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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 June 30, 2008
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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large accelerated filer þ    Accelerated filer o    Non-accelerated filer   o
(Do not check if a smaller reporting company)
  Smaller Reporting Company 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
     As of July 31, 2008, 441.8 million shares of the registrant’s common stock were outstanding.
 
 

 


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DEVON ENERGY CORPORATION
INDEX TO FORM 10-Q QUARTERLY REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION
         
 
       
    4  
 
       
    5  
 
       
    6  
 
       
    6  
    6  
    7  
    8  
    9  
    10  
    11  
    27  
    42  
    43  
 
       
    44  
 
       
    44  
    44  
    44  
    44  
    44  
    45  
    46  
 
       
    46  
 Registrant's Certificate of Amendment of Restated Certificate of Incorporation
 Form of Amendment to Nonqualified Stock Option Award Agreements
 Form of Amendment to Restricted Stock Award Agreements
 Form of Non-Management Director Nonqualified Stock Option Award Agreement
 Form of Non-Management Director Restricted Stock Award Agreement
 Certification of J. Larry Nichols, Chief Executive Officer Pursuant to Section 302
 Certification of Danny J. Heatly, Vice President - Accounting and Chief Accounting Officer Pursuant to Section 302
 Certification of J. Larry Nichols, Chief Executive Officer Pursuant to Section 906
 Certification of Danny J. Heatly, Vice President - Accounting and Chief Accounting Officer Pursuant to Section 906

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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
     This report 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 that was used to prepare the December 31, 2007 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 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 production, and portions of 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, particularly the Canadian-to-U.S. dollar exchange rate;
 
    the weather;
 
    inflation;
 
    the availability of goods and services;
 
    drilling risks;
 
    future processing volumes and pipeline throughput;
 
    general economic conditions, whether internationally, 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 related risks such as general credit, liquidity, market and interest-rate risks; and
 
    other factors disclosed in Devon’s 2007 Annual Report on Form 10-K/A 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.
     “Btu” means British thermal units, a measure of heating value.
     “Federal Funds Rate” means the interest rate that financial institutions charge each other for the use of United States Treasury funds.
     “Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
     “LIBOR” means London Interbank Offered Rate.
     “Mcf” means thousand cubic feet.
     “MMBbls” means million barrels.
     “MMBoe” means million Boe.
     “MMBtu” means million Btu.
     “Oil” includes crude oil and condensate.
     “NGL” or “NGLs” means natural gas liquids.
     “NYMEX” means New York Mercantile Exchange.
     “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.
     “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
                 
    June 30,     December 31,  
    2008     2007  
    (Unaudited)          
    (In millions)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 1,837     $ 1,364  
Short-term investments, at fair value
    1       372  
Accounts receivable
    2,460       1,779  
Deferred income taxes
    775       44  
Current assets held for sale
    105       120  
Other current assets
    255       235  
 
           
Total current assets
    5,433       3,914  
 
           
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($3,741 and $3,417 excluded from amortization in 2008 and 2007, respectively)
    51,953       48,473  
Less accumulated depreciation, depletion and amortization
    21,769       20,394  
 
           
 
    30,184       28,079  
Investment in Chevron Corporation common stock, at fair value
    1,406       1,324  
Goodwill
    6,081       6,172  
Long-term assets held for sale
    84       1,512  
Other long-term assets, including $126 million at fair value in 2008
    592       455  
 
           
Total assets
  $ 43,780     $ 41,456  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable – trade
  $ 1,525     $ 1,360  
Revenues and royalties due to others
    966       578  
Income taxes payable
    306       97  
Debentures exchangeable into shares of Chevron Corporation common stock
    621        
Other short-term debt
          1,004  
Derivative financial instruments, at fair value
    2,125        
Current portion of asset retirement obligation, at fair value
    63       82  
Current liabilities associated with assets held for sale
    16       145  
Accrued expenses and other current liabilities
    410       391  
 
           
Total current liabilities
    6,032       3,657  
 
           
Debentures exchangeable into shares of Chevron Corporation common stock
          641  
Other long-term debt
    4,829       6,283  
Derivative financial instruments, at fair value
    83       488  
Asset retirement obligation, at fair value
    1,430       1,236  
Long-term liabilities associated with assets held for sale
    24       404  
Other long-term liabilities
    905       699  
Deferred income taxes
    7,044       6,042  
Stockholders’ equity:
               
Preferred stock of $1.00 par value. Authorized 4.5 million shares; issued 1.5 million shares ($150 million aggregate liquidation value) in 2007
          1  
Common stock of $0.10 par value. Authorized 1.0 billion shares; issued 444.9 million and 444.2 million shares in 2008 and 2007, respectively
    44       44  
Additional paid-in capital
    6,591       6,743  
Retained earnings
    14,717       12,813  
Accumulated other comprehensive income
    2,131       2,405  
Treasury stock, at cost. 0.4 million shares in 2008
    (50 )      
 
           
Total stockholders’ equity
    23,433       22,006  
 
           
Commitments and contingencies (Note 8)
               
Total liabilities and stockholders’ equity
  $ 43,780     $ 41,456  
 
           
See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2008     2007     2008     2007  
    (Unaudited)  
    (In millions, except per share amounts)  
Revenues:
                               
Oil sales
  $ 1,455     $ 865     $ 2,705     $ 1,556  
Gas sales
    2,210       1,366       3,840       2,612  
NGL sales
    379       224       707       401  
Net (loss) gain on oil and gas derivative financial instruments
    (1,215 )     14       (2,003 )     (6 )
Marketing and midstream revenues
    719       460       1,274       839  
 
                       
Total revenues
    3,548       2,929       6,523       5,402  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    537       439       1,043       869  
Production taxes
    176       90       310       170  
Marketing and midstream operating costs and expenses
    515       341       897       611  
Depreciation, depletion and amortization of oil and gas properties
    762       645       1,499       1,232  
Depreciation and amortization of non-oil and gas properties
    62       49       119       95  
Accretion of asset retirement obligation
    22       18       44       36  
General and administrative expenses
    180       113       328       232  
Interest expense
    90       107       192       217  
Change in fair value of non-oil and gas derivative financial instruments
    (40 )     (10 )     (24 )     (9 )
Other income, net
    (17 )     (17 )     (38 )     (43 )
 
                       
Total expenses and other income, net
    2,287       1,775       4,370       3,410  
Earnings from continuing operations before income tax expense
    1,261       1,154       2,153       1,992  
Income tax expense:
                               
Current
    414       174       517       363  
Deferred
    253       156       391       231  
 
                       
Total income tax expense
    667       330       908       594  
 
                       
Earnings from continuing operations
    594       824       1,245       1,398  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
    851       128       1,040       265  
Income tax expense
    144       48       235       108  
 
                       
Earnings from discontinued operations
    707       80       805       157  
 
                       
Net earnings
    1,301       904       2,050       1,555  
Preferred stock dividends
    3       3       5       5  
 
                       
Net earnings applicable to common stockholders
  $ 1,298     $ 901     $ 2,045     $ 1,550  
 
                       
 
                               
Basic net earnings per share:
                               
Earnings from continuing operations
  $ 1.33     $ 1.84     $ 2.79     $ 3.13  
Earnings from discontinued operations
    1.58       0.18       1.80       0.35  
 
                       
Net earnings
  $ 2.91     $ 2.02     $ 4.59     $ 3.48  
 
                       
 
                               
Diluted net earnings per share:
                               
Earnings from continuing operations
  $ 1.31     $ 1.82     $ 2.76     $ 3.09  
Earnings from discontinued operations
    1.57       0.18       1.79       0.35  
 
                       
Net earnings
  $ 2.88     $ 2.00     $ 4.55     $ 3.44  
 
                       
 
                               
Weighted average common shares outstanding:
                               
Basic
    446       446       445       445  
 
                       
Diluted
    450       450       450       450  
 
                       
See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2008     2007     2008     2007  
    (Unaudited)  
    (In millions)  
Net earnings
  $ 1,301     $ 904     $ 2,050     $ 1,555  
Foreign currency translation:
                               
Change in cumulative translation adjustment
    88       649       (294 )     732  
Income tax benefit (expense)
    (3 )     (35 )     14       (41 )
 
                       
Total
    85       614       (280 )     691  
 
                       
Pension and postretirement benefit plans:
                               
Recognition of net actuarial loss and prior service cost in net earnings
    4       4       9       8  
Income tax expense
    (1 )     (2 )     (3 )     (3 )
 
                       
Total
    3       2       6       5  
 
                       
Other
                      (1 )
 
                       
Other comprehensive income (loss), net of tax
    88       616       (274 )     695  
 
                       
Comprehensive income
  $ 1,389     $ 1,520     $ 1,776     $ 2,250  
 
                       
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)  
Six Months Ended June 30, 2008:
                                                               
Balance as of December 31, 2007
  $ 1       444     $ 44     $ 6,743     $ 12,813     $ 2,405     $     $ 22,006  
Net earnings
                            2,050                   2,050  
Other comprehensive loss
                                  (274 )           (274 )
Stock option exercises
          4       1       107                   (4 )     104  
Common stock repurchased
                                        (316 )     (316 )
Common stock retired
          (3 )     (1 )     (269 )                 270        
Redemption of preferred stock
    (1 )                 (149 )                       (150 )
Common stock dividends
                            (141 )                 (141 )
Preferred stock dividends
                            (5 )                 (5 )
Share-based compensation
                      104                         104  
Excess tax benefits on share-based compensation
                      55                         55  
 
                                               
Balance as of June 30, 2008
  $       445     $ 44     $ 6,591     $ 14,717     $ 2,131     $ (50 )   $ 23,433  
 
                                               
 
                                                               
Six Months Ended June 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
                            364       (364 )            
Adoption of FASB Interpretation No. 48
                            (10 )                 (10 )
Adoption of FASB Statement No. 158
                            (1 )     16             15  
Net earnings
                            1,555                   1,555  
Other comprehensive income
                                  695             695  
Stock option exercises
          2       1       59                         60  
Common stock repurchased
                                        (16 )     (16 )
Common stock retired
                      (17 )                 17        
Common stock dividends
                            (124 )                 (124 )
Preferred stock dividends
                            (5 )                 (5 )
Share-based compensation
                      57                         57  
Excess tax benefits on share-based compensation
                      17                         17  
 
                                               
Balance as of June 30, 2007
  $ 1       446     $ 45     $ 6,956     $ 10,893     $ 1,791     $     $ 19,686  
 
                                               
See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
                 
    Six Months  
    Ended June 30,  
    2008     2007  
    (Unaudited)  
    (In millions)  
Cash flows from operating activities:
               
Net earnings
  $ 2,050     $ 1,555  
Earnings from discontinued operations, net of tax
    (805 )     (157 )
Adjustments to reconcile earnings from continuing operations to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    1,618       1,327  
Deferred income tax expense
    391       231  
Net unrealized loss on oil and gas derivative financial instruments
    1,692       23  
Other noncash charges
    122       71  
(Increase) decrease in assets:
               
Accounts receivable
    (604 )     32  
Other current assets
    (44 )     (27 )
Other long-term assets
    (40 )     (46 )
Increase (decrease) in liabilities:
               
Accounts payable
    120       64  
Revenues and royalties due to others
    348       (17 )
Income taxes payable
    136       178  
Other current liabilities
    (99 )     (96 )
Other long-term liabilities
    181       14  
 
           
Cash provided by operating activities – continuing operations
    5,066       3,152  
Cash provided by operating activities – discontinued operations
    120       197  
 
           
Net cash provided by operating activities
    5,186       3,349  
 
           
 
               
Cash flows from investing activities:
               
Proceeds from sales of property and equipment
    108       37  
Capital expenditures
    (3,867 )     (2,990 )
Purchases of short-term investments
    (50 )     (589 )
Redemptions of short-term and long-term investments
    295       848  
 
           
Cash used in investing activities – continuing operations
    (3,514 )     (2,694 )
Cash provided by (used in) investing activities – discontinued operations
    1,709       (115 )
 
           
Net cash used in investing activities
    (1,805 )     (2,809 )
 
           
 
               
Cash flows from financing activities:
               
Credit facility repayments
    (3,070 )      
Credit facility borrowings
    1,620        
Net commercial paper repayments
    (1,004 )     (183 )
Principal payments on debt
    (47 )      
Preferred stock redemption
    (150 )      
Proceeds from stock option exercises
    104       60  
Repurchases of common stock
    (252 )     (10 )
Dividends paid on common and preferred stock
    (146 )     (129 )
Excess tax benefits related to share-based compensation
    55       17  
 
           
Net cash used in financing activities
    (2,890 )     (245 )
 
           
Effect of exchange rate changes on cash
    (19 )     16  
 
           
Net increase in cash and cash equivalents
    472       311  
Cash and cash equivalents at beginning of period (including cash related to assets held for sale)
    1,373       756  
 
           
Cash and cash equivalents at end of period (including cash related to assets held for sale)
  $ 1,845     $ 1,067  
 
           
Supplementary cash flow data:
               
Interest paid (net of capitalized interest)
  $ 189     $ 202  
Income taxes paid – continuing and discontinued operations
  $ 826     $ 159  
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 unaudited consolidated financial statements and notes of Devon Energy Corporation (“Devon”) have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission. Pursuant to such rules and regulations, 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 should be read in conjunction with the consolidated financial statements and notes included in Devon’s 2007 Annual Report on Form 10-K/A.
     The unaudited interim consolidated financial statements furnished in this report reflect all adjustments which are, in the opinion of management, necessary to a fair statement of Devon’s financial position as of June 30, 2008 and Devon’s results of operations and cash flows for the three-month and six-month periods ended June 30, 2008 and 2007. Except for the reclassification of auction rate securities discussed below, all such adjustments are of a normal recurring nature.
Reclassification of Auction Rate Securities
     At December 31, 2007, Devon held $372 million of auction rate securities. Such securities are rated AAA—the highest rating—by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. Although Devon’s auction rate securities generally have contractual maturities of more than 20 years, the underlying interest rates on such securities are scheduled to reset every seven to 28 days. Therefore, these auction rate securities were generally priced and subsequently traded as short-term investments because of the interest rate reset feature. As a result, Devon classified its auction rate securities as short-term investments in the accompanying December 31, 2007 consolidated balance sheet and in prior periods.
     During the first half of 2008, Devon reduced its auction rate securities holdings to $127 million. However, since February 8, 2008 Devon has experienced difficulty selling its securities due to the failure of the auction mechanism, which provides liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature.
     From February 2008, when auctions began failing, to June 30, 2008, issuers redeemed $26 million of Devon’s auction rate securities holdings at par. Additionally, Devon’s auction rate securities holdings as of June 30, 2008 include approximately $1 million of securities that were called at par value by the issuer and were repaid on July 10, 2008. These called securities are classified as short-term investments in the accompanying June 30, 2008 consolidated balance sheet. However, based on continued auction failures and the current market for Devon’s auction rate securities, Devon has classified the $126 million of securities that have not been called as of June 30, 2008 as long-term investments. These securities are included in other long-term assets in the accompanying June 30, 2008 consolidated balance sheet. Devon has the ability to hold the securities until maturity. At this time, Devon does not believe the values of its long-term securities are impaired.
Recently Issued Accounting Standards Not Yet Adopted
     In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 141(R), Business Combinations, which replaces Statement No. 141. Statement No. 141(R) retains the fundamental requirements of Statement No. 141 that an acquirer be identified and the acquisition method of accounting (previously called the purchase method) be used for all business combinations. Statement No. 141(R)’s scope is broader than that of Statement No. 141, which applied only to business combinations in which control was obtained by transferring consideration. By applying the acquisition method to all transactions and other events in which one entity obtains control over one or more other businesses, Statement No. 141(R) improves the comparability of the information about business combinations provided in financial reports. Statement No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures identifiable assets acquired, liabilities assumed and any noncontrolling interest in the acquiree, as well as any resulting goodwill. Statement No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Devon will evaluate how the new requirements of Statement No. 141(R) would impact any business combinations completed in 2009 or thereafter.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
     In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin No. 51. A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. Statement No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Under Statement No. 160, noncontrolling interests in a subsidiary must be reported as a component of consolidated equity separate from the parent’s equity. Additionally, the amounts of consolidated net income attributable to both the parent and the noncontrolling interest must be reported separately on the face of the income statement. Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008 and earlier adoption is prohibited. Devon does not expect the adoption of Statement No. 160 to have a material impact on its financial statements and related disclosures.
     In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. Statement No. 161 requires additional disclosures about derivative and hedging activities and is effective for fiscal years and interim periods beginning after November 15, 2008. Devon is evaluating the impact the adoption of Statement No. 161 will have on its financial statement disclosures. However, Devon’s adoption of Statement No. 161 will not affect its current accounting for derivative and hedging activities.
2. Property and Equipment and Asset Retirement Obligations
Divestitures
     Near the beginning of 2007, Devon announced plans to sell its assets and terminate its operations located in Africa. This divestiture package consisted primarily of Devon’s operations located in Egypt and the West African countries of Equatorial Guinea, Gabon and Cote D’Ivoire. Additional information regarding Devon’s Egyptian and West African operations, which are presented as discontinued in the accompanying financial statements, is provided in Note 12.
Asset Retirement Obligations (“ARO”)
     The following is a summary of the changes in Devon’s ARO for the first six months of 2008 and 2007.
                 
    Six Months  
    Ended June 30,  
    2008     2007  
    (In millions)  
Asset retirement obligation as of beginning of period
  $ 1,318     $ 857  
Liabilities incurred
    29       32  
Liabilities settled
    (40 )     (24 )
Revision of estimated obligation
    162       311  
Accretion expense on discounted obligation
    44       36  
Foreign currency translation adjustment
    (20 )     47  
 
           
Asset retirement obligation as of end of period
    1,493       1,259  
Less current portion
    63       45  
 
           
Asset retirement obligation, long-term
  $ 1,430     $ 1,214  
 
           
     During the first six months of 2008 and 2007, Devon recognized increases of $162 million and $311 million, respectively, to its ARO. The primary factors causing the 2008 fair value increase were an overall increase in abandonment cost estimates and the effect of a decrease in the discount rate used to present value the obligations. 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.
3. Commodity Derivative Financial Instruments
     Devon periodically enters into derivative financial instruments with respect to a portion of its oil and gas production that hedge the future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to oil and gas price volatility. Devon’s derivative financial instruments include financial price swaps, whereby Devon will receive a fixed price for its production and pay a variable market price to the contract counterparty, and costless price collars that set a floor and ceiling price for

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars.
     As discussed more fully in Note 1 to the consolidated financial statements in Devon’s 2007 Annual Report on Form 10-K/A, Devon’s derivative financial instruments are recognized at the current fair value on the balance sheet. Unrealized changes in such fair values are recorded in the statement of operations. Cash settlements with counterparties to Devon’s price swaps and price collars are also recorded in the statement of operations.
     The following tables present the fair values included in the accompanying balance sheet and the cash settlements and net unrealized losses included in the accompanying statement of operations associated with Devon’s commodity derivative financial instruments.
                 
    June 30, 2008     December 31, 2007  
    (In millions)  
Fair values:
               
Other current assets – gas price swaps
  $     $ 12  
Derivative financial instruments, current liability:
               
Gas price swaps
  $ 606     $  
Gas price collars
    945        
Oil price collars
    46        
 
           
Total derivative financial instruments, current liability
  $ 1,597     $  
 
           
Derivative financial instruments, long-term liability:
               
Gas price swaps
  $     $  
Gas price collars
    83        
Oil price collars
           
 
           
Total derivative financial instruments, long-term liability
  $ 83     $  
 
           
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2008     2007     2008     2007  
    (In millions)  
Cash settlements:
                               
Gas price swaps
  $ (153 )   $ 5     $ (161 )   $ 15  
Gas price collars
    (150 )           (150 )     2  
 
                       
Total cash settlements (paid) received
    (303 )     5       (311 )     17  
 
                       
Unrealized (losses) gains on fair value changes:
                               
Gas price swaps
    (247 )     9       (618 )     (19 )
Gas price collars
    (620 )           (1,028 )     (4 )
Oil price collars
    (45 )           (46 )      
 
                       
Total unrealized (losses) gains on fair value changes
    (912 )     9       (1,692 )     (23 )
 
                       
Net (loss) gain on oil and gas derivative financial instruments
  $ (1,215 )   $ 14     $ (2,003 )   $ (6 )
 
                       
4. Debt
Credit Facilities
     In April 2008, Devon extended the maturity of $2.0 billion of its existing $2.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
Facility”) from April 7, 2012 to April 7, 2013. Lenders representing $0.5 billion of the Senior Credit Facility did not approve a maturity date extension. Therefore, the maturity date for $0.5 billion of the Senior Credit Facility remains at April 7, 2012.
     During the second quarter of 2008, Devon repaid $2.5 billion of outstanding commercial paper and Senior Credit Facility borrowings primarily with proceeds received from the sales of assets in West Africa and cash generated from operations.
     On August 7, 2007, Devon established a $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility (the “Short-Term Facility”). This facility matured on August 5, 2008 and was not extended. As a result of the Short-Term Facility’s maturity, Devon’s commercial paper program capacity decreased from $3.5 billion to $2.0 billion.
     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 June 30, 2008, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at June 30, 2008, as calculated pursuant to the terms of the agreement, was 16.3%.
     As of August 5, 2008, Devon’s available capacity under its Senior Credit Facility was approximately $2.4 billion. This available capacity is net of $140 million of outstanding letters of credit. There were no outstanding commercial paper or Senior Credit Facility borrowings as of August 5, 2008.
Exchangeable Debentures
     During the first six months of 2008, certain holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron Corporation (“Chevron”) common stock that Devon owns prior to the debentures’ August 15, 2008 maturity date. In lieu of delivering Chevron common stock to an exchanging debenture holder, Devon may, at its option, pay to such holder an amount of cash equal to the market value of Chevron common stock. During the first half of 2008, Devon elected to pay the exchanging debenture holders cash totaling $47 million in lieu of delivering shares of Chevron common stock. As a result of these exchanges, Devon retired outstanding exchangeable debentures with a book value totaling $28 million and reduced the related embedded derivative option’s balance by $19 million.
     As of June 30, 2008, Devon has classified the exchangeable debentures as short-term borrowings in the accompanying consolidated balance sheet. Although the exchangeable debentures have been due within one year since August 15, 2007, Devon previously classified the debt as long-term borrowings. The long-term classification was based on the uncertain timing of the closings of sales of assets in West Africa, particularly the sale of assets in Equatorial Guinea. Based on the sale proceeds received during the second quarter of 2008, Devon now intends to repay the exchangeable debentures with cash on hand or short-term commercial paper borrowings.
5. Fair Value Measurements
     Certain of Devon’s assets and liabilities are reported at fair value in the accompanying balance sheets. Such assets and liabilities include amounts for both financial and nonfinancial instruments. The following tables provide fair value measurement information for such assets and liabilities as of June 30, 2008 and December 31, 2007. Following the tables, additional information is provided for those assets and liabilities in which Devon uses significant unobservable inputs (Level 3) to measure fair value.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
                                         
    As of June 30, 2008
                    Fair Value Measurements Using:
                    Quoted   Significant    
                    Prices in   Other   Significant
                    Active   Observable   Unobservable
    Carrying   Total Fair   Markets   Inputs   Inputs
    Amount   Value   (Level 1)   (Level 2)   (Level 3)
    (In millions)
Financial Assets (Liabilities):
                                       
Short-term and long-term investments
  $ 127     $ 127     $ 1     $     $ 126  
Investment in Chevron common stock
  $ 1,406     $ 1,406     $ 1,406     $     $  
Net oil and gas price swaps and collars
  $ (1,680 )   $ (1,680 )   $     $ (1,680 )   $  
Embedded option in exchangeable debentures
  $ (528 )   $ (528 )   $     $ (528 )   $  
Asset retirement obligation
  $ (1,493 )   $ (1,493 )   $     $     $ (1,493 )
                                         
    As of December 31, 2007
                    Fair Value Measurements Using:
                    Quoted   Significant    
                    Prices in   Other   Significant
                    Active   Observable   Unobservable
    Carrying   Total Fair   Markets   Inputs   Inputs
    Amount   Value   (Level 1)   (Level 2)   (Level 3)
    (In millions)
Financial Assets (Liabilities):
                                       
Short-term investments
  $ 372     $ 372     $ 372     $     $  
Investment in Chevron common stock
  $ 1,324     $ 1,324     $ 1,324     $     $  
Gas price swaps
  $ 12     $ 12     $     $ 12     $  
Embedded option in exchangeable debentures
  $ (488 )   $ (488 )   $     $ (488 )   $  
Asset retirement obligation
  $ (1,318 )   $ (1,318 )   $     $     $ (1,318 )
Level 3 Fair Value Measurements
     Short-term and long-term investments — Devon’s short-term and long-term investments presented in the tables above as of June 30, 2008 and December 31, 2007 consisted entirely of auction rate securities, which are discussed in greater detail in Note 1. As of December 31, 2007, Devon estimated the fair values of its short-term investments using quoted market prices. However, due to the auction failures discussed in Note 1 and the lack of an active market for Devon’s long-term auction rate securities, quoted market prices for the vast majority of these securities were not available as of June 30, 2008. Therefore, Devon used valuation techniques that rely on unobservable, or Level 3, inputs to estimate the fair values of its long-term auction rate securities as of June 30, 2008. These inputs were based on the AAA credit rating of the securities, the probability of full repayment of the securities considering the United States government guarantees of substantially all of the underlying student loans and the collection of all accrued interest to date. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of June 30, 2008. At this time, Devon does not believe the values of its long-term securities are impaired. Included below is a summary of the changes in Devon’s Level 3 short-term and long-term investments during the first half of 2008 (in millions).
         
Beginning balance
  $  
Transfers from Level 1 to Level 3
    129  
Redemptions of principal
    (3 )
 
     
Ending balance
  $ 126  
 
     

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
     Asset retirement obligation — The fair values of the asset retirement obligations are estimated using internal discounted cash flow calculations based upon Devon’s estimates of future retirement costs. A summary of the changes in Devon’s asset retirement obligation, including revisions of the estimated fair value in 2008 and 2007, is presented in Note 2.
6. 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 six-month periods ended June 30, 2008 and 2007.
                                                                 
    Pension Benefits     Other Postretirement Benefits  
    Three Months     Six Months     Three Months     Six Months  
    Ended June 30,     Ended June 30,     Ended June 30,     Ended June 30,  
    2008     2007     2008     2007     2008     2007     2008     2007  
    (In millions)  
Net periodic benefit cost:
                                                               
Service cost
  $ 10     $ 7     $ 20     $ 15     $     $     $     $  
Interest cost
    14       11       28       22       2       1       4       2  
Expected return on plan assets
    (13 )     (13 )     (26 )     (25 )                        
Net actuarial loss
    4       4       8       8                          
 
                                               
Net periodic benefit cost
    15       9       30       20       2       1       4       2  
Other comprehensive income:
                                                               
Recognition of net actuarial
loss in net periodic benefit cost
    (4 )     (4 )     (8 )     (8 )                        
 
                                               
Total recognized
  $ 11     $ 5     $ 22     $ 12     $ 2     $ 1     $ 4     $ 2  
 
                                               
     Devon previously disclosed in its financial statements for the year ended December 31, 2007, that it expected to contribute $8 million to the Qualified and Supplemental Plans in 2008 and $6 million to the Postretirement Plans in 2008. Devon presently anticipates contributing an additional $10 million to the Qualified and Supplemental Plans in 2008 for a total of $18 million. As of June 30, 2008, Devon has contributed $13 million to the Qualified and Supplemental Plans and $2 million to the Postretirement Plans.
7. Stockholders’ Equity
Preferred Stock Redemption
     On June 20, 2008, Devon redeemed all 1.5 million outstanding shares of its 6.49% Series A cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption price of $100 per share, plus accrued and unpaid dividends up to the redemption date.
Stock Repurchases
     During the first six months of 2008, Devon repurchased 2.8 million shares for $302 million, or $106.01 per share, under programs approved by its Board of Directors. The 2.8 million shares include 2.0 million shares that were repurchased under Devon’s 50 million share program and 0.8 million shares that were repurchased under Devon’s ongoing, annual stock repurchase program.
Dividends
     Devon paid common stock dividends of $141 million (or a quarterly rate of $0.16 per share) and $124 million (or a quarterly rate of $0.14 per share) in the first six months of 2008 and 2007, respectively. During the first half of 2008 and 2007, Devon also paid $5 million in dividends to preferred stockholders.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
8. 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.
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 NGLs 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 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. Two phases have been scheduled to date, with the first scheduled to begin in August 2008 and the second scheduled to begin in February 2009. Devon is not included in the groups of defendants selected for these first two phases. 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 with respect to this lawsuit and, therefore, no liability related to this lawsuit has been recorded.
     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. In 2006, the MMS 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 not renegotiated any of its existing leases.
     The U.S. House of Representatives in January 2007 passed legislation that would have required companies to renegotiate the 1998 and 1999 leases as a condition of securing future federal leases. This legislation was not passed by the U.S. Senate. However, Congress may consider similar legislation in the future. Although Devon has not signed renegotiated leases, it has accrued through June 30, 2008, approximately $40 million for royalties that would be due if price thresholds were added to its 1998 and 1999 leases effective October 1, 2006.
     Additionally, Devon has $35 million accrued at June 30, 2008 for royalties related to leases issued under the Deep Water Royalty Relief Act in years other than 1998 or 1999. The leases issued in these other years did include price thresholds, but in October 2007 a federal district court ruled in favor of a plaintiff who had challenged the legality of including price thresholds in these leases. This judgment is subject to appeal, and Devon will continue to accrue for royalties on these leases until the matter is resolved.
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 — (Continued)
(Unaudited)
     Certain of Devon’s subsidiaries 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 June 30, 2008, Devon’s balance sheet included $2 million of accrued liabilities, reflected in other long-term 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.
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 had 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 2006 as a full settlement of the amount due from Devon’s primary insurers and $13 million received in 2007 as a full settlement of the amount due from certain of Devon’s secondary insurers. As of June 30, 2008, $388 million of these proceeds had been utilized as reimbursement of past repair costs and deductible amounts. The remaining proceeds of $92 million are expected to be utilized as reimbursement of Devon’s anticipated future repair costs. Devon continues to negotiate with its other secondary insurers and expects to receive additional policy recoveries as a result of such negotiations.
     Should Devon’s total policy recoveries, including the partial 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. Devon’s current insurance program includes business interruption and physical damage coverage for its business. However, due to significant changes in the insurance marketplace, Devon no longer has coverage for damage that may be caused by named windstorms in the Gulf of Mexico.
Other Matters
     Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge as of the date of this report, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
9. Share-Based Compensation
     With the approval of Devon’s Compensation Committee, Devon modified the share-based compensation arrangements for certain members of senior management (“executives”) in the second quarter of 2008. The modified compensation arrangements provide that executives who meet certain years-of-service and age criteria can retire and continue vesting in outstanding share-based grants. As a condition to receiving the benefits of these modifications, the executives must agree not to use or disclose Devon’s confidential information and not to solicit Devon’s employees and customers. The executives are required to agree to these conditions at retirement and again in each subsequent year until all grants have vested.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
     This modification results in accelerated expense recognition as executives approach the years-of-service and age criteria. Additionally, when the modification was made in the second quarter of 2008, certain executives had already met the years-of-service and age criteria. As a result, Devon recognized an additional $27 million of share-based compensation expense in the second quarter of 2008 related to this modification. This additional expense would have been recognized in future reporting periods if the modification had not been made and the executives continued their employment at Devon.
10. Change in Fair Value of Non-Oil and Gas Financial Instruments
     The components of the change in fair value of non-oil and gas financial instruments include the following:
                                 
    Three Months     Six Months  
    Ended June 30,     Ended June 30,  
    2008     2007     2008     2007  
    (In millions)  
Losses (gains) from:
                               
Chevron common stock
  $ (195 )   $ (146 )   $ (82 )   $ (152 )
Option embedded in exchangeable debentures
    155       136       58       144  
Other
                      (1 )
 
                       
Total
  $ (40 )   $ (10 )   $ (24 )   $ (9 )
 
                       
11. Income Taxes
     In the second quarter of 2008, Devon repatriated $1.3 billion in earnings from certain foreign subsidiaries to the United States. Devon also expects to repatriate approximately $1.5 billion in earnings from certain foreign subsidiaries to the United States during the last six months of 2008. Subsequent to these repatriations, Devon does not expect to repatriate similar earnings from its historical operations in the foreseeable future. Also in the second quarter of 2008, Devon made certain tax policy election changes to minimize the taxes Devon otherwise would pay to all relevant tax jurisdictions for the cash repatriations, as well as the taxable gains associated with the sales of assets in West Africa. As a result of the repatriation and tax policy election changes, Devon recognized additional tax expense of $312 million during the second quarter of 2008. Of the $312 million, $295 million was recognized as current income tax expense, and $17 million was recognized as deferred tax expense. Included in the $312 million additional tax expense is $183 million for tax positions in which the resulting tax benefits are not recognized in the accompanying consolidated financial statements. If recognized, all of these unrecognized tax benefits would affect Devon’s effective income tax rate.
12. Discontinued Operations
Divestiture Activity
     In November 2006 and January 2007, Devon announced its plans to divest its operations in Egypt and West Africa, including Equatorial Guinea, Gabon, Cote D’Ivoire and other countries in the region. Pursuant to accounting rules for discontinued operations, Devon has classified all amounts related to its operations in Egypt and West Africa as discontinued operations.
     In the second quarter of 2008, Devon sold its assets and terminated its operations in certain West African countries, consisting primarily of Equatorial Guinea and Gabon. As a result of the sales, Devon recognized gains totaling $736 million ($647 million after taxes) in the second quarter of 2008 from proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase price adjustments).
     In the fourth quarter of 2007, Devon sold its assets and terminated its operations in Egypt and recognized a $90 million after-tax gain from proceeds of $341 million.
     Devon has entered into agreements to sell its operations in Cote D’Ivoire and other countries located in West Africa for approximately $250 million. Devon is obtaining the necessary partner and government approvals for these properties and expects to complete the remaining sales during the third quarter of 2008. Had these transactions closed on June 30, 2008, Devon would have recognized after-tax gains of approximately $100 million. The gains ultimately recorded when the transactions close will depend on

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
the carrying values of Devon’s assets and liabilities at the closing dates, as well as the effect of any purchase price adjustments between the effective dates and the actual closing dates of the sales.
Financial Statement Information
     Revenues related to Devon’s discontinued operations totaled $127 million and $215 million in the three months ended June 30, 2008 and June 30, 2007 and $332 million and $390 million in the six months ended June 30, 2008 and 2007, respectively. These amounts do not include the divestiture gains discussed in the previous section.
     The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations as of June 30, 2008 and December 31, 2007.
                 
    June 30, 2008     December 31, 2007  
    (In millions)  
Assets:
               
Cash
  $ 8     $ 9  
Accounts receivable
    5       83  
Deferred tax asset
    68        
Other current assets
    24       28  
 
           
Current assets
  $ 105     $ 120  
 
           
 
               
Long-term assets — property and equipment, net of accumulated depreciation, depletion and amortization
  $ 84     $ 1,512  
 
           
 
               
Liabilities:
               
Accounts payable — trade
  $ 2     $ 23  
Revenues and royalties due to others
    2       11  
Income taxes payable
    6       100  
Current portion of asset retirement obligation
          9  
Accrued expenses and other current liabilities
    6       2  
 
           
Current liabilities
  $ 16     $ 145  
 
           
 
               
Asset retirement obligation, long-term
  $ 5     $ 35  
Deferred income taxes
    19       366  
Other long-term liabilities
          3  
 
           
Long-term liabilities
  $ 24     $ 404  
 
           

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
13. Earnings Per 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 six-month periods ended June 30, 2008 and 2007.
                         
    Net              
    Earnings     Weighted        
    Applicable to     Average     Net  
    Common     Common Shares     Earnings  
    Stockholders     Outstanding     per Share  
    (In millions, except per share amounts)  
Three Months Ended June 30, 2008:
                       
Earnings from continuing operations
  $ 594                  
Less preferred stock dividends
    (3 )                
 
                     
Basic earnings per share
    591       446     $ 1.33  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          4          
 
                 
Diluted earnings per share
  $ 591       450     $ 1.31  
 
                 
 
                       
Three Months Ended June 30, 2007:
                       
Earnings from continuing operations
  $ 824                  
Less preferred stock dividends
    (3 )                
 
                     
Basic earnings per share
    821       446     $ 1.84  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          4          
 
                 
Diluted earnings per share
  $ 821       450     $ 1.82  
 
                 
 
                       
Six Months Ended June 30, 2008:
                       
Earnings from continuing operations
  $ 1,245                  
Less preferred stock dividends
    (5 )                
 
                     
Basic earnings per share
    1,240       445     $ 2.79  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          5          
 
                 
Diluted earnings per share
  $ 1,240       450     $ 2.76  
 
                 
 
                       
Six Months Ended June 30, 2007:
                       
Earnings from continuing operations
  $ 1,398                  
Less preferred stock dividends
    (5 )                
 
                     
Basic earnings per share
    1,393       445     $ 3.13  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          5          
 
                 
Diluted earnings per share
  $ 1,393       450     $ 3.09  
 
                 
     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 six-month periods ended June 30, 2008, no shares and 1.5 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and six-month periods ended June 30, 2007, 4.0 million shares and 4.1 million shares, respectively, were excluded from the diluted earnings per share calculations.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
14. 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 June 30, 2008:
                               
Current assets
  $ 3,110     $ 1,622     $ 701     $ 5,433  
Property and equipment, net of accumulated depreciation, depletion and amortization
    19,976       8,857       1,351       30,184  
Goodwill
    3,050       2,963       68       6,081  
Other long-term assets
    1,726       61       295       2,082  
 
                       
Total assets
  $ 27,862     $ 13,503     $ 2,415     $ 43,780  
 
                       
 
                               
Current liabilities
  $ 4,994     $ 582     $ 456     $ 6,032  
Long-term debt
    1,852       2,977             4,829  
Asset retirement obligation, long-term
    689       646       95       1,430  
Other long-term liabilities
    938       46       28       1,012  
Deferred income taxes
    4,871       2,086       87       7,044  
Stockholders’ equity
    14,518       7,166       1,749       23,433  
 
                       
Total liabilities and stockholders’ equity
  $ 27,862     $ 13,503     $ 2,415     $ 43,780  
 
                       

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
                                 
    U.S.     Canada     International     Total  
    (In millions)  
Three Months Ended June 30, 2008:
                               
Revenues:
                               
Oil sales
  $ 566     $ 498     $ 391     $ 1,455  
Gas sales
    1,688       517       5       2,210  
NGL sales
    305       74             379  
Net loss on oil and gas derivative financial instruments
    (1,215 )                 (1,215 )
Marketing and midstream revenues
    707       12             719  
 
                       
Total revenues
    2,051       1,101       396       3,548  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    279       211       47       537  
Production taxes
    104       1       71       176  
Marketing and midstream operating costs and expenses
    510       5             515  
Depreciation, depletion and amortization of oil and gas properties
    481       227       54       762  
Depreciation and amortization of non-oil and gas properties
    54       7       1       62  
Accretion of asset retirement obligation
    10       10       2       22  
General and administrative expenses
    145       34       1       180  
Interest expense
    36       54             90  
Change in fair value of non-oil and gas derivative financial instruments
    (40 )                 (40 )
Other income, net
    (11 )           (6 )     (17 )
 
                       
Total expenses and other income, net
    1,568       549       170       2,287  
 
                       
Earnings from continuing operations before income tax expense
    483       552       226       1,261  
Income tax expense (benefit):
                               
Current
    299       46       69       414  
Deferred
    163       104       (14 )     253  
 
                       
Total income tax expense
    462       150       55       667  
 
                       
Earnings from continuing operations
    21       402       171       594  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
                851       851  
Income tax expense
                144       144  
 
                       
Earnings from discontinued operations
                707       707  
 
                       
Net earnings
    21       402       878       1,301  
Preferred stock dividends
    3                   3  
 
                       
Net earnings applicable to common stockholders
  $ 18     $ 402     $ 878     $ 1,298  
 
                       
 
                               
Capital expenditures, before revision of future ARO
  $ 1,654     $ 182     $ 150     $ 1,986  
Revision of future ARO
                22       22  
 
                       
Capital expenditures, continuing operations
  $ 1,654     $ 182     $ 172     $ 2,008  
 
                       

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
                                 
    U.S.     Canada     International     Total  
    (In millions)  
Three Months Ended June 30, 2007:
                               
Revenues:
                               
Oil sales
  $ 305     $ 185     $ 375     $ 865  
Gas sales
    983       380       3       1,366  
NGL sales
    177       47             224  
Net gain on oil and gas derivative financial instruments
    14                   14  
Marketing and midstream revenues
    452       8             460  
 
                       
Total revenues
    1,931       620       378       2,929  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    256       140       43       439  
Production taxes
    59       1       30       90  
Marketing and midstream operating costs and expenses
    338       3             341  
Depreciation, depletion and amortization of oil and gas properties
    402       182       61       645  
Depreciation and amortization of non-oil and gas properties
    44       5             49  
Accretion of asset retirement obligation
    9       8       1       18  
General and administrative expenses
    91       27       (5 )     113  
Interest expense
    57       50             107  
Change in fair value of non-oil and gas derivative financial instruments
    (10 )                 (10 )
Other income, net
    (6 )     (2 )     (9 )     (17 )
 
                       
Total expenses and other income, net
    1,240       414       121       1,775  
 
                       
Earnings from continuing operations before income tax expense
    691       206       257       1,154  
Income tax expense (benefit):
                               
Current
    55       43       76       174  
Deferred
    166       (4 )     (6 )     156  
 
                       
Total income tax expense
    221       39       70       330  
 
                       
Earnings from continuing operations
    470       167       187       824  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
                128       128  
Income tax expense
                48       48  
 
                       
Earnings from discontinued operations
                80       80  
 
                       
Net earnings
    470       167       267       904  
Preferred stock dividends
    3                   3  
 
                       
Net earnings applicable to common stockholders
  $ 467     $ 167     $ 267     $ 901  
 
                       
 
                               
Capital expenditures, continuing operations
  $ 1,079     $ 192     $ 109     $ 1,380  
 
                       

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
                                 
    U.S.     Canada     International     Total  
    (In millions)  
Six Months Ended June 30, 2008:
                               
Revenues:
                               
Oil sales
  $ 1,009     $ 838     $ 858     $ 2,705  
Gas sales
    2,924       906       10       3,840  
NGL sales
    571       136             707  
Net loss on oil and gas derivative financial instruments
    (2,003 )                 (2,003 )
Marketing and midstream revenues
    1,249       25             1,274  
 
                       
Total revenues
    3,750       1,905       868       6,523  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    545       405       93       1,043  
Production taxes
    183       2       125       310  
Marketing and midstream operating costs and expenses
    887       10             897  
Depreciation, depletion and amortization of oil and gas properties
    941       438       120       1,499  
Depreciation and amortization of non-oil and gas properties
    105       13       1       119  
Accretion of asset retirement obligation
    21       20       3       44  
General and administrative expenses
    259       68       1       328  
Interest expense
    88       104             192  
Change in fair value of non-oil and gas derivative financial instruments
    (24 )                 (24 )
Other income, net
    (17 )     (5 )     (16 )     (38 )
 
                       
Total expenses and other income, net
    2,988       1,055       327       4,370  
 
                       
Earnings from continuing operations before income tax expense
    762       850       541       2,153  
Income tax expense:
                               
Current
    345       64       108       517  
Deferred
    213       152       26       391  
 
                       
Total income tax expense
    558       216       134       908  
 
                       
Earnings from continuing operations
    204       634       407       1,245  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
                1,040       1,040  
Income tax expense
                235       235  
 
                       
Earnings from discontinued operations
                805       805  
 
                       
Net earnings
    204       634       1,212       2,050  
Preferred stock dividends
    5                   5  
 
                       
Net earnings applicable to common stockholders
  $ 199     $ 634     $ 1,212     $ 2,045  
 
                       
 
                               
Capital expenditures, before revision of future ARO
  $ 2,965     $ 698     $ 301     $ 3,964  
Revision of future ARO
    70       73       19       162  
 
                       
Capital expenditures, continuing operations
  $ 3,035     $ 771     $ 320     $ 4,126  
 
                       

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
                                 
    U.S.     Canada     International     Total  
    (In millions)  
Six Months Ended June 30, 2007:
                               
Revenues:
                               
Oil sales
  $ 539     $ 338     $ 679     $ 1,556  
Gas sales
    1,872       736       4       2,612  
NGL sales
    313       88             401  
Net loss on oil and gas derivative financial instruments
    (6 )                 (6 )
Marketing and midstream revenues
    823       16             839  
 
                       
Total revenues
    3,541       1,178       683       5,402  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    504       283       82       869  
Production taxes
    115       2       53       170  
Marketing and midstream operating costs and expenses
    604       7             611  
Depreciation, depletion and amortization of oil and gas properties
    773       342       117       1,232  
Depreciation and amortization of non-oil and gas properties
    85       10             95  
Accretion of asset retirement obligation
    19       15       2       36  
General and administrative expenses
    183       52       (3 )     232  
Interest expense
    116       101             217  
Change in fair value of non-oil and gas derivative financial instruments
    (8 )     (1 )           (9 )
Other income, net
    (18 )     (5 )     (20 )     (43 )
 
                       
Total expenses and other income, net
    2,373       806       231       3,410  
 
                       
Earnings from continuing operations before income tax expense
    1,168       372       452       1,992  
Income tax expense (benefit):
                               
Current
    122       105       136       363  
Deferred
    252       (5 )     (16 )     231  
 
                       
Total income tax expense
    374       100       120       594  
 
                       
Earnings from continuing operations
    794       272       332       1,398  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
                265       265  
Income tax expense
                108       108  
 
                       
Earnings from discontinued operations
                157       157  
 
                       
Net earnings
    794       272       489       1,555  
Preferred stock dividends
    5                   5  
 
                       
Net earnings applicable to common stockholders
  $ 789     $ 272     $ 489     $ 1,550  
 
                       
 
                               
Capital expenditures, before revision of future ARO
  $ 2,022     $ 661     $ 215     $ 2,898  
Revision of future ARO
    210       99       2       311  
 
                       
Capital expenditures, continuing operations
  $ 2,232     $ 760     $ 217     $ 3,209  
 
                       

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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 and capital resources and uses for the three-month and six-month periods ended June 30, 2008, compared to the three-month and six-month periods ended June 30, 2007, and in our financial condition and liquidity since December 31, 2007. It is presumed that readers have read or have access to our 2007 Annual Report on Form 10-K/A, which includes disclosures regarding critical accounting policies and estimates 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
     During the second quarter and first six months of 2008, we generated net earnings of $1.3 billion and $2.1 billion, respectively, or $2.88 and $4.55 per diluted share, representing increases of 44% and 32% over the same periods of 2007. Additionally, net cash provided by operating activities for the first half of 2008 climbed to a record amount of $5.2 billion, representing a 55% increase over 2007. These increases in earnings and cash flow are largely attributable to the following factors:
    Production increased 4% and 7% in the second quarter and first six months of 2008, respectively.
 
    The combined realized price without hedges for oil, gas and NGLs increased 58% and 48% in the second quarter and first six months of 2008, respectively.
 
    Oil and gas hedges generated net losses of $1.2 billion and $2.0 billion in the second quarter and first six months of 2008, respectively. Included in these amounts are cash payments of $303 million and $311 million, respectively.
 
    Marketing and midstream operating profit increased 71% and 65% in the second quarter and first six months of 2008, respectively.
 
    Per unit operating costs rose 18% and 12% in the second quarter and first six months of 2008, respectively.
 
    General and administrative expenses increased 59% and 41% in the second quarter and first six months of 2008, respectively.
 
    The effective income tax rates for the second quarter and first six months of 2008 were 53% and 42%, respectively.
 
    Cash spent on capital expenditures for oil and gas exploration and development activities were $3.6 billion during the first half of 2008.
     Additionally, we made significant progress toward completion of our African divestiture program during the second quarter of 2008. We completed the sales of assets in certain West African countries, including Equatorial Guinea—the largest individual transaction in the divestiture program. As a result of the sales, we recognized after-tax gains totaling $647 million in the second quarter of 2008 from proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase price adjustments). Also, in conjunction with these asset sales, we repatriated an additional $1.3 billion of earnings from certain foreign subsidiaries to the United States in the second quarter of 2008. We also expect to repatriate $1.5 billion from certain foreign subsidiaries to the United States in the second half of 2008.
     With the proceeds from asset sales, repatriated funds and growing cash flow from operations, we repaid $2.5 billion of commercial paper and credit facility borrowings during the first six months of 2008. We also repurchased 2.8 million common shares for $302 million during the first six months of 2008.
Results of Operations
Revenues
Oil, Gas and NGL Sales
     The three-month and six-month comparison of our oil, gas and NGL production and the related prices realized without the effect of hedges is shown in the following tables. The amounts for all periods presented exclude our Egyptian operations that were sold in the fourth quarter of 2007 and our West African operations, which are classified as discontinued operations in our financial statements.

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    Total  
    Three Months Ended June 30,     Six Months Ended June 30,  
    2008     2007     Change(2)     2008     2007     Change(2)  
Production
                                               
Oil (MMBbls)
    13       15       -9 %     27       28       -1 %
Gas (Bcf)
    230       212       +8 %     453       414       +9 %
NGLs (MMBbls)
    7       6       +9 %     14       12       +12 %
Oil, Gas and NGLs (MMBoe)(1)
    59       56       +4 %     117       109       +7 %
 
                                               
Realized prices without hedges
                                               
Oil (Per Bbl)
  $ 110.56     $ 60.01       +84 %   $ 98.98     $ 56.22       +76 %
Gas (Per Mcf)
  $ 9.61     $ 6.43       +49 %   $ 8.48     $ 6.31       +34 %
NGLs (Per Bbl)
  $ 54.08     $ 35.03       +54 %   $ 50.76     $ 32.26       +57 %
Oil, Gas and NGLs (Per Boe)(1)
  $ 69.14     $ 43.68       +58 %   $ 62.12     $ 41.87       +48 %
 
                                               
Revenues ($ in millions)
                                               
Oil sales
  $ 1,455     $ 865       +68 %   $ 2,705     $ 1,556       +74 %
Gas sales
    2,210       1,366       +62 %     3,840       2,612       +47 %
NGL sales
    379       224       +69 %     707       401       +76 %
 
                                       
Oil, Gas and NGL sales
  $ 4,044     $ 2,455       +65 %   $ 7,252     $ 4,569       +59 %
 
                                       
                                                 
    Domestic  
    Three Months Ended June 30,     Six Months Ended June 30,  
    2008     2007     Change(2)     2008     2007     Change(2)  
Production
                                               
Oil (MMBbls)
    5       5       -5 %     9       9       -1 %
Gas (Bcf)
    176       155       +14 %     347       301       +15 %
NGLs (MMBbls)
    6       5       +13 %     12       10       +17 %
Oil, Gas and NGLs (MMBoe)(1)
    40       36       +11 %     79       70       +13 %
 
                                               
Realized prices without hedges
                                               
Oil (Per Bbl)
  $ 122.47     $ 62.68       +95 %   $ 109.08     $ 57.67       +89 %
Gas (Per Mcf)
  $ 9.56     $ 6.35       +51 %   $ 8.42     $ 6.22       +35 %
NGLs (Per Bbl)
  $ 50.66     $ 33.26       +52 %   $ 47.78     $ 30.54       +56 %
Oil, Gas and NGLs (Per Boe)(1)
  $ 63.88     $ 40.71       +57 %   $ 56.95     $ 39.05       +46 %
 
                                               
Revenues ($ in millions)
                                               
Oil sales
  $ 566     $ 305       +86 %   $ 1,009     $ 539       +87 %
Gas sales
    1,688       983       +72 %     2,924       1,872       +56 %
NGL sales
    305       177       +72 %     571       313       +83 %
 
                                       
Oil, Gas and NGL sales
  $ 2,559     $ 1,465       +75 %   $ 4,504     $ 2,724       +65 %
 
                                       

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    Canada  
    Three Months Ended June 30,     Six Months Ended June 30,  
    2008     2007     Change(2)     2008     2007     Change(2)  
Production
                                               
Oil (MMBbls)
    5       4       +32 %     10       8       +32 %
Gas (Bcf)
    53       56       -7 %     105       112       -7 %
NGLs (MMBbls)
    1       1       -8 %     2       2       -10 %
Oil, Gas and NGLs (MMBoe)(1)
    16       14       +4 %     30       28       +3 %
 
                                               
Realized prices without hedges
                                               
Oil (Per Bbl)
  $ 94.35     $ 46.32       +104 %   $ 84.16     $ 45.01       +87 %
Gas (Per Mcf)
  $ 9.76     $ 6.66       +47 %   $ 8.66     $ 6.55       +32 %
NGLs (Per Bbl)
  $ 75.10     $ 43.82       +71 %   $ 68.86     $ 40.37       +71 %
Oil, Gas and NGLs (Per Boe)(1)
  $ 72.14     $ 41.99       +72 %   $ 64.01     $ 40.88       +57 %
 
                                               
Revenues ($ in millions)
                                               
Oil sales
  $ 498     $ 185       +168 %   $ 838     $ 338       +148 %
Gas sales
    517       380       +36 %     906       736       +23 %
NGL sales
    74       47       +57 %     136       88       +54 %
 
                                       
Oil, Gas and NGL sales
  $ 1,089     $ 612       +78 %   $ 1,880     $ 1,162       +62 %
 
                                       
                                                 
    International  
    Three Months Ended June 30,     Six Months Ended June 30,  
    2008     2007     Change(2)     2008     2007     Change(2)  
Production
                                               
Oil (MMBbls)
    3       6       -41 %     8       11       -25 %
Gas (Bcf)
    1       1       -14 %     1       1       +27 %
NGLs (MMBbls)
                N/M                   N/M  
Oil, Gas and NGLs (MMBoe)(1)
    3       6       -41 %     8       11       -24 %
 
                                               
Realized prices without hedges
                                               
Oil (Per Bbl)
  $ 119.87     $ 67.57       +77 %   $ 105.63     $ 62.76       +68 %
Gas (Per Mcf)
  $ 11.00     $ 6.19       +78 %   $ 9.56     $ 5.16       +85 %
NGLs (Per Bbl)
  $     $       N/M     $     $       N/M  
Oil, Gas and NGLs (Per Boe)(1)
  $ 118.70     $ 67.11       +77 %   $ 104.68     $ 62.39       +68 %
 
                                               
Revenues ($ in millions)
                                               
Oil sales
  $ 391     $ 375       +4 %   $ 858     $ 679       +26 %
Gas sales
    5       3       +52 %     10       4       +134 %
NGL sales
                N/M                   N/M  
 
                                       
Oil, Gas and NGL sales
  $ 396     $ 378       +5 %   $ 868     $ 683       +27 %
 
                                       
 
(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 volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the three months ended June 30, 2008 and 2007.
                                 
    Oil     Gas     NGLs     Total  
    (In millions)  
2007 sales
  $ 865     $ 1,366     $ 224     $ 2,455  
Changes due to volumes
    (75 )     113       21       59  
Changes due to prices.
    665       731       134       1,530  
 
                       
2008 sales
  $ 1,455     $ 2,210     $ 379     $ 4,044  
 
                       
     The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the six months ended June 30, 2008 and 2007.
                                 
    Oil     Gas     NGLs     Total  
    (In millions)  
2007 sales
  $ 1,556     $ 2,612     $ 401     $ 4,569  
Changes due to volumes
    (20 )     245       48       273  
Changes due to prices.
    1,169       983       258       2,410  
 
                       
2008 sales
  $ 2,705     $ 3,840     $ 707     $ 7,252  
 
                       
Oil Sales
     Oil sales decreased $75 million in the second quarter of 2008 due to a two million barrel, or 9%, decrease in production. International production decreased approximately three million barrels due to reaching certain cost recovery thresholds of our carried interest in Azerbaijan. This was partially offset by an additional one million barrels of production due to increased development activity at our Jackfish and Lloydminster areas in Canada.
     Oil sales increased $665 million in the second quarter of 2008 as a result of an 84% increase in our realized price without hedges. The average NYMEX West Texas Intermediate index price increased 91% during the same time period, accounting for the majority of the increase.
     Oil sales increased $1.2 billion in the first half of 2008 as a result of a 76% increase in our realized price without hedges. The average NYMEX West Texas Intermediate index price increased 80% during the same time period, accounting for the majority of the increase.
Gas Sales
     An 18 Bcf, or 8%, increase in production during the second quarter of 2008 caused gas sales to increase by $113 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 22 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.
     Gas sales increased $731 million during the second quarter of 2008 as a result of a 49% increase in our realized price without hedges. This increase is largely due to increases in the regional index prices upon which our gas sales are based.
     A 39 Bcf, or 9%, increase in production during the first half of 2008 caused gas sales to increase by $245 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 42 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.
     Gas sales increased $983 million during the first half of 2008 as a result of a 34% increase in our realized price without hedges. This increase is largely due to increases in the regional index prices upon which our gas sales are based.

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Net (Loss) Gain on Oil and Gas Derivative Financial Instruments
     The following tables provide financial information associated with our oil and gas hedges for the second quarter and first half of 2008 and 2007. The first table presents the cash settlements and unrealized losses and gains recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements for the second quarter and first half of 2008 and 2007. The prices do not include the effects of unrealized losses and gains.
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2008     2007     2008     2007  
    (In millions)  
Cash settlements:
                               
Gas price swaps
  $ (153 )   $ 5     $ (161 )   $ 15  
Gas price collars
    (150 )           (150 )     2  
Oil price collars
                       
 
                       
Total cash settlements (paid) received
    (303 )     5       (311 )     17  
 
                       
Unrealized (losses) gains on fair value changes:
                               
Gas price swaps
    (247 )     9       (618 )     (19 )
Gas price collars
    (620 )           (1,028 )     (4 )
Oil price collars
    (45 )           (46 )      
 
                       
Total unrealized (losses) gains on fair value changes
    (912 )     9       (1,692 )     (23 )
 
                       
Net (loss) gain on oil and gas derivative financial Instruments
  $ (1,215 )   $ 14     $ (2,003 )   $ (6 )
 
                       
                                 
    Three Months Ended June 30, 2008  
    Oil     Gas     NGLs     Total  
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
Realized price without hedges
  $ 110.56     $ 9.61     $ 54.08     $ 69.14  
Cash settlements of hedges
    (0.01 )     (1.32 )           (5.18 )
 
                       
Realized price, including cash settlements
  $ 110.55     $ 8.29     $ 54.08     $ 63.96  
 
                       
                                 
    Three Months Ended June 30, 2007  
    Oil     Gas     NGLs     Total  
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
Realized price without hedges
  $ 60.01     $ 6.43     $ 35.03     $ 43.68  
Cash settlements of hedges
          0.03             0.10  
 
                       
Realized price, including cash settlements
  $ 60.01     $ 6.46     $ 35.03     $ 43.78  
 
                       
                                 
    Six Months Ended June 30, 2008  
    Oil     Gas     NGLs     Total  
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
Realized price without hedges
  $ 98.98     $ 8.48     $ 50.76     $ 62.12  
Cash settlements of hedges
          (0.69 )           (2.67 )
 
                       
Realized price, including cash settlements
  $ 98.98     $ 7.79     $ 50.76     $ 59.45  
 
                       
                                 
    Six Months Ended June 30, 2007  
    Oil     Gas     NGLs     Total  
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
Realized price without hedges
  $ 56.22     $ 6.31     $ 32.26     $ 41.87  
Cash settlements of hedges
          0.04             0.16  
 
                       
Realized price, including cash settlements
  $ 56.22     $ 6.35     $ 32.26     $ 42.03  
 
                       
     Our oil and gas derivative financial instruments include price swaps and costless collars. For the price swaps, we receive a fixed price for our production and pay a variable market price to the contract counterparty. The costless price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we cash-settle the difference with the counterparty to the collars. Cash settlements as presented in the tables above represent realized losses or gains related to our price swaps and collars.

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     During the second quarter and first half of 2008, we paid $303 million, or $1.32 per Mcf, and $311 million, or $0.69 per Mcf, respectively, to counterparties to settle our gas price swaps and collars. During the second quarter and first half of 2007, we received $5 million, or $0.03 per Mcf, and $17 million, or $0.04 per Mcf, respectively, from counterparties to settle our gas price swaps and collars.
     In addition to recognizing these cash settlement effects, we also recognize unrealized changes in the fair values of our oil and gas derivative instruments in each reporting period. We estimate the fair values of our oil and gas derivative financial instruments primarily by using internal discounted cash flow calculations. From time to time, we validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties and/or brokers.
     The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Based on the amount of volumes subject to price swaps and collars at June 30, 2008, a 10% increase in these forward curves would have increased our second quarter 2008 unrealized loss for our oil and gas derivative financial instruments by approximately $550 million. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility.
     During the second quarter and first half of 2008, we recognized unrealized losses totaling $912 million and $1.7 billion, respectively, related to our oil and gas derivative instruments. These losses result primarily from a significant increase in the Inside FERC Henry Hub and the NYMEX West Texas Intermediate forward curves subsequent to the trade dates for our oil and gas price swaps and collars.
     During the second quarter and first half of 2007, we recognized an unrealized gain totaling $9 million and an unrealized loss totaling $23 million, related to our gas derivative instruments.
Marketing and Midstream Revenues and Operating Costs and Expenses
     The details of the changes in marketing and midstream revenues, operating costs and expenses and the resulting operating profit between the three months ended June 30, 2008 and 2007 and the six months ended June 30, 2008 and 2007 are shown in the table below.
                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2008     2007     Change(1)     2008     2007     Change(1)  
Marketing and midstream ($ in millions):
                                               
Revenues
  $ 719     $ 460       +56 %   $ 1,274     $ 839       +52 %
Operating costs and expenses
    515       341       +51 %     897       611       +47 %
 
                                       
Operating profit
  $ 204     $ 119       +71 %   $ 377     $ 228       +65 %
 
                                       
 
(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.
     Marketing and midstream revenues increased $259 million and operating costs and expenses also increased $174 million, causing operating profit to increase $85 million during the second quarter of 2008. Revenues and expenses increased primarily due to higher natural gas and NGL prices, as well as higher gas pipeline throughput in the Barnett Shale.
     Marketing and midstream revenues increased $435 million and operating costs and expenses also increased $286 million, causing operating profit to increase $149 million during the first six months of 2008. Revenues and expenses increased primarily due to higher natural gas and NGL prices, as well as higher gas pipeline throughput in the Barnett Shale.

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Oil, Gas and NGL Production and Operating Expenses
     The three-month and six-month comparisons of oil, gas and NGL production and operating expenses are shown in the table below.
                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2008     2007     Change(1)     2008     2007     Change(1)  
Production and operating expenses ($ in millions):
                                               
Lease operating expenses
  $ 537     $ 439       +22 %   $ 1,043     $ 869       +20 %
Production taxes
    176       90       +95 %     310       170       +82 %
 
                                       
Total production and operating expenses
  $ 713     $ 529       +35 %   $ 1,353     $ 1,039       +30 %
 
                                       
 
                                               
Production and operating expenses per Boe:
                                               
Lease operating expenses
  $ 9.18     $ 7.81       +18 %   $ 8.93     $ 7.96       +12 %
Production taxes
    3.01       1.61       +88 %     2.66       1.57       +70 %
 
                                       
Total production and operating expenses per Boe
  $ 12.19     $ 9.42       +30 %   $ 11.59     $ 9.53       +22 %
 
                                       
 
(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 (“LOE”)
     LOE increased $98 million in the second quarter of 2008. The largest contributor to this increase, as well as the increase in LOE per Boe, was higher per-unit costs associated with new thermal heavy oil production from our Jackfish operations in Canada as well as new oil production from Brazil. As these large-scale projects are in the early phases of production, per-unit operating costs are higher than the per-unit costs for our overall portfolio of producing properties. LOE also increased $17 million due to our 4% growth in production. Additionally, the effects of changes in the exchange rate between the U.S. and Canadian dollar caused LOE to increase $17 million. The exchange rate effect also contributed to the increase in LOE per Boe.
     LOE increased $174 million in the first half of 2008. The largest contributor to this increase, as well as the increase in LOE per Boe, was higher per-unit costs associated with new thermal heavy oil production from our Jackfish operations in Canada as well as new oil production from Brazil. LOE also increased $61 million due to our 7% growth in production. Furthermore, changes in the exchange rate between the U.S. and Canadian dollar also caused LOE to increase $46 million. This exchange rate also contributed to the increase in LOE per Boe.
Production Taxes
     The following table details the changes in production taxes between the three months ended June 30, 2008 and 2007 and the six months ended June 30, 2008 and 2007. The majority of our production taxes are assessed on our U.S. onshore properties and are based on a fixed percentage of revenues. Therefore, the changes due to revenues in the following table primarily relate to changes in oil, gas and NGL revenues from our U.S. onshore properties.
                 
    Three Months     Six Months  
    Ended June 30,     Ended June 30,  
    (In millions)  
2007 production taxes
  $ 90     $ 170  
Change due to revenues
    58       100  
Change due to rate
    28       40  
 
           
2008 production taxes
  $ 176     $ 310  
 
           

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Depreciation, Depletion and Amortization Expenses (“DD&A”)
     The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties between the three and six months ended June 30, 2008 and 2007 are shown in the table below.
                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2008     2007     Change(1)     2008     2007     Change(1)  
Production volumes (MMBoe)
    59       56       +4 %     117       109       +7 %
DD&A rate ($  per Boe)
  $ 13.03     $ 11.48       +14 %   $ 12.84     $ 11.29       +14 %
 
                                       
DD&A expense ($ in millions)
  $ 762     $ 645       +18 %   $ 1,499     $ 1,232       +22 %
 
                                       
 
(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.
     The following table details the changes in DD&A of oil and gas properties between the three months and six months ended June 30, 2008 and 2007.
                 
    Three Months     Six Months  
    Ended June 30,     Ended June 30,  
    (In millions)  
2007 DD&A
  $ 645     $ 1,232  
Change due to volumes
    26       86  
Change due to rate
    91       181  
 
           
2008 DD&A
  $ 762     $ 1,499  
 
           
     The 4% production increase during the second quarter of 2008 caused oil and gas property related DD&A to increase $26 million. In addition, oil and gas property related DD&A increased $91 million due to a 14% increase in the DD&A rate. The largest contributor to the rate increase was inflationary pressure on costs incurred during 2007 and 2008, as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate increase include a higher Canadian-to-U.S. dollar exchange rate in 2008 and the transfer of previously unproved costs to the depletable base as a result of 2007 and 2008 drilling activities.
     The 7% production increase during the first half of 2008 caused oil and gas property related DD&A to increase $86 million. In addition, oil and gas property related DD&A increased $181 million due to a 14% increase in the DD&A rate. The largest contributor to the rate increase was inflationary pressure on costs incurred during 2007 and 2008, as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate increase include a higher Canadian-to-U.S. dollar exchange rate in 2008 and the transfer of previously unproved costs to the depletable base as a result of 2007 and 2008 drilling activities.
General and Administrative Expenses (“G&A”)
     The following schedule includes the components of G&A expense for the three-month and six-month periods ended June 30, 2008 and 2007.
                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2008     2007     Change(1)     2008     2007     Change(1)  
    (In millions)             (In millions)          
Gross G&A
  $ 307     $ 222       +38 %   $ 584     $ 434       +35 %
Capitalized G&A
    (100 )     (82 )     +22 %     (199 )     (146 )     +37 %
Reimbursed G&A
    (27 )     (27 )     +1 %     (57 )     (56 )     +3 %
 
                                       
Net G&A
  $ 180     $ 113       +59 %   $ 328     $ 232       +41 %
 
                                       
 
(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.

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     Gross G&A increased $85 million in the second quarter of 2008 compared to the same period of 2007. The largest contributor to the increase was higher employee compensation and benefits costs related to our workforce growth and industry inflation. Additionally, gross G&A increased $27 million due to accelerated expense recognition of share-based compensation. In the second quarter of 2008, we modified the share-based compensation arrangements for certain members of senior management (“executives”). The modified compensation arrangements provide that executives who meet certain years-of-service and age criteria can retire and continue vesting in outstanding share-based grants. This modification results in accelerated expense recognition as executives approach the years-of-service and age criteria. Additionally, when the modification was made in the second quarter of 2008, certain executives had already met the years-of-service and age criteria. As a result, we recognized an additional $27 million of share-based compensation expense in the second quarter of 2008 related to this modification. This additional expense would have been recognized in future reporting periods if the modification had not been made and the executives continued their employment at Devon.
     The $18 million increase in capitalized G&A during the second quarter of 2008 is primarily due to the higher employee compensation and benefits costs.
     Gross G&A increased $150 million in the first half of 2008 compared to the same period of 2007. The largest contributor to the increase was higher employee compensation and benefits costs related to our workforce growth and industry inflation. Additionally, gross G&A increased $27 million due to the accelerated expense recognition of share-based compensation discussed above.
     The $53 million increase in capitalized G&A during the first half of 2008 is primarily due to higher employee compensation and benefits costs.
Interest Expense
     The following schedule includes the components of interest expense for the three-month and six-month periods ended June 30, 2008 and 2007.
                                 
    Three Months     Six Months  
    Ended June 30,     Ended June 30,  
    2008     2007     2008     2007  
    (In millions)  
Interest based on debt outstanding
  $ 110     $ 125     $ 236     $ 253  
Capitalized interest
    (25 )     (24 )     (56 )     (47 )
Other
    5       6       12       11  
 
                       
Total
  $ 90     $ 107     $ 192     $ 217  
 
                       
     Interest based on debt outstanding decreased during the second quarter of 2008 and the first half of 2008 primarily due to a decrease in outstanding borrowings. The decrease in borrowings resulted largely from the use of proceeds from asset sales and cash flow from operations to repay all commercial paper and credit facility borrowings in the second quarter of 2008.
Change in Fair Value of Non-Oil and Gas Financial Instruments
     The following schedule includes the components of the change in fair value of non-oil and gas financial instruments for the three months and six months ended June 30, 2008 and 2007.
                                 
    Three Months
Ended June 30,
    Six Months
Ended June 30,
 
    2008     2007     2008     2007  
    (In millions)  
Losses (gains) from:
                               
Chevron common stock
  $ (195 )   $ (146 )   $ (82 )   $ (152 )
Option embedded in exchangeable debentures
    155       136       58       144  
Other
                      (1 )
 
                       
Total
  $ (40 )   $ (10 )   $ (24 )   $ (9 )
 
                       
     Each reporting period, we recognize unrealized changes in the fair values of our investment in 14.2 million shares of Chevron common stock and the conversion option embedded in the debentures exchangeable into shares of Chevron common stock. We calculate the fair value of our investment in Chevron common stock using Chevron’s published market price. The embedded option is not actively traded in an established market. Therefore, we estimate its fair value

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using quotes obtained from a broker for trades occurring near the valuation date. Because the exchangeable debentures are due in August 2008, the embedded option’s recent fair value changes largely coincide with changes in the market price of Chevron’s common stock. As a result, when Chevron’s common stock price has increased from one valuation date to another, we have recognized a gain on our investment and a loss on the embedded option. The inverse is also true.
     The gain on our investment in Chevron common stock and loss on the embedded option during the second quarter of 2008 were directly attributable to a $13.77 increase in the price per share of Chevron’s common stock during the second quarter of 2008. The gain on our investment in Chevron common stock and loss on the embedded option during the second quarter of 2007 were directly attributable to a $10.28 increase in the price per share of Chevron’s common stock during the second quarter of 2007.
     The gain on our investment in Chevron common stock and loss on the embedded option during the first half of 2008 were directly attributable to a $5.80 increase in the price per share of Chevron’s common stock during the first half of 2008. The gain on our investment in Chevron common stock and loss on the embedded option during the first half of 2007 were directly attributable to a $10.71 increase in the price per share of Chevron’s common stock during the first half of 2007.
Income Taxes
     The following table presents our total income tax expense related to continuing operations and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate for the three-month and six-month periods ended June 30, 2008 and 2007. The primary factors causing our effective rates to vary from 2007 to 2008, and differ from the U.S. statutory rate, are discussed below.
                                 
    Three Months     Six Months  
    Ended June 30,     Ended June 30,  
    2008     2007     2008     2007  
Total income tax expense (In millions)
  $ 667     $ 330     $ 908     $ 594  
 
                               
U.S. statutory income tax rate
    35 %     35 %     35 %     35 %
Repatriations and tax policy election changes
    25 %           14 %      
Canadian statutory rate reductions
          (2 %)           (1 %)
Other, primarily taxation on foreign operations
    (7 %)     (4 %)     (7 %)     (4 %)
 
                       
Effective income tax rate
    53 %     29 %     42 %     30 %
 
                       
     In the both the second quarter and six months ended June 30, 2008, our effective income tax rate was higher than the U.S. statutory income tax rate largely due to two related factors. First, in the second quarter of 2008, we repatriated $1.3 billion in earnings from certain foreign subsidiaries to the United States. We also expect to repatriate approximately $1.5 billion in earnings from foreign subsidiaries to the United States during the last six months of 2008. Second, we made certain tax policy election changes in the second quarter of 2008 to minimize the taxes we otherwise would pay to all relevant tax jurisdictions for the cash repatriations, as well as the taxable gains associated with the sales of assets in West Africa. As a result of the repatriation and tax policy election changes, we recognized additional tax expense of $312 million during the second quarter of 2008. Of the $312 million, $295 million was recognized as current income tax expense, and $17 million was recognized as deferred tax expense.
     Excluding the $312 million of additional tax expense, our effective income tax rates would have been 28% for both the second quarter of 2008 and the first half of 2008. These rates, as well as the rates for the second quarter of 2007 and the first half of 2007, were lower than the U.S. statutory income tax rate largely due to our foreign operations, which have statutory rates lower than the U.S. statutory income tax rate. The 2007 rates were also impacted by a $30 million tax benefit that we recognized as a result of a statutory rate reduction enacted by the Canadian Federal government in the second quarter of 2007.
     Additionally, we expect our effective income tax rate for the remainder of 2008 will approximate the 28% rate applicable to the first half of 2008, excluding the $312 million of additional tax expense.

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Earnings from Discontinued Operations
     Our discontinued operations consist of our operations in Egypt, which were sold in the fourth quarter of 2007, and our operations in West Africa, including Equatorial Guinea, Gabon, Cote D’Ivoire and other countries in the region.
     Following are the components of earnings from discontinued operations for the three months and six months ended June 30, 2008 and 2007.
                                 
    Three Months
Ended June 30,
    Six Months
Ended June 30,
 
    2008     2007     2008     2007  
    (In millions)  
Earnings from discontinued operations before income taxes
  $ 851     $ 128     $ 1,040     $ 265  
Income tax expense
    144       48       235       108  
 
                       
Earnings from discontinued operations
  $ 707     $ 80     $ 805     $ 157  
 
                       
     Earnings from discontinued operations increased $627 million in the second quarter of 2008 and increased $648 million in the first half of 2008. The largest contributor to these increases was the recognition of after-tax gains totaling $647 million upon the sale of our assets in Equatorial Guinea, Gabon and other countries in the second quarter of 2008.
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 I, Item 1.
Sources and Uses of Cash
                 
    Six Months Ended June 30,  
    2008     2007  
    (In millions)  
Sources of cash and cash equivalents:
               
Operating cash flow — continuing operations
  $ 5,066     $ 3,152  
Sales of property and equipment
    108       37  
Stock option exercises
    104       60  
Net sales of short-term investments
    245       259  
Cash received from discontinued operations
    1,746        
Other
    55       17  
 
           
Total sources of cash and cash equivalents
    7,324       3,525  
 
           
 
               
Uses of cash and cash equivalents:
               
Capital expenditures
    (3,867 )     (2,990 )
Net commercial paper repayments
    (1,004 )     (183 )
Net repayments of debt
    (1,497 )      
Repurchases of common stock
    (252 )     (10 )
Redemption of preferred stock
    (150 )      
Dividends
    (146 )     (129 )
 
           
Total uses of cash and cash equivalents
    (6,916 )     (3,312 )
 
           
 
               
Increase from continuing operations
    408       213  
Increase from discontinued operations, net
    83       82  
of distributions to continuing operations Effect of foreign exchange rates
    (19 )     16  
 
           
Net increase in cash and cash equivalents
  $ 472     $ 311  
 
           
 
               
Cash and cash equivalents at end of period
  $ 1,845     $ 1,067  
 
           
Short-term investments at end of period
  $ 1     $ 315  
 
           

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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 half of 2008. 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 and deferred income tax expense. As a result, our operating cash flow increased in 2008 primarily due to the increase in earnings as discussed in the “Results of Operations” section of this report.
     During the first half of 2008, our operating cash flow was sufficient to fund our capital expenditures. Additionally, during 2007, operating cash flow was sufficient to fund all of our capital expenditures.
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 sometimes acquire 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 2008, we reduced our short-term investment balances by $245 million. During 2007, we reduced our short-term investment balances by $259 million to supplement our operating cash flow and fund debt repayments.
     In 2008, another significant source of cash is the proceeds from our African divestiture program. In the second quarter of 2008, we received $2.4 billion in proceeds ($1.7 billion net of income taxes and purchase price adjustments) for sales of assets located in certain West African countries, including Equatorial Guinea—the largest individual transaction in the divestiture program. Also, in conjunction with these asset sales, we repatriated an additional $1.3 billion of earnings from certain foreign subsidiaries to the United States in the second quarter of 2008.
     During 2008, we have used the proceeds from asset sales, repatriated funds and our operating cash flow in excess of capital expenditures to fund debt repayments, common stock repurchases and dividends on common and preferred stock.
Capital Expenditures
     Following are the components of our capital expenditures for the first half of 2008 and 2007.
                 
    Six Months  
    Ended June 30,  
    2008     2007  
    (In millions)  
U.S. Onshore
  $ 2,082     $ 1,526  
U.S. Offshore
    538       300  
Canada
    707       682  
International
    274       269  
 
           
Total exploration and development
    3,601       2,777  
Midstream
    205       171  
Other
    61       42  
 
           
Total capital expenditures
  $ 3,867     $ 2,990  
 
           
     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 $3.6 billion and $2.8 billion in the first six months of 2008 and 2007, respectively. 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.
     Our exploration and development capital expenditures increased $824 million in the first six months of 2008. The higher expenditures primarily relate to increased drilling activities in the Barnett Shale, Gulf of Mexico and Carthage areas of the United States. Expenditures also increased due to inflationary pressure driven by increased competition for field services.

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Net Repayments of Debt
     During the first half of 2008, we repaid $2.5 billion in outstanding credit facility and commercial paper borrowings primarily with proceeds received from the sales of assets under our African divestiture program and cash generated from operations. This compares to $183 million of commercial paper borrowings we repaid during the first half of 2007.
     Also during the first half of 2008, certain holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common stock that we own prior to the debentures’ August 15, 2008 maturity date. We have the option, in lieu of delivering shares of Chevron common stock, to pay exchanging debenture holders an amount of cash equal to the market value of Chevron common stock. We paid $47 million in cash to debenture holders who exercised their exchange rights in the first half of 2008. This amount included the retirement of debentures with a book value of $28 million and a $19 million reduction of the related embedded derivative option’s balance.
Repurchases of Common Stock
     During the first half of 2008, we repurchased 2.8 million shares for $302 million, or $106.01 per share. The 2.8 million shares include 2.0 million shares that were repurchased under our 50 million share program and 0.8 million shares that were repurchased under our ongoing, annual stock repurchase program.
Redemption of Preferred Stock
     On June 20, 2008, we redeemed all 1.5 million outstanding shares of our 6.49% Series A cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption price of $100 per share, plus accrued and unpaid dividends up to the redemption date.
Dividends
     Our common stock dividends were $141 million (or a quarterly rate of $0.16 per share) and $124 million (or a quarterly rate of $0.14 per share) in the first half of 2008 and 2007, respectively. The higher dividend rate was the primary cause of the increase in common dividends. We also paid $5 million of preferred stock dividends in the first six months of 2008 and 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 on hand and the issuance of equity securities and long-term debt. Another major source of near-term liquidity is proceeds from the sales of our operations in West Africa, including related repatriations of earnings from certain foreign subsidiaries to the United States. In the second quarter of 2008, we repatriated $1.3 billion in earnings. We expect to repatriate approximately $1.5 billion during the last six months of 2008.
Operating Cash Flow
     Our operating cash flow increased 55% to a record high of $5.2 billion in the first half of 2008. 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 various 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 to fix the price of a portion of our future oil and natural gas production. As disclosed in “Item 7A. Quantitative and Qualitative Disclosures of Market Risk” of our 2007 Annual Report on Form 10-K/A, approximately 64% of our estimated 2008 natural gas production and 12% of our estimated oil production are subject to either price collars, swaps or fixed-price contracts. Additionally, subsequent to the filing of our 2007 Annual Report, we have entered into additional gas price collars, which represent approximately 10% of our estimated 2009 natural gas production. The key terms of these 2009 price collars are included in “Item 3. Quantitative and Qualitative Disclosures of Market Risk” of this report.

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Interest Rate Swaps
     As of June 30, 2008, we had long-term debt of $4.8 billion. All of this long-term debt bears interest at fixed rates with an overall weighted-average rate of 7.6%. In July 2008, we entered into interest rate swaps to mitigate a portion of the fair value effects of interest rate fluctuations on our fixed-rate debt. Under the terms of these swaps, we receive a fixed rate and pay a variable rate on a total notional amount of $1.05 billion. The key terms of these interest rate swaps are presented in the table below.
                     
            Variable    
Notional     Fixed Rate Received     Rate Paid   Expiration
(In millions)                  
$ 500       3.90 %  
Federal funds rate
  July 18, 2013
$ 300       4.30 %  
Six month LIBOR
  July 18, 2011
$ 250       3.85 %  
Federal funds rate
  July 22, 2013
           
 
   
$ 1,050       4.00 %  
 
   
           
 
   
     Including the effects of these swaps, the weighted-average interest rate related to our fixed-rate debt was 7.2% as of July 31, 2008.
Credit Availability
     In April 2008, we extended the maturity of $2.0 billion of our existing $2.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) from April 7, 2012 to April 7, 2013. Lenders representing $0.5 billion of the Senior Credit Facility did not approve a maturity date extension. Therefore, the maturity date for $0.5 billion of the Senior Credit Facility remains at April 7, 2012.
     On August 7, 2007, we established a $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility (the “Short-Term Facility”). This facility matured on August 5, 2008 and was not extended. As a result of the Short-Term Facility’s maturity, our commercial paper program capacity decreased from $3.5 billion to $2.0 billion.
     The Senior Credit Facility contains only one material financial covenant. This covenant requires our ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no more than 65%. As of June 30, 2008, we were in compliance with this covenant. Our debt-to-capitalization ratio at June 30, 2008, as calculated pursuant to the terms of the agreement, was 16.3%.
     As of August 5, 2008, our available capacity under our Senior Credit Facility was approximately $2.4 billion. This available capacity is net of $140 million of outstanding letters of credit. There were no outstanding commercial paper or Senior Credit Facility borrowings as of August 5, 2008.
Debt Ratings
     During the first quarter of 2008, Standard and Poor’s upgraded our credit rating from BBB with a positive outlook to BBB+ with a stable outlook. During the second quarter of 2008, Fitch upgraded our credit rating from BBB with a positive outlook to BBB+ with a stable outlook. We are not aware of any potential downgrades or changes contemplated by the other rating agencies as of July 31, 2008.
Property Divestitures
     In the second quarter of 2008, we made significant progress toward completion of our African divestiture program. We completed the sales of assets in certain West African countries, including Equatorial Guinea—the largest individual transaction in the divestiture program. As a result of the sales, we received proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase price adjustments).
     We have also entered into agreements to sell our operations in Cote D’Ivoire and other countries located in West Africa for approximately $250 million. Devon is obtaining the necessary partner and government approvals for these properties and expects to complete the remaining sales during the third quarter of 2008.

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Capital Expenditures
     In February 2008, we provided guidance for our 2008 capital expenditures. At that time, we estimated capital expenditures for our oil and gas exploration and development operations would range from $5.6 billion to $5.9 billion.
     With higher than expected realized oil and gas prices through the first half of 2008 and the proceeds received from sales of assets in West Africa in the second quarter of 2008, we now have robust cash flow and liquidity that can be leveraged to optimize Devon’s value per share. In addition to repaying our commercial paper and credit facility borrowings and restarting our substantial share repurchase program, we are also increasing our planned 2008 investment in capital projects. Therefore, we have increased our estimate of 2008 capital expenditures for oil and gas exploration and development operations, which are now expected to range from $7.2 billion to $7.5 billion. A significant portion of this incremental capital is directed to additional acreage capture in North America and increased investment in the Lower Tertiary trend.
Common Stock Repurchase Programs
     Our Board of Directors approved an ongoing, annual stock repurchase program to minimize dilution resulting from restricted stock issued to, and options exercised by, employees. In 2008, the repurchase program authorizes the repurchase of up to 4.8 million shares or a cost of $422 million, whichever amount is reached first. Our Board of Directors also approved a separate program to repurchase up to 50 million shares, which expires on December 31, 2009. As of June 30, 2008, up to 4.0 million shares or $358 million can be repurchased under the ongoing, annual repurchase program and up to 48.0 million shares can be repurchased under the 50 million share repurchase program.
Auction Rate Securities
     At December 31, 2007, we held $372 million of auction rate securities, which are asset-backed securities that have an auction rate reset feature. Our auction rate securities are rated AAA—the highest rating—by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. Although our auction rate securities generally have contractual maturities of more than 20 years, the underlying interest rates on such securities are scheduled to reset every seven to 28 days. Therefore, these auction rate securities were generally priced and subsequently traded as short-term investments because of the interest rate reset feature. As a result, we considered our auction rate securities to be short-term investments at the end of 2007.
     During the first half of 2008, we reduced our auction rate securities holdings to $127 million as of June 30, 2008. However, since February 8, 2008 we have experienced difficulty selling our securities due to the failure of the auction mechanism, which provides liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature.
     From February 2008, when auctions began failing, to June 30, 2008, issuers redeemed $26 million of our auction rate securities holdings at par. Additionally, our auction rate securities holdings as of June 30, 2008 include approximately $1 million of securities that were called at par value by the issuer and were repaid on July 10, 2008. These called securities continue to be considered short-term investments as of June 30, 2008. However, based on continued auction failures and the current market for our auction rate securities, we have classified the $126 million of securities that have not been called as long-term investments as of June 30, 2008 and generally not available for short-term liquidity needs.
     As of December 31, 2007, we estimated the fair values of our short-term auction rate securities using quoted market prices. However, due to the auction failures discussed above and the lack of an active market for our long-term securities, quoted market prices for the vast majority of these securities were not available as of June 30, 2008. Therefore, we used valuation techniques that rely on unobservable inputs to estimate the fair values of our long-term auction rate securities as of June 30, 2008. These inputs were based on the AAA credit rating of the securities, the probability of full repayment of the securities considering the United States government guarantees of substantially all of the underlying student loans and the collection of all accrued interest to date. As a result of using these inputs, we concluded the estimated fair values of our long-term auction rate securities approximated the par values as of June 30, 2008. At this time, we do not believe the values of our long-term securities are impaired.

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Recently Issued Accounting Standards Not Yet Adopted
     In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 141(R), Business Combinations, which replaces Statement No. 141. Statement No. 141(R) retains the fundamental requirements of Statement No. 141 that an acquirer be identified and the acquisition method of accounting (previously called the purchase method) be used for all business combinations. Statement No. 141(R)’s scope is broader than that of Statement No. 141, which applied only to business combinations in which control was obtained by transferring consideration. By applying the acquisition method to all transactions and other events in which one entity obtains control over one or more other businesses, Statement No. 141(R) improves the comparability of the information about business combinations provided in financial reports. Statement No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures identifiable assets acquired, liabilities assumed and any noncontrolling interest in the acquiree, as well as any resulting goodwill. Statement No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We will evaluate how the new requirements of Statement No. 141(R) would impact any business combinations completed in 2009 or thereafter.
     In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin No. 51. A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. Statement No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Under Statement No. 160, noncontrolling interests in a subsidiary must be reported as a component of consolidated equity separate from the parent’s equity. Additionally, the amounts of consolidated net income attributable to both the parent and the noncontrolling interest must be reported separately on the face of the income statement. Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008 and earlier adoption is prohibited. We do not expect the adoption of Statement No. 160 to have a material impact on our financial statements and related disclosures.
     In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. Statement No. 161 requires additional disclosures about derivative and hedging activities and is effective for fiscal years and interim periods beginning after November 15, 2008. We are evaluating the impact the adoption of Statement No. 161 will have on our financial statement disclosures. However, our adoption of Statement No. 161 will not affect our current accounting for derivative and hedging activities.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Gas Collar Contracts
     We have various financial price swaps to fix the price of a portion of our 2008 gas production. We also have various financial price collars to set minimum and maximum prices on a portion of our 2008 oil and gas production. The key terms to these 2008 price swaps and collars are included in Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2007 Annual Report on Form 10-K/A.
     We have also entered into various financial price collars to set minimum and maximum prices on approximately 10% of our expected 2009 gas production. The key terms to our 2009 gas financial collar contracts are not included in our 2007 Annual Report on Form 10-K/A but are presented in the following table.
                                         
Gas Price Collar Contracts
            Floor Price   Ceiling Price
                    Weighted           Weighted
            Floor   Average   Ceiling   Average
    Volume   Range   Floor Price   Range   Ceiling Price
Period   (MMBtu/d)   ($/MMBtu)   ($/MMBtu)   ($/MMBtu)   ($/MMBtu)
First quarter.
    300,000     $ 8.00 - $8.50     $ 8.25     $ 10.60 - $14.00     $ 11.97  
Second quarter
    300,000     $ 8.00 - $8.50     $ 8.25     $ 10.60 - $14.00     $ 11.97  
Third quarter.
    300,000     $ 8.00 - $8.50     $ 8.25     $ 10.60 - $14.00     $ 11.97  
Fourth quarter
    300,000     $ 8.00 - $8.50     $ 8.25     $ 10.60 - $14.00     $ 11.97  
2009 average
    300,000     $ 8.00 - $8.50     $ 8.25     $ 10.60 - $14.00     $ 11.97  

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     The fair values of all our oil and gas hedging instruments are largely determined by estimates of the forward curves of relevant oil and gas price indexes. At June 30, 2008, a 10% increase in these forward curves would have increased the net liabilities recorded for our 2008 and 2009 commodity hedging instruments by approximately $550 million.
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 Exchange Act of 1934) were effective as of June 30, 2008 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 second quarter of 2008 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 2007 Annual Report on Form 10-K/A.
Item 1A. Risk Factors
     There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2007 Annual Report on Form 10-K/A.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
                                 
                    Total Number of   Maximum Number of
                    Shares Purchased as   Shares that May Yet
    Total   Average Price     Part of Publicly   Be Purchased Under
    Number of Shares   Paid   Announced Plans or   the Plans or
  Period   Purchased   per Share   Programs (1)   Programs (1)
April
        $             53,991,900  
May
        $             53,991,900  
June
    2,036,715     $ 116.57       2,036,715       51,955,185  
 
                               
Total
    2,036,715     $ 116.57       2,036,715          
 
                               
 
(1)   Our Board of Directors approved an ongoing, annual stock repurchase program to minimize dilution resulting from restricted stock issued to, and options exercised by, employees. In 2008, the repurchase program authorizes the repurchase of up to 4.8 million shares or a cost of $422 million, whichever amount is reached first. Our Board of Directors also approved a separate program to repurchase up to 50 million shares, which expires on December 31, 2009. All shares repurchased during the second quarter of 2008 were repurchased under the 50 million share repurchase program. As of June 30, 2008, up to 4.0 million shares or $358 million can be repurchased under the ongoing, annual repurchase program and up to 48.0 million shares can be repurchased under the 50 million share repurchase program.
Item 3. Defaults Upon Senior Securities
     None.
Item 4. Submission of Matters to a Vote of Security Holders
     (a) Devon’s Annual Meeting of Stockholders was held in Oklahoma City, Oklahoma at 8:00 a.m., local time, on Wednesday, June 4, 2008.
     (b) Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities Exchange Act of 1934, as amended. There was no solicitation in opposition to the nominees for election as Directors as listed in the Proxy Statement for the June 4, 2008 meeting and all nominees were elected.
     (c) A total of 401,657,101 shares of Devon’s common stock outstanding and entitled to vote were present at the June 4, 2008 meeting in person or by proxy, representing approximately 90.11% of the total outstanding shares. The matters voted upon were as follows:

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     1. The election of three Directors to serve on Devon’s Board of Directors until the 2011 Annual Meeting of Stockholders. A total of at least 98.65% of all voted shares were cast for approval of each nominee. The vote tabulation with respect to each nominee was as follows:
                 
            Authority
Nominee   For   Withheld
David A. Hager
    396,269,943       5,387,158  
John A. Hill
    396,241,980       5,415,121  
Mary P. Ricciardello
    396,253,911       5,403,190  
     2. Ratification of KPMG LLP as the Company’s Independent Auditors for 2008. A total of 97.99% of all voted shares were cast for ratification of KPMG LLP. The results of the votes were as follows:
         
FOR:
    393,574,431  
AGAINST:
    4,480,321  
ABSTAIN:
    3,602,349  
     3. The adoption of an amendment to the Restated Certificate of Incorporation to increase the number of authorized shares of common stock. A total of 97.07% of all voted shares were cast to increase the number of authorized shares of common stock.
         
FOR:
    389,884,929  
AGAINST:
    8,003,108  
ABSTAIN:
    3,769,064  
     4. The adoption of an amendment to the Restated Certificate of Incorporation to provide for the annual election of directors. A total of 98.06% of all voted shares were cast to provide for the annual election of directors.
         
FOR:
    393,850,136  
AGAINST:
    4,165,847  
ABSTAIN:
    3,641,118  
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
3.1
  Registrant’s Certificate of Amendment of Restated Certificate of Incorporation.
 
   
10.1
  Form of Amendment to Nonqualified Stock Option Award Agreements under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Daryl G. Smette and Lyndon C. Taylor. *
 
   
10.2
  Form of Amendment to Restricted Stock Award Agreements under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor. *
 
   
10.3
  Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and all Non-Management Directors.*
 
   
10.4
  Form of Non-Management Director Restricted Stock Award Agreement under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and all Non-Management Directors.*
 
   
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.
 
*   Compensatory plans or arrangements
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: August 7, 2008
  /s/ Danny J. Heatly    
 
       
 
  Danny J. Heatly    
 
  Vice President – Accounting and Chief Accounting Officer    

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INDEX TO EXHIBITS
     
Exhibit    
Number   Description
3.1
  Registrant’s Certificate of Amendment of Restated Certificate of Incorporation.
 
   
10.1
  Form of Amendment to Nonqualified Stock Option Award Agreements under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Daryl G. Smette and Lyndon C. Taylor. *
 
   
10.2
  Form of Amendment to Restricted Stock Award Agreements under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor. *
 
   
10.3
  Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and all Non-Management Directors.*
 
   
10.4
  Form of Non-Management Director Restricted Stock Award Agreement under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and all Non-Management Directors.*
 
   
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.
 
*   Compensatory plans or arrangements

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