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

(Mark One)

For the quarterly period ended March 31, 2013

or

Commission File Number: 1-9743

 

EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)

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.

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EOG RESOURCES, INC.

TABLE OF CONTENTS

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PART I.  FINANCIAL INFORMATION

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

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

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

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

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

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

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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, 2012, filed on February 22, 2013 (EOG's 2012 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 months ended March 31, 2013, are not necessarily indicative of the results to be expected for the full year.

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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 2012 Annual Report, EOG maintains various stock-based compensation plans.  Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon job functions of the employees receiving the grants as follows (in millions):

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, performance units, performance stock and other stock-based awards.  At March 31, 2013, approximately 3.2 million common shares remained available for grant under the 2008 Plan.  EOG's policy is to issue shares related to the 2008 Plan from either previously authorized unissued shares or treasury shares to the extent treasury shares are available.

At the 2013 Annual Meeting of Stockholders, EOG's stockholders approved the Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Plan).  As more fully discussed in the Plan document, the Plan, among other things, authorizes an additional 15,500,000 shares of EOG common stock for grant under the Plan and extends the expiration date of the Plan to May 2023.

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan.  The fair value of stock option and SAR grants is estimated using the Hull-White II binomial option pricing model.  The fair value of Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model.  Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $10.4 million and $10.9 million during the three months ended March 31, 2013 and 2012, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the three-month periods ended March 31, 2013 and 2012 are as follows:

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.

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

The following table sets forth stock option and SAR transactions for the three-month periods ended March 31, 2013 and 2012 (stock options and SARs in thousands):

(1)

The total intrinsic value of stock options/SARs exercised for the three months ended March 31, 2013 and 2012 was $36.2 million and $32.4 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 March 31, 2013 and 2012 was $225.1 million and $313.3 million, respectively.  At March 31, 2013 and 2012, the weighted average remaining contractual life was 4.2 years and 3.5 years, respectively.

(3)

The total intrinsic value of stock options/SARs vested or expected to vest at March 31, 2013 and 2012 was $218.0 million and $307.5 million, respectively.  At March 31, 2013 and 2012, the weighted average remaining contractual life was 4.1 years and 3.5 years, respectively.

(4)

The total intrinsic value of stock options/SARs exercisable at March 31, 2013 and 2012 was $130.7 million and $239.1 million, respectively.  At March 31, 2013 and 2012, the weighted average remaining contractual life was 2.7 years and 2.2 years, respectively.

At March 31, 2013, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $83 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.5 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 $19.7 million and $17.4 million for the three months ended March 31, 2013 and 2012, respectively.

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

The following table sets forth the restricted stock and restricted stock unit transactions for the three-month periods ended March 31, 2013 and 2012 (shares and units in thousands):

(1)

The total intrinsic value of restricted stock and restricted stock units released for the three months ended March 31, 2013 and 2012 was $19.0 million and $53.1 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 March 31, 2013 and 2012 was $497.4 million and $445.4 million, respectively.

At March 31, 2013, unrecognized compensation expense related to restricted stock and restricted stock units totaled $146 million.  Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.6 years.

Performance Units and Performance Stock.  As more fully discussed in Note 6 to the Consolidated Financial Statements included in EOG's 2012 Annual Report, in September 2012, EOG granted an aggregate of 54,526 performance units and 16,752 shares of performance stock to its executive officers (in each case under the terms of the 2008 Plan), which units and shares remained outstanding at March 31, 2013.  The fair value of the performance units and performance stock is estimated using a Monte Carlo simulation. Stock-based compensation expense related to performance unit and performance stock grants totaled $0.3 million for the three months ended March 31, 2013.

At March 31, 2013, unrecognized compensation expense related to performance units and performance stock totaled $3 million.  Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.8 years.

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

3.	Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the three-month periods ended March 31, 2013 and 2012 (in thousands, except per share data):

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive.  Shares underlying the excluded stock options and SARs totaled 0.1 million shares for each of the three months ended March 31, 2013 and 2012.

Net cash paid for interest and income taxes was as follows for the three-month periods ended March 31, 2013 and 2012 (in thousands):

(1)

Net of capitalized interest of $10 million and $12 million for the three months ended March 31, 2013 and 2012, respectively.

EOG's accrued capital expenditures at March 31, 2013 and 2012 were $809 million and $880 million, respectively.

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

5.	Segment Information

Selected financial information by reportable segment is presented below for the three-month periods ended March 31, 2013 and 2012 (in thousands):

Total assets by reportable segment are presented below at March 31, 2013 and December 31, 2012 (in thousands):

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

6.	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 three-month periods ended March 31, 2013 and 2012 (in thousands):

 

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.

7.	Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the three-month period ended March 31, 2013 are presented below (in thousands):

(1)

Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

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

The following table provides an aging of capitalized exploratory well costs at March 31, 2013 (in thousands, except well count):

(1)

Consists of costs related to an outside operated, offshore Central North Sea natural gas project in the United Kingdom ($19 million) and costs associated with evaluation of a project in Central Alberta, Canada ($8 million).  In the Central North Sea Columbus project, the operator and partners are currently re-evaluating export route options as a result of an announced change in plans by the export infrastructure owners.  In the Central Alberta project, EOG is currently evaluating alternatives for the well and surrounding acreage.

8.	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.

9.	Pension and Postretirement Benefits

EOG has defined contribution pension plans in place for most of its employees in the United States, Canada, Trinidad and the United Kingdom, and defined benefit pension plans covering certain of its employees in Canada and Trinidad.  For the three months ended March 31, 2013 and 2012, EOG's total costs recognized for these pension plans were $10.4 million and $10.9 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.

Long-Term Debt.  During the three months ended March 31, 2013 and 2012, EOG utilized commercial paper, bearing market interest rates, for various corporate financing purposes.  EOG had no outstanding borrowings from commercial paper issuances at March 31, 2013.  The average of the borrowings outstanding under the commercial paper program was $2 million during the three months ended March 31, 2013.  The weighted average interest rate for commercial paper borrowings for the three months ended March 31, 2013 was 0.36%.  At March 31, 2013, $350 million principal amount of Floating Rate Senior Notes due 2014 (Floating Rate Notes) and $150 million principal amount of 4.75% Subsidiary Debt due 2014 (4.75% Subsidiary Debt), were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amounts with other long-term debt.

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

EOG currently has a $2.0 billion unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders.  The Agreement matures on October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the banks holding greater than 50% of the commitments then outstanding under the Agreement.  At March 31, 2013, there were no borrowings or letters of credit outstanding under the Agreement.  Advances under the Agreement accrue interest based, at EOG's option, on either the London InterBank Offered Rate (LIBOR) plus an applicable margin (Eurodollar rate), or the base rate (as defined in the Agreement) plus an applicable margin.  At March 31, 2013, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.08% and 3.25%, respectively.

Common Stock.  On February 13, 2013, EOG's Board of Directors increased the quarterly cash dividend on the Common Stock from the previous $0.17 per share to $0.1875 per share, effective with the dividend paid on April 30, 2013 to stockholders of record as of April 16, 2013.

11.	Fair Value Measurements

As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2012 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 March 31, 2013 and December 31, 2012 (in millions):

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

The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) and the interest rate swap contract 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 was based upon forward currency rates.  Swaps were valued using market prices and discount rates from an independent third-party provider of financial market data.  The Black 76 Model is utilized in valuing options.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment.  Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives.  A reconciliation of EOG's asset retirement obligations is presented in Note 6.

Proved oil and gas properties and other assets with a carrying amount of $68 million were written down to their fair value of $41 million, resulting in pretax impairment charges of $27 million for the three months ended March 31, 2013.  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.

Fair Value of Debt.  At both March 31, 2013 and December 31, 2012, EOG had outstanding $6,290 million aggregate principal amount of debt, which had estimated fair values of approximately $6,980 million and $7,032 million, respectively.  The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at the end of each respective period.

12.	Risk Management Activities

Commodity Price Risk.  As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2012 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, option, swaption, collar and basis swap contracts, as a means to manage this price risk.  In addition to financial transactions, from time to time 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.  These physical commodity contracts qualify for the normal purchases and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting.  The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

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

Commodity Derivative Contracts.  Presented below is a comprehensive summary of EOG's crude oil derivative contracts at March 31, 2013, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month or six-month periods.  Options covering a notional volume of 8,000 Bbld are exercisable on April 30, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 8,000 Bbld at an average price of $97.66 per barrel for each month during the period May 1, 2013 through July 31, 2013.  Options covering a notional volume of 62,000 Bbld are exercisable on June 28, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 62,000 Bbld at an average price of $100.24 per barrel for each month during the period July 1, 2013 through December 31, 2013.  Options covering a notional volume of 54,000 Bbld are exercisable on December 31, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 54,000 Bbld at an average price of $98.91 per barrel for each month during the period January 1, 2014 through June 30, 2014.

(2)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Options covering a notional volume of 10,000 Bbld are exercisable on June 27, 2014 and options covering a notional volume of 30,000 Bbld are exercisable on June 30, 2014.   If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 40,000 Bbld at an average price of $95.77 per barrel for each month during the period July 1, 2014 through December 31, 2014.

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

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at March 31, 2013, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

(1)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month during the period May 1, 2013 through December 31, 2013.

(2)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  Additionally, in connection with certain natural gas derivative contracts settled in July 2012, counterparties retain an option of entering into derivative contracts at future dates.  All 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 derivative contracts will increase by 250,000 MMBtud at an average price of $4.66 per MMBtu for each month during the period January 1, 2014 through December 31, 2014.

Foreign Currency Exchange Rate Derivative.  EOG is party to a foreign currency aggregate swap with multiple banks to eliminate any exchange rate impacts that may result from the 4.75% Subsidiary Debt issued by one of EOG's Canadian subsidiaries.  The foreign currency swap agreement expires on March 15, 2014.  EOG accounts for the foreign currency swap transaction using the hedge accounting method.  Changes in the fair value of the foreign currency swap do not impact Net Income.  The after-tax net impact from the foreign currency swap resulted in an increase in Other Comprehensive Income (OCI) of $1.7 million and $1.5 million for the three months ended March 31, 2013 and 2012, respectively.

Interest Rate Derivative.  EOG is a party to an interest rate swap with a counterparty bank.  The interest rate swap was entered into in order to mitigate EOG's exposure to volatility in interest rates related to the Floating Rate Notes.  The interest rate swap has a notional amount of $350 million and expires on February 3, 2014.  EOG accounts for the interest rate swap using the hedge accounting method.  Changes in the fair value of the interest rate swap do not impact Net Income.  The after-tax impact from the interest rate swap resulted in an increase in OCI of $0.5 million and a reduction in OCI of $0.4 million for the three months ended March 31, 2013 and 2012, respectively.

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

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding derivative financial instruments at March 31, 2013 and December 31, 2012.  Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

(1)	The current portion of Assets from Price Risk Management Activities consists of gross assets of $72 million partially offset by gross liabilities of $39 million at March 31, 2013 and gross assets of $257 million partially offset by gross liabilities of $91 million at December 31, 2012.

(2)	The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $28 million partially offset by gross assets of $14 million at March 31, 2013 and gross liabilities of $17 million partially offset by gross assets of $9 million at December 31, 2012.

(3)	The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $56 million partially offset by gross assets of $11 million at March 31, 2013 and gross liabilities of $13 million at December 31, 2012.

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 11).  EOG evaluates its exposure to significant counterparties on an ongoing basis, including those 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 (ISDAs) 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 ISDA 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 11 for the aggregate fair value of all derivative instruments that are in a net liability position at March 31, 2013 and December 31, 2012.  EOG had no collateral posted at March 31, 2013 and held collateral of $6 million at December 31, 2012.

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

13.  Divestitures

During the first quarter of 2013, EOG received proceeds of approximately $480 million primarily from the sale of its entire interest in the planned Kitimat liquefied natural gas export terminal, the proposed Pacific Trail Pipelines and approximately 28,500 undeveloped net acres in the Horn River Basin in Canada and from sales of producing properties and acreage in the Upper Gulf Coast region and the Permian Basin.  During the first quarter of 2012, EOG received proceeds of approximately $450 million from sales of producing properties and acreage, primarily in the Upper Gulf Coast region, the Rocky Mountain area and the Permian Basin.

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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, China and Argentina.  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 liquids-rich natural gas production.  EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and liquids-rich reservoirs.  In 2013, EOG continues to focus its efforts on developing its existing North American crude oil and liquids-rich acreage.  In addition, EOG continues to evaluate certain potential crude oil and, to a lesser extent, liquids-rich natural gas exploration and development prospects.  For the first quarter of 2013, crude oil and condensate and natural gas liquids (NGLs) production accounted for approximately 52% of total company production as compared to 43% for the comparable period in 2012.  In North America, crude oil and condensate and NGLs production accounted for approximately 59% of total North American production during the first quarter of 2013 as compared to 49% for the comparable period in 2012.  This liquids growth primarily reflects increased production from both the South Texas Eagle Ford and the Permian Basin.  Based on current results, EOG expects its 2013 crude oil and condensate and NGLs production to continue to increase both in total and as a percentage of total company production as compared to 2012.  In 2013, EOG's major producing areas in the United States and Canada are in New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

EOG continues to deliver its crude oil to various markets in the United States, including sales points on the Gulf Coast where sales are based on the premium Light Louisiana Sweet crude oil index.  EOG's crude-by-rail facilities provide EOG the ability to direct its crude oil shipments via rail car to the most favorable markets, including the Gulf Coast, Cushing, Oklahoma, and other markets.

In December 2012, EOG's wholly-owned Canadian subsidiary signed a purchase and sale agreement for the sale of its entire interest in the planned Kitimat liquefied natural gas export terminal, the proposed Pacific Trail Pipelines and approximately 28,500 undeveloped net acres in the Horn River Basin.  The transaction closed in February 2013 and is subject to customary post-closing adjustments.

International.  In Trinidad, EOG continued to deliver natural gas under existing supply contracts.  Several fields in the South East Coast Consortium Block, Modified U(a) Block, Block 4(a) and Modified U(b) Block, as well as in the Pelican Field and the EMZ Area, have been developed and are producing natural gas sold to the National Gas Company of Trinidad and Tobago and condensate sold to the Petroleum Company of Trinidad and Tobago.  During the first quarter of 2013, EOG continued its four-well program in the Modified U(a) Block, drilling two development wells and one successful exploratory well.  EOG expects to finish drilling the fourth well in the second quarter of 2013 and complete all four wells in the second half of 2013.

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In the United Kingdom, EOG continues to make progress in field development for its East Irish Sea Conwy/Corfe crude oil discovery.  Offshore construction modifications to the nearby Douglas platform, which will be used to process Conwy/Corfe production, began in the first quarter of 2013.  First production from the Conwy/Corfe field is anticipated in early 2014.  In the Central North Sea Columbus project, the operator and partners are currently re-evaluating export route options as a result of an announced change in plans by the export infrastructure owners.  In the Central North Sea Block 21/12b awarded to EOG in 2009, EOG plans to drill an exploratory well in the fourth quarter of 2013.  EOG will operate this well.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Basin in Neuquén Province.  During 2012, EOG participated in the drilling and completion of a vertical well in the Bajo del Toro Block, which is producing.  Also in 2012, a monitor well was drilled and one horizontal well was drilled and completed in the Aguada del Chivato Block.  EOG completed the monitor well at the end of March 2013 and is currently evaluating these wells.

During the first quarter of 2013, EOG successfully recompleted a well in the Sichuan Basin, Sichuan Province, The People's Republic of China. Two additional wells are planned in the fourth quarter of 2013.

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 where indigenous 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 31% at March 31, 2013 and 32% at December 31, 2012.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.  At March 31, 2013, $350 million principal amount of Floating Rate Senior Notes due 2014 and $150 million principal amount of 4.75% Subsidiary Debt due 2014 were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amounts with other long-term debt.

EOG's total anticipated 2013 capital expenditures are estimated to range from $7.0 billion to $7.2 billion, excluding acquisitions.  The majority of 2013 expenditures will be focused on United States crude oil and, to a lesser extent, liquids-rich natural gas drilling activity.  EOG expects capital expenditures to be greater than cash flow from operating activities for 2013.  EOG's business plan includes selling certain non-core assets in 2013 realizing proceeds of $550 million to cover the anticipated shortfall.  In the first quarter of 2013, proceeds of approximately $480 million were received from sales of assets.  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 its $2.0 billion senior unsecured revolving credit 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.

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Results of Operations

The following review of operations for the three months ended March 31, 2013 and 2012 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Net Operating Revenues.  During the first quarter of 2013, net operating revenues increased $550 million, or 20%, to $3,357 million from $2,807 million for the same period of 2012.  Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, for the first quarter of 2013 increased $486 million, or 26%, to $2,362 million from $1,876 million for the same period of 2012.  During the first quarter of 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $105 million compared to net gains of $134 million for the same period of 2012.  Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, NGLs and natural gas as well as fees associated with gathering third-party natural gas, for the first quarter of 2013 increased $205 million, or 29%, to $923 million from $718 million for the same period of 2012.  Gains on asset dispositions, net, of $164 million for the first quarter of 2013 primarily consist of gains on asset dispositions in Canada and Texas.

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Wellhead volume and price statistics for the three-month periods ended March 31, 2013 and 2012 were as follows:

(1)	Thousand barrels per day or million cubic feet per day, as applicable.

(2)	Other International includes EOG's United Kingdom, China and Argentina operations.

(3)	Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments.  See Note 12 to the Consolidated Financial Statements.

(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 first quarter of 2013 increased $472 million, or 36%, to $1,782 million from $1,310 million for the same period of 2012, due to an increase of 47 MBbld, or 33%, in wellhead crude oil and condensate deliveries ($396 million) and a higher composite average wellhead crude oil and condensate price ($76 million).  The increase in deliveries primarily reflects increased production in the South Texas Eagle Ford and the Permian Basin.  EOG's composite average wellhead crude oil and condensate price for the first quarter of 2013 increased 4% to $105.61 per barrel compared to $101.12 per barrel for the same period of 2012.

NGLs revenues for the first quarter of 2013 decreased $28 million, or 15%, to $170 million from $198 million for the same period of 2012, due to a lower composite average price ($57 million), partially offset by an increase of 8 MBbld, or 16%, in NGLs deliveries ($29 million).  The increase in deliveries primarily reflects increased volumes in the South Texas Eagle Ford.  EOG's composite average NGLs price for the first quarter of 2013 decreased 25% to $31.78 per barrel compared to $42.62 per barrel for the same period of 2012.

Wellhead natural gas revenues for the first quarter of 2013 increased $44 million, or 12%, to $411 million from $367 million for the same period of 2012.  The increase was due to a higher composite average wellhead natural gas price ($88 million), partially offset by a decrease in natural gas deliveries ($44 million).  Natural gas deliveries for the first quarter of 2013 decreased 174 MMcfd, or 11%, to 1,373 MMcfd from 1,547 MMcfd for the same period of 2012.  The decrease was primarily due to lower production in the United States (128 MMcfd), Canada (26 MMcfd) and Trinidad (17 MMcfd).  The decrease in the United States was primarily attributable to asset sales and reduced natural gas drilling activity.  The decrease in Canada was primarily due to decreased production in Alberta and the Horn River Basin area.  The decrease in Trinidad was primarily attributable to a decrease in contractual deliveries.  EOG's composite average wellhead natural gas price for the first quarter of 2013 increased 27% to $3.32 per Mcf compared to $2.61 per Mcf for the same period of 2012.

During the first quarter of 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $105 million compared to net gains of $134 million for the same period of 2012.  During the first quarter of 2013, the net cash inflow related to settled crude oil and natural gas derivative contracts was $67 million compared to $134 million for the same period of 2012.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with gathering third-party natural gas.  For the three months ended March 31, 2013 and 2012, gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas.  Purchases and sales 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 first quarter of 2013, gathering, processing and marketing revenues and marketing costs increased primarily as a result of increased crude oil marketing activities.  Gathering, processing and marketing revenues less marketing costs for the first quarter of 2013 totaled $18 million compared to $13 million for the same period of 2012.

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Operating and Other Expenses.  For the first quarter of 2013, operating expenses of $2,523 million were $276 million higher than the $2,247 million incurred during the first quarter of 2012.  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended March 31, 2013 and 2012:

(1)

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 March 31, 2013 compared to the same period of 2012 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 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 first quarter of 2013 decreased $12 million from $261 million for the same prior year period primarily due to lower operating and maintenance costs in the United States.

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale.  Transportation costs include transportation fees, costs associated with crude-by-rail operations, 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 and fuel costs.

Transportation costs of $184 million for the first quarter of 2013 increased $52 million from $132 million for the same prior year period primarily due to increased transportation costs related to production from the Rocky Mountain area ($25 million), the South Texas Eagle Ford ($19 million) and the Fort Worth Basin Barnett Shale area ($8 million).

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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, economic factors 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 generally calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses for the first quarter of 2013 increased $97 million to $846 million from $749 million for the same prior year period.  DD&A expenses associated with oil and gas properties for the first quarter of 2013 were $107 million higher than the same prior year period.  The increase primarily reflects higher unit rates in the United States ($67 million) and Trinidad ($14 million) and increased production in the United States ($48 million), partially offset by a decrease in unit rates in Canada ($10 million) and a decrease in production in Canada ($10 million) and Trinidad ($2 million).  Unit rates increased due primarily to downward revisions of natural gas reserves at December 31, 2012, and an increase in production from higher-cost properties.

Interest expense, net, of $62 million for the first three months of 2013 increased $12 million from $50 million for the same prior year period primarily due to a higher average debt balance ($10 million) and lower capitalized interest ($2 million).

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties and other assets.  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 by using the Income Approach as described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification.  For certain assets held for sale, EOG utilized accepted bids as the basis for determining fair value.

Impairments of $54 million for the first quarter of 2013 were $80 million lower than impairments for the same prior year period primarily due to lower impairments of proved properties and other assets ($79 million) and decreased amortization of unproved property costs ($12 million) in the United States, partially offset by higher impairments of proved properties ($13 million) in Canada.  EOG recorded impairments of proved properties and other assets of $27 million and $94 million for the first quarter of 2013 and 2012, respectively.

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 first quarter of 2013 increased $13 million to $135 million (5.7% of wellhead revenues) compared to $122 million (6.5% 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 ($17 million), partially offset by decreased severance/production taxes in Trinidad ($3 million).

Other income (expense), net for the first quarter of 2013 declined $21 million compared to the same prior year period.  The decrease was primarily due to an increase in foreign currency transaction losses.

Income tax provision of $266 million for the first quarter of 2013 increased $70 million from $196 million in 2012 due primarily to greater pretax income.  The net effective tax rate for the first quarter of 2013 decreased to 35% from 38% in the prior year period.

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Capital Resources and Liquidity

Cash Flow.  The primary sources of cash for EOG during the three months ended March 31, 2013 were funds generated from operations and proceeds from asset sales.  The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; and dividend payments to stockholders.  During the first three months of 2013, EOG's cash balance increased $232 million to $1,108 million from $876 million at December 31, 2012.

Net cash provided by operating activities of $1,425 million for the first three months of 2013 increased $347 million compared to the same period of 2012 primarily reflecting an increase in wellhead revenues ($486 million) and a decrease in cash paid for income taxes ($30 million), partially offset by an unfavorable change in the net cash flow from the settlement of financial commodity derivative contracts ($67 million), an increase in cash operating expenses ($53 million), unfavorable changes in working capital and other assets and liabilities ($34 million) and an increase in net cash paid for interest expense ($21 million).

Net cash used in investing activities of $1,160 million for the first three months of 2013 decreased by $216 million compared to the same period of 2012 due primarily to a decrease in additions to oil and gas properties ($275 million), a decrease in additions to other property, plant and equipment ($79 million) and an increase in proceeds from sales of assets ($29 million), partially offset by unfavorable changes in working capital associated with investing activities ($167 million).

Net cash used in financing activities of $39 million for the first three months of 2013 included cash dividend payments ($46 million) and the purchase of treasury stock in connection with stock compensation plans ($11 million).  Cash provided by financing activities for the first three months of 2013 included excess tax benefits from stock-based compensation ($12 million) and proceeds from stock options exercised ($8 million).  Net cash used in financing activities for the first three months of 2012 included cash dividend payments ($43 million) and the purchase of treasury stock in connection with stock compensation plans ($20 million).  Cash provided by financing activities for the first three months of 2012 included proceeds from stock options exercised ($20 million) and excess tax benefits from stock-based compensation ($17 million).

Total Expenditures.  For the year 2013, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $7.0 billion to $7.2 billion, excluding acquisitions.  The table below sets out components of total expenditures for the three-month periods ended March 31, 2013 and 2012 (in millions):

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Exploration and development expenditures of $1,649 million for the first three months of 2013 were $273 million lower than the same period of 2012 due primarily to decreased drilling and facilities expenditures in the United States ($215 million) and Argentina ($8 million); and decreased leasehold acquisition expenditures in the United States ($62 million) and Canada ($15 million); partially offset by increased drilling and facilities expenditures in Trinidad ($23 million).  The exploration and development expenditures for the first three months of 2013 of $1,649 million consist of $1,469 million in development, $170 million in exploration and $10 million in capitalized interest.  The exploration and development expenditures for the first three months of 2012 of $1,922 million consist of $1,648 million in development, $262 million in exploration and $12 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors.  EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant.  While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

Commodity Derivative Transactions.  As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2012, filed on February 21, 2013, 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, option, swaption, collar and basis swap contracts, as a means to manage this price risk.  EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method.  Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as (Losses) Gains on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income.  The related cash flow impact is reflected as Cash Flows from Operating Activities.  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.

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Commodity Derivative Contracts.  The total fair value of EOG's crude oil and natural gas derivative contracts was reflected on the Consolidated Balance Sheets at March 31, 2013 as an asset of $33 million and a liability of $59 million, respectively.  Presented below is a comprehensive summary of EOG's crude oil derivative contracts at May 3, 2013, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month periods.  Options covering a notional volume of 62,000 Bbld are exercisable on June 28, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 62,000 Bbld at an average price of $100.24 per barrel for each month during the period July 1, 2013 through December 31, 2013.  Options covering a notional volume of 54,000 Bbld are exercisable on December 31, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 54,000 Bbld at an average price of $98.91 per barrel for each month during the period January 1, 2014 through June 30, 2014.

(2)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Options covering a total notional volume of 11,000 Bbld are exercisable on June 27, 2014 and options covering a total notional volume of 31,000 Bbld are exercisable on June 30, 2014.   If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 42,000 Bbld at an average price of $95.86 per barrel for each month during the period July 1, 2014 through December 31, 2014.

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Presented below is a comprehensive summary of EOG's natural gas derivative contracts at May 3, 2013, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

(1)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  For the period June 1, 2013 through October 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 200,000 MMBtud at an average price of $4.72 per MMBtu for each month during that period.  For the period November 1, 2013 through December 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month during that period.

(2)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  Additionally, in connection with certain natural gas derivative contracts settled in July 2012, counterparties retain an option of entering into derivative contracts at future dates.  All 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 derivative contracts will increase by 320,000 MMBtud at an average price of $4.66 per MMBtu for each month during the period January 1, 2014 through December 31, 2014.

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Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements.  EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements.  In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate income or cash flows or pay dividends are forward-looking statements.  Forward-looking statements are not guarantees of performance.  Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct.  Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control.  Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

·	the timing and extent of changes in prices for, and demand for, crude oil and condensate, NGLs, natural gas and related commodities;

·	the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

·	the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing;

·

the extent to which EOG is successful in its efforts to economically develop its acreage in, and to produce reserves and achieve anticipated production levels from, its existing and future crude oil and natural gas exploration and development projects, given the risks and uncertainties and capital expenditure requirements inherent in drilling, completing and operating crude oil and natural gas wells and the potential for interruptions of development and production, whether involuntary or intentional as a result of market or other conditions;

·	the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;

·	the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

·	the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;

·

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

·	EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

·	the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;

·	competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

·	the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

·	weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation of production, gathering, processing, compression and transportation facilities;

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·	the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

·	EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;

·	the extent and effect of any hedging activities engaged in by EOG;

·	the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;

·	political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;

·	the use of competing energy sources and the development of alternative energy sources;

·	the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;

·	acts of war and terrorism and responses to these acts;

·	physical, electronic and cyber security breaches; and

·	the other factors described under Item 1A, "Risk Factors," on pages 16 through 23 of EOG's Annual Report on Form 10-K for the year ended December 31, 2012.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

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PART I.  FINANCIAL INFORMATION

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
EOG RESOURCES, INC.

EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in (i) the "Derivative Transactions," "Financing," "Foreign Currency Exchange Rate Risk" and "Outlook" sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity" on pages 42 through 47 of EOG's Annual Report on Form 10-K for the year ended December 31, 2012, filed on February 22, 2013 (EOG's 2012 Annual Report); and (ii) Note 11, "Risk Management Activities," to EOG's Consolidated Financial Statements on pages F-25 through F-28 of EOG's 2012 Annual Report. There have been no material changes in this information. For additional information regarding EOG's financial commodity derivative contracts and physical commodity contracts, see (i) Note 12, "Risk Management Activities," to EOG's Consolidated Financial Statements in this Quarterly Report on Form 10-Q; (ii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Net Operating Revenues" in this Quarterly Report on Form 10-Q; and (iii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions" in this Quarterly Report on Form 10-Q.