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

(Mark One)

For the quarterly period ended June 30, 2012

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)

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- 6 -

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

 

- 8 -

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

- 9 -

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

EOG's accrued capital expenditures at June 30, 2012 and 2011 were $857 million and $763 million, respectively.

Selected financial information by reportable segment is presented below for the three-month and six-month periods ended June 30, 2012 and 2011 (in thousands):

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Total assets by reportable segment are presented below at June 30, 2012 and December 31, 2011 (in thousands):

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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 six-month periods ended June 30, 2012 and 2011 (in thousands):

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(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 six-month period ended June 30, 2012 are presented below (in thousands):

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The following table provides an aging of capitalized exploratory well costs at June 30, 2012 (in thousands, except well count):

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(1)

Consists of costs related to an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($20 million) and a shale project in the Horn River area of British Columbia, Canada (B.C.) ($6 million).  In the Central North Sea Columbus project, during the second quarter of 2012, a revised commercial arrangement for transportation and an updated project schedule necessitated the filing of a revised field development plan with the U.K. Department of Energy and Climate Change (DECC). The revised plan is expected to be submitted during the third quarter of 2012.  DECC approval of the revised plan is expected during the first quarter of 2013.  In the B.C. shale project, EOG drilled seven wells in the first half of 2012 to retain land and further evaluate the project.  The related well completion activities for the B.C. shale project are not expected to commence until 2013 or later.

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.

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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 six months ended June 30, 2012 and 2011, EOG's total costs recognized for these pension plans were $18.8 million and $13.9 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 six months ended June 30, 2012, EOG utilized commercial paper and short-term borrowings from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes.  EOG had no outstanding borrowings from commercial paper issuances or uncommitted credit facilities at June 30, 2012.  The average of the borrowings outstanding under the commercial paper program and uncommitted credit facilities was $240 million and $82 thousand, respectively, during the six months ended June 30, 2012.  The weighted average interest rates for commercial paper and uncommitted credit facility borrowings for the six months ended June 30, 2012 were 0.44% and 0.70%, respectively.

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 June 30, 2012, 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 June 30, 2012, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.12% and 3.25%, respectively.

Common Stock.  On February 16, 2012, EOG's Board of Directors increased the quarterly cash dividend on the Common Stock from the previous $0.16 per share to $0.17 per share, effective with the dividend paid on April 30, 2012 to stockholders of record as of April 16, 2012.

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11.    Fair Value Measurements

As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2011 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 June 30, 2012 and December 31, 2011 (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 contracts was based upon forward commodity price and interest rate curves based on quoted market prices.  The estimated fair value of the foreign currency rate swap 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 was utilized in valuing options.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on estimates of future retirement costs associated with 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.

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Proved oil and gas properties and other property, plant and equipment with a carrying amount of $178 million were written down to their fair value of $82 million, resulting in a pretax impairment charge of $96 million for the six months ended June 30, 2012.  Included in the $96 million pretax impairment charge is a $60 million impairment of proved oil and gas properties and other property, plant and equipment, for which EOG utilized an accepted offer from a third-party 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 June 30, 2012 and December 31, 2011, EOG had outstanding $5,040 million aggregate principal amount of debt, which had estimated fair values of approximately $5,735 million and $5,657 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.

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Presented below is a comprehensive summary of EOG's natural gas derivative contracts at June 30, 2012, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

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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.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from August 1, 2012 through December 31, 2012.

(2)

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 of 2013 and 2014.

Subsequent to June 30, 2012, EOG settled its natural gas financial price swap contracts for the period January 1, 2014 through December 31, 2014 and received proceeds of $36.6 million.  Options associated with the settled 2014 price swap contracts remain in place.  An updated summary of EOG's natural gas financial price swap contracts as of August 2, 2012 is presented in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions."

 

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 $150 million principal amount of notes issued by one of EOG's Canadian subsidiaries.  EOG accounts for the foreign currency swap using the hedge accounting method.  Changes in the fair value of the foreign currency swap do not impact Net Income.  The after-tax net impact from the foreign currency swap resulted in a reduction in Other Comprehensive Income (OCI) of $1 million for both the three months ended June 30, 2012 and 2011, respectively, and an increase of $1 million and a reduction of $0.1 million for the six months ended June 30, 2012 and 2011, 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 EOG's $350 million principal amount of Floating Rate Senior Notes due 2014.  The interest rate swap has a notional amount of $350 million.  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 net impact from the interest rate swap resulted in an increase in OCI of $0.1 million and a reduction of $4 million for the three months ended June 30, 2012 and 2011, respectively, and a reduction of $0.2 million and $3 million for the six months ended June 30, 2012 and 2011, respectively.

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The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding financial derivative instruments at June 30, 2012 and December 31, 2011.  Certain amounts may be presented on a net basis in the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

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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 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 are in a net liability position at June 30, 2012 and December 31, 2011.  EOG had no collateral posted at either June 30, 2012 or December 31, 2011 and held collateral of $100 million and $67 million at June 30, 2012 and December 31, 2011, respectively.

13.   Divestitures

During the first six months of 2012, EOG received proceeds of approximately $1,112 million from the sales of producing properties and acreage primarily in the Rocky Mountain area, the Upper Gulf Coast area 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 and China.  EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries.  This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet.  EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves.  Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

United States and Canada.  EOG's efforts to identify plays with large reserve potential have proven a successful supplement to its base development and exploitation program in the United States and Canada.  EOG continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas liquids production.  EOG has placed an emphasis on applying its horizontal drilling and completion expertise gained from its natural gas resource plays to unconventional crude oil and liquids-rich reservoirs.  In 2012, 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 liquids-rich exploration and development prospects.  For the first half of 2012, crude oil and condensate and natural gas liquids production accounted for approximately 44% of total company production as compared to 33% for the comparable period in 2011.  In North America, crude oil and condensate and natural gas liquids production accounted for approximately 51% of total North American production during the first half of 2012 as compared to 39% for the comparable period in 2011.  This liquids growth primarily reflects increased production from the Eagle Ford Shale near San Antonio, Texas, and the Fort Worth Basin Barnett Shale area.  Based on current trends, EOG expects its 2012 crude oil and condensate and natural gas liquids production to continue to increase both in total and as a percentage of total company production as compared to 2011.

EOG delivers its crude oil to various markets in the United States, including sales points on the Gulf Coast where sales are based upon a Light Louisiana Sweet (LLS) crude oil index.  As part of its diversification strategy for its crude-by-rail shipments, EOG completed the construction of a crude oil unloading facility in St. James, Louisiana, where sales are based upon the LLS crude oil index.  This facility, which received the first unit train of EOG crude oil in April 2012, has a capacity of approximately 100 thousand barrels per day (MBbld) and is able to accommodate multiple trains at a single time.  With completion of the St. James facility, EOG's crude-by-rail system now has access to the Gulf Coast market as well as the Cushing, Oklahoma, market.  At the beginning of July 2012, EOG began shipping a portion of its Eagle Ford Shale crude oil production to Gulf Coast sales points on the newly completed Enterprise Products Partners L.P. crude oil pipeline.  In addition, EOG began supplying sand for a portion of its completion operations in several plays, primarily in Texas, from Wisconsin sand mines in 2012.

EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), holds a 30% interest in both the planned liquefied natural gas export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia (Kitimat LNG Terminal) and the proposed Pacific Trail Pipelines (PTP) which is intended to link Western Canada's natural gas producing regions to the Kitimat LNG Terminal.  An affiliate of Apache Corporation is the operator of both the PTP and the Kitimat LNG Terminal.  The front-end engineering and design study is expected to be delivered in the second half of 2012, and EOG expects to make a final investment decision at the beginning of 2013.

EOG's major producing areas in the United States and Canada are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

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International.  In Trinidad, EOG continued to deliver natural gas under existing supply contracts.  Several fields in the South East Coast Consortium Block, Modified U(a) Block and Modified U(b) Block, as well as the Pelican Field, have been developed and are producing natural gas and crude oil and condensate.  Production from the Block 4(a) Toucan Field and the EMZ Area that began in the first quarter of 2012 is supplying natural gas under a contract with the National Gas Company of Trinidad and Tobago.

In the United Kingdom, EOG continues to make progress in field development for its East Irish Sea Conwy/Corfe crude oil discovery and its Central North Sea Columbus natural gas discovery.  The field development plan for the Conwy/Corfe project was approved by the U.K. Department of Energy and Climate Change (DECC) in March 2012.  The production platform was installed during the second quarter of 2012 and the pipelines are scheduled to be installed in the fourth quarter of 2012.  EOG expects to begin processing facility installation in the first half of 2013.  The drilling of development wells is expected to commence at the beginning of 2013, with initial production expected in the second half of 2013.  In the Central North Sea Columbus project, during the second quarter of 2012, a revised commercial arrangement for transportation and an updated project schedule necessitated the filing of a revised field development plan with the DECC.  The revised plan is expected to be submitted in the third quarter of 2012 with DECC approval expected in the first quarter of 2013.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Basin in Neuquén Province.  EOG participated in the drilling and completion of a vertical well in the Bajo del Toro Block.  In the first quarter of 2012, EOG drilled a well to monitor future well completions in the Aguada del Chivato Block.  During the second quarter of 2012, EOG completed a horizontal well in this block.  Both the horizontal and vertical wells that were completed are under evaluation.

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 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 27% and 28% at June 30, 2012 and December 31, 2011, respectively.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

EOG's total 2012 capital expenditures are estimated to range from $7.4 billion to $7.6 billion, excluding acquisitions.  The majority of 2012 expenditures will be focused on United States and Canada crude oil and liquids-rich gas drilling activity and, to a much lesser extent, natural gas drilling activity in the Haynesville, Marcellus and British Columbia Horn River Basin plays to hold acreage.  EOG expects capital expenditures to be greater than cash flow from operating activities for 2012.  EOG's business plan includes selling certain non-core assets in 2012 to partially cover the anticipated shortfall.  In the first half of 2012, proceeds of approximately $1.1 billion were received from the sales of producing properties and acreage primarily in the Rocky Mountain area, Upper Gulf Coast area and Canada.  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 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 six months ended June 30, 2012 and 2011 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 June 30, 2012 vs. Three Months Ended June 30, 2011

Net Operating Revenues.  During the second quarter of 2012, net operating revenues increased $339 million, or 13%, to $2,909 million from $2,570 million for the same period of 2011.  Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, natural gas liquids and natural gas, for the second quarter of 2012 increased $164 million, or 9%, to $1,886 million from $1,722 million for the same period of 2011.  During the second quarter of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $188 million compared to $190 million for the same period of 2011.  Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas, for the second quarter of 2012 increased $223 million, or 46%, to $711 million from $488 million for the same period of 2011.  Gains on asset dispositions, net, of $113 million for the second quarter of 2012 primarily consist of gains on asset dispositions in the Rocky Mountain area and Canada.

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Wellhead volume and price statistics for the three-month periods ended June 30, 2012 and 2011 were as follows:

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(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 second quarter of 2012 increased $437 million, or 47%, to $1,376 million from $939 million for the same period of 2011, due to an increase of 54 MBbld, or 52%, in wellhead crude oil and condensate deliveries ($503 million), partially offset by a lower composite average wellhead crude oil and condensate price ($66 million).  The increase in deliveries primarily reflects increased production in the Eagle Ford Shale.  EOG's composite average wellhead crude oil and condensate price for the second quarter of 2012 decreased 5% to $95.20 per barrel compared to $99.77 per barrel for the same period of 2011.

Natural gas liquids revenues for the second quarter of 2012 decreased $34 million, or 18%, to $150 million from $184 million for the same period of 2011, due to a lower composite average natural gas liquids price ($80 million), partially offset by an increase of 16 MBbld, or 42%, in natural gas liquids deliveries ($46 million).  The increase in deliveries primarily reflects increased volumes in the Eagle Ford Shale and Fort Worth Basin Barnett Shale plays.  EOG's composite average natural gas liquids price for the second quarter of 2012 decreased 35% to $33.72 per barrel compared to $51.65 per barrel for the same period of 2011.

Wellhead natural gas revenues for the second quarter of 2012 decreased $241 million, or 40%, to $359 million from $600 million for the same period of 2011.  The decrease was due to a lower composite average wellhead natural gas price ($235 million) and a decrease in natural gas deliveries ($6 million).  EOG's composite average wellhead natural gas price for the second quarter of 2012 decreased 39% to $2.47 per thousand cubic feet (Mcf) compared to $4.08 per Mcf for the same period of 2011.

Natural gas deliveries for the second quarter of 2012 decreased 17 MMcfd, or 1%, to 1,598 MMcfd from 1,615 MMcfd for the same period of 2011.  The decrease was primarily due to lower production in the United States (44 MMcfd) and Canada (43 MMcfd), partially offset by increased production in Trinidad (73 MMcfd).  The decrease in the United States was primarily attributable to asset sales that occurred subsequent to the second quarter of 2011 and decreased production in Louisiana, the Rocky Mountain area, Kansas and New Mexico, partially offset by increased production in Texas and Pennsylvania.  The decrease in Canada was primarily due to decreased production in Alberta and the Horn River Basin area.  The increase in Trinidad was primarily attributable to an increase in contractual deliveries.

During the second quarter of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $188 million compared to $190 million for the same period of 2011.  During the second quarter of 2012, the net cash inflow related to settled crude oil and natural gas derivative contracts was $173 million compared to $6 million for the same period of 2011.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas.  For the three months and six months ended June 30, 2012 and 2011, gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas.  The purchase and sale of third-party crude oil and natural gas are utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities.  Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs.

During the second quarter of 2012, gathering, processing and marketing revenues and marketing costs increased, compared to the same period of 2011, primarily as a result of increased crude oil marketing activities.  Gathering, processing and marketing revenues less marketing costs for the second quarter of 2012 totaled $17 million compared to $18 million for the same period of 2011.

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Operating and Other Expenses.  For the second quarter of 2012, operating expenses of $2,217 million were $235 million higher than the $1,982 million incurred in the second quarter of 2011.  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended June 30, 2012 and 2011:
 

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(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 G&A for the three months ended June 30, 2012 compared to the same period of 2011 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 $251 million for the second quarter of 2012 increased $34 million from $217 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($31 million), increased workover expenditures in the United States ($4 million) and increased lease and well administrative expenses in the United States ($3 million), partially offset by decreased operating and maintenance costs in Canada ($4 million).

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

Transportation costs of $135 million for the second quarter of 2012 increased $33 million from $102 million for the same prior year period primarily due to increased transportation costs in the Eagle Ford Shale ($25 million) and the Rocky Mountain area ($11 million), partially offset by decreased transportation costs in the Fort Worth Basin Barnett Shale area ($5 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 and 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 calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses for the second quarter of 2012 increased $206 million to $809 million from $603 million for the same prior year period.  DD&A expenses associated with oil and gas properties for the second quarter of 2012 were $203 million higher than the same prior year period primarily due to higher unit rates in the United States ($118 million), Canada ($8 million) and Trinidad ($3 million) and as a result of increased production in the United States ($90 million) and Trinidad ($5 million), partially offset by decreased production in Canada ($19 million) and favorable changes in the Canadian exchange rate ($3 million).

G&A expenses of $76 million for the second quarter of 2012 increased $8 million compared to the same prior year period primarily due to higher employee-related costs.

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets.

Gathering and processing costs increased $3 million to $21 million for the second quarter of 2012 compared to $18 million for the same prior year period.  The increase primarily reflects increased activities in the Eagle Ford Shale.

Exploration costs of $48 million for the second quarter of 2012 increased $7 million from $41 million for the same prior year period primarily due to increased geological and geophysical expenditures ($4 million) and increased exploration administrative expenses ($3 million) both in the United States.

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

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Impairments of $54 million for the second quarter of 2012 were $304 million lower than impairments for the same prior year period primarily due to decreased impairments of proved properties in Canada ($312 million) and decreased amortization of unproved property costs in the United States ($11 million) and Canada ($2 million), partially offset by increased impairments of proved properties in the United States ($21 million).  EOG recorded impairments of proved properties of $21 million and $312 million for the second quarter of 2012 and 2011, 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 second quarter of 2012 increased $14 million to $118 million (6.3% of wellhead revenues) compared to $104 million (6.1% of wellhead revenues) for the same prior year period.  The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($18 million) primarily as a result of increased wellhead revenues and the accrual of a new fee imposed retroactively by the State of Pennsylvania on certain wells drilled in the state during 2011 and prior years, partially offset by decreased severance/production taxes in Trinidad ($6 million).

Income tax provision of $250 million for the second quarter of 2012 increased $3 million compared to 2011 due primarily to higher pretax income.  The net effective tax rate for 2012 decreased to 39% from 46% in the same prior year period primarily due to the absence of certain 2011 Canadian shallow natural gas impairments, which were tax effected at the lower Canadian statutory tax rate.  The effective tax rate for 2012 exceeded the United States statutory tax rate (35%) primarily due to foreign earnings in Trinidad (55% statutory tax rate) combined with losses in Canada (26% statutory tax rate).

Six Months Ended June 30, 2012 vs. Six Months Ended June 30, 2011

Net Operating Revenues.  During the first six months of 2012, net operating revenues increased $1,249 million, or 28%, to $5,716 million from $4,467 million for the same period of 2011.  Total wellhead revenues for the first six months of 2012 increased $550 million, or 17%, to $3,762 million from $3,212 million for the same period of 2011.  During the first six months of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $323 million compared to net gains of $123 million for the same period of 2011.  Gathering, processing and marketing revenues for the first six months of 2012 increased $546 million, or 62%, to $1,429 million from $883 million for the same period of 2011.  Gains on asset dispositions, net, of $181 million for the first six months of 2012 primarily consist of gains on asset dispositions in the Rocky Mountain area and Canada.

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Wellhead volume and price statistics for the six-month periods ended June 30, 2012 and 2011 were as follows: