eog3qtr10-q.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 
FORM 10-Q
 
(Mark One)

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

For the quarterly period ended September 30, 2011

or

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

Commission File Number: 1-9743
EOG Logo
EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)

Delaware
 
47-0684736
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002
(Address of principal executive offices)       (Zip Code)

713-651-7000
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x  No 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 x  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 x    Accelerated filer o    Non-accelerated filer o   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 x

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Title of each class
Number of shares
Common Stock, par value $0.01 per share
268,850,778 (as of October 26, 2011)


 
 

 



EOG RESOURCES, INC.

TABLE OF CONTENTS



PART I.
FINANCIAL INFORMATION
Page No.
     
 
ITEM 1.
Financial Statements (Unaudited)
 
       
   
 
3
       
   
4
       
   
 
5
       
   
6
       
 
ITEM 2.
 
20
       
 
ITEM 3.
37
       
 
ITEM 4.
37
       
PART II.
OTHER INFORMATION
 
       
 
ITEM 1.
38
       
 
ITEM 2.
38
       
 
ITEM 5.
38
       
 
ITEM 6.
40
       
 
41
       
 
42


 
- 2 -

 

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Data)
(Unaudited)

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
                         
                         
Net Operating Revenues
                       
Crude Oil and Condensate
  $ 953,154     $ 506,368     $ 2,649,034     $ 1,368,338  
Natural Gas Liquids
    206,572       107,482       539,104       314,750  
Natural Gas
    576,803       602,242       1,760,715       1,832,578  
Gains on Mark-to-Market Commodity Derivative Contracts
    357,664       60,998       480,539       105,816  
Gathering, Processing and Marketing
    578,022       233,971       1,461,303       601,790  
Gains on Asset Dispositions, Net
    207,468       64,809       442,981       72,441  
Other, Net
    6,061       6,205       19,424       15,023  
Total
    2,885,744       1,582,075       7,353,100       4,310,736  
                                 
Operating Expenses
                               
Lease and Well
    248,926       180,921       680,710       507,647  
Transportation Costs
    108,678       103,262       308,276       286,318  
Gathering and Processing Costs
    18,532       18,472       55,444       47,353  
Exploration Costs
    48,469       47,307       140,616       148,635  
Dry Hole Costs
    22,604       2,700       47,231       45,095  
Impairments
    83,431       352,908       531,413       502,865  
Marketing Costs
    572,604       231,758       1,427,450       591,735  
Depreciation, Depletion and Amortization
    651,684       500,888       1,822,854       1,398,137  
General and Administrative
    82,260       81,310       219,703       206,470  
Taxes Other Than Income
    98,526       74,244       308,669       227,773  
Total
    1,935,714       1,593,770       5,542,366       3,962,028  
                                 
Operating Income (Loss)
    950,030       (11,695 )     1,810,734       348,708  
Other Income, Net
    1,377       5,772       11,205       7,910  
Income (Loss) Before Interest Expense and Income Taxes
    951,407       (5,923 )     1,821,939       356,618  
Interest Expense, Net
    52,186       32,890       153,772       88,215  
Income (Loss) Before Income Taxes
    899,221       (38,813 )     1,668,167       268,403  
Income Tax Provision
    358,343       32,093       697,742       161,422  
Net Income (Loss)
  $ 540,878     $ (70,906 )   $ 970,425     $ 106,981  
                                 
Net Income (Loss) Per Share
                               
Basic
  $ 2.03     $ (0.28 )   $ 3.71     $ 0.43  
Diluted
  $ 2.01     $ (0.28 )   $ 3.66     $ 0.42  
                                 
Dividends Declared per Common Share
  $ 0.160     $ 0.155     $ 0.480     $ 0.465  
                                 
Average Number of Common Shares
                               
Basic
    266,053       251,015       261,664       250,719  
Diluted
    269,292       251,015       265,245       254,444  
                                 

The accompanying notes are an integral part of these consolidated financial statements.

 
- 3 -

 

EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
(Unaudited)

   
September 30,
   
December 31,
 
   
2011
   
2010
 
ASSETS
 
Current Assets
           
Cash and Cash Equivalents
  $ 1,386,728     $ 788,853  
Accounts Receivable, Net
    1,249,649       1,113,279  
Inventories
    580,355       415,792  
Assets from Price Risk Management Activities
    364,991       48,153  
Income Taxes Receivable
    28,013       54,916  
Deferred Income Taxes
    -       9,260  
Other
    125,626       97,193  
      Total
    3,735,362       2,527,446  
                 
Property, Plant and Equipment
               
Oil and Gas Properties (Successful Efforts Method)
    32,196,279       29,263,809  
   Other Property, Plant and Equipment
    1,993,824       1,733,073  
      Total Property, Plant and Equipment
    34,190,103       30,996,882  
   Less:  Accumulated Depreciation, Depletion and Amortization
    (13,453,905 )     (12,315,982 )
      Total Property, Plant and Equipment, Net
    20,736,198       18,680,900  
Other Assets
    323,118       415,887  
Total Assets
  $ 24,794,678     $ 21,624,233  
                 
                 
LIABILITIES AND STOCKHOLDERS' EQUITY
 
Current Liabilities
               
   Accounts Payable
  $ 1,926,455     $ 1,664,944  
   Accrued Taxes Payable
    157,297       82,168  
   Dividends Payable
    43,015       38,962  
   Liabilities from Price Risk Management Activities
    -       28,339  
   Deferred Income Taxes
    139,646       41,703  
   Current Portion of Long-Term Debt
    220,000       220,000  
   Other
    179,910       143,983  
      Total
    2,666,323       2,220,099  
                 
Long-Term Debt
    5,007,746       5,003,341  
Other Liabilities
    768,518       667,455  
Deferred Income Taxes
    3,858,243       3,501,706  
Commitments and Contingencies (Note 9)
               
                 
Stockholders' Equity
               
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 269,124,759 Shares Issued at September 30, 2011 and 254,223,521 Shares Issued at December 31, 2010
    202,691       202,542  
Additional Paid in Capital
    2,230,600       729,992  
Accumulated Other Comprehensive Income
    372,448       440,071  
Retained Earnings
    9,711,207       8,870,179  
Common Stock Held in Treasury, 281,595 Shares at September 30, 2011 and 146,186 Shares at December 31, 2010
    (23,098 )     (11,152 )
Total Stockholders' Equity
    12,493,848       10,231,632  
Total Liabilities and Stockholders' Equity
  $ 24,794,678     $ 21,624,233  
                 

The accompanying notes are an integral part of these consolidated financial statements.


 
- 4 -

 

EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)

   
Nine Months Ended
 
   
September 30,
 
   
2011
   
2010
 
Cash Flows from Operating Activities
           
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
           
Net Income
  $ 970,425     $ 106,981  
Items Not Requiring (Providing) Cash
               
Depreciation, Depletion and Amortization
    1,822,854       1,398,137  
Impairments
    531,413       502,865  
Stock-Based Compensation Expenses
    95,057       81,700  
Deferred Income Taxes
    499,279       53,067  
Gains on Asset Dispositions, Net
    (442,981 )     (72,441 )
Other, Net
    2,270       (2,317 )
Dry Hole Costs
    47,231       45,095  
Mark-to-Market Commodity Derivative Contracts
               
Total Gains
    (480,539 )     (105,816 )
Realized Gains
    83,765       25,180  
Other, Net
    21,052       13,354  
Changes in Components of Working Capital and Other Assets and Liabilities
               
Accounts Receivable
    (128,965 )     (124,813 )
Inventories
    (167,611 )     (134,181 )
Accounts Payable
    245,385       527,418  
Accrued Taxes Payable
    101,239       (40,104 )
Other Assets
    (28,600 )     (16,051 )
Other Liabilities
    37,022       44,348  
Changes in Components of Working Capital Associated with Investing and Financing Activities
    133,227       (216,695 )
Net Cash Provided by Operating Activities
    3,341,523       2,085,727  
                 
Investing Cash Flows
               
Additions to Oil and Gas Properties
    (4,665,535 )     (3,740,883 )
Additions to Other Property, Plant and Equipment
    (502,112 )     (223,072 )
Proceeds from Sales of Assets
    1,294,627       126,371  
Changes in Components of Working Capital Associated with Investing Activities
    (133,512 )     216,546  
Other, Net
    -       (4,206 )
Net Cash Used in Investing Activities
    (4,006,532 )     (3,625,244 )
                 
Financing Cash Flows
               
Common Stock Sold
    1,388,270       -  
Net Commercial Paper Borrowings
    -       33,700  
Long-Term Debt Borrowings
    -       991,395  
Long-Term Debt Repayments
    -       (37,000 )
Dividends Paid
    (124,133 )     (114,277 )
Treasury Stock Purchased
    (21,357 )     (10,298 )
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
    26,887       24,527  
Debt Issuance Costs
    -       (6,469 )
Other, Net
    285       149  
Net Cash Provided by Financing Activities
    1,269,952       881,727  
                 
Effect of Exchange Rate Changes on Cash
    (7,068 )     (129 )
                 
Increase (Decrease) in Cash and Cash Equivalents
    597,875       (657,919 )
Cash and Cash Equivalents at Beginning of Period
    788,853       685,751  
Cash and Cash Equivalents at End of Period
  $ 1,386,728     $ 27,832  
                 
The accompanying notes are an integral part of these consolidated financial statements.

 
- 5 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


1.      Summary of Significant Accounting Policies

General.  The consolidated financial statements of EOG Resources, Inc., together with its subsidiaries (collectively, EOG), included herein have been prepared by management without audit pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC).  Accordingly, they reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods presented.  Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) have been condensed or omitted pursuant to such rules and regulations.  However, management believes that the disclosures included either on the face of the financial statements or in these notes are sufficient to make the interim information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in EOG's Annual Report on Form 10-K for the year ended December 31, 2010, filed on February 24, 2011 (EOG's 2010 Annual Report).

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.  The operating results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results to be expected for the full year.

Recently Issued Accounting Standards and Developments.  In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, which amends the Fair Value Measurements and Disclosures topic of the Accounting Standards Codification.  The amendments clarify the FASB's intent about the application of existing fair value measurement requirements and change certain principles or requirements for measuring fair value or disclosing information about fair value measurements.  ASU 2011-04 is effective for interim and annual fiscal periods beginning after December 15, 2011.  EOG does not expect that the adoption of ASU 2011-04 will have a material impact on its financial statements, but it may result in additional disclosures regarding fair value measurements.

In June 2011, the FASB issued ASU 2011-05 "Comprehensive Income (Topic 220): Presentation of Comprehensive Income."  ASU 2011-05 is intended to increase the prominence of comprehensive income in the financial statements by requiring that an entity that reports items of comprehensive income do so in either one continuous or two consecutive financial statements.  ASU 2011-05 also requires separate presentation on the face of the financial statements for items reclassified from other comprehensive income into net income.  The provisions of ASU 2011-05 are effective for interim and annual fiscal periods beginning after December 15, 2011.  Retroactive application is required.



 
- 6 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



2.      Stock-Based Compensation

As more fully discussed in Note 6 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, EOG maintains various stock-based compensation plans.  Stock-based compensation expense is included in the Consolidated Statements of Income based upon the job function of the employee receiving the grants as follows (in millions):

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
                         
Lease and Well
  $ 9.5     $ 8.0     $ 24.4     $ 20.3  
Gathering and Processing Costs
    0.2       0.1       0.6       0.4  
Exploration Costs
    7.8       7.3       19.4       18.1  
General and Administrative
    24.1       21.3       50.6       42.9  
   Total
  $ 41.6     $ 36.7     $ 95.0     $ 81.7  
 
The EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, as amended (2008 Plan), provides for grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units and other stock-based awards.  At September 30, 2011, approximately 4.9 million common shares remained available for grant under the 2008 Plan.  EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares.

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan.  The fair value of Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model.  The fair value of stock option and SAR grants is estimated using the Hull-White II binomial option pricing model.  Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $13.5 million and $12.6 million during the three months ended September 30, 2011 and 2010, respectively, and $33.4 million and $30.4 million during the nine months ended September 30, 2011 and 2010, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the nine-month periods ended September 30, 2011 and 2010 are as follows:

   
Stock Options/SARs
   
ESPP
 
   
Nine Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
                         
Weighted Average Fair Value of Grants
  $ 29.87     $ 32.10     $ 22.35     $ 25.42  
Expected Volatility
    40.92 %     39.74 %     29.68 %     38.18 %
Risk-Free Interest Rate
    0.58 %     0.87 %     0.18 %     0.18 %
Dividend Yield
    0.7 %     0.7 %     0.7 %     0.7 %
Expected Life
 
5.6 yrs
   
5.5 yrs
   
0.5 yrs
   
0.5 yrs
 


Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's common stock.  The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant.  The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants.


 
- 7 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



The following table sets forth stock option and SAR transactions for the nine-month periods ended September 30, 2011 and 2010 (stock options and SARs in thousands):
 
   
Nine Months Ended
   
Nine Months Ended
 
   
September 30, 2011
   
September 30, 2010
 
         
Weighted
         
Weighted
 
   
Number of
   
Average
   
Number of
   
Average
 
   
Stock
   
Grant
   
Stock
   
Grant
 
   
Options/SARs
   
Price
   
Options/SARs
   
Price
 
                         
Outstanding at January 1
    8,445     $ 64.49       8,335     $ 57.08  
Granted
    1,470       85.25       1,420       93.02  
Exercised (1)
    (1,150 )     48.41       (924 )     40.11  
Forfeited
    (133 )     87.75       (80 )     80.12  
Outstanding at September 30 (2)
    8,632     $ 69.80       8,751     $ 64.49  
                                 
Vested or Expected to Vest (3)
    8,387     $ 69.29       8,221     $ 64.01  
                                 
Exercisable at September 30 (4)
    5,382     $ 59.25       5,632     $ 51.79  

(1)
The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2011 and 2010 was $69 million and $58 million, respectively.  The intrinsic value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the stock options/SARs.
(2)
The total intrinsic value of stock options/SARs outstanding at September 30, 2011 and 2010 was $91 million and $252 million, respectively.  At September 30, 2011 and 2010, the weighted average remaining contractual life was 3.9 years and 4.1 years, respectively.
(3)
The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2011 and 2010 was $91 million and $241 million, respectively.  At September 30, 2011 and 2010, the weighted average remaining contractual life was 3.8 years and 4.1 years, respectively.
(4)
The total intrinsic value of stock options/SARs exercisable at September 30, 2011 and 2010 was $91 million and $233 million, respectively.  At September 30, 2011 and 2010, the weighted average remaining contractual life was 2.6 years and 3.0 years, respectively.

At September 30, 2011, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $100 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 3.0 years.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them.  Stock-based compensation expense related to restricted stock and restricted stock units totaled $28.1 million and $24.1 million for the three months ended September 30, 2011 and 2010, respectively, and $61.6 million and $51.3 million for the nine months ended September 30, 2011 and 2010, respectively.
 

 

 
- 8 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



The following table sets forth the restricted stock and restricted stock units transactions for the nine-month periods ended September 30, 2011 and 2010 (shares and units in thousands):
 
   
Nine Months Ended
   
Nine Months Ended
 
   
September 30, 2011
   
September 30, 2010
 
         
Weighted
         
Weighted
 
   
Number of
   
Average
   
Number of
   
Average
 
   
Shares and
   
Grant Date
   
Shares and
   
Grant Date
 
   
Units
   
Fair Value
   
Units
   
Fair Value
 
                         
Outstanding at January 1
    4,009     $ 79.13       3,636     $ 73.69  
Granted
    917       90.93       840       93.36  
Released (1)
    (410 )     65.77       (308 )     53.99  
Forfeited
    (202 )     82.51       (57 )     77.71  
Outstanding at September 30 (2)
    4,314     $ 82.75       4,111     $ 79.13  

(1)
The total intrinsic value of restricted stock and restricted stock units released for the nine months ended September 30, 2011 and 2010 was $40 million and $30 million, respectively.  The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.
(2)
The total intrinsic value of restricted stock and restricted stock units outstanding at September 30, 2011 and 2010 was $306 million and $382 million, respectively.

At September 30, 2011, unrecognized compensation expense related to restricted stock and restricted stock units totaled $153 million.  Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.7 years.

3.      Net Income (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the three-month and nine-month periods ended September 30, 2011 and 2010 (in thousands, except per share data).  For the three-month period ending September 30, 2010, the same number of shares was used in the calculation of both basic and diluted earnings per share as a result of the net loss during the period.

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Numerator for Basic and Diluted Earnings Per Share -
                       
Net Income (Loss)
  $ 540,878     $ (70,906 )   $ 970,425     $ 106,981  
                                 
Denominator for Basic Earnings Per Share -
                               
Weighted Average Shares
    266,053       251,015       261,664       250,719  
Potential Dilutive Common Shares -
                               
Stock Options/SARs
    1,479       -       1,759       2,059  
Restricted Stock and Restricted Stock Units
    1,760       -       1,822       1,666  
Denominator for Diluted Earnings Per Share -
                               
Adjusted Diluted Weighted Average Shares
    269,292       251,015       265,245       254,444  
                                 
Net Income (Loss) Per Share
                               
Basic
  $ 2.03     $ (0.28 )   $ 3.71     $ 0.43  
Diluted
  $ 2.01     $ (0.28 )   $ 3.66     $ 0.42  



 
- 9 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



The diluted earnings per share calculation excludes stock options, SARs and restricted stock and restricted stock units that were anti-dilutive.  The excluded stock options and SARs totaled 0.6 million and 7.9 million shares for the three months ended September 30, 2011 and 2010, respectively, and 0.4 million and 0.3 million shares for the nine months ended September 30, 2011 and 2010, respectively.  For the three months ended September 30, 2010, 4.1 million shares of restricted stock and restricted stock units were excluded.

4.      Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the nine-month periods ended September 30, 2011 and 2010 (in thousands):

   
Nine Months Ended
 
   
September 30,
 
   
2011
   
2010
 
             
Interest (1)
  $ 111,111     $ 71,177  
Income Taxes, Net of Refunds Received
  $ 148,937     $ 187,484  

(1)  
Net of capitalized interest of $44 million and $57 million for the nine months ended September 30, 2011 and 2010, respectively.

EOG’s accrued capital expenditures at September 30, 2011 and 2010 were $747 million and $679 million, respectively.

5.      Comprehensive Income (Loss)

The following table presents the components of EOG's comprehensive income (loss) for the three-month and nine-month periods ended September 30, 2011 and 2010 (in thousands):

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Comprehensive Income (Loss)
                       
Net Income (Loss)
  $ 540,878     $ (70,906 )   $ 970,425     $ 106,981  
Other Comprehensive Income (Loss)
                               
Foreign Currency Translation Adjustments
    (119,338 )     61,687       (63,823 )     32,599  
Foreign Currency Swap
    646       (666 )     462       4,724  
Income Tax Related to Foreign Currency Swap
    (166 )     170       (114 )     (1,273 )
Interest Rate Swap
    (2,503 )     -       (6,612 )     -  
Income Tax Related to Interest Rate Swap
    901       -       2,378       -  
Other
    28       25       86       77  
Total
  $ 420,446     $ (9,690 )   $ 902,802     $ 143,108  



 
- 10 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



6.      Segment Information

Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, 2011 and 2010 (in thousands):

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
                         
Net Operating Revenues
                       
United States
  $ 2,640,739     $ 1,359,896     $ 6,549,392     $ 3,603,758  
Canada
    103,842       103,587       360,380       357,186  
Trinidad
    134,542       110,904       421,884       328,900  
Other International (1)
    6,621       7,688       21,444       20,892  
Total
  $ 2,885,744     $ 1,582,075     $ 7,353,100     $ 4,310,736  
                                 
Operating Income (Loss)
                               
United States
  $ 923,810     $ 252,871     $ 1,938,349     $ 562,194  
Canada
    (36,596 )     (330,985 )     (356,012 )     (386,205 )
Trinidad
    96,304       76,028       279,413       222,997  
Other International (1)
    (33,488 )     (9,609 )     (51,016 )     (50,278 )
Total
    950,030       (11,695 )     1,810,734       348,708  
                                 
Reconciling Items
                               
Other Income, Net
    1,377       5,772       11,205       7,910  
Interest Expense, Net
    52,186       32,890       153,772       88,215  
Income (Loss) Before Income Taxes
  $ 899,221     $ (38,813 )   $ 1,668,167     $ 268,403  
 
(1)      Other International includes EOG's United Kingdom and China operations and, in 2011, EOG's Argentina operations.

Total assets by reportable segment are presented below at September 30, 2011 and December 31, 2010 (in thousands):

   
At
   
At
 
   
September 30,
   
December 31,
 
   
2011
   
2010
 
Total Assets
           
United States
  $ 21,234,270     $ 17,762,533  
Canada
    2,186,128       2,598,412  
Trinidad
    1,079,335       954,391  
Other International (1)
    294,945       308,897  
Total
  $ 24,794,678     $ 21,624,233  
 
(1)      Other International includes EOG's United Kingdom and China operations and, in 2011, EOG's Argentina operations.


 
- 11 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



7.      Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the nine-month periods ended September 30, 2011 and 2010 (in thousands):

   
Nine Months Ended
 
   
September 30,
 
   
2011
   
2010
 
             
Carrying Amount at Beginning of Period
  $ 498,288     $ 456,484  
Liabilities Incurred
    45,754       27,439  
Liabilities Settled (1)
    (58,084 )     (21,653 )
Accretion
    20,125       19,105  
Revisions
    61,668       53,824  
Foreign Currency Translations
    (3,688 )     1,980  
Carrying Amount at End of Period
  $ 564,063     $ 537,179  
                 
Current Portion
  $ 30,306     $ 28,767  
Noncurrent Portion
  $ 533,757     $ 508,412  

(1)
Includes settlements related to asset sales.

The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

8.      Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the nine-month period ended September 30, 2011 are presented below (in thousands):

   
Nine Months Ended
 
   
September 30, 2011
 
       
Balance at December 31, 2010
  $ 99,801  
Additions Pending the Determination of Proved Reserves
    49,617  
Reclassifications to Proved Properties
    (28,568 )
Charged to Dry Hole Costs
    (40,189 )
Foreign Currency Translations
    (72 )
Balance at September 30, 2011
  $ 80,589  



 
- 12 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



The following table provides an aging of capitalized exploratory well costs at September 30, 2011 (in thousands, except well count):

   
At
       
   
September 30,
       
   
2011
       
             
Capitalized exploratory well costs that have been capitalized for a period less than one year
  $ 36,557        
Capitalized exploratory well costs that have been capitalized for a period greater than one year
    44,032  (1)        
Total
  $ 80,589          
Number of exploratory wells that have been capitalized for a period greater than one year
    4          

(1)
Consists of costs related to an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($20 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($9 million), and a shale project in British Columbia, Canada (B.C.) ($6 million).  In the Central North Sea project, the operator and partners are currently negotiating processing and transportation terms with export infrastructure owners.  The operator has submitted a field development plan to the U.K. Department of Energy and Climate Change (DECC) and anticipates receiving approval of this plan by the end of the first quarter of 2012.  In the East Irish Sea project, EOG submitted its field development plan to the DECC during the first quarter of 2011 with regulatory approval expected by the end of 2011.  In addition, EOG is in the process of designing and constructing the infrastructure for the project in anticipation of final regulatory approval.  The evaluation of the Sichuan Basin project is expected to be completed in early 2012.  In the B.C. shale project, EOG drilled four additional wells during the first half of 2011 to further evaluate the project.  The related well completion activities are expected to commence in 2013.

9.      Commitments and Contingencies

There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes.  While the ultimate outcome and impact on EOG cannot be predicted, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow.  EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

10.      Pension and Postretirement Benefits

EOG has a non-contributory defined contribution pension plan and a matched defined contribution savings plan in place for most of its employees in the United States, Canada, Trinidad and the United Kingdom, in addition to defined benefit pension plans covering certain employees of its Canadian and Trinidadian subsidiaries.  For the nine months ended September 30, 2011 and 2010, EOG's total costs recognized for these pension plans were $21 million and $19 million, respectively.  EOG also has postretirement medical and dental plans in place for eligible employees in the United States and Trinidad, the costs of which are not material.

11.      Long-Term Debt and Common Stock

Long-Term Debt.  EOG utilizes commercial paper and short-term borrowings from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes.  EOG had no outstanding borrowings from commercial paper issuances or uncommitted credit facilities at September 30, 2011.  The average borrowings outstanding under the commercial paper program were $2 million during the nine months ended September 30, 2011.  The weighted average interest rate for commercial paper borrowings for the nine months ended September 30, 2011 was 0.32%.


 
- 13 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



At September 30, 2011, EOG had two $1.0 billion senior unsecured Revolving Credit Agreements with domestic and foreign lenders.  There were no borrowings or letters of credit outstanding under either of these agreements at September 30, 2011.  The first $1.0 billion unsecured Revolving Credit Agreement (2005 Agreement) was scheduled to mature on June 28, 2012.  Advances under the 2005 Agreement accrue interest based, at EOG's option, on either the London Interbank Offering Rate (LIBOR) plus an applicable margin (Eurodollar rate) or the base rate (as defined in the 2005 Agreement).  At September 30, 2011, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2005 Agreement, would have been 0.43% and 3.25%, respectively.

The second $1.0 billion senior unsecured Revolving Credit Agreement (2010 Agreement) was scheduled to mature on September 10, 2013.  Advances under the 2010 Agreement accrue interest based, at EOG's option, on either the Eurodollar rate or the base rate (as defined in the 2010 Agreement) plus an applicable margin.  At September 30, 2011, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2010 Agreement, would have been 1.81% and 3.83%, respectively.

On October 11, 2011, EOG entered into a $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks).  The New Facility replaces the 2005 Agreement and 2010 Agreement described above.  Unamortized fees related to the 2005 Agreement and 2010 Agreement will be written off in the fourth quarter of 2011.

The New Facility has a scheduled maturity date of October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods.  The New Facility commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions.  Advances under the New Facility will accrue interest based, at EOG's option, on either the LIBOR plus an applicable margin, or the base rate (as defined in the New Facility) plus an applicable margin.  Consistent with terms in the 2005 Agreement and the 2010 Agreement, the New Facility contains representations, warranties, covenants and events of default that are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a total debt-to-total capitalization ratio of no greater than 65%.

Fair Value of Debt.  At both September 30, 2011 and December 31, 2010, EOG had outstanding $5,260 million aggregate principal amount of debt, which had estimated fair values of approximately $5,816 million and $5,602 million, respectively.  The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, upon interest rates available to EOG at the end of each respective period.

Common Stock.  On March 7, 2011, EOG completed the sale of 13,570,000 shares of EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share.  Net proceeds from the sale of the Common Stock were approximately $1,388 million after deducting the underwriting discount and offering expenses.  Proceeds from the sale were used for general corporate purposes, including funding capital expenditures.

On February 17, 2011, the EOG Board of Directors increased the quarterly cash dividend on the Common Stock from the previous $0.155 per share to $0.16 per share effective with the dividend paid on April 29, 2011 to stockholders of record as of April 15, 2011.


 
- 14 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



12.      Fair Value Measurements

As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets.  The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at September 30, 2011 and December 31, 2010 (in millions):

   
Fair Value Measurements Using:
 
   
Quoted Prices in Active Markets (Level 1)
   
Significant Other Observable Inputs (Level 2)
             
   
Significant Unobservable Inputs (Level 3)
       
       
       
   
Total
 
At September 30, 2011
                       
Financial Assets:
                       
Crude Oil and Natural Gas Price Swaps
  $ -     $ 215     $ -     $ 215  
Natural Gas Swaptions
    -       211       -       211  
                                 
Financial Liabilities:
                               
Foreign Currency Rate Swap
  $ -     $ 46     $ -     $ 46  
Interest Rate Swap
    -       5       -       5  
                                 
At December 31, 2010
                               
Financial Assets:
                               
Natural Gas Price Swaps
  $ -     $ 62     $ -     $ 62  
Natural Gas Swaptions
    -       6       -       6  
Interest Rate Swap
    -       2       -       2  
                                 
Financial Liabilities:
                               
Crude Oil Price Swaps and Natural Gas Basis Swaps
  $ -     $ 29     $ -     $ 29  
Foreign Currency Rate Swap
    -       55       -       55  


The estimated fair value of crude oil financial price swap contracts, natural gas financial price swap and basis swap contracts, natural gas swaption contracts and interest rate swap contracts was based upon forward commodity price and interest rate curves based on quoted market prices.  The estimated fair value of the foreign currency rate swap contract was based upon forward currency rates.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on estimates of future retirement costs associated with oil and gas properties and other property, plant and equipment.  Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs, reserve lives and useful lives of other property, plant and equipment.  A reconciliation of EOG's asset retirement obligations is presented in Note 7.


 
- 15 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



Proved oil and gas properties with a carrying amount of $571 million were written down to their fair value of $180 million, resulting in a pretax impairment charge of $391 million for the nine months ended September 30, 2011.  Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.  In connection with certain impairments of proved oil and gas properties and other property, plant and equipment, EOG utilized an accepted offer from a third-party buyer.

13.      Risk Management Activities

Commodity Price Risk.  As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, EOG engages in price risk management activities from time to time.  These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas.  EOG utilizes financial commodity derivative instruments, primarily price swap, collar and basis swap contracts, as a means to manage this price risk.  In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions.  The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.  EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $358 million and $61 million for the three months ended September 30, 2011 and 2010, respectively, and $481 million and $106 million for the nine months ended September 30, 2011 and 2010, respectively.


 
- 16 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



Financial Price Swap Contracts.  Presented below is a comprehensive summary of EOG's crude oil and natural gas financial price swap contracts at September 30, 2011, with notional volumes expressed in barrels per day (Bbld) and in million British thermal units per day (MMBtud) and prices expressed in dollars per barrel ($/Bbl) and in dollars per million British thermal units ($/MMBtu), as applicable.

Financial Price Swap Contracts
 
   
Crude Oil
   
Natural Gas
 
   
Volume (Bbld)
   
Weighted Average Price ($/Bbl)
   
Volume (MMBtud)
   
Weighted Average Price ($/MMBtu)
 
2011 (1)
                       
January 2011 (closed)
    17,000     $ 90.44       275,000     $ 5.19  
February 2011 (closed)
    18,000       90.69       425,000       5.09  
March 2011 (closed)
    20,000       91.82       425,000       5.09  
April 2011 (closed)
    24,000       93.61       475,000       5.03  
May 2011 (closed)
    24,000       93.61       650,000       4.90  
June 1, 2011 through September 30, 2011 (closed)
    30,000       97.02       650,000       4.90  
October 1, 2011 through December 31, 2011 (2)
    30,000       97.02       650,000       4.90  
                                 
2012 (3)
                               
January 1, 2012 through December 31, 2012
    11,000     $ 106.37       525,000     $ 5.44  

(1)
EOG has entered into natural gas financial price swap contracts which give counterparties the option of entering into price swap contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas financial price swap contracts will increase by 500,000 MMBtud at an average price of $4.73 per million British thermal units (MMBtu) for the period from November 1, 2011 through December 31, 2011.
(2)
The crude oil contracts for October 2011 closed on October 31, 2011.  The natural gas contracts for October 2011 are closed.
(3)
EOG has entered into natural gas financial price swap contracts which give counterparties the option of entering into price swap contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas financial price swap contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for each month of 2012.


 
- 17 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)



Foreign Currency Exchange Rate Risk.  As more fully described in Note 2 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, EOG is party to a foreign currency swap with multiple banks to eliminate any exchange rate impacts that may result from the $150 million principal amount of notes issued by one of EOG's Canadian subsidiaries.  EOG accounts for the foreign currency swap using the hedge accounting method.  Changes in the fair value of the foreign currency swap do not impact Net Income (Loss).  The after-tax net impact from the foreign currency swap transaction was an increase in Other Comprehensive Income (OCI) of $0.5 million and a reduction in OCI of $0.5 million for the three months ended September 30, 2011 and 2010, respectively, and increases in OCI of $0.3 million and $3.5 million for the nine months ended September 30, 2011 and 2010, respectively.

Interest Rate Derivatives.  As more fully discussed in Note 2 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, EOG is a party to an interest rate swap to mitigate its exposure to volatility in interest rates related to EOG's $350 million principal amount of Floating Rate Senior Notes due 2014 issued on November 23, 2010.  EOG accounts for the interest rate swap transaction using the hedge accounting method.  The after-tax net impact from the interest rate swap transaction was a reduction in OCI of $1.6 million and $4.2 million for the three and nine months ended September 30, 2011, respectively.

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding financial derivative financial instruments at September 30, 2011 and December 31, 2010.  Certain amounts may be presented on a net basis in the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

     
Fair Value at
 
     
September 30,
   
December 31,
 
Description
Location on Balance Sheet
 
2011
   
2010
 
               
Asset Derivatives
             
Crude oil and natural gas price swaps and natural gas swaptions -
             
Current Portion
Assets from Price Risk Management Activities
  $ 365     $ 51  
   
Noncurrent Portion
Other Assets
  $ 61     $ 18  
                   
Liability Derivatives
                 
Crude oil price swaps, natural gas price and basis swaps and natural gas swaptions -
                 
Current Portion
Liabilities from Price Risk Management Activities
  $ -     $ 30  
   
Noncurrent Portion
Other Liabilities
  $ -     $ -  
                   
Foreign currency swap - Noncurrent Portion
Other Liabilities
  $ 46     $ 55  
                   
Interest rate swap - Noncurrent Portion
Other Assets
  $ -     $ 2  
 
Other Liabilities
  $ 5     $ -  



 
- 18 -

 

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)
(Unaudited)



Credit Risk.  Notional contract amounts are used to express the magnitude of commodity price, foreign currency and interest rate swap agreements.  The amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 12).  EOG evaluates its exposure to significant counterparties on an ongoing basis, including exposure arising from physical and financial transactions.  In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk.

All of EOG's outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDA) with counterparties.  The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings.  In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit rating to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDAs to be settled immediately.  See Note 12 for the aggregate fair value of all outstanding derivative instruments with credit-risk-related contingent features that are in a net liability position at September 30, 2011 and December 31, 2010.  EOG had no collateral posted at either September 30, 2011 or December 31, 2010.

14.  Acquisitions and Divestitures

In March 2011, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), purchased an additional 24.5% interest in the proposed Pacific Trail Pipelines (PTP) for $25.2 million.  The PTP is intended to link western Canada's natural gas producing regions to the planned liquefied natural gas (LNG) export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia (Kitimat LNG Terminal).  A portion of the purchase price ($15.3 million) was paid at closing with the remaining amount to be paid contingent on the decision to proceed with the construction of the Kitimat LNG Terminal.  Additionally in March 2011, EOGRC and an affiliate of Apache Corporation (Apache), through a series of transactions, sold a portion of their interests in the Kitimat LNG Terminal and PTP to an affiliate of Encana Corporation (Encana).  Subsequent to these transactions, ownership interests in both the Kitimat LNG Terminal and PTP are:  Apache (operator) 40%, EOGRC 30% and Encana 30%.  All future costs of the project will be paid by each party in proportion to its respective ownership percentage.

During the first nine months of 2011, EOG received proceeds of approximately $1.3 billion from sales of producing properties and acreage and certain midstream assets, primarily in the Rocky Mountain area and Texas, and the sale of a portion of EOG’s interest in the Kitimat LNG Terminal and PTP.



 
- 19 -

 

PART I.  FINANCIAL INFORMATION

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EOG RESOURCES, INC.

Overview

      EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Canada, Trinidad, the United Kingdom and China.  EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries.  This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet.  EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves.  Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

United States and Canada.  EOG's efforts to identify plays with large reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada.  EOG continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas production.  EOG has placed an emphasis on applying its horizontal drilling expertise gained from its natural gas resources plays to unconventional crude oil reservoirs.  In 2011, EOG has focused its efforts on developing its existing North American crude oil and condensate and natural gas liquids acreage.  In addition, EOG continues to evaluate certain potential liquids-rich exploration and development prospects.  For the first nine months of 2011, crude oil and condensate and natural gas liquids production accounted for approximately 35% of total company production as compared to 26% for the comparable period in 2010.  North American liquids production accounted for approximately 40% of total North American production during the first nine months of 2011 as compared to 30% for the comparable period in 2010.  This liquids growth reflects production from the Eagle Ford Shale Play near San Antonio, Texas, and increasing amounts of crude oil and condensate and natural gas liquids production in the Fort Worth Basin Barnett Shale area and in the Colorado Niobrara play.  Based on current trends, EOG expects its 2011 crude oil and condensate and natural gas liquids production to continue to increase both in total and as a percentage of total company production as compared to 2010.  EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.  EOG delivers its crude oil to various markets in the United States, including sales points on the Gulf Coast.  Most recently, with increases in crude oil production from the Eagle Ford Sale Play, EOG has increased sales to the Gulf Coast and is receiving pricing based off of the Light Louisiana Sweet price.  In order to create further market diversification for its growing crude oil production, EOG is expanding its crude-by-rail system to have the capability to increase deliveries of crude oil to St. James, Louisiana, beginning in early 2012.  In addition, to further reduce well completion costs, EOG expects to begin using sand from its Wisconsin sand mines and processing facilities in late 2011.

In March 2011, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), purchased an additional 24.5% interest in the proposed Pacific Trail Pipelines (PTP) for $25.2 million.  The PTP is intended to link western Canada's natural gas producing regions to the planned liquefied natural gas (LNG) export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia (Kitimat LNG Terminal).  A portion of the purchase price ($15.3 million) was paid at closing with the remaining amount to be paid contingent on the decision to proceed with the construction of the Kitimat LNG Terminal.  Additionally in March 2011, EOGRC and an affiliate of Apache Corporation (Apache), through a series of transactions, sold a portion of their interests in the Kitimat LNG Terminal and PTP to an affiliate of Encana Corporation (Encana).  Subsequent to these transactions, ownership interests in both the Kitimat LNG Terminal and PTP are:  Apache (operator) 40%, EOGRC 30% and Encana 30%.  All future costs of the project will be paid by each party in proportion to its respective ownership percentage.  In the first quarter of 2011, EOGRC and Apache awarded a front-end engineering and design contract to a global engineering company with the final report expected in early 2012.  In October 2011, the Canadian National Energy Board granted a 20-year export license to ship liquefied natural gas from the Kitimat LNG Terminal to international markets.


 
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International.  In Trinidad, EOG continued to deliver natural gas under existing supply contracts.  Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block and Modified U(b) Block, as well as the Pelican Field, have been developed and are producing crude oil and condensate and natural gas.  During 2011, EOG drilled and completed six development wells in the Toucan Field on Block 4(a) and expects first production from this block in 2012.  In the United Kingdom, EOG continues to make progress in field development plans for its East Irish Sea Conwy/Corfe crude oil discovery and its Central North Sea Columbus natural gas discovery.  Also during 2011, EOG signed two exploration contracts and one farm-in agreement covering approximately 100,000 net acres in the Neuquen Basin in Neuquen Province, Argentina.  During the third quarter of 2011, EOG performed exploration activity on a portion of this acreage in preparation for drilling a well targeting the Vaca Muerta oil shale in the Aguada del Chivato Block.  EOG expects to begin drilling this well in the fourth quarter of 2011.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States and Canada primarily by pursuing exploitation opportunities in countries with large shale plays where crude oil and natural gas reserves have been identified.

Capital Structure.  One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group.  EOG's debt-to-total capitalization ratio was 29% at September 30, 2011 and 34% at December 31, 2010.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On October 11, 2011, EOG entered into a $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks).  The New Facility replaces EOG's two $1.0 billion senior unsecured credit facilities existing at September 30, 2011.  Unamortized fees totaling $5.7 million related to the facilities existing at September 30, 2011 will be written off in the fourth quarter of 2011.

The New Facility has a scheduled maturity date of October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods.  The New Facility commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions.  Advances under the New Facility will accrue interest based, at EOG's option, on either the London InterBank Offering Rate plus an applicable margin, or the base rate (as defined in the New Facility) plus an applicable margin.  Consistent with terms in the credit facilities existing at September 30, 2011, the New Facility contains representations, warranties, covenants and events of default that are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a total debt-to-total capitalization ratio of no greater than 65%.

On March 7, 2011, EOG completed the sale of 13,570,000 shares of EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share.  Net proceeds from the sale of the Common Stock were approximately $1.39 billion after deducting the underwriting discount and offering expenses.  Proceeds from the sale were used for general corporate purposes, including funding capital expenditures.  During the first nine months of 2011, EOG funded $5.3 billion in exploration and development and other property, plant and equipment expenditures and paid $124 million in dividends to common stockholders, primarily by utilizing cash on hand, cash provided from its operating activities, proceeds from the Common Stock sold and proceeds from asset sales.


 
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The total anticipated 2011 capital expenditures are estimated to range from $6.8 billion to $7.0 billion, excluding acquisitions.  The majority of 2011 expenditures are focused on United States and Canada crude oil drilling activity and, to a lesser extent, natural gas drilling activity in the Haynesville, Marcellus and British Columbia Horn River Basin plays to hold acreage.  EOG expects capital expenditures to be greater than cash flow from operating activities for 2011.  Along with the sale of Common Stock discussed above, EOG's business plan includes selling certain non-core natural gas assets in 2011 to cover the anticipated shortfall.  In the first nine months of 2011, proceeds of approximately $1.3 billion were received from sales of producing properties and acreage and certain midstream assets, primarily in the Rocky Mountain area and Texas, and the sale of a portion of EOG's interest in the Kitimat LNG Terminal and PTP.  Producing properties sold represent approximately 3% of EOG's total daily production.  EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under the New Facility and equity and debt offerings.  When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities.  Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

Results of Operations

The following review of operations for the three and nine months ended September 30, 2011 and 2010 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Three Months Ended September 30, 2011 vs. Three Months Ended September 30, 2010

Net Operating Revenues.  During the third quarter of 2011, net operating revenues increased $1,304 million, or 82%, to $2,886 million from $1,582 million for the same period of 2010.  Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, natural gas liquids and natural gas, for the third quarter of 2011 increased $521 million, or 43%, to $1,737 million from $1,216 million for the same period of 2010.  During the third quarter of 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $358 million compared to net gains of $61 million for the same period of 2010.  Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas, for the third quarter of 2011 increased $344 million, or 147%, to $578 million from $234 million for the same period of 2010.  Gains on asset dispositions, net, totaled $207 million and $65 million for the third quarter of 2011 and 2010, respectively, primarily as a result of asset dispositions in the Rocky Mountain area and Texas in 2011 and in the Rocky Mountain area in 2010.



 
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Wellhead volume and price statistics for the three-month periods ended September 30, 2011 and 2010 were as follows:

   
Three Months Ended
 
   
September 30,
 
   
2011
   
2010
 
             
Crude Oil and Condensate Volumes (MBbld) (1)
           
United States
    108.9       66.6  
Canada
    6.8       5.9  
Trinidad
    3.1       4.8  
Other International (2)
    0.1       0.1  
Total
    118.9       77.4  
                 
Average Crude Oil and Condensate Prices ($/Bbl) (3)
               
United States
  $ 87.22     $ 71.54  
Canada
    90.54       69.12  
Trinidad
    89.70       65.06  
Composite
    87.49       70.96  
                 
Natural Gas Liquids Volumes (MBbld) (1)
               
United States
    43.2       31.1  
Canada
    0.8       0.8  
Total
    44.0       31.9  
                 
Average Natural Gas Liquids Prices ($/Bbl) (3)
               
United States
  $ 50.90     $ 36.56  
Canada
    57.69       40.34  
Composite
    51.02       36.66  
                 
Natural Gas Volumes (MMcfd) (1)
               
United States
    1,122       1,175  
Canada
    123       200  
Trinidad
    330       333  
Other International (2)
    12       14  
Total
    1,587       1,722  
                 
Average Natural Gas Prices ($/Mcf) (3)
               
United States
  $ 4.06     $ 4.21  
Canada
    3.81       3.42  
Trinidad
    3.59       2.53  
Other International (2)
    5.54       5.41  
Composite
    3.95       3.80  
                 
Crude Oil Equivalent Volumes (MBoed) (4)
               
United States
    339.4       293.5  
Canada
    27.9       40.0  
Trinidad
    58.0       60.3  
Other International (2)
    2.0       2.5  
Total
    427.3       396.3  
                 
Total MMBoe (4)
    39.3       36.5  

(1)
Thousand barrels per day or million cubic feet per day, as applicable.
(2)
Other International includes EOG's United Kingdom and China operations.
(3)
Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments.
(4)
Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas.  Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.  MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

 
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Wellhead crude oil and condensate revenues for the third quarter of 2011 increased $447 million, or 88%, to $953 million from $506 million for the same period of 2010, due to an increase of 42 MBbld, or 54%, in wellhead crude oil and condensate deliveries ($267 million) and a higher composite average wellhead crude oil and condensate price ($180 million).  The increase in deliveries primarily reflects increased production in Texas (43 MBbld) and Colorado (4 MBbld), partially offset by decreased production in North Dakota (5 MBbld).  Production increases in Texas were the result of increased production from the Eagle Ford and Fort Worth Basin Barnett Combo plays.  EOG's composite average wellhead crude oil and condensate price for the third quarter of 2011 increased 23% to $87.49 per barrel compared to $70.96 per barrel for the same period of 2010.

Natural gas liquids revenues for the third quarter of 2011 increased $100 million, or 92%, to $207 million from $107 million for the same period of 2010, due to an increase of 12 MBbld, or 38%, in natural gas liquids deliveries ($41 million) and a higher composite average natural gas liquids price ($59 million).  The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale, Eagle Ford Shale and Rocky Mountain area.  EOG’s composite average natural gas liquids price for the third quarter of 2011 increased 39% to $51.02 per barrel compared to $36.66 per barrel for the same period of 2010.

Wellhead natural gas revenues for the third quarter of 2011 decreased $25 million, or 4%, to $577 million from $602 million for the same period of 2010.  The decrease was primarily due to a decrease in natural gas deliveries ($47 million), partially offset by a higher composite average wellhead natural gas price ($22 million).  EOG's composite average wellhead natural gas price for the third quarter of 2011 increased 4% to $3.95 per Mcf compared to $3.80 per Mcf for the same period of 2010.

Natural gas deliveries for the third quarter of 2011 decreased 135 MMcfd, or 8%, to 1,587 MMcfd from 1,722 MMcfd for the same period of 2010.  The decrease was primarily due to lower production in Canada (77 MMcfd) and the United States (53 MMcfd).  The decreased production in Canada primarily reflects sales of certain shallow natural gas assets during the fourth quarter of 2010, partially offset by increased production from the Horn River Basin area.  The decrease in the United States was primarily attributable to decreased production resulting from a decrease in natural gas drilling activity in Louisiana (45 MMcfd), the Rocky Mountain area (38 MMcfd), New Mexico (8 MMcfd) and Mississippi (8 MMcfd), partially offset by increased production in Pennsylvania (33 MMcfd) and Texas (17 MMcfd).

During the third quarter of 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $358 million compared to net gains of $61 million for the same period of 2010.  During the third quarter of 2011, the net cash inflow related to settled crude oil and natural gas financial price swap contracts was $52 million compared to the net cash outflow related to settled natural gas financial collar, price swap and basis swap contracts of $14 million for the same period of 2010.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas.  For the three months and nine months ended September 30, 2011 and 2010, gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas.  The purchase and sale of third-party crude oil and natural gas are utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities.  Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs.

During the third quarter of 2011, gathering, processing and marketing revenues and marketing costs increased primarily as a result of increased crude oil and natural gas marketing activities.  Gathering, processing and marketing revenues less marketing costs for the third quarter of 2011 increased to $5 million from $2 million for the same period of 2010 due primarily to increased activity and higher margins from crude oil marketing activities, partially offset by lower margins in natural gas marketing activities.


 
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Operating and Other Expenses.  For the third quarter of 2011, operating expenses of $1,936 million were $342 million higher than the $1,594 million incurred in the third quarter of 2010.  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2011 and 2010:

   
Three Months Ended
       
   
September 30,
       
   
2011
   
2010
       
                   
Lease and Well
  $ 6.34     $ 4.96        
Transportation Costs
    2.77       2.83        
Depreciation, Depletion and Amortization (DD&A) -
                     
Oil and Gas Properties
    15.87       13.09  (1)        
Other Property, Plant and Equipment
    0.73       0.71          
General and Administrative (G&A)
    2.09       2.23          
Interest Expense, Net
    1.33       0.90          
Total (2)
  $ 29.13     $ 24.72          

(1)
The 2010 amount excludes the change in the estimated fair value of a contingent consideration liability relating to the acquisition of certain unproved acreage of $2 million, or $0.07 per Boe.
(2)
Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, and interest expense, net for the three months ended September 30, 2011 compared to the same period of 2010 are set forth below.

Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property.  Lease and well expenses can be divided into the following categories: costs to operate and maintain EOG's crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses.  Operating and maintenance costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power.  Workovers are operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations.  EOG continues to increase its operating activities by drilling new wells in existing and new areas.  Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.  In general, operating and maintenance costs for wells producing crude oil are higher than operating and maintenance costs for wells producing natural gas.

Lease and well expenses of $249 million for the third quarter of 2011 increased $68 million from $181 million for the same prior year period primarily due to higher operating and maintenance costs in the United States ($60 million), increased workover expenditures in Canada ($4 million) and the United States ($3 million), increased lease and well administrative expenses ($5 million) and unfavorable changes in the Canadian exchange rate ($2 million), partially offset by lower operating and maintenance costs in Canada ($7 million).

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale.  Transportation costs include the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees, fuel costs, transportation fees and costs associated with crude-by-rail operations.

Transportation costs of $109 million for the third quarter of 2011 increased $6 million from $103 million for the same prior year period primarily due to increased transportation costs in the San Antonio area ($8 million) and the Upper Gulf Coast area ($3 million), partially offset by decreased transportation costs in the Rocky Mountain area ($6 million).  The net increase in transportation costs primarily reflects increased volumes transported to downstream markets.

 
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DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method.  EOG's DD&A rate and expense are the composite of numerous individual field calculations.  There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells, reserve revisions (upward or downward) primarily related to well performance and impairments.  Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from year to year.  DD&A of the cost of other property, plant and equipment is calculated using the straight-line depreciation method over the useful lives of the assets.  Other property, plant and equipment consists of gathering and processing assets, compressors, crude-by-rail assets, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

DD&A expenses for the third quarter of 2011 increased $151 million to $652 million from $501 million for the same prior year period.  DD&A expenses associated with oil and gas properties for the third quarter of 2011 were $148 million higher than the same prior year period primarily due to higher unit rates in the United States ($95 million), Canada ($9 million) and Trinidad ($4 million); increased production in the United States ($58 million); and unfavorable changes in the Canadian exchange rate ($4 million), partially offset by decreased production in Canada ($22 million).

DD&A expenses associated with other property, plant and equipment for the third quarter of 2011 were $3 million higher than the same prior year period primarily due to gathering and processing assets placed in service in the San Antonio area.

Interest expense, net, of $52 million for the third quarter of 2011 increased $19 million compared to the same prior year period primarily due to a higher average debt balance ($13 million) and lower capitalized interest ($6 million).

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties and other property, plant and equipment.  Unproved properties with individually significant acquisition costs are amortized over the lease term and analyzed on a property-by-property basis for any impairment in value.  Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term.  When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset.  If the future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated using the Income Approach as described in Accounting Standards Codification Topic 820, Fair Value Measurement and Disclosures.  For certain natural gas assets held for sale, EOG utilizes accepted bids as the basis for determining fair value.

Impairments of $83 million for the third quarter of 2011 were $269 million lower than impairments for the same prior year period primarily due to decreased impairments of proved properties in Canada ($267 million) and lower amortization of unproved property costs in Canada ($10 million), partially offset by increased amortization of unproved property costs in the United States ($10 million).  EOG recorded impairments of proved properties and other property, plant and equipment of $32 million and $302 million for the third quarter of 2011 and 2010, respectively.  Included in the third quarter 2010 amount were impairments of $280 million related to certain Canadian shallow natural gas assets.

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes.  Severance/production taxes are generally determined based on wellhead revenues and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income for the third quarter of 2011 increased $25 million to $99 million (5.7% of wellhead revenues) compared to $74 million (6.1% of wellhead revenues) for the same prior year period.  The increase in taxes other than income was primarily due to increased severance/production taxes as a result of increased wellhead revenues in the United States ($26 million) and lower credits available to EOG in 2011 for Texas high-cost gas severance tax rate reductions ($8 million), partially offset by lower ad valorem/property taxes in the United States ($5 million) and Canada ($2 million) and decreased severance/production taxes in Canada as a result of asset dispositions during 2010 ($3 million).

 
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Income tax provision of $358 million for third quarter of 2011 increased $326 million compared to $32 million for the same prior year period due primarily to taxes associated with increased pretax earnings.  The third quarter 2011 effective tax rate of 40% exceeded the United States statutory tax rate (35%) due primarily to foreign earnings in Trinidad (55% statutory tax rate) and foreign losses in China (25% statutory tax rate).

Nine Months Ended September 30, 2011 vs. Nine Months Ended September 30, 2010

Net Operating Revenues.  During the first nine months of 2011, net operating revenues increased $3,042 million, or 71%, to $7,353 million from $4,311 million for the same period of 2010.  Total wellhead revenues for the first nine months of 2011 increased $1,433 million, or 41%, to $4,949 million from $3,516 million for the same period of 2010.  During the first nine months of 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $481 million compared to net gains of $106 million for the same period of 2010.  Gathering, processing and marketing revenues for the first nine months of 2011 increased $859 million, or 143%, to $1,461 million from $602 million for the same period of 2010.  Gains on asset dispositions, net, totaled $443 million and $72 million for the first nine months of 2011 and 2010, respectively, primarily as a result of asset dispositions in the Rocky Mountain area and Texas in 2011 and in the Rocky Mountain area in 2010.


 
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Wellhead volume and price statistics for the nine-month periods ended September 30, 2011 and 2010 were as follows:

   
Nine Months Ended
 
   
September 30,
 
   
2011
   
2010
 
             
Crude Oil and Condensate Volumes (MBbld)
           
United States
    94.3       59.5  
Canada
    8.0       6.1  
Trinidad
    3.6       4.7  
Other International
    0.1       0.1  
Total
    106.0       70.4  
                 
Average Crude Oil and Condensate Prices ($/Bbl) (1)
               
United States
  $ 91.40     $ 72.58  
Canada
    92.76       71.32  
Trinidad
    91.56       66.91  
Composite
    91.52       72.09  
                 
Natural Gas Liquids Volumes (MBbld)
               
United States
    38.7       27.4  
Canada
    0.8       0.9  
Total
    39.5       28.3  
                 
Average Natural Gas Liquids Prices ($/Bbl)
               
United States
  $ 49.85     $ 40.68  
Canada
    54.36       42.90  
Composite
    49.93       40.75  
                 
Natural Gas Volumes (MMcfd)
               
United States
    1,123       1,096  
Canada
    135       205  
Trinidad
    354       342  
Other International
    13       15  
Total
    1,625       1,658  
                 
Average Natural Gas Prices ($/Mcf) (1)
               
United States
  $ 4.13     $ 4.50  
Canada
    3.88       4.09  
Trinidad
    3.42       2.54  
Other International
    5.60       4.64  
Composite
    3.97       4.05  
                 
Crude Oil Equivalent Volumes (MBoed)
               
United States
    320.3       269.6  
Canada
    31.2       41.1  
Trinidad
    62.7       61.7  
Other International
    2.2       2.6  
Total
    416.4       375.0  
                 
Total MMBoe
    113.7