(Mark One)

333 Clay Street, Suite 4200, Houston, Texas 77002-7361
(Address of principal executive offices, including 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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer x Accelerated filer o Non-accelerated filer 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 issuer's classes of common stock, as of April 23, 2007.

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

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

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

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EOG Resources, Inc. (EOG) is one of the largest independent (non-integrated) oil and natural gas companies in the United States with proved reserves in the United States, Canada, offshore Trinidad and the United Kingdom North Sea. EOG operates under a consistent business and operational strategy that focuses predominantly on achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.

Operations. EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG plans to continue to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas production. Production in the United States and Canada accounted for approximately 81% of total company production in the first three months of 2007. Based on current trends, EOG expects its full year 2007 production profile to be similar. EOG's major producing areas are in Louisiana, New Mexico, Oklahoma, Texas, Utah, Wyoming and western Canada.

Although EOG continues to focus on United States and Canada natural gas, EOG sees an increasing linkage between United States and Canada natural gas demand and Trinidad natural gas supply. For example, liquefied natural gas (LNG) imports from existing and planned facilities in Trinidad are contenders to meet increasing United States natural gas demand. In addition, ammonia, methanol and chemical production has been relocating from the United States and Canada to Trinidad, driven by attractive natural gas feedstock prices in the island nation. EOG believes that its existing position with the supply contracts to two ammonia plants, a methanol plant and the Atlantic LNG Train 4 (ALNG) plant will continue to give its portfolio an even broader exposure to United States and Canada natural gas fundamentals.

Beginning December 2005, ALNG began taking start-up gas and remained in the start-up phase through March 2007. ALNG is expected to commence commercial operations by the second half of 2007.

In addition to EOG's ongoing production from the Valkyrie and Arthur Fields in the United Kingdom North Sea, EOG participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f. The Columbus well was a farm-in opportunity and a rig has been contracted to drill an appraisal well in the third quarter of 2007.

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

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Capital Structure. One of management's key strategies is to keep 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 12% at both March 31, 2007 and December 31, 2006. During the first three months of 2007, EOG funded its capital programs primarily by utilizing cash provided from its operating activities. As management continues to assess price forecast and demand trends for 2007, EOG believes that operations and capital expenditure activity can be funded largely by cash from operations.

For 2007, EOG's estimated exploration and development expenditure budget is approximately $3.4 billion, excluding acquisitions. United States and Canada natural gas drilling activity continues to be a key component of this effort. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

At March 31, 2007, EOG maintained various stock-based compensation plans. See Note 2 to Consolidated Financial Statements. For the three months ended March 31, 2007 and 2006, EOG recognized $14.2 million and $9.0 million, respectively, of compensation expense related to its stock-based compensation plans. Such expense is included in the Consolidated Statements of Income based upon job functions of the employees receiving the grants as follows (in millions):

The following review of operations for the three-month periods ended March 31, 2007 and 2006 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included with this Quarterly Report on Form 10-Q.

Net Operating Revenues. During the first quarter of 2007, net operating revenues decreased $210 million to $875 million from $1,085 million for the same period of 2006. Total wellhead revenues, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, decreased $63 million, or 6%, to $911 million as compared to $974 million for the first quarter of 2006. Natural gas, crude oil, condensate and natural gas liquids revenues solely represent wellhead revenues for these products.

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

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Wellhead natural gas revenues for the first quarter of 2007 decreased $53 million, or 7%, to $736 million from $789 million for the same period of 2006. The decrease was due to a lower composite average wellhead natural gas price ($123 million), partially offset by increased natural gas deliveries ($70 million). The composite average wellhead price for natural gas decreased 14% to $5.76 per Mcf for the first quarter of 2007 from $6.72 per Mcf for the same period of 2006.

Wellhead crude oil and condensate revenues for the first quarter of 2007 decreased $18 million, or 11%, to $140 million from $158 million for the same period of 2006. The decrease was primarily due to a lower composite average wellhead crude oil and condensate price. The composite average wellhead price for crude oil and condensate decreased 9% to $54.51 per barrel for the first quarter of 2007 from $59.90 per barrel for the same period of 2006.

Natural gas liquids revenues for the first quarter of 2007 increased $8 million, or 30%, to $35 million from $27 million for the same period of 2006 as a result of increased deliveries.

During the first quarter of 2007, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $40 million compared to a gain of $107 million for the same period of 2006. During the first quarter of 2007, the net cash inflow related to settled natural gas and crude oil price swap contracts was $47 million compared to a net cash inflow related to settled natural gas financial collar and price swap contracts of $30 million for the comparable period of 2006.

Operating and Other Expenses. For the first quarter of 2007, operating expenses of $538 million were $82 million higher than the $456 million incurred in the first quarter of 2006. The following table presents the costs per Mcfe for the three-month periods ended March 31:

* Total per-unit costs do not include exploration costs, dry hole costs and impairments.

The changes in per-unit rates of lease and well, transportation costs, DD&A, G&A, taxes other than income and interest expense, net for the three-month period ended March 31, 2007 compared to the same period of 2006 were due primarily to the reasons set forth below.

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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 expense can be divided into the following categories: costs to operate and maintain EOG's oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance expenses include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are costs of 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 costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses of $104 million for the first quarter of 2007 increased $17 million from $87 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($13 million) and higher lease and well administrative expenses ($4 million).

Transportation costs represent costs incurred directly by EOG from third party carriers associated with the delivery of hydrocarbon products from the lease to a down-stream 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 and transportation fees.

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles; drilling or acquisition of new wells; disposition of existing wells; reserve revisions (upward or downward) primarily related to well performance; and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from quarter to quarter.

DD&A expenses of $244 million for the first quarter of 2007 increased $67 million from the same prior year period primarily due to increased DD&A rates in the United States ($35 million), Canada ($7 million) and the United Kingdom ($2 million); and increased production in the United States ($24 million).

G&A expenses of $44 million for the first quarter of 2007 increased $8 million from the same prior year period primarily due to higher employee related costs ($6 million) and higher office rent ($1 million).

Interest expense, net of $8 million for the first quarter of 2007 decreased $6 million compared to the same prior year period primarily due to higher capitalized interest ($2 million), interest associated with risk assessed tax liability in 2006 ($2 million) and lower average debt balance ($2 million).

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Taxes other than income of $41 million for the first quarter of 2007 decreased $13 million from the same prior year period.

Severance/production taxes in the United States decreased primarily due to increased credits taken for Texas high cost gas severance tax rate reductions ($17 million); partially offset by an increase in Trinidad due to changes to the tax legislation governing the Supplemental Petroleum Tax which resulted in an adjustment that decreased production tax expense in the first quarter of 2006 ($3 million).

Exploration costs of $26 million for the first quarter of 2007 are $13 million lower than the $39 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the Fort Worth Basin Barnett Shale play.

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Impairments include amortization of unproved leases, as well as impairments under SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $24 million for the first quarter of 2007 were $1 million higher than the same prior year period. Under SFAS No. 144, EOG recorded impairments of $10 million for each of the first quarters of 2007 and 2006.

Other income, net was $6 million for the first quarter of 2007 compared to $15 million for the same prior year period. The decrease of $9 million was primarily due to lower interest income ($5 million) and a decrease in equity income from investment in the Nitrogen (2000) Unlimited ammonia plant ($2 million).

Income tax provision of $118 million for the first quarter of 2007 decreased $85 million compared to the same prior year period primarily due to lower pre-tax income ($103 million), partially offset by an increase in foreign income taxes ($17 million). The net effective tax rate for the first quarter of 2007 increased to 35% from 32% for the same prior year period.

Cash Flow. The primary sources of cash for EOG during the three months ended March 31, 2007 were funds generated from operations and net borrowings. The primary uses of cash were funds used in operations, exploration and development expenditures, and dividend payments to shareholders. During the first three months of 2007, EOG's cash balance decreased $76 million to $142 million from $218 million at December 31, 2006.

Net cash used in investing activities of $858 million for the first three months of 2007 increased by $300 million compared to the same period of 2006 due primarily to increased additions to oil and gas properties.

Net cash provided by financing activities was $83 million for the first three months of 2007 compared to net cash used in financing activities of $51 million for the same period of 2006. Cash provided by financing activities for 2007 included net commercial paper and Trinidad revolving credit facility borrowings ($117 million), excess tax benefits from stock-based compensation expenses ($7 million) and proceeds from sales of treasury stock attributable to employee stock option exercises ($5 million). Cash used by financing activities for 2007 included repayments of long-term debt borrowings ($30 million) and cash dividend payments ($16 million).

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Total Exploration and Development Expenditures. The table below presents total exploration and development expenditures for the three-month periods ended March 31 (in millions):

Total exploration and development expenditures of $902 million for the first three months of 2007 were $270 million higher than the same period of 2006. The 2007 exploration and development expenditures of $894 million included $726 million in development, $161 million in exploration, $6 million in capitalized interest and $1 million in property acquisitions. The 2006 exploration and development expenditures of $628 million included $457 million in development, $167 million in exploration and $4 million in capitalized interest.

Lower exploration expenditures of $6 million for the first three months of 2007 were due primarily to decreased exploratory expenditures in Trinidad ($11 million), the United States ($4 million) and the United Kingdom ($2 million), partially offset by increased exploratory expenditures in Canada ($11 million).

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

Commodity Derivative Transactions. As more fully discussed in Note 11 to Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2006, 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 natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collar and price swap contracts, as the means to manage this price risk. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

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Presented below is a comprehensive summary of EOG's 2007 natural gas and crude oil financial price swap contracts at April 30, 2007, with notional volumes expressed in million British thermal units per day (MMBtud) and in barrels per day (Bbld), as applicable, and prices expressed in dollars per million British thermal units ($/MMBtu) and in dollars per barrel ($/Bbl), as applicable. Currently, EOG is not a party to any financial collar contracts. EOG accounts for these price swap contracts using the mark-to-market accounting method.

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts, including, among others, statements regarding EOG's future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "strategy," "intend," "plan," "target" and "believe" or the negative of those terms or other variations of them or by comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning future operating results, the ability to replace or increase reserves or to increase production, or the ability to generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes its expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, among others: the timing and extent of changes in commodity prices for crude oil, natural gas and related products, foreign currency exchange rates and interest rates; the timing and impact of liquefied natural gas imports and changes in demand or prices for ammonia or methanol; the extent and effect of any hedging activities engaged in by EOG; the extent of EOG's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; the availability and cost of drilling rigs, experienced drilling crews, materials and equipment used in well completions, and tubular steel; the availability, terms and timing of governmental and other permits and rights of way; the availability of pipeline transportation capacity; the availability of compression uplift capacity; the extent to which EOG can economically develop its Barnett Shale acreage outside of Johnson County, Texas; whether EOG is successful in its efforts to more densely develop its acreage in the Barnett Shale and other production areas; political developments around the world; acts of war and terrorism and responses to these acts; weather; and financial market conditions. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements might not occur. Forward-looking statements speak only as of the date made and EOG undertakes no obligation to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise.

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EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in the Derivative Transactions, Financing, Foreign Currency Exchange Rate Risk and Outlook sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity," on pages 29 through 32 of EOG's Annual Report on Form 10-K for the year ended December 31, 2006, filed on February 28, 2007.

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this Quarterly Report on Form 10-Q (Evaluation Date). Based on this evaluation, the principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date to ensure that information that is required to be disclosed by EOG in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to EOG's management as appropriate to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting. There were no changes in EOG's internal control over financial reporting that occurred during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

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See Part I, Item 1, Note 9 to Consolidated Financial Statements, which is incorporated herein by reference.

There have been no material changes from the risk factors previously disclosed in Item 1A, "Risk Factors" of EOG's Annual Report on Form 10-K for the year ended December 31, 2006.

Issuer Purchases of Equity Securities

*Exhibits filed herewith

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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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*Exhibits filed herewith

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