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UNITED STATES
SECURITIES AND EXCHANGEEXCHANGE COMMISSION
WASHINGTON, D.C.  20549

FORM 10-Q

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

For the quarterly period ended March 31,June 30, 2009

OR

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

For the transition period from _____to_____

Commission file number: 001-07964
GRAPHIC
NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)

Delaware 73-0785597
(State or other jurisdiction of incorporation)incorporation
or organization)
 (I.R.S. employer identification number)
100 Glenborough Drive, Suite 100  
Houston, Texas 77067
(Address of principal executive offices) (Zip Code)

(281) 872-3100
(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 definitionthe 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]

Number
As of July 13, 2009, there were 173,394,620 shares of the registrant’s common stock, outstanding as of April 13, 2009: 173,347,618.

par value $3.33 1/3 per share, outstanding.

 
 
 

TABLE OF CONTENTS
Page
PART I
Item 1.Financial Statements
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2009 and 2008
3
Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008
4
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008
5
Consolidated Statements of Shareholders' Equity for the Six Months Ended June 30, 2009 and 2008
6
Notes to Consolidated Financial Statements
7
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
25
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
39
Item 4.
Controls and Procedures
40
PART II
Item 1.
Legal Proceedings
41
Item 1A.
Risk Factors
41
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
41
Item 3.
Defaults Upon Senior Securities
41
Item 4.
Submission of Matters to a Vote of Security Holders
41
Item 5.
Other Information
42
Item 6.
Exhibits
42


2

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

NOBLE ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)
(unaudited)

 PART I.  FINANCIAL INFORMATION      
ITEM 1. FINANCIAL STATEMENTS      
       
Noble Energy, Inc. and Subsidiaries      
Consolidated Statements of Operations      
(in millions, except per share amounts)      
(unaudited)      
       
  Three Months Ended 
  March 31, 
  2009  2008 
Revenues      
Oil, gas and NGL sales $406  $944 
Income from equity method investees  11   62 
Other revenues  24   19 
Total  441   1,025 
Costs and Expenses        
Lease operating expense  100   82 
Production and ad valorem taxes  18   43 
Transportation expense  12   13 
Exploration expense  42   40 
Depreciation, depletion and amortization  200   203 
General and administrative  59   60 
Asset impairments  437   - 
Other operating (income) expense, net  (6)  27 
Total  862   468 
Operating Income (Loss)  (421)  557 
Other (Income) Expense        
(Gain) loss on commodity derivative instruments  (73)  237 
Interest, net of amount capitalized  18   17 
Other (income) expense, net  8   (13)
Total  (47)  241 
Income (Loss) Before Income Taxes  (374)  316 
Income Tax Provision (Benefit)  (186)  101 
Net Income (Loss) $(188) $215 
         
Earnings (Loss) Per Share        
Basic $(1.09) $1.25 
Diluted  (1.09)  1.20 
         
Weighted average number of shares outstanding        
Basic  173   172 
Diluted  173   175 
         
The accompanying notes are an integral part of these financial statements.        
     
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
     2009  2008  2009  2008 
Revenues               
Oil, Gas and NGL Sales    $460  $1,130  $866  $2,074 
Income from Equity Method Investees     16   56   27   118 
Other Revenues     15   19   39   38 
Total Revenues     491   1,205   932   2,230 
Costs and Expenses                   
Lease Operating Expense     93   88   193   170 
Production and Ad Valorem Taxes     23   51   42   94 
Transportation Expense     13   16   25   29 
Exploration Expense     33   103   75   143 
Depreciation, Depletion and Amortization     196   196   396   399 
General and Administrative     60   61   119   121 
Asset Impairments     -   -   437   - 
Other Operating (Income) Expense, Net     (3)  20   (11)  46 
Total Operating Expenses     415   535   1,276   1,002 
Operating Income (Loss)     76   670   (344)  1,228 
Other (Income) Expense                   
Loss on Commodity Derivative Instruments     139   828   66   1,065 
Interest, Net of Amount Capitalized     23   17   41   34 
Other Non-Operating (Income) Expense, Net     4   23   12   10 
Total Non-Operating (Income) Expense      166   868   119   1,109 
Income (Loss) Before Income Taxes      (90)  (198)  (463)  119 
Income Tax Provision (Benefit)      (33)  (54)  (218)  48 
Net Income (Loss)     $(57) $(144) $(245) $71 
                     
Earnings (Loss) Per Share, Basic     $(0.33) $(0.84) $(1.42) $0.41 
Earnings (Loss) Per Share, Diluted      (0.33)  (0.84)  (1.42)  0.41 
                     
Weighted Average Number of Shares Outstanding, Basic      173   172   173   172 
Weighted Average Number of Shares Outstanding, Diluted      173   172   173   175 
                     
The accompanying notes are an integral part of these financial statements.             
 

23

NOBLE ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(in millions)

Noble Energy, Inc. and Subsidiaries 
Consolidated Balance Sheets 
(in millions) 
        
   (unaudited)    
   March 31, December 31,
   2009  2008 
ASSETS       
Current Assets       
Cash and cash equivalents $        1,017 $1,140 
Accounts receivable, net              493            423 
Commodity derivative instruments              403            437 
Other current assets              134            158 
Total current assets           2,047         2,158 
Property, plant and equipment       
Oil and gas properties (successful efforts method of accounting)         11,921       11,963 
Other property, plant and equipment              176            175 
Total property, plant and equipment         12,097       12,138 
Accumulated depreciation, depletion and amortization          (3,328)       (3,134) 
Total property, plant and equipment, net           8,769         9,004 
Goodwill              757            759 
Other noncurrent assets              469            463 
Total Assets $      12,042 $12,384 
        
LIABILITIES AND SHAREHOLDERS’ EQUITY       
Current Liabilities       
Accounts payable - trade $           509 $579 
Income taxes payable              165            130 
Deferred income taxes              121            142 
Other current liabilities              354            323 
Total current liabilities           1,149         1,174 
Long-term debt           2,357         2,241 
Deferred income taxes           1,901         2,174 
Other noncurrent liabilities              510            486 
Total Liabilities           5,917         6,075 
        
Commitments and Contingencies       
        
Shareholders’ Equity       
Preferred stock - par value $1.00; 4 million shares authorized, none issued                   -                - 
Common stock - par value $3.33 1/3; 250 million shares authorized;
    193 million and 192 million shares issued, respectively
              645            641 
Capital in excess of par value           2,215         2,193 
Accumulated other comprehensive loss             (100)          (110) 
Treasury stock, at cost; 19 million shares             (615)          (614) 
Retained earnings           3,980         4,199 
Total Shareholders’ Equity           6,125         6,309 
Total Liabilities and Shareholders’ Equity $     12,042 $12,384 
        
The accompanying notes are an integral part of these financial statements.    
  
(unaudited)
June 30,
  December 31, 
  2009  2008 
ASSETS      
Current Assets      
Cash and Cash Equivalents
 $956  $1,140 
Accounts Receivable, Net  450   423 
Commodity Derivative Assets, Current  203   437 
Other Current Assets  128   158 
Total Assets, Current  1,737   2,158 
Property, Plant and Equipment        
Oil and Gas Properties (Successful Efforts Method of Accounting)  12,161   11,963 
Property, Plant and Equipment, Other  224   175 
Total Property, Plant and Equipment, Gross  12,385   12,138 
Accumulated Depreciation, Depletion and Amortization  (3,504)  (3,134)
Total Property, Plant and Equipment, Net  8,881   9,004 
Goodwill  758   759 
Other Noncurrent Assets  475   463 
Total Assets $11,851  $12,384 
         
LIABILITIES AND SHAREHOLDERS’ EQUITY        
Current Liabilities        
Accounts Payable - Trade $493  $579 
Income Taxes Payable  69   130 
Deferred Income Taxes, Net, Current  25   142 
Other Current Liabilities  303   323 
Total Liabilities, Current  890   1,174 
Long-Term Debt  2,416   2,241 
Deferred Income Taxes, Noncurrent  1,947   2,174 
Other Noncurrent Liabilities  539   486 
Total Liabilities  5,792   6,075 
         
Commitments and Contingencies        
         
Shareholders’ Equity        
Preferred Stock - Par Value $1.00; 4 million Shares Authorized, None Issued  -   - 
Common Stock - Par Value $3.33 1/3; 250 Million Shares Authorized; 193 Million and 192 Million Shares Issued, Respectively  645   641 
Additional Paid in Capital  2,229   2,193 
Accumulated Other Comprehensive Loss  (91)  (110)
Treasury Stock, at Cost; 19 Million Shares  (615)  (614)
Retained Earnings  3,891   4,199 
Total Shareholders’ Equity  6,059   6,309 
Total Liabilities and Shareholders’ Equity $11,851  $12,384 
         
The accompanying notes are an integral part of these financial statements.     
 

3
Noble Energy, Inc. and Subsidiaries 
Consolidated Statements of Cash Flows 
(in millions) 
(unaudited) 
       
  Three Months Ended 
  March 31, 
  2009  2008 
Cash Flows From Operating Activities      
Net income (loss) $(188) $215 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
        
Depreciation, depletion and amortization  200   203 
Asset impairments  437   - 
Deferred income taxes  (301)  35 
Income from equity method investees  (11)  (62)
Dividends from equity method investees  -   76 
Unrealized loss on commodity derivative instruments  80   218 
Settlement of previously recognized hedge losses  -   (62)
Allowance for doubtful accounts  (40)  3 
Other  24   17 
Changes in operating assets and liabilities:        
(Increase) in accounts receivable  (34)  (137)
(Increase) in other current assets  (1)  (5)
(Decrease) in accounts payable  (35)  (61)
Increase in other current liabilities  54   66 
Net Cash Provided by Operating Activities  185   506 
         
Cash Flows From Investing Activities        
Additions to property, plant and equipment  (399)  (464)
Proceeds from sale of property, plant and equipment  -   109 
Net Cash Used in Investing Activities  (399)  (355)
         
Cash Flows From Financing Activities        
Exercise of stock options  11   10 
Excess tax benefits from stock-based awards  3   9 
Cash dividends paid  (31)  (21)
Purchase of treasury stock  (1)  (2)
Proceeds from credit facilities  180   200 
Repayment of credit facilities  (1,060)  (200)
Proceeds from issuance of 8 ¼% senior notes  989   - 
Net Cash Provided by (Used in) Financing Activities  91   (4)
(Decrease) Increase in Cash and Cash Equivalents  (123)  147 
Cash and Cash Equivalents at Beginning of Period  1,140   660 
Cash and Cash Equivalents at End of Period $1,017  $807 
         
The accompanying notes are an integral part of these financial statements.        
         


4
Noble Energy, Inc. and Subsidiaries      
Consolidated Statements of Shareholders' Equity      
(in millions)      
(unaudited)      
       
  Three Months Ended 
  March 31, 
  2009  2008 
       
Common Stock      
Balance, beginning of period $641  $636 
Exercise of stock options  2   2 
Restricted stock awards, net  2   1 
Balance, end of period  645   639 
Capital in Excess of Par Value        
Balance, beginning of period  2,193   2,106 
Stock-based compensation expense  12   9 
Exercise of stock options  9   8 
Tax benefits related to exercise of stock options  3   9 
Restricted stock awards, net  (2)  (1)
Rabbi trust shares sold  -   2 
Balance, end of period  2,215   2,133 
Accumulated Other Comprehensive Loss        
Balance, beginning of period  (110)  (284)
Oil and gas cash flow hedges:        
Realized amounts reclassified into earnings  11   38 
Interest rate cash flow hedges:        
Unrealized change in fair value  -   (27)
Net change in other  (1)  (1)
Balance, end of period  (100)  (274)
Treasury Stock at Cost        
Balance, beginning of period  (614)  (613)
Purchases of treasury stock  (1)  (2)
Rabbi trust shares sold  -   2 
Balance, end of period  (615)  (613)
Retained Earnings        
Balance, beginning of period  4,199   2,964 
Net income (loss)  (188)  215 
Cash dividends ($0.18 per share and $0.12 per share, respectively)  (31)  (21)
Balance, end of period  3,980   3,158 
         
Total Shareholders' Equity $6,125  $5,043 
         
The accompanying notes are an integral part of these financial statements. 



NOBLE ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
(unaudited)

  
Six Months Ended 
June 30,
 
  2009  2008 
Cash Flows From Operating Activities      
Net Income (Loss) $(245) $71 
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:     
Depreciation, Depletion and Amortization  396   399 
Asset Impairments  437   - 
Deferred Income Taxes  (359)  10 
Income from Equity Method Investees  (27)  (118)
Dividends from Equity Method Investees  5   121 
Unrealized Loss on Commodity Derivative Instruments  358   934 
Settlement of Previously Recognized Hedge Losses  -   (101)
Allowance for Doubtful Accounts  (38)  6 
Gain on Asset Sale  (24)  - 
Other Adjustments for Noncash Items Included in Income  46   122 
Changes in Operating Assets and Liabilities:        
(Increase) Decrease in Accounts Receivable  7   (276)
(Increase) Decrease in Other Current Assets  17   (28)
Increase in Accounts Payable  10   64 
(Decrease) in Other Current Liabilities  (47)  (41)
Other Assets and Liabilities, Net  (38)  (9)
Net Cash Provided by Operating Activities  498   1,154 
         
Cash Flows From Investing Activities        
Additions to Property, Plant and Equipment  (777)  (932)
Proceeds from Sale of Property, Plant and Equipment  -   109 
Net Cash Used in Investing Activities  (777)  (823)
         
Cash Flows From Financing Activities        
Exercise of Stock Options  13   24 
Excess Tax Benefits from Stock-Based Awards  3   23 
Dividends Paid, Common Stock  (63)  (53)
Purchase of Treasury Stock  (1)  (2)
Proceeds from Credit Facilities  340   450 
Repayment of Credit Facilities  (1,161)  (425)
Net Proceeds from Issuance of 8 ¼% Senior Notes  989   - 
Repayment of Installment Note  (25)  (25)
Net Cash Provided by (Used in) Financing Activities  95   (8)
Increase (Decrease) in Cash and Cash Equivalents  (184)  323 
Cash and Cash Equivalents at Beginning of Period  1,140   660 
Cash and Cash Equivalents at End of Period $956  $983 
         
The accompanying notes are an integral part of these financial statements.        

5

NOBLE ENERGY, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in millions)
(unaudited)

  
Six Months Ended
June 30,
 
  2009  2008 
       
Common Stock      
Balance, Beginning of Period $641  $636 
Exercise of Stock Options  2   4 
Restricted Stock Awards, Net  2   1 
Balance, End of Period  645   641 
Capital in Excess of Par Value        
Balance, Beginning of Period  2,193   2,106 
Stock-Based Compensation Expense  24   20 
Exercise of Stock Options  11   20 
Tax Benefits Related to Exercise of Stock Options  3   23 
Restricted Stock Awards, Net  (2)  (1)
Rabbi Trust Shares Sold  -   2 
Balance, End of Period  2,229   2,170 
Accumulated Other Comprehensive Loss        
Balance, Beginning of Period  (110)  (284)
Oil and Gas Cash Flow Hedges:        
Realized Amounts Reclassified Into Earnings  20   97 
Interest Rate Cash Flow Hedges:        
Unrealized Change in Fair Value  -   (7)
Net Change in Other  (1)  (1)
Balance, End of Period  (91)  (195)
Treasury Stock at Cost        
Balance, Beginning of Period  (614)  (613)
Purchases of Treasury Stock  (1)  (2)
Rabbi Trust Shares Sold  -   2 
Balance, End of Period  (615)  (613)
Retained Earnings        
Balance, Beginning of Period  4,199   2,964 
Net Income (Loss)  (245)  71 
Cash Dividends ($0.36 Per Share and $0.30 Per Share, Respectively)  (63)  (53)
Balance, End of Period  3,891   2,982 
         
Total Shareholders' Equity $6,059  $4,985 
         
The accompanying notes are an integral part of these financial statements.        

6


Note 1 – Organization and Nature of Operations
Noble Energy, Inc. (Noble Energy, we or us) is an independent energy company engaged in worldwide crude oil, natural gas and natural gas liquids (NGL) acquisition, exploration and production. We operate primarily in the Rocky Mountains, Mid-continent, and deepwater Gulf of Mexico areas in the US, with keysignificant international operations offshore Israel, the North SeaUK and West Africa.
 
Note 2 – Basis of Presentation
Presentation – Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US generally accepted accounting principles (GAAP) for complete financial statements. The accompanying consolidated financial statements at March 31,June 30, 2009 (unaudited) and December 31, 2008 and for the three months and six months ended March 31,June 30, 2009 and 2008 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations and cash flows for such periods. Operating results for the three-month periodand six-month periods ended March 31,June 30, 2009 are not necessarily indicative of the results that may be expected for the year ended December 31, 2009. Certain reclassifications of amounts previously reported have been made to conform to current year presentations. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2008.
 
Estimates – The preparation of consolidated financial statements in conformity with GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Current credit market conditions combined with volatile commodity prices have resulted in increased uncertainty inherent in such estimates and assumptions. As future events and their effects cannot be determined accurately, actual results could differ significantly from our estimates.
 
Statements of Operations Information – Other statements of operations information is as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
  (in millions) 
Other Revenues      
Electricity sales (1)
 $20  $15 
Gathering, marketing and processing (GMP) revenues  4   4 
Total $24  $19 
Other Operating (Income) Expense, net        
Electricity generation expense (1)
 $(30) $15 
Gathering, marketing and processing (GMP) expense  6   5 
Other operating expense, net  18   7 
Total $(6) $27 
Other (Income) Expense, net        
Deferred compensation expense (income) $5  $(7)
Interest income  -   (6)
Other expense, net  3   - 
Total $8  $(13)

6


  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
  (in millions) 
Other Revenues            
Electricity Sales (1)
 $11  $14  $32  $29 
Gathering, Marketing and Processing Revenues  4   5   7   9 
Total $15  $19  $39  $38 
Other Operating (Income) Expense, Net                
Gain on Asset Sale (2)
 $(24) $-  $(24) $- 
Electricity Generation Expense (1)
  11   13   (19)  28 
Gathering, Marketing and Processing Expense  5   4   10   8 
Settlement of Legal Proceedings (3)
  4   -   9   - 
Gain on Involuntary Conversion (4)
  (3)  -   (3)  - 
Other Operating (Income) Expense, Net  4   3   16   10 
Total $(3) $20  $(11) $46 
Other Non-Operating (Income) Expense, Net                
Deferred Compensation Expense $5  $29  $10  $22 
Interest Income  (1)  (6)  (1)  (12)
Other (Income) Expense, Net  -   -   3   - 
Total $4  $23  $12  $10 
 
(1)
Includes amounts related to our 100%-owned Ecuador integrated power project. The project includes the Amistad natural gas field, offshore Ecuador, which supplies natural gas to fuel the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation, depletion and amortization expense (DD&A) and changes in the allowance for doubtful accounts. We recognized a net decreaseincrease of $42$2 million in the Ecuador allowance during firstsecond quarter 2009 and a net increasedecrease of $40 million in the allowance during the first six months of 2009. We recognized net increases of $3 million and $6 million in the allowance during the second quarter and first quarter 2008.six months of 2008, respectively. See Allowance for Doubtful Accounts below.

7
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)


(2)In February 2008, effective July 1, 2007, we sold our interest in Argentina for a sales price of $117.5 million. The gain on sale was deferred until second quarter 2009 when the Argentine government approved the sale.
(3)
Second quarter 2009 includes a $19 million charge on legal settlement (See Note 14 – Commitments and Contingencies), offset by a $15 million gain on legal settlement related to reimbursement of bonuses paid for federal leases offshore California.
(4)Amount represents receipt of insurance claims related to Hurricane Katrina damage.
 
Balance Sheet Information – Other balance sheet information is as follows:
 
  March 31, December 31, 
  2009 2008 
  (in millions) 
Other Current Assets     
Inventories $116 $105 
Asset held for sale (1)
  -  26 
Prepaid expenses and other current assets  18  27 
Total $134 $158 
Other Noncurrent Assets       
Equity method investments $323 $311 
Mutual fund investments  77  84 
Commodity derivative instruments  24  33 
Other noncurrent assets  45  35 
Total $469 $463 
Other Current Liabilities       
Accrued and other current liabilities $202 $215 
Commodity derivative instruments  34  23 
Short-term borrowings  25  25 
Asset retirement obligations  44  27 
Interest payable  25  9 
Deferred gain on asset sale  24  24 
Total $354 $323 
Other Noncurrent Liabilities       
Deferred compensation liabilities $164 $159 
Asset retirement obligations  185  184 
Accrued benefit costs  83  81 
Commodity derivative instruments  12  2 
Other noncurrent liabilities  66  60 
Total $510 $486 
  June 30, December 31, 
    2009    2008 
   (in millions) 
Other Current Assets       
Inventories, Current $107 $105 
Prepaid Expenses and Other Assets, Current           21            27 
Asset Held for Sale (1)
             -            26 
Total $128 $158 
Other Noncurrent Assets       
Equity Method Investments $335 $311 
Mutual Fund Investments           90            84 
Commodity Derivative Assets, Noncurrent             7            33 
Other Assets, Noncurrent           43            35 
Total $475 $463 
Other Current Liabilities       
Accrued and Other Liabilities, Current $182 $215 
Commodity Derivative Liabilities, Current           39            23 
Asset Retirement Obligations, Current           44            27 
Interest Payable           38              9 
Short-Term Borrowings             -            25 
Deferred Gain on Asset Sale, Current (2)
             -            24 
Total $303 $323 
Other Noncurrent Liabilities       
Deferred Compensation Liabilities, Noncurrent $182 $159 
Asset Retirement Obligations, Noncurrent         187          184 
Accrued Benefit Costs, Noncurrent           83            81 
Commodity Derivative Liabilities, Noncurrent           53              2 
Other Liabilities, Noncurrent           34            60 
Total $539 $486 
 
(1)
The Main Pass asset was reclassified as held-and-used and impaired during first quarter 2009. Estimated proved reserves attributed to this property were less than 1% of our total estimated proved reserves. See Note 5 Asset Held for Sale– below.Fair Value Measurements
 
Asset Held for Sale – During 2008, we initiated a process to sell our remaining operated non-core Gulf of Mexico shelf asset located at Main Pass. Numerous parties expressed an interest in purchasing the asset. However, due to difficulties in obtaining appropriate insurance, bonding or financing, none of the potential buyers were able to close on the sale. As a result, we believe it is no longer probable that a sale of the asset will be completed within one year of its classification as held-for-sale. Therefore, the asset has been reclassified as held-and-used.  Due to significant increases in insurance costs and exposure to further windstorm damage, our current plans are to abandon the Main Pass asset, and therefore this property was impaired.  See Note 5 – Fair Value Measurements.
(2)
See footnote (2) to Statements of Operations Information above.
 
Allowance for Doubtful Accounts – Through December 31, 2008, we had recorded an allowance for doubtful accounts of $57 million related to our Ecuador power operations. The allowance was necessary to cover potentially uncollectible balances, as certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. As a result of pursuing various strategies to protect our interests, including international arbitration and litigation, we reached a settlement in fourth quarter 2008. In March and April 2009, we received total payments of $60 million in accordance with the terms of the settlement, against which a reserve of $46 million had previously been recorded.  Accordingly, we reduced the allowance for doubtful accounts by $46 million and included the amount as a reduction in electricity generation expense.expense during first quarter 2009. We recorded an additionaladditions to the allowance for doubtful accounts of $6$2 million and $8 million during the second quarter and first six months of 2009, respectively, related to current period commodity and electricity sales.
 

78
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)


Adoption of FSP SFAS 132(R) – In December 2008, the FASB issued FSP SFAS 132(R), “Employers’ Disclosures About Postretirement Benefit Plan Assets” (FSP SFAS 132(R)). FSP SFAS 132(R) requires employers to make additional disclosures about plan assets for defined benefit pension and other postretirement benefit plans beginning with annual periods ending after December 15, 2009. The requirements apply to entities that are subject to the disclosure requirements of SFAS 132(R). Disclosures are to provide an understanding of how investment allocation decisions are made, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair-value measurements using significant unobservable inputs on changes in plan assets for the period, and significant concentrations of risk within plan assets. We adopted FSP SFAS 132(R) as of January 1, 2009. The statement provides only for enhanced annual disclosures and does not require additional interim disclosures. Adoption had no impact on our financial position or results of operations.
 
Adoption of SFAS 141(R) and SFAS 160 – In 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (SFAS 141(R)) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (SFAS 160). These statements require most identifiable assets, liabilities and noncontrolling interests to be recorded at full fair value and require noncontrolling interests to be reported as a component of equity. Both statements are effective for periods beginning on or after December 15, 2008. SFAS 141(R) will be applied to business combinations occurring after the effective date and SFAS 160 will be applied prospectively to all noncontrolling interests, including any that arose before the effective date. We adopted SFAS 141(R) and SFAS 160 as of January 1, 2009. There were no non-controlling interests at adoption date. Adoption had no effectimpact on our financial position or results of operations.
 
Adoption of SFAS 157 – SFAS No. 157, “Fair Value Measurements” (SFAS 157) establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. As of January 1, 2008, we adopted the provisions of SFAS 157 related to our financial assets and liabilities. As of January 1, 2009, we adopted the provisions of SFAS 157 related to our nonfinancial assets and liabilities, including nonfinancial assets and liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill;goodwill impairment assessments; and initial recognition of asset retirement obligations. Adoption of SFAS 157 did not have a significant impact on our consolidated financial statements. See Note 5 – Fair Value Measurements. See also Note 1615 – Recently Issued Pronouncements.
 
Adoption of SFAS 161 – In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161). SFAS 161 amends and expands the disclosure requirements of SFAS 133, "Accounting“Accounting for Derivative Instruments and Hedging Activities"Activities” (SFAS 133), andand requires qualitative disclosures about objectives and strategies for using derivative instruments, quantitative disclosures about fair value amounts of derivative instruments and related gains and losses, and disclosures about credit risk-related contingent features in derivative agreements. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted SFAS 161 as of January 1, 2009. The statement provides only for enhanced disclosures. Therefore, adoption had no impact on our financial position or results of operations. See Note 4 – Derivative Instruments and Hedging Activities.
 
Adoption of SFAS 165 – In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (SFAS 165). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. In particular, SFAS 165 sets forth:
·The period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements (through the date that the financial statements are issued or are available to be issued);
·The circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and
·The disclosures that an entity should make about events or transactions that occurred after the balance sheet date.

9
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)


SFAS 165 is effective for interim or annual periods ending after June 15, 2009, and is to be applied prospectively. We adopted SFAS 165 as of June 30, 2009. We have evaluated subsequent events after the balance sheet date of June 30, 2009 through July 30, 2009 which is the date the financial statements were issued.
Adoption of SFAS 168 – In June 2009, the FASB issued SFAS No. 168, “The ‘FASB Accounting Standards Codification’ and the Hierarchy of Generally Accepted Accounting Principles” (SFAS 168).  SFAS 168 establishes the FASB Accounting Standards Codification (Codification), which officially commenced July 1, 2009, to become the source of authoritative US GAAP recognized by the FASB to be applied by nongovernmental entities.  Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative US GAAP for SEC registrants.  The subsequent issuances of new standards will be in the form of Accounting Standards Updates that will be included in the Codification.  Generally, the Codification is not expected to change US GAAP.  All other accounting literature excluded from the Codification will be considered nonauthoritative.  SFAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009.  We will adopt SFAS 168 for our quarter ending September 30, 2009.  We are currently evaluating the effect on our financial statement disclosures as all future references to authoritative accounting literature will be referenced in accordance with the Codification.
Adoption of EITF Issue 08-06 – In November 2008, the FASB ratified the consensus reached in EITF Issue 08-06, “Equity Method Investment Accounting Considerations” (EITF 08-06). EITF 08-06 was issued to address questions that arose regarding the application of the equity method subsequent to the issuance of SFAS 141(R). EITF 08-06 concluded that equity method investments should continue to be recognized using a cost accumulation model, thus continuing to include transaction costs in the carrying amount of the equity method investment. In addition, EITF 08-06 clarifies that an impairment assessment should be applied to the equity method investment as a whole, rather than to the individual assets underlying the investment. EITF 08-06 is effective for fiscal years beginning on or after December 15, 2008. We adopted EITF 08-06 as of January 1, 2009. Adoption had no effectimpact on our financial position or results of operations.
 
Adoption of Recent Staff Positions – In April 2009, the FASB issued three related staff positions to clarify the application of SFAS 157 to fair value measurements in the current economic environment, modify the recognition of other-than-temporary impairments of debt securities, and require companies to disclose the fair value of financial instruments in interim periods. The final staff positions are effective for interim and annual periods ending after June 15, 2009.
·
FSP SFAS 157-4– FASB Staff Position No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability has Significantly Decreased and Identifying Transactions That Are Not Orderly” provides guidance on how to determine the fair value of assets and liabilities under SFAS 157 in the current economic environment and reemphasizes that the objective of a fair value measurement remains the price that would be received to sell an asset or paid to transfer a liability at the measurement date.
·
FSP SFAS 115-2 and SFAS 124-2 – FASB Staff Position No. 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” modifies the requirements for recognizing other-than-temporarily impaired debt securities and significantly changes the existing impairment model for such securities. It also modifies the presentation of other-than-temporary impairment losses and increases the frequency of and expands already required disclosures about other-than-temporary impairment for debt and equity securities.
·
FSP SFAS 107-1 and APB 28-1 – FASB Staff Position No. 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” requires disclosures of the fair value of financial instruments within the scope of SFAS 107 in interim financial statements, adding to the current requirement to make those disclosures in annual financial statements. The staff position also requires that companies disclose the method or methods and significant assumptions used to estimate the fair value of financial instruments and a discussion of changes, if any, in the method or methods and significant assumptions during the period.
We adopted the new staff positions for the quarter ended June 30, 2009. Adoption had no impact on our financial position or results of operations. See Note 5 – Fair Value Measurements for interim disclosures required by FSP SFAS 107-1 and APB 28-1.

10
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)


Note 3 – Debt Issuance
On February 27, 2009, we closed an offering of $1 billion senior unsecured notes receiving net proceeds of $989 million, after deducting the discount and underwriting fees. The notes are due March 1, 2019, and pay interest semi-annually at 8¼%. Debt issuance costs of approximately $2 million were incurred and are being amortized to expense over the life of the debt issue. Substantially all of the net proceeds from the offering were used to repay outstanding indebtedness under our revolving credit facility maturing 2012. The notes are senior unsecured debt and will rank pari passu with any of our other senior unsecured indebtedness with respect to the payment of both principal and interest.
 

On May 11, 2009, we made the final $25 million installment payment to the seller of properties we purchased in 2007. Interest on the unpaid amount was due quarterly and accrued at a LIBOR rate plus .30%. The interest rate was 1.51% at the date of payment.
8


 
Our debt consists of the following:
 
  March 31,  December 31, 
  2009  2008 
  Debt  Interest Rate  Debt  Interest Rate 
  (in millions, except percentages) 
Credit facility $726   0.81% $1,606   0.80%
5 ¼% Senior Notes, due April 15, 2014  200   5.25%  200   5.25%
8 ¼% Senior Notes, due March 1, 2019  1,000   8.25%  -   - 
7 ¼% Notes, due October 15, 2023  100   7.25%  100   7.25%
8% Senior Notes, due April 1, 2027  250   8.00%  250   8.00%
7 ¼% Senior Debentures, due August 1, 2097  89   7.25%  89   7.25%
Long-term debt  2,365       2,245     
Installment payments, due May 11, 2009  25   1.76%  25   4.18%
Total debt  2,390       2,270     
Unamortized discount  (8)      (4)    
Total debt, net of discount $2,382      $2,266     
  June 30,  December 31, 
  2009  2008 
  Debt  Interest Rate  Debt  Interest Rate 
  (in millions, except percentages) 
Credit Facility $785   0.62% $1,606   0.80%
5 ¼% Senior Notes, due April 15, 2014  200   5.25%  200   5.25%
8 ¼% Senior Notes, due March 1, 2019  1,000   8.25%  -   - 
7 ¼% Notes, due October 15, 2023  100   7.25%  100   7.25%
8% Senior Notes, due April 1, 2027  250   8.00%  250   8.00%
7 ¼% Senior Debentures, due August 1, 2097  89   7.25%  89   7.25%
Long-term Debt  2,424       2,245     
Installment Payment, due May 11, 2009  -   -   25   4.18%
Total Debt  2,424       2,270     
Unamortized Discount  (8)      (4)    
Total Debt, Net of Discount $2,416      $2,266     
 
Note 4 – Derivative Instruments and Hedging Activities
Objectives and Strategies for Using Derivative Instruments – We are exposed to certain risks relating to our ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk. We use various commodity derivative instruments in connection with forecasted crude oil and natural gas sales to minimize the impact of commodity price fluctuations. Such instruments include variable to fixed price swaps, collars and basis swaps.
 
We may also use derivative instruments to manage interest rate risk by entering into forward contracts or swap agreements to minimize the impact of interest rate fluctuations associated with fixed or floating rate borrowings. We may designate these as cash flow hedges.
 
We accountIn accordance with US GAAP for derivative instruments and hedging activities, in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and all of our derivative instruments are reflected as either assets or liabilities at fair value in our consolidated balance sheets. See Note 5 – Fair Value Measurements for a discussion of methods and assumptions used to estimate the fair values of our commodity derivative instruments and gross amounts of commodity derivative assets and liabilities.
 
Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of financial institutions, a majority of which are lenders under our credit facility arrangement.  Certain of these financial institutions have received capital injections and other forms of support from government sources, and may require additional financial assistance in the future to remain viable.  Discontinuance of government support to these institutions could have an adverse impact on the collectibility of our derivative receivables. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election.
 
We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices as well as incur a loss. See also Note 5 – Fair Value Measurements.
 

11
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)


Commodity Derivative Instruments – During 2009 and 2008 we accounted for our commodity derivative instruments using mark-to-market accounting, and we recognize all gains and losses on such instruments in earnings during the period in which they occur.  Prior to January 1, 2008, we elected to designate certain of our commodity derivative instruments as cash flow hedges. Net derivative gains and losses that were deferred in accumulated other comprehensive loss (AOCL) as of January 1, 2008, as a result of previous cash flow hedge accounting, are reclassified to earnings in future periods as the original hedged transactions occur.  See Derivatives in SFAS 133 Cash Flow Hedging Relationships table below.

9

As of March 31,June 30, 2009, we had entered into the following crude oil derivative instruments:
 
  Variable to Fixed Price Swaps  Collars 
        Weighted        Weighted Weighted 
Production    Bbls  Average     Bbls  Average Average 
Period Index  Per Day  Fixed Price  Index  Per Day  Floor Price Ceiling Price
2009 NYMEX WTI      9,000 $88.43  NYMEX WTI   6,700 $79.70 $90.60 
2009 Dated Brent          2,000           87.98  Dated Brent         5,074       70.62       87.93 
2009 Average          11,000           88.35          11,774       75.79       89.45 
2010          NYMEX WTI       10,500       61.10       76.73 
  Variable to Fixed Price Swaps Collars 
      Weighted     Weighted Weighted 
Production   Bbls Average   Bbls Average Average 
Period Index Per Day Fixed Price Index Per Day Floor Price Ceiling Price 
2009 NYMEX WTI  9,000 $88.43 NYMEX WTI  6,700 $79.70 $90.60 
2009 Dated Brent  2,000  87.98 Dated Brent  4,924  71.40  88.36 
2009 Average    11,000  88.35    11,624  76.19  89.65 
                     
2010         NYMEX WTI  14,500  61.48  75.63 
2010         Dated Brent  6,000  63.83  73.79 
2010 Average            20,500  62.17  75.10 

From AprilJuly 1, 2009 to April 17,July 27, 2009, we entered into an additional NYMEX WTI collarsDated Brent collar covering 3,0001,000 Bbls per day for calendar year 2010 with weighted average floor and ceiling prices of $60.00$65.00 and $75.00, respectively.  We also entered into an additional NYMEX WTI collar covering 1,000 Bbls per day for calendar year 2011 with floor and ceiling prices of $70.00 and $82.40, respectively.
 
As of March 31,June 30, 2009, we had entered into the following natural gas derivative instruments:
 
Collars 
      MMBtu  Weighted AverageWeighted Average
Production Period  Index  Per Day  Floor Price Ceiling Price 
2009  NYMEX HH     170,000 $9.15 $10.81 
2009  
IFERC CIG (1)
       15,000         6.00          9.90 
2009 Average        185,000         8.90        10.73 
2010   NYMEX HH       40,000         5.88          6.50 
2010   IFERC CIG       15,000         6.25          8.10 
2010 Average          55,000         5.98          6.94 
   Collars 
        Weighted  Weighted 
Production    MMBtu  Average  Average 
Period  Index Per Day  Floor Price  Ceiling Price 
2009  NYMEX HH  170,000  $9.15  $10.81 
2009  
IFERC CIG (1)
  15,000   6.00   9.90 
2009 Average     185,000   8.90   10.73 
                
2010  NYMEX HH  160,000   5.88   6.84 
2010  IFERC CIG  15,000   6.25   8.10 
2010 Average     175,000   5.91   6.95 
                
2011  NYMEX HH  90,000   5.92   7.04 
(1)    Colorado Interstate Gas – Northern System
 
From AprilJuly 1, 2009 to April 17,July 27, 2009, we entered into additional NYMEX HH collars covering 80,00050,000 MMBtu per day for calendar yearyears 2010 with weighted average floor and ceiling prices of $5.81 and $6.83, respectively.  We also entered into additional NYMEX HH collars covering 60,000 MMBtu per day for calendar year 2011 with weighted average floor and ceiling prices of $5.83$6.00 and $6.94,$6.40, respectively.
 

12
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)

As of March 31,June 30, 2009, we had entered into the following natural gas basis swaps:
 
Basis Swaps 
   Index Less MMBtu Weighted Average   Basis Swaps     
Production Period Index Differential Per Day Differential 
       Weighted 
Production   Index Less MMBtu Average 
Period  Index Differential Per Day Differential 
2009 IFERC CIG  NYMEX HH  140,000  $(2.49) IFERC CIG  NYMEX HH  140,000 $(2.49)
2010 IFERC CIG  NYMEX HH  80,000   (1.77)  IFERC CIG  NYMEX HH  90,000  (1.68)
 
From AprilJuly 1, 2009 to April 17,July 27, 2009, we did not enterentered into any additional IFERC CIG for NYMEX HH basis swaps.swaps covering 10,000 MMBtu per day for calendar year 2010, and 40,000 MMBtu per day for calendar year 2011, with weighted average differential prices of $(0.90) and $(0.88), respectively.
 
Interest Rate Derivative Instruments – Changes in fair value of interest rate swaps or interest rate “locks” designated as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related notes. During the first quartersix months of 2008, we had two interest rate swaps, or interest rate “locks”, each in the notional amount of $500 million. The locks were based on five and ten year US Treasury rates of 3.55% and 4.15%, respectively, and were scheduled to expire in September 2008. The locks were designated as cash flow hedgeshedges. The net increase in fair value of $20 million (net of tax) for second quarter 2008 and changesthe net decrease in their fair valuesvalue of $27$7 million net(net of tax,tax) for the first six months of 2008 were reported as losses in AOCL during first quarter 2008.AOCL. The locks were settled in July 2008 at a cost of $0.2 million.
 


10

Fair Value Amounts and Gains and Losses on Derivative Instruments – The fair values of derivative instruments in our consolidated balance sheetsheets were as follows:
 
Derivative Instruments Not Designated as Hedging Instruments Under SFAS 133
 
 
  Asset Derivative Instruments Liability Derivative Instruments 
  March 31, December 31, March 31, December 31, 
  2009 2008 2009 2008 
(in millions) 
Balance
Sheet
Location
 Fair Value
Balance
Sheet
Location
 Fair Value 
Balance
Sheet
Location
 Fair Value
Balance
Sheet
Location
 Fair Value 
Commodity derivative instruments               
  Current   Current    Current    Current   
  assets $403 assets $437  liabilities $34  liabilities $23 
  Noncurrent    Noncurrent     Noncurrent    Noncurrent 
  assets  24 assets  33  liabilities  12  liabilities  2 
Total   $427   $470   $46   $25 
The effect of derivative instruments on our consolidated statements of operations was as follows:
Derivative Instruments Not Designated as Hedging Instruments Under SFAS 133
 
 
  
Location of (Gain) Loss Rcognized in Income
on Derivative Instrument
 
Amount of (Gain) Loss
Recognized in Income
on Derivative Instrument
 
    Three Months Ended 
    March 31, 
    2009  2008 
    (in millions) 
Commodity derivative instruments        
Realized mark-to-market (gain) loss (Gain) loss on commodity derivative instruments $(153) $19 
Unrealized mark-to-market loss (Gain) loss on commodity derivative instruments  80   218 
Total   $(73) $237 
Derivative Instruments in Previously Designated SFAS 133 Cash Flow Hedging Relationships
 
 
   Amount of (Gain) Loss Recognized in OCI on Derivative Instrument Location of (Gain) Loss Reclassified from AOCL into Income Amount of (Gain) Loss Reclassified from AOCL on Derivative Instrument 
   Three Months Ended     Three Months Ended 
   March 31,     March 31, 
   2009  2008     2009  2008 
   (in millions)     (in millions) 
Commodity derivative instruments (1)
                
Crude oil $- $  - Oil, gas and NGL sales$17 $97 
Natural gas            -               - Oil, gas and NGL sales              -        (37)
Treasury rate locks            -            43   -                -            - 
Total $- $ 43    $  17 $  60 
Derivative Instruments Not Designated as Hedging Instruments Under SFAS 133
 
 
  Asset Derivative Instruments Liability Derivative Instruments 
  June 30,  December 31, June 30, December 31, 
  2009  2008 2009 2008 
(in millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair ValueBalance Sheet Location Fair Value 
Commodity Derivative Instruments                  
  Current Assets $203  Current Assets $437 Current Liabilities $39 Current Liabilities $23 
  Noncurrent Assets  7  Noncurrent Assets  33 Noncurrent Liabilities  53 Noncurrent Liabilities  2 
Total   $210    $470   $92   $25 











13
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)


The effect of derivative instruments on our consolidated statements of operations was as follows:
Derivative Instruments Not Designated as Hedging Instruments Under SFAS 133
 
 
  
 Amount of (Gain) Loss on Derivative
Instruments Recognized in Income
 
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
  (in millions) 
Commodity Derivative Instruments
            
Realized Mark-to-Market (Gain) Loss (1)
 $(138) $112  $(292) $131 
Unrealized Mark-to-Market Loss (1)
  277   716   358   934 
Total (Gain) Loss on Commodity Derivative Instruments $139  $828  $66  $1,065 
(1)Amounts are included in the line item “Loss on Commodity Derivative Instruments” in our consolidated statements of operations.

Derivative Instruments in Previously Designated SFAS 133 Cash Flow Hedging Relationships
 
 
  Amount of (Gain) Loss on Derivative Instruments Recognized in OCI  Amount of (Gain) Loss on Derivative Instruments Reclassified from AOCL 
  2009  2008  2009  2008 
  (in millions)  (in millions) 
Three Months Ended June 30,            
Commodity Derivative Instruments (1)
            
Crude Oil (2)
 $-  $-  $15  $93 
Natural Gas (2)
  -   -   -   2 
                 
Treasury Rate Locks  -   (32)  -   - 
Total $-  $(32) $15  $95 
                 
Six Months Ended June 30,                
Commodity Derivative Instruments (1)
                
Crude Oil (2)
 $-  $-  $32  $190 
Natural Gas (2)
  -   -   -   (35)
                 
Treasury Rate Locks  -   11   -   - 
Total $-  $11  $32  $155 
 
(1)Includes effect of commodity derivative instruments previously accounted for as cash flow hedges. Net derivative gains and losses that were deferred in AOCL as of January 1, 2008, as a result of previous cash flow hedge accounting, are reclassified to earnings in future periods as the original hedged transactions occur.
(2)The amount of (Gain) Loss reclassified from AOCL on Derivative Instrument is recognized in Oil, Gas and NGL Sales within our consolidated statement of operations.




1114
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)


AOCL – As of March 31,AOCL – As of June 30, 2009, the balance in AOCL included net deferred losses of $29 million related to the fair value of commodity derivative instruments previously accounted for as cash flow hedges. The net deferred losses are net of deferred income tax benefits of $17 million. Approximately $22 million of deferred losses (net of tax) related to the fair values of the commodity derivative instruments previously designated as cash flow hedges and remaining in AOCL at June 30, 2009 will be reclassified to earnings during the next 12 months as the forecasted transactions occur, and will be recorded as a reduction in oil and gas sales of approximately $36 million before tax. All forecasted transactions currently being hedged and for which amounts remain in AOCL at June 30, 2009, the balance in AOCL included net deferred losses of $38 million related to the fair value of commodity derivative instruments previously accounted for as cash flow hedges. The net deferred losses are net of deferred income tax benefits of $23 million. Approximately $29 million of deferred losses (net of tax) related to the fair values of the commodity derivative instruments previously designated as cash flow hedges and remaining in AOCL at March 31, 2009 will be reclassified to earnings during the next 12 months as the forecasted transactions occur, and will be recorded as a reduction in oil and gas sales of approximately $46 million before tax. All forecasted transactions currently being hedged and for which amounts remain in AOCL at March 31, 2008, are expected to occur by December 2010.
 
Note 5 – Fair Value Measurements
SFAS 157US GAAP for fair value measurements establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis in our consolidated balance sheets.  The following methods and assumptions were used to estimate the fair values: 
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable – The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.
 
Mutual Fund Investments – Our mutual fund investments, which primarily include assets held in a rabbi trust, consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices.prices for identical assets. 
 
Commodity Derivative Instruments – Our commodity derivative instruments consist of variable to fixed price commodity swaps, collars and basis swaps. We estimate the fair values of these instruments based on published forward commodity futures price curvesstrips for the underlying commodities as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty credit risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract parameters.terms. See Note 4 – Derivative Instruments and Hedging Activities.
 
Patina Deferred Compensation Liability - The value is dependant upon the fair values of mutual fund investments and shares of Noble Energy common stock held in a rabbi trust. See Mutual Fund Investments above.above.

 

1215
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)

Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:

   Fair Value Measurements Using       
   
Quoted Prices in Active Markets
(Level 1)
  
Significant Other Observable Inputs
(Level 2)
  
Significant Unobservable Inputs
(Level 3)
  
Adjustment (1)
Fair Value
Measurement
 
   (in millions) 
As of March 31, 2009                
Financial assets:                
Mutual fund investments $ 77 $     - $ - $ - $77 
Commodity derivative instruments             -       445           -     (18)     427 
Financial liabilities:                
Commodity derivative instruments             -        (64)          -       18       (46)
Liability under Patina deferred compensation plan      (122)            -           -          -     (122)
As of December 31, 2008                
Financial assets:                
 Mutual fund investments          84            -           -          -        84 
 Commodity derivative instruments             -       492           -     (22)     470 
Financial liabilities:                
 Commodity derivative instruments             -        (47)           -       22       (25)
 Liability under Patina deferred compensation plan      (123)           -           -          -     (123)
                 
(1)    Amount represents the impact of master netting agreements that allow us to net cash settle asset and liability positions with the same counterparty.  
  Fair Value Measurements Using       
  
Quoted Prices in 
Active Markets (Level 1)
  Significant Other Observable Inputs (Level 2)  Significant Unobservable Inputs (Level 3)  
Adjustment (1)
  Fair Value Measurement 
  (in millions) 
As of June 30, 2009               
Financial Assets:               
Mutual Fund Investments $90  $-  $-  $-  $90 
Commodity Derivative Instruments  -   245   -   (35)  210 
Financial Liabilities:                    
Commodity Derivative Instruments  -   (127)  -   35   (92)
Patina Deferred Compensation Liability  (139)  -   -   -   (139)
As of December 31, 2008                    
Financial Assets:                    
Mutual Fund Investments  84   -   -   -   84 
Commodity Derivative Instruments  -   492   -   (22)  470 
Financial Liabilities:                    
Commodity Derivative Instruments  -   (47)  -   22   (25)
Patina Deferred Compensation Liability  (123)  -   -   -   (123)
 
(1) Amount represents the impact of master netting agreements that allow us to net cash settle asset and liability positions with the same counterparty.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis in our consolidated balance sheets.  The following methods and assumptions were used to estimate the fair values: 
 
Asset Impairments – In accordance with SFAS No. 144, “AccountingUS GAAP for the Impairmentimpairment or Disposaldisposal of Long-Lived Assets,”long-lived assets, we review a proved oil and gas property for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. We estimate the future cash flows expected in connection with the property and compare such future cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.
 
As a result of a significant decline in the forward natural gas futures price strip at March 31, 2009, we reviewed our oil and gas properties that are sensitive to natural gas price decreases for impairment. We determined that the carrying amount of Granite Wash, an onshore US area where we have significantly reduced investments beginning in 2007, was not recoverable from future cash flows and, therefore, was impaired at March 31, 2009.  We reduced Granite Wash to its fair value, which was determined using the discounted cash flow method described above, as comparable market data was not available.  We also impaired the Main Pass asset which had been reclassified from held-for-sale to held-and-used. Total pre-tax (non-cash) impairments for first quarter 2009 were $437 million. The impaired assets, which had a total carrying amount of $753 million, were reduced to their estimated fair value of $316 million. See also Note 2 million–. The asset impairments were Level 3 fair value measurements. Basis of Presentation – Asset Held for Sale.
 
Asset Retirement Obligations Incurred in Current Period – We estimate the fair values of asset retirement obligations (AROs) based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note 7 – Asset Retirement Obligations for a summary of changes in AROs.Asset retirement obligations incurred in the current period were Level 3 fair value measurements.
 

1316
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)

Measurement information for assets that are measured atDebt –The fair value of fixed-rate debt is estimated based on a nonrecurring basis wasthe published market prices for the same or similar issues.  The fair value of floating-rate debt is estimated using the carrying amounts because the interest rates paid on such debt are set for periods of three months or less. See Note 3 – Debt.
Additional information regarding our debt is as follows:
 
      Fair Value Measurements Using    
Description  Fair Value Measurement 
Quoted Prices in
Active Markets
(Level 1)
  
Significant Other Observable Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
  
Total
Impairment
Loss
 
   (in millions) 
Three Months Ended March 31, 2009                
Impaired US oil and gas properties $  316             -            - $316 $       (437) 
Asset retirement obligations incurred in current period
  1             -            -  1                  - 
Three Months Ended March 31, 2008                
Asset retirement obligations incurred in current period
  14             -            -  14                  - 
  June 30,  December 31, 
  2009  2008 
  Carrying Amount  Fair Value  Carrying Amount  Fair Value 
  (in millions) 
Total Debt, Net of Unamortized Discount $2,416  $2,566  $2,266  $2,172 

Note 6 – Capitalized Exploratory Well Costs
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
 
 Three Months Ended 
 March 31, 2009 
 (in millions) 
Capitalized exploratory well costs, beginning of period$501 
Additions to capitalized exploratory well costs pending determination of proved reserves 68 
Reclassified to property, plant and equipment based on determination of proved reserves (88)
Capitalized exploratory well costs charged to expense (4)
Capitalized exploratory well costs, end of period$477 
  
Six Months Ended
June 30,
   (in millions)
Capitalized Exploratory Well Costs, Beginning of Period $501 
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves             96 
Reclassified to Property, Plant and Equipment Based on Determination of Proved Reserves            (88)
Capitalized Exploratory Well Costs Charged to Expense                (9) 
Capitalized Exploratory Well Costs, End of Period $500 

 
The following table provides an aging of capitalized exploratory well costs (suspended well costs) based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
 
  March 31,  December 31, 
  2009  2008 
  (in millions) 
Exploratory well costs capitalized for a period of one year or less $255  $256 
Exploratory well costs capitalized for a period greater than one year after completion of drilling  222   245 
Balance at end of period $477  $501 
Number of projects with exploratory well costs that have been capitalized for a period greater than one year after completion of drilling  4   6 
  June 30, December 31, 
  2009  2008 
  (in millions) 
Exploratory Well Costs Capitalized for a Period of One Year or Less $225  $256 
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling  275   245 
Balance at End of Period $500  $501 
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year After Completion of Drilling  4   6 
 

17
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)

The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of March 31,June 30, 2009:
 
    Suspended Since 
          2006     Suspended Since 
 Total  2008  2007  & Prior  Total  2008  2007  
2006 &
Prior
 
 (in millions)  (in millions) 
Project                        
West Africa $168  $8  $140  $20  $221  $61  $140  $20 
Redrock (deepwater Gulf of Mexico)  17   -   -   17   17   -   -   17 
Flyndre (North Sea)  15   -   12   3   15   -   12   3 
Selkirk (North Sea)  22   -   22   -   22   -   22   - 
Total exploratory well costs capitalized for a period greater that one year after completion of drilling
 $222  $9  $174  $40 
Total Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling $275  $61  $174  $40 
 

14

West Africa – The West Africa project includes Blocks O and I offshore Equatorial Guinea and the YoYo concession and Tilapia production sharing contract offshore Cameroon. Since drilling the initial well for this project, additional seismic work has been completed and exploration and appraisal wells have been drilled to further evaluate our discoveries. The West Africa development team is proceeding with a program to further define the resources in this area such that an optimal development program may be designed. Accordingly, a development plan for the BenitaAseng (formerly Benita) discovery on Block I was submitted to the Equatorial Guinean government in December 2008, and we await its approval.has been approved.  In addition to the exploratory well costs that have been capitalized for a period greater than one year for the West Africa project, we have incurred $113$43 million in suspended costs related to additional drilling activity in West Africa through March 31,June 30, 2009.
 
Redrock (deepwater(Deepwater Gulf of Mexico) – Redrock (Mississippi Canyon Block 204) was a 2006 natural gas/condensate discovery and is currently considered a co-development candidate to the completed sidetrack well atwith Raton South (Mississippi Canyon Block 292). The anticipated development plan consists of tying Raton South back to the Matterhorn facility for processing and then connecting Redrock into this gathering system. Tie-back of Redrock is anticipated to occur following the tie-backdevelopment of Raton South.South planned in 2010.
 
Flyndre (North Sea) – The Flyndre project is located in the UK sector of the North Sea and we successfully completed an exploratory appraisal well in 2007.  We are currently working with the project operator and other partners to finalize the field development plan and relevant operating agreements.
 
Selkirk (North Sea) – The Selkirk project is also located in the UK sector of the North Sea. Capitalized costs to date primarily consist of the cost of drilling an appraisal well which was then sidetracked to the original discovery well location, to ensure presence of effective reservoir, and suspended as a future producer. We are currently working with our non-operating partners on an alternative host and with the supply chain to reduce costs.
 
Note 7 – Asset Retirement Obligations
Asset retirement obligations consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. See Note 5 – Fair Value Measurements for a discussion of the methods and assumptions used to estimate the fair values of asset retirement obligations. Changes in asset retirement obligations were as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
   (in millions) 
Asset retirement obligations, beginning of period $211  $144 
Liabilities incurred in current period  1   14 
Liabilities settled in current period  (2)  (4)
Revisions  16   3 
Accretion expense  3   2 
Asset retirement obligations, end of period $229  $159 
  
Six Months Ended
June 30,
 
  2009  2008 
   (in millions) 
Asset Retirement Obligations, Beginning of Period $211  $144 
Liabilities Incurred in Current Period  4   14 
Liabilities Settled in Current Period  (8)  (7)
Revisions  17   6 
Accretion Expense  7   4 
Asset Retirement Obligations, End of Period $231  $161 
 

18
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)


Liabilities settled and revisions in 2009 relate primarily to our remainingthe Main Pass asset. Accretion expense is included in DD&A expense in the consolidated statements of operations.

15

Note 8 – Employee Benefit Plans
We have a noncontributory, tax-qualified defined benefit pension plan covering employees who were hired prior to May 1, 2006. We also have an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by the Internal Revenue Code of 1986, as amended. Net periodic benefit cost related to the retirement and restoration plans was as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
  (in millions) 
Service cost $3  $3 
Interest cost  3   3 
Expected return on plan assets  (3)  (3)
Other  1   - 
Net periodic benefit cost $4  $3 
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
  (in millions) 
Service Cost $3  $3  $6  $6 
Interest Cost  3   3   6   6 
Expected Return on Plan Assets  (3)  (3)  (7)  (6)
Other  -   1   1   1 
Net Periodic Benefit Cost $3  $4  $6  $7 

 
Note 9 – Stock-Based Compensation
We recognized stock-based compensation expense as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
  (in millions) 
Stock-based compensation expense $12  $9 
Tax benefit recognized  (4)  (3)
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
  (in millions) 
Stock-Based Compensation Expense $12  $11  $24  $20 
Tax Benefit Recognized  (4)  (4)  (8)  (8)
 
During the threesix months ended March 31,June 30, 2009, we granted 1.5 million stock options with a weighted-average grant-date fair value of $18.75$18.76 per share and awarded 0.6 million shares of restricted stock subject to service conditions with a weighted-average grant-date fair value of $50.21$50.33 per share. In 2009, we began making grants of restricted stock under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan that will time-vest 20% after year one, an additional 30% after year two and the remaining 50% after year three.
 
On April 28, 2009, our stockholders approved an amendment to the 1992 Stock Option and Restricted Stock Plan (the Plan) that increased the number of shares of our common stock authorized for issuance under the Plan from 22 million to 24 million.

19
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)


Note 10 – Basic and Diluted Earnings (Loss) Per Share
Basic earnings (loss) per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of common stock may include the effect of Noble Energy shares held in a rabbi trust, outstanding stock options or shares of restricted stock, except in periods in which there is a net loss. The following table summarizes the calculation of basic and diluted earnings (loss) per share:
 
  Three Months Ended March 31, 
  2009  2008 
     Weighted    Weighted 
  Net  Average  Net  Average 
  (Loss)  Shares  Income  Shares 
  (in millions, except per share amounts) 
Net income (loss) $(188)  173  $215   172 
Basic Earnings (Loss) Per Share $(1.09)     $1.25     
Net income (loss) $(188)  173  $215   172 
Plus incremental shares from assumed conversions:             
Dilutive options, restricted stock awards and shares
of common stock in rabbi trust
  -   -   (4)  3 
Net income (loss) available to common shareholders $(188)  173  $211   175 
Diluted Earnings (Loss) Per Share $(1.09)     $1.20     
   Net Income (Loss)   Weighted Average SharesNet Income (Loss)  Weighted Average Shares 
   2009   2008 
   (in millions, except per share amounts) 
Three Months Ended June 30:                
Net Income (Loss) $       (57)               173  $(144)              172 
Basic Earnings (Loss) Per Share $   (0.33)      $(0.84)    
Net Income (Loss) $       (57)               173  $(144)              172 
Plus Incremental Shares from Assumed Conversions:                
Dilutive Options, Restricted Stock and Shares of Common Stock in Rabbi Trust              -                   -               -                  - 
Net Income (Loss) Available to Common Shareholders $  (57)               173  $(144)              172 
Diluted Earnings (Loss) Per Share $ (0.33)     $(0.84)    
                 
Six Months Ended June 30:                
Net Income (Loss) $  (245)               173  $71               172 
Basic Earnings (Loss) Per Share $ (1.42)      $0.41     
Net Income (Loss) $ (245)               173  $71               172 
Plus Incremental Shares from Assumed Conversions:                
Dilutive Options, Restricted Stock and Shares of Common Stock in Rabbi Trust              -                   -               -                   3 
Net Income (Loss) Available to Common Shareholders $ (245)              173  $71               175 
Diluted Earnings (Loss) Per Share $  (1.42)      $0.41     
 
16

The effect of stock options and unvested restricted stock outstanding has not been included in the calculation of weighted average shares outstanding for diluted EPSearnings per share for the threesecond quarter 2009, the first six months ended March 31,of 2009 and the second quarter 2008 as their effect would have been antidilutive. Had we recognized net income for this period,these periods, incremental shares attributable to the assumed exercise of outstanding options and restricted stock would have increased diluted weighted average shares outstanding by 1.61.9 million shares for the three months ended March 31, 2009.June 30, 2009, 1.8 million shares for the six months ended June 30, 2009 and 2.5 million shares for the three months ended June 30, 2008.
 
A total of 4.64.2 million and 4.4 million weighted average stock options, restricted shares and common shares held in a rabbi trust were antidilutive for the second quarter and first quartersix months of 2009, respectively, and were excluded from the calculation of diluted earnings per share.  A total of 1.21.1 million weighted average stock options, and restricted shares and common shares  held in a rabbi trust were antidilutive for the second quarter and first quartersix months of 2008 and were excluded from the calculation of diluted earnings per share.
 

20
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)

Note 11 – Income Taxes
The income tax provision (benefit) consists of the following:

 Three Months Ended 
 March 31,  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
 2009  2008  2009  2008  2009  2008 
 (in millions)  (in millions) 
Current $115  $66  $25  $(28) $141  $38 
Deferred  (301)  35   (58)  (26)  (359)  10 
Total income tax provision (benefit) $(186) $101 
Total Income Tax Provision (Benefit) $(33) $(54) $(218) $48 
 
The deferred tax benefit for the threesix months ended March 31,June 30, 2009 was due primarily to the fact that mostresult of the reversal of a deferred tax liability recorded in 2008 with respect to unrealized mark-to-market gains reverseswhich were realized in 2009.  In addition, we recorded a deferred tax asset with respect to impairment losses on our US oil and gas properties.
 
Our effective tax rate increased to 50%47% for the first quartersix months of 2009 as compared with 32%40% for the first quartersix months of 2008 due primarily toand is the fact that the 2009 rate representsresult of a tax benefit divided by a pre-tax loss.  In thatthe case of a loss, our favorable permanent differences, such as income from equity method investees, have the effect of increasing the tax benefit which, in turn, increases the effective rate.
 
During first quarter 2009, we repatriated $180 million of accumulated earnings of foreign subsidiaries and used the proceeds for debt repayment and general corporate purposes. The repatriation increased US current tax expense by $11 million.  In addition, we reversed a $9 million, US deferred tax liability that had beenwhich was recorded in 2008 with respect to the repatriated earnings.2008. Repatriation of additional earnings in the future could result in a decrease in our net income and cash flows.
 
Unrecognized Tax Positions – We do not have significant unrecognized tax benefits as of March 31,June 30, 2009. Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. We did not accrue interest or penalties at March 31,June 30, 2009, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest on underpayments of tax, and we believe that we are below the minimum statutory threshold for imposition of penalties.
 
In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2005, Equatorial Guinea – 2006,2007, China – 2006, Israel – 2000, UK – 20062007 and the Netherlands – 2005.

17
 
Note 12 – Comprehensive Income (Loss)
Comprehensive income (loss) includes net income (loss) and certain items recorded directly to shareholders’ equity and classified as AOCL. Comprehensive income (loss) was calculated as follows:
 
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
  (in millions) 
Net Income (Loss) $(57) $(144) $(245) $71 
Other Items of Comprehensive Income (Loss)                
Oil and Gas Cash Flow Hedges                
Realized Losses Reclassified Into Earnings  15   95   32   155 
Less Tax Provision  (6)  (36)  (12)  (58)
Interest Rate Cash Flow Hedges                
Unrealized Change in Fair Value (Gain / (Loss))  -   32   -   (11)
Less Tax Provision  -   (12)  -   4 
Net Change in Other  -   -   (1)  (1)
Other Comprehensive Income  9   79   19   89 
Comprehensive Income (Loss) $(48) $(65) $(226) $160 
  Three Months Ended 
  March 31, 
  2009  2008 
  (in millions) 
Net income (loss) $(188) $215 
Other items of comprehensive income (loss)        
Oil and gas cash flow hedges        
Realized amounts reclassified into earnings  17   60 
Less tax provision  (6)  (22)
Interest rate cash flow hedges        
Unrealized change in fair value  -   (43)
Less tax provision  -   16 
Net change in other  (1)  (1)
Other comprehensive income  10   10 
Comprehensive income (loss) $(178) $225 

21
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)


Note 13 – Segment Information
We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are all primarily in the business of crude oil and natural gas acquisition, exploration and production:  the United States; West Africa;Africa (Equatorial Guinea and Cameroon); the North Sea; Israel;Sea (UK and the Netherlands); Eastern Mediterranean (Israel and Cyprus); and Other International, Corporate and Marketing. Other International includes primarily Argentina (through February 2008), China, Ecuador and Suriname. The following data was prepared on the same basis as our consolidated financial statements and excludes the effects of income taxes.
 
                 Other Int'l, 
     United  West  North     Corporate, 
  Consolidated  States  Africa  Sea  Israel  Marketing 
  (in millions) 
Three Months Ended March 31, 2009                  
Revenues from third parties $447  $237  $58  $34  $28  $90 
Reclassification from AOCL (1)
  (17)  (9)  (8)  -   -   - 
Intersegment revenue  -   52   -   -   -   (52)
Income from equity method investees
  11   -   11   -   -   - 
Total Revenues  441   280   61   34   28   38 
                         
DD&A  200   169   9   9   5   8 
Asset impairments  437   437   -   -   -   - 
Gain on commodity derivative instruments  (73)  (67)  (6)  -   -   - 
Income (loss) before income taxes  (374)  (409)  42   11   21   (39)
                         
Three Months Ended March 31, 2008                        
Revenues from third parties  1,023  $577  $141  $92  $40  $173 
Reclassification from AOCL (1)
  (60)  (48)  (12)  -   -   - 
Intersegment revenue  -   116   -   -   -   (116)
Income from equity method investees
  62   -   62   -   -   - 
Total Revenues  1,025   645   191   92   40   57 
                         
DD&A  203   164   9   16   6   8 
Loss on commodity derivative instruments  237   209   28   -   -   - 
Income (loss) before income taxes  316   145   150   55   31   (65)
Total assets at March 31, 2009 (2)
 $12,042  $9,008  $1,590  $581  $407  $456 
Total assets at December 31, 2008 (2)
  12,384   9,212   1,614   775   366   417 
  Consolidated  United States  West Africa  North Sea  Eastern Mediter-ranean  Other Int'l, Corporate, Marketing 
  (in millions) 
Three Months Ended June 30, 2009                  
Revenues from Third Parties $490  $275  $85  $35  $24  $71 
Reclassification from AOCL (1)
  (15)  (8)  (7)  -   -   - 
Intersegment Revenue  -   36   -   -   -   (36)
Income from Equity Method Investees  16   -   16   -   -   - 
Total Revenues  491   303   94   35   24   35 
                         
DD&A  196   164   9   9   5   9 
Loss on Commodity Derivative Instruments  139   109   30   -   -   - 
Income (Loss) Before Income Taxes  (90)  (72)  40   13   14   (85)
                         
Three Months Ended June 30, 2008                        
Revenues from Third Parties $1,244  $752  $163  $99  $30  $200 
Reclassification from AOCL (1)
  (95)  (84)  (11)  -   -   - 
Intersegment Revenue  -   144   -   -   -   (144)
Income from Equity Method Investees  56   -   56   -   -   - 
Total Revenues  1,205   812   208   99   30   56 
                         
DD&A  196   165   9   12   5   5 
Loss on Commodity Derivative Instruments  828   677   151   -   -   - 
Income (Loss) Before Income Taxes  (198)  (214)  38   72   23   (117)



22
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)

  Consolidated  United States  West Africa  North Sea  Eastern Mediter-ranean  Other Int'l, Corporate, Marketing 
  (in millions) 
Six Months Ended June 30, 2009                  
Revenues from Third Parties $937  $511  $144  $69  $52  $161 
Reclassification from AOCL (1)
  (32)  (16)  (16)  -   -   - 
Intersegment Revenue  -   88   -   -   -   (88)
Income from Equity Method Investees  27   -   27   -   -   - 
Total Revenues  932   583   155   69   52   73 
                         
DD&A  396   333   18   18   10   17 
Asset Impairments  437   437   -   -   -   - 
Loss on Commodity Derivative Instruments  66   42   24   -   -   - 
Income (Loss) Before Income Taxes  (463)  (481)  82   24   35   (123)
                         
Six Months Ended June 30, 2008                        
Revenues from Third Parties $2,267  $1,329  $304  $191  $70  $373 
Reclassification from AOCL (1)
  (155)  (132)  (23)  -   -   - 
Intersegment Revenue  -   260   -   -   -   (260)
Income from Equity Method Investees  118   -   118   -   -   - 
Total Revenues  2,230   1,457   399   191   70   113 
                         
DD&A  399   329   18   28   11   13 
Loss on Commodity Derivative Instruments  1,065   886   179   -   -   - 
Income (Loss) Before Income Taxes  119   (68)  188   127   54   (182)
Total Assets at June 30, 2009 (2)
  11,851   8,849   1,590   593   427   392 
Total Assets at December 31, 2008 (2)
  12,384   9,212   1,614   775   366   417 
 
(1)Revenues include decreases resulting from hedging activities. The decreases resulted from hedge gains and losses that were deferred in AOCL, as a result of previous cash flow hedge accounting, and subsequently reclassified to revenues.
(2)The US reporting unit includes goodwill of $757$758 million at March 31,June 30, 2009 and $759 million at December 31, 2008.
 

1823
NOBLE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)

Note 14 – Commitments and Contingencies
Purchaser Bankruptcy – We have an exposure from crude oil sales for the months of June and July 2008 to SemCrude, L.P. (SemCrude), a subsidiary of SemGroup, L.P. (SemGroup).  On July 22, 2008, SemGroup, including SemCrude, filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code under Case Number 08-11525 (BLS) in the United States Bankruptcy Court for the District of Delaware. Bankrupcty proceedings are ongoing as of June 30, 2009.
 
We have a receivable of approximately $70 million from SemCrude. During 2008, we determined that it was probable that a portion of the receivable was uncollectible and reduced the carrying value of the SemCrude receivable by $38 million for the probable loss. We are pursuing various legal remedies to protect our interests. We believe that ultimate disposition of this matter will not have a material adverse affect on our financial position, results of operations, or cash flows.
 
Legal Proceedings– We are among a group of 18 defendantswere named in a lawsuit filed August 23, 2002 by Dore Energy Corporation under Docket Number 10-16202 in the 38th Judicial District Court, Cameron Parish, Louisiana. The lawsuit allegesalleged damage to property owned by Dore resulting from oil and gas activities dating to the 1930’s.  Our predecessor, Samedan Oil Corporation, operated on a portion of the property from 1989 to 1999.  Dore has delivered documents alleging approximately $140 million in damages. Dore has obtained judgment or settlement with certain defendants, and trial involving Dore’s claims against us, whichactivities. Trial began on April 27, 2009, and is ongoing.  We intend to vigorously defend against these allegations and believe that our share2009; however, we reached a confidential settlement with Dore on May 7, 2009. The amount of damages, if any, willthe settlement did not have a material adverse effect on our financial position results of operations, or cash flowsflows..
 
We are involved in various other legal proceedings in the ordinary course of business.  These proceedings are subject to the uncertainties inherent in any litigation.  We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
 
Note 15 – Recently Issued Pronouncements
Recent FASB Staff Positions – In April 2009, the FASB issued three related staff positions to clarify the application of SFAS 157 to fair value measurements in the current economic environment, modify the recognition of other-than-temporary impairments of debt securities, and require companies to disclose the fair value of financial instruments in interim periods. The final staff positions are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009, if all three staff positions or both the fair value measurements and other-than-temporary impairment staff positions are adopted simultaneously.
·
FSP SFAS 157-4 – FASB Staff Position No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability has Significantly Decreased and Identifying Transactions That Are Not Orderly” provides guidance on how to determine the fair value of assets and liabilities under SFAS 157 in the current economic environment and reemphasizes that the objective of a fair value measurement remains the price that would be received to sell an asset or paid to transfer a liability at the measurement date.
·
FSP SFAS 115-2 and SFAS 124-2 – FASB Staff Position No. 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” modifies the requirements for recognizing other-than-temporarily impaired debt securities and significantly changes the existing impairment model for such securities. It also modifies the presentation of other-than-temporary impairment losses and increases the frequency of and expands already required disclosures about other-than-temporary impairment for debt and equity securities.
·
FSP SFAS 107-1 and APB 28-1 – FASB Staff Position No. 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” requires disclosures of the fair value of financial instruments within the scope of SFAS 107 in interim financial statements, adding to the current requirement to make those disclosures in annual financial statements. The staff position also requires that companies disclose the method or methods and significant assumptions used to estimate the fair value of financial instruments and a discussion of changes, if any, in the method or methods and significant assumptions during the period.
We will adopt the new staff positions as of July 1, 2009. We are currently evaluating the provisions of the staff positions and assessing the impact, if any, they may have on our financial position and results of operations.

19
Recent SEC Rule-Making Activity – In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following:
 
·
Commodity Prices – Economic producibility of reserves and discounted cash flows will be based on a 12-month average commodity price unless contractual arrangements designate the price to be used.
 ·Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.
 ·Proved Undeveloped Reserve Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered.
 ·Reserve Estimation Using New Technologies – Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
 ·Reserve Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees our reserves estimation process.  We will also be required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
 ·Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of our total oil and gas proved reserves.
 ·
Non-Traditional Resources – The definition of oil and gas producing activities will expand and focus on the marketable product rather than the method of extraction.
 
The rules are effective for fiscal years ending on or after December 31, 2009, and early adoption is not permitted.  We are currently evaluating the new rules and assessing the impact they will have on our reported oil and gas reserves.  The SEC is coordinating with the Financial Accounting Standards Board (FASB) to obtain the revisions necessary to SFAS 19, “Financial AccountingUS GAAP concerning financial accounting and Reportingreporting by Oiloil and Gas Producing Companies”,gas producing companies and SFAS 69, "Disclosures About Oildisclosures about oil and Gas Producing Activities",gas producing activities to provide consistency with the new rules. In the event that consistency is not achieved in timeThe FASB expects to issue both a Proposed Accounting Standards Update and a Final Accounting Standards Update for companies to comply with the new rules, the SEC has indicated that it will consider delaying the compliance date.Oil and Gas Disclosures during third quarter 2009.
 


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

EXECUTIVE OVERVIEW
 
We are an independent energy company engaged in worldwide crude oil, natural gas and NGL exploration and production. We operate primarily in the Rocky Mountains, Mid-continent, and deepwater Gulf of Mexico areas in the US, with keywith significant international operations offshore Israel, the North SeaUK and West Africa.
 
Our accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be referred to in conjunction with the following discussion.
 
Our financial results for firstsecond quarter 2009 included:
 
·      net loss of $188 million, as compared with $215 million net income for first quarter 2008;
 ·$437net loss of $57 million, as compared with a net loss of asset impairment charges;$144 million for second quarter 2008;
 ·collectionloss on commodity derivative instruments of Ecuador power receivable, resulting in$139 million as compared with a $46loss of $828 million reversalfor second quarter 2008;
·gain of $24 million on the allowance for doubtful accounts;completed Argentina asset sale;
 ·diluted loss per share of $1.09,$0.33, as compared with diluted earningsloss per share of $1.20$0.84 for firstsecond quarter 2008;
·ending cash and cash equivalents balance of $956 million; and
 ·cash flow provided by operating activities of $185$313 million, as compared with $506$648 million for firstsecond quarter 2008;2008.
Significant operational highlights for second quarter 2009 included:
·
successful Tamar appraisal well offshore Israel;
 ·issuancesuccessful flow test at the Dalit natural gas discovery offshore Israel;
·record Wattenberg field production of $1 billion in 10-year unsecured notes;282 MMcfepd, including liquid production of over 21 MBopd; and
 ·repatriationaward of $180 million22 of earningsthe 24 high bid lease blocks from foreign subsidiaries.

Significant operational highlights for first quarter 2009 included:
·exploration success offshore Israel at Tamar, our largest discovery to date;
·additional natural gas discovery offshore Israel at Dalit;
·our first oil discovery on Block O offshore Equatorial Guinea at the Carmen prospect;
·successful high bidder on 24 deepwater blocks in Central Gulf of Mexico lease sale 208; and208.
·deepwater Gulf of Mexico discovery at Santa Cruz.

Sanction of Aseng Oil Project – On July 22, 2009, we announced that the Plan of Development for the Aseng oil project has been sanctioned by us, our partners, and the Ministry of Mines, Industry, and Energy of the Republic of Equatorial Guinea.  We serve as technical operator of the development with a 40% working interest.
Formerly known as Benita, Aseng was originally discovered in 2007 as a gas-condensate field in Block I offshore Equatorial Guinea. Subsequently, two appraisal wells were drilled in the structure, with the first identifying the oil resources and the second determining downdip reservoir limits.
Initial development of the field will include multiple subsea wells flowing to a floating production, storage, and offloading vessel (FPSO) where the production stream will be separated.  The oil will be stored on the vessel until sold, while the natural gas and water will be re-injected back into the reservoir to maintain pressure and maximize oil recoveries. The FPSO will be designed with capacity to handle 120,000 barrels of liquids per day, including 80,000 barrels of oil per day. In addition, the vessel will be capable of reinjecting 170 million cubic feet per day of natural gas. Storage on the vessel will be approximately 1.5 million barrels of oil and condensate.
Total development costs, excluding the costs related to the FPSO, are estimated at $1.3 billion ($530 million net) with the majority of this capital to be invested in 2010 and 2011. FPSO services are expected to be acquired through a leasing agreement and, depending on the terms of the agreement, will likely require capital lease accounting treatment. First production from the field is estimated to commence by mid-year 2012 at 50,000 barrels of oil per day gross (16,500 barrels per day net). The FPSO lease has not yet been awarded.
Impact of Recession and Current Credit and Commodity Markets – During first quarter 2009, we took initiatives to strengthen our liquidity and lengthen our weighted average debt maturities in response to ongoing uncertainty in the credit markets.  In February we issued $1 billion of 8¼% senior notes due 2019 and used substantially all of the net proceeds to repay outstanding indebtedness under our credit facility.  As a result, the amount available under our credit facility increased to almost $1.4 billion at March 31, 2009. In addition, we repatriated $180 million of accumulated earnings of foreign subsidiaries and used the proceeds for debt repayment and general corporate purposes. See Liquidity and Capital Resources below.
 


As noted in our 2008 Annual Report on Form 10-K (Item 1A. Risk Factors), significant decreases in crude oil and natural gas prices could result in a reduction of the carrying values of our oil and gas properties.  The commodity price decreases that began during the second half of 2008 required us to record asset impairment charges during fourth quarter 2008.  Further declines in natural gas prices during first quarter 2009 led us to review those properties that, at year-end 2008, were susceptible to impairment should commodity prices continue to decline appreciably.  As a result of this review, we determined that additional properties were impaired as of March 31, 2009. Total pre-tax (non-cash) impairments for first quarter 2009 were $437 million and were predominately related to Granite Wash, an onshore US area in which we have significantly reduced investments beginning in 2007. The decrease in the natural gas futures price strip that occurred during first quarter 2009 was the primary factor that required an impairment of Granite Wash.  See Item 1. Financial Statements – Note 5 – Fair Value Measurements. FurtherThere were no asset impairments during second quarter 2009. However, further declines in commodity prices could result in additional impairment of our oil and gas properties, other long-lived assets or goodwill. See Item 1. Financial Statements – Note 5 – Fair Value Measurements.
 
ContinuedDuring second quarter 2009, our operations benefited from the strengthening crude oil market, but sustained lower commodity prices will continue to reduce our cash flows from operations. To mitigate the impact of lower commodity prices on our cash flows, we have entered into crude oil commodity contracts for 2009 and 2010 and natural gas commodity contracts for 2009, 2010 and 2011. Depending on the length of the current recession, commodity prices may stay depressed or decline further, thereby causing a prolonged downturn, which would further reduce our cash flows from operations.  This could cause us to alter our business plans including reducing or delaying our exploration and development program spending and other cost reduction initiatives.  See 2009 Budget below.
 
We are closely monitoring costs and have implemented several cost savings initiatives, including continued reduction of well costs through drilling and completion efficiencies and comprehensive review of oil and gas operating costs.  We are also beginning to see reductions in third party drilling costs and operating supplies and services.
 

21

OUTLOOK
 
Our expected crude oil, natural gas and NGL production for the remainder of 2009 may be impacted by several factors including:
 
 ·
overall level and timing of capital expenditures, as discussed below, which, dependent upon our drilling success, are expected to result inmaintain our near-term production growth;volumes;
 ·natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-continent areas of our US operations and the North Sea;
 ·highervariations in sales volumes of natural gas from the Alba field in Equatorial Guinea;
 ·potential hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast areas of our US operations as occurred with Hurricanes Gustav and Ike in 2008;
 ·timing of the full restoration of pipeline and facilities necessary to increase our Gulf of Mexico production;
 ·potential winter storm-related volume curtailments in the Northern region of our US operations;
 ·potential pipeline and processing facility capacity constraints in the Rocky Mountains area of our US operations and timing of start-up of a new interstate crude oil transportation pipeline system which will run from Weld County, Colorado to Cushing, Oklahoma;operations;
·growth in demand for natural gas in Israel;
 ·Israeli seasonal demand;
·competingdemand for electricity which affects demand for natural gas as fuel for power generation, market growth and competing deliveries in Israelof natural gas from Egypt, which could lower our sales volumes;Egypt;
 ·potential downtime at the methanol, LPG and/or LNG plants in Equatorial Guinea;
 ·seasonal variations in rainfall in Ecuador that affect our natural gas-to-power project; and
 ·timing of significant project completion and initial production.

2009 Budget – Due to the uncertain economic and commodity price environment, we have designed a flexible capital spending program that will beis responsive to conditions that develop during 2009.  Our revised capital program for 2009 accommodates an investment level of $1.6 billion, with the ability to adjust up or down by approximately 15%. Currently we are managing towards an investment level of approximately $1.4 billion, the lower end of this range.  
 
Approximately 40% of the 2009 budget is committed to longer-term projects that will provide considerable production growth several years in the future. The remainder is allocated toward maintaining and strengthening the existing property base.  Development spending will focusis focused on our international and deepwater Gulf of Mexico assets as well as certain higher return opportunities onshore in the US including the Wattenberg field.  The exploration budget will centeris centered on significant resource potential in Israel, West Africa and the deepwater Gulf of Mexico.  International expenditures are estimated to represent 30% of the total capital program.
 
The 2009 budget does not include the impact of possible asset purchases. We expect that the remaining 2009 budget will be funded primarily from cash flows from operations, cash on hand, and borrowings under our revolving credit facility. We will evaluate the level of capital spending throughout the remainder of the year based on drilling results, commodity prices, cash flows from operations and property acquisitions and divestitures.
 


Recently Issued Pronouncements – See Item 1. Financial Statements – Note 15 – Recently Issued Pronouncements.
 

22

RESULTS OF OPERATIONS
 
Oil, Gas and NGL Sales
Revenues from sales of commodities were as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
  (in millions) 
Crude oil and condensate sales $202  $527 
Natural gas sales  183   371 
NGL sales  21   46 
Total $406  $944 
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
  (in millions) 
Crude Oil and Condensate Sales $296  $674  $497  $1,200 
Natural Gas Sales  143   399   326   771 
NGL Sales  21   57   43   103 
Total $460  $1,130  $866  $2,074 


 
Average daily sales volumes and average realized sales prices were as follows:
 
 Sales Volumes     Average Realized Sales Prices   Sales Volumes  Average Realized Sales Prices 
 Crude Oil &  Natural     Crude Oil &  Natural      Crude Oil & Condensate (MBopd)  Natural Gas (MMcfpd)  NGLs (MBpd)  Crude Oil & Condensate (Per Bbl) Natural Gas (Per Mcf)  NGLs (Per Bbl) 
 Condensate  Gas  NGLs  Condensate  Gas  NGLs 
 (MBopd)  (MMcfpd)  (MBpd)  (Per Bbl)  (Per Mcf)  (Per Bbl) 
Three Months Ended March 31, 2009                
United States (1)
  35   411   9  $35.65  $3.93  $24.74 
West Africa (2) (3)
  13   243   -   39.41   0.27   - 
Three Months Ended June 30, 2009              
United States (1) (2)
                    37               394             10 $  51.85 $3.09 $  23.94 
West Africa (3) (4)
                    15               244                -         51.63         0.27                - 
North Sea  7   5   -   45.91   8.17   -                       6                   5                -         56.57         5.20                - 
Israel  -   112   -   -   2.81   -                       -                 95                -                -         2.76                - 
Ecuador (4)
  -   30   -   -   -   - 
Ecuador (5)
                      -                 16                -                -               -                - 
Other International  4   -   -   36.89   -   -                       5                    -                 -          48.87                -                 - 
Total Consolidated Operations  59   801   9   37.81   2.64   24.74                     63               754             10         52.05         2.13        23.94 
Equity Investees (5)
  2   -   7   41.76   -   26.89 
Equity Investees (6)
                      2                    -                6          56.12                -         30.12 
Total  61   801   16  $37.91  $2.64  $25.62                     65                754              16 $ 52.19 $2.13 $ 26.24 
Three Months Ended March 31, 2008                     
United States (1)
  43   393   9  $71.33  $8.97  $55.15 
West Africa (2) (3)
  15   220   -   88.79   0.27   - 
Three Months Ended June 30, 2008              
United States (1) (2)
                    44               402             10 $ 99.05 $9.82 $59.65 
West Africa (3) (4)
                    14               222                -       112.32         0.27                - 
North Sea  9   6   -   100.46   9.65   -                       8                   5                -       126.05       10.81                - 
Israel  -   145   -   -   3.04   -                       -               121                -                -         2.72                - 
Ecuador (4)
  -   23   -   -   -   - 
Ecuador (5)
                      -                 22                -                -               -                - 
Other International  6   -   -   73.37   -   -                       4                    -                 -        109.17                -                 - 
Total Consolidated Operations  73   787   9   78.89   5.34   55.15                     70               772             10       105.46         5.86        59.65 
Equity Investees (5)
  2   -   6   98.55   -   60.78 
Equity Investees (6)
                      2                    -                7        118.95                -         69.70 
Total  75   787   15  $79.43  $5.34  $57.47                     72                772              17 $ 105.74 $5.86 $ 63.75 
Six Months Ended June 30, 2009              
United States (1) (2)
                    36               403             10 $ 43.92 $3.52 $ 24.33 
West Africa (3) (4)
                    14               243                -         46.19         0.27                - 
North Sea                      7                   5                -         50.81         6.72                - 
Israel                      -               103                -                -         2.78                - 
Ecuador (5)
                      -                 23                -                -               -                - 
Other International                      4                    -                 -          43.28                -                 - 
Total Consolidated Operations                    61               777             10         45.17         2.39        24.33 
Equity Investees (6)
                      2                    -                6          50.38                -         28.38 
Total                    63                777              16 $45.32 $2.39 $ 25.92 
Six Months Ended June 30, 2008              
United States (1) (2)
                    43               397             10 $ 85.36 $9.40 $ 57.55 
West Africa (3) (4)
                    15               221                -       100.16         0.27                - 
North Sea                      9                   6                -       112.36       10.18                - 
Israel                      -               133                -                -         2.90                - 
Ecuador (5)
                      -                 23                -                -               -                - 
Other International                      5                    -                 -          87.47                -                 - 
Total Consolidated Operations                    72               780             10         91.88         5.60        57.55 
Equity Investees (6)
                      2                    -                7        107.01                -         65.50 
Total                    74                780              17 $ 92.24 $5.60 $60.80 
 
(1)
Average realized crude oil and condensate prices reflect reductions of $2.70$2.29 per Bbl and $20.46 per Bbl for firstsecond quarter 2009 and $21.812008, respectively, and reductions of $2.49 per Bbl and $21.13 per Bbl for the first quartersix months of 2009 and 2008, respectively, from hedging activities. The price reductions resulted from hedge gains and losses that were previously deferred in AOCL.

(2) Average realized natural gas prices reflect an increase of $0.01 per Mcf and a reduction of $0.01$0.06 per Mcf for firstsecond quarter 2009 and 2008, respectively, and an increase of $1.05$0.49 per Mcf for the first quartersix months of 2008 from hedging activities.  The price reductionsincreases and increasereduction resulted from hedge gains and losses that were previously deferred in AOCL. The average realized natural gas price for the first six months of 2009 was not impacted by hedging activities, as the net deferred gain reclassified from AOCL was de minimis.
(2)(3) Average realized crude oil and condensate prices reflect reductions of $7.08$5.33 per Bbl and $8.20 per Bbl for firstsecond quarter 2009 and $8.622008, respectively, and $6.11 per Bbl and $8.42 per Bbl for the first quartersix months of 2009 and 2008, respectively, from hedging activities.  The price reductions resulted from hedge losses that were previously deferred in AOCL.
(3)(4) 
Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.  Natural gas volumes sold to the LNG plant totaled 188200 MMcfpd and 175 MMcfpd during firstsecond quarter 2009 and 1732008, respectively, and 194 MMcfpd and 174 MMcfpd during the first quarter 2008.
six months of 2009 and 2008, respectively.

23

(4)(5) The natural gas-to-power project in Ecuador is 100% owned by our subsidiaries and intercompany natural gas sales are eliminated for accounting purposes. Electricity sales are included in other revenues. See Item 1. Financial Statements – Note 2 – Basis of Presentation.
(5)(6) 
Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Equity Method Investees below.
 
Crude oil and condensate sales volumes in the table above differ from actual production volumes due to the timing of liquid hydrocarbon tanker liftings. Crude oil and condensate production volumes were as follows:
 
 Three Months Ended March 31,  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
 2009  2008  2009  2008  2009  2008 
 (MBopd)  (MBopd) 
United States  35   43   37   44   36   43 
West Africa  15   15   14   15   14   15 
North Sea  8   11   8   9   8   10 
Other International  4   6   5   4   4   5 
Total Consolidated Operations  62   75   64   72   62   73 
Equity Investees  2   2   2   2   2   2 
Total  64   77   66   74   64   75 
 


If the realized gains and losses on commodity derivative instruments, which are included in (gain) loss on commodity derivative instruments, had been included in oil and gas revenues, the effect on average realized prices would have been as follows:
 
 Three Months Ended March 31,  Crude Oil & Condensate  Natural Gas  Crude Oil & Condensate  Natural Gas 
 2009  2008  2009  2008 
 Crude Oil &  Natural  Crude Oil &  Natural  (Per Bbl)  (Per Mcf)  (Per Bbl)  (Per Mcf) 
 Condensate  Gas  Condensate  Gas  Commodity Price Increase (Decrease) 
 (Per Bbl)  (Per Mcf)  (Per Bbl)  (Per Mcf) 
Three Months Ended June 30,            
United States $56.78  $5.51  $70.02  $8.63  $13.39  $2.00  $(13.84) $(1.09)
West Africa  64.21   0.27   87.39   0.27   15.77   -   (12.42)  - 
Total Consolidated Operations  55.65   3.48   77.83   5.16   11.68   1.07   (11.19)  (0.58)
Total  55.32   3.48   78.40   5.16   11.29   1.07   (10.96)  (0.58)
                
Six Months Ended June 30,                
United States $17.18  $1.79  $(7.65) $(0.72)
West Africa  19.79   -   (6.72)  - 
Total Consolidated Operations  14.65   0.95   (6.01)  (0.38)
Total  14.23   0.95   (5.87)  (0.38)
 
Crude Oil and Condensate Sales – Crude oil and condensate sales decreased during the second quarter and first quartersix months of 2009 as compared with first quarter 2008 due to the significant decrease in average realized prices combined with a decline inlower sales volumes.  The decreaseDecreases in US sales volumes waswere due to continuedthe ongoing impact of shut-ins related to Hurricane Ike-related shut-ins of certainIke in the deepwater Gulf of Mexico assets, the timing of liftings in Equatorial Guinea and the North Sea and natural field decline in the deepwater Gulf of Mexico and Gulf Coast area. These decreases were offset somewhat by increases in production in the Northern region.
Internationally, sales remained relatively flat, although North Sea.Sea volumes declined due to natural field decline and the timing of liftings.
 
Revenues included deferred losses of $15 million and $93 million for firstsecond quarter 2009 and 2008, included deferred losses of $17respectively, and $32 million and $97$190 million for the first six months of 2009 and 2008, respectively, reclassified from AOCL and related to commodity derivative instruments previously accounted for as cash flow hedges.
 
Natural Gas Sales – Natural gas sales decreased during the second quarter and first quartersix months of 2009 as compared with first quarter 2008 primarily due to the significant decrease in average realized prices. The effect ofIn the price decreases wasUS, increases in natural gas production from the Wattenberg, Piceance and Tri-state areas were partially offset by an overall increasethe ongoing impact of shut-ins related to Hurricane Ike in sales volumes due to the following:deepwater Gulf of Mexico and natural field decline in the deepwater Gulf of Mexico and Gulf Coast area.
 
·increase in production from the Wattenberg, Piceance and Tri-state areas of our North America operations; and
International volumes also declined overall.  In Israel, power plant downtime, an overall decrease in demand and competing natural gas sales from Egypt led to decreased natural gas sales. West Africa sales volumes were higher primarily due to increased natural gas sales to the third-party LNG facility.
·increase in volumes sold to the LNG plant in Equatorial Guinea;
and partially offset by:
·decrease in Israel sales volumes due to power plant downtime and milder weather conditions; and
·continued Hurricane Ike-related shut-ins of certain deepwater Gulf of Mexico assets.

Revenues included a deferred loss of $2 million for firstsecond quarter 2008 includedand a deferred gain of $37$35 million for the first six months of 2008 reclassified from AOCL and related to commodity derivative instruments previously accounted for as cash flow hedges. Revenues for the second quarter and first quartersix months of 2009 included a de minimis amount reclassified from AOCL and related to commodity derivative instruments previously accounted for as cash flow hedges.
 

24

NGL Sales – Most of our US NGL production is from the Wattenberg field and deepwater Gulf of Mexico. NGL sales decreased during the second quarter and first quartersix months of 2009 as compared with first quarter 2008 due to a 55%the significant decrease in average realized NGL prices.
 

30

Equity Method Investees
Our share of operations of equity method investees, Atlantic Methanol Production Company, LLC (AMPCO) and Alba Plant LLC (Alba Plant), was as follows:
 
 Three Months Ended  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
 March 31,  2009  2008  2009  2008 
 2009  2008 
Net income (in millions):      
AMPCO and affiliates $-  $28 
Net Income (in millions):            
AMPCO and Affiliates $2  $17  $2  $45 
Alba Plant  11   34   14   39   25   73 
Distributions/dividends (in millions):        
AMPCO and affiliates $-  $34 
Distributions/Dividends (in millions):                
AMPCO and Affiliates  -   5   -   39 
Alba Plant  -   42   5   40   5   82 
Production volumes:        
Sales Volumes:                
Methanol (MMgal)  40   34   41   36   76   70 
Condensate (MBopd)  2   2   2   2   2   2 
LPG (MBpd)  6   6   6   7   6   7 
Sales volumes:        
Production Volumes:                
Methanol (MMgal)  35   34   29   31   68   63 
Condensate (MBopd)  2   2   2   2   2   2 
LPG (MBpd)  7   6   6   6   6   6 
Average realized prices:        
Average Realized Prices:                
Methanol (per gallon) $0.46  $1.63  $0.49  $1.15  $0.47  $1.38 
Condensate (per Bbl)  41.76   98.55   56.12   118.95   50.38   107.01 
LPG (per Bbl)  26.89   60.78   30.12   69.70   28.38   65.50 
 
The decrease in net income for each of the equity method investees for the second quarter and first quartersix months of 2009 as compared with first quarter 2008 was due to significant decreases in average realized prices. NoIn addition, during second quarter 2009 and 2008, AMPCO experienced downtime for refractory repairs and drew down inventory to meet customer demand. The decreases in Alba Plant distributions were made during the second quarter and first quartersix months of 2009 were due to the decreases in net income and in anticipation of planned tax payments.
 
Other Revenues
Other revenues include electricity sales and GMP revenues. See Item 1. Financial Statements – Note 2 – Basis of Presentation.
 

2531

Costs and Expenses
Production Costs – ProductionComponents of production costs were as follows:

  Total  United States  West Africa  North Sea  Israel 
Other Int'l, Corporate(1)
 
  (in millions) 
Three Months Ended June 30, 2009                  
Oil and Gas Operating Costs (2)
 $88  $60  $11  $9  $3  $5 
Workover and Repair Expense  5   5   -   -   -   - 
Lease Operating Expense  93   65   11   9   3   5 
Production and Ad Valorem Taxes  23   20   -   -   -   3 
Transportation Expense  13   11   -   1   -   1 
Total Production Costs  129   96   11   10   3   9 
Three Months Ended June 30, 2008                        
Oil and Gas Operating Costs (2)
  80   56   10   9   2   3 
Workover and Repair Expense  8   8   -   -   -   - 
Lease Operating Expense  88   64   10   9   2   3 
Production and Ad Valorem Taxes  51   41   -   -   -   10 
Transportation Expense  16   14   -   2   -   - 
Total Production Costs  155   119   10   11   2   13 
Six Months Ended June 30, 2009                        
Oil and Gas Operating Costs (2)
  180   131   20   17   4   8 
Workover and Repair Expense  13   11   -   2   -   - 
Lease Operating Expense  193   142   20   19   4   8 
Production and Ad Valorem Taxes  42   38   -   -   -   4 
Transportation Expense  25   21   -   2   -   2 
Total Production Costs  260   201   20   21   4   14 
Six Months Ended June 30, 2008                        
Oil and Gas Operating Costs (2)
  156   105   19   20   4   8 
Workover and Repair Expense  14   14   -   -   -   - 
Lease Operating Expense  170   119   19   20   4   8 
Production and Ad Valorem Taxes  94   74   -   -   -   20 
Transportation Expense  29   25   -   4   -   - 
Total Production Costs $ 293  $218  $19  $24  $4  $28 
     United  West  North    Other Int'l, 
  Total  States  Africa  Sea  Israel 
Corporate(1)
 
  (in millions) 
Three Months Ended March 31, 2009                  
Oil and gas operating costs (2)
 $93  $71  $9  $9  $1  $3 
Workover and repair expense  7   6   -   1   -   - 
Lease operating expense  100   77   9   10   1   3 
Production and ad valorem taxes  18   18   -   -   -   - 
Transportation expense  12   10   -   1   -   1 
Total production costs  130   105   9   11   1   4 
Three Months Ended March 31, 2008                        
Oil and gas operating costs (2)
  76   49   9   11   2   5 
Workover and repair expense  6   6   -   -   -   - 
Lease operating expense  82   55   9   11   2   5 
Production and ad valorem taxes  43   33   -   -   -   10 
Transportation expense  13   11   -   2   -   - 
Total production costs $138  $99  $9  $13  $2  $15 
(1)Other international includes Ecuador, China, and Argentina (through February 2008).
(2)Oil and gas operating costs include labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs.
 
Total production costs decreasedfor the second quarter and first quartersix months of 2009 decreased as compared with first quarter 2008 primarily due to a2008. The largest decrease was in production and ad valorem taxes, offset by an increase in oil and gas operating costs. Production and ad valorem taxes in the US decreased primarilywhich declined due to lower commodity prices.  Other Internationalreduced proceeds from production taxes were de minimis for first quarter 2009 dueattributable to lower commodity prices in the US and China and the cessation of production due to the sale of our oil and gas interestsinterest in Argentina. US oil and gas operating costs increased primarily due to an increase in well counts, production volumes andcount, higher salt water disposal costs in the Northern region and were partially offset by a decrease in Internationalhigher insurance expense.  North Sea oil and gas operating costs.costs decreased due to lower sales volumes (timing of liftings).
 


Selected expenses on a per BOE basis were as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
Oil and gas operating costs $5.09  $3.88 
Workover and repair expense  0.41   0.33 
Lease operating expense  5.50   4.21 
Production and ad valorem taxes  1.00   2.23 
Transportation expense  0.63   0.68 
Total production costs (1) (2)
 $7.13  $7.12 
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
Oil and Gas Operating Costs $4.88  $4.23  $4.99  $4.05 
Workover and Repair Expense  0.29   0.42   0.35   0.38 
Lease Operating Expense  5.17   4.65   5.34   4.43 
Production and Ad Valorem Taxes  1.29   2.67   1.14   2.45 
Transportation Expense  0.73   0.81   0.68   0.74 
Total Production Costs (1) (2)
 $7.19  $8.13  $7.16  $7.62 
 
(1)Consolidated unit rates exclude sales volumes and costsexpenses attributable to equity method investees. Sales volumes include natural gas sales to an LNG plant in Equatorial Guinea. The inclusion of these volumes reduced the unit rate by $1.30$1.45 per BOE and $1.32 per BOE for firstsecond quarter 2009 and $1.112008, respectively, and $1.38 per BOE and $1.21 per BOE for the first quarter 2008.six months of 2009 and 2008, respectively.
(2)     Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.





26
(2)Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.
 
Oil and Gas Exploration Expense – OilComponents of oil and gas exploration expense waswere as follows:
 
     United  West  North     Other Int'l/ 
  Total  States  Africa  Sea  Israel  
Corporate (1)
 
  (in millions) 
Three Months Ended March 31, 2009                  
Dry hole expense $2  $(1) $4  $-  $-  $(1)
Seismic  23   23   -   -   -   - 
Staff expense  15   4   3   1   -   7 
Other  2   2   -   -   -   - 
Total exploration expense $42  $28  $7  $1  $-  $6 
Three Months Ended March 31, 2008                        
Dry hole expense $7  $(1) $-  $8  $-  $- 
Seismic  13   13   -   -   -   - 
Staff expense  16   11   -   1   1   3 
Other  4   4   -   -   -   - 
Total exploration expense $40  $27  $-  $9  $1  $3 
  Total  United States  West Africa  North Sea  Eastern Mediter-ranean  
Other Int'l, Corporate (1)
  (in millions) 
Three Months Ended June 30, 2009                  
Dry Hole Expense $7  $7  $-  $-  $-  $- 
Seismic  7   5   -   -   2   - 
Staff Expense  17   3   3   -   -   11 
Other  2   2   -   -   -   - 
Total Exploration Expense  33   17   3   -   2   11 
Three Months Ended June 30, 2008                        
Dry Hole Expense $61  $28  $1  $-  $-  $32 
Seismic  20   16   -   4   -   - 
Staff Expense  16   1   4   3   -   8 
Other  6   6   -   -   -   - 
Total Exploration Expense  103   51   5   7   -   40 
Six Months Ended June 30, 2009                        
Dry Hole Expense $9  $6  $4  $-  $-  $(1)
Seismic  30   28   -   -   2   - 
Staff Expense  32   6   6   1   -   19 
Other  4   4   -   -   -   - 
Total Exploration Expense  75   44   10   1   2   18 
Six Months Ended June 30, 2008                        
Dry Hole Expense $68  $27  $1  $8  $-  $32 
Seismic  33   29   -   4   -   - 
Staff Expense  32   6   4   4   -   18 
Other  10   10   -   -   -   - 
Total Exploration Expense  143   72   5   16   -   50 
(1)Other international includes amounts spent in support of various international new ventures.
 
(1)     Other international includes amounts spent in support of various international new ventures.
Oil and gas exploration expense for the second quarter and first six months of 2009 decreased primarily due to lower dry hole expense.  Dry hole expense for the second quarter of 2009 includesrelated to an increaseunsuccessful exploratory well drilled in the Northern region of our US operations. Dry hole expense for 2008 was due primarily to an exploration well offshore Suriname and in the deepwater Gulf of Mexico which did not encounter hydrocarbons in commercial quantities. US seismic expense for 2009 and 2008 represents seismic expense incurred in support of the annual central Gulf of Mexico lease sale. sales.

Exploration expense also includes stock-based compensation expense of $2 million and $1 million for firstsecond quarter 2009 and less than2008, respectively, and $5 million and $1 million for the first quarter 2008.six months of 2009 and 2008, respectively.
 
Depreciation, Depletion and Amortization – DD&A expense was as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
  (in millions, except unit rate) 
DD&A expense $197  $201 
Accretion of discount on asset retirement obligations  3   2 
Total DD&A expense $200  $203 
Unit rate per BOE (1)
 $11.01  $10.42 
  
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
  (in millions, except unit rate) 
DD&A Expense $192  $194  $389  $395 
Accretion of Discount on Asset Retirement Obligations  4   2   7   4 
Total DD&A Expense $196  $196  $396  $399 
Unit Rate per BOE (1)
 $10.88  $10.30  $10.95  $10.36 
 
(1)Consolidated unit rates exclude sales volumes and costsexpenses attributable to equity method investees. Sales volumes include natural gas sales to an LNG plant in Equatorial Guinea. The inclusion of these volumes reduced the unit rate by $1.67$1.82 per BOE and $1.34 per BOE for firstsecond quarter 2009 and 2008, respectively, and $1.75 and $1.32 per BOE for the first quarter 2008.six months of 2009 and 2008, respectively.
 
Total DD&A expense for the second quarter and first quartersix months of 2009 remainedwas flat as compared with first quarter 2008.  DD&A expense was higher infor the USWattenberg, Rocky Mountain, and Mid-continent areas of our Northern region increased due to an increase in Northern region production (primarily in Piceance and Wattenberg), offset somewhat by decreasedhigher production in the Gulf of Mexico. DD&A expense also included $4 million of abandoned asset expense in first quarter 2009.
ThePiceance basin, higher DD&A unit rate resulted from the change in our mix of production, including lower volumes in Israel,capital spending necessary to complete these projects, and was also impacted by negative reserve revisions  related to lower year-end 2008 commodity pricesprices. These increases were offset by decreases in DD&A expense due to lower sales volumes in the deepwater Gulf of Mexico, North Sea and Israel. See Oil, Gas and NGL Sales. above. DD&A expense included $4 million abandoned asset expense during the first six months of 2009 and higher accretion expense for the second quarter and first six months of 2009.
 

27
The unit rate per BOE increased for both the second quarter and first six months of 2009 as compared with 2008 due to the change in mix of production, including a reduction in Israel sales volumes (which have a lower DD&A rate), and higher capital spending and negative reserve revisions in the Northern region, as described above.
 
General and Administrative Expense – General and administrative expense (G&A) was as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
G&A expense (in millions) $59  $60 
Unit rate per BOE (1)
 $3.23  $3.09 
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
             
G&A Expense (in millions) $60  $61  $119  $121 
Unit Rate per BOE (1)
 $3.35  $3.21  $3.29  $3.15 
 
(1)Consolidated unit rates exclude sales volumes and costsexpenses attributable to equity method investees. Sales volumes include natural gas sales to an LNG plant in Equatorial Guinea. The inclusion of these volumes reduced the unit rate by $0.59$0.68 per BOE and $0.52 per BOE for firstsecond quarter 2009 and $0.482008, respectively and $0.63 per BOE and $0.50 per BOE for the first quarter 2008.six months of 2009 and 2008, respectively.
 
G&A expense during the second quarter and first quartersix months of 2009 remained flat as compared with first quarter 2008. G&A expenseflat. It included stock-based compensation expense of $9 million in eachand $10 million for the second quarter of first quarter 2009 and 2008, respectively, and $17 million and $19 million for the first six months of 2009 and 2008, respectively. The unit rate per BOE for the second quarter and first six months of 2009 increased as compared with 2008 due to lower sales volumes.
 
Asset Impairments – During first quarter 2009 we recorded total pre-tax (non-cash) impairment charges of $437 million on certain US oil and gas properties, primarily due to lower natural gas prices. In determining the fair values of the impaired properties, we applied the principles of fair value definition of SFAS 157. SFAS 157 requiresmeasurements as defined by US GAAP. These principles require that fair values be determined from the perspective of a market participant considering, among other things, appropriate discount rates, multiple valuation techniques, the most advantageous market and assumptions around the highest and best use of the assets.


Due to the absence of comparable market data for the impaired properties, we estimated the fair values using a discounted cash flow method. Estimated future cash flows were based on management’s expectations for the future and included management’s estimates of future oil and gas production, commodity prices based on published commodity futures price strips as of March 31, 2009, operating and development costs, as well as appropriate discount rates. Due to the use of significant unobservable inputs, the fair values of the impaired properties were classified as Level 3 measurements in the fair value hierarchy. A change in any of the assumptions used, such as a significant increase or decreaseddecrease in estimated commodity prices or production, could have had a significant impact on the amount of the impairment loss recognized. There were no asset impairments during second quarter 2009. See Item 1. Financial Statements – Note 5 – Fair Value Measurements.
 
Other Operating Expense, Net – Other operating expense, net includes electricity generation expense and GMP expense. See Item 1. Financial Statements – Note 2 – Basis of Presentation.
 
(Gain) Loss on Commodity Derivative Instruments – See Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities and Note 5 – Fair Value Measurements.
 
Interest Expense and Capitalized Interest – Interest expense and capitalized interest were as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
  (in millions) 
Interest expense $24  $27 
Capitalized interest  (6)  (10)
Interest expense, net $18  $17 
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
  (in millions) 
Interest Expense $35  $23  $59  $49 
Capitalized Interest  (12)  (6)  (18)  (15)
Interest Expense, net $23  $17  $41  $34 
 
Interest expense decreased duringincreased $12 million for second quarter 2009 and $10 million for the first quartersix months of 2009, as compared with first quarter 2008 due to a declining rate of2008. The increase in interest applicableexpense primarily relates to our credit facility from 2.99% at March 31, 2008 to 0.81% at March 31, 2009, offset by a higher rate of interest related to the issuance of $1 billion 10-year8¼% senior unsecured notes due March 1, 2019, which we issued on February 27, 2009. This increase was partially offset by a significant decrease in credit facility interest expense due to a decline in both the average outstanding balance and the average interest rate. See also Liquidity and Capital Resources – Financing Activities below.
The increases in the amount of interest capitalized decreased primarilyare due to a lower average interest rate applicablehigher development work in progress related to our long-term debt.extended projects in West Africa and the Gulf of Mexico.
 
Other (Income) Expense, Net – See Item 1. Financial Statements – Note 2 – Basis of Presentation.
 
Income Tax Provision (Benefit) – The income tax provision (benefit) was as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
Income tax provision (benefit) (in millions) $(186) $101 
Effective rate  50%  32%
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2009  2008  2009  2008 
Income Tax Provision (Benefit) (in millions) $(33) $(54) $(218) $48 
Effective Rate  37%  27%  47%  40%
 
OurSee Item 1. Financial Statements – Note 11 – Income Taxes for a discussion of the change in our effective tax rate increased during the first quartersix months of 2009 as compared with first quarter 2008 due primarily to the fact that the 2009 rate represents a tax benefit divided by a pre-tax loss.  In that case, our favorable permanent differences, such as income from equity method investees, have the effect of increasing the tax benefit which, in turn, increases the effective rate.
2008.
 


LIQUIDITY AND CAPITAL RESOURCES
 
Overview
Our primary cash needs are to fund operating expenses and capital expenditures related to the acquisition, exploration and development of crude oil and natural gas properties, to repay outstanding borrowings and associated interest payments and other contractual commitments and to pay dividends. Traditional sources of our liquidity are cash on hand, cash flows from operations and available borrowing capacity under credit facilities. Occasional sales of non-strategic crude oil and natural gas properties as well as our periodic access to capital markets may also generate cash.
 
The ongoing disruption in the credit markets has had a significant adverse impact on a number of financial institutions. We have reviewed the creditworthiness of the banks and financial institutions with which we maintain our investments as well as the securities underlying our investments. Thus far, our liquidity and financial position have not been materially impacted. However, further deterioration in the credit markets could adversely affect our results of operations and cash flows. See Executive Overview – Impact of Recession and Current Credit and Commodity Markets.
 
Cash and Cash Equivalents – We had $1.0 billion$956 million in cash and cash equivalents at March 31,June 30, 2009. Our cash is denominated in US dollars and is invested in US Treasury securities and short-term deposits with major financial institutions. In response to the credit market crisis, we shortened the duration of our investment maturities and increased our investments in US Treasury securities.
 
A majority of this cash is attributable to our foreign subsidiaries and most would be subject to US income taxes if repatriated. We currently intend to use a majority of our international cash to fund international projects, including the development of West Africa and Israel.
 
During fourth quarter 2008, we performed an analysis of projected short-term working capital needs as well as long-term capital requirements for our US and foreign operations. As a result, we repatriated $180 million of the accumulated earnings of foreign subsidiaries during first quarter 2009. We used the proceeds for debt repayment and general corporate purposes. See Item 1. Financial Statements – Note 411 – Income Taxes for a discussion of the related income tax effects.
 
Commodity Derivative Instruments – We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such instruments include variable to fixed commodity price swaps, collars and basis swaps. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments. Except for certain minor derivative contracts that are entered into from time to time by our marketing subsidiary, none of our counterparty agreements contain margin requirements.
 
Commodity derivative instruments are recorded at fair value in our consolidated balance sheets, and changes in fair value are recorded in earnings in the period in which the change occurs. As of March 31,June 30, 2009, the fair value of our commodity derivative assets was $427$210 million and the fair value of our commodity derivative liabilities was $46$92 million (after consideration of netting agreements). See Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities for a discussion of counterparty credit risk and Note 5 – Fair Value Measurements for a description of the methods we use to estimate the fair values of commodity derivative instruments.
 
Contractual Obligations
In February 2009, we completed an underwritten public offering of $1 billion of 8¼% senior unsecured notes due March 1, 2019. See Financing Activities below. As a result, our future debt principal payments as of March 31,June 30, 2009 consist of the following: $25 million for the remainder of 2009; $726$785 million for 2012; and $1.6 billion for 2014 and beyond for a total of $2.4 billion. Based on the total debt balance, scheduled maturities and interest rates in effect at March 31,June 30, 2009, our cash payments for interest would be $88$66 million for the remainder of 2009; $133$132 million in 2010; $133$132 million in 2011; $132 million in 2012; $127 million in 2013; and $1.3 billion for the remaining years for a total of $2.0$1.9 billion. See Item 1. Financial Statements – Note 3 – Debt Issuance.Debt.
 


Cash Flows
Cash flow information is as follows:
 
  Three Months Ended 
  March 31, 
  2009  2008 
  (in millions) 
Total cash provided by (used in):      
Operating activities $185  $506 
Investing activities  (399)  (355)
Financing activities  91   (4)
Increase (decrease) in cash and cash equivalents $(123) $147 
  
Six Months Ended
June 30,
 
  2009  2008 
  (in millions) 
Total Cash Provided By (Used in):      
Operating Activities $498  $1,154 
Investing Activities  (777)  (823)
Financing Activities  95   (8)
Increase (Decrease) in Cash and Cash Equivalents $(184) $323 
 
Operating Activities – Net cash provided by operating activities for the first quartersix months of 2009 decreased as compared with the first quartersix months of 2008 due primarily to decreases in commodity prices.
 
Investing Activities – Our investing activities include capital spending on a cash basis for oil and gas properties, which may be offset by proceeds from property sales. Net cash used in investing activities increaseddecreased by $46 million during the first quartersix months of 2009 as compared with the first quartersix months of 2008. Activity for the first six months of 2008 and consisted only of capital spending. First quarter 2008 activity included capital spending of $464$932 million, which was partially offset by net proceeds of $109 million from asset sales. See Investing Activities – Acquisition, Capital and Exploration Expenditures below.
 
Financing Activities – Our financing activities include the issuance or repurchase of our common stock, payment of cash dividends on our common stock, the borrowing of cash and the repayment of borrowings. During the first quartersix months of 2009, we received $989 million net proceeds from the issuance of our 8¼% senior notes. Fundsnotes, and $16 million of funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($14 million).options. We used $821 million cash for net repayments of amounts outstanding under our revolving credit facility ($880 million), to payand repaid $25 million of an installment note. We also paid $63 million in cash dividends on our common stock ($31 million), and used $1 million to repurchase shares of our common stock ($1 million).stock.
 
In comparison, during the first quartersix months of 2008, $47 million of funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options, ($19 million) and we usedpaid $53 million in cash to pay dividends on our common stock ($21 million) and used $2 million to repurchase shares of our common stock ($2 million).stock. There were no net changes in outstanding debt.
 
Investing Activities
Acquisition, Capital and Exploration Expenditures – Information for investing activities, (onwhich consist of capital spending (including seismic expense) on an accrual basis)basis, is as follows:
 
 Three Months Ended 
 March 31,  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
 2009  2008  2009  2008  2009  2008 
 (in millions)  (in millions) 
Acquisition, Capital and Exploration Expenditures                  
Unproved property acquisition $16  $176 
Unproved Property Acquisition $46  $87  $62  $263 
Exploration  95   45   50   198   145   243 
Development  231   246   198   261   429   506 
Corporate and other  44   19 
Corporate and Other  29   15   73   34 
Total $386  $486  $323  $561  $709  $1,046 
 
Unproved property acquisition costs for the first quartersix months of 2009 and 2008 include primarily lease bonuses on deepwater lease blocks acquired in central Gulf of Mexico lease sales.
 
Property Sales – In February 2008, effective July 1, 2007, we sold our interest in Argentina for a sales price of $117.5 million. The gain on sale was deferred until second quarter 2009 when the Argentine government approved the sale.
 

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Financing Activities
Long-Term Debt – Our principal source of liquidity is an unsecured revolving credit facility that matures December 9, 2012. The commitment is $2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8 billion. The credit facility (i) provides for credit facility fee rates that range from 5 basis points to 15 basis points per year depending upon our credit rating, (ii) makes available short-term loans up to an aggregateaggregate amount of $300 million and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the credit facility. The credit facility is with certain commercial lending institutions and is available for general corporate purposes.
 

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In order to provide increased liquidity and lengthen ourour weighted averageaverage debt maturity, on February 27, 2009 we completed an underwritten public offering of $1 billion of 8¼% senior unsecured notes due March 1, 2019, receiving net proceeds of $989 million.  We used substantially all of the net proceeds from the offering to repay outstanding indebtedness under the revolving credit facility.
 
As a result, at March 31,June 30, 2009, borrowings outstanding under the credit facility totaled $726$785 million, leaving almost $1.4in excess of $1.3 billion available for use. The weighted average interest rate applicable to borrowings under the credit facility at March 31,June 30, 2009 was 0.81%0.62%.
 
Our outstanding fixed-rate debt, including the new 8¼% senior unsecured notes discussed above, totaled $1.6 billion at March 31,June 30, 2009. The weighted average interest rate on fixed-rate debt was 7.73%, with maturities ranging from 2014 to 2097.
 
Our ratio of debt-to-book capital was 28%29% at March 31,June 30, 2009 as compared with 26% at December 31, 2008. We define our ratio of debt-to-book capital as total debt (which includes both long-term debt, excluding unamortized discount, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.
 
Short-Term Borrowings – We oweIn May 2009, we made the final $25 million in the form of an installment payment to the seller of properties we purchased in 2007. The amount is due May 11, 2009 and is included in short-term borrowings in the consolidated balance sheets. Interest on the unpaid amount iswas due quarterly and accruesaccrued at a LIBOR rate plus .30%. The interest rate was 1.76%1.51% at March 31, 2009.the date of payment.
 
Our committed credit facility has been supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing. There were no amounts outstanding under uncommitted credit lines at March 31,June 30, 2009 or December 31, 2008. Depending upon future credit market conditions, these sources may or may not be available. However, we are not dependent on them to fund our day-to-day operations.
 
Dividends – We paid a quarterlytotal cash dividenddividends of 18.036.0 cents per share of common stock during the first quartersix months of 2009 and 12.030.0 cents per share of common stock during the first quartersix months of 2008. On April 27,July 28, 2009, our Board of Directors declared a quarterly cash dividend of 18.0 cents per common share, payable May 26,August 24, 2009 to shareholders of record on May 11,August 10, 2009. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.
 
Exercise of Stock Options – We received cash proceeds of $11$13 million from the exercise of stock options during the first quartersix months of 2009 as compared with $10$24 million during the first quartersix months of 2008.
 
Common Stock Repurchases – We receive shares of common stock from employees for the payment of withholding taxes due on the vesting of restricted shares issued under stock-based compensation plans. We received 17,510 shares with a value of $1 million during the first quartersix months of 2009 and 24,38032,518 shares with a value of $2 million during the first quartersix months of 2008. 
 

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
 
Commodity Price Risk
Derivative Instruments Held for Non-Trading Purposes – We are exposed to market risk in the normal course of business operations, and the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.
 
At March 31,June 30, 2009, we had entered into variable to fixed price commodity swaps, collars and basis swaps related to crude oil and natural gas sales. Our open commodity derivative instruments were in a net receivable position with a fair value of $381$118 million. Based on the March 31,June 30, 2009 published forward commodity futures price curvesstrips for the underlying commodities, a price increase of $1.00 per Bbl for crude oil would decrease the fair value of our net commodity derivative receivable by approximately $9$10 million. A price increase of $0.10 per MMBtu for natural gas would decrease the fair value of our net commodity derivative receivable by approximately $8$11 million.  Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities.
 
Interest Rate Risk
Changes in interest rates affect the amount of interest we pay on borrowings under our revolving credit facility and other variable-rate debt and the amount of interest we earn on our short-term investments.
 
At March 31,June 30, 2009, we had $2.4 billion (excluding unamortized discount) of long-term debt outstanding. Of this amount, $1.6 billion was fixed-rate debt with a weighted average interest rate of 7.73%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss. 
 
The remainder of our long-term debt, $726$785 million at March 31,June 30, 2009, was variable-rate debt drawn under our credit facility. We also had $25 million of short-term variable-rate debt at March 31, 2009.  Variable-rate debt exposes us to the risk of earnings or cash flow loss due to increases in market interest rates. We estimate that a hypothetical 25 basis point change in the floating interest rates applicable to the March 31,June 30, 2009 balance of our variable-rate debt would result in a change in annual interest expense of approximately $2 million.
 
We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. At March 31,June 30, 2009, AOCL included $2 million, net of tax, related to interest rate locks. This amount is currently being reclassified into earnings as adjustments to interest expense over the term of our 5¼% Senior Notes due April 2014. We currently have no treasury locks outstanding.
 
We are also exposed to interest rate risk related to our short-term investments. As of March 31,June 30, 2009, approximately 46%50% of our cash was invested in US Treasury securities. A hypothetical 25 basis point change in the floating interest rates applicable to the March 31,June 30, 2009 short-term investment balance would result in a change in annual interest income of approximately $1 million.
 
Foreign Currency Risk
We have not entered into foreign currency derivative instruments. The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are completedpaid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. We do not have any significantCertain monetary assets orand liabilities, denominated in a foreign currency other than oursuch as foreign deferred tax liabilities in certain foreign tax jurisdictions.jurisdictions, are denominated in a foreign currency. An increase in exchange rates between the US dollar and the currency of the foreign tax jurisdiction in which these liabilities are located could result in the use of additional cash to settle these liabilities. However, transactionTransaction gains or losses were not material in any of the periods presented and we do not believe we are currently exposed to any material risk of loss on this basis. Such gains or losses are included in other (income) expense, net in the consolidated statements of operations.
 
In the UK sector of our North Sea operations, significant future capital commitments and certain operating expenses are expected to be denominated in British pounds. Therefore, our cash flows could be impacted by future changes in the exchange rate between the US dollar and the British pound. We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency derivative instruments (such as forward contracts, costless collars or swap agreements) in the future if we determined that it is necessary to invest in such instruments in order to mitigate our foreign currency exchange risk.


DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This quarterly report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:
 
·the extent and effect of any hedging activities engaged in by us;
 ·our growth strategies;
 ·our ability to successfully and economically explore for and develop crude oil and natural gas resources;
 ·anticipated trends in our business;
 ·our future results of operations;
 ·effect of current volatility in the credit markets;
 ·our liquidity and ability to finance our exploration and development activities;
 ·market conditions in the oil and gas industry;
 ·our ability to make and integrate acquisitions; and
 ·the impact of governmental regulation.

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included herein, if any, and included in our 2008 annual reportQuarterly Report on Form 10-Q for the quarter ended March 31, 2009, and our Annual Report on Form 10-K for the year ended December 31, 2008, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.  Our 2008 annual reportQuarterly Report on Form 10-Q for the quarter ended March 31, 2009, and our Annual Report on Form 10-K isfor the year ended December 31, 2008 are available on our website at www.nobleenergyinc.com.

ITEM 4.  CONTROLS AND PROCEDURES
 
Based on the evaluation of our disclosure controls and procedures by Charles D. Davidson, our principal executive officer and Chris Tong, our acting principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, are effective. There were no changes in internal control over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 

 

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PART II. OTHER INFORMATION
 
ITEM 1.  LEGAL PROCEEDINGS
 
See Item I. Financial Statements – Note 14 – Commitments and Contingencies.

ITEM 1A.  RISK FACTORS
 
There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our annual reportQuarterly Report on Form 10-Q for the quarter ended March 31, 2009 or our Annual Report on Form 10-K for the year ended December 31, 2008, other than the following:
 
Federal climate change regulation could increase our operating and capital costs.
The proposed United States federal budget for fiscal year 2010 includes certain provisions that,American Clean Energy and Security Act of 2009 (ACES), also known as the Waxman-Markey Bill, was approved by the House of Representatives on June 26, 2009. The ACES, if passed by the Senate, would establish a variant of a “cap-and-trade” plan for greenhouse gases (GHG) in order to address climate change. A “cap-and-trade” plan would require businesses that emit more greenhouse gases than permitted to acquire emission allowances from other businesses that emit greenhouse gases at levels lower than the limits specified and then surrender these allowances as originally submitted, willa credit against such emissions. As a result of such a plan, we could be required to purchase and surrender emission allowances for GHG emissions resulting from our operations.
Although it is not possible at this time to predict the final outcome of the ACES, any new federal restrictions on GHG emissions, including a cap-and-trade-plan, that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on our financial position, results of operations, and cash flows.
On February 26, 2009,business or demand for the Office of Management and Budget released a summary of the President’s proposed federal budget for fiscal year 2010.  The proposed budget repeals many tax incentives and deductions that are currently used by UScrude oil and natural gas companies and imposes new taxes. The provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; increases in the taxation of foreign source income; levy of an excise tax on Gulf of Mexico oil and gas production; repeal of the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands.we produce.

Should some or all of these provisions become law our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities. Since none of these proposals have yet to be voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
 
None.
Period 
Total Number
of Shares
Purchased (1)
  
Average Price
Paid
Per Share
  
Total Number of
Shares Purchased
as Part of Publicly Announced Plans
or Programs
  
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs
 
           (in thousands) 
01/01/09 - 01/31/09  786  $51.02   -   - 
02/01/09 - 02/28/09  16,724   50.21   -   - 
03/01/09 - 03/31/09  -   -   -   - 
     Total  17,510  $50.24   -   - 

 
(1)Stock repurchases during the period related to stock received by us from employees for the payment of withholding taxes due on shares issued under stock-based compensation plans.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
 
None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a)Our annual stockholders meeting was held at 9:30 a.m., Central Time, on Tuesday, April 28, 2009 in The Woodlands, Texas.

(b)Proxies were solicited by our Board of Directors pursuant to Regulation 14A under the Securities Exchange Act of 1934. There was no solicitation in opposition to the Board of Directors’ nominees as listed in the proxy statement and all such nominees were duly elected.

(c)Out of a total of 173,328,806 shares of our common stock outstanding and entitled to vote, 158,577,955 shares were present in person or by proxy, representing 91.49% of the outstanding shares of common stock.



None.The stockholder voting results are as follows:

Proposal I.  Election of our Board of Directors to serve until the next annual stockholders meeting.
 
Number of
Shares Voting
For Election As
Director
Number of
Shares Withholding
Authority To Vote
for Election As
Director
Jeffrey L. Berenson155,834,018 2,743,937 
Michael A. Cawley152,273,049 6,304,906 
Edward F. Cox155,358,078 3,219,877 
Charles D. Davidson155,278,394 3,299,561 
Thomas J. Edelman157,425,631 1,152,324 
Eric P. Grubman157,954,331 623,624 
Kirby L. Hedrick155,909,611 2,668,344 
Scott D. Urban157,595,343 982,612 
William T. Van Kleef157,671,218 906,737 

Proposal II.  Ratification of appointment of KPMG LLP as our independent auditors.
(For 157,421,503; Against 1,082,482; Abstaining 73,970)

Proposal III.  Ratification of amendment of 1992 Stock Option and Restricted Stock Plan to increase the number of shares of common stock authorized for issuance under the plan from 22,000,000 to 24,000,000.
(For 93,068,057; Against 54,295,631; Abstaining 97,536; Broker Non-Vote 11,116,731)
 

ITEM 5.  OTHER INFORMATION
 
None.

ITEM 6.  EXHIBITS
 
The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q.
 



SIGNATURES

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


 NOBLE ENERGY, INC.
          (Registrant)




DateAprilJuly 30, 2009 /s/ CHRIS TONGFrederick B. Bruning
   
CHRIS TONGFrederick B. Bruning
Senior Vice President and Chief FinancialAccounting Officer
    
    
    







INDEX TO EXHIBITS

Exhibit
NumberExhibit


Exhibit
Number 
Exhibit
10.1Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (as amended through April 28, 2009) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed April 29, 2009).

31.1Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

31.2Certification of the Company’s ChiefActing Principal Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

32.1Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

32.2Certification of the Company’s ChiefActing Principal Financial Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).


101The following materials from the Noble Energy, Inc. Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Operations, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Statements of Shareholders’ Equity, and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text.




 
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