed to a lock-up restriction such that Investor would not sell its shares for a period of 12 months following the closing, subject to certain exceptions. The standstill and lock-up restrictions also terminate at such time as Investor holds 5% or less of the outstanding shares of common stock. Investor will have certain registration rights and preemptive rights under the Stockholder Agreement with respect to its shares of common stock of the Company.

COMPREHENSIVE INCOME

The components of comprehensive income (loss) for the three months ended March 31, 2010 and 2009 were as follows:

 

      March 31,  
         2010             2009      
     (in millions)  

Net income

   $             402     $             501  

Change in fair value of available-for-sale securities, net of income tax benefit of $2 and $0, respectively

     (4     -   

Foreign currency translation adjustments, net of income tax benefit (expense) of $5 and $(1), respectively

     (134     (69

Derivative activity:

    

Reclassification to earnings, net of income tax (expense) benefit of ($11) and $11, respectively

     32        (6

Change in derivative fair value, net of income tax benefit (expense) of $13 and $(40), respectively

     (66     100  
                

Total change in fair value of derivatives

     (34     94  

Change in unfunded pension obligation, net of income tax expense of $1 and $0, respectively

     2       1  
                

Other comprehensive (loss) income

     (170     26  
                

Comprehensive income

     232       527  

Less: Comprehensive income attributable to noncontrolling interests(1)

     (164     (300
                

Comprehensive income attributable to The AES Corporation

   $ 68     $ 227  
                

 

(1)

Includes the income attributed to noncontrolling interests in the form of common securities and dividends on preferred stock of subsidiary.

The components of accumulated other comprehensive loss as of March 31, 2010 and December 31, 2009 were as follows:

 

     March 31,
2010
    December 31,
2009
 
     (in millions)  

Foreign currency translation adjustment

   $             2,400     $             2,312  

Unrealized derivative losses

     291       224  

Unfunded pension obligation

     192       194  

Securities available-for-sale

     (2     (6
                

Accumulated other comprehensive loss

   $ 2,881     $ 2,724  
                

 

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10. SEGMENTS

The management reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally. The Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and concluded it has the following six reportable segments:

 

   

Latin America — Generation;

 

   

Latin America — Utilities;

 

   

North America — Generation;

 

   

North America — Utilities;

 

   

Europe — Generation;

 

   

Asia — Generation.

Corporate and Other — The Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation and Climate Solutions operating segments are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our presentation of reportable segments, individually or in the aggregate. “Corporate and Other” also includes costs related to business development efforts, corporate overhead costs which are not directly associated with the operations of our six 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. In the 2009 Form 10-K, the Company changed the segment performance measures disclosed to align with how management internally reviews the results and assesses the performance of the business. Accordingly, previously reported segment information has been revised to reflect our new measure of segment performance, Adjusted Gross Margin, to conform to current year presentation.

Segment revenue includes inter-segment sales related to the transfer of electricity from generation plants to utilities within Latin America. No inter-segment revenue relationships exist between other segments. Corporate allocations include certain management fees and self insurance activity 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. All balance sheet information for businesses that were discontinued or classified as held for sale as of March 31, 2010 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.

 

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Information about the Company’s operations by segment for the three months ended March 31, 2010 and 2009 was as follows:

 

    Total Revenue   Intersegment     External Revenue
    2010     2009   2010     2009     2010   2009
    (in millions)

Revenue

           

Latin America—Generation

  $ 983     $ 892   $ (255   $ (184   $ 728   $ 708

Latin America—Utilities

    1,765       1,212     -        -        1,765     1,212

North America—Generation

    532       502     -        -        532     502

North America—Utilities

    288       290     -        -        288     290

Europe Generation

    305       204     -        -        305     204

Asia—Generation

    245       137     -        -        245     137

Corp/Other & eliminations

    (6     32             255               184       249     216
                                         

Total Revenue

  $         4,112     $         3,269   $ -      $ -      $         4,112   $         3,269
                                         

 

    Total Adjusted Gross Margin     Intersegment     External Adjusted Gross Margin  
            2010                   2009             2010     2009             2010                     2009          
    (in millions)  

Adjusted Gross Margin

           

Latin America—Generation

  $         394   $         413     $ (251   $ (180   $         143     $         233  

Latin America—Utilities

    299     221               255               184       554       405  

North America—Generation

    180     168       4       4       184       172  

North America—Utilities

    113     110       -        1       113       111  

Europe Generation

    110     73       1       1       111       74  

Asia—Generation

    96     30       1       1       97       31  

Corp/Other & eliminations

    10     (8     (10     (11     -        (19

Reconciliation to Income from Continuing Operations before Taxes

  

Depreciation and amortization

  

    (284     (235

Interest expense

  

    (393     (380

Interest income

  

    109       93  

Other expense

  

    (12     (22

Other income

  

    9       222  

Gain on sale of investments

  

    -        13  

Foreign currency transaction gains (losses) on net monetary position

  

    (51     (39

Other non-operating expense

  

    -        (10
               

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

   

  $ 580     $ 649  
               

 

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Assets by segment as of March 31, 2010 and December 31, 2009 were as follows:

 

     Total Assets
     March 31,
2010
   December  31,
2009
     (in millions)

Assets

     

Latin America—Generation

   $ 9,941    $ 9,802

Latin America—Utilities

     9,114      9,233

North America—Generation

     6,316      6,226

North America—Utilities

     3,107      3,035

Europe Generation

     3,617      2,878

Asia—Generation

     2,545      2,506

Discontinued businesses

     603      590

Corp/Other & eliminations

     6,639      5,265
             

Total Assets

   $         41,882    $         39,535
             

11. OTHER INCOME (EXPENSE)

The components of other income for the three months ended March 31, 2010 and 2009 were as follows:

 

     Three Months Ended
March 31,
         2010            2009    
     (in millions)

Tax credit settlement

   $ -    $ 129

Performance incentive fee

     -      80

Other

     9      13
             

Total other income

   $         9    $         222
             

Other income generally includes gains on asset sales and extinguishments of liabilities, favorable judgments on contingencies and income from miscellaneous transactions. Other income was $9 million for the three months ended March 31, 2010. Other income of $222 million for the three months ended March 31, 2009 primarily consisted of a favorable court decision on a legal dispute in which Eletropaulo, the Company’s utility business in Brazil, had requested reimbursement for excess non-income taxes paid from 1989 to 1992. Eletropaulo received reimbursement in the form of tax credit to be applied against future tax liabilities resulting in a $129 million gain. The net impact to the Company after noncontrolling interests was $21 million. In addition, the Company recognized income of $80 million from a performance incentive bonus for management services provided to Ekibastuz and Maikuben in 2008. The management agreement was related to the sale of these businesses in Kazakhstan in May 2008.

Other expense generally includes losses on asset sales, losses on the extinguishment of debt, contingencies and losses from miscellaneous transactions. Other expense of $12 million for the three months ended March 31, 2010 was primarily comprised of losses on disposal of assets at Eletropaulo. Other expense of $22 million for the three months ended March 31, 2009 was primarily comprised of losses on disposal of assets at Eletropaulo and Andres.

12. DISCONTINUED OPERATIONS AND HELD FOR SALE BUSINESSES

In December 2009, the Company entered into agreements to sell its interests in three generation businesses located in Pakistan and Oman, reported in the Asia Generation segment. The businesses, Lal Pir and Pak Gen, located in Pakistan, and Barka, located in Oman, will be sold to two separate buyers. The sales are expected to

 

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close in the second quarter of 2010. Upon completion of the transactions, the Company will sell its 55% ownership in Lal Pir and Pak Gen, two oil-fired facilities with respective generation capacities of 362 MW and 365 MW. Further, the Company will also sell its 35% ownership interest in Barka, a 456 MW combined cycle gas facility and water desalination plant and its 100% ownership interest in two Barka related service companies.

For the three months ended March 31, 2010, the Company recognized additional impairment of $13 million ($7 million, net of tax and noncontrolling interests), to reflect the change in the carrying value of net assets of Lal Pir and Pak Gen subsequent to meeting the held for sale criteria as of December 31, 2009. The carrying value of net assets was compared to the agreed upon sales proceeds of Lal Pir and Pak Gen, resulting in the additional impairment.

The following table summarizes the revenue, income from operations of discontinued businesses, income tax expense and impairment of discontinued operations for the three months ended March 31, 2010 and 2009:

 

     Three Months Ended
March 31,
 
         2010             2009      
     (in millions)  

Revenue

   $         185     $         109  
                

Income from operations of discontinued businesses

   $ 18     $ 20  

Income tax expense

     (1     (1
                

Income from operations of discontinued businesses, net of tax

   $ 17     $ 19  
                

Impairment of discontinued operations

   $ (13   $ -   
                

13. 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 table presents 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, 2010 and 2009. In the table below income represents the numerator and weighted-average shares represent the denominator:

 

    Three Months Ended March 31,
    2010   2009
    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

  $ 185   695   $ 0.27   $ 208   665   $ 0.31

EFFECT OF DILUTIVE SECURITIES

           

Stock options and warrants

    -   2     -     -   1     -

Restricted stock units

    -   4     -     -   -     -
                               

DILUTED EARNINGS PER SHARE

  $         185           701   $         0.27   $         208           666   $         0.31
                               

 

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There were approximately 16,446,542 and 20,849,485 additional options outstanding at March 31, 2010 and 2009, 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 exceeded the average market price during the related periods. For the three months ended March 31, 2010 and 2009, all convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. During the three months ended March 31, 2010, 1,175,236 shares of common stock were issued under the Company’s profit sharing plan and 84,622 shares of common stock were issued upon the exercise of stock options. In addition, on March 15, 2010, the Company issued 125,468,788 shares of common stock to Investor as described in Note 9 — Equity.

14. SUBSEQUENT EVENTS

On April 26, 2010, the Company announced that it had entered into an agreement to sell its 55% equity interest in Ras Laffan, in Qatar. The Company is selling its interest to its partner, the Qatar Electricity and Water Company, for approximately $190 million, subject to customary purchase price adjustments. The transaction is subject to customary approvals and is expected to close during the second half of 2010. The Ras Laffan facility is comprised of a 756 MW combined cycle gas plant and a 40 million imperial gallons per day water desalination facility. AES is also selling its interest in the associated operations company in the transaction. The business is currently reported in the Asia Generation segment and will be reported as a discontinued operation beginning in the second quarter of 2010.

 

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

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

The condensed consolidated financial statements included in Item 1. — Financial Statements of this Form 10-Q and the discussions contained herein should be read in conjunction with our 2009 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 2009 Form 10-K filed on February 25, 2010. 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 to distribute, transmit and sell electricity to end-user customers in the residential, commercial, industrial and governmental sectors within a defined service area. For the three months ended March 31, 2010, our Generation and Utilities businesses comprised approximately 46% and 54% of our consolidated revenue, respectively.

We are also continuing to expand our wind generation business and are pursuing additional opportunities in the renewable business including solar and climate solutions, which develops and invests in projects that generate greenhouse gas offsets and/or other renewable projects. These initiatives are not material contributors to our operating results, but we believe that certain of these initiatives may become material in the future. For additional information regarding our business, see Item 1. — Business of the 2009 Form 10-K.

Our Organization and Segments. The management reporting structure is organized along our two lines of business (Generation and Utilities) and three regions: (1) Latin America & Africa; (2) North America; and (3) Europe, Middle East & Asia (collectively “EMEA”), each managed by a regional president. The financial reporting segment structure uses the Company’s management reporting structure as its foundation and reflects how the Company manages the business internally. The Company applied the segment reporting accounting guidance, which provides certain quantitative thresholds and aggregation criteria, and concluded that it has the following six reportable segments:

 

   

Latin America — Generation;

 

   

Latin America — Utilities;

 

   

North America — Generation;

 

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North America — Utilities;

 

   

Europe — Generation;

 

   

Asia — Generation.

Corporate and Other. The Company’s Europe Utilities, Africa Utilities, Africa Generation, Wind Generation and Climate Solutions operating segments are reported within “Corporate and Other” because they do not meet the criteria to allow for aggregation with another operating segment or the quantitative thresholds that would require separate disclosure under segment reporting accounting guidance. None of these operating segments are currently material to our financial statement presentation of reportable segments, individually or in the aggregate. “Corporate and Other” also includes costs related to business development efforts, corporate overhead costs which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

Key Drivers of Our Results of Operations.    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 slightly 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; and in developing countries, reduction of commercial and technical losses. The operating results of our Utilities businesses are sensitive to changes in 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 affects 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 2009 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

 

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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. 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.

Global diversification also helps us to 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 2009 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 in 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 2009 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, 2010, changes in foreign currency exchange rates have had a significant impact on our operating results. If the current foreign currency exchange rate volatility continues, our gross margin and other financial metrics could be affected.

Another key driver of our results is our ability to bring new businesses into commercial operations successfully. We currently have approximately 1,600 MW of projects under construction in six countries. Our prospects for increases in 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 2009 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.

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

 

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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 greenhouse gas (“GHG”) emissions, could substantially increase our capital expenditures or other compliance costs, which could in turn have a material adverse affect on our business and results of operations. For a further discussion of the Regulatory Environment, see Note 7 — Contingencies and Commitments — Environmental, included in Item 1. — Financial Statements of this Form 10-Q and Item 1. — Business — Regulatory Matters — Environmental and Land Use Regulations and Item 1A. — Risk Factors — Risks Associated with Government Regulation and Laws of the 2009 Form 10-K.

Key Drivers of Results in the Three Months Ended March 31, 2010

During the three months ended March 31, 2010, the Company’s gross margin and net cash from operating activities increased $144 million and $327 million, respectively, while net income attributable to The AES Corporation decreased $31 million compared to the same period in 2009.

We achieved these results despite the fact that certain of our North American businesses continue to face challenges associated with low gas and power prices relative to coal. As a result of relatively low gas prices, power prices have declined which has affected the financial results of our coal-fired plants in New York. We expect these challenges to continue for the balance of 2010. Additionally, gross margin was negatively impacted by lower generation in Chile, driven by the high dispatch of Gener’s diesel units in the first quarter of 2009 as a result of lower available capacity in the system and the Chilean earthquake at the end of February 2010. Despite these challenges, gross margin and net cash provided by operating activities increased due to the favorable impact of foreign currency translation, better operating performance at certain businesses and improved management of working capital. In particular, the Company’s gross margin and net cash provided by operating activities benefited from the following:

 

   

the favorable impact of foreign currency translation gains on the gross margin of certain of our international operations, particularly in Brazil;

 

   

better operating performance at certain of our operations in Asia and Latin America; and

 

   

improved collections and payables management at certain of our businesses in Latin America offset in part by an increase in accounts receivable in Asia as a result of an increase in revenue in the period.

An example of where higher demand and favorable market conditions benefited the Company in the first quarter of 2010 took place at Masinloc, our generation business in the Philippines. Masinloc completed its plant overhauls in the second quarter of 2009 and the first quarter of 2010 that lead to higher availability and plant production in the first quarter of 2010. This improved performance allowed Masinloc to benefit from increased contract and spot market sales and favorable market prices in the Philippines in the first quarter. It is unclear if Masinloc’s favorable first quarter performance will continue for the remainder of 2010.

We expect to face continued challenges in 2010, including the challenges in North America described above. Management expects improved operating performance at certain businesses and growth from new businesses launched in 2009 or expected to launch operation in 2010 may lessen or offset the impact of the challenges described above. However, if these favorable effects do not occur or if the challenges described above impact our operations more than we currently anticipate, or if volatile foreign currencies move unfavorably, then these adverse factors may impact our gross margin, net income attributable to The AES Corporation and net cash provided by operating activities.

 

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The following briefly describes the key changes in our reported revenue, gross margin, net income attributable to The AES Corporation, diluted earnings per share from continuing operations, Adjusted Earnings per Share (a non-GAAP measure) and net cash provided by operating activities for the three months ended March 31, 2010 compared to the three months ended March 31, 2009 and should be read in conjunction with our Consolidated Results of Operations discussion below.

Performance Highlights

 

      Three Months Ended March 31,  
      2010    2009    % Change  
     (in millions)  

Revenue

   $         4,112    $         3,269            26

Gross Margin

   $ 1,000    $ 856    17

Net Income Attributable to The AES Corporation

   $ 187    $ 218    -14

Diluted Earnings per Share from Continuing Operations

   $ 0.27    $ 0.31    -13

Adjusted Earnings Per Share (a non-GAAP measure) (1)

   $ 0.26    $ 0.37    -30

Net Cash Provided by Operating Activities

   $ 684    $ 357    92

 

(1)

See reconciliation and definition below under Non-GAAP Measure.

Revenue increased $843 million, or 26%, to $4.1 billion in the three months ended March 31, 2010 compared with $3.3 billion in the three months ended March 31, 2009. Key drivers of the increase included:

 

   

the favorable impact of foreign currency of $427 million, largely driven by the Brazilian Real;

 

   

an increase in tariff rates and volume at our utilities businesses in Latin America;

 

   

the impact of the consolidation of Cartagena, in Spain, in accordance with the new consolidation accounting guidance which became effective January 1, 2010; and

 

   

higher generation availability and rates at Masinloc in the Philippines.

Gross margin increased $144 million, or 17%, to $1.0 billion in the three months ended March 31, 2010 compared with $856 million in the three months ended March 31, 2009. Key drivers of the increase included:

 

   

the favorable impact of foreign currency of $101 million, largely driven by the Brazilian Real;

 

   

higher generation availability and rates at Masinloc in the Philippines;

 

   

higher volume at our utilities businesses in Latin America;

 

   

the favorable impact of a mark-to-market derivative adjustment on natural gas hedges in New York, largely offset by unfavorable power prices;

 

   

partially offset by an increase in fixed costs, largely driven by bad debt recoveries and a reduction in bad debt expense in Brazil in 2009 that did not recur; and

 

   

lower volume at our generation business in Chile.

Net income attributable to The AES Corporation decreased $31 million, or 14%, to $187 million in the three months ended March 31, 2010 compared with $218 million in the three months ended March 31, 2009. Key drivers of the decrease included:

 

   

a decrease in other income due to a performance incentive bonus for management services provided to Ekibastuz and Maikuben which occurred in 2009; and

 

   

an increase in income tax expense as a result of the expiration of a favorable U.S. tax law and the non-taxable impact of the aforementioned performance incentive bonus in 2009; partially offset by

 

   

an increase in gross margin for the quarter as described above.

 

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Net cash provided by operating activities increased $327 million, or 92%, to $684 million in the three months ended March 31, 2010 compared with $357 million in the three months ended March 31, 2009 primarily due to increases in Latin America partially offset by a decrease in Asia. Please refer to Consolidated Cash Flows — Operating Activities for further discussion.

Our cash flows from operating activities may vary significantly from quarter to quarter and are influenced by such factors as our operating results, the timing of accounts receivable collections and payments of obligations or other costs. Accordingly, there is no assurance that we will achieve the amount or percentage of increase in cash flow from operations experienced in the first quarter of 2010 in future quarters.

Non-GAAP Measure

We define adjusted earnings per share (“Adjusted EPS”) as diluted earnings per share from continuing operations excluding gains or losses of the consolidated entity due to (a) mark-to-market amounts related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) significant gains or losses due to dispositions and acquisitions of business interests, (d) significant losses due to impairments, and (e) costs due to the early retirement of debt. The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. AES believes that Adjusted EPS better reflects the underlying business performance of the Company and is considered in the Company’s internal evaluation of financial performance. Factors in this determination include the variability due to mark-to-market gains or losses related to derivative transactions, currency gains or losses, losses due to impairments and strategic decisions to dispose or acquire business interests or retire debt which affect results in a given period or periods. Adjusted EPS should not be construed as an alternative to diluted earnings per share from continuing operations, which is determined in accordance with GAAP.

 

      Three Months Ended
March 31,
 
     2010     2009  

Reconciliation of Adjusted Earnings Per Share

    

Diluted earnings per share from continuing operations

   $         0.27      $         0.31   

Derivative mark-to-market (gains)/losses (1)

     (0.03 )       0.03   

Currency transaction (gains)/losses (2)

     0.02        0.03   

Disposition/acquisition (gains)/losses

     -        (0.02 )  (3) 

Impairment losses

     -        0.02   (4) 
                

Adjusted earnings per share

   $ 0.26      $ 0.37   
                

 

  (1)

Derivative mark-to-market (gains)/losses were net of income tax per share of $(0.02) and $0.01 in the three months ended March 31, 2010 and 2009, respectively.

  (2)

Unrealized foreign currency transaction (gains)/losses were net of income tax per share of $0.00 and $0.02 in the three months ended March 31, 2010 and 2009, respectively.

  (3)

Amount includes: Kazakhstan gain of $13 million, or $0.02 per share, related to the reversal of a withholding tax contingency. There were no taxes associated with this transaction.

  (4)

Amount includes: Nontaxable impairment of the Company’s investment in “blue gas” (coal to gas) technology of $10 million, or $0.02 per share.

Management’s Priorities

Management continues to focus on the following priorities:

 

   

Improvement of operations in the existing portfolio;

 

   

Completion of an approximately 1,600 MW construction program on time and within budget. During 2009, the Company stopped construction on its Campiche plant, as further described in Key Trends and Uncertainties — Operational Challenges below;

 

   

Prudent deployment of capital to fund growth initiatives of the Company through greenfield development or mergers and acquisitions, including $1.58 billion of proceeds received in the sale of common stock to China Investment Corporation;

 

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Completing Announced Asset Sales — In December 2009, we reached agreements to sell our entire interests in our two generation businesses in Pakistan and our entire interest in our business in Oman for aggregate gross proceeds, before purchase price adjustments, of approximately $200 million. These transactions are subject to customary purchase prices adjustments and approvals and are expected to close in the second quarter of 2010. Until the transactions close, the businesses will be reported as discontinued operations in our consolidated statements of operations. Additionally, in April 2010, we reached an agreement to sell our interest in Ras Laffan, our generation business in Qatar. Beginning in the second quarter of 2010, Ras Laffan will be reported as discontinued operations in our consolidated statements of operations.

 

   

Maximizing the use of cash, including establishment of low-cost development options, and reducing debt balances; and

 

   

Integration of new projects. During the three months ended March 31, 2010, the following projects commenced commercial operations:

 

Project

   Location    Fuel    Gross MW    AES
Equity Interest
(Percent,  Rounded)
 

Guacolda 4(1)

   Chile    Coal    152    35

Nueva Ventanas

   Chile    Coal    270    71

North Rhins

   Scotland    Wind    22    100

St. Nikola

   Bulgaria    Wind    156    89

St. Patrick

   France    Wind    35    100

 

  (1)

Guacolda is an equity method investment indirectly held by AES through Gener. The AES equity interest reflects the 29% noncontrolling interests in Gener.

Key Trends and Uncertainties

Our operations continue to face many risks as discussed in Item 1A. — Risk Factors of the 2009 Form 10-K. Some of these challenges are also described above in “Key Drivers of Results in the Three Months Ended March 31, 2010”. We continue to monitor our operations and address challenges as they arise.

Operations.    On February 27, 2010, a significant earthquake occurred in Chile. Following the earthquake, energy demand dropped due to damage to the distribution network and lower demand from our industrial customers that suffered earthquake related damage. After inspection of all the affected facilities, it was determined that there was no material damage to any of the Company’s generation facilities, outages were isolated and they continue to operate without significant interruption. It is estimated that the Company’s operating results were impacted by approximately $16 million for the quarter ended March 31, 2010.

Development.    During the past quarter, the Company has successfully completed a number of construction projects, totaling approximately 635 MW, on schedule, including Guacolda 4 and Nueva Ventanas in Chile, North Rhins in Scotland, St. Nikola in Bulgaria and St. Patrick in France. However, as discussed in Item 1A. — Risk Factors — Risks Associated with our Operations — Our business is subject to substantial development uncertainties of the 2009 Form 10-K, our development projects are subject to uncertainties. The Company has 670 MW under construction at its Maritza project in Bulgaria. Certain delays have occurred in the project. However, at this time, we believe that Maritza will still be completed by the second half of 2010. However, in the event of further delays of the project, completion of the project and commencement of commercial operations could be delayed beyond this timeframe.

In June 2009, the Supreme Court of Chile affirmed a January 2009 decision of the Valparaiso Court of Appeals that the environmental permit for Empresa Electrica Campiche’s (“EEC”) thermal power plant (“Plant”) was not properly granted and illegal. Construction of the Plant was stopped as a consequence of the Supreme Court’s decision. In September 2009, the Municipality of Puchuncaví issued an order to demolish the Plant on the basis of other permitting issues. In October 2009, EEC and AES Gener filed a judicial claim against the Municipality of Puchuncaví before the Civil Judge of the City of Quintero, seeking to revoke the demolition

 

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order and asking for an immediate stay of said order. At the request of EEC and AES Gener, the Civil Judge of Quintero agreed to suspend the demolition order until a final decision on the order is issued. In December 2009, Chilean authorities approved new land use regulations that entitled EEC to apply for a new environmental permit. The new land use regulations were challenged by local groups but this challenge was declared inadmissible by the Court of Appeals of Santiago. Local groups filed a motion to reconsider this decision in the same Court but this motion was dismissed. EEC applied for a new environmental permit on January 14, 2010 and permit approval was granted by the Environmental Authority on February 26, 2010. On April 1, 2010, EEC requested the construction permits required to resume the Plant’s construction. On March 24, 2010 the Mayor of Puchuncavi and another third party challenged the environmental permit of Campiche before the Court of Appeals of Valparaiso. Subsequently, on April 12, 2010 the Mayor of Puchuncavi requested an immediate stay to the issuance of the construction permits. The Court granted the petition of the Mayor on April 13, 2010. On April 20, 2010, EEC and AES Gener filed a motion in the same court to reconsider this decision. The Court on April 22, 2010, issued its decision releasing the stay with respect to the construction permits but maintaining the stay as to the final reception certificate, which is required to commence commercial operations.

EEC and the construction contractor have agreed on a path forward while construction work suspension is ongoing and once construction is reinitiated. However, if EEC is unable to complete the project, AES may be required to record an impairment of the Campiche project proportional to its indirect ownership, which could have a material impact on earnings in the period in which it is recorded. Based on cash investments through March 31, 2010 and potential termination costs, AES could incur an impairment of approximately $188 million. In the event an impairment charge is recognized with regard to the project, the amount of such impairment will depend on a number of factors, including EEC’s ability to recover project costs.

Impairments.    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 2009 Form 10-K, there is always a risk that “Our acquisitions may not perform as expected.” The benefits of goodwill are typically realized through the future operating results of an acquired business. Management believes that the recoverability of goodwill is positively correlated with the economic environments in which our acquired businesses operate and a severe economic downturn could negatively impact the recoverability of goodwill. Also, the evolving environmental regulations, including GHG regulations, around the globe continue to increase the operating costs of our generation businesses. In extreme situations, the environmental regulations could even make a once profitable business, uneconomic. 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 recovered through their periodic operating results. The accounting guidance, however, prohibits a 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.

As part of its 2009 annual goodwill impairment evaluation, the Company noted three businesses with an aggregate goodwill balance of $202 million, whose fair values were not higher than their carrying values by more than 10%. While there were no indicators of potential impairment during the first quarter of 2010, it is possible in the future we may incur goodwill impairment charges on these businesses or even other businesses whose fair values currently exceed their carrying values by more than 10% if any of the following events occur: a significant adverse change in business climate or legal factors, an adverse action or assessment by a regulator, sale of assets at below book value, unanticipated competition, a loss of key personnel, acquisitions not performing as expected, changing environmental regulations that significantly increase the cost of doing business, or a business reaches the end of its finite life. The likelihood of the occurrence of these events may increase because of the challenging global macroeconomic conditions.

As further described in the Company’s 2009 Form 10-K within Item 1. — Regulatory Matters — United Kingdom, the Northern Ireland Authority for Utility Regulation (“NIAUR”) has the right to require the termination of the long-term PPAs under which Kilroot, our generation business in Northern Ireland, supplies electricity to Northern Ireland Electricity plc (“NIE”) as early as 2010. One of the conditions to the early

 

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termination is 180 days notice, which was provided to Kilroot on April 30, 2010. Kilroot may not be able to replace the contract on competitive terms and upon cancellation of the PPA effective November 1, 2010 will become a merchant plant and operate under the gross mandatory pool under the single electricity market (“SEM”) in Northern Ireland. At March 31, 2010, management evaluated Kilroot’s long-lived tangible assets for potential impairment assuming the early termination of the PPA and concluded that no impairment exists at this time.

Global Recession.    The global economic slowdown has caused unprecedented market illiquidity, widening credit spreads, volatile currencies, fluctuating fuel prices and increased counterparty credit risk each of which could impact our operations. While there are indications that global economic conditions may be improving, there is still substantial risk that any recovery will be slow or that conditions could worsen.

Despite these challenges, management continues to believe that the Company can meet its near-term liquidity requirements through a combination of existing cash balances, cash provided by operating activities, financings, and, if needed, borrowings under its secured facility. Although there can be no assurance due to the challenging times currently faced by financial institutions, management believes that the participating banks under its senior secured credit facility will be able to meet their funding commitments.

The Company is subject to credit risk, which includes risk related to the ability of counterparties (such as parties to our PPAs, fuel supply agreements, our 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. While counterparty credit risk has increased in the current crisis and there can be no assurances regarding the future, the Company has not suffered any material effects related to its counterparties during 2010.

The global economic weakness could also result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development, which could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses as needed. A decline in asset value, including pension asset values, could also lead to a material increase in our obligations.

In addition, as described in Overview of Our Business, volatility in foreign currency exchange rates has had an impact on the Company’s financial results. If the current volatility in foreign currencies continues, our gross margin and other financial metrics could be affected. For further discussion of the risks associated with commodity prices, see “We may not be adequately hedged against our exposure to changes in commodity prices or interest rates” in Item 1A. — Risk Factors of the 2009 Form 10-K. It is also possible that commodity or power price volatility could continue to impact our financial results. As noted in “Key Drivers of Results on the Three Months Ended March 31, 2010,” 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 which are merchant plants that are exposed to market risk and those that have hybrid merchant risk (meaning those businesses that have a PPA in place, but purchase coal at market prices). If these conditions continue or worsen, these businesses may need to restructure their obligations or seek additional funding (including from the Parent) or face the possibility that they are unable to meet their obligations and continue operations. Any of these events could have a material impact on the Company.

In the event that global economic conditions deteriorate further, or continue for a prolonged period, there could be a material adverse impact on the Company. The Company could be materially affected if such events or other events occur such that participating lenders under its secured facility fail to meet their commitments, or the Company is unable to access the capital markets on favorable terms or at all, or is unable to raise funds through the sale of assets, or is otherwise unable to finance or refinance its activities, or if capital market disruptions result in increased borrowing costs (including with respect to interest payments on the Company’s variable rate debt) or if commodity prices affect the profitability of our plants or their ability to continue operations. The Company could also be adversely affected if the foregoing effects are exacerbated or general economic or political conditions in the markets where the Company operates deteriorate, resulting in a reduction in cash flow from operations, a reduction in the availability and/or an increase in the cost of capital, a reduction in the value of currencies in these markets relative to the U.S. dollar (which could cause currency losses), an increase in the

 

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price of commodities used in our operations and construction, or if the value of its assets remain depressed or decline 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.

Regulatory — Environment.    The Company faces certain risks and uncertainties related to numerous environmental laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion by-products), and certain air emissions, such as SO2 , NOx , 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, 2009.

Legislation and Regulation of GHG Emissions

Regional Greenhouse Gas Initiative.    As noted in the Company’s 2009 Form 10-K, to date, the primary regulation of GHG emissions affecting the Company’s U.S. plants has been through the Regional Greenhouse Gas Initiative (“RGGI”). Under RGGI, ten Northeastern States have coordinated to establish rules that require reductions in CO2 emissions from power plant operations within those states through a cap-and-trade program. States in which our subsidiaries have generating facilities include Connecticut, Maryland, New York and New Jersey. Under RGGI, power plants must acquire one carbon allowance through auction or in the emission trading markets for each ton of CO2 emitted. As noted in the Company’s 2009 Form 10-K, we have estimated the costs to the Company of compliance with RGGI could be approximately $17.5 million per year for 2010 and 2011.

Potential U.S. Federal GHG Legislation.    As noted in the Company’s 2009 Form 10-K, federal legislation passed the U.S House of Representatives in 2009 that contemplates a nationwide cap-and-trade program to reduce GHG emissions. New and similar legislation may be considered in the U.S. Senate in the coming weeks and months. It is uncertain whether any such legislation will be voted on or passed by the Senate. If any such legislation is passed by the Senate, it is uncertain whether such legislation will be reconciled with the House of Representatives’ legislation and ultimately enacted into law. However, if any such legislation is enacted, the impact could be material to the Company.

EPA GHG Regulation.    As noted in the Company’s 2009 Form 10-K, the U.S. Environmental Protection Agency (“EPA”) has proposed to regulate GHG emissions under the U.S. Clean Air Act (“CAA”). The EPA has proposed a rule that would require certain existing stationary sources, such as power plants, that are planning physical changes that would increase their GHG emissions, or new sources of GHG emissions, to obtain “new source review” permits from the EPA prior to construction. In February of 2010, the EPA announced that it will not require stationary sources of GHG emissions to seek CAA permits prior to 2011. After January 2011, major sources of GHG emissions may be required to obtain or amend their Title V operating permits to reflect GHG emissions and any applicable emission limitations.

International GHG Regulation.    As noted in the Company’s 2009 Form 10-K, the primary international agreement concerning GHG emissions is the Kyoto Protocol which became effective on February 16, 2005 and requires the industrialized countries that have ratified it to significantly reduce their GHG emissions. The vast majority of the developing countries which have ratified the Kyoto Protocol have no GHG reduction requirements. Many of the countries in which the Company’s subsidiaries operate have no reduction obligations under the Kyoto Protocol. In addition, of the 29 countries in which the Company’s subsidiaries operate, all but one — the United States (including Puerto Rico) — have ratified the Kyoto Protocol. The Kyoto Protocol is

 

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currently expected to expire at the end of 2012, and countries have been unable to agree on a successor agreement. The next annual United Nations conference to develop a successor international agreement is sched