UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(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, 2013

or

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

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 and nine months ended September 30, 2013 are not necessarily indicative of the results to be expected for the full year.

Recently Issued Accounting Standards.  In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2013-02 "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income" (ASU 2013-02).  ASU 2013-02 amends ASU 2011-05 and requires that entities disclose additional information about amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component.  Significant amounts reclassified out of AOCI are required to be presented either on the face of the Consolidated Statements of Income and Comprehensive Income or in the notes to the financial statements.  The requirements of ASU 2013-02 are effective for fiscal years and interim periods in those years beginning after December 15, 2012.  EOG adopted the provisions of ASU 2013-02 effective January 1, 2013.  The adoption did not have a material impact on EOG's financial statements.  No significant amounts were reclassified out of AOCI during the three and nine months ended September 30, 2013 and 2012, respectively.

In July 2013, the FASB issued ASU 2013-11 "Presentation of an Unrecognized Tax Benefit when a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists" (ASU 2013-11).  ASU 2013-11 includes specific guidance on financial statement presentation of an unrecognized tax benefit  when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists.  The requirements of ASU 2013-11 are effective for fiscal years and interim periods in those years beginning after December 15, 2013.  Early adoption is permitted.  EOG does not expect a material impact on its financial statements from the adoption of ASU 2013-11.

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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 the job function of the employees receiving the grants as follows (in millions):

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

The 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 September 30, 2013, approximately 16.6 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.

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 $19.2 million and $16.5 million during the three months ended September 30, 2013 and 2012, respectively, and $40.0 million and $37.8 million during the nine months ended September 30, 2013 and 2012, 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, 2013 and 2012 are as follows:

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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.

The following table sets forth stock option and SAR transactions for the nine-month periods ended September 30, 2013 and 2012 (stock options and SARs in thousands):

(1)

The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2013 and 2012 was $134.2 million and $110.8 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, 2013 and 2012 was $332.3 million and $231.1 million, respectively.  At September 30, 2013 and 2012, the weighted average remaining contractual life was 4.8 years and 4.1 years, respectively.

(3)

The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2013 and 2012 was $322.5 million and $227.3 million, respectively.  At September 30, 2013 and 2012, the weighted average remaining contractual life was 4.7 years and 4.0 years, respectively.

(4)

The total intrinsic value of stock options/SARs exercisable at September 30, 2013 and 2012 was $202.4 million and $182.7 million, respectively.  At September 30, 2013 and 2012, the weighted average remaining contractual life was 3.5 years and 2.7 years, respectively.

At September 30, 2013, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $115.5 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.9 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 unit grants totaled $19.2 million and $23.1 million for the three months ended September 30, 2013 and 2012, respectively, and $55.5 million and $57.2 million for the nine months ended September 30, 2013 and 2012, respectively.

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The following table sets forth restricted stock and restricted stock unit transactions for the nine-month periods ended September 30, 2013 and 2012 (shares and units in thousands):

(1)

The total intrinsic value of restricted stock and restricted stock units released for the nine months ended September 30, 2013 and 2012 was $89.2 million and $110.7 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, 2013 and 2012 was $637.0 million and $438.6 million, respectively.

 

At September 30, 2013, unrecognized compensation expense related to restricted stock and restricted stock unit grants totaled $171.8 million.  Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.7 years.

Performance Units and Performance Stock.  EOG grants performance units and/or performance stock to its executive officers.  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 $7.1 million and $6.3 million for the three months ended September 30, 2013 and 2012, respectively, and $7.7 million and $6.3 million for the nine months ended September 30, 2013 and 2012, respectively.

Weighted average fair values and valuation assumptions used to value performance unit and performance stock grants during the nine-month periods ended September 30, 2013 and 2012 are as follows:

Expected volatility is based on the term-matched historical volatility over the simulated term, which is calculated as the time between the grant date and the end of the performance period.  The risk-free interest rate is based on a 3.26 year zero-coupon risk-free interest rate derived from the Treasury Constant Maturities yield curve on the grant date.

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The following table sets forth performance unit and performance stock transactions for the nine-month periods ended September 30, 2013 and 2012 (shares and units in thousands):

(1)

The total intrinsic value of performance units and performance stock outstanding at September 30, 2013 and 2012 was $22.1 million and $8.0 million, respectively.

At September 30, 2013, unrecognized compensation expense related to performance unit and performance stock grants totaled $7.1 million.  Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.7 years.

3.	Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the three-month and nine-month periods ended September 30, 2013 and 2012 (in thousands, except per share data):

The diluted earnings per share calculation excluded stock options and SARs that were anti-dilutive.  Shares underlying the excluded stock options and SARs totaled 0.3 million and 0.5 million shares for the three months ended September 30, 2013 and 2012, respectively, and 0.1 million and 0.3 million shares for the nine months ended September 30, 2013 and 2012, respectively.

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4.	Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the nine-month periods ended September 30, 2013 and 2012 (in thousands):

(1)

Net of capitalized interest of $34 million and $37 million for the nine months ended September 30, 2013 and 2012, respectively.

EOG's accrued capital expenditures at September 30, 2013 and 2012 were $743 million and $725 million, respectively.

 

5.	Segment Information

Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, 2013 and 2012 (in thousands):

(1)

Other International primarily includes EOG's United Kingdom, China and Argentina operations.

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Total assets by reportable segment are presented below at September 30, 2013 and December 31, 2012 (in thousands):

(1)

Other International primarily includes EOG's United Kingdom, China and Argentina operations.

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 nine-month periods ended September 30, 2013 and 2012 (in thousands):

(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.

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7.	Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the nine-month period ended September 30, 2013 are presented below (in thousands):

(1)

Includes capitalized exploratory well costs charged to dry hole costs.

At September 30, 2013, all capitalized exploratory well costs had been capitalized for a period of less than one year.

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 nine months ended September 30, 2013 and 2012, EOG's total costs recognized for these pension plans were $28.9 million and $27.1 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.

10.	Long-Term Debt

Long-Term Debt.  During the nine months ended September 30, 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 September 30, 2013.  The average of the borrowings outstanding under the commercial paper program was $23 million during the nine months ended September 30, 2013.  The weighted average interest rate for commercial paper borrowings for the nine months ended September 30, 2013 was 0.30 %.  At September 30, 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.  On October 1, 2013, EOG repaid, at maturity, the $400 million principal amount of its 6.125 % Senior Notes.

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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 September 30, 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 September 30, 2013, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.05 % and 3.25 %, respectively.

Restricted Cash.  In May 2013, the Canadian Alberta Energy Regulator (AER) made effective certain regulations affecting the Licensee Liability Rating program which requires well owners to post financial security for well abandonment obligations in amounts set forth by the AER.  In order to comply with these requirements, EOG Resources Canada Inc. (EOGRC) established a 160 million Canadian dollar letter of credit facility (maturing May 29, 2018) with Royal Bank of Canada (RBC) as the lender.  The letter of credit facility requires EOGRC to deposit cash, in an amount equal to all outstanding letters of credit under such facility, in a cash collateral account at RBC.  At September 30, 2013, the balance in this account was 70 million Canadian dollars (68 million United States dollars).

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 September 30, 2013 and December 31, 2012 (in millions):

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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.  Commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable.

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 $247 million were written down to their fair value of $154 million, resulting in pretax impairment charges of $93 million for the nine months ended September 30, 2013.  Included in the $93 million pretax impairment charges are $7 million of impairments of proved oil and gas properties for which EOG utilized an accepted offer from a third-party purchaser as the basis for determining fair value.  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 September 30, 2013 and December 31, 2012, EOG had outstanding $6,290 million aggregate principal amount of debt, which had estimated fair values of approximately $6,692 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.  EOG has not designated any of its financial commodity derivative contracts as hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method.  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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Commodity Derivative Contracts.  EOG entered into additional crude oil derivative contracts as a result of counterparties exercising outstanding options on September 30, 2013.  In addition, during September 2013, EOG settled certain crude oil derivative contracts covering notional volumes of 5,000 barrels per day (Bbld) for the period July 1, 2014 through December 31, 2014.  Presented below is a comprehensive summary of EOG's crude oil derivative contracts at September 30, 2013, with notional volumes expressed in 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 an additional six-month period.  Options covering a notional volume of 64,000 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 64,000 Bbld at an average price of $99.58 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 additional six-month and nine-month periods.  Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014.   If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014.  Options covering a notional volume of 93,000 Bbld are exercisable on or about June 30, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 93,000 Bbld at an average price of $96.47 per barrel for each month during the period July 1, 2014 through December 31, 2014.  In addition, in connection with the crude oil derivative contracts settled in September 2013, counterparties retain the option to enter into derivative contracts on December 31, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 5,000 Bbld at an average price of $95.43 per barrel for each month during the period January 1, 2015 through June 30, 2015.

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(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 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.

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 increases in Other Comprehensive Income (OCI) of $1.5 million and $1.1 million for the three months ended September 30, 2013 and 2012, respectively, and increases in OCI of $2.5 million and $1.7 million for the nine months ended September 30, 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 transaction using the hedge accounting method.  Changes in the fair value of the interest rate swap do not impact Net Income.  The after-tax net impact from the interest rate swap resulted in an increase in OCI of $0.4 million and a reduction in OCI of $0.2 million for the three months ended September 30, 2013 and 2012, respectively, and an increase in OCI of $1.3 million and a reduction in OCI of $0.4 million for the nine months ended September 30, 2013 and 2012, respectively.

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The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at September 30, 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 $47 million, partially offset by gross liabilities of $2 million at September 30, 2013 and gross assets of $271 million, partially offset by gross liabilities of $105 million at December 31, 2012.

(2)	The noncurrent portion of Assets from Price Risk Management Activities consists of gross assets of $4 million, partially offset by gross liabilities of $1 million at September 30, 2013.

(3)	The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $177 million, partially offset by gross assets of $2 million at September 30, 2013 and gross liabilities of $113 million, partially offset by gross assets of $105 million at December 31, 2012.

(4)	The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $1 million, offset by gross assets of $1 million at September 30, 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.

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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 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 11 for the aggregate fair value of all derivative instruments that were in a net liability position at September 30, 2013 and December 31, 2012.  EOG held no collateral at September 30, 2013 and held $6 million of collateral at December 31, 2012.  EOG had collateral of $2 million posted at September 30, 2013 and no collateral posted at December 31, 2012.

13.  Divestitures

During the first nine months of 2013, EOG received proceeds of approximately $587 million primarily from the sale of its entire interest in the planned Kitimat liquefied natural gas export terminal and the proposed Pacific Trail Pipelines, undeveloped acreage in the Horn River Basin in Canada and producing properties and acreage in the Upper Gulf Coast region, the Mid-Continent area and the Permian Basin.  During the first nine months of 2012, EOG received proceeds of approximately $1,214 million from sales of producing properties and acreage primarily in the Rocky Mountain area, the Upper Gulf Coast region and Canada.

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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 have proven to be successful.  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 is focused on developing its existing North American crude oil and liquids-rich acreage and testing methods to improve the recovery factor of the oil-in-place in these plays.  In addition, EOG continues to evaluate certain potential crude oil and liquids-rich exploration and development prospects.  For the first nine months of 2013, revenues from the sales of crude oil and condensate and natural gas liquids (NGLs) were approximately 84% of total wellhead revenues.  On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 55% of total company production for the first nine months of 2013 as compared to 45% for the comparable period in 2012.  In North America, crude oil and condensate and NGLs production accounted for approximately 62% of total North American production during the first nine months of 2013 as compared to 52% for the comparable period in 2012.  This liquids growth primarily reflects increased production from the South Texas Eagle Ford, the Permian Basin and the North Dakota Bakken.  Based on current trends, 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 upon 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.

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 nine months of 2013, EOG continued its four-well program in the Modified U(a) Block, drilling three development wells and one successful exploratory well.  In the third quarter of 2013, three of the four wells began production.  The fourth well will begin production in the fourth quarter of 2013.  In addition, an existing well was recompleted and began production in the third quarter of 2013.

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In the United Kingdom, EOG continues to make progress in field development for its East Irish Sea Conwy crude oil discovery.  Modifications to the nearby third-party-owned Douglas platform, which will be used to process Conwy production, began in the first quarter of 2013.  In the third quarter of 2013, a crude oil processing module was installed on the Douglas platform.  In addition, drilling began on three development wells.  First production from the Conwy field is anticipated in late 2014.  In the second quarter of 2013, costs totaling $24.1 million associated with the Central North Sea Columbus natural gas project were written off.  In the third quarter of 2013, EOG drilled an unsuccessful exploratory well in the Central North Sea Block 21/12b which was awarded to EOG in 2009.

In Argentina, EOG is focused on the Vaca Muerta oil shale formation in the Neuquén Basin in Neuquén Province.  In 2012, a monitor well was drilled in the Aguada del Chivato Block and completed during the first half of 2013.  Also, in 2013, the first well on the Cerro Avispa Block was drilled with completion expected in the fourth quarter of 2013.  EOG continues to evaluate its drilling results and exploration program in Argentina.

During the first half of 2013, EOG successfully recompleted a well in the Sichuan Basin, Sichuan Province, The People's Republic of China. A second well was drilled in the third quarter of 2013 and will be completed in the fourth quarter of 2013.  One additional well is planned in the fourth quarter of 2013, which is expected to begin producing in 2014.

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 30% and 32% at September 30, 2013 and December 31, 2012, respectively.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.  At September 30, 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.  On October 1, 2013, EOG repaid, at maturity, the $400 million principal amount of its 6.125% Senior Notes.

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 have been and 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 slightly higher than cash flow from operating activities for 2013.  EOG's business plan includes an objective of selling certain non-core assets in 2013 to cover any anticipated shortfall in cash flows.  In the first nine months of 2013, EOG achieved this goal by receiving proceeds of approximately $587 million 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 and nine months ended September 30, 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.

Three Months Ended September 30, 2013 vs. Three Months Ended September 30, 2012

Net Operating Revenues.  During the third quarter of 2013, net operating revenues increased $586 million, or 20%, to $3,541 million from $2,955 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 third quarter of 2013 increased $833 million, or 39%, to $2,942 million from $2,109 million for the same period of 2012.  During the third quarter of 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $293 million compared to net gains of $5 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 third quarter of 2013 increased $109 million, or 14%, to $873 million from $764 million for the same period of 2012.  Gains on asset dispositions, net, for the third quarter of 2013 and 2012 totaled $8 million and $67 million, respectively.

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Wellhead volume and price statistics for the three-month periods ended September 30, 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.

(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 2013 increased $826 million, or 55%, to $2,338 million from $1,512 million for the same period of 2012, due to an increase of 66 MBbld, or 39%, in wellhead crude oil and condensate deliveries ($587 million) and a higher composite average wellhead crude oil and condensate price ($239 million).  The increase in deliveries primarily reflects increased production in the South Texas Eagle Ford, the North Dakota Bakken and the Permian Basin.  EOG's composite average wellhead crude oil and condensate price for the third quarter of 2013 increased 11% to $108.20 per barrel compared to $97.13 per barrel for the same period of 2012.

NGLs revenues for the third quarter of 2013 increased $38 million, or 22%, to $208 million from $170 million for the same period of 2012, due to an increase of 10 MBbld, or 17%, in NGLs deliveries ($28 million) and a higher composite average NGLs price ($10 million).  The increase in deliveries primarily reflects increased volumes in the South Texas Eagle Ford and the Permian Basin.  EOG's composite average NGLs price for the third quarter of 2013 increased 5% to $32.74 per barrel compared to $31.11 per barrel for the same period of 2012.

Wellhead natural gas revenues for the third quarter of 2013 decreased $31 million, or 7%, to $396 million from $427 million for the same period of 2012.  The decrease was due to a decrease in natural gas deliveries ($50 million), partially offset by a higher composite average wellhead natural gas price ($19 million).  EOG's composite average wellhead natural gas price for the third quarter of 2013 increased 5% to $3.23 per thousand cubic feet (Mcf) compared to $3.07 per Mcf for the same period of 2012.  Natural gas deliveries for the third quarter of 2013 decreased 178 MMcfd, or 12%, primarily due to lower production in the United States (123 MMcfd), Trinidad (35 MMcfd) and Canada (18 MMcfd).  The decrease in the United States was primarily attributable to asset sales and reduced natural gas drilling activity.  The decrease in Trinidad was primarily attributable to higher contractual deliveries in 2012.

During the third quarter of 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $293 million compared to net gains of $5 million for the same period of 2012.  During the third quarter of 2013, the net cash outflow related to settled crude oil and natural gas derivative contracts was $21 million compared to the net cash inflow of $249 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.  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 third quarter of 2013, gathering, processing and marketing revenues and marketing costs increased compared to the same period of 2012 primarily as a result of increased crude oil marketing activities.  Gathering, processing and marketing revenues less marketing costs for the third quarter of 2013 decreased $13 million compared to the same period of 2012 due to lower margins on crude oil marketing activities.

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