10-Q 1 d83899e10vq.htm FORM 10-Q e10vq
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2011
or
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-32318
DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
     
Delaware
(State of other jurisdiction of incorporation or organization)
  73-1567067
(I.R.S. Employer identification No.)
     
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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ   No o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer o  Non-accelerated filer o
(Do not check if a smaller reporting company)
Smaller reporting company o
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o   No þ
     On July 22, 2011, 416.5 million shares of common stock were outstanding.
 
 

 


 

DEVON ENERGY CORPORATION
FORM 10-Q
For the Quarterly Period Ended June 30, 2011
INDEX
         
 
       
    3  
 
       
    4  
 
       
     
    5  
    5  
    6  
    7  
    8  
    9  
    10  
    27  
    40  
    41  
 
       
       
    42  
    42  
    42  
    42  
    42  
    42  
 
       
    43  
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT

2


Table of Contents

DEFINITIONS
Measurements of Oil, Natural Gas and Natural Gas Liquids
    “NGL” or “NGLs” means natural gas liquids.
 
    “Oil” includes crude oil and condensate.
 
    “Bbl” means barrel of oil. One barrel equals 42 U.S. gallons.
    “MBbls” means thousand barrels.
 
    “MMBbls” means million barrels.
 
    “MBbls/d” means thousand barrels per day.
    “Mcf” means thousand cubic feet of natural gas.
    “MMcf” means million cubic feet.
 
    “Bcf” means billion cubic feet.
 
    “Bcfe” means billion cubic feet equivalent.
 
    “MMcf/d” means million cubic feet per day.
    “Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
    “MBoe” means thousand Boe.
 
    “MMBoe” means million Boe.
 
    “MBoe/d” means thousand Boe per day.
    “Btu” means British thermal units, a measure of heating value.
    “MMBtu” means million Btu.
 
    “MMBtu/d” means million Btu per day.
Geographic Areas
    “Canada” means the operations of Devon encompassing oil and gas properties located in Canada.
 
    “International” means the discontinued operations of Devon that encompass oil and gas properties that lie outside the United States and Canada.
 
    “North America Onshore” means the operations of Devon encompassing oil and gas properties in the continental United States and Canada.
 
    “U.S. Offshore” means the divested operations of Devon that encompassed oil and gas properties in the Gulf of Mexico.
 
    “U.S. Onshore” means the properties of Devon encompassing oil and gas properties in the continental United States.
Other
    “FASB” means the United States Financial Accounting Standards Board.
 
    “Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal Reserve to other depository institutions overnight.
 
    “Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
 
    “LIBOR” means London Interbank Offered Rate.
 
    “NYMEX” means New York Mercantile Exchange.
 
    “SEC” means United States Securities and Exchange Commission.

3


Table of Contents

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 used to prepare the December 31, 2010 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, including the supply and demand for oil, gas, NGLs and other products or services, as well as the prices of oil, gas, NGLs and other products or services, including regional pricing differentials;
 
    production levels, including Canadian production subject to government royalties, which fluctuate with prices and production;
 
    reserve levels;
 
    competitive conditions;
 
    technology;
 
    the availability of capital resources within the securities or capital markets and related risks such as general credit, liquidity, market and interest-rate risks;
 
    capital expenditure and other contractual obligations;
 
    currency exchange rates;
 
    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;
 
    public policy and government regulatory changes, including changes in royalty, production tax and income tax regimes, changes in hydraulic fracturing regulation and changes in environmental laws, regulation and liability;
 
    terrorism;
 
    occurrence of property acquisitions or divestitures; and
 
    other factors disclosed in Devon’s 2010 Annual Report on Form 10-K under “Item 1A. Risk Factors,” “Item 2. Properties,” “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.

4


Table of Contents

PART I. Financial Information
Item 1. Consolidated Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
                 
    June 30,     December 31,  
    2011     2010  
    (Unaudited)          
    (In millions, except share data)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 3,351     $ 2,866  
Short-term investments
    3,367       145  
Accounts receivable
    1,446       1,202  
Current assets held for sale
    36       563  
Other current assets
    711       779  
 
           
Total current assets
    8,911       5,555  
 
           
Property and equipment, at cost:
               
Oil and gas, based on full cost accounting:
               
Subject to amortization
    59,423       56,012  
Not subject to amortization
    3,915       3,434  
 
           
Total oil and gas
    63,338       59,446  
Other
    4,732       4,429  
 
           
Total property and equipment, at cost
    68,070       63,875  
Less accumulated depreciation, depletion and amortization
    (45,643 )     (44,223 )
 
           
Property and equipment, net
    22,427       19,652  
 
           
Goodwill
    6,176       6,080  
Long-term assets held for sale
    94       859  
Other long-term assets
    929       781  
 
           
Total assets
  $ 38,537     $ 32,927  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable — trade
  $ 1,365     $ 1,411  
Revenues and royalties due to others
    669       538  
Short-term debt
    1,962       1,811  
Current liabilities associated with assets held for sale
    43       305  
Other current liabilities
    445       518  
 
           
Total current liabilities
    4,484       4,583  
 
           
Long-term debt
    5,968       3,819  
Asset retirement obligations
    1,499       1,423  
Liabilities associated with assets held for sale
    2       26  
Other long-term liabilities
    808       1,067  
Deferred income taxes
    4,348       2,756  
Stockholders’ equity:
               
Common stock of $0.10 par value. Authorized 1.0 billion shares; issued 418.3 million and 431.9 million shares in 2011 and 2010, respectively
    42       43  
Additional paid-in capital
    4,489       5,601  
Retained earnings
    14,901       11,882  
Accumulated other comprehensive earnings
    2,021       1,760  
Treasury stock, at cost. 0.3 million and 0.4 million shares in 2011 and 2010, respectively
    (25 )     (33 )
 
           
Total stockholders’ equity
    21,428       19,253  
 
           
Commitments and contingencies (Note 11)
               
Total liabilities and stockholders’ equity
  $ 38,537     $ 32,927  
 
           
See accompanying notes to consolidated financial statements.

5


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
    (Unaudited)  
    (In millions, except  
    per share amounts)  
Revenues:
                               
Oil, gas and NGL sales
  $ 2,200     $ 1,782     $ 4,060     $ 3,852  
Oil, gas and NGL derivatives
    416       45       248       665  
Marketing and midstream revenues
    604       405       1,059       935  
 
                       
Total revenues
    3,220       2,232       5,367       5,452  
 
                       
Expenses and other, net:
                               
Lease operating expenses
    453       442       877       856  
Taxes other than income taxes
    120       92       228       193  
Marketing and midstream operating costs and expenses
    456       280       789       677  
Depreciation, depletion and amortization of oil and gas properties
    485       426       927       852  
Depreciation and amortization of non-oil and gas properties
    65       63       129       126  
Accretion of asset retirement obligations
    23       24       46       50  
General and administrative expenses
    135       130       265       268  
Restructuring costs
    6       (8 )     1       (8 )
Interest expense
    85       111       166       197  
Interest-rate and other financial instruments
    25       81       8       66  
Other, net
    (11 )     (22 )     (27 )     (26 )
 
                       
Total expenses and other, net
    1,842       1,619       3,409       3,251  
 
                       
Earnings from continuing operations before income taxes
    1,378       613       1,958       2,201  
 
                       
Income tax expense (benefit):
                               
Current
    36       707       (53 )     1,006  
Deferred
    1,158       (446 )     1,438       (231 )
 
                       
Total income tax expense
    1,194       261       1,385       775  
 
                       
Earnings from continuing operations
    184       352       573       1,426  
 
                       
Discontinued operations:
                               
Earnings from discontinued operations before income taxes
    2,558       473       2,588       610  
Discontinued operations income tax (benefit) expense
    (1 )     119       2       138  
 
                       
Earnings from discontinued operations
    2,559       354       2,586       472  
 
                       
Net earnings
  $ 2,743     $ 706     $ 3,159     $ 1,898  
 
                       
 
                               
Basic net earnings per share:
                               
Basic earnings from continuing operations per share
  $ 0.44     $ 0.79     $ 1.35     $ 3.20  
Basic earnings from discontinued operations per share
    6.06       0.80       6.09       1.06  
 
                       
Basic net earnings per share
  $ 6.50     $ 1.59     $ 7.44     $ 4.26  
 
                       
 
                               
Diluted net earnings per share:
                               
Diluted earnings from continuing operations per share
  $ 0.43     $ 0.79     $ 1.34     $ 3.19  
Diluted earnings from discontinued operations per share
    6.05       0.79       6.07       1.05  
 
                       
Diluted net earnings per share
  $ 6.48     $ 1.58     $ 7.41     $ 4.24  
 
                       
See accompanying notes to consolidated financial statements.

6


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
    (Unaudited)  
    (In millions)  
 
                               
Net earnings
  $ 2,743     $ 706     $ 3,159     $ 1,898  
Foreign currency translation:
                               
Change in cumulative translation adjustment
    67       (326 )     262       (104 )
Foreign currency translation income tax (expense) benefit
    (2 )     17       (12 )     5  
 
                       
Foreign currency translation total
    65       (309 )     250       (99 )
 
                       
Pension and postretirement benefit plans:
                               
Recognition of net actuarial loss and prior service cost in earnings
    8       8       17       16  
Pension and postretirement benefit plans income tax expense
    (3 )     (3 )     (6 )     (6 )
 
                       
Pension and postretirement benefit plans total
    5       5       11       10  
 
                       
Other comprehensive earnings (loss), net of tax
    70       (304 )     261       (89 )
 
                       
Comprehensive earnings
  $ 2,813     $ 402     $ 3,420     $ 1,809  
 
                       
See accompanying notes to consolidated financial statements.

7


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
                                                         
                                    Accumulated                
                    Additional             Other             Total  
    Common Stock     Paid-In     Retained     Comprehensive     Treasury     Stockholders’  
    Shares     Amount     Capital     Earnings     Earnings     Stock     Equity  
    (Unaudited)  
    (In millions)  
Six Months Ended June 30, 2011:
                                                       
Balance as of December 31, 2010
    432     $ 43     $ 5,601     $ 11,882     $ 1,760     $ (33 )   $ 19,253  
Net earnings
                      3,159                   3,159  
Other comprehensive earnings (loss), net of tax
                            261             261  
Stock option exercises
    2             96                         96  
Common stock repurchased
                                  (1,285 )     (1,285 )
Common stock retired
    (16 )     (1 )     (1,292 )                 1,293        
Common stock dividends
                      (140 )                 (140 )
Share-based compensation
                72                         72  
Share-based compensation tax benefits
                12                         12  
 
                                         
Balance as of June 30, 2011
    418     $ 42     $ 4,489     $ 14,901     $ 2,021     $ (25 )   $ 21,428  
 
                                         
 
                                                       
Six Months Ended June 30, 2010:
                                                       
Balance as of December 31, 2009
    447     $ 45     $ 6,527     $ 7,613     $ 1,385     $     $ 15,570  
Net earnings
                      1,898                   1,898  
Other comprehensive earnings (loss), net of tax
                            (89 )           (89 )
Stock option exercises
                15                         15  
Common stock repurchased
                                  (503 )     (503 )
Common stock retired
    (7 )     (1 )     (437 )                 438        
Common stock dividends
                      (142 )                 (142 )
Share-based compensation
                75                         75  
Share-based compensation tax benefits
                6                         6  
 
                                         
Balance as of June 30, 2010
    440     $ 44     $ 6,186     $ 9,369     $ 1,296     $ (65 )   $ 16,830  
 
                                         
See accompanying notes to consolidated financial statements.

8


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
                 
    Six Months  
    Ended June 30,  
    2011     2010  
    (Unaudited)  
    (In millions)  
Cash flows from operating activities:
               
Net earnings
  $ 3,159     $ 1,898  
Earnings from discontinued operations, net of tax
    (2,586 )     (472 )
Adjustments to reconcile earnings from continuing operations to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    1,056       978  
Deferred income tax expense (benefit)
    1,438       (231 )
Unrealized change in fair value of financial instruments
    (74 )     (231 )
Other noncash charges
    82       81  
Net (increase) decrease in working capital
    (89 )     581  
Decrease in long-term other assets
    45       14  
(Decrease) increase in long-term other liabilities
    (201 )     1  
 
           
Cash from operating activities — continuing operations
    2,830       2,619  
Cash from operating activities — discontinued operations
    (20 )     273  
 
           
Net cash from operating activities
    2,810       2,892  
 
           
 
               
Cash flows from investing activities:
               
Capital expenditures
    (3,720 )     (3,221 )
Proceeds from property and equipment divestitures
    5       4,129  
Purchases of short-term investments
    (4,520 )      
Redemptions of short-term investments
    1,298        
Redemptions of long-term investments
    1       18  
Other
    (33 )      
 
           
Cash from investing activities — continuing operations
    (6,969 )     926  
Cash from investing activities — discontinued operations
    3,170       429  
 
           
Net cash from investing activities
    (3,799 )     1,355  
 
           
 
               
Cash flows from financing activities:
               
Net commercial paper borrowings (repayments)
    2,340       (1,432 )
Debt repayments
          (350 )
Proceeds from stock option exercises
    96       15  
Repurchases of common stock
    (1,290 )     (430 )
Dividends paid on common stock
    (140 )     (142 )
Excess tax benefits related to share-based compensation
    12       6  
 
           
Net cash from financing activities
    1,018       (2,333 )
 
           
Effect of exchange rate changes on cash
    32       (9 )
 
           
Net increase in cash and cash equivalents
    61       1,905  
Cash and cash equivalents at beginning of period (including cash related to assets held for sale)
    3,290       1,011  
 
           
Cash and cash equivalents at end of period (including cash related to assets held for sale)
  $ 3,351     $ 2,916  
 
           
See accompanying notes to consolidated financial statements.

9


Table of Contents

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 2010 Annual Report on Form 10-K.
     The unaudited interim consolidated financial statements furnished in this report reflect all adjustments that are, in the opinion of management, necessary to a fair statement of Devon’s financial position as of June 30, 2011 and Devon’s results of operations and cash flows for the three-month and six-month periods ended June 30, 2011 and 2010.
Recently Issued Accounting Standards Not Yet Adopted
     In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. However, beginning in Devon’s 2011 Annual Report on Form 10-K, this update will require certain additional disclosures related to Devon’s fair value measurements. Devon does not expect the adoption of this update will materially impact its financial statement disclosures.
     In June 2011, the FASB issued Accounting Standards Update 2011-05, Presentation of Comprehensive Income. Beginning in Devon’s 2011 Annual Report on Form 10-K, this update will give Devon the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Devon has not determined which presentation option it will choose but does not expect its selection to materially impact the presentation of its financial statements.
2. Short-Term Investments
     Devon periodically invests excess cash in U.S. Treasury and other marketable securities that are presented as short-term investments in the accompanying June 30, 2011 consolidated balance sheet. During the first half of 2011, Devon invested a portion of the International offshore divestiture proceeds it had received into United States Treasury securities, causing short-term investments to increase. The carrying value of these investments approximates their fair value. As of June 30, 2011, the average remaining maturity of these investments was 67 days, with a weighted average yield of 0.06 percent.
3. Accounts Receivable
     The components of accounts receivable include the following:
                 
    June 30, 2011     December 31, 2010  
    (In millions)  
Oil, gas and NGL sales
  $ 879     $ 786  
Joint interest billings
    245       204  
Marketing and midstream revenues
    136       165  
Other
    195       57  
 
           
Gross accounts receivable
    1,455       1,212  
Allowance for doubtful accounts
    (9 )     (10 )
 
           
Net accounts receivable
  $ 1,446     $ 1,202  
 
           

10


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
4. Derivative Financial Instruments
Objectives and Strategies
     Devon periodically enters into commodity and interest rate derivative financial instruments. These instruments are used to manage the inherent uncertainty of future revenues due to oil, gas and NGL price volatility and to manage exposure to interest rate volatility. Devon does not hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.
     Devon’s derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional gas index prices and pays a variable differential on the same two index prices to the contract counterparty. The 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, Devon will cash-settle the difference with the counterparty to the collars. Under the terms of the call options, Devon sold to counterparties the right to purchase production at a predetermined price.
     Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon’s interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount. Devon also had forward starting swaps and U.S. Treasury locks. In conjunction with Devon’s debt issuance discussed in Note 7, Devon received $35 million from the net settlement of its forward starting swaps and U.S. Treasury locks in July 2011.
Counterparty Risk
     By using derivative financial instruments to manage exposures to changes in commodity prices and interest rates, Devon exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are minimal credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $55 million for the majority of Devon’s contracts. As of June 30, 2011, the credit ratings of all Devon’s counterparties were investment grade.
Commodity Derivatives
     As of June 30, 2011, Devon had the following open oil derivative positions. Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price.
                                                         
Production                  
Period   Price Swaps     Price Collars     Call Options Sold  
            Weighted             Weighted     Weighted             Weighted  
    Volume     Average Price     Volume     Average Floor Price     Average Ceiling Price     Volume     Average Price  
Period   (Bbls/d)     ($/Bbl)     (Bbls/d)     ($/Bbl)     ($/Bbl)     (Bbls/d)     ($/Bbl)  
Q3-Q4 2011
                45,000     $ 75.00     $ 108.89       19,500     $ 95.00  
Q1-Q4 2012
    22,000     $ 107.17       54,000     $ 85.74     $ 126.42       19,500     $ 95.00  
Q1-Q4 2013
                7,000     $ 90.00     $ 125.12              

11


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
     As of June 30, 2011, Devon had the following open natural gas derivative positions. Devon’s natural gas derivative swaps, collars and call options settle against the Inside Ferc first of the month Henry Hub index.
                                                         
Production            
Period   Price Swaps   Price Collars   Call Options Sold
            Weighted           Weighted   Weighted           Weighted
    Volume   Average Price   Volume   Average Floor Price   Average Ceiling Price   Volume   Average Price
Period   (MMBtu/d)   ($/MMBtu)   (MMBtu/d)   ($/MMBtu)   ($/MMBtu)   (MMBtu/d)   ($/MMBtu)
Q3-Q4 2011
    712,500     $ 5.51       215,000       4.75       5.17              
Q1-Q4 2012
    325,000     $ 5.09       490,000       4.75       5.57       487,500     $ 6.00  
                         
Basis Swaps  
                    Weighted Average  
                    Differential to  
            Volume     Henry Hub  
Production Period   Index     (MMBtu/d)     ($/MMBtu)  
Q3-Q4 2011
  Panhandle Eastern Pipeline     150,000     $ (0.33 )
     As of June 30, 2011, Devon had the following open NGL derivative positions:
                         
NGL Basis Swaps
                    Weighted Average
            Volume   Differential to WTI
Production Period   Pay   (Bbls/d)   ($/Bbl)
Q3-Q4 2011
  Natural Gasoline     416     $ (9.75 )
Q1-Q4 2012
  Natural Gasoline     500     $ (10.10 )
Q1-Q4 2013
  Natural Gasoline     500     $ (6.80 )
Interest Rate Derivatives
     As of June 30, 2011, Devon had the following open interest rate derivative positions:
                           
Fixed-to-Floating Swaps  
      Fixed Rate     Variable        
Notional   Received     Rate Paid     Expiration  
(In millions)                        
$300
      4.30 %   Six month LIBOR   July 18, 2011
100
      1.90 %   Federal funds rate   August 3, 2012
500
      3.90 %   Federal funds rate   July 18, 2013
250
      3.85 %   Federal funds rate   July 22, 2013
   
$1,150
      3.82 %                
   
                         
Forward Starting Swaps
    Fixed Rate   Variable    
Notional   Paid   Rate Received   Expiration
(In millions)                        
$950
    3.92 %   Three month LIBOR   July 7, 2011
                           
U.S. Treasury Locks  
      Fixed Rate     Variable        
Notional   Paid     Rate Received     Expiration  
(In millions)                        
$350
      1.56 %   Five year U.S. Treasury   July 6, 2011
300
      2.96 %   Ten year U.S. Treasury   July 6, 2011
   
$650
    2.21 %                
   

12


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
Financial Statement Presentation
     The following table presents the derivative fair values included in the accompanying consolidated balance sheets.
                         
    Balance Sheet Caption     June 30, 2011     December 31, 2010  
            (In millions)  
Asset derivatives:
                       
Commodity derivatives
  Other current assets   $ 240     $ 248  
Commodity derivatives
  Other long-term assets     81       1  
Interest rate derivatives
  Other current assets     78       100  
Interest rate derivatives
  Other long-term assets     33       40  
 
                   
Total asset derivatives
          $ 432     $ 389  
 
                   
Liability derivatives:
                       
Commodity derivatives
  Other current liabilities   $ 83     $ 50  
Commodity derivatives
  Other long-term liabilities     78       142  
 
                   
Total liability derivatives
          $ 161     $ 192  
 
                   
     The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying consolidated statements of operations associated with these derivative financial instruments. Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s commodity derivatives are presented in the “Oil, gas and NGL derivatives” caption in the accompanying consolidated statements of operations. Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s interest rate derivatives are presented in the “Interest-rate and other financial instruments” caption in the accompanying consolidated statements of operations.
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     2011     2010  
            (In millions)          
Cash settlements:
                               
Commodity derivatives
  $ 59     $ 252     $ 145     $ 348  
Interest rate derivatives
    5       4       21       20  
 
                       
Total cash settlements
    64       256       166       368  
 
                       
 
                               
Unrealized gains (losses):
                               
Commodity derivatives
    357       (207 )     103       317  
Interest rate derivatives
    (30 )     (85 )     (29 )     (86 )
 
                       
Total unrealized gains (losses)
    327       (292 )     74       231  
 
                       
Net gain (loss) recognized on statement of operations
  $ 391     $ (36 )   $ 240     $ 599  
 
                       
5. Other Current Assets
     The components of other current assets include the following:
                 
    June 30, 2011     December 31, 2010  
    (In millions)  
Derivative financial instruments
  $ 318     $ 348  
Income taxes receivable
    206       270  
Inventories
    137       120  
Other
    50       41  
 
           
Other current assets
  $ 711     $ 779  
 
           

13


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
6. Goodwill
     During the first six months of 2011, Devon’s Canadian goodwill increased $96 million entirely due to foreign currency translation.
7. Debt
Credit Lines
     Devon has a $2.7 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). As of June 30, 2011, Devon had no borrowings under the Senior Credit Facility.
     The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization to be less than 65 percent. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the consolidated financial statements. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill impairments. As of June 30, 2011, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at June 30, 2011, as calculated pursuant to the terms of the agreement, was 19.3 percent.
Commercial Paper
     In March 2011, Devon’s Board of Directors authorized an increase in its commercial paper program from $2.2 billion to $5.0 billion. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market.
     Although Devon ended the second quarter of 2011 with approximately $6.7 billion of cash and short-term investments, the vast majority of this amount consists of proceeds from its International divestitures. Based on Devon’s evaluation of future cash needs across its operations in the United States and Canada, these proceeds remain outside of the United States.
     Consequently, during the first six months of 2011, Devon borrowed $2.3 billion of commercial paper in the United States primarily to fund capital expenditures, common stock repurchases and dividends in excess of cash flow generated by its United States operating activities. As of June 30, 2011, Devon’s average borrowing rate on its $2.3 billion of commercial paper borrowings was 0.27 percent.
     In July 2011, Devon received net proceeds totaling $2,224 million from the issuance of $500 million of 2.40% senior notes due July 15, 2016, $500 million of 4.00% senior notes due July 15, 2021 and $1,250 million of 5.60% senior notes due July 15, 2041. The net proceeds from issuance of this long-term debt is being used to repay substantially all of Devon’s outstanding commercial paper as of June 30, 2011 as it matures. Therefore, $2,224 million of Devon’s outstanding commercial paper is classified as long-term debt in the accompanying June 30, 2011 consolidated balance sheet.

14


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
8. Asset Retirement Obligations
     The schedule below summarizes changes in Devon’s asset retirement obligations.
                 
    Six Months  
    Ended June 30,  
    2011     2010  
    (In millions)  
Asset retirement obligations as of beginning of period
  $ 1,497     $ 1,513  
Liabilities incurred
    23       25  
Liabilities settled
    (39 )     (71 )
Revision of estimated obligation
    16       194  
Liabilities assumed by others
          (256 )
Accretion expense on discounted obligation
    46       50  
Foreign currency translation adjustment
    28       (14 )
 
           
Asset retirement obligations as of end of period
    1,571       1,441  
Less current portion
    72       95  
 
           
Asset retirement obligations, long-term
  $ 1,499     $ 1,346  
 
           
     During the first six months of 2010, Devon recognized a revision to its asset retirement obligations totaling $194 million. The increase was primarily due to an overall increase in abandonment cost estimates and a decrease in the discount rate used to calculate the present value of the obligations.
     During the first six months of 2010, Devon reduced its asset retirement obligations by $256 million for those obligations that were assumed by purchasers of Devon’s Gulf of Mexico oil and gas properties in 2010.
9. Retirement Plans
Net Periodic Benefit Cost
     The following table presents the components of net periodic benefit cost for Devon’s pension and other postretirement benefit plans.
                                                                 
    Pension Benefits     Other Postretirement Benefits  
    Three Months     Six Months     Three Months     Six Months  
    Ended June 30,     Ended June 30,     Ended June 30,     Ended June 30,  
    2011     2010     2011     2010     2011     2010     2011     2010  
                            (In millions)                          
Service cost
  $ 9     $ 8     $ 18     $ 16     $ 1     $     $ 1     $  
Interest cost
    15       14       30       28             1       1       2  
Expected return on plan assets
    (11 )     (9 )     (21 )     (18 )                        
Amortization of prior service cost
    1       1       2       2       (1 )           (1 )      
Net actuarial loss
    8       7       16       14                          
 
                                               
Net periodic benefit cost
  $ 22     $ 21     $ 45     $ 42     $     $ 1     $ 1     $ 2  
 
                                               
Pension Plan Assets
     Devon previously disclosed in its financial statements for the year ended December 31, 2010, that it expected to contribute $84 million to its qualified pension plans in 2011. Devon now expects to contribute $346 million to its qualified pension plans in 2011, including $246 million that was contributed in the first six months of 2011 and $100 million that was contributed in July 2011. The increase in Devon’s 2011 contributions is due to increased discretionary funding.
     As a result of the discretionary contributions noted above, Devon amended its target allocation for its pension plan assets in the second quarter of 2011. Devon previously disclosed a target allocation of 47.5% for equity securities, 40% for fixed

15


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
income and 12.5% for other investment types. Devon now expects an allocation of 70% fixed income, 20% equity and 10% for other investment types for its pension assets.
10. Stockholders’ Equity
Stock Repurchases
     During the first six months of 2011, Devon repurchased 15.2 million common shares under its $3.5 billion stock repurchase program announced in 2010 for $1.3 billion, or $84.52 per share. As of June 30, 2011, Devon had repurchased 33.5 million common shares for $2.5 billion, or $74.16 per share, under this program, which expires December 31, 2011.
Dividends
     Devon paid common stock dividends of $140 million and $142 million in the first six months of 2011 and 2010, respectively. The quarterly cash dividend was $0.16 per share in the first and second quarter of 2010 and the first quarter of 2011. In the second quarter of 2011, Devon increased the dividend rate to $0.17 per share.
11. 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 natural 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. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
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 and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated costs associated with remediation. Devon’s monetary exposure for environmental matters is not expected to be material.
Chief Redemption Matters
     In 2006, Devon acquired Chief Holdings LLC (“Chief”) from the owners of Chief, including Trevor Rees-Jones, the majority owner of Chief. In 2008, a former owner of Chief filed a petition against Rees-Jones, as the former majority owner of Chief, and Devon, as Chief’s successor pursuant to the 2006 acquisition. The petition claimed, among other things, violations of the Texas Securities Act, fraud and breaches of Rees-Jones’ fiduciary responsibility to the former owner in connection with Chief’s 2004 redemption of the owner’s minority ownership stake in Chief.
     On June 20, 2011, a court issued a judgment against Rees-Jones for $196 million, of which $133 million of the judgment was also issued against Devon. Both Rees-Jones and Devon are appealing the judgment. However, if the appeal is unsuccessful, Devon can and will seek full payment of the judgment and any related interest, costs and expenses from Rees-Jones pursuant to an existing indemnification agreement between Rees-Jones, certain other parties and Devon. Devon does not expect to have any net exposure as a result of the judgment. However, because Devon does not have a legal right of set

16


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
off with respect to the judgment, Devon has recorded in its June 30, 2011 consolidated balance sheet both a $133 million liability relating to the judgment with an offsetting $133 million receivable relating to its right to be indemnified by Rees-Jones and certain other parties pursuant to the indemnification agreement.
Other Matters
     Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
Commitments
     At the end of 2010, Devon’s commitments included approximately $0.6 billion related to lease contracts for a deepwater drilling rig and a floating, production, storage and offloading facility being used in Brazil. Devon’s remaining commitments for these leases were assumed by the buyer of its assets upon closing the Brazil divestiture transaction discussed in Note 15.
12. Fair Value Measurements
     Certain of Devon’s assets and liabilities are reported at fair value in the accompanying consolidated balance sheets. Such assets and liabilities include amounts for both financial and non-financial instruments. The following tables provide carrying value and fair value measurement information for Devon’s financial assets and liabilities.
     The carrying values of cash and cash equivalents, accounts receivable, other current receivables, accounts payable and other current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at June 30, 2011 and December 31, 2010. These assets and liabilities are not presented in the following table.
                                         
                    Fair Value Measurements Using:
    Carrying   Total Fair   Level 1   Level 2   Level 3
    Amount   Value   Inputs   Inputs   Inputs
                    (In millions)                
June 30, 2011 assets (liabilities):
                                       
Short-term investments
  $ 3,367     $ 3,367     $ 3,367     $     $  
Long-term investments
  $ 93     $ 93     $     $     $ 93  
Commodity derivatives
  $ 321     $ 321     $     $ 321     $  
Commodity derivatives
  $ (161 )   $ (161 )   $     $ (161 )   $  
Interest rate derivatives
  $ 111     $ 111     $     $ 111     $  
Debt
  $ (7,930 )   $ (8,867 )   $ (2,340 )   $ (6,423 )   $ (104 )
                                         
                    Fair Value Measurements Using:
    Carrying   Total Fair   Level 1   Level 2   Level 3
    Amount   Value   Inputs   Inputs   Inputs
                    (In millions)                
December 31, 2010 assets (liabilities):
                                       
Short-term investments
  $ 145     $ 145     $ 145     $     $  
Long-term investments
  $ 94     $ 94     $     $     $ 94  
Commodity derivatives
  $ 249     $ 249     $     $ 249     $  
Commodity derivatives
  $ (192 )   $ (192 )   $     $ (192 )   $  
Interest rate derivatives
  $ 140     $ 140     $     $ 140     $  
Debt
  $ (5,630 )   $ (6,629 )   $     $ (6,485 )   $ (144 )

17


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
     Devon’s Level 3 fair value measurements included in the table above relate to certain long-term investments and a non-interest bearing promissory note. Included below is a summary of the changes in Devon’s Level 3 fair value measurements during the first six months of 2011 and 2010.
                 
    Six Months  
    Ended June 30,  
    2011     2010  
    (In millions)  
Long-term investments balance at beginning of period
  $ 94     $ 115  
Redemptions of principal
    (1 )     (18 )
 
           
Long-term investments balance at end of period
  $ 93     $ 97  
 
           
                 
    Six Months  
    Ended June 30,  
    2011     2010  
    (In millions)  
Debt balance at beginning of period
  $ (144 )   $  
Issuance of promissory note
          (139 )
Foreign exchange translation adjustment
    (4 )      
Accretion of promissory note
    (2 )      
Redemptions of principal
    46        
 
           
Debt balance at end of period
  $ (104 )   $ (139 )
 
           
13. Restructuring Costs
     In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of June 30, 2011, Devon had divested all of its U.S. Offshore assets and substantially all of its International assets.
     Through the end of the second quarter of 2011, Devon had incurred $204 million of restructuring costs associated with these divestitures. This amount is comprised of $120 million of employee severance costs, $81 million associated with abandoned office leases and $3 million of other miscellaneous costs.
Financial Statement Presentation
     The schedule below summarizes activity and balances associated with Devon’s restructuring liabilities.
                                                 
    Continuing Operations     Discontinued Operations  
    Other     Other             Other     Other        
    Current     Long-Term             Current     Long-Term        
    Liabilities     Liabilities     Total     Liabilities     Liabilities     Total  
    (In millions)  
Balance as of December 31, 2010
  $ 31     $ 51     $ 82     $ 16     $     $ 16  
Cash severance settled
    (16 )           (16 )     (4 )           (4 )
Lease obligations settled
    (1 )     (7 )     (8 )                  
Lease obligations revision
    (1 )     (1 )     (2 )                  
Cash severance revision
    1             1       (2 )           (2 )
 
                                   
Balance as of June 30, 2011
  $ 14     $ 43     $ 57     $ 10     $     $ 10  
 
                                   
 
                                               
Balance as of December 31, 2009
  $ 61     $     $ 61     $ 23     $     $ 23  
Cash severance settled
    (5 )           (5 )     (1 )           (1 )
Cash severance revision
    (5 )           (5 )     (3 )           (3 )
 
                                   
Balance as of June 30, 2010
  $ 51     $     $ 51     $ 19     $     $ 19  
 
                                   

18


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
     The schedule below summarizes the components of restructuring costs in the accompanying 2011 and 2010 consolidated statement of operations.
                                                 
    Three Months Ended June 30, 2011     Six Months Ended June 30, 2011  
    Continuing     Discontinued             Continuing     Discontinued        
    Operations     Operations     Total     Operations     Operations     Total  
    (In millions)  
Cash severance
  $ 1     $ (8 )   $ (7 )   $ 1     $ (2 )   $ (1 )
Asset impairments
    2             2       2             2  
Lease obligations
    2             2       (2 )           (2 )
Share-based awards
                      (1 )           (1 )
Other
    1             1       1             1  
 
                                   
Restructuring costs
  $ 6     $ (8 )   $ (2 )   $ 1     $ (2 )   $ (1 )
 
                                   
                                                 
    Three Months Ended June 30, 2010     Six Months Ended June 30, 2010  
    Continuing     Discontinued             Continuing     Discontinued        
    Operations     Operations     Total     Operations     Operations     Total  
    (In millions)  
Cash severance
  $ (5 )   $ (3 )   $ (8 )   $ (5 )   $ (3 )   $ (8 )
Share-based awards
    (4 )     (2 )     (6 )     (4 )     (2 )     (6 )
Other
    1             1       1             1  
 
                                   
Restructuring costs
  $ (8 )   $ (5 )   $ (13 )   $ (8 )   $ (5 )   $ (13 )
 
                                   
14. Income Taxes
     In the second quarter of 2011, a portion of Devon’s foreign earnings were no longer deemed to be permanently reinvested in accordance with accounting principles generally accepted in the United States of America. Accordingly, Devon recognized $725 million of deferred tax expense and $19 million of current income tax expense during the second quarter of 2011 related to assumed repatriations of such earnings under current U.S. tax law. These earnings were primarily related to the gains generated from Devon’s International divestiture transactions. Excluding the $744 million of tax expense, Devon’s effective income tax rate was 33% in both the second quarter and first six months of 2011, respectively.
15. Discontinued Operations
     In May 2011, Devon completed the divestiture of its operations in Brazil. With the close of the Brazil transaction, Devon has substantially completed its planned offshore divestitures. In aggregate, Devon’s U.S. and International offshore sales have generated total proceeds of $10 billion, or approximately $8 billion after-tax, assuming repatriation of a portion of the foreign proceeds under current U.S. tax law.
     Revenues related to Devon’s discontinued operations totaled $43 million in the first six months of 2011 and $222 million and $434 million in the second quarter and first six months of 2010, respectively. Devon did not have revenues related to its discontinued operations in the second quarter of 2011.

19


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
     Earnings from discontinued operations in the second quarter and first six months of 2011 and 2010 were largely impacted by gains on Devon’s International divestiture transactions. The following table presents the gains on the divestitures according to the quarters in which the divestitures closed in 2011 and 2010. The after-tax amounts in the table below exclude $744 million of income tax expense related to assumed repatriations discussed in Note 14.
                                                 
    Second Quarter 2011     Third Quarter 2010     Second Quarter 2010  
            After             After             After  
    Gross     Taxes     Gross     Taxes     Gross     Taxes  
    (In millions)  
Brazil
  $ 2,546     $ 2,546     $     $     $     $  
Azerbaijan
                1,543       1,524              
China — Panyu
                            308       235  
Other
                (8 )     (2 )            
 
                                   
Total
  $ 2,546     $ 2,546     $ 1,535     $ 1,522     $ 308     $ 235  
 
                                   
     The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations.
                 
    June 30,     December 31,  
    2011     2010  
    (In millions)  
Cash and cash equivalents
  $     $ 424  
Accounts receivable
    2       43  
Other current assets
    34       96  
 
           
Current assets
  $ 36     $ 563  
 
           
 
               
Property and equipment, net
  $ 92     $ 848  
Other long-term assets
    2       11  
 
           
Total long-term assets
  $ 94     $ 859  
 
           
 
               
Accounts payable
  $ 4     $ 260  
Other current liabilities
    39       45  
 
           
Current liabilities
  $ 43     $ 305  
 
           
 
               
Long-term liabilities
  $ 2     $ 26  
 
           
16. 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.
                         
            Common     Earnings  
    Earnings     Shares     per Share  
    (In millions, except per share amounts)  
Three Months Ended June 30, 2011:
                       
Earnings from continuing operations
  $ 184       422          
Attributable to participating securities
    (2 )     (5 )        
 
                   
Basic earnings per share
    182       417     $ 0.44  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          2          
 
                   
Diluted earnings per share
  $ 182       419     $ 0.43  
 
                   

20


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
                         
            Common     Earnings  
    Earnings     Shares     per Share  
    (In millions, except per share amounts)  
Three Months Ended June 30, 2010:
                       
Earnings from continuing operations
  $ 352       445          
Attributable to participating securities
    (4 )     (5 )        
 
                   
Basic earnings per share
    348       440     $ 0.79  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          1          
 
                   
Diluted earnings per share
  $ 348       441     $ 0.79  
 
                   
 
                       
Six Months Ended June 30, 2011:
                       
Earnings from continuing operations
  $ 573       425          
Attributable to participating securities
    (6 )     (5 )        
 
                   
Basic earnings per share
    567       420     $ 1.35  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          2          
 
                   
Diluted earnings per share
  $ 567       422     $ 1.34  
 
                   
 
                       
Six Months Ended June 30, 2010:
                       
Earnings from continuing operations
  $ 1,426       446          
Attributable to participating securities
    (17 )     (5 )        
 
                   
Basic earnings per share
    1,409       441     $ 3.20  
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options
          1          
 
                   
Diluted earnings per share
  $ 1,409       442     $ 3.19  
 
                   
     Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculation because the options are antidilutive. During the three-month and six-month periods ended June 30, 2011, 3.1 million shares were excluded from the diluted earnings per share calculations. During the three-month and six-month periods ended June 30, 2010, 7.9 million shares and 6.4 million shares, respectively, were excluded from the diluted earnings per share calculations.

21


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
17. Segment Information
     Devon manages its North American onshore operations through distinct operating segments, or divisions, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its United States divisions into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian and International divisions are reported as separate reporting segments primarily due to significant differences in the respective regulatory environments.
                                 
    U.S.     Canada     International     Total  
    (In millions)  
As of June 30, 2011:
                               
Current assets (1)
  $ 1,916     $ 6,959     $ 36     $ 8,911  
Property and equipment, net
    14,472       7,955             22,427  
Goodwill
    3,046       3,130             6,176  
Other assets
    538       391       94       1,023  
 
                       
Total assets
  $ 19,972     $ 18,435     $ 130     $ 38,537  
 
                       
 
                               
Current liabilities
  $ 1,995     $ 2,446     $ 43     $ 4,484  
Long-term debt
    4,725       1,243             5,968  
Asset retirement obligations
    578       921             1,499  
Other liabilities
    742       66       2       810  
Deferred income taxes
    2,939       1,409             4,348  
Stockholders’ equity
    8,993       12,350       85       21,428  
 
                       
Total liabilities and stockholders’ equity
  $ 19,972     $ 18,435     $ 130     $ 38,537  
 
                       
 
(1)   Current assets in the Canadian segment include $6.1 billion of cash, cash equivalents and short-term investments that were generated from Devon’s International offshore divestiture program and have not been repatriated to the United States.

22


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
                         
    U.S.     Canada     Total  
    (In millions)  
Three Months Ended June 30, 2011:
                       
Revenues:
                       
Oil, gas and NGL sales
  $ 1,438     $ 762     $ 2,200  
Oil, gas and NGL derivatives
    416             416  
Marketing and midstream revenues
    554       50       604  
 
                 
Total revenues
    2,408       812       3,220  
 
                 
Expenses and other, net:
                       
Lease operating expenses
    224       229       453  
Taxes other than income taxes
    107       13       120  
Marketing and midstream operating costs and expenses
    413       43       456  
Depreciation, depletion and amortization of oil and gas properties
    291       194       485  
Depreciation and amortization of non-oil and gas properties
    59       6       65  
Accretion of asset retirement obligations
    8       15       23  
General and administrative expenses
    94       41       135  
Restructuring costs
    6             6  
Interest expense
    40       45       85  
Interest-rate and other financial instruments
    25             25  
Other, net
    (7 )     (4 )     (11 )
 
                 
Total expenses and other, net
    1,260       582       1,842  
 
                 
Earnings from continuing operations before income taxes
    1,148       230       1,378  
Income tax expense:
                       
Current
    35       1       36  
Deferred
    1,100       58       1,158  
 
                 
Total income tax expense
    1,135       59       1,194  
 
                 
Earnings from continuing operations
  $ 13     $ 171     $ 184  
 
                 
 
                       
Capital expenditures, continuing operations
  $ 1,499     $ 334     $ 1,833  
 
                 

23


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
                         
    U.S.     Canada     Total  
    (In millions)  
Three Months Ended June 30, 2010:
                       
Revenues:
                       
Oil, gas and NGL sales
  $ 1,144     $ 638     $ 1,782  
Oil, gas and NGL derivatives
    32       13       45  
Marketing and midstream revenues
    372       33       405  
 
                 
Total revenues
    1,548       684       2,232  
 
                 
Expenses and other, net:
                       
Lease operating expenses
    243       199       442  
Taxes other than income taxes
    83       9       92  
Marketing and midstream operating costs and expenses
    252       28       280  
Depreciation, depletion and amortization of oil and gas properties
    248       178       426  
Depreciation and amortization of non-oil and gas properties
    57       6       63  
Accretion of asset retirement obligations
    12       12       24  
General and administrative expenses
    98       32       130  
Restructuring costs
    (8 )           (8 )
Interest expense
    55       56       111  
Interest-rate and other financial instruments
    81             81  
Other, net
    (26 )     4       (22 )
 
                 
Total expenses and other, net
    1,095       524       1,619  
 
                 
Earnings from continuing operations before income taxes
    453       160       613  
Income tax expense (benefit):
                       
Current
    631       76       707  
Deferred
    (421 )     (25 )     (446 )
 
                 
Total income tax expense
    210       51       261  
 
                 
Earnings from continuing operations
  $ 243     $ 109     $ 352  
 
                 
 
                       
Capital expenditures, continuing operations
  $ 1,145     $ 774     $ 1,919  
 
                 

24


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
                         
    U.S.     Canada     Total  
    (In millions)  
Six Months Ended June 30, 2011:
                       
Revenues:
                       
Oil, gas and NGL sales
  $ 2,650     $ 1,410     $ 4,060  
Oil, gas and NGL derivatives
    248             248  
Marketing and midstream revenues
    977       82       1,059  
 
                 
Total revenues
    3,875       1,492       5,367  
 
                 
Expenses and other, net:
                       
Lease operating expenses
    432       445       877  
Taxes other than income taxes
    201       27       228  
Marketing and midstream operating costs and expenses
    721       68       789  
Depreciation, depletion and amortization of oil and gas properties
    551       376       927  
Depreciation and amortization of non-oil and gas properties
    117       12       129  
Accretion of asset retirement obligations
    17       29       46  
General and administrative expenses
    185       80       265  
Restructuring costs
    1             1  
Interest expense
    77       89       166  
Interest-rate and other financial instruments
    8             8  
Other, net
    (21 )     (6 )     (27 )
 
                 
Total expenses and other, net
    2,289       1,120       3,409  
 
                 
Earnings from continuing operations before income taxes
    1,586       372       1,958  
Income tax (benefit) expense:
                       
Current
    (53 )           (53 )
Deferred
    1,343       95       1,438  
 
                 
Total income tax expense
    1,290       95       1,385  
 
                 
Earnings from continuing operations
  $ 296     $ 277     $ 573  
 
                 
 
                       
Capital expenditures, before revision of future asset retirement obligations
  $ 2,749     $ 866     $ 3,615  
Revision of future asset retirement obligations
    2       14       16  
 
                 
Capital expenditures, continuing operations
  $ 2,751     $ 880     $ 3,631  
 
                 

25


Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)
                         
    U.S.     Canada     Total  
    (In millions)  
Six Months Ended June 30, 2010:
                       
Revenues:
                       
Oil, gas and NGL sales
  $ 2,514     $ 1,338     $ 3,852  
Oil, gas and NGL derivatives
    657       8       665  
Marketing and midstream revenues
    868       67       935  
 
                 
Total revenues
    4,039       1,413       5,452  
 
                 
Expenses and other, net:
                       
Lease operating expenses
    467       389       856  
Taxes other than income taxes
    173       20       193  
Marketing and midstream operating costs and expenses
    621       56       677  
Depreciation, depletion and amortization of oil and gas properties
    509       343       852  
Depreciation and amortization of non-oil and gas properties
    113       13       126  
Accretion of asset retirement obligations
    25       25       50  
General and administrative expenses
    206       62       268  
Restructuring costs
    (8 )           (8 )
Interest expense
    85       112       197  
Interest-rate and other financial instruments
    66             66  
Other, net
    (29 )     3       (26 )
 
                 
Total expenses and other, net
    2,228       1,023       3,251  
 
                 
Earnings from continuing operations before income taxes
    1,811       390       2,201  
Income tax expense (benefit):
                       
Current
    845       161       1,006  
Deferred
    (186 )     (45 )     (231 )
 
                 
Total income tax expense
    659       116       775  
 
                 
Earnings from continuing operations
  $ 1,152     $ 274     $ 1,426  
 
                 
 
                       
Capital expenditures, before revision of future asset retirement obligations
  $ 2,189     $ 1,144     $ 3,333  
Revision of future asset retirement obligations
    72       122       194  
 
                 
Capital expenditures, continuing operations
  $ 2,261     $ 1,266     $ 3,527  
 
                 
18. Supplemental Information to Statements of Cash Flows
                 
    Six Months  
    Ended June 30,  
    2011     2010  
    (In millions)  
Net (increase) decrease in working capital:
               
Increase in accounts receivable
  $ (100 )   $ (1 )
(Increase) decrease in other current assets
    (41 )     44  
Increase (decrease) in accounts payable
    9       (21 )
Increase (decrease) in revenues and royalties due to others
    130       (21 )
(Decrease) increase in other current liabilities
    (87 )     580  
 
           
Net (increase) decrease in working capital
  $ (89 )   $ 581  
 
           
 
               
Supplementary cash flow data — total operations:
               
Interest paid (net of capitalized interest)
  $ 160     $ 202  
Income taxes (received) paid
  $ (125 )   $ 306  

26


Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The following discussion and analysis addresses material changes in our results of operations and capital resources and uses for the three-month and six-month periods ended June 30, 2011, compared to the three-month and six-month periods ended June 30, 2010, and in our financial condition and liquidity since December 31, 2010. For information regarding our critical accounting policies and estimates, see our 2010 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Financial Overview
     During the second quarter and first six months of 2011, we generated net earnings of $2.7 billion, or $6.48 per diluted share, and $3.2 billion, or $7.41 per diluted share, for the respective periods. This compares to net earnings of $706 million, or $1.58 per diluted share, and $1.9 billion, or $4.24 per diluted share for the second quarter and first six months of 2010, respectively. Our financial results for the second quarter and first six months of 2011 include an after-tax gain of $1.8 billion related to International divestitures.
     Key measures of our financial performance for the second quarter and first six months of 2011 compared to 2010 are summarized below. Our North America Onshore comparisons exclude amounts related to our Gulf of Mexico assets that were divested in the first half of 2010.
    North America Onshore oil and NGL production increased 7% to 20 MMBbls and 5% to 39 MMBbls in the second quarter and first six months of 2011, respectively.
 
    North America Onshore gas production increased 4% to 240 Bcf and 5% to 468 Bcf in the second quarter and first six months of 2011, respectively.
 
    The combined realized price without hedges for oil, gas and NGLs increased 20% to $36.63 per Boe and 3% to $34.80 per Boe in the second quarter and first six months of 2011, respectively.
 
    Oil, gas and NGL derivatives generated cash receipts of $59 million and $145 million for the second quarter and first six months of 2011, respectively, and cash receipts of $252 million and $348 million in the second quarter and first six months of 2010, respectively.
 
    Marketing and midstream operating profit increased 19% to $148 million and 5% to $270 million in the second quarter and first six months of 2011, respectively.
 
    North America Onshore per unit operating costs increased 3% to $7.55 per Boe and 3% to $7.52 per Boe in the second quarter and first six months of 2011, respectively.
 
    Operating cash flow increased 11% to $1.6 billion in the second quarter of 2011 and decreased 3% to $2.8 billion in the first six months of 2011, respectively.
 
    Capital spending totaled approximately $3.7 billion in the first six months of 2011.
     In the second quarter of 2011, we completed the divestiture of our operations in Brazil. With the close of the Brazil transaction, we have substantially completed our planned offshore divestitures, generating aggregate after-tax proceeds of approximately $8 billion assuming repatriation of a portion of the foreign proceeds under current U.S. tax law.
     In July 2011, we issued $500 million of 2.40% senior notes due July 15, 2016, $500 million of 4.00% senior notes due July 15, 2021 and $1,250 million of 5.60% senior notes due July 15, 2041. The net proceeds from issuance of this debt is being used to repay our outstanding commercial paper as it matures.
     Our performance and the proceeds from our previous offshore divestitures have allowed us to maintain a robust level of liquidity. As of June 30, 2011, we held approximately $6.7 billion in cash and short-term investments. We also have access to short-term commercial paper borrowings and our $2.7 billion credit facility. With this liquidity, we continue executing our exploration and development programs, with a focus on near-term growth of our liquids production, and repurchasing common shares under our $3.5 billion share repurchase program. Through July 22, 2011, we had repurchased 35.1 million shares for $2.6 billion, or $74.44 per share.

27


Table of Contents

Second-Quarter Operating Highlights
    In the Permian Basin, we increased production 17 percent over the second quarter of 2010, to 49 MBoe/d. Oil and natural gas liquids accounted for 75 percent of the Permian Basin’s second quarter production.
 
    We completed nine operated Bone Spring wells within the Permian Basin in the second quarter. Initial daily production from the nine wells averaged more than 700 Boe/d per well. We have an average working interest of 77 percent in these wells.
 
    In Canada, we commenced steam injection and achieved first production from our Jackfish 2 oil sands project in the second quarter. Production from the 100 percent-owned project is expected to ramp-up to 35 MBbls/d before royalties over the next 18 months.
 
    Production from our Cana-Woodford Shale play averaged a record 189 MMcfe/d in the second quarter, including nearly 9 MBbls/d of liquids. This represents an 80 percent increase in total production compared to the year-ago quarter.
 
    Our Barnett Shale production increased 13 percent over the second-quarter 2010 to a record 1.3 Bcfe/d, including 46 MBbls/d of liquids production.
 
    We brought 8 operated Granite Wash wells online in the second quarter. Initial production from these wells averaged 2 MBoe/d, including 200 Bbls/d of oil and 730 Bbls/d of natural gas liquids. We have an average working interest of 71 percent in these wells.
 
    We have assembled 1.1 million net acres targeting new oil and liquids-rich gas opportunities across multiple basins in the U.S. In 2011, we plan to drill more than 30 wells targeting the Tuscaloosa Marine Shale, Niobrara Shale, Mississippian Lime, Ohio Utica Shale and the A1 Carbonate and Utica Shale in Michigan.
Results of Operations
Revenues
                                                 
    Three Months Ended June 30,   Six Months Ended June 30,
    2011   2010   Change (1)   2011   2010   Change (1)
Oil Volumes (MMBbls)
                                               
U.S. Onshore
    5       3       +27 %     8       6       +26 %
Canada
    6       6       -3 %     13       13       -1 %
 
                                               
North America Onshore
    11       9       +7 %     21       19       +8 %
U.S. Offshore
          1       -100 %           2       -100 %
 
                                               
Total
    11       10       0 %     21       21       -2 %
 
                                               
Gas Volumes (Bcf)
                                               
U.S. Onshore
    184       173       +6 %     361       339       +7 %
Canada
    56       58       -3 %     107       108       -1 %
 
                                               
North America Onshore
    240       231       +4 %     468       447       +5 %
U.S. Offshore
          7       -100 %           17       -100 %
 
                                               
Total
    240       238       +1 %     468       464       +1 %
 
                                               
NGLs Volumes (MMBbls)
                                               
U.S. Onshore
    8       7       +20 %     16       14       +18 %
Canada
    1       1       -5 %     2       2       -2 %
 
                                               
North America Onshore
    9       8       +17 %     18       16       +16 %
U.S. Offshore
                -100 %                 -100 %
 
                                               
Total
    9       8       +15 %     18       16       +13 %
 
                                               
Total Volumes (MMBoe)
                                               
U.S. Onshore
    43       39       +11 %     84       76       +10 %
Canada
    17       17       -3 %     33       33       -1 %
 
                                               
North America Onshore
    60       56       +6 %     117       109       +7 %
U.S. Offshore
          2       -100 %           5       -100 %
 
                                               
Total
    60       58       +3 %     117       114       +2 %
 
                                               
 
(1)   All percentage changes included in this table are based on actual figures rather than the rounded figures presented.

28


Table of Contents

                                                 
    Three Months Ended June 30,   Six Months Ended June 30,
    2011 (1)   2010 (1)   Change   2011 (1)   2010 (1)   Change
Oil Prices (per Bbl)
                                               
U.S. Onshore
  $ 98.28     $ 74.65       +32 %   $ 93.84     $ 74.73       +26 %
Canada
  $ 73.65     $ 54.43       +35 %   $ 67.29     $ 58.36       +15 %
North America Onshore
  $ 83.31     $ 61.11       +36 %   $ 77.32     $ 63.67       +21 %
U.S. Offshore
  $     $ 79.09       N/M     $     $ 77.81       N/M  
Total
  $ 83.31     $ 62.35       +34 %   $ 77.32     $ 64.93       +19 %
Gas Prices (per Mcf)
                                               
U.S. Onshore
  $ 3.72     $ 3.47       +7 %   $ 3.61     $ 4.05       -11 %
Canada
  $ 4.08     $ 3.99       +2 %   $ 4.05     $ 4.50       -10 %
North America Onshore
  $ 3.80     $ 3.60       +6 %   $ 3.71     $ 4.16       -11 %
U.S. Offshore
  $     $ 4.39       N/M     $     $ 5.12       N/M  
Total
  $ 3.80     $ 3.62       +5 %   $ 3.71     $ 4.19       -12 %
NGLs Prices (per Bbl)
                                               
U.S. Onshore
  $ 40.43     $ 28.73       +41 %   $ 38.04     $ 31.39       +21 %
Canada
  $ 58.80     $ 46.18       +27 %   $ 56.49     $ 47.52       +19 %
North America Onshore
  $ 42.20     $ 30.81       +37 %   $ 39.90     $ 33.31       +20 %
U.S. Offshore
  $     $ 35.59       N/M     $     $ 38.22       N/M  
Total
  $ 42.20     $ 30.90       +37 %   $ 39.90     $ 33.41       +19 %
Combined Prices (per Boe)
                                               
U.S. Onshore
  $ 33.19     $ 26.77       +24 %   $ 31.53     $ 29.71       +6 %
Canada
  $ 45.55     $ 37.08       +23 %   $ 43.23     $ 40.62       +6 %
North America Onshore
  $ 36.63     $ 29.92       +22 %   $ 34.80     $ 33.00       +5 %
U.S. Offshore
  $     $ 46.17       N/M     $     $ 49.06       N/M  
Total
  $ 36.63     $ 30.49       +20 %   $ 34.80     $ 33.70       +3 %
 
(1)   The prices presented exclude any effects due to oil, gas and NGL derivatives.
     The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the three months ended June 30, 2011 and 2010.
                                 
    Oil     Gas     NGLs     Total  
    (In millions)  
2010 sales
  $ 673     $ 861     $ 248     $ 1,782  
Changes due to volumes
    (1 )     9       37       45  
Changes due to prices
    225       43       105       373  
 
                       
2011 sales
  $ 897     $ 913     $ 390     $ 2,200  
 
                       
     The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the six months ended June 30, 2011 and 2010.
                                 
    Oil     Gas     NGLs     Total  
    (In millions)  
2010 sales
  $ 1,383     $ 1,947     $ 522     $ 3,852  
Changes due to volumes
    (26 )     17       70       61  
Changes due to prices
    259       (227 )     115       147  
 
                       
2011 sales
  $ 1,616     $ 1,737     $ 707     $ 4,060  
 
                       
Oil Sales
     Oil sales decreased $1 million and $26 million in the second quarter and first six months of 2011, respectively, due to a decrease in production. The decreases were primarily due to the divestiture of our U.S. Offshore properties in the second quarter of 2010, partially offset by increased North America Onshore production of 7 percent and 8 percent, respectively. The increased North America Onshore production in both periods resulted primarily from continued development of our Permian Basin properties and increased production from our Jackfish thermal heavy oil project in Canada.

29


Table of Contents

     Oil sales increased $225 million and $259 million in the second quarter and first six months of 2011, respectively, as a result of a 34 percent and 19 percent increase in our realized price without hedges. The largest contributor to the increase in our realized prices was the increase in the average West Texas Intermediate price over the same time period.
Gas Sales
     A 1 percent increase in production during the second quarter and first six months of 2011 caused gas sales to increase by $9 million and $17 million, respectively. The increases were comprised of the net effect of a 4 percent and 5 percent increase, respectively, in our North America Onshore production, partially offset by the divestiture of our U.S. Offshore properties in the second quarter of 2010. The increased North America Onshore production in both periods resulted primarily from continued development activities in the Barnett and Cana-Woodford Shales, partially offset by natural declines in our other operating areas.
     Gas sales increased $43 million and decreased $227 million during the second quarter and first six months of 2011, respectively, as a result of a 5 percent increase and a 12 percent decrease, respectively, in our realized price without hedges. The changes in price were largely due to the volatility of the North American regional index prices upon which our gas sales are based.
NGL Sales
     NGL sales increased $37 million and $70 million during the second quarter and first six months of 2011, respectively, due to a 15 percent increase and 13 percent increase in production. The increased production in both periods was primarily due to increased drilling in our Barnett Shale, Cana-Woodford Shale and Granite Wash locations.
     NGL sales increased $105 million and $115 million during the second quarter and first six months of 2011, respectively, due to a 37 percent and 19 percent increase in our realized price without hedges. The increases were largely due to increases in the Mont Belvieu, Texas hub price during the same time periods.
Oil, Gas and NGL Derivatives
     The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and unrealized gains and 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. The prices do not include the effects of unrealized gains and losses.
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     2011     2010  
            (In millions)          
Cash receipts (payments):
                               
Gas derivatives
  $ 74     $ 252     $ 165     $ 348  
Oil derivatives
    (16 )           (21 )      
NGL derivatives
    1             1        
 
                       
Total cash settlements
    59       252       145       348  
 
                       
Unrealized gains (losses) on fair value changes:
                               
Gas derivatives
    49       (331 )     (8 )     189  
Oil derivatives
    308       124       110       128  
NGL derivatives
                1        
 
                       
Total unrealized gains (losses)
    357       (207 )     103       317  
 
                       
Oil, gas and NGL derivatives
  $ 416     $ 45     $ 248     $ 665  
 
                       
                                 
    Three Months Ended June 30, 2011  
    Oil     Gas     NGLs     Total  
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
Realized price without hedges
  $ 83.31     $ 3.80     $ 42.20     $ 36.63  
Cash settlements of hedges
    (1.49 )     0.31       0.05       0.99  
 
                       
Realized price, including cash settlements
  $ 81.82     $ 4.11     $ 42.25     $ 37.62  
 
                       

30


Table of Contents

                                 
    Three Months Ended June 30, 2010  
    Oil     Gas     NGLs     Total  
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
Realized price without hedges
  $ 62.35     $ 3.62     $ 30.90     $ 30.49  
Cash settlements of hedges
          1.06             4.31  
 
                       
Realized price, including cash settlements
  $ 62.35     $ 4.68     $ 30.90     $ 34.80  
 
                       
                                 
    Six Months Ended June 30, 2011  
    Oil     Gas     NGLs     Total  
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
Realized price without hedges
  $ 77.32     $ 3.71     $ 39.90     $ 34.80  
Cash settlements of hedges
    (1.00 )     0.35       0.06       1.25  
 
                       
Realized price, including cash settlements
  $ 76.32     $ 4.06     $ 39.96     $ 36.05  
 
                       
                                 
    Six Months Ended June 30, 2010  
    Oil     Gas     NGLs     Total  
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
Realized price without hedges
  $ 64.93     $ 4.19     $ 33.41     $ 33.70  
Cash settlements of hedges
          0.75             3.04  
 
                       
Realized price, including cash settlements
  $ 64.93     $ 4.94     $ 33.41     $ 36.74  
 
                       
     Our oil, gas and NGL derivatives include price swaps, costless collars and basis swaps. For the price swaps, we receive a fixed price for our production and pay a variable market price to the contract counterparty. The price collars set a floor and ceiling price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we cash-settle the difference with the counterparty to the collars. For the basis swaps, we receive a fixed differential between two regional gas index prices and pay a variable differential on the same two index prices to the contract counterparty. Cash settlements as presented in the tables above represent realized gains or losses related to these various instruments.
     Additionally, to enhance a portion of our natural gas price swaps, we have sold gas call options for 2012 and oil call options for 2011 and 2012. The call options give counterparties the right to purchase production at a predetermined price.
     During the second quarter and first six months of 2011, we received $74 million, or $0.31 per Mcf, and $165 million, or $0.35 per Mcf, respectively, from counterparties to settle our gas derivatives and paid $16 million, or $1.49 per Bbl, and $21 million, or $1.00 per Bbl, respectively, from counterparties to settle our oil derivatives. During the second quarter and first six months of 2010, we received $252 million, or $1.06 per Mcf, and $348 million, or $0.75 per Mcf, respectively, from counterparties to settle our gas derivatives.
     In addition to recognizing these cash settlement effects, we also recognize unrealized changes in the fair values of our oil, gas and NGL derivative instruments in each reporting period. We estimate the fair values of these derivatives primarily by using internal discounted cash flow calculations. We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties 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 our gas derivative financial instruments at June 30, 2011, a 10 percent increase in these forward curves would have increased our unrealized losses by approximately $224 million. A 10 percent increase in the forward curves associated with our oil derivatives would have decreased our unrealized gains by approximately $300 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. Finally, the amount of production subject to oil, gas and NGL derivatives is not a variable in our cash flow calculations, but it does impact the total derivative value.
     Counterparty credit risk is also a component of commodity derivative valuations. We have mitigated our exposure to any single counterparty by contracting with fourteen counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade.

31


Table of Contents

Such thresholds generally range from zero to $55 million for the majority of our contracts. As of June 30, 2011, the credit ratings of all our counterparties were investment grade.
     Including the cash settlements discussed above, our oil, gas and NGL derivatives generated net gains of $416 million and $248 million during the second quarter and first six months of 2011, respectively. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated net gains of $45 million and $665 million during the second quarter and first six months of 2010, respectively. In addition to the impact of cash settlements, these net gains and losses were also impacted by new positions that occurred during each period, as well as the relationships between contract prices and the associated forward curves. A summary of our outstanding oil, gas and NGL derivative positions as of June 30, 2011 is included in Item 3. “Quantitative and Qualitative Disclosures About Market Risk” of this report.
Marketing and Midstream Revenues and Operating Costs and Expenses
                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     Change(1)     2011     2010     Change(1)  
    ($ in millions)  
Marketing and midstream:
                                               
Revenues
  $ 604     $ 405       +49 %   $ 1,059     $ 935       +13 %
Operating costs and expenses
    456       280       +63 %     789       677       +16 %
 
                                       
Operating profit
  $ 148     $ 125       +19 %   $ 270     $ 258       +5 %
 
                                       
 
(1)   All percentage changes included in this table are based on actual figures rather than the rounded figures presented.
     During the second quarter of 2011, marketing and midstream revenues increased $199 million and operating costs and expenses increased $176 million, causing operating profit to increase $23 million. During the first six months of 2011, marketing and midstream revenues increased $124 million and operating costs and expenses increased $112 million, causing operating profit to increase $12 million. The increases in each period were primarily due to higher NGL prices and higher natural gas throughput and NGL production.
Lease Operating Expenses (“LOE”)
                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     Change(1)     2011     2010     Change(1)  
Lease operating expenses ($ in millions):
                                               
U.S. Onshore
  $ 224     $ 216       +4 %   $ 432     $ 407       +6 %
Canada
    229       199       +15 %     445       389       +14 %
 
                                       
North America Onshore
    453       415       +9 %     877       796       +10 %
U.S. Offshore
          27       -100 %           60       -100 %
 
                                       
Total
  $ 453     $ 442       +3 %   $ 877     $ 856       +3 %
 
                                       
 
                                               
Lease operating expenses per Boe:
                                               
U.S. Onshore
  $ 5.18     $ 5.52       -6 %   $ 5.15     $ 5.33       -3 %
Canada
  $ 13.71     $ 11.53       +19 %   $ 13.63     $ 11.80       +16 %
North America Onshore
  $ 7.55     $ 7.36       +3 %   $ 7.52     $ 7.28       +3 %
U.S. Offshore
  $     $ 13.18       N/M     $     $ 12.00       N/M  
Total
  $ 7.55     $ 7.56       0 %   $ 7.52     $ 7.49       0 %
 
(1)   All percentage changes included in this table are based on actual figures rather than the rounded figures presented.
     LOE increased $11 million in the second quarter of 2011. This amount consisted of a $38 million increase related to our North America Onshore operations and a $27 million decrease related to our U.S. Offshore operations that were sold in the second quarter of 2010. Our 6 percent increase in North America Onshore production increased LOE by $27 million. Additionally, North America Onshore LOE increased $14 million due to changes in the exchange rate between the U.S. and Canadian dollars. The higher exchange rate was also the main contributor to the increases in North America Onshore and total LOE per Boe.
     LOE increased $21 million in the first six months of 2011. This amount consisted of an $81 million increase related to our North America Onshore operations and a $60 million decrease related to our U.S. Offshore operations that were sold in the

32


Table of Contents

second quarter of 2010. Our 7 percent increase in North America Onshore production increased LOE by $54 million. Additionally, North America Onshore LOE increased $25 million due to changes in the exchange rate between the U.S. and Canadian dollars. The higher exchange rate was also the main contributor to the increases in North America Onshore and total LOE per Boe.
Taxes Other Than Income Taxes
                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     Change(1)     2011     2010     Change(1)  
                    ($ in millions)                  
Production
  $ 68     $ 46       +48 %   $ 124     $ 105       +18 %
Ad valorem
    51       46       +10 %     101       86       +17 %
Other
    1             +175 %     3       2       +62 %
 
                                       
Total
  $ 120     $ 92       +30 %   $ 228     $ 193       +18 %
 
                                       
 
(1)   All percentage changes included in this table are based on actual figures rather than the rounded figures presented.
     Production taxes increased $22 million and $19 million in the second quarter of 2011 and first six months of 2011, respectively, primarily due to an increase in our U.S. Onshore revenues. Ad valorem taxes increased $5 million and $15 million in the second quarter and first six months of 2011, respectively, primarily due to higher estimated assessed values of our oil and gas property and equipment.
Depreciation, Depletion and Amortization of Oil and Gas Properties (“DD&A”)
                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     Change(1)     2011     2010     Change(1)  
Total production volumes (MMBoe)
    60       58       +3 %     117       114       +2 %
DD&A rate ($  per Boe)
  $ 8.08     $ 7.28       +11 %   $ 7.95     $ 7.45       +7 %
 
                                       
DD&A expense ($ in millions)
  $ 485     $ 426       +14 %   $ 927     $ 852       +9 %
 
                                       
 
(1)   All percentage changes included in this table are based on actual figures rather than the rounded figures presented.
     The following table details the changes in DD&A of oil and gas properties between the three and six months ended June 30, 2011 and 2010 (in millions).
                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
2010 DD&A
  $ 426     $ 852  
Change due to rate
    48       58  
Change due to volumes
    11       17  
 
           
2011 DD&A
  $ 485     $ 927  
 
           
     Oil and gas property-related DD&A increased $48 million and $58 million in the second quarter of 2011 and first six months of 2011, respectively, due to 11 percent and 7 percent increases in the respective DD&A rates. The largest contributors to the higher rates were our drilling and development activities subsequent to the end of the second quarter of 2010 and changes in the exchange rate between the U.S. and Canadian dollars. These increases were partially offset by a decrease in the rate due to our 2010 U.S. offshore property divestitures.

33


Table of Contents

General and Administrative Expenses (“G&A”)
                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     Change(1)     2011     2010     Change(1)  
    ($ in millions)  
Gross G&A
  $ 245     $ 240       +3 %   $ 483     $ 485       0 %
Capitalized G&A
    (81 )     (81 )     +1 %     (162 )     (161 )     +1 %
Reimbursed G&A
    (29 )     (29 )     0 %     (56 )     (56 )     0 %
 
                                       
Net G&A
  $ 135     $ 130       +4 %   $ 265     $ 268       -1 %
 
                                       
 
(1)   All percentage changes included in this table are based on actual figures rather than the rounded figures presented.
     Gross and net G&A increased during the second quarter of 2011 primarily due to changes in the exchange rate between the U.S. and Canadian dollars. Gross and net G&A decreased during the first six months of 2011 primarily due to lower employee compensation and benefits resulting from our 2010 offshore divestitures.
Interest Expense
                                 
    Three Months     Six Months  
    Ended June 30,     Ended June 30,  
    2011     2010     2011     2010  
    (In millions)  
Interest based on debt outstanding
  $ 100     $ 104     $ 198     $ 209  
Capitalized interest
    (17 )     (14 )     (37 )     (35 )
Early retirement of debt
          19             19  
Other
    2       2       5       4  
 
                       
Total interest expense
  $ 85     $ 111     $ 166     $ 197  
 
                       
     Interest expense decreased during the second quarter and first six months of 2011 primarily due to the early redemption of our 7.25 percent $350 million senior notes in the second quarter of 2010. When we redeemed these notes prior to their scheduled maturity, we recognized $19 million of additional interest expense related to the early retirement of the debt.
Interest-Rate and Other Financial Instruments
                                 
    Three Months     Six Months  
    Ended June 30,     Ended June 30,  
    2011     2010     2011     2010  
    (In millions)  
(Gains) losses from interest rate swaps:
                               
Cash settlements
  $ (5 )   $ (4 )   $ (21 )   $ (20 )
Unrealized fair value changes
    30       85       29       86  
 
                       
Total
  $ 25     $ 81     $ 8     $ 66  
 
                       
     During the second quarter and first six months of 2011, we received cash settlements totaling $5 million and $21 million, respectively, from counterparties to settle our interest rate swaps. During the second quarter and first six months of 2010, we received cash settlements totaling $4 million and $20 million, respectively.
     In addition to recognizing cash settlements, we recognize unrealized changes in the fair values of our interest rate swaps each reporting period. We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest-rate yields. We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers. During the second quarter and first six months of 2011, we incurred unrealized losses of $30 million and $29 million, respectively, as a result of changes in interest rates. During the second quarter and first six months of 2010, we incurred unrealized losses of $85 million and $86 million, respectively.
     The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by a third party. Based on the notional amount subject to the interest rate swaps at June 30, 2011, a 10% increase in these forward curves would have decreased our unrealized losses for our interest rate swaps by approximately $79 million.

34


Table of Contents

     Similar to our commodity derivative contracts, counterparty credit risk is also a component of interest rate derivative valuations. We have mitigated our exposure to any single counterparty by contracting with seven separate counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $55 million for the majority of our contracts. The credit ratings of all our counterparties were investment grade as of June 30, 2011.
Income Taxes
     The following table presents our total income tax expense and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate.
                                 
    Three Months     Six Months  
    Ended June 30,     Ended June 30,  
    2011     2010     2011     2010  
Total income tax expense (in millions)
  $ 1,194     $ 261     $ 1,385     $ 775  
 
                       
 
                               
U.S. statutory income tax rate
    35 %     35 %     35 %     35 %
State income taxes
    1 %     3 %     1 %     1 %
Taxation on Canadian operations
    (2 %)     (1 %)     (2 %)     (1 %)
Assumed repatriations
    54 %     8 %     38 %     2 %
Other
    (1 %)     (2 %)     (1 %)     (2 %)
 
                       
Effective income tax rate
    87 %     43 %     71 %     35 %
 
                       
     In the second quarter of 2011, a portion of our foreign earnings were no longer deemed to be permanently reinvested in accordance with accounting principles generally accepted in the United States of America. Accordingly, we recognized $725 million of deferred tax expense and $19 million of current income tax expense during the second quarter of 2011 related to assumed repatriations of such earnings under current U.S. tax law. These earnings were primarily related to the gains generated from our International divestiture transactions. Excluding the $744 million of tax expense, our effective income tax rate was 33% in both the second quarter and first six months of 2011.
     In the second quarter of 2010, we recognized $52 million of deferred income tax expense related to assumed repatriations of earnings from certain of our foreign subsidiaries. Excluding the $52 million of deferred tax expense, our effective income tax rate was 35% and 33% in the second quarter and first six months of 2010.
Earnings From Discontinued Operations
     The following table presents the components of our earnings from discontinued operations.
                                 
    Three Months     Six Months  
    Ended June 30,     Ended June 30,  
    2011     2010     2011     2010  
Total production (MMBoe)
          3       1       6  
Combined price without hedges (per Boe)
  $     $ 74.45     $ 81.94     $ 73.56  
    (In millions)  
Operating revenues
  $     $ 222     $ 43     $ 434  
 
                       
Expenses and other, net:
                               
Operating expenses
    7       56       33       133  
Gain on sale of oil and gas properties
    (2,546 )     (308 )     (2,546 )     (308 )
Other, net
    (19 )     1       (32 )     (1 )
 
                       
Total expenses and other, net
    (2,558 )     (251 )     (2,545 )     (176 )
 
                       
Earnings before income taxes
    2,558       473       2,588       610  
Income tax (benefit) expense
    (1 )     119       2       138  
 
                       
Earnings from discontinued operations
  $ 2,559     $ 354     $ 2,586     $ 472  
 
                       

35


Table of Contents

     Earnings increased in the second quarter and first six months of 2011 primarily as a result of the $2.5 billion gain ($2.5 billion after-tax) recognized from the divestiture of our Brazil operations. This increase was partially offset by a $308 million gain ($235 million after taxes) recognized from the divestiture of our Panyu operations in China during the second quarter of 2010.
Capital Resources, Uses and Liquidity
     The following discussion of capital resources and liquidity should be read in conjunction with the consolidated statements of cash flows included in Part I, Item 1.
Sources and Uses of Cash
                 
    Six Months Ended June 30,  
    2011     2010  
    (In millions)  
Sources of cash and cash equivalents:
               
Operating cash flow — continuing operations
  $ 2,830     $ 2,619  
Cash reclassified from discontinued operations
    3,251       450  
Commercial paper borrowings
    2,340        
Stock option exercises
    96       15  
Divestitures of property and equipment
    5       4,129  
Other
    13       24  
 
           
Total sources of cash and cash equivalents
    8,535       7,237  
 
           
Uses of cash and cash equivalents:
               
Capital expenditures
    (3,720 )     (3,221 )
Net purchases of short-term investments
    (3,222 )      
Repurchases of common stock
    (1,290 )     (430 )
Dividends
    (140 )     (142 )
Commercial paper repayments
          (1,432 )
Debt repayments
          (350 )
Other
    (33 )      
 
           
Total uses of cash and cash equivalents
    (8,405 )     (5,575 )
 
           
Increase from continuing operations
    130       1,662  
(Decrease) increase from discontinued operations, net of reclassifications to continuing operations
    (101 )     252  
Effect of foreign exchange rates
    32       (9 )
 
           
Net increase in cash and cash equivalents
  $ 61     $ 1,905  
 
           
Cash and cash equivalents at end of period
  $ 3,351     $ 2,916  
 
           
Short-term investments at end of period
  $ 3,367     $  
 
           
Operating Cash Flow — Continuing Operations
     Net cash provided by operating activities (“operating cash flow”) continued to be a significant source of capital and liquidity in the first six months of 2011. Our operating cash flow increased approximately 8 percent during 2011 largely due to higher current income taxes in 2010 associated with taxable gains on our U.S. Offshore divestitures. Higher commodity prices and production, partially offset by lower realized gains from our commodity derivatives, also contributed to the increase in cash flow.
Other Sources of Cash — Continuing and Discontinued Operations
     As needed, we supplement our operating cash flow and available cash by accessing available credit under our credit facilities and commercial paper program. We may also issue long-term debt to supplement our operating cash flow while maintaining adequate liquidity under our credit facilities. Additionally, we may acquire short-term investments to maximize our income on available cash balances. As needed, we reduce such short-term investment balances to further supplement our operating cash flow and available cash. Another source of cash proceeds comes from employee stock option exercises.
     During the second quarter of 2011, we completed the divestiture of our operations in Brazil, generating $3.3 billion in net proceeds.

36


Table of Contents

     During the first six months of 2011, we utilized commercial paper borrowings of $2.3 billion to fund capital expenditures, common share repurchases and dividends in excess of our operating cash flow.
     During the first six months of 2011, we received proceeds of $96 million from shares issued for employee stock option exercises.
     During the first six months of 2010, we completed the divestiture of all our U.S. Offshore properties and our Panyu operations in China, generating $4.6 billion in pre-tax proceeds ($3.6 billion after taxes). We used proceeds from these divestitures to repay commercial paper borrowings, retire $350 million of other debt and repurchase our common shares. In addition, we redeployed $500 million of proceeds into our North America Onshore properties by acquiring a 50% interest in the Pike oil sands in Alberta, Canada.
Capital Expenditures
     Our capital expenditures are presented by geographic area and type in the following table. The amounts in the table reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior quarters. Capital expenditures actually incurred during the first six months of 2011 and 2010 were approximately $3.6 billion and $3.3 billion, respectively.
                 
    Six Months Ended June 30,  
    2011     2010  
    (In millions)  
U.S. Onshore
  $ 2,375     $ 1,468  
Canada
    936       1,202  
 
           
North America Onshore
    3,311       2,670  
U.S. Offshore
          287  
 
           
Total exploration and development
    3,311       2,957  
Midstream
    151       108  
Other
    258       156  
 
           
Total continuing operations
  $ 3,720     $ 3,221  
 
           
     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 and development of oil and gas properties, which totaled $3.3 billion and $3.0 billion in the first six months of 2011 and 2010, respectively. Excluding the $500 million Pike oil sands acquisition in 2010, the increase in exploration and development capital spending in the first six months of 2011 was primarily due to increased drilling and development and new venture acreage acquisitions. With rising oil prices and proceeds from our offshore divestitures, we are increasing our acreage positions and associated exploration and development activities to drive near-term growth of our onshore liquids production.
     Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas pipeline systems and oil pipelines. Our midstream capital expenditures are largely impacted by oil and gas drilling activities. Therefore, the increase in development drilling also increased midstream capital activities.
     Capital expenditures related to corporate activities increased in 2011. This increase is largely driven by the construction of our new headquarters in Oklahoma City.
Short-term Investments
     During the first six months of 2011, we had net short-term investment purchases totaling $3.2 billion. These purchases represent our investment of a portion of the International offshore divestiture proceeds into United States Treasury securities. As of June 30, 2011, the average remaining maturity of these short-term investments was 67 days.

37


Table of Contents

Repurchases of Common Stock
     During the first six months of 2011, we continued repurchasing shares under our $3.5 billion stock repurchase program announced in May 2010. Including unsettled shares, we repurchased 15.2 million common shares for $1.3 billion, or $84.52 per share, in the first six months of 2011. This program expires on December 31, 2011.
Dividends
     We paid common stock dividends of $140 million and $142 million in the first six months of 2011 and 2010, respectively. The quarterly cash dividend was $0.16 per share in the first and second quarter of 2010 and the first quarter of 2011. In the second quarter of 2011, we increased the dividend rate to $0.17 per share.
Liquidity
     Historically, our primary source of capital and liquidity has been operating cash flow and cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include equity and debt securities that can be issued pursuant to our automatically effective shelf registration statement filed with the SEC. We estimate the combination of these sources of capital will be adequate to fund future capital expenditures, share repurchases, debt repayments and other contractual commitments. The following sections discuss changes to our liquidity subsequent to filing our 2010 Annual Report on Form 10-K.
Operating Cash Flow
     We expect operating cash flow to continue to be our primary source of liquidity. Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, gas and NGLs produced. To mitigate some of the risk inherent in prices, we have utilized various price swap, fixed-price physical delivery and price collar contracts to set minimum and maximum prices on our 2011 production. As of June 30, 2011, approximately 38 percent of our 2011 gas production is associated with financial price swaps, collars and fixed-price physicals. We also have basis swaps associated with 0.2 Bcf per day of our 2011 gas production. Additionally, approximately 36 percent of our 2011 oil production is associated with financial price collars. We also have call options that, if exercised, would relate to an additional 16 percent of our 2011 oil production.
     Looking beyond 2011, we have also entered into contracts to manage the price risk relative to our 2012 and 2013 oil, gas and NGL production. A summary of these contracts as of June 30, 2011, is included in Item 3. “Quantitative and Qualitative Disclosures About Market Risk” of this report.
Offshore Divestitures
     In May 2011, we completed the divestiture of our operations in Brazil. With the close of the Brazil transaction, we have substantially completed our planned offshore divestitures. In aggregate, our U.S. and International offshore sales generated total proceeds of $10 billion, or approximately $8 billion after-tax assuming repatriation of a portion of the foreign proceeds under current U.S. tax law.
     Furthermore, in connection with the divestiture of our Brazil assets, our remaining deepwater drilling rig and floating, production storage and offloading facility commitments were assumed by the purchaser of the assets.
Credit Availability
     In March 2011, our Board of Directors authorized an increase in our commercial paper program from $2.2 billion to $5.0 billion.
     In July 2011, we issued $500 million of 2.40% senior notes due July 15, 2016, $500 million of 4.00% senior notes due July 15, 2021 and $1,250 million of 5.60% senior notes due July 15, 2041. The net proceeds from this issuance are being used to repay our outstanding commercial paper as it matures. As of July 22, we had repaid $1.9 billion of commercial paper borrowings, and had $2.6 billion of available capacity under our syndicated, unsecured Senior Credit Facility.
     The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65 percent. The credit agreement

38


Table of Contents

defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial writedowns, such as full cost ceiling impairments. As of June 30, 2011, we were in compliance with this covenant. Our debt-to-capitalization ratio at June 30, 2011, as calculated pursuant to the terms of the agreement, was 19.3 percent.
     Although we ended the second quarter of 2011 with $6.7 billion of cash and short-term investments, the vast majority of this amount consists of proceeds from our International offshore divestitures. Based on our evaluation of future cash needs across our operations in the United States and Canada, these proceeds remain outside of the United States. With these proceeds remaining outside of the United States, we expect to continue to increase our commercial paper borrowings in the United States to supplement our United States based operating cash flow to fund our capital expenditures, common stock repurchase program and repay long-term debt.
Capital Expenditures
     We previously disclosed that we expected our 2011 capital expenditures to range from $5.4 billion to $6.0 billion. In the first half of 2011, we expanded our Canadian, Permian Basin and new ventures exploration activities, which were all targeted at oil and liquids-rich opportunities. We also increased drilling activity in the liquids-rich portions of the Barnett and Cana shales. Additionally, we are experiencing upward pressure on costs due to industry inflation and a weaker U.S. dollar compared to the Canadian dollar. As a result, we increased our total estimated capital expenditures. We now expect our 2011 capital expenditures to range from $6.7 billion to $7.3 billion. We anticipate having adequate capital resources to fund our capital expenditures.
Common Stock Repurchase Program
     As of July 22, 2011, we had repurchased $2.6 billion, or 35.1 million common shares at an average price of $74.44 under our $3.5 billion repurchase program. This program expires on December 31, 2011.
Pension Funding and Estimates
     We previously disclosed that we expected to contribute approximately $84 million to our qualified pension plans during 2011. We now expect to contribute $346 million to our qualified pension plans in 2011, including $246 million that was contributed in the first six months of 2011 and $100 million that was contributed in July 2011. The increase in our 2011 estimated contribution is due to discretionary funding.
Recently Issued Accounting Standards Not Yet Adopted
     In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. However, beginning in our 2011 Annual Report on Form 10-K, this update will require certain additional disclosures related to our fair value measurements. We do not expect the adoption of this update will materially impact our financial statement disclosures.
     In June 2011, the FASB issued Accounting Standards Update 2011-05, Presentation of Comprehensive Income. Beginning in our 2011 Annual Report on Form 10-K, this update will give us the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. We have not determined which presentation option we will choose but do not expect our selection to materially impact the presentation of our financial statements.

39


Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
     We have commodity derivatives that pertain to production for the last six months of 2011, as well as 2012 and 2013. The key terms to all our oil, gas and NGL derivative financial instruments as of June 30, 2011 are presented in the following tables.
     We had the following open oil derivative positions. Our oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price.
                                                         
Production            
Period   Price Swaps   Price Collars   Call Options Sold
            Weighted           Weighted   Weighted           Weighted
    Volume   Average Price   Volume   Average Floor Price   Average Ceiling Price   Volume   Average Price
Period   (Bbls/d)   ($/Bbl)   (Bbls/d)   ($/Bbl)   ($/Bbl)   (Bbls/d)   ($/Bbl)
Q3-Q4 2011
                45,000     $ 75.00     $ 108.89       19,500     $ 95.00  
Q1-Q4 2012
    22,000     $ 107.17       54,000     $ 85.74     $ 126.42       19,500     $ 95.00  
Q1-Q4 2013
                7,000     $ 90.00     $ 125.12              
     We had the following open natural gas derivative positions. Our natural gas derivative swaps, collars and call options settle against the Inside Ferc first of the month Henry Hub index.
                                                         
Production                    
Period   Price Swaps           Price Collars   Call Options Sold
            Weighted           Weighted   Weighted           Weighted
    Volume   Average Price   Volume   Average Floor Price   Average Ceiling Price   Volume   Average Price
Period   (MMBtu/d)   ($/MMBtu)   (MMBtu/d)   ($/MMBtu)   ($/MMBtu)   (MMBtu/d)   ($/MMBtu)
Q3-Q4 2011
    712,500     $ 5.51       215,000       4.75       5.17              
Q1-Q4 2012
    325,000     $ 5.09       490,000       4.75       5.57       487,500     $ 6.00  
                         
Basis Swaps
                    Weighted Average
                    Differential to
            Volume   Henry Hub
Production Period   Index   (MMBtu/d)   ($/MMBtu)
Q3-Q4 2011
  Panhandle Eastern Pipeline     150,000     $ (0.33 )
     We had the following open NGL derivative positions:
                         
NGL Basis Swaps
                    Weighted Average
            Volume   Differential to WTI
Production Period   Pay   (Bbls/d)   ($/Bbl)
Q3-Q4 2011
  Natural Gasoline     416     $ (9.75 )
Q1-Q4 2012
  Natural Gasoline     500     $ (10.10 )
Q1-Q4 2013
  Natural Gasoline     500     $ (6.80 )
     The fair values of our commodity derivatives presented in the tables above are largely determined by estimates of the forward curves of the relevant price indices. At June 30, 2011, a 10 percent increase in the forward curves associated with our gas derivative instruments would have increased our unrealized losses by approximately $224 million. A 10 percent increase in the forward curves associated with our oil derivative instruments would have decreased our unrealized gains by approximately $300 million.
Interest Rate Risk
     At June 30, 2011, we had debt outstanding of $7.9 billion. Of this amount, $5.6 billion, or 70 percent bears fixed interest rates averaging 7.2 percent. Additionally, we had $2.3 billion of outstanding commercial paper, bearing interest at floating rates which averaged 0.27 percent.

40


Table of Contents

     As of June 30, 2011, we had the open interest rate swap positions listed in the following table. As of June 30, 2011, we also had forward starting swaps and U.S. Treasury locks that were net settled in July 2011 in conjunction with our $2.25 billion debt issuance. We received $35 million to settle these derivatives.
                         
Fixed-to-Floating Swaps
        Fixed Rate   Variable    
Notional   Received   Rate Paid   Expiration
(In millions)                    
$ 300       4.30 %  
Six month LIBOR
  July 18, 2011
  100       1.90 %  
Federal funds rate
  August 3, 2012
  500       3.90 %  
Federal funds rate
  July 18, 2013
  250       3.85 %  
Federal funds rate
  July 22, 2013
$ 1,150       3.82 %  
 
       
     The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the Federal Funds rate and LIBOR. At June 30, 2011, a 10 percent increase in these forward curves would have decreased our unrealized losses for our interest rate swaps by approximately $79 million.
Foreign Currency Risk
     Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period. A 10 percent unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our June 30, 2011 balance sheet.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
     We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.
     Based on their evaluation, Devon’s principal executive and principal financial officers have concluded that Devon’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of June 30, 2011, to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Changes in Internal Control Over Financial Reporting
     There was no change in Devon’s internal control over financial reporting during the second quarter of 2011 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.

41


Table of Contents

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 2010 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 2010 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
                         
                    Maximum Dollar Value
    Total Number           of Shares that May Yet
    of Shares   Average Price   Be Purchased Under the
2011 Period   Purchased(1)   Paid per Share   Plans or Programs(1)
                    (In millions)
April 1 — April 30
    1,907,538     $ 88.81     $ 1,433  
May 1 — May 31
    2,217,710     $ 82.83     $ 1,250  
June 1 — June 30
    2,942,530     $ 79.08     $ 1,017  
 
                       
Total
    7,067,778     $ 82.88          
 
                       
 
(1)   In May 2010, our Board of Directors approved a $3.5 billion share repurchase program. This program expires December 31, 2011. As of June 30, 2011, we had repurchased 33.5 million common shares for $2.5 billion, or $74.16 per share under this program.
Item 3. Defaults Upon Senior Securities
     None.
Item 5. Other Information
     None.
Item 6. Exhibits
     (a) Exhibits required by Item 601 of Regulation S-K are as follows:
     
Exhibit    
Number   Description
31.1
  Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
  Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
  Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
  Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS
  XBRL Instance Document
101.SCH
  XBRL Taxonomy Extension Schema Document
101.CAL
  XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB
  XBRL Taxonomy Extension Labels Linkbase Document
101.PRE
  XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF
  XBRL Taxonomy Extension Definition Linkbase Document

42


Table of Contents

SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  DEVON ENERGY CORPORATION
 
 
Date: August 3, 2011  /s/ Jeffrey A. Agosta    
  Jeffrey A. Agosta   
  Executive Vice President — Chief Financial Officer   

43


Table of Contents

         
INDEX TO EXHIBITS
     
Exhibit
Number
  Description
31.1
  Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
  Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
  Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
  Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS
  XBRL Instance Document
101.SCH
  XBRL Taxonomy Extension Schema Document
101.CAL
  XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB
  XBRL Taxonomy Extension Labels Linkbase Document
101.PRE
  XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF
  XBRL Taxonomy Extension Definition Linkbase Document

44