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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2007
or
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No. 001-32318
Devon Energy Corporation
(Exact Name of Registrant as Specified in its Charter)
     
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  73-1567067
(I.R.S. Employer
Identification Number)
     
20 North Broadway
Oklahoma City, Oklahoma

(Address of Principal Executive Offices)
  73102-8260
(Zip Code)
Registrant’s telephone number, including area code:
(405) 235-3611
Former name, former address and former fiscal year, if changed from last report.
Not applicable
     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 þ No o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ      Accelerated filer o      Non-accelerated filer o
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
     The number of shares outstanding of Registrant’s common stock, par value $0.10, as of October 31, 2007, was 444,960,000.
 
 

 


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DEVON ENERGY CORPORATION
INDEX TO FORM 10-Q QUARTERLY REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION
         
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    5  
 
       
    6  
 
       
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    28  
    41  
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    44  
 
       
    44  
 
       
    45  
 
       
 First Amendment to Amended and Restated Credit Agreement
 Second Amendment to Amended and Restated Credit Agreement
 Certification of J. Larry Nichols Pursuant to Section 302
 Certification of Danny J. Heatly Pursuant to Section 302
 Certification of J. Larry Nichols Pursuant to Section 906
 Certification of Danny J. Heatly Pursuant to Section 906

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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
     This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information which was used to prepare the December 31, 2006 reserve reports and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or the negatives or variations of such terms or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:
    energy markets;
 
    production levels, including our Canadian production subject to government royalties which fluctuate with prices and our International production governed by payout agreements which affect reported production;
 
    reserve levels;
 
    competitive conditions;
 
    technology;
 
    the availability of capital resources;
 
    capital expenditure and other contractual obligations;
 
    the supply and demand for oil, natural gas, NGLs and other energy products or services;
 
    the price of oil, natural gas, NGLs and other energy products or services;
 
    currency exchange rates;
 
    the weather;
 
    inflation;
 
    the availability of goods and services;
 
    drilling risks;
 
    future processing volumes and pipeline throughput;
 
    general economic conditions, either internationally or nationally or in the jurisdictions in which we or our subsidiaries conduct business;
 
    legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;
 
    terrorism;
 
    occurrence of property acquisitions or divestitures or the timing of such planned transactions;
 
    the securities or capital markets; and
 
    other factors disclosed in Devon’s 2006 Annual Report on Form 10-K under “Item 2. Properties — Proved Reserves and Estimated Future Net Revenue,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk”.
     All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

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DEFINITIONS
AS USED IN THIS DOCUMENT:
     “Bbl” or “Bbls” means barrel or barrels.
     “Bcf” means billion cubic feet.
     “Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
     “MMBbls” means million barrels.
     “MMBoe” means million Boe.
     “Mcf” means thousand cubic feet.
     “NGL” or “NGLs” means natural gas liquids.
     “Oil” includes crude oil and condensate.
     “SEC” means United States Securities and Exchange Commission.
     “Domestic” means the properties of Devon in the onshore continental United States and the offshore Gulf of Mexico.
     “United States Onshore” means the properties of Devon in the continental United States.
     “United States Offshore” means the properties of Devon in the Gulf of Mexico.
     “Canada” means the division of Devon encompassing oil and gas properties located in Canada.
     “International” means the division of Devon encompassing oil and gas properties that lie outside the United States and Canada.

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PART I. Financial Information
Item 1. Consolidated Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
                 
    September 30,     December 31,  
    2007     2006  
    (Unaudited)          
    (In millions, except share data)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 1,392       692  
Short-term investments, at fair value
    341       574  
Accounts receivable
    1,435       1,324  
Current assets held for sale
    176       232  
Other current assets
    340       390  
 
           
Total current assets
    3,684       3,212  
 
           
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($3,371 and $3,293 excluded from amortization in 2007 and 2006, respectively)
    46,546       39,585  
Less accumulated depreciation, depletion and amortization
    19,561       16,429  
 
           
 
    26,985       23,156  
Investment in Chevron Corporation common stock, at fair value
    1,327       1,043  
Goodwill
    6,150       5,706  
Assets held for sale
    1,707       1,619  
Other assets
    418       327  
 
           
Total assets
  $ 40,271       35,063  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
 
               
Current liabilities:
               
Accounts payable – trade
  $ 1,268       1,154  
Revenues and royalties due to others
    529       522  
Income taxes payable
    187       82  
Short-term debt
    2,076       2,205  
Accrued interest payable
    191       114  
Current liabilities associated with assets held for sale
    190       173  
Accrued expenses and other current liabilities
    325       395  
 
           
Total current liabilities
    4,766       4,645  
 
           
Debentures exchangeable into shares of Chevron Corporation common stock
    638       727  
Other long-term debt
    5,235       4,841  
Financial instruments, at fair value
    495       302  
Asset retirement obligation, at fair value
    1,246       804  
Liabilities associated with assets held for sale
    445       429  
Other liabilities
    622       583  
Deferred income taxes
    5,992       5,290  
Stockholders’ equity:
               
Preferred stock of $1.00 par value. Authorized 4,500,000 shares; issued 1,500,000 ($150 million aggregate liquidation value)
    1       1  
Common stock of $0.10 par value. Authorized 800,000,000 shares; issued 444,699,000 in 2007 and 444,040,000 in 2006
    45       44  
Additional paid-in capital
    6,883       6,840  
Retained earnings
    11,564       9,114  
Accumulated other comprehensive income
    2,339       1,444  
Treasury stock, at cost: 11,000 shares in 2006
          (1 )
 
           
Total stockholders’ equity
    20,832       17,442  
 
           
Commitments and contingencies (Note 6)
               
Total liabilities and stockholders’ equity
  $ 40,271       35,063  
 
           
See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
    (Unaudited)  
    (In millions, except per share amounts)  
Revenues:
                               
Oil sales
  $ 905       696       2,461       1,806  
Gas sales
    1,182       1,186       3,788       3,709  
NGL sales
    242       204       643       573  
Marketing and midstream revenues
    434       413       1,273       1,261  
 
                       
Total revenues
    2,763       2,499       8,165       7,349  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    457       363       1,326       1,036  
Production taxes
    85       92       255       261  
Marketing and midstream operating costs and expenses
    301       301       912       924  
Depreciation, depletion and amortization of oil and gas properties
    705       547       1,937       1,480  
Depreciation and amortization of non-oil and gas properties
    51       43       146       127  
Accretion of asset retirement obligation
    19       12       55       35  
General and administrative expenses
    126       104       358       284  
Interest expense
    108       112       325       315  
Change in fair value of financial instruments
    (22 )     22       (31 )     81  
Reduction of carrying value of oil and gas properties
          20             36  
Other income, net
    (28 )     (28 )     (71 )     (86 )
 
                       
Total expenses and other income, net
    1,802       1,588       5,212       4,493  
Earnings from continuing operations before income tax expense
    961       911       2,953       2,856  
Income tax expense:
                               
Current
    96       147       459       471  
Deferred
    221       111       452       253  
 
                       
Total income tax expense
    317       258       911       724  
 
                       
Earnings from continuing operations
    644       653       2,042       2,132  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
    177       112       442       337  
Income tax expense
    86       60       194       205  
 
                       
Earnings from discontinued operations
    91       52       248       132  
 
                       
Net earnings
    735       705       2,290       2,264  
Preferred stock dividends
    2       2       7       7  
 
                       
Net earnings applicable to common stockholders
  $ 733       703       2,283       2,257  
 
                       
 
                               
Basic net earnings per share:
                               
Earnings from continuing operations
  $ 1.45       1.47       4.57       4.81  
Earnings from discontinued operations
    0.20       0.12       0.56       0.30  
 
                       
Net earnings
  $ 1.65       1.59       5.13       5.11  
 
                       
 
                               
Diluted net earnings per share:
                               
Earnings from continuing operations
  $ 1.43       1.45       4.52       4.76  
Earnings from discontinued operations
    0.20       0.12       0.55       0.29  
 
                       
Net earnings
  $ 1.63       1.57       5.07       5.05  
 
                       
 
                               
Weighted average common shares outstanding:
                               
Basic
    445       441       445       441  
 
                       
Diluted
    450       447       450       447  
 
                       
See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
    (Unaudited)  
    (In millions)  
Net earnings
  $ 735       705       2,290       2,264  
Foreign currency translation:
                               
Change in cumulative translation adjustment
    579       (1 )     1,311       303  
Income taxes
    (33 )           (74 )     7  
 
                       
Total
    546       (1 )     1,237       310  
 
                       
Derivative financial instruments – reclassification adjustment for realized gains included in net earnings
                (1 )     (1 )
 
                       
Pension and postretirement benefit plans:
                               
Recognition of net actuarial loss in net earnings
    4             12        
Income taxes
    (2 )           (5 )      
 
                       
Total
    2             7        
 
                       
Investment in Chevron Corporation common stock (Note 1):
                               
Unrealized holding gain
          39             114  
Income taxes
          (14 )           (41 )
 
                       
Total
          25             73  
 
                       
Other comprehensive income, net of tax
    548       24       1,243       382  
 
                       
Comprehensive income
  $ 1,283       729       3,533       2,646  
 
                       
See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
                                                                 
                                            Accumulated                
                            Additional             Other             Total  
    Preferred     Common Stock     Paid-In     Retained     Comprehensive     Treasury     Stockholders’  
    Stock     Shares     Amount     Capital     Earnings     Income     Stock     Equity  
    (Unaudited)  
    (In millions)  
Nine Months Ended September 30, 2007
                                                               
Balance as of December 31, 2006
  $ 1       444     $ 44       6,840       9,114       1,444       (1 )     17,442  
Adoption of FASB Statement No. 159 (Note 1)
                            364       (364 )            
Adoption of FASB Interpretation No. 48 (Note 1)
                            (10 )                 (10 )
Adoption of FASB Statement No. 158 (Note 4)
                            (1 )     16             15  
Net earnings
                            2,290                   2,290  
Other comprehensive income
                                  1,243             1,243  
Stock option exercises
          3       1       70                         71  
Common stock repurchased
          (2 )                             (138 )     (138 )
Common stock retired
                      (139 )                 139        
Common stock dividends
                            (186 )                 (186 )
Preferred stock dividends
                            (7 )                 (7 )
Share-based compensation
                      92                         92  
Excess tax benefits on share-based compensation
                      20                         20  
 
                                               
Balance as of September 30, 2007
  $ 1       445     $ 45       6,883       11,564       2,339             20,832  
 
                                               
 
                                                               
Nine Months Ended September 30, 2006
                                                               
Balance as of December 31, 2005
  $ 1       443     $ 44       6,928       6,477       1,414       (2 )     14,862  
Net earnings
                            2,264                   2,264  
Other comprehensive income
                                  382             382  
Stock option exercises
          2             53                         53  
Restricted stock grants, net of cancellations
          1             (3 )                 (2 )     (5 )
Common stock repurchased
          (4 )                             (253 )     (253 )
Common stock retired
                      (256 )                 256        
Common stock dividends
                            (148 )                 (148 )
Preferred stock dividends
                            (7 )                 (7 )
Share-based compensation
                      55                         55  
Excess tax benefits on share-based compensation
                      14                         14  
 
                                               
Balance as of September 30, 2006
  $ 1       442     $ 44       6,791       8,586       1,796       (1 )     17,217  
 
                                               
See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
                 
    Nine Months Ended  
    September 30,  
    2007     2006  
    (Unaudited)  
    (In Millions)  
Cash flows from operating activities:
               
Net earnings
  $ 2,290       2,264  
Earnings from discontinued operations, net of tax
    (248 )     (132 )
Adjustments to reconcile earnings from continuing operations to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    2,083       1,607  
Deferred income tax expense
    452       253  
Net gain on sales of non-oil and gas property and equipment
    (1 )     (5 )
Reduction of carrying value of oil and gas properties
          36  
Other noncash charges
    125       163  
Changes in assets and liabilities:
               
(Increase) decrease in:
               
Accounts receivable
    (12 )     206  
Other current assets
    (65 )     (45 )
Long-term other assets
    (53 )     (37 )
Increase (decrease) in:
               
Accounts payable
    111       (59 )
Income taxes payable
    139       (34 )
Other current liabilities
    (78 )     197  
Long-term other liabilities
    (4 )     (1 )
 
           
Cash provided by operating activities – continuing operations
    4,739       4,413  
Cash provided by operating activities – discontinued operations
    370       469  
 
           
Net cash provided by operating activities
    5,109       4,882  
 
           
 
               
Cash flows from investing activities:
               
Proceeds from sales of property and equipment
    39       36  
Capital expenditures, including acquisitions of businesses
    (4,477 )     (5,959 )
Purchases of short-term investments
    (659 )     (1,868 )
Sales of short-term investments
    892       2,424  
 
           
Cash used in investing activities – continuing operations
    (4,205 )     (5,367 )
Cash used in investing activities – discontinued operations
    (153 )     (187 )
 
           
Net cash used in investing activities
    (4,358 )     (5,554 )
 
           
 
               
Cash flows from financing activities:
               
Net senior credit facility borrowings, net of issuance costs
    400        
Net commercial paper (repayments) borrowings, net of issuance costs
    (129 )     1,439  
Principal payments on debt, including current maturities
    (166 )     (860 )
Proceeds from exercise of stock options
    71       53  
Repurchases of common stock
    (133 )     (253 )
Excess tax benefits related to share-based compensation
    20       14  
Dividends paid on common stock
    (186 )     (148 )
Dividends paid on preferred stock
    (7 )     (7 )
 
           
Net cash (used in) provided by financing activities
    (130 )     238  
 
           
Effect of exchange rate changes on cash
    44       24  
 
           
Net increase (decrease) in cash and cash equivalents
    665       (410 )
Cash and cash equivalents at beginning of period (including cash related to assets held for sale)
    756       1,606  
 
           
Cash and cash equivalents at end of period (including cash related to assets held for sale)
  $ 1,421       1,196  
 
           
 
               
Supplementary cash flow data:
               
Interest paid (net of capitalized interest)
  $ 226       349  
Income taxes paid
  $ 293       581  
See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Summary of Significant Accounting Policies
     The accompanying consolidated financial statements and notes thereto of Devon Energy Corporation (“Devon”) have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission. Accordingly, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in Devon’s 2006 Annual Report on Form 10-K.
     In the opinion of Devon’s management, all adjustments (all of which are normal and recurring) that have been made are necessary to fairly state the consolidated financial position of Devon and its subsidiaries as of September 30, 2007, and the results of their operations and their cash flows for the three-month and nine-month periods ended September 30, 2007 and 2006.
Net Earnings Per Common Share
     The following table reconciles earnings from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings per share for the three-month and nine-month periods ended September 30, 2007 and 2006.
                         
    Net              
    Earnings     Weighted        
    Applicable to     Average     Net  
    Common     Common Shares     Earnings  
    Stockholders     Outstanding     per Share  
    (In millions, except per share amounts)  
Three Months Ended September 30, 2007:
                       
Earnings from continuing operations
  $ 644                  
Less preferred stock dividends
    (2 )                
 
                     
Basic earnings per share
    642       445     $ 1.45  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          5          
 
                   
Diluted earnings per share
  $ 642       450     $ 1.43  
 
                 
 
                       
Three Months Ended September 30, 2006:
                       
Earnings from continuing operations
  $ 653                  
Less preferred stock dividends
    (2 )                
 
                     
Basic earnings per share
    651       441     $ 1.47  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          6          
 
                   
Diluted earnings per share
  $ 651       447     $ 1.45  
 
                 
 
                       
Nine Months Ended September 30, 2007:
                       
Earnings from continuing operations
  $ 2,042                  
Less preferred stock dividends
    (7 )                
 
                     
Basic earnings per share
    2,035       445     $ 4.57  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          5          
 
                   
Diluted earnings per share
  $ 2,035       450     $ 4.52  
 
                 
 
                       
Nine Months Ended September 30, 2006:
                       
Earnings from continuing operations
  $ 2,132                  
Less preferred stock dividends
    (7 )                
 
                     
Basic earnings per share
    2,125       441     $ 4.81  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          6          
 
                   
Diluted earnings per share
  $ 2,125       447     $ 4.76  
 
                 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
     Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculations because the options are antidilutive. During the three-month and nine-month periods ended September 30, 2007, 2.1 million and 4.0 million shares were excluded from the diluted earnings per share calculations, respectively. During both the three-month and nine-month periods ended September 30, 2006, 2.6 million shares were excluded from the diluted earnings per share calculations.
Short-term Investments and Other Marketable Securities – Change in Accounting Principle
     Devon owns approximately 14.2 million shares of Chevron Corporation (“Chevron”) common stock. The majority of these shares are held in connection with debt owed by Devon that contains an exchange option. This exchange option allows the debt holders, prior to the debt’s maturity, to exchange the debt for the shares of Chevron common stock owned by Devon.
     The shares of Chevron common stock and the exchange option embedded in the debt have always been recorded on Devon’s balance sheet at fair value. However, pursuant to accounting rules prior to January 1, 2007, only the change in fair value of the embedded option has historically been included in Devon’s results of operations. Conversely, the change in fair value of the Chevron common stock has not been included in Devon’s results of operations, but instead has been recorded directly to stockholders’ equity as part of “accumulated other comprehensive income.”
     Effective January 1, 2007, Devon adopted Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115. Statement No. 159 allows a company the option to value its financial assets and liabilities, on an instrument by instrument basis, at fair value, and include the change in fair value of such assets and liabilities in its results of operations. Devon chose to apply the provisions of Statement No. 159 to its shares of Chevron common stock. Accordingly, beginning with the first quarter of 2007, the change in fair value of the Chevron common stock owned by Devon, along with the change in fair value of the related exchange option, are both included in Devon’s results of operations.
     In the three-month and nine-month periods ended September 30, 2007, the change in fair value of financial instruments caption on Devon’s statements of operations includes unrealized gains of $133 million and $285 million, respectively, related to the Chevron common stock, and unrealized losses of $111 million and $255 million, respectively, related to the embedded option. In the three-month and nine-month periods ended September 30, 2006, prior to adopting Statement No. 159, unrealized losses of $22 million and $83 million, respectively, related to the change in fair value of the embedded option were included in the change in fair value of financial instruments caption on Devon’s statements of operations.
     As of December 31, 2006, $364 million of after-tax unrealized gains related to Devon’s investment in the Chevron common stock was included in accumulated other comprehensive income. This is the amount of unrealized gains that, prior to Devon’s adoption of Statement No. 159, had not been recorded in Devon’s historical results of operations. Upon the adoption of Statement No. 159 as of January 1, 2007, this $364 million of unrealized gains was reclassified on Devon’s balance sheet from accumulated other comprehensive income to retained earnings.
     In conjunction with the adoption of Statement No. 159, Devon also adopted on January 1, 2007 Statement of Financial Accounting Standards No. 157, Fair Value Measurements. Statement No. 157 provides a common definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements, but does not require any new fair value measurements. The adoption of Statement No. 157 had no impact on Devon’s financial statements, but it did result in additional required disclosures as set forth in Note 7.
Income Taxes – Change in Accounting Principle
     Devon and its subsidiaries are subject to current income taxes assessed by the federal and various state jurisdictions in the United States and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
     At September 30, 2007, undistributed earnings of foreign subsidiaries included in continuing operations were determined to be permanently reinvested. Therefore, no U.S. deferred income taxes were provided on such amounts at September 30, 2007. If it becomes apparent that some or all of the undistributed earnings will be distributed, Devon would then record taxes on those earnings.
     In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109. Interpretation No. 48 prescribes a threshold for recognizing the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in accrued expenses and other current liabilities. Interest and penalties related to unrecognized tax benefits are included in income tax expense.
     On January 1, 2007, Devon adopted Interpretation No. 48 and recorded a $10 million reduction to the January 1, 2007 balance of retained earnings related to unrecognized tax benefits. The $10 million includes $8 million for related interest and penalties. An additional $2 million of liabilities were recorded with a corresponding increase to goodwill.
     As a result of the adoption of Interpretation No. 48, certain liabilities included in income taxes payable and deferred income taxes were reclassified to other current and long-term liabilities in the accompanying balance sheet. The total $12 million increase in liabilities included a $15 million increase to long-term liabilities, partially offset by a $3 million reduction to current liabilities.
     As of January 1, 2007, Devon’s unrecognized tax benefits were $114 million. This amount included $82 million that, if recognized, would affect Devon’s effective income tax rate.
     Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.
     
              Jurisdiction   Tax Years Open
U.S. federal
  2002-2006
Various U.S. states
  2001-2006
Canada federal
  2000-2006
Various Canadian provinces
  2000-2006
Various other foreign jurisdictions
  1997-2006
     Devon is currently in the final stages of the administrative review process for certain open tax years. In addition, certain statute of limitation expirations are scheduled to occur in the next twelve months. Due to these factors, Devon anticipates it is reasonably possible that liabilities for certain tax positions will decrease between $15 million and $25 million within the next twelve months.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
2. Property and Equipment and Asset Retirement Obligations (“ARO”)
Divestitures
     On November 14, 2006, Devon announced that it intended to divest its operations in Egypt. Devon closed the sale of its Egyptian properties on October 4, 2007. Also, on January 23, 2007, Devon announced that it intends to divest its operations in West Africa. See Note 11 for more discussion regarding these divestiture activities.
Asset Retirement Obligations
     The following is a summary of the changes in Devon’s ARO for the first nine months of 2007 and 2006.
                 
    Nine Months Ended  
    September 30,  
    2007     2006  
    (In millions)  
Asset retirement obligation as of beginning of period
  $ 857       636  
Liabilities incurred
    44       92  
Liabilities settled
    (52 )     (39 )
Revision of estimated obligation
    311       135  
Accretion expense on discounted obligation
    55       35  
Foreign currency translation adjustment
    85       13  
 
           
Asset retirement obligation as of end of period
    1,300       872  
Less current portion
    54       45  
 
           
Asset retirement obligation, long-term
  $ 1,246       827  
 
           
     During the nine months ended September 30, 2007 and 2006, Devon recognized a $311 million and $135 million revision to its ARO, respectively. The primary factors causing the 2007 fair value increase were an overall increase in abandonment cost estimates and an increase in the assumed inflation rate. The effect of these factors was partially offset by the effect of an increase in the discount rate used to calculate the present value of the obligations. The primary factor causing the 2006 fair value increase was an overall increase in abandonment cost estimates.
3. Debt
Senior Credit Facility
     In April 2007, Devon extended the maturity of its existing $2.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) from April 7, 2011 to April 7, 2012.
     The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. As of September 30, 2007, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at September 30, 2007, as calculated pursuant to the terms of the agreement, was 24.8%.
     As of September 30, 2007, Devon had $400 million of outstanding borrowings under the Senior Credit Facility at an average rate of 5.85%. The available capacity under the Senior Credit Facility as of September 30, 2007, net of these borrowings as well as $1.7 billion of outstanding commercial paper and $280 million of outstanding letters of credit, was approximately $128 million.
Short-Term Credit Facility
     On August 7, 2007, Devon established a new $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility (the “Short-Term Facility”). This new facility provides Devon with provisional interim liquidity until it receives the proceeds from divestitures of assets in Africa (see Note 11). The Short-Term Facility was also used to support an increase in Devon’s commercial paper program from $2 billion to $3.5 billion.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
     The Short-Term Facility matures 364 days from the closing date. On the maturity date, all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to the maturity date, Devon has the option to convert any outstanding principal amount of loans under the Short-Term Facility to a term loan which will be repayable in a single payment 364 days from the maturity date.
     Amounts borrowed under the Short-Term Facility bear interest at various fixed rate options for periods of up to 12 months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Short-Term Facility currently provides for an annual facility fee of approximately $1.0 million that is payable quarterly in arrears.
     The agreement governing the Short-Term Facility contains substantially the same covenants and restrictions as Devon’s existing Senior Credit Facility, including a maximum allowed debt-to-capitalization ratio of 65% as defined in the agreement.
     As of September 30, 2007, there were no amounts borrowed under the Short-Term Facility, and the available capacity was $1.5 billion.
Commercial Paper
     As of September 30, 2007, Devon had $1.7 billion of outstanding commercial paper at an average rate of 5.66%.
Exchangeable Debentures
     During the third quarter of 2007, certain holders of exchangeable debentures exercised their option to convert their debentures prior to the August 15, 2008 maturity date. Devon has the option to settle conversions of the exchangeable debentures with either shares of Chevron common stock or cash equal to the market value of Chevron common stock at the time of conversion. Devon paid $166 million in cash to settle the conversions in the third quarter of 2007. As a result of the $166 million payment, Devon retired outstanding exchangeable debentures totaling $104 million as well as the related embedded derivative option with a value of $62 million.
     As of September 30, 2007, the Chevron exchangeable debentures are due within one year. However, Devon continues to classify this debt as long-term because it has the intent and ability to refinance these debentures on a long-term basis with the available capacity under its existing credit facilities or other long-term financing arrangements.
4. Retirement Plans
Net Periodic Benefit Cost and Other Comprehensive Income
     The following table presents the components of net periodic benefit cost and other comprehensive income for Devon’s pension and other post retirement benefit plans for the three-month and nine-month periods ended September 30, 2007 and 2006.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
                                                                 
    Pension Benefits     Other Postretirement Benefits  
    Three Months     Nine Months     Three Months     Nine Months  
    Ended September 30,     Ended September 30,     Ended September 30,     Ended September 30,  
    2007     2006     2007     2006     2007     2006     2007     2006  
                            (In millions)                          
Net periodic benefit cost:
                                                               
Service cost
  $ 8       6       23       18                          
Interest cost
    11       10       33       30       1       1       3       3  
Expected return on plan assets
    (12 )     (11 )     (36 )     (33 )                        
Net actuarial loss
    3       3       10       9                          
 
                                               
Net periodic benefit cost
    10       8       30       24       1       1       3       3  
Other comprehensive income:
                                                               
Recognition of net actuarial loss in net periodic benefit cost
    (4 )           (12 )                              
 
                                               
Total recognized
  $ 6       8       18       24       1       1       3       3  
 
                                               
     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R). Statement No. 158 requires the measurement of plan assets and benefit obligations as of the date of the employer’s fiscal year-end, beginning with fiscal years ending after December 15, 2008. Although not required until 2008, Devon adopted this measurement-date requirement in the second quarter of 2007 and is changing its measurement date from November 30 to December 31. As a result, Devon used data as of December 31, 2006 to remeasure its plans assets and benefit obligations previously measured using data as of November 30, 2006. As a result of the remeasurement, Devon recognized the following amounts in the second quarter of 2007.
         
    Increase (Decrease)
    (In millions)
Other long-term liabilities
    (26 )
Deferred income tax liabilities
    9  
Retained earnings
    (1 )
Accumulated other comprehensive income
    16  
General and administrative expenses
    2  
Revisions to Retirement Plans
     Devon has various noncontributory defined benefit pension plans, including qualified and nonqualified plans (“Defined Benefit Plans”), that provide defined levels of benefits to its domestic employees. Devon also has a 401(k) Incentive Savings Plan (“401(k) Plan”) that covers its domestic employees. Benefits under the 401(k) Plan consist of a discretionary match of a percentage of employees’ contributions to the 401(k) Plan.
     In the second quarter of 2007, Devon adopted an enhanced defined contribution structure related to the 401(k) Plan to be effective January 1, 2008. Participants in this enhanced defined contribution structure will continue to receive a discretionary match of a percentage of their contributions to the 401(k) Plan. These participants will also receive additional, nondiscretionary contributions by Devon calculated as a percentage of annual compensation. The percentage will vary based on the employee’s years of service.
     On or before November 15, 2007, existing eligible employees will elect to either continue to participate in the Defined Benefit Plan or participate in the enhanced defined contribution structure of the 401(k) Plan. Employees who continue to participate in the Defined Benefit Plans will continue to accrue benefits under the existing provisions of the Defined Benefit Plans. Employees who elect to participate in the enhanced defined contribution structure will receive enhanced contributions to the 401(k) Plan and will retain the benefits which they have accrued under the Defined Benefit Plan as of December 31, 2007. However, such employees will only be entitled to the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
benefits which have accrued in the Defined Benefit Plans as of December 31, 2007, after all applicable vesting requirements have been met. Employees hired on or after October 1, 2007 will not have an election and will only participate in the 401(k) Plan and the enhanced defined contribution structure.
     The effect the employee elections will have on Devon’s benefit obligations and related expenses will not be known until such elections are made with respect to the Defined Benefit Plans. However, based upon the most likely employee election scenarios, Devon expects that the effect, including any accelerated recognition of obligations of the Defined Benefit Plans, will be immaterial to its financial statements.
5. Stockholders’ Equity
Stock Repurchases
     In August 2005, Devon’s Board of Directors approved a stock repurchase program to repurchase up to 50 million shares of Devon’s common stock. This program was suspended in 2006 as a result of the $2.0 billion acquisition of oil and gas properties from Chief Holdings LLC (“Chief”) in June 2006. Prior to the suspension of the program and as of September 30, 2007, Devon had repurchased 6.5 million shares under this program for $387 million, or $59.80 per share. Although this program expires at the end of 2007, it could be extended. Should the Board of Directors elect to extend this repurchase program beyond the end of 2007, management expects to resume repurchases in conjunction with the closings of the planned sales of Devon’s operations in West Africa (see Note 11).
     On June 6, 2007, Devon’s Board of Directors approved an ongoing, annual stock repurchase program to offset dilution resulting from restricted stock issued to, and options exercised by, employees. The new repurchase program authorizes the repurchase of up to 4.5 million shares in 2007 and is in addition to the repurchase program described above. As of September 30, 2007, Devon had repurchased 1.8 million shares under the new program for $136 million, or $77.49 per share.
Dividends
     Dividends on Devon’s common stock were paid in 2007 and 2006 at quarterly per share rates of $0.14 and $0.1125, respectively.
6. Commitments and Contingencies
     Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals although actual amounts could differ materially from management’s estimate.
Environmental Matters
     Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon’s consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
     Certain of Devon’s subsidiaries acquired in past mergers are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties (“PRPs”) under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of September 30, 2007, Devon’s consolidated balance sheet included $4 million of non-current accrued liabilities, reflected in “Other liabilities,” related to these and other environmental remediation liabilities. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devon’s monetary exposure is not expected to be material.
Royalty Matters
     Numerous gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The principal suit in which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the “Wright case”). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. On April 12, 2007, the court entered a trial plan and scheduling order in which the case will proceed in phases. A defendant other than Devon is set for trial in August 2008. The next phase trial is set for February 2009. Defendants, other than Devon, were selected for this trial. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.
     In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain years by the Minerals Management Service (the “MMS”) have contained price thresholds, such that if the market prices for oil or natural gas exceeded the thresholds for a given year, royalty relief would not be granted for that year. Deep water leases issued in 1998 and 1999 did not include price thresholds. The MMS in 2006 informed Devon and other oil and gas companies that the omission of price thresholds from these leases was an error on its part and was not its intention. Accordingly, the MMS invited Devon and the other affected oil and gas producers to renegotiate the terms and conditions of the 1998 and 1999 leases to add price threshold provisions to the lease agreements for periods after October 1, 2006. Devon has since had several discussions with MMS representatives on this issue, but has not yet entered into renegotiated leases.
     The U.S. House of Representatives in January 2007 and July 2007 passed legislation that would require companies to renegotiate the 1998 and 1999 leases as a condition of securing future federal leases. If this legislation were to become law, it would require price thresholds to be effective in the renegotiated 1998 and 1999 leases effective October 1, 2006. Although Devon has not yet signed renegotiated leases, it has accrued through September 30, 2007 approximately $21 million for royalties that would be due if price thresholds were added to its 1998 and 1999 leases effective October 1, 2006.
Canadian Royalties
     On October 25, 2007, the Alberta government proposed increases to the royalty rates on oil and natural gas production beginning in 2009. Devon believes this proposal would reduce future earnings and cash flows from its oil and gas properties located in Alberta. Additionally, assuming all other factors are equal, higher royalty rates would likely result in lower levels of capital investment in Alberta relative to Devon’s other areas of operation.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
However, the magnitude of the potential impact, which will depend on the final form of enacted legislation and other factors which impact the relative expected economic returns of capital projects, cannot be reasonably estimated at this time.
Equatorial Guinea Investigation
     The SEC has been conducting an inquiry into payments made to the government of Equatorial Guinea and to officials and persons affiliated with officials of the government of Equatorial Guinea. On August 9, 2005, Devon received a subpoena issued by the SEC pursuant to a formal order of investigation. Devon has cooperated fully with the SEC’s requests for information in this inquiry. After responding in 2005 to such requests for information, Devon has not been contacted by the SEC. In the event that Devon receives any further inquiries, Devon will work with the SEC in connection with its investigation.
Hurricane Contingencies
     Historically, Devon maintained a comprehensive insurance program that included coverage for physical damage to its offshore facilities caused by hurricanes. Devon’s historical insurance program also included substantial business interruption coverage which Devon is utilizing to recover costs associated with the suspended production related to hurricanes that struck the Gulf of Mexico in the third quarter of 2005. Under the terms of this insurance program, Devon was entitled to be reimbursed for the portion of production suspended longer than forty-five days, subject to upper limits to oil and natural gas prices. Also, the terms of the insurance include a standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate annual deductible.
     Based on current estimates of physical damage and the anticipated length of time Devon will have production suspended, Devon expects its policy recoveries will exceed repair costs and deductible amounts. This expectation is based upon several variables, including the $467 million received in the third quarter of 2006 as a full settlement of the amount due from Devon’s primary insurers and $13 million received in the second quarter of 2007 as a full settlement of the amount due from certain of Devon’s secondary insurers. Devon continues to negotiate with its other secondary insurers and expects to receive additional policy recoveries as a result of such negotiations. As of September 30, 2007, $281 million of these proceeds had been utilized as reimbursement of past repair costs and deductible amounts. The remaining proceeds of $199 million are expected to be utilized as reimbursement of Devon’s anticipated future repair costs.
     Should Devon’s total policy recoveries, including settlements already received from Devon’s primary and secondary insurers, exceed all repair costs and deductible amounts, such excess will be recognized as other income in the statement of operations in the period in which such determination can be made.
     The policy underlying the insurance program terms described above expired on August 31, 2006. During the third quarter of 2006 and again in the third quarter of 2007, Devon was able to re-establish a comprehensive insurance program that includes business interruption and physical damage coverage for its business. However, due to significant changes in the marketplace, Devon was only able to obtain a de minimis amount of coverage for any damage that may be caused by named windstorms in the Gulf of Mexico. Devon has not experienced any windstorm losses covered by the new insurance arrangements through September 30, 2007.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
7. Fair Value Measurements
     Certain of Devon’s assets and liabilities are reported at fair value in the accompanying balance sheets. The following table provides fair value measurement information for such assets and liabilities as of September 30, 2007.
                                 
            Fair Value Measurements Using:
        Quoted   Significant    
        Prices in   Other   Significant
        Active   Observable   Unobservable
    Total Fair   Markets   Inputs   Inputs
    Value   (Level 1)   (Level 2)   (Level 3)
    (In millions)
Assets:
                               
Short-term investments
  $ 341       341              
Investment in Chevron common stock
  $ 1,327       1,327              
Financial instruments
  $ 8             8        
 
                               
Liabilities:
                               
Financial instruments
  $ 497             497        
Asset retirement obligation (ARO)
  $ 1,300                   1,300  
     Statement No. 157 (see Note 1) establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the table above, this hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 3 inputs have the lowest priority.
     Devon uses appropriate valuation techniques based on the available inputs to measure the fair values of its assets and liabilities. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value. Devon owes debt that has an embedded exchange option. Because the exchange option is not actively traded in an established market, its fair value is measured using Level 2 inputs. Devon also has certain commodity and interest-rate derivative financial instruments which are measured using Level 2 inputs, such as forward commodity price curves or interest-rate yield curves. Devon only uses Level 3 inputs to measure the fair value of its ARO. A reconciliation of the beginning and ending balances of Devon’s ARO, including a revision of the fair value in 2007, is presented in Note 2.
8. Change in Fair Value of Financial Instruments
     The components of change in fair value of financial instruments include the following:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
    (In millions)  
Option embedded in exchangeable debentures
  $ 111       22       255       83  
Investment in Chevron common stock (Note 1)
    (133 )           (285 )      
Interest rate swaps
                (1 )     (2 )
 
                       
Total
  $ (22 )     22       (31 )     81  
 
                       

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
9. Reduction of Carrying Value of Oil and Gas Properties
     The following schedule summarizes the reductions of carrying value of oil and gas properties for the third quarter and first nine months of 2006.
                                 
    Three Months Ended     Nine Months Ended  
    September 30, 2006     September 30, 2006  
            Net of             Net of  
    Gross     Taxes     Gross     Taxes  
    (In millions)  
Brazil
  $             16       16  
Russia
    20       10       20       10  
 
                       
Total
  $ 20       10       36       26  
 
                       
     As a result of a decline in projected future net cash flows, the carrying value of Devon’s Russian properties exceeded the ceiling by $10 million in the third quarter of 2006. Therefore, in the third quarter of 2006, Devon recognized a $20 million reduction of the carrying value of its oil and gas properties in Russia, offset by a $10 million deferred income tax benefit.
     During the second quarter of 2006, Devon drilled two unsuccessful exploratory wells in Brazil and determined that the capitalized costs related to these two wells should be impaired. Therefore, in the second quarter of 2006, Devon recognized a $16 million impairment of its investment in Brazil equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There was no tax benefit related to this impairment. The two wells were unrelated to Devon’s Polvo development project in Brazil.
     See Note 11 for information related to reductions of carrying value of oil and gas properties included in discontinued operations.
10. Other Income
     The components of other income include the following:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
    (In millions)  
Interest and dividend income
  $ 24       22       63       78  
Net gain on sales of non-oil and gas property and equipment
                1       5  
Other
    4       6       7       3  
 
                       
Total
  $ 28       28       71       86  
 
                       
11. Discontinued Operations
Egypt and West Africa
     On November 14, 2006, Devon announced its plans to divest its operations in Egypt. On January 23, 2007, Devon announced its plans to divest its operations in West Africa. Pursuant to accounting rules for discontinued operations, Devon has classified all 2007 and prior period amounts related to its operations in Egypt and West Africa as discontinued operations.
     On October 4, 2007, Devon closed the sale of its Egyptian operations and received proceeds of $341 million. As a result of this sale, Devon will record an after-tax gain related to this transaction of approximately $130 million in the fourth quarter of 2007.
     Devon is finalizing purchase and sales agreements and obtaining the necessary partner and government

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
approvals for the properties in the West African divestiture package. Devon expects to complete these sales during the first half of 2008.
     Revenues related to Devon’s operations in Egypt and West Africa totaled $206 million and $223 million in the three months ended September 30, 2007 and September 30, 2006 and $596 million and $707 million in the nine months ended September 30, 2007 and September 30, 2006, respectively.
     The following table presents the main classes of assets and liabilities associated with Devon’s operations in Egypt and West Africa as of September 30, 2007 and December 31, 2006.
                 
    September 30,     December 31,  
    2007     2006  
    (In millions)  
Assets:
               
Cash
  $ 29       64  
Accounts receivable
    87       101  
Other current assets
    60       67  
 
           
Current assets
  $ 176       232  
 
           
 
               
Long-term assets – property and equipment, net of accumulated depreciation, depletion and amortization
  $ 1,707       1,619  
 
           
 
               
Liabilities:
               
Accounts payable – trade
  $ 34       48  
Income taxes payable
    146       115  
Current portion of asset retirement obligation
    8       8  
Accrued expenses and other current liabilities
    2       2  
 
           
Current liabilities
  $ 190       173  
 
           
 
               
Asset retirement obligation, long-term
  $ 44       38  
Deferred income taxes
    385       375  
Other liabilities
    16       16  
 
           
Long-term liabilities
  $ 445       429  
 
           
Reduction of Carrying Value
     Based on recent drilling activities in Nigeria, Devon reduced the carrying value of its Nigerian assets held for sale in the second quarter of 2007. As a result, earnings from discontinued operations in the nine months ended 2007 include a $13 million after-tax loss ($64 million pre-tax).
     As a result of unsuccessful exploratory activities in Egypt during the third quarter of 2006, the net book value of Devon’s Egyptian oil and gas properties, less related deferred income taxes, exceeded the ceiling by $18 million as of September 30, 2006. Therefore, in the third quarter of 2006, Devon recognized a $13 million after-tax loss Egypt ($31 million pre-tax).
     Due to unsuccessful drilling activities in Nigeria, in the first quarter of 2006, Devon recognized an $85 million impairment of its investment in Nigeria equal to the costs to drill two dry holes and a proportionate share of block-related costs. There was no income tax benefit related to this impairment.
12. Income Taxes
     During the second quarter of 2007, the Canadian Federal government enacted a statutory rate reduction. As a result of this rate reduction, Devon recorded a $30 million deferred tax benefit in such quarter.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
13. Segment Information
     Following is certain financial information regarding Devon’s reporting segments. The revenues reported are all from external customers.
                                 
    U.S.     Canada     International     Total  
    (In millions)  
As of September 30, 2007:
                               
Current assets
  $ 1,693       837       1,154       3,684  
Property and equipment, net of accumulated depreciation, depletion and amortization
    17,237       8,652       1,096       26,985  
Goodwill
    3,053       3,029       68       6,150  
Other assets
    1,624       53       1,775       3,452  
 
                       
Total assets
  $ 23,607       12,571       4,093       40,271  
 
                       
 
                               
Current liabilities
  $ 3,660       670       436       4,766  
Long-term debt
    2,898       2,975             5,873  
Asset retirement obligation, long-term
    605       569       72       1,246  
Other liabilities
    1,070       43       449       1,562  
Deferred income taxes
    3,734       2,195       63       5,992  
Stockholders’ equity
    11,640       6,119       3,073       20,832  
 
                       
Total liabilities and stockholders’ equity
  $ 23,607       12,571       4,093       40,271  
 
                       

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
                                 
    U.S.     Canada     International     Total  
            (In millions)          
Three Months Ended September 30, 2007:
                               
Revenues:
                               
Oil sales
  $ 359       224       322       905  
Gas sales
    867       312       3       1,182  
NGL sales
    196       46             242  
Marketing and midstream revenues
    421       13             434  
 
                       
Total revenues
    1,843       595       325       2,763  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    247       177       33       457  
Production taxes
    50       1       34       85  
Marketing and midstream operating costs and expenses
    296       5             301  
Depreciation, depletion and amortization of oil and gas properties
    457       193       55       705  
Depreciation and amortization of non-oil and gas properties
    45       5       1       51  
Accretion of asset retirement obligation
    10       8       1       19  
General and administrative expenses
    95       31             126  
Interest expense
    58       50             108  
Change in fair value of financial instruments
    (22 )                 (22 )
Other income, net
    (10 )     (6 )     (12 )     (28 )
 
                       
Total expenses and other income, net
    1,226       464       112       1,802  
 
                       
Earnings from continuing operations before income tax expense
    617       131       213       961  
Income tax expense (benefit):
                               
Current
    (2 )     40       58       96  
Deferred
    215       8       (2 )     221  
 
                       
Total income tax expense
    213       48       56       317  
 
                       
Earnings from continuing operations
    404       83       157       644  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
                177       177  
Income tax expense
                86       86  
 
                       
Earnings from discontinued operations
                91       91  
 
                       
Net earnings
    404       83       248       735  
Preferred stock dividends
    2                   2  
 
                       
Net earnings applicable to common stockholders
  $ 402       83       248       733  
 
                       
 
                               
Capital expenditures, continuing operations
  $ 1,182       291       114       1,587  
 
                       

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
                                 
    U.S.     Canada     International     Total  
            (In millions)          
Three Months Ended September 30, 2006:
                               
Revenues:
                               
Oil sales
  $ 328       174       194       696  
Gas sales
    856       329       1       1,186  
NGL sales
    151       53             204  
Marketing and midstream revenues
    404       9             413  
 
                       
Total revenues
    1,739       565       195       2,499  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    207       141       15       363  
Production taxes
    58       1       33       92  
Marketing and midstream operating costs and expenses
    299       2             301  
Depreciation, depletion and amortization of oil and gas properties
    358       164       25       547  
Depreciation and amortization of non-oil and gas properties
    38       5             43  
Accretion of asset retirement obligation
    6       6             12  
General and administrative expenses
    80       24             104  
Interest expense
    56       56             112  
Change in fair value of financial instruments
    22                   22  
Reduction of carrying value of oil and gas properties
                20       20  
Other (income) expense, net
    7             (35 )     (28 )
 
                       
Total expenses and other income, net
    1,131       399       58       1,588  
 
                       
Earnings from continuing operations before income tax expense
    608       166       137       911  
Income tax expense (benefit):
                               
Current
    86       23       38       147  
Deferred
    93       32       (14 )     111  
 
                       
Total income tax expense
    179       55       24       258  
 
                       
Earnings from continuing operations
    429       111       113       653  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
                112       112  
Income tax expense
                60       60  
 
                       
Earnings from discontinued operations
                52       52  
 
                       
Net earnings
    429       111       165       705  
Preferred stock dividends
    2                   2  
 
                       
Net earnings applicable to common stockholders
  $ 427       111       165       703  
 
                       
 
                               
Capital expenditures, continuing operations
  $ 931       326       85       1,342  
 
                       

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
                                 
    U.S.     Canada     International     Total  
            (In millions)          
Nine Months Ended September 30, 2007:
                               
Revenues:
                               
Oil sales
  $ 898       562       1,001       2,461  
Gas sales
    2,733       1,048       7       3,788  
NGL sales
    509       134             643  
Marketing and midstream revenues
    1,244       29             1,273  
 
                       
Total revenues
    5,384       1,773       1,008       8,165  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    751       460       115       1,326  
Production taxes
    165       3       87       255  
Marketing and midstream operating costs and expenses
    900       12             912  
Depreciation, depletion and amortization of oil and gas properties
    1,230       535       172       1,937  
Depreciation and amortization of non-oil and gas properties
    130       15       1       146  
Accretion of asset retirement obligation
    29       23       3       55  
General and administrative expenses
    278       83       (3 )     358  
Interest expense
    174       151             325  
Change in fair value of financial instruments
    (30 )     (1 )           (31 )
Other income, net
    (28 )     (11 )     (32 )     (71 )
 
                       
Total expenses and other income, net
    3,599       1,270       343       5,212  
 
                       
Earnings from continuing operations before income tax expense
    1,785       503       665       2,953  
Income tax expense (benefit):
                               
Current
    120       145       194       459  
Deferred
    467       3       (18 )     452  
 
                       
Total income tax expense
    587       148       176       911  
 
                       
Earnings from continuing operations
    1,198       355       489       2,042  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
                442       442  
Income tax expense
                194       194  
 
                       
Earnings from discontinued operations
                248       248  
 
                       
Net earnings
    1,198       355       737       2,290  
Preferred stock dividends
    7                   7  
 
                       
Net earnings applicable to common stockholders
  $ 1,191       355       737       2,283  
 
                       
 
Capital expenditures, before revision of future ARO
  $ 3,204       952       329       4,485  
Revision of future ARO
    210       99       2       311  
 
                       
Capital expenditures, continuing operations
  $ 3,414       1,051       331       4,796  
 
                       

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
                                 
    U.S.     Canada     International     Total  
            (In millions)          
Nine Months Ended September 30, 2006:
                               
Revenues:
                               
Oil sales
  $ 956       463       387       1,806  
Gas sales
    2,577       1,122       10       3,709  
NGL sales
    414       159             573  
Marketing and midstream revenues
    1,237       24             1,261  
 
                       
Total revenues
    5,184       1,768       397       7,349  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    601       399       36       1,036  
Production taxes
    182       4       75       261  
Marketing and midstream operating costs and expenses
    917       7             924  
Depreciation, depletion and amortization of oil and gas properties
    943       484       53       1,480  
Depreciation and amortization of non-oil and gas properties
    113       13       1       127  
Accretion of asset retirement obligation
    19       16             35  
General and administrative expenses
    221       66       (3 )     284  
Interest expense
    144       171             315  
Change in fair value of financial instruments
    83       (2 )           81  
Reduction of carrying value of oil and gas properties
                36       36  
Other income, net
    (27 )     (11 )     (48 )     (86 )
 
                       
Total expenses and other income, net
    3,196       1,147       150       4,493  
 
                       
Earnings from continuing operations before income tax expense (benefit)
    1,988       621       247       2,856  
Income tax expense (benefit):
                               
Current
    281       111       79       471  
Deferred
    398       (121 )     (24 )     253  
 
                       
Total income tax expense (benefit)
    679       (10 )     55       724  
 
                       
Earnings from continuing operations
    1,309       631       192       2,132  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
                337       337  
Income tax expense
                205       205  
 
                       
Earnings from discontinued operations
                132       132  
 
                       
Net earnings
    1,309       631       324       2,264  
Preferred stock dividends
    7                   7  
 
                       
Net earnings applicable to common stockholders
  $ 1,302       631       324       2,257  
 
                       
 
                               
Capital expenditures, before revision of future ARO
  $ 4,758       1,296       229       6,283  
Revision of future ARO
    64       71             135  
 
                       
Capital expenditures, continuing operations
  $ 4,822       1,367       229       6,418  
 
                       
14. Subsequent Event – Master Limited Partnership
     Devon announced on July 18, 2007 its plan to form a new, publicly traded master limited partnership (“MLP”). The proposed MLP was expected to initially own a minority interest in Devon’s U.S. onshore marketing and midstream business. On November 7, 2007, Devon announced that it had decided not to proceed at this time with its plans to form this MLP. This decision was based primarily on a change in public market conditions for MLPs and other yield-driven investments subsequent to Devon’s announcement of the proposed MLP.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The following discussion addresses material changes in our results of operations for the three-month and nine-month periods ended September 30, 2007, compared to the three-month and nine-month periods ended September 30, 2006, and in our financial condition since December 31, 2006. It is presumed that readers have read or have access to our 2006 Annual Report on Form 10-K which includes disclosures regarding critical accounting policies as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.
Overview
     The following summarizes our performance for the three months and nine months ended September 30, 2007 compared to the three months and nine months ended September 30, 2006:
    Net earnings and earnings per share both increased 4% and 1% during the third quarter of 2007 and the first nine months of 2007, respectively.
 
    Net cash provided by operating activities increased $227 million, or 5%, during the first nine months of 2007.
 
    Production increased 10% to 618 thousand barrels per day for the third quarter of 2007 and increased 12% to 608 thousand barrels per day for the first nine months of 2007.
 
    Combined realized price for oil, gas and NGLs increased 2% and 1% for the third quarter of 2007 and the first nine months of 2007, respectively.
 
    Marketing and midstream operating profit increased 19% and 7% during the third quarter of 2007 and the first nine months of 2007, respectively.
 
    Per unit operating costs increased 15% and 14% for the third quarter and first nine months of 2007, respectively.
 
    Capital expenditures for oil and gas exploration and development activities were $1.4 billion during the third quarter of 2007 and $4.1 billion during the first nine months of 2007.
     On November 14, 2006, we announced our plans to divest our operations in Egypt. On January 23, 2007, we announced our plans to divest our operations in West Africa. Pursuant to accounting rules for discontinued operations, we have classified all 2007 and prior period amounts related to our operations in Egypt and West Africa as discontinued operations.
     On October 4, 2007, we closed the sale of our Egyptian operations and received proceeds of $341 million. As a result of this sale, we will record an after-tax gain related to this transaction of approximately $130 million in the fourth quarter of 2007.
     We are finalizing purchase and sales agreements and obtaining the necessary partner and government approvals for the properties in the West African divestiture package. We expect to complete these sales during the first half of 2008.
     On October 25, 2007, the Alberta government proposed increases to the royalty rates on oil and natural gas production beginning in 2009. We believe this proposal would reduce future earnings and cash flows from our oil and gas properties located in Alberta. Additionally, assuming all other factors are equal, higher royalty rates would likely result in lower levels of capital investment in Alberta relative to our other areas of operation. However, the magnitude of the potential impact, which will depend on the final form of enacted legislation and other factors which impact the relative expected economic returns of capital projects, cannot be reasonably estimated at this time.
     A more complete overview and discussion of full-year expectations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2006 Annual Report on Form 10-K and in our Current Report on Form 8-K dated November 7, 2007.

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Results of Operations
Revenues
     The three-month and nine-month comparisons of production and price changes are shown in the following tables. The amounts for all periods presented exclude our Egyptian and West African operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.
                                                 
    Total  
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2007     2006     Change(2)     2007     2006     Change(2)  
Production
                                               
Oil (MMBbls)
    13       11       +23 %     41       31       +35 %
Gas (Bcf)
    223       210       +6 %     637       599       +6 %
NGLs (MMBbls)
    7       5       +9 %     19       17       +8 %
Oil, Gas and NGLs (MMBoe)(1)
    57       52       +10 %     166       148       +12 %
 
                                               
Average Prices
                                               
Oil (Per Bbl)
  $ 67.41       63.77       +6 %   $ 59.88       59.43       +1 %
Gas (Per Mcf)
    5.31       5.63       -6 %     5.95       6.19       -4 %
NGLs (Per Bbl)
    38.34       34.98       +10 %     34.31       32.99       +4 %
Oil, Gas and NGLs (Per Boe)(1)
    40.99       40.24       +2 %     41.53       41.23       +1 %
 
                                               
Revenues ($ in millions)
                                               
Oil
  $ 905       696       +30 %   $ 2,461       1,806       +36 %
Gas
    1,182       1,186             3,788       3,709       +2 %
NGLs
    242       204       +19 %     643       573       +12 %
 
                                       
Oil, Gas and NGLs
  $ 2,329       2,086       +12 %   $ 6,892       6,088       +13 %
 
                                       
                                                 
    Domestic  
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2007     2006     Change(2)     2007     2006     Change(2)  
Production
                                               
Oil (MMBbls)
    5       5       +2 %     14       15       -4 %
Gas (Bcf)
    164       149       +10 %     465       415       +12 %
NGLs (MMBbls)
    6       4       +15 %     16       14       +13 %
Oil, Gas and NGLs (MMBoe)(1)
    38       35       +9 %     107       98       +10 %
 
                                               
Average Prices
                                               
Oil (Per Bbl)
  $ 73.19       68.27       +7 %   $ 63.01       64.30       -2 %
Gas (Per Mcf)
    5.28       5.73       -8 %     5.88       6.21       -5 %
NGLs (Per Bbl)
    36.78       32.41       +13 %     32.68       30.06       +9 %
Oil, Gas and NGLs (Per Boe)(1)
    37.81       38.86       -3 %     38.56       40.34       -4 %
 
                                               
Revenues ($ in millions)
                                               
Oil
  $ 359       328       +9 %   $ 898       956       -6 %
Gas
    867       856       +1 %     2,733       2,577       +6 %
NGLs
    196       151       +30 %     509       414       +23 %
 
                                       
Oil, Gas and NGLs
  $ 1,422       1,335       +6 %   $ 4,140       3,947       +5 %
 
                                       

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    Canada  
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2007     2006     Change(2)     2007     2006     Change(2)  
Production
                                               
Oil (MMBbls)
    4       3       +32 %     12       9       +24 %
Gas (Bcf)
    59       61       -5 %     171       183       -7 %
NGLs (MMBbls)
    1       1       -16 %     3       3       -12 %
Oil, Gas and NGLs (MMBoe)(1)
    15       14       +2 %     43       43       -1 %
 
                                               
Average Prices
                                               
Oil (Per Bbl)
  $ 53.40       54.85       -3 %   $ 48.01       49.06       -2 %
Gas (Per Mcf)
    5.40       5.40             6.16       6.14        
NGLs (Per Bbl)
    46.77       45.23       +3 %     42.36       44.20       -4 %
Oil, Gas and NGLs (Per Boe)(1)
    39.28       38.34       +2 %     40.33       40.11       +1 %
 
                                               
Revenues ($ in millions)
                                               
Oil
  $ 224       174       +29 %   $ 562       463       +21 %
Gas
    312       329       -5 %     1,048       1,122       -7 %
NGLs
    46       53       -13 %     134       159       -16 %
 
                                       
Oil, Gas and NGLs
  $ 582       556       +5 %   $ 1,744       1,744        
 
                                       
                                                 
    International  
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2007     2006     Change(2)     2007     2006     Change(2)  
Production
                                               
Oil (MMBbls)
    4       3       +48 %     15       7       +149 %
Gas (Bcf)
                +74 %     1       1       -19 %
NGLs (MMBbls)
                N/M                   N/M  
Oil, Gas and NGLs (MMBoe)(1)
    4       3       +48 %     16       7       +142 %
 
                                               
Average Prices
                                               
Oil (Per Bbl)
  $ 74.43       66.00       +13 %   $ 66.10       63.59       +4 %
Gas (Per Mcf)
    6.61       5.11       +29 %     5.73       6.34       -10 %
NGLs (Per Bbl)
                N/M                   N/M  
Oil, Gas and NGLs (Per Boe)(1)
    73.77       65.42       +13 %     65.66       62.53       +5 %
 
                                               
Revenues ($ in millions)
                                               
Oil
  $ 322       194       +67 %   $ 1,001       387       +159 %
Gas
    3       1       +125 %     7       10       -26 %
NGLs
                N/M                   N/M  
 
                                       
Oil, Gas and NGLs
  $ 325       195       +67 %   $ 1,008       397       +154 %
 
                                       
 
(1)   Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices. NGL volumes are converted to Boe on a one-to-one basis with oil.
 
(2)   All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.
N/M Not meaningful.

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     The following tables include the effect of our financial hedging activities for the three months and nine months ended September 30, 2007 and 2006, respectively.
                                 
    Three Months   Nine Months
    Ended September 30, 2007   Ended September 30, 2007
    With   Without   With   Without
    Hedges   Hedges   Hedges   Hedges
Oil (per Bbl)
  $ 67.41       67.41     59.88       59.88  
Gas (per Mcf)
  $ 5.31 (1)     5.28     5.95 (1)     5.94  
NGLs (per Bbl)
  $ 38.34       38.34     34.31       34.31  
Oil, Gas and NGLs (per Boe)
  $ 40.99       40.86     41.53       41.52  
 
(1)   The average gas sales price with the effect of hedges includes both the effect due to unrealized losses and the effect due to cash settlements on our hedging contracts. Excluding an unrealized loss of $6 million for the three months ended September 30, 2007 and an unrealized loss of $30 million for the nine months ended September 30, 2007, our average realized gas sales price would have been $5.34 and $6.00, respectively.
                                 
    Three Months   Nine Months
    Ended September 30, 2006   Ended September 30, 2006
    With   Without   With   Without
    Hedges   Hedges   Hedges   Hedges
Oil (per Bbl)
  $ 63.77       63.77       59.43       59.43  
Gas (per Mcf)
  $ 5.63 (1)     5.61       6.19 (1)     6.18  
NGLs (per Bbl)
  $ 34.98       34.98       32.99       32.99  
Oil, Gas and NGLs (per Boe)
  $ 40.24       40.14       41.23       41.19  
 
(1)   The average gas sales price with the effect of hedges includes both the effect due to unrealized gains and the effect due to cash settlements on our hedging contracts. Excluding an unrealized gain of $5 million for both the three months and nine months ended September 30, 2006, our average realized gas sales price would have been $5.61 and $6.18, respectively.
     The following tables summarize the changes in our oil, gas and NGL revenues between the three months ended September 30, 2007 and 2006 and the nine months ended September 30, 2007 and 2006.
                                 
    Three Months Ended September 30, 2007  
    Oil     Gas     NGL     Total  
            (In millions)          
2006 revenues
  $ 696       1,186       204       2,086  
Changes due to volumes
    160       67       18       245  
Changes due to prices
    49       (60 )     20       9  
Changes due to unrealized hedge losses
          (11 )           (11 )
 
                       
2007 revenues
  $ 905       1,182       242       2,329  
 
                       
                                 
    Nine Months Ended September 30, 2007  
    Oil     Gas     NGL     Total  
            (In millions)          
2006 revenues
  $ 1,806       3,709       573       6,088  
Changes due to volumes
    637       230       46       913  
Changes due to prices
    18       (116 )     24       (74 )
Changes due to unrealized hedge losses
          (35 )           (35 )
 
                       
2007 revenues
  $ 2,461       3,788       643       6,892  
 
                       

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Oil Revenues
     Production increases of 23% and 35% in the third quarter of 2007 and first nine months of 2007 were the primary causes of our increased oil revenues in these periods. The increased 2007 production was primarily from our properties in Azerbaijan where we achieved payout of certain carried interests in the last half of 2006. The remainder of the 2007 increases were primarily related to increased production from our Lloydminster area in Canada.
Gas Revenues
     A 13 Bcf increase in production caused gas revenues to increase by $67 million during the third quarter of 2007. Our drilling and development program in the Barnett Shale field in north Texas contributed 17 Bcf to the gas production increase. This increase and the effect of new drilling and development in our other North American properties were partially offset by natural production declines.
     A 38 Bcf increase in production caused gas revenues to increase by $230 million during the first nine months of 2007. Our drilling and development program in the Barnett Shale field in north Texas contributed 36 Bcf to the gas production increase. The June 2006 Chief Holdings LLC (“Chief”) acquisition also contributed 12 Bcf of increased production. These increases and the effect of new drilling and development in our other North American properties were partially offset by natural production declines.
Marketing and Midstream Revenues and Operating Costs and Expenses
     The following table details the changes in our marketing and midstream revenues and operating costs and expenses between the three months ended September 30, 2007 and 2006 and the nine months ended September 30, 2007 and 2006. The changes due to prices in the table represent the effect on both revenues and expenses due to changes in the market prices for natural gas and NGLs.
                                 
    Three Months     Nine Months  
    Ended September 30,     Ended September 30,  
    Revenues     Expenses     Revenues     Expenses  
2006 marketing and midstream
  $ 413       301       1,261       924  
Changes due to volumes
    30       6       41       33  
Changes due to prices
    (9 )     (6 )     (30 )     (45 )
Other
                1        
 
                       
2007 marketing and midstream
  $ 434       301       1,273       912  
 
                       
     Volume increases in our third-party crude oil and NGL marketing activities caused both revenues and expenses to increase in the third quarter of 2007 and first nine months of 2007. Lower natural gas prices partially offset by higher NGL prices caused revenues and expenses to decrease in the third quarter of 2007 and the first nine months of 2007.

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Oil, Gas and NGL Production and Operating Expenses
     The three-month and nine-month comparisons of oil, gas and NGL production and operating expenses are shown in the table below.
                                                 
    Three Months     Nine Months  
    Ended September 30,     Ended September 30,  
    2007     2006     Change(1)     2007     2006     Change(1)  
Production and operating expenses ($ in millions):
                                               
Lease operating expenses
  $ 457       363       +26 %   $ 1,326       1,036       +28 %
Production taxes
    85       92       -8 %     255       261       -2 %
 
                                       
Total production and operating expenses
  $ 542       455       +19 %   $ 1,581       1,297       +22 %
 
                                       
 
                                               
Production and operating expenses per Boe:
                                               
Lease operating expenses
  $ 8.04       7.01       +15 %   $ 7.99       7.02       +14 %
Production taxes
    1.49       1.77       -16 %     1.54       1.77       -13 %
 
                                       
Total production and operating expenses per Boe
  $ 9.53       8.78       +9 %   $ 9.53       8.79       +8 %
 
                                       
 
(1)   All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.
     Lease operating expenses increased $94 million and $290 million in the third quarter of 2007 and the first nine months of 2007 largely due to the continued effects of higher commodity prices. Commodity price increases in 2005 and the first nine months of 2006 contributed to industry-wide inflationary pressures on materials and personnel costs. Although commodity prices have somewhat stabilized compared to the first nine months of 2006, demand for materials, equipment and personnel continued to increase subsequent to September 30, 2006. In addition, consideration of continued higher commodity prices contributed to our decision to perform more well workovers and maintenance projects in 2007 to maintain or improve production volumes.
     Lease operating expenses also increased $16 million and $77 million in the third quarter of 2007 and the first nine months ended 2007, respectively, as a result of payouts of our carried interests in Azerbaijan in the last half of 2006. The June 2006 Chief acquisition also increased our lease operating expenses by $15 million in the first nine months ended 2007. Our 10% and 12% production growth in the third quarter and the first nine months of 2007, respectively, were also key contributors to the increase in our lease operating expenses. Furthermore, changes in the exchange rate between the U.S. and Canadian dollar also caused lease operating expenses to increase $12 million and $13 million in the third quarter of 2007 and the first nine months of 2007, respectively.
     The following table details the changes in production taxes between the three months ended September 30, 2007 and 2006 and the nine months ended September 30, 2007 and 2006.
                 
    Three Months     Nine Months  
    Ended September 30,     Ended September 30,  
    (In millions)  
2006 production taxes
  $ 92       261  
Change due to revenues
    11       35  
Change due to rate
    (18 )     (41 )
 
           
2007 production taxes
  $ 85       255  
 
           
     Our lower production tax rates in 2007 are primarily due to the increase in Azerbaijan revenues subsequent to the payouts of our carried interests in Azerbaijan in the last half of 2006. Our Azerbaijan revenues are not subject to production taxes. Therefore, the increased revenues generated in Azerbaijan in 2007 caused our overall rate of production taxes to decrease.

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Depreciation, Depletion and Amortization Expenses (“DD&A”)
     The following table details the changes in DD&A of oil and gas properties between the three months ended September 30, 2007 and 2006 and the nine months ended September 30, 2007 and 2006.
                 
    Three Months     Nine Months  
    Ended September 30,     Ended September 30,  
    (In millions)  
2006 DD&A
  $ 547       1,480  
Change due to volumes
    53       184  
Change due to rate
    105       273  
 
           
2007 DD&A
  $ 705       1,937  
 
           
     Oil and gas property related DD&A increased $105 million in the third quarter of 2007 due to an increase in the DD&A rate from $10.55 per Boe to $12.41 per Boe. Oil and gas property related DD&A increased $273 million in the first nine months of 2007 due to an increase in the DD&A rate from $10.03 per Boe to $11.67 per Boe. The largest contributor to the rate increases were inflationary pressure on both the costs incurred during 2006 and 2007 as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Rising estimates for future asset retirement obligations also caused the rate to increase. Other factors contributing to the rate increase include the transfer of previously unproved costs to the depletable base as a result of drilling activities subsequent to September 30, 2006 and the effects of changes in the exchange rate between the U.S. and Canadian dollar.
General and Administrative Expenses (“G&A”)
     The following schedule includes the components of G&A expense for the three months ended September 30, 2007 and 2006 and the nine months ended September 30, 2007 and 2006.
                                 
    Three Months     Nine Months  
    Ended September 30,     Ended September 30,  
    2007     2006     2007     2006  
            (In millions)          
Gross G&A
  $ 239       190       673       526  
Capitalized G&A
    (84 )     (59 )     (230 )     (162 )
Reimbursed G&A
    (29 )     (27 )     (85 )     (80 )
 
                       
Net G&A
  $ 126       104       358       284  
 
                       
     Gross G&A increased $49 million and $147 million in the third quarter and first nine months of 2007, respectively, compared to the same periods of 2006. Higher employee compensation and benefits costs related to our growth and industry inflation caused gross G&A to increase $37 million and $110 million, respectively. The $25 million and $68 million increases in capitalized G&A during the third quarter and first nine months of 2007, respectively, are also primarily due to higher employee compensation and benefits costs.

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Interest Expense
     The following schedule includes the components of interest expense for the three months ended September 30, 2007 and 2006 and the nine months ended September 30, 2007 and 2006.
                                 
    Three Months     Nine Months  
    Ended September 30,     Ended September 30,  
    2007     2006     2007     2006  
            (In millions)          
Interest based on debt outstanding
  $ 127       126       380       359  
Capitalized interest
    (26 )     (21 )     (73 )     (57 )
Other
    7       7       18       13  
 
                       
Total
  $ 108       112       325       315  
 
                       
     Interest based on debt outstanding increased in the first nine months of 2007 primarily due to the effect of commercial paper borrowings related to the June 2006 acquisition of the Chief properties. This increase was partially offset by the effect of $680 million of debt maturities in the last half of 2006.
     Capitalized interest in the third quarter and the first nine months of 2007 increased primarily due to costs related to our Jackfish development project and the related Access Pipeline in Canada, as well as development projects in the Gulf of Mexico and Brazil.
Change in Fair Value of Financial Instruments
     The following schedule includes the components of the change in fair value of financial instruments for the three months ended September 30, 2007 and 2006 and the nine months ended September 30, 2007 and 2006.
                                 
    Three Months     Nine Months  
    Ended September 30,     Ended September 30,  
    2007     2006     2007     2006  
            (In millions)          
Option embedded in exchangeable debentures
  $ 111       22       255       83  
Investment in Chevron common stock
    (133 )           (285 )      
Interest rate swaps
                (1 )     (2 )
 
                       
Total (income) expense
  $ (22 )     22       (31 )     81  
 
                       
     The change in the fair value of the embedded option relates to the debentures exchangeable into shares of Chevron common stock. These expenses were caused primarily by increases in the price of Chevron’s common stock.
     During the third quarter of 2007, certain holders of exchangeable debentures exercised their option to convert their debentures prior to the August 15, 2008 maturity date. We have the option to settle conversions of the exchangeable debentures with either shares of Chevron common stock or cash equal to the market value of Chevron common stock at the time of conversion. We paid $166 million in cash to settle the conversions in the third quarter of 2007. As a result of the $166 million payment, we retired outstanding exchangeable debentures totaling $104 million as well as the related embedded derivative option with a value of $62 million.
     As discussed in Note 1 to our financial statements, effective January 1, 2007 as a result of our adoption of Statement No. 159, we began recognizing unrealized gains and losses on our investment in Chevron common stock in net earnings rather than as part of other comprehensive income. The change in the fair value of our investment in Chevron common stock resulted from increases in the price of Chevron’s common stock during the third quarter and first nine months of 2007.

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Reduction of Carrying Value of Oil and Gas Properties
     The following schedule summarizes the reductions of carrying value of oil and gas properties for the third quarter and first nine months of 2006. We had no such reductions in 2007.
                                 
    Three Months Ended     Nine Months Ended  
    September 30, 2006     September 30, 2006  
            Net of             Net of  
    Gross     Taxes     Gross     Taxes  
    (In millions)  
Brazil
  $             16       16  
Russia
    20       10       20       10  
 
                       
Total
  $ 20       10       36       26  
 
                       
     As a result of a decline in projected future net cash flows, our Russian properties exceeded the ceiling by $10 million in the third quarter of 2006. Therefore, in the third quarter of 2006, we recognized a $20 million reduction of the carrying value of our oil and gas properties in Russia, offset by a $10 million deferred income tax benefit.
     During the second quarter of 2006, we drilled two unsuccessful exploratory wells in Brazil and determined that the capitalized costs related to these two wells should be impaired. Therefore, in the second quarter of 2006, we recognized a $16 million impairment of our investment in Brazil equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There was no tax benefit related to this impairment. The two wells were unrelated to our Polvo development project in Brazil.
Other Income, net
     The following schedule includes the components of other income for the three months ended September 30, 2007 and 2006 and the nine months ended September 30, 2007 and 2006.
                                 
    Three Months     Nine Months  
    Ended September 30,     Ended September 30,  
    2007     2006     2007     2006  
            (In millions)          
Interest and dividend income
  $ 24       22       63       78  
Net gain on sales of non-oil and gas property and equipment
                1       5  
Other
    4       6       7       3  
 
                       
Total
  $ 28       28       71       86  
 
                       
     The decrease in interest and dividend income in the first nine months of 2007 were primarily due to a decrease in interest-bearing cash and short-term investment balances subsequent to the June 2006 Chief acquisition.
Income Taxes
     The effective tax rate was 33% in the third quarter of 2007 and 28% in the third quarter of 2006. The effective tax rate was 31% in the first nine months of 2007 and 25% in the first nine months of 2006.
     The rates for the third quarter and first nine months of 2007 were lower than the statutory federal tax rate primarily due to the effects of certain U.S. and Canadian deductions. The 2007 rates were further lowered due to the increase in revenues generated in Azerbaijan, whose statutory rate is 25%, and the effect of a statutory rate reduction enacted by the Canadian Federal government in the second quarter of 2007. As a result of the 2007 Canadian rate reduction, we recorded a $30 million tax benefit in such quarter.

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     The rates for the third quarter and first nine months of 2006 were lower than the statutory federal tax rate primarily due to the effects of tax law changes. During the second quarter of 2006, the Canadian Federal and Alberta provincial governments enacted statutory rate reductions. As a result, we recorded a $243 million deferred tax benefit in such quarter. Also during the second quarter of 2006, the state of Texas enacted a new income-based tax that replaces a previous franchise tax. The new tax is effective January 1, 2007. As a result of the enactment of the tax in the second quarter of 2006, we recorded $39 million of deferred tax expense in such quarter. In addition, in the third quarter of 2006 we recognized an $11 million deferred tax benefit related to the expected utilization of a net operating loss carryforward that has been generated in Brazil.
Earnings from Discontinued Operations
     On November 14, 2006, we announced our plans to divest our operations in Egypt. On January 23, 2007, we announced our plans to divest our operations in West Africa. Pursuant to accounting rules for discontinued operations, we have classified all 2007 and prior period amounts related to our operations in Egypt and West Africa as discontinued operations.
     On October 4, 2007, we closed the sale of our Egyptian operations and received proceeds of $341 million. As a result of this sale, we will record an after-tax gain related to this transaction of approximately $130 million in the fourth quarter of 2007.
     We are finalizing purchase and sales agreements and obtaining the necessary partner and government approvals for the properties in the West African divestiture package. We expect to complete these sales during the first half of 2008.
     Following are the components of earnings from discontinued operations for the three months ended September 30, 2007 and 2006 and the nine months ended September 30, 2007 and 2006.
                                 
    Three Months     Nine Months  
    Ended September 30,     Ended September 30,  
    2007     2006     2007     2006  
            (In millions)          
Earnings from discontinued operations before income taxes
  $ 177       112       442       337  
Income tax expense
    86       60       194       205  
 
                       
Earnings from discontinued operations
  $ 91       52       248       132  
 
                       
     Earnings from discontinued operations increased $39 million in the third quarter of 2007 primarily due to the net effect of the following factors. First, pursuant to accounting rules for discontinued operations, we ceased recording DD&A in November 2006 for our Egypt property and equipment and in January 2007 for our West Africa property and equipment. During the third quarter of 2006, we recorded $57 million of DD&A associated with these properties. Second, as a result of unsuccessful exploratory activities in Egypt during 2005 and 2006, the net book value of our Egyptian oil and gas properties, less related deferred income taxes, exceeded the calculated full cost ceiling by $18 million as of September 30, 2006. Therefore, in the third quarter of 2006, we recognized a $31 million reduction of the book value of our oil and gas properties in Egypt, offset by a $13 million deferred income tax benefit. The after-tax increase in earnings caused by these factors was partially offset by a decrease due to a decline in production.
     Earnings from discontinued operations increased $116 million in the first nine months of 2007 primarily due to the net effect of the following factors. First, during the first nine months of 2006, we recorded $187 million of DD&A associated with our Egypt and West Africa properties. In addition, due to unsuccessful drilling activities in Nigeria, in the first quarter of 2006, we recognized an $85 million impairment of our investment in Nigeria equal to the costs to drill two dry holes and a proportionate share of block-related costs. There was no income tax benefit related to this impairment. The after-tax increase in earnings caused by these factors was partially offset by a

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decrease due to a decline in production. Additionally, based on recent drilling activities in Nigeria, we reduced the carrying value of our Nigerian assets held for sale in the second quarter of 2007. As a result, earnings from discontinued operations in the first nine months of 2007 include a $13 million after-tax loss ($64 million pre-tax).
Capital Resources, Uses and Liquidity
     The following discussion of liquidity and capital resources should be read in conjunction with the consolidated statements of cash flows included in Part 1, Item 1.
Sources and Uses of Cash
                 
    Nine Months Ended September 30,  
    2007     2006  
    (In millions)  
Sources of cash and cash equivalents:
               
Operating cash flow – continuing operations
  $ 4,739       4,413  
Net commercial paper borrowings
          1,439  
Net credit facility borrowings
    400        
Sales of property and equipment
    39       36  
Stock option exercises
    71       53  
Net decrease in short-term investments
    233       556  
Other
    20       14  
 
           
Total sources of cash and cash equivalents
    5,502       6,511  
 
           
 
               
Uses of cash and cash equivalents:
               
Capital expenditures
    (4,477 )     (5,959 )
Net commercial paper repayments
    (129 )      
Debt repayments
    (166 )     (860 )
Repurchases of common stock
    (133 )     (253 )
Dividends
    (193 )     (155 )
 
           
Total uses of cash and cash equivalents
    (5,098 )     (7,227 )
 
           
 
               
Increase (decrease) from continuing operations
    404       (716 )
Increase from discontinued operations
    217       282  
Effect of foreign exchange rates
    44       24  
 
           
Net increase (decrease) in cash and cash equivalents
  $ 665       (410 )
 
           
 
               
Cash and cash equivalents at end of period
  $ 1,421       1,196  
 
           
Short-term investments at end of period
  $ 341       124  
 
           
Operating Cash Flow – Continuing Operations
     Net cash provided by operating activities (“operating cash flow”) continued to be the primary source of capital and liquidity in the first nine months of 2007. Changes in operating cash flow are largely due to the same factors that affect our net earnings, with the exception of those earnings changes due to such noncash expenses as DD&A, financial instrument fair value changes, property impairments and deferred income tax expense. As a result, our operating cash flow increased in 2007 primarily due to the increase in earnings as discussed in the “Results of Operations” section of this report.
     Additionally, during 2007 and 2006, operating cash flow was primarily used to fund our capital expenditures. Excluding the June 2006 $2.0 billion Chief acquisition, our operating cash flow was sufficient to fund our 2007 and 2006 capital expenditures.

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Other Sources of Cash
     As needed, we utilize cash on hand and access our available credit under our credit facilities and commercial paper program as sources of cash to supplement our operating cash flow. Additionally, we invest in highly liquid, short-term investments to maximize our income on available cash balances. As needed, we may reduce such short-term investment balances to further supplement our operating cash flow.
     During 2007, we borrowed $0.4 billion under our unsecured revolving line of credit and reduced our short-term investment balances by $0.2 billion. These sources of cash combined with our operating cash flow in excess of capital expenditures were primarily used to fund long-term debt repayments, net commercial paper repayments, common stock repurchases and dividends on common and preferred stock.
     As of September 30, 2007, our credit facility borrowings had an average interest rate of 5.85% and our commercial paper borrowings had an average interest rate of 5.66%.
     During 2006, we borrowed $1.4 billion under our commercial paper program and reduced our short-term investment balances by $0.6 billion. These sources of cash were largely used to fund the $2.0 billion acquisition of Chief in June 2006. Also during 2006, we supplemented operating cash flow with cash on hand. Our operating cash flow in excess of capital expenditures, excluding Chief, and cash on hand were primarily used to fund scheduled long-term debt maturities, common stock repurchases and dividends on common and preferred stock.
Capital Expenditures
     Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling or development of oil and gas properties, which totaled $4.1 billion and $5.7 billion in the first nine months of 2007 and 2006, respectively. The 2006 capital expenditures include $2.0 billion related to the acquisition of the Chief properties. Excluding the Chief acquisition, the increase in such capital expenditures is primarily due to an increase in drilling and development in the Barnett Shale field in north Texas. Additionally, capital expenditures also increased from our properties in Azerbaijan where we achieved payout of certain carried interests in the last half of 2006.
     Our capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas pipeline systems and oil pipelines. These midstream facilities exist primarily to support our oil and gas development operations. Such expenditures were $254 million and $228 million in the first nine months of 2007 and 2006, respectively. The majority of our 2007 and 2006 expenditures related to development activities in the Barnett Shale, the Woodford Shale in eastern Oklahoma and Jackfish in Canada.
Debt Repayments
     During the third quarter of 2007, certain holders of exchangeable debentures exercised their option to convert their debentures prior to the August 15, 2008 maturity date. We have the option to settle conversions of the exchangeable debentures with either shares of Chevron common stock or cash equal to the market value of Chevron common stock at the time of conversion. We paid $166 million in cash to settle the conversions in the third quarter of 2007.
     During 2006, we retired the $500 million 2.75% notes and the $178 million ($200 million Canadian) 6.55% debt on their scheduled maturity dates. We also repaid $180 million of debt acquired in the Chief acquisition.
Repurchases of Common Stock
     On June 6, 2007, our Board of Directors approved an ongoing, annual stock repurchase program to offset dilution resulting from restricted stock issued to, and options exercised by, employees. The new repurchase program authorizes the repurchase of up to 4.5 million shares in 2007 and is in addition to our 50 million share repurchase program approved in August 2005.

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     During the first nine months of 2007, we repurchased 1.8 million shares at a cost of $136 million under the program authorized in June 2007. Included in the $136 million is $3 million for unsettled purchases as of September 30, 2007. During the first nine months of 2006, we repurchased 4.2 million shares at a cost of $253 million under the program authorized in August 2005.
Dividends
     Our common stock dividends were $186 million and $148 million in the first nine months of 2007 and 2006, respectively. We also paid $7 million of preferred stock dividends in 2007 and 2006. The 2007 increase in common stock dividends was primarily related to a 25% increase in the quarterly dividend rate in the first quarter of 2007.
Liquidity
     Our primary source of capital and liquidity has been our operating cash flow. Additionally, we maintain revolving lines of credit and a commercial paper program which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include cash and short-term investments on hand and the issuance of equity securities and long-term debt. Another major source of near-term liquidity will be proceeds from the sales of our operations in Egypt and West Africa.
Operating Cash Flow
     We expect operating cash flow to continue to be our primary source of liquidity. Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs produced. To mitigate some of the risk inherent in prices, we have utilized price collars to set minimum and maximum prices on a portion of our production. We have also utilized various price swap contracts and fixed-price physical delivery contracts. Based on contracts currently in place, approximately 5% of our estimated 2007 natural gas production from continuing operations (3% of our total oil, gas and NGL production from continuing operations) is subject to either price collars, swaps or fixed-price contracts.
Credit Lines
     In April 2007, we extended the maturity of our existing $2.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) from April 7, 2011 to April 7, 2012.
     The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. As of September 30, 2007, we were in compliance with this covenant. Our debt-to-capitalization ratio at September 30, 2007, as calculated pursuant to the terms of the agreement, was 24.8%.
     On August 7, 2007, we established a new $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility (the “Short-Term Facility”). This new facility provides us with provisional interim liquidity until we receive the proceeds from divestitures of assets in Africa. The Short-Term Facility was also used to support an increase in our commercial paper program from $2 billion to $3.5 billion.
     The Short-Term Facility matures 364 days from the closing date. On the maturity date, all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to the maturity date, we have the option to convert any outstanding principal amount of loans under the Short-Term Facility to a term loan which will be repayable in a single payment 364 days from the maturity date.
     Amounts borrowed under the Short-Term Facility bear interest at various fixed rate options for periods of up to 12 months. Such rates are generally less than the prime rate. We may also elect to borrow at the prime rate. The Short-Term Facility currently provides for an annual facility fee of approximately $1.0 million that is payable quarterly in arrears.

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     The agreement governing the Short-Term Facility contains substantially the same covenants and restrictions as our existing Senior Credit Facility, including a maximum allowed debt-to-capitalization ratio of 65% as defined in the agreement.
     As of September 30, 2007, our combined available capacity under these credit facilities was $1.6 billion.
Debt Ratings
     During September 2007, our senior unsecured long term debt rating was upgraded by Moody’s from Baa2 to Baa1 with a stable outlook. This upgrade was primarily due to improved organic reserves replacement, production growth and reduced leverage. We are not aware of any potential downgrades contemplated by the rating agencies as of September 30, 2007.
Exchangeable Debentures
     As of September 30, 2007, our outstanding debt includes Chevron exchangeable debentures with a scheduled maturity date of August 15, 2008. Although these debentures are now due within one year, we continue to classify this debt as long-term because we have the intent and ability to refinance these debentures on a long-term basis with the available capacity under our existing credit facilities or other long-term financing arrangements.
Canadian Royalties
     On October 25, 2007, the Alberta government proposed increases to the royalty rates on oil and natural gas production beginning in 2009. We believe this proposal would reduce future earnings and cash flows from our oil and gas properties located in Alberta. Additionally, assuming all other factors are equal, higher royalty rates would likely result in lower levels of capital investment in Alberta relative to our other areas of operation. However, the magnitude of the potential impact, which will depend on the final form of enacted legislation and other factors which impact the relative expected economic returns of capital projects, cannot be reasonably estimated at this time.
Master Limited Partnership
     We announced on July 18, 2007 our plan to form a new, publicly traded master limited partnership (“MLP”). The proposed MLP was expected to initially own a minority interest in our U.S. onshore marketing and midstream business. On November 7, 2007, we announced that we had decided not to proceed at this time with our plans to form this MLP. This decision was based primarily on a change in public market conditions for MLPs and other yield-driven investments subsequent to our announcement of the proposed MLP.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
     There have been no material changes to the information included in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” in our 2006 Annual Report on Form 10-K.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
     We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.
     Based on their evaluation, Devon’s principal executive and principal financial officers have concluded that Devon’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities

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Exchange Act of 1934) were effective as of September 30, 2007 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Changes in Internal Control Over Financial Reporting
     There was no change in Devon’s internal control over financial reporting during the third quarter of 2007 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.

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Part II. Other Information
Item 1. Legal Proceedings
     There have been no material changes to the information included in Item 3. “Legal Proceedings” in our 2006 Annual Report on Form 10-K.
Item 1A. Risk Factors
     There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2006 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
                                 
    Total             Total Number of     Maximum Number of  
    Number of     Average Price     Shares Purchased as     Shares that May Yet Be  
    Shares     Paid per     Part of Publicly Announced     Purchased Under the  
           Period   Purchased     Share     Plans or Programs(1)     Plans or Programs(1)  
July
    527,300     $ 78.58       527,300       47,304,901  
August
    669,300     $ 75.12       669,300       46,635,601  
September
    361,500     $ 79.83       361,500       46,274,101  
 
                           
Total
    1,558,100     $ 77.38       1,558,100          
 
                           
 
(1)   In August 2005, Devon’s Board of Directors approved a stock repurchase program to repurchase up to 50 million shares of Devon’s common stock. This program was suspended in 2006 as a result of the Chief acquisition. As of September 30, 2007, there were still 43,533,001 shares available for purchase under this program. On June 6, 2007, Devon’s Board of Directors approved an ongoing, annual stock repurchase program to offset dilution resulting from restricted stock issued to, and options exercised by, employees. The new repurchase program authorizes the repurchase of up to 4.5 million shares in 2007 and is in addition to the 50 million share repurchase program that was authorized in August 2005. The shares purchased in the third quarter relate to the program authorized in June 2007.
Item 3. Defaults Upon Senior Securities
     None
Item 4. Submission of Matters to a Vote of Security Holders
     None
Item 5. Other Information
     None

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Item 6. Exhibits
     (a) Exhibits required by Item 601 of Regulation S-K are as follows:
     
Exhibit    
Number   Description
10.1
  Credit Agreement dated as of August 7, 2007 among Registrant as Borrower, Bank of America, N.A. as Administrative Agent, JPMorgan Chase Bank, N.A. as Syndication Agent, and The Other Lenders Party Hereto, Banc of America Securities LLC and J.P. Morgan Securities, Inc. as Joint Lead Arrangers and Book Managers for the $1.5 Billion Senior Credit Facility (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 9, 2007).
 
   
10.2
  First Amendment to Amended and Restated Credit Agreement dated as of June 1, 2006, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party to this Amendment.
 
   
10.3
  Second Amendment to Amended and Restated Credit Agreement dated as of September 19, 2007, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party to this Amendment.
 
   
31.1
  Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2
  Certification of Danny J. Heatly, Vice President – Accounting and Chief Accounting Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1
  Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
32.2
  Certification of Danny J. Heatly, Vice President – Accounting and Chief Accounting Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  DEVON ENERGY CORPORATION
 
 
Date: November 7, 2007  /s/ Danny J. Heatly    
  Danny J. Heatly   
  Vice President – Accounting and Chief Accounting Officer  

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INDEX TO EXHIBITS
     
Exhibit    
Number   Description
10.1
  Credit Agreement dated as of August 7, 2007 among Registrant as Borrower, Bank of America, N.A. as Administrative Agent, JPMorgan Chase Bank, N.A. as Syndication Agent, and The Other Lenders Party Hereto, Banc of America Securities LLC and J.P. Morgan Securities, Inc. as Joint Lead Arrangers and Book Managers for the $1.5 Billion Senior Credit Facility (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on August 9, 2007).
 
   
10.2
  First Amendment to Amended and Restated Credit Agreement dated as of June 1, 2006, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party to this Amendment.
 
   
10.3
  Second Amendment to Amended and Restated Credit Agreement dated as of September 19, 2007, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party to this Amendment.
 
   
31.1
  Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2
  Certification of Danny J. Heatly, Vice President – Accounting and Chief Accounting Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1
  Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
32.2
  Certification of Danny J. Heatly, Vice President – Accounting and Chief Accounting Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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