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 June 30, 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 July 31, 2010 was 794,015,970.

 

 

 


Table of Contents

THE AES CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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    51

ITEM 3.

  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    88

ITEM 4.

  CONTROLS AND PROCEDURES    90

PART II: OTHER INFORMATION

   91

ITEM 1.

  LEGAL PROCEEDINGS    91

ITEM 1A.

  RISK FACTORS    91

ITEM 2.

  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS    91

ITEM 3.

  DEFAULTS UPON SENIOR SECURITIES    91

ITEM 4.

  REMOVED AND RESERVED    91

ITEM 5.

  OTHER INFORMATION    91

ITEM 6.

  EXHIBITS    91

 

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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
June 30,
    Six Months Ended
June 30,
 
     2010     2009     2010     2009  
     (in millions, except per share amounts)  

Revenue:

        

Regulated

   $         2,213     $         1,779     $         4,454     $         3,445  

Non-Regulated

     1,808       1,512       3,638       3,081  
                                

Total revenue

     4,021       3,291       8,092       6,526  
                                

Cost of Sales:

        

Regulated

     (1,641     (1,311     (3,307     (2,531

Non-Regulated

     (1,398     (1,177     (2,817     (2,343
                                

Total cost of sales

     (3,039     (2,488     (6,124     (4,874
                                

Gross margin

     982       803       1,968       1,652  
                                

General and administrative expenses

     (101     (87     (181     (170

Interest expense

     (394     (368     (780     (740

Interest income

     101       89       210       182  

Other expense

     (48     (30     (60     (52

Other income

     69       22       77       243  

Gain on sale of investments

     -        102       -        115  

Asset impairment expense

     (1     (1     (1     (1

Foreign currency transaction gains (losses) on net monetary position

     (71     28       (122     (11

Other non-operating expense

     (5     -        (5     (10
                                

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

     532       558       1,106       1,208  

Income tax expense

     (255     (105     (451     (279

Net equity in earnings of affiliates

     134       50       148       57  
                                

INCOME FROM CONTINUING OPERATIONS

     411       503       803       986  

Income from operations of discontinued businesses, net of income tax expense of $1, $0, $2 and $1, respectively

     27       28       50       46  

Loss from disposal of discontinued businesses, net of income tax benefit of $0, $0, $0 and $0, respectively

     (9     -        (22     -   
                                

NET INCOME

     429       531       831       1,032  

Noncontrolling interests:

        

Less: Income from continuing operations attributable to noncontrolling interests

     (277     (217     (488     (492

Less: Income from discontinued operations attributable to noncontrolling interests

     (8     (11     (12     (19
                                

Total net income attributable to noncontrolling interests

     (285     (228     (500     (511
                                

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION

   $ 144     $ 303     $ 331     $ 521  
                                

BASIC EARNINGS PER SHARE:

        

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

   $ 0.17     $ 0.43     $ 0.42     $ 0.74  

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

     0.01       0.02       0.02       0.04  
                                

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS

   $ 0.18     $ 0.45     $ 0.44     $ 0.78  
                                

DILUTED EARNINGS PER SHARE:

        

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

   $ 0.17     $ 0.43     $ 0.42     $ 0.74  

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

     0.01       0.02       0.02       0.04  
                                

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS

   $ 0.18     $ 0.45     $ 0.44     $ 0.78  
                                

AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:

        

Income from continuing operations, net of tax

   $ 134     $ 286     $ 315     $ 494  

Discontinued operations, net of tax

     10       17       16       27  
                                

Net income

   $ 144     $ 303     $ 331     $ 521  
                                

See Notes to Condensed Consolidated Financial Statements

 

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THE AES CORPORATION

Condensed Consolidated Balance Sheets

 

     June 30,
2010
    December 31,
2009
 
    

(in millions except share

and per share data)

 
     (unaudited)        

ASSETS

    

CURRENT ASSETS

    

Cash and cash equivalents

   $ 2,891     $ 1,782  

Restricted cash

     572       407  

Short-term investments

     1,716       1,648  

Accounts receivable, net of allowance for doubtful accounts of $288 and $290, respectively

     2,184       2,118  

Inventory

     551       560  

Receivable from affiliates

     16       24  

Deferred income taxes — current

     257       210  

Prepaid expenses

     172       161  

Other current assets

     1,086       1,557  

Current assets of discontinued and held for sale businesses

     119       320  
                

Total current assets

     9,564       8,787  
                

NONCURRENT ASSETS

    

Property, Plant and Equipment:

    

Land

     1,083       1,111  

Electric generation, distribution assets and other

     28,299       26,815  

Accumulated depreciation

     (9,099     (8,774

Construction in progress

     3,803       4,644  
                

Property, plant and equipment, net

     24,086       23,796  
                

Other Assets:

    

Deferred financing costs, net of accumulated amortization of $290 and $293, respectively

     374       377  

Investments in and advances to affiliates

     1,227       1,157  

Debt service reserves and other deposits

     603       595  

Goodwill

     1,293       1,299  

Other intangible assets, net of accumulated amortization of $228 and $223, respectively

     574       510  

Deferred income taxes — noncurrent

     604       587  

Other

     1,533       1,551  

Noncurrent assets of discontinued and held for sale businesses

     843       876  
                

Total other assets

     7,051       6,952  
                

TOTAL ASSETS

   $ 40,701     $ 39,535  
                

LIABILITIES AND EQUITY

    

CURRENT LIABILITIES

    

Accounts payable and other accrued liabilities

   $ 4,067     $ 4,193  

Accrued interest

     259       269  

Non-recourse debt — current

     1,433       1,718  

Recourse debt — current

     471       214  

Current liabilities of discontinued and held for sale businesses

     134       227  
                

Total current liabilities

     6,364       6,621  
                

LONG-TERM LIABILITIES

    

Non-recourse debt — noncurrent

     13,131       12,304  

Recourse debt — noncurrent

     4,637       5,301  

Deferred income taxes — noncurrent

     1,208       1,090  

Pension and other post-retirement liabilities

     1,257       1,322  

Other long-term liabilities

     2,742       3,146  

Long-term liabilities of discontinued and held for sale businesses

     643       811  
                

Total long-term liabilities

     23,618       23,974  
                

Contingencies and Commitments (see Note 8)

    

Redeemable stock of subsidiaries

     65       60  

EQUITY

    

THE AES CORPORATION STOCKHOLDERS’ EQUITY

    

Common stock ($0.01 par value, 1,200,000,000 shares authorized; 804,399,275 issued and 795,495,286 outstanding at June 30, 2010 and 677,214,493 issued and 667,679,913 outstanding at December 31, 2009

     8       7  

Additional paid-in capital

     8,457       6,868  

Retained earnings

     942       650  

Accumulated other comprehensive loss

     (2,602     (2,724

Treasury stock, at cost (8,903,989 shares at June 30, 2010 and 9,534,580 shares at December 31, 2009, respectively)

     (118     (126
                

Total The AES Corporation stockholders’ equity

     6,687       4,675  

NONCONTROLLING INTERESTS

     3,967       4,205  
                

Total equity

     10,654       8,880  
                

TOTAL LIABILITIES AND EQUITY

   $         40,701     $         39,535  
                

See Notes to Condensed Consolidated Financial Statements

 

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THE AES CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

 

     Six Months Ended
June 30,
 
     2010     2009  
     (in millions)  

OPERATING ACTIVITIES:

    

Net income

   $ 831     $ 1,032  

Adjustments to net income:

    

Depreciation and amortization

     584       498  

Loss (gain) from sale of investments and impairment expense

     18       (103

Loss on disposal and impairment write-down — discontinued operations

     18       -   

Provision for deferred taxes

     117       (111

Contingencies

     72       (54

Loss (gain) on the extinguishment of debt

     9       (3

Undistributed gain from sale of equity method investment

     (115     -   

Other

     (42     4  

Changes in operating assets and liabilities:

    

Increase in accounts receivable

     (69     (3

Increase in inventory

     (1     (11

Decrease in prepaid expenses and other current assets

     170       34  

Increase in other assets

     (51     (139

Decrease in accounts payable and accrued liabilities

     (91     (292

(Decrease) increase in income taxes and other income tax payables, net

     (90     54  

Increase (decrease) in other liabilities

     56       (32
                

Net cash provided by operating activities

     1,416       874  
                

INVESTING ACTIVITIES:

    

Capital expenditures

     (1,002     (1,193

Acquisitions — net of cash acquired

     (100     -   

Proceeds from the sale of businesses

     198       2  

Sale of short-term investments

     3,139       2,269  

Purchase of short-term investments

     (3,255     (1,740

(Increase) decrease in restricted cash

     (74     305  

(Increase) decrease in debt service reserves and other assets

     (9     40  

Affiliate advances and equity investments

     (27     (87

Proceeds from loan repayments

     132       -   

Other investing

     43       20  
                

Net cash used in investing activities

     (955     (384
                

FINANCING ACTIVITIES:

    

Issuance of common stock

     1,569       -   

Borrowings (repayments) under the revolving credit facilities, net

     88       (31

Issuance of recourse debt

     -        503  

Issuance of non-recourse debt

     1,343       816  

Repayments of recourse debt

     (406     (154

Repayments of non-recourse debt

     (1,297     (491

Payments for deferred financing costs

     (29     (53

Distributions to noncontrolling interests

     (542     (334

Contributions from noncontrolling interests

     -        74  

Financed capital expenditures

     (17     (24

Other financing

     (17     25  
                

Net cash provided by financing activities

     692       331  

Effect of exchange rate changes on cash

     (44     14  
                

Total increase in cash and cash equivalents

     1,109       835  

Cash and cash equivalents, beginning

     1,782       865  
                

Cash and cash equivalents, ending

   $         2,891     $         1,700  
                

SUPPLEMENTAL DISCLOSURES:

    

Cash payments for interest, net of amounts capitalized

   $ 764     $ 697  

Cash payments for income taxes, net of refunds

   $ 429     $ 306  

SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:

    

Assets acquired in noncash asset exchange

   $ -      $ 110  

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

Balance at January 1, 2010

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

Net income

    -     -        -     331       -        500     $         831  

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

    -     -        -     -        (6     -        (6

Foreign currency translation adjustment, net of income tax

    -     -        -     -        302       (68     234  

Change in unfunded pensions obligation, net of income tax

    -     -        -     -        2       3       5  

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

    -     -        -     -        (138     (31     (169
                   

Other comprehensive income

                64  
                   

Total comprehensive income

              $ 895  
                   

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

    -     -        -     -        -        3    

Dividends declared to noncontrolling interests

    -     -        -     -        -        (646  

Disposition of businesses

    -     -        -     -        -        (14  

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       9     -        -        -     

Stock compensation

    -     -        14     -        -        -     

Changes in the carrying amount of redeemable stock of subsidiaries

    -     -        -     7       -        -     
                                             

Balance at June 30, 2010

  $         8   $         (118   $         8,457   $         942     $         (2,602   $         3,967    
                                             
    THE AES CORPORATION STOCKHOLDERS              
    Common
Stock
  Treasury
Stock
    Additional
Paid-In
Capital
  (Accumulated
Deficit) /
Retained

Earnings
    Accumulated
Other
Comprehensive
Loss
    Noncontrolling
Interests
    Consolidated
Comprehensive
Income
 
    (in millions)  

Balance at January 1, 2009

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

Net income

    -     -        -     521       -        511     $ 1,032  

Foreign currency translation adjustment, net of income tax

    -     -        -     -        65       268       333  

Change in unfunded pensions obligation, net of income tax

    -     -        -     -        2       -        2  

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

    -     -        -     -        104       39       143  
                   

Other comprehensive income

                478  
                   

Total comprehensive income

              $ 1,510  
                   

Capital contributions from noncontrolling interests

    -     -        -     -        -        75    

Dividends declared to noncontrolling interests

    -     -        -     -        -        (412  

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

    -     18       5     -        -        -     

Stock compensation

    -     -        8     -        -        -     
                                             

Balance at June 30, 2009

  $ 7   $ (126   $ 6,845   $ 513     $ (2,847   $ 3,839    
                                             

See Notes to Condensed Consolidated Financial Statements

 

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THE AES CORPORATION

Notes to Condensed Consolidated Financial Statements

For the Three and Six Months Ended June 30, 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 13 — Discontinued Operations.

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 and six months ended June 30, 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 $40 million as accounts receivable and an associated secured borrowing on its condensed consolidated balance sheet; both of which have since grown to $50 million as of June 30, 2010, as additional interests in receivables have been sold. IPL, the Company’s integrated utility in Indianapolis, had securitized these accounts receivable through IPL Funding, a special

 

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purpose entity, 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, interests in these accounts receivable are sold, on a revolving basis, 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 responsibilities 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 is 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 June 30, 2010, total assets and total liabilities related to these VIEs were $781 million and $865 million. In addition, revenue for the three and six months ended June 30, 2010 included $85 million and $187 million, respectively, 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 June 30, 2010 and December 31, 2009:

 

     June 30,
2010
   December 31,
2009
     (in millions)

Coal, fuel oil and other raw materials

   $ 284    $ 293

Spare parts and supplies

     267      267
             

Total

   $         551    $         560
             

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 June 30, 2010 and December 31, 2009:

 

     June 30, 2010      December 31, 2009  
      Carrying
Amount
   Fair Value      Carrying
Amount
   Fair Value  
     (in millions)  

Assets

           

Marketable securities

   $ 1,758    $ 1,758       $ 1,691    $ 1,691   

Derivatives

     155      155         141      141   
                               

Total assets

   $ 1,913    $ 1,913       $ 1,832    $ 1,832   
                               

Liabilities

           

Debt

   $ 19,672    $ 20,046       $ 19,537    $ 20,008   

Derivatives

     510      510         310      310   
                               

Total liabilities

   $     20,182    $     20,556       $     19,847    $     20,318   
                               

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 a loss on disposal and impairment losses totaling $9 million and $22 million before taxes and noncontrolling interests related to nonfinancial assets and liabilities at our Pakistan businesses currently reflected as discontinued operations during the three and six months ended June 30, 2010, respectively. See further discussion of these adjustments in Note 13 — 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 comparable assets or liabilities. The income approach uses valuation techniques to convert future amounts to a

 

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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 over-the-counter derivatives, which include interest rate swaps and options, foreign currency options and forwards, and commodity swaps. In addition, the Company’s subsidiaries are counterparties to certain PPAs and fuel supply agreements that are derivatives or include embedded derivatives.

For the derivatives where there is a standard industry valuation model, the Company uses that model to estimate the fair value. For the derivatives (such the PPAs and fuel supply agreements that are derivatives or include embedded derivatives) where there is not a standard industry valuation model, the Company has created internal valuation models to estimate the fair value. For all derivatives, the income approach is used, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The following are among the most common market data used in the income approach: volatilities, spot and forward benchmark interest rates (such as LIBOR and EURIBOR), foreign exchange rates and commodity prices. Forward rates and prices generally come from published information provided by pricing services for an instrument with the same duration as the derivative instrument being valued. In situations where significant inputs are not observable, the Company uses relevant techniques to best estimate the input, such as regression, Monte Carlo simulation or similarly traded instrument available in the market.

For each derivative, the income approach is used to estimate the stream of cash flows over the remaining term of the contract. Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR and EURIBOR) plus a spread that reflects the credit or nonperformance risk. This risk is estimated by the Company using credit spreads and risk premiums that are observable in the market whenever possible or estimates of the borrowing costs based on quotes from banks, industry publications and/or information on financing closed on similar projects. To the extent that management can estimate the fair value of these assets or liabilities without the use of significant unobservable inputs, these derivatives are classified as Level 2.

 

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In certain instances, the published forward rates or prices may not extend through the remaining term of the contract and management must make assumptions to extrapolate the curve, which result in the use of unobservable inputs. In addition, in certain instances, the financial or physical instrument is traded in an inactive market requiring us to use unobservable inputs. Similarly, in certain instances, the spread that reflects the credit or nonperformance risk is unobservable. Where the use of unobservable inputs is significant, these derivatives are classified as Level 3.

The following table sets forth by level within the fair value hierarchy certain of the Company’s financial assets and liabilities that were measured at fair value on a recurring basis as of June 30, 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
June  30,
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

   $             1,749    $             125    $             1,582    $ 42

Trading securities

     8      8      -      -

Derivatives

     155      -      99      56
                           

Total assets

   $ 1,912    $ 133    $ 1,681    $ 98
                           

Liabilities

           

Derivatives

   $ 510    $ -    $ 231    $             279
                           

Total liabilities

   $ 510    $ -    $ 231    $ 279
                           
     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

   $ 310    $ -    $ 280    $ 30
                           

Total liabilities

   $ 310    $ -    $ 280    $ 30
                           

 

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The following tables present a reconciliation of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and six months ended June 30, 2010 and 2009:

 

      Three Months Ended June 30,  
     2010     2009  
     Interest
Rate
    Cross
Currency
    Foreign
Exchange
    Commodity     Total     Total  
     (in millions)  

Balance at beginning of period(1)

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

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

            

Included in earnings(2)

     -        (1     -        (1     (2     (5

Included in other comprehensive income

     (10     (28     -        -        (38     77  

Included in regulatory assets

     (2     -        -        5       3       1  

Purchases, issuances and settlements(1)

     -        2       22       (4     20       9  

Transfers of assets (liabilities) into Level 3(3)

     (209     -        (3     -        (212     -   

Transfers of (assets) liabilities out of
Level 3
(3)

     13       -        -        -        13       126  
                                                

Balance at June 30(1)

   $ (226   $       (34   $ 18     $         19     $ (223   $ (9
                                                

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

   $ (1   $ (1   $ 20     $ (6   $ 12     $ (5
                                                
     Six Months Ended June 30,  
     2010     2009  
     Interest
Rate
    Cross
Currency
    Foreign
Exchange
    Commodity     Total     Total  
     (in millions)  

Balance at beginning of period(1)

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

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

            

Included in earnings(2)

     -        5       -        2       7       (24

Included in other comprehensive income

     (13     (30     -        -        (43     140  

Included in regulatory assets

     (3     -        -        5       2       2  

Purchases, issuances and settlements(1)

     1       3       22       (12     14       (1

Transfers of assets (liabilities) into
Level 3
(3)

     (208     -        (4     -        (212     -   

Transfers of (assets) liabilities out of
Level 3
(3)

     9       -        -        -        9       (57
                                                

Balance at June 30(1)

   $ (226   $ (34   $ 18     $ 19     $ (223   $ (9
                                                

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

   $ (1   $ 5     $             20     $ (10   $ 14     $ (13
                                                

 

(1)

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

(2)

The gains (losses) included in earnings for these Level 3 derivatives are classified as follows: interest rate and cross currency derivatives as interest expense, foreign exchange derivatives as foreign currency transaction gains (losses) and commodity derivatives as non-regulated cost of sales. 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.

 

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(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. The (assets) liabilities transferred out of Level 3 during the six months ended June 30, 2009 include 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. Otherwise, the (assets) liabilities transferred out of Level 3 are primarily the result of a decrease in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments. Similarly, the assets (liabilities) transferred into Level 3 are primarily the result of an increase in the significance of unobservable inputs used to calculate the credit valuation adjustments of these derivative instruments.

The following table presents a reconciliation of available-for-sale securities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and six months ended June 30, 2010 and 2009:

 

      Three Months Ended
June 30,
    Six Months Ended
June 30,
 
      2010    2009     2010    2009  
     (in millions)  

Balance at beginning of period (1)

   $ 42    $ 13     $   42    $ 42  

Purchases, issuances and settlements

     -          (11     -      (40
                              

Balance at June 30

   $               42    $ 2     $ 42    $ 2  
                              
          

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

   $ -    $ -      $ -    $ -   
                              

 

(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.

 

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4. INVESTMENTS IN MARKETABLE SECURITIES

The following table sets forth the Company’s investments in marketable debt and equity securities as of June 30, 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 a security and are consistent with how the Company manages, monitors and measures its marketable securities.

 

     June 30, 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)

  $ -   $ 579   $ -   $ 579   $ -   $ 667   $ -   $ 667

Certificates of deposit(2)

    -     771     -     771     -     652     -     652

Government debt securities

    -     147     -     147     -     152     -     152

Other debt securities

    -     -     42     42     -     -     42     42
                                               

Subtotal

    -     1,497     42     1,539     -     1,471     42     1,513

Equity securities:

               

Mutual funds

    118     65     -     183     117     -     -     117

Common stock

    7     -     -     7     16     -     -     16

Money market funds

    -     20     -     20     -     30     -     30
                                               

Subtotal

    125     85     -     210     133     30     -     163
                                               

Total available-for-sale

  $     125   $     1,582   $     42   $     1,749   $     133   $     1,501   $     42   $     1,676
                                               

TRADING:

               

Equity securities:

               

Mutual funds

    8     -     -     8     7     -     -     7
                                               

Total trading

    8     -     -     8     7     -     -     7
                                               

TOTAL

  $ 133   $ 1,582   $ 42   $ 1,757   $ 140   $ 1,501   $ 42   $ 1,683
                                               

Held-to-maturity securities(3)

          1           8
                       

Total marketable securities

        $ 1,758         $ 1,691
                       

 

(1)

Amortized cost approximated fair value at June 30, 2010 and December 31, 2009, with the exception of certain common stock investments with a cost basis of $6 million carried at its fair value of $7 million and $16 million as of June 30, 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 government debt securities. The amortized cost approximated fair value of the held-to-maturity securities at June 30, 2010 and December 31, 2009. As of June 30, 2010, all held-to-maturity debt securities had stated maturities within one year.

As of June 30, 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 June 30, 2010.

 

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The following table summarizes the pre-tax gains and losses related to available-for-sale and trading securities for the three and six months ended June 30, 2010 and 2009. There were no realized losses on the sale of available-for-sale securities. 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 and six months ended June 30, 2010 and 2009.

 

     Three Months Ended
June 30,
   Six Months Ended
June 30,
     2010     2009    2010     2009
     (in millions)    (in millions)

Gains included in earnings that relate to trading securities held at the reporting date

   $ 1     $ 1    $ 1     $ 1

Losses included in other comprehensive income

   $ (3   $ -    $ (10   $ -

Proceeds from sales

   $     2,247     $     1,222    $     3,210     $     2,143

Gross realized gains on sales

   $ 1     $ 1    $ 1     $ 1

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Risk Management Objectives

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

Interest Rate Risk

AES and its subsidiaries utilize variable rate debt financing for construction projects and operations, resulting in an exposure to interest rate risk. Interest rate swap, cap and floor agreements are entered into to manage interest rate risk by effectively fixing or limiting the interest rate exposure on the underlying financing. These interest rate contracts range in maturity through 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 June 30, 2010 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:

 

      June 30, 2010  
     Current    Maximum (1)              

Interest Rate Derivatives

   Derivative
Notional
   Derivative
Notional
Translated
to USD
   Derivative
Notional
   Derivative
Notional
Translated
to USD
    Weighted
Average
Remaining
Term (1)
    % of Debt
Currently
Hedged
by  Index (2)
 
     (in millions)     (in years)        

Libor (U.S. Dollar)

   2,517    $     2,517    2,743    $     2,743      10      69

Euribor (Euro)

   1,185      1,450    1,242      1,519      14      73

Libor (British Pound Sterling)

   47      70    47      70      10      68

Securities Industry and Financial Markets Association Municipal Swap Index (U.S. Dollar)

   40      40    40      40       13       N/A (3) 

 

(1)

The Company’s interest rate derivative instruments primarily include accreting and amortizing notionals. The maximum derivative notional represents the largest notional at any point between June 30, 2010 and the

 

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maturity of the derivative instrument, which includes forward starting derivative instruments that generally start around when a construction project had been expected to be completed and commence operations. 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 June 30, 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 June 30, 2010:

 

     June 30, 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    $     217      16      83

 

(1)

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

(2)

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

Foreign Currency Risk

We are exposed to foreign currency risk as a result of our investments in foreign subsidiaries and affiliates. AES operates businesses in many foreign environments and such operations in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. Foreign currency options and forwards 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 June 30, 2010 regardless of whether the derivative instruments are in qualifying hedging relationships:

 

     June 30, 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)

   116    $             65       $             45    <1   

Euro (EUR)

   7      10         9    <1   

Philippine Peso (PHP)

   143      3         2    <1   

British Pound (GBP)

   3      4         4    <1   

 

  (1)

Represents contractual notionals at inception of the derivative instrument.

  (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.

 

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     June 30, 2010  

Foreign Currency Forwards

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

Chilean Peso (CLP)

   91,404    $ 178    <1   

Colombian Peso (COP)

   105,832                  54    <1   

Argentine Peso (ARS)

   76      17    <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 June 30, 2010:

 

     June 30, 2010  

Embedded Foreign Currency Derivatives

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

Philippine Peso (PHP)

   13,781    $             297    4   

Kazakhstani Tenge (KZT)

   43,644      296    10   

Argentine Peso (ARS)

   330      84    10   

Euro (EUR)

   35      43    5   

Hungarian Forint (HUF)

   927      4    1   

Brazilian Real (BRL)

   2      1    1   

 

  (1)

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

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 PPAs 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 in New York and Deepwater in Texas, two of our North America generation businesses, and IPL, a North America utility business, sell electricity into the power pools managed by the New York Independent System Operator (“NYISO”), Electric Reliability Council of Texas (“ERCOT”), and the Midwest Independent System Operator (“MISO”), respectively. 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

 

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a strong relationship between natural gas and power prices, the natural gas hedges do not currently qualify for hedge accounting treatment and are included in the below table entitled “Commodity Derivatives”. The following table sets forth the Company’s current notionals under its commodity derivative instruments at Eastern Energy, Deepwater and IPL and the percentage of forecasted electricity sales hedged as of June 30, 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)

   12      31   -      -

NYISO electricity swaps (MWh)

   1      28   - (1)    - %(1) 

ERCOT electricity swaps (MWh)

   - (1)    12   -      -

MISO electricity swaps (MWh)

   - (1)    17 %(2)    -      -

 

  (1)

De minimis amount.

  (2)

This amount is based on wholesale energy forecasts above committed regulated energy sales.

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

Nonetheless, certain of the PPAs and fuel supply agreements entered into by the Company are derivatives or contain embedded derivatives requiring separate valuation and accounting. These agreements 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 the commodity hedges at Eastern Energy, Deepwater and IPL, which are presented in the above table) and embedded derivative instruments as of June 30, 2010:

 

     June 30, 2010  

Commodity Derivatives

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

Natural gas (MMBTU)

   92      8   

Petcoke (Metric tons)

   14      14   

Coal (Metric tons)

   - (2)    <1   

Log wood (Tons)

   - (2)    3   

 

  (1)

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

  (2)

De minimis amount.

 

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Accounting and Reporting

The following table sets forth the Company’s derivative instruments as of June 30, 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.

 

    June 30, 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

  $             -   $ 21      $ 3      $ 24      $ -   $ 6   $ -   $ 6

Commodity derivatives

               

Electricity

    -     12        -        12        -     22     -     22

Natural gas

    -     20        9        29        -     -     11     11

Other

    -     1        14        15        -     -     17     17
                                                     

Total current assets

    -     54        26        80        -     28     28     56
                                                     

Noncurrent assets:

               

Interest rate derivatives

    -     37        -        37        -     83     2     85

Foreign exchange derivatives

    -     5 (1)      30        35        -     -     -     -

Other

    -     3        -        3        -     -     -     -
                                                     

Total noncurrent assets

    -     45        30        75        -     83     2     85
                                                     

Total assets

  $ -   $ 99      $ 56      $ 155      $ -   $ 111   $ 30   $ 141
                                                     

Liabilities

               

Current liabilities:

               

Interest rate derivatives

  $ -   $ 79      $ 56      $ 135 (1)    $ -   $ 118   $ 7   $ 125

Cross currency derivatives

    -     -        14        14        -     -     -                 -

Foreign exchange derivatives

    -     12        -        12        -     3     -     3

Commodity derivatives

               

Electricity

    -     4        -        4        -     2     -     2

Natural gas

    -     -        -        -        -     5                 -     5

Other

    -     -                    -                    -                    -                 -     2     2
                                                     

Total current liabilities

    -     95        70        165        -     128     9     137
                                                     

Noncurrent liabilities:

               

Interest rate derivatives

    -     135        170        305 (1)      -     150     7     157

Cross currency derivatives

    -     -        20        20        -     -     12     12

Foreign exchange derivatives

    -     1        15 (1)      16        -     2     -     2

Commodity derivatives

               

Natural gas

    -     -        1        1        -     -     2     2

Other fuel

    -                 -        3        3        -     -     -     -
                                                     

Total noncurrent liabilities

    -     136        209        345        -     152     21     173
                                                     

Total liabilities

  $ -   $ 231      $ 279      $ 510      $ -   $ 280   $ 30   $ 310
                                                     

 

(1)

Includes the impact of consolidating Cartagena beginning January 1, 2010 under VIE accounting guidance as follows: $2 million of noncurrent assets and $2 million in noncurrent liabilities on foreign exchange derivatives and $18 million of current liabilities and $53 million of noncurrent liabilities for interest rate derivatives as of June 30, 2010.

 

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The following table sets forth the fair value and balance sheet classification of derivative instruments as of June 30, 2010 and December 31, 2009:

 

    June 30, 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      $ 18 (1)    $ 24   $ -   $ 6   $ 6

Commodity derivatives:

           

Electricity

    12        -        12         22     -         22

Natural gas

    -        29        29     -     11     11

Other

    -            15            15     -         17     17
                                       

Total other current assets

    18        62        80     22     34     56
                                       

Other assets:

           

Interest rate derivatives

        37        -        37     85     -     85

Foreign exchange derivatives

    -        35 (1)      35     -     -     -

Other

    -        3        3     -     -     -
                                       

Total other assets — noncurrent

    37        38        75     85     -     85
                                       

Total assets

  $ 55      $ 100      $ 155   $ 107   $ 34   $ 141
                                       

Liabilities

           

Accounts payable and other accrued liabilities:

           

Interest rate derivatives

  $ 119 (1)    $ 16      $ 135   $ 115   $ 10   $ 125

Cross currency derivatives

    14        -        14     -     -     -

Foreign exchange derivatives

    2        10        12     2     1     3

Commodity derivatives:

           

Electricity

    4        -        4     2     -     2

Natural gas

    -        -        -     -     5     5

Other

    -        -        -     -     2     2
                                       

Total accounts payable and other accrued liabilities — current

    139        26        165     119     18     137
                                       

Other long-term liabilities:

           

Interest rate derivatives

    287 (1)      18        305     141     16     157

Cross currency derivatives

    20        -        20     12     -     12

Foreign exchange derivatives

    -        16 (1)      16     -     2     2

Commodity derivatives:

           

Natural gas

    -        1        1     -     2     2

Other fuel

    -        3        3     -     -     -
                                       

Total other long-term liabilities

    307        38        345     153     20     173
                                       

Total liabilities

  $ 446      $ 64      $ 510   $ 272   $ 38   $ 310
                                       

 

(1)

Includes the impact of consolidating Cartagena beginning January 1, 2010 under VIE accounting guidance as follows: $2 million of noncurrent assets and $2 million in noncurrent liabilities on foreign exchange derivatives and $18 million of current liabilities and $53 million of noncurrent liabilities for interest rate derivatives as of June 30, 2010.

 

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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 June 30, 2010 and December 31, 2009, we held $23 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 June 30, 2010 and December 31, 2009, we had no cash collateral posted with (held by) counterparties to our derivative positions.

The table below sets forth the pre-tax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes over the next twelve months as of June 30, 2010 for the following types of derivative instruments:

 

     Accumulated
Other Comprehensive
Income (Loss)
     (in millions)

Interest rate derivatives

   $     (113)

Cross currency derivatives

   $ (14)

Foreign currency derivatives

   $ 5

Commodity derivatives

   $ 7

The balance in accumulated other comprehensive loss related to derivative transactions that 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 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.

 

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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 and six months ended June 30, 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
June  30,
      Three Months Ended
June 30,
 
     2010     2009           2010              2009       
     (in millions)         (in millions)  

Interest rate derivatives

  $ (160 )(3)    $ 48      Interest expense   $ (34 )(1)    $ 2 (1) 
      Non-regulated cost of sales     -        -   

Cross currency
derivatives

    (27 )       28      Interest expense     -        -   
     

Foreign currency transaction gains (losses)

    -        -   

Foreign currency
derivatives

            7        - (2)    

Foreign currency transaction gains (losses)

    -        -   

Commodity derivatives — electricity

    (12 )       28      Non-regulated revenue     2                57   
                                 

Total

  $ (192   $         104        $     (32   $ 59   
                                 
     Gains (Losses)
Recognized in AOCL
   

Classification in Condensed
Consolidated Statement of Operations

  Gains (Losses) Reclassified
from AOCL into

Earnings
 
    Six Months Ended
June 30,
      Six Months Ended
June 30,
 
     2010     2009       2010     2009  
     (in millions)         (in millions)  

Interest rate derivatives

  $ (232 )(3)    $ 93      Interest expense   $ (67 )(1)    $ 1 (1) 
      Non-regulated cost of sales     -        -   

Cross currency
derivatives

    (30 )       34      Interest expense     (1 )       -   
     

Foreign currency transaction gains (losses)

    -        -   

Foreign currency
derivatives

    7        - (2)    

Foreign currency transaction gains (losses)

    -        -   

Commodity derivatives — electricity

    -                109      Non-regulated revenue         10                87   
                                 

Total

  $     (255)      $ 236        $ (58   $ 88   
                                 

 

(1)

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

(2)

De minimis amount.

(3)

Includes $12 million related to Cartagena for the three months ended June 30, 2010 and $32 million for the six months ended June 30, 2010, which was consolidated prospectively beginning January 1, 2010 under VIE accounting guidance.

 

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The following tables set 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 and six months ended June 30, 2010 and 2009:

 

    

Classification in Condensed
Consolidated Statement of Operations

   Gains (Losses)
Recognized in Earnings
 
      Three Months Ended
June 30,
 
          2010             2009      
          (in millions)  

Interest rate derivatives

  

Interest expense

   $ 6      $ 9   

Cross currency derivatives

  

Interest expense

     (1 )       -   

Foreign currency derivatives

  

Foreign currency transaction gains (losses)

     -        -   

Commodity derivatives — electricity

  

Non-regulated revenue

     -        -   
                   

Total

      $         5      $         9   
                   
    

Classification in Condensed
Consolidated Statement of Operations

   Gains (Losses)
Recognized in Earnings
 
        Six Months Ended
June 30,
 
            2010             2009      
          (in millions)  

Interest rate derivatives

   Interest expense    $ 2      $ 7   

Cross currency derivatives

   Interest expense      5        2   

Foreign currency derivatives

  

Foreign currency transaction gains (losses)

     - (1)      -   

Commodity derivatives — electricity

   Non-regulated revenue      -        (2
                   

Total

      $ 7      $ 7   
                   

The following tables set 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 and six months ended June 30, 2010 and 2009, respectively:

 

    

Classification in Condensed
Consolidated Statement of Operations

   Gains (Losses)
Recognized in Earnings
 
        Three Months Ended
June 30,
 
            2010             2009      
          (in millions)  

Interest rate derivatives

   Interest expense    $ (1   $ 5  

Foreign exchange derivatives

   Non-regulated cost of sales      -        -   
  

Foreign currency transaction gains (losses)

     (28 )(1)      (19

Commodity derivatives — natural gas

   Non-regulated revenue      (7 )       -   
   Non-regulated cost of sales              3        -   

Commodity derivatives — other

   Non-regulated revenue      4        -   
   Non-regulated cost of sales      (2 )               6  
                   

Total

      $ (31   $ (8
                   

 

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Classification in Condensed
Consolidated Statement of Operations

   Gains (Losses)
Recognized in Earnings
 
        Six Months Ended
June 30,
 
            2010             2009      
          (in millions)  

Interest rate derivatives

  

Interest expense

   $ (5   $ -   

Foreign exchange derivatives

  

Non-regulated cost of sales

     2 (1)      -   
  

Foreign currency transaction gains (losses)

     (29     (12

Commodity derivatives — natural gas

  

Non-regulated revenue

     36                -   
  

Non-regulated cost of sales

     8        -   

Commodity derivatives — other

  

Non-regulated revenue

             4        (5
  

Non-regulated cost of sales

     (2 )       (7
                   

Total

      $ 14      $ (24
                   

 

  (1)

Includes $(5) million and $0 for the three and six months ended June 30, 2010, respectively, related to Cartagena, which was consolidated as of January 1, 2010 under variable interest entity accounting guidance.

In addition, IPL has two derivative instruments for which the gains and losses are accounted for as regulatory assets or liabilities in accordance with accounting standards for regulated operations. 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. The following table sets forth the increase (decrease) in regulatory assets and liabilities resulting from the change in the fair value of these derivatives for the three and six months ended June 30, 2010 and 2009:

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2010    2009     2010    2009  
     (in millions)  

Increase (decrease) in regulatory assets

   $ 2    $ 2     $ 1    $ (2

Increase (decrease) in regulatory liabilities

   $     5    $     (1   $     6    $     (2

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 June 30, 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.

 

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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 $35 million and $12 million, respectively at June 30, 2010 and December 31, 2009. As of June 30, 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. INVESTMENTS IN AND ADVANCES TO AFFILIATES

During the second quarter of 2010, the Company, through Southern Electric Brasil Participações Ltda. (“SEB”) (an equity method investment of Cayman Energy Traders (“CET”), an equity method investment of the Company) transferred its shares of Companhia Energética de Minas Gerais (“CEMIG”), representing a 14.8% voting interest, to Andrade Gutierrez Concessões S.A. and its affiliate (jointly referred to as, “AG”). AG also assumed SEB’s debt with Banco Nacional de Desenvolvimento Econômico e Social (“BNDES”) in the amount of approximately $1.4 billion (the “BNDES Loan”) including all unpaid interest and penalties. In exchange, SEB received $25 million and obtained a full release from any claims of BNDES and originating from the BNDES Loan. See Note 8 — Contingencies and Commitments of this Form 10-Q for additional information regarding these claims and proceedings.

The Company had previously recognized its equity method investment in SEB as a $484 million net long-term liability on the Consolidated Balance Sheet. See further discussion of the background in the Company’s 2009 Form 10-K — Item 8. — Financial Statements and Supplementary Data — Note 7 — Investments In and Advances to Affiliates. The consummation of the share purchase and sale agreement along with AG’s assumption of the BNDES Loan in June 2010 resulted in the reversal of the Company’s net long-term liability along with the associated cumulative translation adjustment, resulting in the recognition of a $115 million pre-tax gain reflected in “Net equity in earnings of affiliates” on the Condensed Consolidated Statement of Operations for the three months ended June 30, 2010. Additionally, $70 million of net tax expense resulting from the CEMIG sale transaction was recorded as “income tax expense” rather than equity earnings since the expense is attributable to a consolidated corporate level partner in the CEMIG investment.

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

The following table summarizes the carrying amount and fair value of the Company’s debt as of June 30, 2010 and December 31, 2009:

 

     June 30, 2010    December 31, 2009
     Carrying
Amount
   Fair Value    Carrying
Amount
   Fair Value
     (in millions)

Non-recourse debt

   $ 14,564    $ 14,889    $ 14,022    $ 14,405

Recourse debt

     5,108      5,157      5,515      5,603
                           

Total debt

   $         19,672    $         20,046    $         19,537    $         20,008
                           

 

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Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is estimated based on quoted market prices. The fair value of non-recourse debt is estimated differently based upon the type of loan. The fair value of fixed rate loans is estimated using a discounted cash flow analysis or quoted market prices, if available. 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 June 30, 2010. The Company is not aware of any factors that would significantly affect the fair value amounts subsequent to June 30, 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 June 30, 2010:

 

Subsidiary

   Primary Nature
of Default
   June 30, 2010
      Default    Net Assets
          (in millions)

Sonel

   Covenant    $ 301    $             272

Jordan

   Covenant      209      65

St. Patrick

   Covenant      50      26

Kelanitissa

   Covenant      34      21

Ebute(1)

   Covenant      6      159

Aixi

   Payment      2      9
            

Total

      $             602   
            

 

  (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.

Additionally, approximately $43 million of non-recourse debt at Sociedad Electrica Santiago S.A. (“ESSA”), one of the Company’s subsidiaries in Latin America, has been classified as short-term because the debt may become callable within the next twelve months.

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.

Recourse Debt

On May 17, 2010, the Company closed the redemption of $400 million aggregate principal of its 8.75% Second Priority Senior Secured Notes due 2013 (“the 2013 Notes”). The 2013 Notes were redeemed on a pro rata basis at a redemption price equal to 101.458% of the principal amount redeemed. The Company recognized a

 

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pre-tax loss on the redemption of the 2013 Notes of $9 million for the three months ended June 30, 2010, which is included in “Other expense” in the accompanying condensed consolidated statement of operations. The total outstanding principal amount of the 2013 Notes remaining at June 30, 2010 was $290 million.

8. 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 June 30, 2010, the Company had recorded liabilities of $43 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 June 30, 2010.

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 byproducts), 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, if adopted, would impose a nationwide cap-and-trade program to reduce GHG emissions. In the U.S. Senate, several different draft bills pertaining to GHG legislation have been introduced in recent months, including comprehensive GHG legislation similar to the legislation that passed the U.S. House of Representatives and more limited legislation focusing only on the utility and electric generation industry. 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”) promulgated regulations governing GHG emissions from automobiles under the U.S. Clean Air

 

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Act (“CAA”). The effect of EPA’s regulation of GHG emissions from mobile sources is that certain provisions of the CAA will also apply to GHG emissions from existing stationary sources, including many U.S. power plants. In particular, after January 2, 2011, construction of new stationary sources, and modifications to existing stationary sources that result in increased GHG emissions, may require permitting under the prevention of significant deterioration (“PSD”) program of the CAA. The PSD program, if it were to become applicable to GHG emissions, would require sources that emit GHGs to obtain PSD permits prior to commencement of new construction or modifications to existing facilities. In addition, major sources of GHG emissions may be required to amend, or obtain new, Title V air permits under the CAA to reflect any applicable GHG emissions limitations.

The EPA also promulgated a final rule on June 3, 2010, (the “Tailoring Rule”) that would significantly increase the thresholds for GHG emissions that trigger PSD review and related permitting requirements. Specifically, commencing in 2011, the Tailoring Rule would increase the “major source” threshold from 250 tons per year to 75,000 tons per year for GHG emissions – this means any new source of GHG emissions would need to emit over 75,000 tons per year in order to trigger PSD review and related permitting requirements. Also, commencing in 2011, the Tailoring Rule would increase the “significance threshold” from zero tons per year to 50,000 tons per year for GHG emissions – this means any modifications to existing sources of GHG emissions would need to increase aggregate GHG emissions by over 50,000 tons per year in order to trigger PSD review and related permitting requirements. The Tailoring Rule, as currently proposed by EPA, would substantially reduce the number of sources subject to PSD requirements for GHG emissions and the number of sources required to obtain Title V air permits, although new thermal power plants would still generally be subject to PSD and Title V requirements because annual GHG emissions from such plants typically far exceed the “major source” threshold noted above. The higher “significance threshold” for increased GHG emissions from modifications to existing sources may enable some of our U.S. subsidiaries to avoid PSD requirements for many future modifications, although some projects that would expand capacity or electric output are likely to exceed the 50,000 tons per year threshold.

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 30 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.

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 or 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.

 

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As disclosed in the Company’s Form 10-K for the year ended December 31, 2009, the number of GHG emissions allowances that AES Cartagena must surrender under the European Union ETS is greater than the number of free allowances allocated to it. AES Cartagena is currently in a contractual dispute with its offtaker, GDF-Suez, regarding who has responsibility to surrender the emissions allowances necessary to meet the shortfall. AES Cartagena believes it has meritorious claims, but if AES Cartagena fails to prevail in the dispute, the resulting increase in costs could affect its ability to continue operations and/or result in a write down in the value of its assets, any of which could have a material adverse impact on the Company or its results of operations.

Other U.S. Air Emissions Regulations and Legislation

As noted in the Company’s 2009 Form 10-K, the Company’s U.S. operations are subject to regulation of air emissions such as SO2 and NOx under the “Clean Air Interstate Rule” (“CAIR”). On July 6, 2010, the EPA issued a new proposed rule (the “Transport Rule”) to replace CAIR and remedy the flaws with CAIR identified in a ruling by the U.S. Court of Appeals for the D.C. Circuit. The Transport Rule would require significant reductions in SO2 and NOx emissions in 31 states and the District of Columbia starting in 2012, including several states where subsidiaries of the Company conduct business.

The Transport Rule contemplates three possible options for reducing SO2 and NOx emissions in the designated states. The EPA’s preferred option contemplates a set limit or budget on SO2 and NOx emissions for each of the states and limited interstate trading as well as unlimited intrastate trading of SO2 and NOx emissions allowances among power plants. Affected power plants would receive emissions allowances based on the applicable state emissions budgets. The EPA’s second option under the Transport Rule would establish emission budgets for each state but only allow intrastate trading of emissions allowances. The final option would set emission rate limitations for each power plant but would allow for some intrastate averaging of emission rates. Under any of the proposed options, additional pollution control technology may be required by some of our subsidiaries, and the cost of any such technology could affect the financial condition or results of operations of these subsidiaries.

The Transport Rule is subject to public comments until 60 days after it has been published in the Federal Register, and any such public comments will be considered by the EPA prior to promulgating a final rule. A final rule is expected in the spring of 2011. In addition to the Transport Rule, legislation is also being discussed in the U.S. Congress to address emissions of SO2, and NOx . Such legislation, if enacted, could preempt the Transport Rule or any similar EPA regulation. While the exact impact and compliance cost of the Transport Rule or any federal legislation pertaining to SO2 and NOx emissions cannot be established until such regulation or legislation is finalized and implemented, the Company’s businesses and financial condition or results of operations could be materially and adversely affected by such regulation or legislation.

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 June 21, 2010 the EPA published in the Federal Register a proposed rule to regulate CCB under the Resource Conservation and Recovery Act (“RCRA”). The proposed rule provides two possible options for CCB regulation, and each option would allow for the continued beneficial use of CCB. Both options contemplate heightened structural integrity requirements for surface impoundments of CCB.

The first option contemplates regulation of CCB as a hazardous waste subject to regulation under Subtitle C of the RCRA. Under this option, existing surface impoundments containing CCB would be required to be retrofitted with composite liners and these impoundments would likely be phased out over several years. State and/or federal permit programs would be developed for storage, transport and disposal of CCB. States could bring enforcement actions for non-compliance with permitting requirements, and the EPA would have oversight responsibilities as well as the authority to bring lawsuits for non-compliance.

 

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The second option contemplates regulation of CCB under Subtitle D of the RCRA. Under this option, the EPA would create national criteria applicable to CCB landfills and surface impoundments. Existing impoundments would also be required to be retrofitted with composite liners and would likely be phased out over several years. This option would not contain federal or state permitting requirements. The primary enforcement mechanism under regulation pursuant to Subtitle D would be private lawsuits.

The two options contained in the proposed rule are subject to public comments until September 20, 2010, and any such public comments will be considered by the EPA prior to promulgating a final rule. Requirements under a final rule would not be effective until 2011 or later. 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 credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most of the contingent obligations 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 17 years.

The following table summarizes the Parent Company’s contingent contractual obligations as of June 30, 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 businesses of $106 million.

 

Contingent contractual obligations

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

Guarantees

   $         422    26    < $1 - $57

Letters of credit under the senior secured credit facility

     147    31    < $1 - $67
              

Total

   $ 569    57   
              

As of June 30, 2010, The AES Corporation had $81 million of commitments to invest in subsidiaries under construction and to purchase related equipment, excluding approximately $78 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: $41 million in 2010 and $40 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

 

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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 June 30, 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 ($558 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 (“AC”) 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 in accordance with the methodology proposed by Eletrobrás. Pursuant to its reservation of rights, Eletropaulo filed an interlocutory appeal with the AC asserting that the expert was required to determine the issues in accordance with the methodology proposed by Eletropaulo, and that Eletropaulo should be entitled to take discovery and present arguments on the issues to be determined by the expert. In April 2010, the AC issued a decision agreeing with Eletropaulo’s arguments and directing the Fifth District Court to proceed in accordance with the methodology proposed by Eletropaulo. Eletrobrás may restart the proceedings at the Fifth District Court at any time, which would proceed according to the AC’s April 2010 decision. In the Fifth District Court proceedings, the expert’s conclusions 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 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 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

 

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February 2010, SEB filed an appeal with the Supreme Court Collegiate (“SCC”). Pursuant to a settlement between SEB and BNDES (see Note 6—Investments In and Advances to Affiliates) relating to the collection suit filed by BNDES against SEB in April 2004, which is further described below, SEB filed a petition with the SCC waiving its right to pursue further litigation against the Minas Gerais and requesting that the SCC dismiss the appeal. SEB is awaiting a determination on its petition.

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. More than 98% 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 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

 

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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. In June 2010, a 2-to-1 majority of the tribunal awarded the Company some of its costs. 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. In May 2010, the MPF filed an appeal with the Superior Court of Justice challenging the transfer. 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) 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.

 

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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.

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,

 

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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. In June 2010, the Circuit Court approved a settlement between SEB and BNDES pursuant to which all of SEB’s alleged debt and the CEMIG shares were transferred to unrelated third parties (see Note 6—Investments In and Advances to Affiliates). The Circuit Court’s approval has become final and, consequently, the collection suit has been closed.

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, in October 2009, 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 February 2010, the Fifth Circuit granted the petitions for en banc rehearing filed by the Company and other defendants, and thereby vacated its October 2009 decision. In May 2010, the Fifth Circuit dismissed the appeal on the ground that it had lost its quorum for en banc review. The plaintiffs may appeal to the Supreme Court of the United States. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In 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

 

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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. In June 2010, the court of appeals (first panel) rejected Nurenergoservice’s appeal. Nurenergoservice intends to file further appeals. 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 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 had been suspended pending the outcome of judicial proceedings concerning the inclusion of the Hydros on the list of dominant suppliers in Eastern Kazakhstan but was resumed after the Hydros failed to prevail in those proceedings. The Hydros then challenged 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 had been suspended pending the outcome of a criminal investigation of UKT employees relating to the power sales that are at issue in the administrative proceedings. However, the criminal investigation was terminated recently, and the Antimonopoly Agency thereafter resumed the administrative proceedings. If the Antimonopoly Agency prevails in the administrative proceedings, UKT may be ordered 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

 

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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 granted 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 and in April 2010 a petition for reconsideration was denied. In May 2010, the Complainants appealed 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 December 2007, an arbitral tribunal terminated ESSA’s gas supply contracts with members of the Sierra Chata Consortium in light of the restrictions that had been placed on the export of gas by the Argentine Republic. ESSA thereafter terminated its gas transportation contract with Transportadora de Gas del Norte S.A. (“TGN”), and initiated arbitration seeking relief from the obligation to pay the firm tariff under, or in the alternative terminate, ESSA’s gas transportation contracts with Gasoducto GasAndes (Argentina) S.A. (“GasAndes Argentina”) and Gasoducto GasAndes S.A. (“GasAndes Chile”). TGN (which later filed a lawsuit against ESSA in Argentina), GasAndes Argentina, and GasAndes Chile dispute that the restrictions on the export of gas justify the adjustment or termination of the respective gas transportation contracts and seek due tariff payments. If ESSA fails to prevail in the dispute resolution proceedings, the Company will need to assess whether a triggering event has occurred, in which case the Company may have to record an impairment of certain of its assets, which could be material but cannot yet be quantified. In addition, if ESSA does not prevail in the ongoing lawsuit with TGN, 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 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 parties are briefing the appeal. 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 ($325 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

 

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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.

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. The period for public comments on the Consent Decree expired in June of 2010, and the Consent Decree was signed by the Court and became effective on July 29, 2010.

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 was approved by the NYSDEC on May 14, 2010 and such permit modification allows for closure of this approximately 10-acre portion of the landfill. 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

 

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seeks an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserts that if it is determined that AESU is responsible for the termination of the GSA, AESU is liable for TGM’s alleged losses, including losses under the TA. 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 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 March 24, 2010 the Mayor of Puchuncaví and another third party (collectively, “Municipality”) challenged the new environmental permit before the Court of Appeals in Valparaiso. At the parties’ request, the Court of Appeals suspended the proceedings on the new environmental permit to allow the parties to attempt to settle the challenge. On July 20, 2010, the Council of the Municipality approved a settlement agreement between EEC and the Municipality requiring the Municipality to withdraw its challenge to the new environmental permit. Subsequent to the Council’s approval, EEC and the Municipality executed the settlement agreement on July 26, 2010. Pursuant to the settlement agreement, the Municipality filed a petition with the Court of Appeals to withdraw the challenge to the new environmental permit, which petition was approved by the Court on July 27, 2010. Certain residents of the Municipality subsequently filed a petition with the Court of Appeals to reopen the proceedings on the new environmental permit, but that petition was denied by the Court of Appeals on August 2, 2010. In addition, EEC has requested that the Municipality issue the construction permits that are required to resume construction of the Plant. If the construction permits are issued, EEC intends to instruct the construction contractor to resume construction of the Plant. EEC and the construction contractor have agreed on a path forward while construction is suspended 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 June 30, 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. In June 2010, the Inter-American Court of Human Rights vacated the IACHR’s request. With respect to the merits of the underlying petition, the IACHR heard arguments by the communities and Panama 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.

 

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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 the proceeds of the sale of electricity from AES Cartagena’s plant 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 ($24 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 $639,000) for 2007 and €19,907,248 (approximately $24 million) for 2008. In October 2009, 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. In addition, in July 2010, AES Cartagena received an invoice for approximately €5.5 million ($7 million) for the free allowances relating to the first half of 2009. AES Cartagena intends to challenge that invoice. 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. In the arbitration AES Cartagena also seeks 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 and, in turn, there could be a material adverse effect on the Company and its results of operations. 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 systems on coal-fired electric generating units. A similar outcome in this case could

 

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have a material impact to IPL. IPL would seek recovery through customer rates of any operating or capital expenditures related to pollution control technology systems 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 damages, but generally allege that they are entitled to compensatory and punitive damages. The AES defendants have moved for partial dismissal of both the November 2009 and April 2010 lawsuits on various grounds. 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 and Lakefield subsequently agreed to settle their dispute. Pursuant to the settlement IPL rescinded its termination of the PPA and both parties agreed to keep the original PPA intact. The project is subject to approval by the Minnesota Public Utilities Commission.

9. PENSION PLANS

Total pension cost for the three and six months ended June 30, 2010 and 2009 included the following components:

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2010     2009     2010     2009  
     U.S.     Foreign     U.S.     Foreign     U.S.     Foreign     U.S.     Foreign  
     (in millions)     (in millions)  

Service cost

   $ 2     $ 4     $ 2     $ 3     $ 4     $ 9     $ 4     $ 6  

Interest cost

     9       126       9       111       17       251       17       211  

Expected return on plan assets

     (8     (105     (6     (90     (16     (210     (13     (171

Amortization of initial net asset

     -        -        -        -        -        -        -        (1

Amortization of prior service cost

     1       -        1       -        2       -        2       -   

Amortization of net loss

     3       4       4       2       6       7       8       3  
                                                                

Total pension cost

   $ 7     $ 29     $ 10     $ 26     $ 13     $ 57     $ 18     $ 48  
                                                                

Total employer contributions for the six months ended June 30, 2010 for the Company’s U.S. and foreign subsidiaries were $11 million and $74 million, respectively. The expected remaining scheduled annual employer contributions for 2010 are $18 million for U.S. subsidiaries and $77 million for foreign subsidiaries.

10. 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

 

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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. As of August 5, 2010, Investor has not designated its nominee for election to the Board of Directors of the Company. In addition, until such 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 and six months ended June 30, 2010 and 2009 were as follows:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
    2010     2009     2010     2009  
    (in millions)  

Net income

  $         429     $         531     $         831     $         1,032  

Change in fair value of available-for-sale securities, net of income tax (expense) benefit of $1, $0, $4 and $0, respectively

    (2     -        (6     -   

Foreign currency translation adjustments, net of income tax (expense) benefit of $3, $(65), $7 and $(66), respectively

    408       402       234       333  

Derivative activity:

       

Reclassification to earnings, net of income tax (expense) benefit of $(8), $15, $(19) and $26, respectively

    36       (37     68       (43

Change in derivative fair value, net of income tax (expense) benefit of $45, $(29), $58 and $(69), respectively

    (171     86       (237     186  
                               

Total change in fair value of derivatives

    (135     49       (169     143  

Change in unfunded pension obligation, net of income tax (expense) benefit of $(1), $(1), $(2) and $(1), respectively

    3       1       5       2  
                               

Other comprehensive income

    274       452       64       478  
                               

Comprehensive income

    703       983       895       1,510  

Less: Comprehensive income attributable to noncontrolling interests(1)

    (280     (518     (404     (818
                               

Comprehensive income attributable to The AES Corporation

  $ 423     $ 465     $ 491     $ 692  
                               

 

(1)

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

 

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The components of accumulated other comprehensive loss as of June 30, 2010 and December 31, 2009 were as follows:

 

     June 30,
2010
   December 31,
2009
 
     (in millions)  

Foreign currency translation adjustment

   $         2,010    $         2,312  

Unrealized derivative losses

     401      224  

Unfunded pension obligation

     191      194  

Securities available-for-sale

     -      (6
               

Accumulated other comprehensive loss

   $ 2,602    $ 2,724  
               

11. 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. During the second quarter of 2010, the Company modified its internal reporting structure to move the management of the Company’s generation business in Jordan, Amman East, from Asia to Europe. Accordingly, Amman East is now reported within the Europe — Generation segment. All prior periods have been retrospectively restated to reflect this change and conform to current period presentation. 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 businesses. 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.

 

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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 activities which are reflected within segment Adjusted Gross Margin. All intra-segment activity has been eliminated with respect to revenue and Adjusted Gross Margin within the segment. Inter-segment activity has been eliminated within the total consolidated results. All balance sheet information for businesses that were discontinued or classified as held for sale as of June 30, 2010 is segregated and is shown in the line “Discontinued Businesses” in the accompanying segment tables.

Information about the Company’s operations by segment for the three and six months ended June 30, 2010 and 2009 was as follows:

 

     Total Revenue    Intersegment     External Revenue

Three Months Ended June 30,

   2010     2009    2010     2009     2010    2009
     (in millions)

Latin America — Generation

   $         1,084     $ 894    $ (256   $ (202   $ 828    $ 692

Latin America — Utilities

     1,770       1,364      -        -        1,770      1,364

North America — Generation

     455       475