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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 March 31, 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. (Check one):
Large accelerated filer þAccelerated 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 April 30, 2008, 446,162,105 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
         
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    39  
 Fourth Ammendment to Amended and Restated Credit Agreement
 Certification of Principal Executive Officer Pursuant to Section 302
 Certification of Principal Financial Officer Pursuant to Section 302
 Certification of Principal Executive Officer Pursuant to Section 906
 Certification of Principal Financial 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 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.
     “Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
     “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
                 
    March 31,     December 31,  
    2008     2007  
    (Unaudited)          
    (In millions, except share data)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 1,875     $ 1,364  
Short-term investments, at fair value
    23       372  
Accounts receivable
    2,090       1,779  
Deferred income taxes
    325       44  
Current assets held for sale
    112       120  
Other current assets
    232       235  
 
           
Total current assets
    4,657       3,914  
 
           
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($3,492 and $3,417 excluded from amortization in 2008 and 2007, respectively)
    49,816       48,473  
Less accumulated depreciation, depletion and amortization
    20,883       20,394  
 
           
 
    28,933       28,079  
Investment in Chevron Corporation common stock, at fair value
    1,211       1,324  
Goodwill
    6,054       6,172  
Long-term assets held for sale
    1,531       1,512  
Other long-term assets
    599       455  
 
           
Total assets
  $ 42,985     $ 41,456  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable — trade
  $ 1,440     $ 1,360  
Revenues and royalties due to others
    695       578  
Short-term debt
    1,446       1,004  
Derivative financial instruments, at fair value
    775        
Current portion of asset retirement obligation, at fair value
    68       82  
Current liabilities associated with assets held for sale
    173       145  
Accrued expenses and other current liabilities
    398       488  
 
           
Total current liabilities
    4,995       3,657  
 
           
Debentures exchangeable into shares of Chevron Corporation common stock
    620       641  
Other long-term debt
    5,751       6,283  
Derivative financial instruments, at fair value
    376       488  
Asset retirement obligation, at fair value
    1,377       1,236  
Long-term liabilities associated with assets held for sale
    428       404  
Other long-term liabilities
    701       699  
Deferred income taxes
    6,339       6,042  
Stockholders’ equity:
               
Preferred stock of $1.00 par value. Authorized 4,500,000 shares; issued 1,500,000 ($150 million aggregate liquidation value)
    1       1  
Common stock of $0.10 par value. Authorized 800,000,000 shares; issued 445,645,000 in 2008 and 444,214,000 in 2007
    45       44  
Additional paid-in capital
    6,820       6,743  
Retained earnings
    13,489       12,813  
Accumulated other comprehensive income
    2,043       2,405  
 
           
Total stockholders’ equity
    22,398       22,006  
 
           
Commitments and contingencies (Note 8)
               
Total liabilities and stockholders’ equity
  $ 42,985     $ 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 March 31,  
    2008     2007  
    (Unaudited)  
    (In millions, except  
    per share amounts)  
Revenues:
               
Oil sales
  $ 1,250     $ 691  
Gas sales
    1,630       1,246  
NGL sales
    328       177  
Net loss on oil and gas derivative financial instruments
    (788 )     (20 )
Marketing and midstream revenues
    555       379  
 
           
Total revenues
    2,975       2,473  
 
           
Expenses and other income, net:
               
Lease operating expenses
    506       430  
Production taxes
    134       80  
Marketing and midstream operating costs and expenses
    382       270  
Depreciation, depletion and amortization of oil and gas properties
    737       587  
Depreciation and amortization of non-oil and gas properties
    57       46  
Accretion of asset retirement obligation
    22       18  
General and administrative expenses
    148       119  
Interest expense
    102       110  
Change in fair value of non-oil and gas derivative financial instruments
    16       1  
Other income, net
    (21 )     (26 )
 
           
Total expenses and other income, net
    2,083       1,635  
Earnings from continuing operations before income tax expense
    892       838  
Income tax expense:
               
Current
    103       189  
Deferred
    138       75  
 
           
Total income tax expense
    241       264  
 
           
Earnings from continuing operations
    651       574  
Discontinued operations:
               
Earnings from discontinued operations before income tax expense
    189       137  
Income tax expense
    91       60  
 
           
Earnings from discontinued operations
    98       77  
 
           
Net earnings
    749       651  
Preferred stock dividends
    2       2  
 
           
Net earnings applicable to common stockholders
  $ 747     $ 649  
 
           
 
Basic net earnings per share:
               
Earnings from continuing operations
  $ 1.46     $ 1.29  
Earnings from discontinued operations
    0.22       0.17  
 
           
Net earnings
  $ 1.68     $ 1.46  
 
           
 
               
Diluted net earnings per share:
               
Earnings from continuing operations
  $ 1.44     $ 1.27  
Earnings from discontinued operations
    0.22       0.17  
 
           
Net earnings
  $ 1.66     $ 1.44  
 
           
 
               
Weighted average common shares outstanding:
               
Basic
    445       444  
 
           
Diluted
    449       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 March 31,  
    2008     2007  
    (Unaudited)  
    (In millions)  
 
Net earnings
  $ 749     $ 651  
Foreign currency translation:
               
Change in cumulative translation adjustment
    (382 )     83  
Income tax benefit (expense)
    17       (6 )
 
           
Total
    (365 )     77  
 
           
Pension and postretirement benefit plans:
               
Recognition of net actuarial loss and prior service cost in net earnings
    5       4  
Income tax expense
    (2 )     (1 )
 
           
Total
    3       3  
 
           
Other
          (1 )
 
           
Other comprehensive (loss) income, net of tax
    (362 )     79  
 
           
Comprehensive income
  $ 387     $ 730  
 
           
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)  
Three Months Ended March 31, 2008:
                                                               
Balance as of December 31, 2007
  $ 1       444     $ 44     $ 6,743     $ 12,813     $ 2,405     $     $ 22,006  
Net earnings
                            749                   749  
Other comprehensive loss
                                  (362 )           (362 )
Stock option exercises
          3       1       78                   (3 )     76  
Common stock repurchased
                                        (65 )     (65 )
Common stock retired
          (1 )           (68 )                 68        
Common stock dividends
                            (71 )                 (71 )
Preferred stock dividends
                            (2 )                 (2 )
Share-based compensation
                      40                         40  
Excess tax benefits on share-based compensation
                      27                         27  
 
                                               
Balance as of March 31, 2008
  $ 1       446     $ 45     $ 6,820     $ 13,489     $ 2,043     $     $ 22,398  
 
                                               
 
                                                               
Three Months Ended March 31, 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 )
Net earnings
                            651                   651  
Other comprehensive income
                                  79             79  
Stock option exercises
          1             23                         23  
Common stock retired
                      (1 )                 1        
Common stock dividends
                            (62 )                 (62 )
Preferred stock dividends
                            (2 )                 (2 )
Share-based compensation
                      30                         30  
Excess tax benefits on share-based compensation
                      5                         5  
 
                                               
Balance as of March 31, 2007
  $ 1       445     $ 44     $ 6,897     $ 10,055     $ 1,159     $     $ 18,156  
 
                                               
See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
                 
    Three Months  
    Ended March 31,  
    2008     2007  
    (Unaudited)  
    (In millions)  
Cash flows from operating activities:
               
Net earnings
  $ 749     $ 651  
Earnings from discontinued operations, net of tax
    (98 )     (77 )
Adjustments to reconcile earnings from continuing operations to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    794       633  
Deferred income tax expense
    138       75  
Net unrealized loss on oil and gas derivative financial instruments
    780       32  
Other noncash charges
    74       43  
Changes in assets and liabilities:
               
Increase in:
               
Accounts receivable
    (328 )     (29 )
Other current assets
    (39 )     (10 )
Other long-term assets
    (11 )     (25 )
Increase (decrease) in:
               
Accounts payable
    38       66  
Revenues and royalties due to others
    119       (46 )
Other current liabilities
    (167 )     89  
Other long-term liabilities
    21       (2 )
 
           
Cash provided by operating activities — continuing operations
    2,070       1,400  
Cash provided by operating activities — discontinued operations
    185       117  
 
           
Net cash provided by operating activities
    2,255       1,517  
 
           
 
               
Cash flows from investing activities:
               
Proceeds from sales of property and equipment
    105       25  
Capital expenditures
    (1,862 )     (1,484 )
Purchases of short-term investments
    (50 )     (424 )
Sales of short-term investments
    270       723  
 
           
Cash used in investing activities — continuing operations
    (1,537 )     (1,160 )
Cash used in investing activities — discontinued operations
    (24 )     (53 )
 
           
Net cash used in investing activities
    (1,561 )     (1,213 )
 
           
 
               
Cash flows from financing activities:
               
Credit facility repayments
    (1,450 )      
Credit facility borrowings
    920        
Net commercial paper borrowings (repayments)
    442       (348 )
Principal payments on debt
    (41 )      
Proceeds from stock option exercises
    74       23  
Repurchases of common stock
    (64 )      
Dividends paid on common and preferred stock
    (73 )     (64 )
Excess tax benefits related to share-based compensation
    27       5  
 
           
Net cash used in financing activities
    (165 )     (384 )
 
           
Effect of exchange rate changes on cash
    (19 )     2  
 
           
Net increase (decrease) in cash and cash equivalents
    510       (78 )
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)
  $ 1,883     $ 678  
 
           
 
               
Supplementary cash flow data:
               
Interest paid (net of capitalized interest)
  $ 136     $ 138  
Income taxes paid (received) — continuing and discontinued operations
  $ 83     $ (24 )
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.
     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 March 31, 2008 and Devon’s results of operations and cash flows for the three months ended March 31, 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 quarter of 2008, Devon reduced its auction rate securities holdings to $152 million as of March 31, 2008. 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.
     Devon’s auction rate securities holdings as of March 31, 2008 include $23 million of securities that have been called at par value by the issuer effective May 21, 2008. These called securities continue to be classified as short-term investments in the accompanying March 31, 2008 consolidated balance sheet. However, based on continued auction failures and the current market for Devon’s auction rate securities, Devon has classified the $129 million of securities that have not been called as long-term investments as of March 31, 2008. Devon has the ability to hold the securities until maturity. These securities are included in other long-term assets in the accompanying March 31, 2008 consolidated balance sheet. 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
     Devon sold its assets and terminated its operations in Egypt in the fourth quarter of 2007. Devon is also in the process of divesting its assets and terminating its operations in West Africa. Additional information regarding Devon’s Egyptian and West African operations, which are presented as discontinued in the accompanying financial statements, is provided in Note 10.
Asset Retirement Obligations (“ARO”)
     The following is a summary of the changes in Devon’s ARO for the first three months of 2008 and 2007.
                 
    Three Months Ended March 31,  
    2008     2007  
    (In millions)  
Asset retirement obligation as of beginning of period
  $ 1,318     $ 857  
Liabilities incurred
    16       28  
Liabilities settled
    (25 )     (12 )
Revision of estimated obligation
    140       311  
Accretion expense on discounted obligation
    22       18  
Foreign currency translation adjustment
    (26 )     5  
 
           
Asset retirement obligation as of end of period
    1,445       1,207  
Less current portion
    68       55  
 
           
Asset retirement obligation, long-term
  $ 1,377     $ 1,152  
 
           
     During the first quarters of 2008 and 2007, Devon recognized increases of $140 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 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 settle the difference with the counterparty to the collars.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
     As discussed more fully in Note 1 to the consolidated financial statements in Devon’s 2007 Annual Report on Form 10-K, 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 unrealized losses included in the accompanying statement of operations associated with Devon’s commodity derivative financial instruments.
                 
    March 31,     December 31,  
    2008     2007  
    (In millions)  
Fair values:
               
Other current assets — gas price swaps
  $     $ 12  
Other long-term assets — gas price collars
  $ 7     $  
Financial instruments, current liability:
               
Gas price swaps
  $ 359     $  
Gas price collars
    415        
Oil price collars
    1        
 
           
Total financial instruments, current liability
  $ 775     $  
 
           
                 
    Three Months Ended March 31,  
    2008     2007  
    (In millions)  
Cash settlements:
               
Gas price swaps
  $ (8 )   $ 10  
Gas price collars
          2  
Oil price collars
           
 
           
Total cash settlements (paid) received
    (8 )     12  
 
           
Unrealized losses on fair value changes:
               
Gas price swaps
    (371 )     (28 )
Gas price collars
    (408 )     (4 )
Oil price collars
    (1 )      
 
           
Total unrealized losses on fair value changes
    (780 )     (32 )
 
           
Net loss on oil and gas derivative financial instruments
  $ (788 )   $ (20 )
 
           
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 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.
     The Senior Credit Facility and Devon’s $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility contain 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 March 31, 2008, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at March 31, 2008, as calculated pursuant to the terms of the agreement, was 23.3%.
     As of March 31, 2008, Devon’s combined available capacity under its credit facilities was approximately $1.5 billion. This available capacity is net of $920 million of outstanding borrowings, $1.4 billion of outstanding commercial paper and $143 million of

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
outstanding letters of credit.
     As of March 31, 2008 interest rates on Devon’s borrowings under its credit facilities and commercial paper program averaged 3.2% and 3.3%, respectively.
Exchangeable Debentures
     During the first quarter 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. Devon elected to pay the exchanging debenture holders cash totaling $41 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 $25 million and reduced the related embedded derivative option’s balance by $16 million.
     As of March 31, 2008, the Chevron exchangeable debentures are due within one year. However, Devon continues to classify this debt as long-term because it has the intent and ability to refinance these debentures on a long-term basis with the available capacity under its existing credit facilities or other long-term financing arrangements.
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 March 31, 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.
                                         
    As of March 31, 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
  $ 152     $ 152     $ 23     $     $ 129  
Investment in Chevron common stock
  $ 1,211     $ 1,211     $ 1,211     $     $  
Net oil and gas price swaps and collars
  $ (768 )   $ (768 )   $     $ (768 )   $  
Embedded option in exchangeable debentures
  $ (376 )   $ (376 )   $     $ (376 )   $  
Asset retirement obligation
  $ (1,445 )   $ (1,445 )   $     $     $ (1,445 )
                                         
    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     $     $  
Oil and gas price swaps and collars
  $ 12     $ 12     $     $ 12     $  
Embedded option in exchangeable debentures
  $ (488 )   $ (488 )   $     $ (488 )   $  
Asset retirement obligation
  $ (1,318 )   $ (1,318 )   $     $     $ (1,318 )

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
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 March 31, 2008 and December 31, 2007 consisted entirely of auction rate securities, which are discussed in greater detail in Note 1. As of March 31, 2008 and 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 these securities were not available as of March 31, 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 March 31, 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 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 March 31, 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 quarter of 2008 (in millions).
         
Beginning balance
  $  
Transfers from Level 1 to Level 3
    129  
 
     
Ending balance
  $ 129  
 
     
     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 a revision 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 periods ended March 31, 2008 and 2007.
                                 
    Pension Benefits     Other Postretirement Benefits  
    Three Months     Three Months  
    Ended March 31,     Ended March 31,  
    2008     2007     2008     2007  
    (In millions)
 
Net periodic benefit cost:
                               
Service cost
  $ 10     $ 8     $     $  
Interest cost
    14       11       2       1  
Expected return on plan assets
    (13 )     (12 )            
Net actuarial loss
    4       4              
 
                       
Net periodic benefit cost
    15       11       2       1  
Other comprehensive income:
                               
Recognition of net actuarial loss in net periodic benefit cost
    (5 )     (4 )            
 
                       
Total recognized
  $ 10     $ 7     $ 2     $ 1  
 
                       
7. Stockholders’ Equity
Stock Repurchases
     During the first quarter of 2008, Devon repurchased 0.8 million shares for $64 million, or $79.37 per share. These repurchases were made under Devon’s ongoing, annual stock repurchase program approved by its Board of Directors.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
Dividends
     Devon paid common stock dividends of $71 million (or $0.16 per share) and $62 million (or $0.14 per share) in the first quarter of 2008 and first quarter of 2007, respectively. Devon also paid $2 million in the first quarters of 2008 and 2007 to preferred stockholders.
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 in association with this lawsuit and no liability has been recorded in connection therewith.
     In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain years by the Minerals Management Service (the “MMS”) have contained price thresholds, such that if the market prices for oil or natural gas exceeded the thresholds for a given year, royalty relief would not be granted for that year. Deep water leases issued in 1998 and 1999 did not include price thresholds. 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 March 31, 2008, approximately $34 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 $29 million accrued at March 31, 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.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
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.
     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 March 31, 2008, Devon’s balance sheet included $3 million of noncurrent accrued liabilities, reflected in other liabilities, related to these and other environmental remediation liabilities. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devon’s monetary exposure is not expected to be material.
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 March 31, 2008, $364 million of these proceeds had been utilized as reimbursement of past repair costs and deductible amounts. The remaining proceeds of $116 million will 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 has only been able to obtain a de minimis amount of coverage for any damage that may be caused by named windstorms in the Gulf of Mexico. Devon has not experienced any windstorm-related losses under this new insurance arrangement through March 31, 2008.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
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. 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  
    Ended March 31,  
    2008     2007  
Losses (gains) from:
               
Chevron common stock
  $ 113     $ (6 )
Option embedded in exchangeable debentures
    (97 )     8  
Interest rate swaps
          (1 )
 
           
Total
  $ 16     $ 1  
 
           
10. 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 fourth quarter of 2007, Devon completed the sale of its Egyptian operations and recognized a $90 million after-tax gain from proceeds of $341 million.
     Devon has entered into agreements to sell its operations in Equatorial Guinea, Gabon, Cote D’Ivoire and other smaller countries for $2.6 billion. Devon is obtaining the necessary partner and government approvals for these properties. Devon expects to complete the majority of these sales, including Equatorial Guinea, during the second quarter of 2008. Had these transactions closed on March 31, 2008, Devon would have recognized after-tax gains of approximately $850 million. The gains ultimately recorded when the transactions close will depend on 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 $205 million and $175 million for the three months ended March 31, 2008 and 2007, respectively.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
     The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations as of March 31, 2008 and December 31, 2007.
                 
    March 31,     December 31,  
    2008     2007  
    (In millions)  
Assets:
               
Cash
  $ 8     $ 9  
Accounts receivable
    79       83  
Other current assets
    25       28  
 
           
Current assets
  $ 112     $ 120  
 
           
 
               
Long-term assets — property and equipment, net of accumulated depreciation, depletion and amortization
  $ 1,531     $ 1,512  
 
           
 
               
Liabilities:
               
Accounts payable — trade
  $ 19     $ 23  
Revenues and royalties due to others
    5       11  
Current portion of asset retirement obligation
    9       9  
Accrued expenses and other current liabilities
    140       102  
 
           
Current liabilities
  $ 173     $ 145  
 
           
 
               
Asset retirement obligation, long-term
  $ 35     $ 35  
Deferred income taxes
    390       366  
Other long-term liabilities
    3       3  
 
           
Long-term liabilities
  $ 428     $ 404  
 
           
11. 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 periods ended March 31, 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 March 31, 2008:
                       
Earnings from continuing operations
  $ 651                  
Less preferred stock dividends
    (2 )                
 
                     
Basic earnings per share
    649       445     $ 1.46  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          4          
 
                 
Diluted earnings per share
  $ 649       449     $ 1.44  
 
                 
 
                       
Three Months Ended March 31, 2007:
                       
Earnings from continuing operations
  $ 574                  
Less preferred stock dividends
    (2 )                
 
                     
Basic earnings per share
    572       444     $ 1.29  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          6          
 
                 
Diluted earnings per share
  $ 572       450     $ 1.27  
 
                 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
     Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculations because the options are antidilutive. During the three-month periods ended March 31, 2008 and 2007, 1.8 million shares and 4.2 million shares, respectively, were excluded from the diluted earnings per share calculations.
12. 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 March 31, 2008:
                               
Current assets
  $ 1,992     $ 1,030     $ 1,635     $ 4,657  
Property and equipment, net of accumulated depreciation, depletion and amortization
    18,868       8,831       1,234       28,933  
Goodwill
    3,050       2,936       68       6,054  
Other long-term assets
    1,544       68       1,729       3,341  
 
                       
Total assets
  $ 25,454     $ 12,865     $ 4,666     $ 42,985  
 
                       
 
                               
Current liabilities
  $ 3,933     $ 573     $ 489     $ 4,995  
Long-term debt
    3,395       2,976             6,371  
Asset retirement obligation, long-term
    675       631       71       1,377  
Other long-term liabilities
    1,028       44       433       1,505  
Deferred income taxes
    4,284       1,963       92       6,339  
Stockholders’ equity
    12,139       6,678       3,581       22,398  
 
                       
Total liabilities and stockholders’ equity
  $ 25,454     $ 12,865     $ 4,666     $ 42,985  
 
                       

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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 March 31, 2008:
                               
Revenues:
                               
Oil sales
  $ 443     $ 340     $ 467     $ 1,250  
Gas sales
    1,236       389       5       1,630  
NGL sales
    266       62             328  
Net loss on oil and gas derivative financial instruments
    (788 )                 (788 )
Marketing and midstream revenues
    542       13             555  
 
                       
Total revenues
    1,699       804       472       2,975  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    266       194       46       506  
Production taxes
    79       1       54       134  
Marketing and midstream operating costs and expenses
    377       5             382  
Depreciation, depletion and amortization of oil and gas properties
    460       211       66       737  
Depreciation and amortization of non-oil and gas properties
    51       6             57  
Accretion of asset retirement obligation
    11       10       1       22  
General and administrative expenses
    114       34             148  
Interest expense
    52       50             102  
Change in fair value of non-oil and gas derivative financial instruments
    16                   16  
Other income, net
    (6 )     (5 )     (10 )     (21 )
 
                       
Total expenses and other income, net
    1,420        506       157       2,083  
 
                       
Earnings from continuing operations before income tax expense
    279       298       315       892  
Income tax expense:
                               
Current
    46       18       39       103  
Deferred
    50       48       40       138  
 
                       
Total income tax expense
    96       66       79       241  
 
                       
Earnings from continuing operations
    183       232       236       651  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
                189       189  
Income tax expense
                91       91  
 
                       
Earnings from discontinued operations
                98       98  
 
                       
Net earnings
    183       232       334       749  
Preferred stock dividends
    2                   2  
 
                       
Net earnings applicable to common stockholders
  $ 181     $ 232     $ 334     $ 747  
 
                       
 
                               
Capital expenditures, before revision of future ARO
  $ 1,311     $ 516     $ 151     $ 1,978  
Revision of future ARO
    70       73       (3 )     140  
 
                       
Capital expenditures, continuing operations
  $ 1,381     $ 589     $ 148     $ 2,118  
 
                       

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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 March 31, 2007:
                               
Revenues:
                               
Oil sales
  $ 234     $ 153     $ 304     $ 691  
Gas sales
    889       356       1       1,246  
NGL sales
    136       41             177  
Net loss on oil and gas derivative financial instruments
    (20 )                 (20 )
Marketing and midstream revenues
    371       8             379  
 
                       
Total revenues
    1,610       558       305       2,473  
 
                       
Expenses and other income, net:
                               
Lease operating expenses
    248       143       39       430  
Production taxes
    56       1       23       80  
Marketing and midstream operating costs and expenses
    266       4             270  
Depreciation, depletion and amortization of oil and gas properties
    371       160       56       587  
Depreciation and amortization of non-oil and gas properties
    41       5             46  
Accretion of asset retirement obligation
    10       7       1       18  
General and administrative expenses
    92       25       2       119  
Interest expense
    59       51             110  
Change in fair value of non-oil and gas derivative financial instruments
    2       (1 )           1  
Other income, net
    (12 )     (3 )     (11 )     (26 )
 
                       
Total expenses and other income, net
    1,133       392       110       1,635  
 
                       
Earnings from continuing operations before income tax expense
    477       166       195       838  
Income tax expense (benefit):
                               
Current
    67       62       60       189  
Deferred
    86       (1 )     (10 )     75  
 
                       
Total income tax expense
    153       61       50       264  
 
                       
Earnings from continuing operations
    324       105       145       574  
Discontinued operations:
                               
Earnings from discontinued operations before income tax expense
                137       137  
Income tax expense
                60       60  
 
                       
Earnings from discontinued operations
                77       77  
 
                       
Net earnings
    324       105       222       651  
Preferred stock dividends
    2                   2  
 
                       
Net earnings applicable to common stockholders
  $ 322     $ 105     $ 222     $ 649  
 
                       
 
                               
Capital expenditures, before revision of future ARO
  $ 943     $ 469     $ 111     $ 1,523  
Revision of future ARO
    210       99       2       311  
 
                       
Capital expenditures, continuing operations
  $ 1,153     $ 568     $ 113     $ 1,834  
 
                       

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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 period ended March 31, 2008, compared to the three-month period ended March 31, 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, 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 first quarter of 2008, we generated net earnings of $749 million, or $1.66 per diluted share, representing a 15% increase over the first quarter of 2007. Additionally, net cash provided by operating activities climbed to a record quarterly amount of $2.3 billion, representing a 49% increase over 2007. These increases in earnings and cash flow are largely attributable to the following factors:
    Production increased 10% to 58 million Boe.
 
    Our combined realized price without hedges for oil, gas and NGLs increased 38% to $55.07 per Boe.
 
    Our oil and gas hedges generated a net loss of $788 million in the first quarter of 2008, of which $780 million represented an unrealized fair value loss and $8 million represented cash payments to counterparties.
 
    Marketing and midstream operating profit increased 59% to $173 million.
 
    Per unit operating costs rose 14% to $10.99.
 
    Cash spent on capital expenditures for oil and gas exploration and development activities were $1.7 billion.
     Additionally, we have continued to make progress toward the divestitures of our West African operations. We have entered into agreements to sell our operations in Equatorial Guinea, Gabon, Cote D’Ivoire and other smaller countries for $2.6 billion. We are obtaining the necessary partner and government approvals for these properties. We expect to complete the majority of these sales, including Equatorial Guinea, during the second quarter of 2008.
Results of Operations
Revenues
Oil, Gas and NGL Sales
     The three-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 March 31,  
    2008     2007     Change(2)  
Production
                       
Oil (MMBbls)
    14       13       +7 %
Gas (Bcf)
    223       202       +10 %
NGLs (MMBbls)
    7       6       +15 %
Oil, Gas and NGLs (MMBoe)(1)
    58       53       +10 %
 
                       
Realized prices without hedges
                       
Oil (Per Bbl)
  $ 88.23     $ 52.11       +69 %
Gas (Per Mcf)
  $ 7.31     $ 6.17       +18 %
NGLs (Per Bbl)
  $ 47.40     $ 29.33       +62 %
Oil, Gas and NGLs (Per Boe)(1)
  $ 55.07     $ 39.94       +38 %
 
                       
Revenues ($ in millions)
                       
Oil sales
  $ 1,250     $ 691       +81 %
Gas sales
    1,630       1,246       +31 %
NGL sales
    328       177       +86 %
 
                   
Oil, Gas and NGL sales
  $ 3,208     $ 2,114       +52 %
 
                   
                         
    Domestic  
    Three Months Ended March 31,  
    2008     2007     Change(2)  
Production
                       
Oil (MMBbls)
    4       4       +3 %
Gas (Bcf)
    171       146       +17 %
NGLs (MMBbls)
    6       5       +21 %
Oil, Gas and NGLs (MMBoe)(1)
    39       34       +16 %
 
                       
Realized prices without hedges
                       
Oil (Per Bbl)
  $ 95.70     $ 52.22       +83 %
Gas (Per Mcf)
  $ 7.24     $ 6.08       +19 %
NGLs (Per Bbl)
  $ 44.86     $ 27.59       +63 %
Oil, Gas and NGLs (Per Boe)(1)
  $ 49.84     $ 37.29       +34 %
 
                       
Revenues ($ in millions)
                       
Oil sales
  $ 443     $ 234       +89 %
Gas sales
    1,236       889       +39 %
NGL sales
    266       136       +96 %
 
                   
Oil, Gas and NGL sales
  $ 1,945     $ 1,259       +55 %
 
                   

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    Canada  
    Three Months Ended March 31,  
    2008     2007     Change(2)  
Production
                       
Oil (MMBbls)
    5       4       +33 %
Gas (Bcf)
    52       56       -7 %
NGLs (MMBbls)
    1       1       -11 %
Oil, Gas and NGLs (MMBoe)(1)
    14       14       +3 %
 
                       
Realized prices without hedges
                       
Oil (Per Bbl)
  $ 72.68     $ 43.51       +67 %
Gas (Per Mcf)
  $ 7.53     $ 6.43       +17 %
NGLs (Per Bbl)
  $ 62.67     $ 37.03       +69 %
Oil, Gas and NGLs (Per Boe)(1)
  $ 55.42     $ 39.71       +40 %
 
                       
Revenues ($ in millions)
                       
Oil sales
  $ 340     $ 153       +123 %
Gas sales
    389       356       +9 %
NGL sales
    62       41       +51 %
 
                   
Oil, Gas and NGL sales
  $ 791     $ 550       +44 %
 
                   
                         
    International  
    Three Months Ended March 31,  
    2008     2007     Change(2)  
Production
                       
Oil (MMBbls)
    5       5       -8 %
Gas (Bcf)
                +105 %
NGLs (MMBbls)
                N/M  
Oil, Gas and NGLs (MMBoe)(1)
    5       5       -7 %
 
                       
Realized prices without hedges
                       
Oil (Per Bbl)
  $ 96.08     $ 57.72       +66 %
Gas (Per Mcf)
  $ 8.41     $ 3.21       +162 %
NGLs (Per Bbl)
  $     $       N/M  
Oil, Gas and NGLs (Per Boe)(1)
  $ 95.24     $ 57.40       +66 %
 
                       
Revenues ($ in millions)
                       
Oil sales
  $ 467     $ 304       +53 %
Gas sales
    5       1       +437 %
NGL sales
                N/M  
 
                   
Oil, Gas and NGL sales
  $ 472     $ 305       +54 %
 
                   
 
(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 March 31, 2008 and 2007.
                                 
    Oil     Gas     NGLs     Total  
    (In millions)  
2007 sales
  $ 691     $ 1,246     $ 177     $ 2,114  
Changes due to volumes
    47       131       26       204  
Changes due to prices
    512       253       125       890  
 
                       
2008 sales
  $ 1,250     $ 1,630     $ 328     $ 3,208  
 
                       
Oil Sales
     Oil sales increased $47 million due to a one million barrel, or 7%, increase in production. The increase in production was primarily due to increased development activity in our Lloydminster area in Canada.
     Oil sales increased $512 million as a result of a 69% increase in our realized price without hedges. The average NYMEX West Texas Intermediate index price increased 67% during the same time period, accounting for the majority of the increase.
Gas Sales
     A 21 Bcf, or 10%, increase in production caused gas sales to increase by $131 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 20 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 $253 million as a result of an 18% 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.
Net Loss on Oil and Gas Derivative Financial Instruments
     The following tables provide financial information associated with our oil and gas hedges for the first quarter of 2008 and 2007. The first table presents the cash settlements and unrealized losses 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 first quarter of 2008 and 2007. The prices do not include the effects of the unrealized losses for the first quarter of 2008 and 2007.
                 
    Three Months Ended March 31,  
    2008     2007  
    (In millions)  
Cash settlements:
               
Gas price swaps
  $ (8 )   $ 10  
Gas price collars
          2  
Oil price collars
           
 
           
Total cash settlements (paid) received
    (8 )     12  
 
           
Unrealized losses on fair value changes:
               
Gas price swaps
    (371 )     (28 )
Gas price collars
    (408 )     (4 )
Oil price collars
    (1 )      
 
           
Total unrealized losses on fair value changes
    (780 )     (32 )
 
           
Net loss on oil and gas derivative financial instruments
  $ (788 )   $ (20 )
 
           

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    Three Months Ended March 31, 2008  
    Oil     Gas     NGLs     Total  
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
Realized price without hedges
  $ 88.23     $ 7.31     $ 47.40     $ 55.07  
Cash settlements of hedges
          (0.04 )           (0.14 )
 
                       
Realized price, including cash settlements
  $ 88.23     $ 7.27     $ 47.40     $ 54.93  
 
                       
                                 
    Three Months Ended March 31, 2007  
    Oil     Gas     NGLs     Total  
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
Realized price without hedges
  $ 52.11     $ 6.17     $ 29.33     $ 39.94  
Cash settlements of hedges
          0.06             0.22  
 
                       
Realized price, including cash settlements
  $ 52.11     $ 6.23     $ 29.33     $ 40.16  
 
                       
     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 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.
     During the first quarter of 2008, we paid $8 million, or $0.04 per Mcf, to counterparties to settle our gas price swaps. During the first quarter of 2007, we received $12 million, or $0.06 per Mcf, 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 March 31, 2008, a 10% increase in these forward curves would have increased our first quarter 2008 unrealized loss for our oil and gas derivative financial instruments by approximately $500 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 first quarter of 2008, we recognized unrealized losses totaling $779 million related to our gas derivative instruments. This loss results primarily from a significant increase in the Inside FERC Henry Hub forward curve subsequent to the trade dates for our gas price swaps and collars.
     During the first quarter of 2007, we recognized unrealized losses totaling $32 million related to our gas derivative instruments.

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Table of Contents

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 March 31, 2008 and 2007 are shown in the table below.
                         
    Three Months Ended March 31,  
    2008     2007     Change(1)  
Marketing and midstream ($ in millions):
                       
Revenues
  $ 555     $ 379       +46 %
Operating costs and expenses
    382       270       +41 %
 
                   
Operating profit
  $ 173     $ 109       +59 %
 
                   
 
(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 $176 million and operating costs and expenses also increased $112 million, causing operating profit to increase $64 million. Revenues and expenses increased primarily due to higher natural gas and NGL prices, as well as higher gas pipeline throughput in the Barnett Shale.
Oil, Gas and NGL Production and Operating Expenses
     The three-month comparison of oil, gas and NGL production and operating expenses are shown in the table below.
                         
    Three Months Ended March 31,  
    2008     2007     Change(1)  
Production and operating expenses ($ in millions):
                       
Lease operating expenses
  $ 506     $ 430       +18 %
Production taxes
    134       80       +66 %
 
                   
Total production and operating expenses
  $ 640     $ 510       +25 %
 
                   
 
                       
Production and operating expenses per Boe:
                       
Lease operating expenses
  $ 8.69     $ 8.13       +7 %
Production taxes
    2.30       1.52       +51 %
 
                   
Total production and operating expenses per Boe
  $ 10.99     $ 9.65       +14 %
 
                   
 
(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 $76 million in the first quarter of 2008. The largest contributor to this increase was our 10% growth in production, which caused an increase of $43 million. Furthermore, changes in the exchange rate between the U.S. and Canadian dollar also caused LOE to increase $28 million. This exchange rate effect was also the primary factor causing LOE per Boe to increase.

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Table of Contents

Production Taxes
     The following table details the changes in production taxes between the three months ended March 31, 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  
    Ended March 31,  
    (In millions)  
2007 production taxes
  $ 80  
Change due to revenues
    42  
Change due to rate
    12  
 
     
2008 production taxes
  $ 134  
 
     
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 months ended March 31, 2008 and 2007 are shown in the table below.
                         
    Three Months Ended March 31,  
    2008     2007     Change(1)  
 
                       
Total production volumes (MMBoe)
    58       53       +10 %
DD&A rate ($  per Boe)
  $ 12.64     $ 11.09       +14 %
 
                   
DD&A expense ($ in millions)
  $ 737     $ 587       +25 %
 
                   
 
(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 ended March 31, 2008 and 2007.
         
    Three Months  
    Ended March 31,  
    (In millions)  
2007 DD&A
  $ 587  
Change due to volumes
    59  
Change due to rate
    91  
 
     
2008 DD&A
  $ 737  
 
     
     The 10% production increase caused oil and gas property related DD&A to increase $59 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 both 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 the transfer of previously unproved costs to the depletable base as a result of 2007 and 2008 drilling activities and a higher Canadian-to-U.S. dollar exchange rate in 2008.

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General and Administrative Expenses (“G&A”)
     The following schedule includes the components of G&A expense for the three months ended March 31, 2008 and 2007.
                         
    Three Months Ended March 31,  
    2008     2007     Change (1)  
    (In millions)          
Gross G&A
  $ 277     $ 212       +31 %
Capitalized G&A
    (99 )     (64 )     +55 %
Reimbursed G&A
    (30 )     (29 )     +4 %
 
                   
Net G&A
  $ 148     $ 119       +24 %
 
                   
 
(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.
     Gross G&A increased $65 million in the first quarter of 2008 compared to the same period of 2007. Higher employee compensation and benefits costs related to our workforce growth and industry inflation caused gross G&A to increase $55 million. The $35 million increase in capitalized G&A during the first quarter of 2008 is also primarily due to higher employee compensation and benefits costs.
Interest Expense
     The following schedule includes the components of interest expense for the three months ended March 31, 2008 and 2007.
                 
    Three Months  
    Ended Mach 31,  
    2008     2007  
    (In millions)  
Interest based on debt outstanding
  $ 126     $ 128  
Capitalized interest
    (31 )     (23 )
Other
    7       5  
 
           
Total
  $ 102     $ 110  
 
           
     Capitalized interest increased primarily due to an increase in development activities and related accumulated costs for projects in the Gulf of Mexico and Brazil.
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 ended March 31, 2008 and 2007.
                 
    Three Months  
    Ended March 31,  
    2008     2007  
    (In millions)  
Losses (gains) from:
               
Investment in Chevron common stock
  $ 113     $ (6 )
Option embedded in exchangeable debentures
    (97 )     8  
Interest rate swaps
          (1 )
 
           
Total
  $ 16     $ 1  
 
           

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     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 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 2008 loss on our investment in Chevron common stock and gain on the embedded option were directly attributable to a $7.97 decrease in the price per share of Chevron’s common stock during the first quarter of 2008. The 2007 gain on our investment in Chevron common stock and loss on the embedded option were directly attributable to a $0.43 increase in the price per share of Chevron’s common stock during the first quarter 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 first quarters of 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  
    Ended Mach 31,  
    2008     2007  
 
               
Total income tax expense (In millions)
  $ 241     $ 264  
 
               
U.S. statutory income tax rate
    35 %     35 %
Canadian statutory rate reductions
    (1 %)      
Other, primarily taxation on foreign operations
    (7 %)     (3 %)
 
           
Effective income tax rate
    27 %     32 %
 
           
     In the first quarters of both 2008 and 2007, our effective income tax rate was 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 2008 effective income tax rate was lower than the 2007 rate largely due to Canadian Federal and provincial statutory rate reductions enacted subsequent to the first quarter of 2007. Additionally, in the first quarter of 2008, deferred income taxes were reduced $7 million due to statutory rate reductions enacted by the British Columbia and Saskatchewan provincial governments in Canada.
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, Cote D’Ivoire, Gabon and other countries in the region.

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     Following are the components of earnings from discontinued operations for the three months ended March 31, 2008 and 2007.
                 
    Three Months  
    Ended March 31,  
    2008     2007  
    (In millions)  
Earnings from discontinued operations before income taxes
  $ 189     $ 137  
Income tax expense
    91       60  
 
           
Earnings from discontinued operations
  $ 98     $ 77  
 
           
     Earnings from discontinued operations increased $21 million in the first quarter of 2008. In addition to variances caused by changes in production volumes and realized prices, our earnings from discontinued operations in 2008 were impacted by other significant factors. As a result of closing the sale of our Egyptian operations in the fourth quarter of 2007, we had no earnings from our Egyptian operations in the first quarter of 2008. Egypt accounted for $11 million of earnings from discontinued operations in the first quarter of 2007. Also, pursuant to accounting rules for discontinued operations, we ceased recording DD&A in January 2007 for our West African operations. During January 2007, prior to the decision to divest our West African properties, we recorded $16 million ($9 million after tax) of DD&A associated with these properties.
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
                 
    Three Months Ended March 31,  
    2008     2007  
    (In millions)  
Sources of cash and cash equivalents:
               
Operating cash flow — continuing operations
  $ 2,070     $ 1,400  
Sales of property and equipment
    105       25  
Stock option exercises
    74       23  
Net sales of short-term investments
    220       299  
Other
    27       5  
 
           
Total sources of cash and cash equivalents
    2,496       1,752  
 
           
 
               
Uses of cash and cash equivalents:
               
Capital expenditures
    (1,862 )     (1,484 )
Net repayments of debt
    (129 )     (348 )
Repurchases of common stock
    (64 )      
Dividends
    (73 )     (64 )
 
           
Total uses of cash and cash equivalents
    (2,128 )     (1,896 )
 
           
 
               
Increase (decrease) from continuing operations
    368       (144 )
Increase from discontinued operations
    161       64  
Effect of foreign exchange rates
    (19 )     2  
 
           
Net increase (decrease) in cash and cash equivalents
  $ 510     $ (78 )
 
           
 
               
Cash and cash equivalents at end of period
  $ 1,883     $ 678  
 
           
Short-term investments at end of period
  $ 23     $ 275  
 
           

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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 quarter 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 quarter of 2008, our operating cash flow was sufficient to fund our capital expenditures. Additionally, during 2007, operating cash flow was used to fund substantially 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 $220 million. This source of cash and our operating cash flow in excess of capital expenditures were primarily used to fund debt repayments, common stock repurchases and dividends on common and preferred stock.
     As of March 31, 2008, our credit facility borrowings had an average interest rate of 3.2% and our commercial paper borrowings had an average interest rate of 3.3%.
     During 2007, we reduced our short-term investment balances by $299 million to supplement our operating cash flow and fund debt repayments.
Capital Expenditures
     Following are the components of our capital expenditures for the first quarters of 2008 and 2007.
                 
    Three Months  
    Ended March 31,  
    2008     2007  
    (In millions)  
U.S. Onshore
  $ 959     $ 726  
U.S. Offshore
    244       168  
Canada
    415       374  
International
    110       91  
 
           
Total exploration and development
    1,728       1,359  
Midstream
    104       83  
Other
    30       42  
 
           
Total capital expenditures
  $ 1,862     $ 1,484  
 
           
     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 $1.7 billion and $1.4 billion in the first quarters 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.

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     Our exploration and development capital expenditures increased $369 million in the first quarter 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.
Net Repayments of Debt
     During the first quarter of 2008, we reduced our credit facility and commercial paper borrowings by $88 million. Also during the first quarter 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 $41 million in cash to debenture holders who exercised their exchange rights in the first quarter of 2008. This amount included the retirement of debentures with a book value of $25 million and a $16 million reduction of the related embedded derivative option’s balance.
     During the first quarter of 2007, we repaid $348 million of commercial paper borrowings.
Repurchases of Common Stock
     During the first quarter of 2008, we repurchased 0.8 million shares for $64 million, or $79.37 per share under our ongoing, annual repurchase program approved by our Board of Directors.
Dividends
     Our common stock dividends were $71 million ($0.16 per share) and $62 million ($0.14 per share) in the first quarter of 2008 and 2007, respectively. The higher dividend rate was the primary cause of the increase in common dividends. We also paid $2 million of preferred stock dividends in the first quarters 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 and short-term investments on hand and the issuance of equity securities and long-term debt. Another major source of near-term liquidity will be proceeds from the sales of our operations in West Africa.
Operating Cash Flow
     Our operating cash flow increased 49% to a record high of $2.3 billion in the first quarter 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, 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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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.
     The Senior Credit Facility and our $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility contain 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 March 31, 2008, we were in compliance with this covenant. Our debt-to-capitalization ratio at March 31, 2008, as calculated pursuant to the terms of the agreement, was 23.3%.
     As of March 31, 2008, our combined available capacity under our credit facilities was approximately $1.5 billion. This available capacity is net of $920 million of outstanding borrowings, $1.4 billion of outstanding commercial paper and $143 million of outstanding letters of credit.
     As of March 31, 2008, interest rates on our borrowings under our credit facilities and commercial paper program averaged 3.2% and 3.3%, respectively.
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. We are not aware of any potential downgrades or changes contemplated by the other rating agencies as of April 30, 2008.
Property Divestitures
     We have continued to make progress toward the divestitures of our West African operations. We have entered into agreements to sell our operations in Equatorial Guinea, Gabon, Cote D’Ivoire and other smaller countries for $2.6 billion. We are obtaining the necessary partner and government approvals for these properties. We expect to complete the majority of these sales, including Equatorial Guinea, during the second quarter of 2008.
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 quarter of 2008, we reduced our auction rate securities holdings to $152 million as of March 31, 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.
     Our auction rate securities holdings as of March 31, 2008 include $23 million of securities that have been called at par value by the issuer effective May 21, 2008. Therefore, these called securities continue to be considered short-term investments as of March 31, 2008. However, based on continued auction failures and the current market for our auction rate securities, we now consider the $129 million of securities that have not been called to be long-term investments as of March 31, 2008 and generally not available for short-term liquidity needs.

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     As of March 31, 2008 and 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 these securities were not available as of March 31, 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 March 31, 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 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 March 31, 2008. At this time, we do not believe the values of our 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. 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.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk
     Subsequent to filing our 2007 Annual Report on Form 10-K, we entered into various 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 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  
     The fair values of our oil and gas hedging instruments are largely determined by estimates of the forward curves of relevant oil and gas price indexes. At March 31, 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 $500 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 March 31, 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 first 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.
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.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
                                 
                    Total Number of   Maximum Number of
    Total           Shares Purchased as   Shares that May Yet
    Number of   Average Price   Part of Publicly   Be Purchased Under
    Shares   Paid per   Announced Plans or   the Plans or
Period   Purchased   Share   Programs(1)   Programs(1)
January
    808,100     $ 79.37       808,100       53,991,900  
February
        $             53,991,900  
March
        $             53,991,900  
 
                               
Total
    808,100     $ 79.37       808,100          
 
                               
 
(1)   Devon’s 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. All shares repurchased in 2008 were made in conjunction with this plan. Also, in anticipation of the completion of our West African divestitures, our Board of Directors approved a separate program to repurchase up to 50 million shares. This program expires on December 31, 2009.
Item 3. Defaults Upon Senior Securities
     None.
Item 4. Submission of Matters to a Vote of Security Holders
     None.
Item 5. Other Information
     None.

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Item 6. Exhibits
     (a) Exhibits required by Item 601 of Regulation S-K are as follows:
     
Exhibit    
Number   Description
10.1
  Fourth Amendment to Amended and Restated Credit Agreement dated as of April 7, 2008, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto.
 
   
31.1
  Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2
  Certification of Danny J. Heatly, Vice President — Accounting and Chief Accounting Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1
  Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
32.2
  Certification of Danny J. Heatly, Vice President — Accounting and Chief Accounting Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  DEVON ENERGY CORPORATION
 
 
Date: May 8, 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
10.1
  Fourth Amendment to Amended and Restated Credit Agreement dated as of April 7, 2008, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto.
 
   
31.1
  Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2
  Certification of Danny J. Heatly, Vice President — Accounting and Chief Accounting Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1
  Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
32.2
  Certification of Danny J. Heatly, Vice President — Accounting and Chief Accounting Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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