(Mark One)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002
(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, 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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                                              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., together with its subsidiaries (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, 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 continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's natural gas and crude oil production. Production in the United States and Canada accounted for approximately 86% of total company production in the first three months of 2008 as compared to 81% in the same period of 2007. First quarter 2008 crude oil and natural gas liquids production accounted for approximately 17% of total company production as compared to 14% for the same period of 2007. Based on current trends, EOG expects its production profile for the remainder of 2008 to be similar to the first quarter. EOG's major producing areas are in Louisiana, New Mexico, Texas, Utah, Wyoming and western Canada.

In February 2008, EOG completed a sale of the majority of its producing shallow gas assets and surrounding acreage in the Appalachian Basin to a subsidiary of EXCO Resources, Inc., an independent crude oil and natural gas company. Net proceeds from the sale, including a $40 million deposit received in December 2007, totaled $386 million. The purchase price is subject to customary adjustments under the agreement. EOG retained certain of its undeveloped acreage in this area, including rights in the Marcellus Shale, and will continue its shale exploration program. EOG recognized a pre-tax gain of $130 million on the sale of these properties in the first quarter of 2008 that is included in Net Operating Revenues - Other, Net on the Consolidated Statements of Income.

In the first quarter of 2008, EOG's Trinidad operation realized higher prices for natural gas sales as compared to the first quarter of 2007. This increase was due to higher ammonia, methanol and liquefied natural gas prices.

In the first quarter of 2008, EOG purchased an 80% interest in the Pelican field facilities from the subsidiaries of the other participants in the South East Coast Consortium Block. Also, in the first quarter of 2008, EOG finalized a crude oil and condensate sales contract with the Petroleum Company of Trinidad and Tobago. The pricing terms are based on the valuation of the distillation yield of the crude oil and condensate produced less a refining margin.

In addition to EOG's ongoing production from the Valkyrie and Arthur Fields in the United Kingdom North Sea, EOG is evaluating development plans for its Columbus prospect in the Central North Sea Block 23/16f. Alternative export routes are being considered in parallel with discussions with adjacent block owners concerning additional appraisal drilling to extend the boundary of this prospect to the south. A development plan decision is expected in early 2009.

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.

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 14% at both March 31, 2008 and December 31, 2007. During the first quarter of 2008, EOG funded $1.2 billion in exploration and development and other property, plant and equipment expenditures, paid $22 million in dividends to common and preferred stockholders and paid $5 million for the redemption of all remaining shares of its outstanding 7.195% Fixed Rate Cumulative Perpetual Senior Preferred Stock by utilizing cash provided from its operating activities and proceeds from the sale of its Appalachian properties. Cash on hand increased to $205 million at March 31, 2008 from $54 million at December 31, 2007. Management continues to assess price

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forecast and demand trends for 2008 and believes that operations and capital expenditure activity can be funded with cash from operating activities.

EOG's 2008 budget for exploration and development and other property, plant and equipment expenditures is approximately $4.4 billion, excluding acquisitions. United States and Canada natural gas drilling activity continues to be a key component of these expenditures. 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 that EOG currently has one of the strongest prospect inventories in EOG's history.

The following review of operations for the three-month periods ended March 31, 2008 and 2007 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 2008, net operating revenues increased $230 million to $1,101 million from $871 million for the same period of 2007. Total wellhead revenues for the first quarter of 2008, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, increased $527 million, or 58%, to $1,432 million as compared to $905 million for the first quarter of 2007.

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Wellhead volume and price statistics for the three-month periods ended March 31, 2008 and 2007 were as follows:

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids.
      Natural gas equivalents are determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil, condensate or natural gas liquids.

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Wellhead natural gas revenues for the first three months of 2008 increased $307 million, or 42%, to $1,038 million from $731 million for the same period of 2007. The increase was due to a higher composite average wellhead natural gas price ($232 million) and increased natural gas deliveries ($75 million). The composite average wellhead price for natural gas increased 29% to $7.36 per Mcf for the first three months of 2008 from $5.71 per Mcf for the same period of 2007.

Natural gas deliveries increased 129 MMcfd, or 9%, to 1,549 MMcfd for the first three months of 2008 from 1,420 MMcfd for the same period of 2007. The increase was mainly due to higher production in the United States (170 MMcfd), partially offset by decreased production in Trinidad (22 MMcfd), the United Kingdom (13 MMcfd) and Canada (6 MMcfd). The increase in the United States was attributable to increased production in Texas (132 MMcfd), the Rocky Mountain area (21 MMcfd) and Mississippi (17 MMcfd). The decline in Trinidad was due to a decrease in overall contractual demand (32 MMcfd), partially offset by an increase in deliveries to Atlantic LNG Train 4 (ALNG) (10 MMcfd). During the first quarter of 2007, ALNG was in the start-up phase but did not require any gas from EOG until May 2007 when ALNG reached commercial status and EOG began supplying gas under the ALNG take-or-pay contract. The decrease in the United Kingdom was due to production declines in both the Arthur and Valkyrie fields.

Wellhead crude oil and condensate revenues for the first three months of 2008 increased $163 million, or 117%, to $303 million from $140 million for the same period of 2007. The increase was due to a higher composite average wellhead crude oil and condensate price ($122 million) and increased wellhead crude oil and condensate deliveries ($41 million). The composite average wellhead crude oil and condensate price increased 68% to $91.46 per barrel for the first three months of 2008 from $54.51 per barrel for the same period of 2007. The increase in deliveries primarily reflects increased production in North Dakota.

Natural gas liquids revenues for the first three months of 2008 increased $57 million, or 161%, to $92 million from $35 million for the same period of 2007. The increase was due to increases in the composite average price ($33 million) and deliveries ($24 million). The increase in deliveries primarily reflects increased production in the Fort Worth area.

During the first quarter of 2008, as a result of rising commodity prices, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $470 million compared to a loss of $40 million for the same period of 2007. During the first quarter of 2008, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $23 million compared to the net cash inflow of $47 million for the same period of 2007. See "Capital Resources and Liquidity - Commodity Derivative Transactions."

Operating and Other Expenses. For the first quarter of 2008, operating expenses of $720 million were $187 million higher than the $533 million incurred during the first quarter of 2007. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the three-month periods ended March 31, 2008 and 2007:

(1) Total per-unit costs do not include exploration costs, dry hole costs, impairments and taxes other than income.

The primary factors impacting per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the three months ended March 31, 2008 compared to the same period of 2007 are 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 expenses can be divided into the following categories: costs to operate and maintain EOG's crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance 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 $132 million for the first quarter of 2008 increased $28 million from $104 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($17 million), higher lease and well administrative expenses ($6 million) and changes in the Canadian exchange rate ($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 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 and transportation fees.

Transportation costs of $62 million for the first quarter of 2008 increased $29 million from $33 million for the same prior year period primarily due to increased production and related costs associated with new marketing arrangements to transport additional production from the Fort Worth Basin Barnett Shale play ($16 million) and the Rocky Mountain area ($8 million) to new downstream markets.

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 $297 million for the first quarter of 2008 increased $53 million from the same prior year period primarily due to increased production in the United States ($48 million) and changes in the Canadian exchange rates ($7 million), partially offset by decreased production in the United Kingdom ($3 million).

G&A expenses of $53 million for the first quarter of 2008 increased $9 million from the same prior year period primarily due to higher employee related costs ($7 million) and an increase in legal and other professional services ($3 million).

Interest expense, net of $12 million for the first quarter of 2008 increased $4 million compared to the same prior year period primarily due to a higher average debt balance ($8 million), partially offset by higher capitalized interest ($3 million).

Exploration costs of $48 million for the first quarter of 2008 increased $22 million from $26 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($16 million) and Canada ($4 million). The increase in the United States was primarily attributable to the Fort Worth Basin Barnett Shale play ($13 million).

Impairments include amortization of unproved leases, as well as impairments under SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," (SFAS No. 144) which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $33 million for the first quarter of 2008 were $9 million higher than the same prior year period primarily due to increased

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amortization of unproved leases in the United States ($6 million) and Canada ($3 million). Under SFAS No. 144, EOG recorded impairments of $9 million and $10 million for the first quarter of 2008 and 2007, 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 determined based on wellhead revenues and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income for the first quarter of 2008 increased $46 million to $87 million (6.1% of wellhead revenues) from $41 million (4.5% of wellhead revenues) for the same prior year period. The increase in taxes other than income was a result of increases in both the United States and Trinidad. Severance/production taxes in the United States increased primarily due to an increase in wellhead revenues ($23 million), a decrease in credits taken for Texas high cost gas severance tax rate reductions ($15 million), and an increase in ad valorem/property taxes ($2 million). Severance/production taxes in Trinidad increased as a result of higher wellhead revenues ($2 million).

Other income, net was $2 million for the first quarter of 2008 compared to $5 million for the same prior year period. The decrease of $3 million was primarily due to increased foreign currency transaction losses ($2 million) and lower equity income from investment in Carribean Nitrogen Company Limited ammonia plant ($1 million).

Income tax provision of $129 million for the first quarter of 2008 increased $12 million compared to the same prior year period primarily due to higher pretax income. The net effective tax rate for the first quarter of 2008 remained unchanged from the 2007 rate of 35%.

Cash Flow. The primary sources of cash for EOG during the three months ended March 31, 2008 were funds generated from operations, proceeds from the sale of its producing shallow gas assets and surrounding acreage in the Appalachian Basin, proceeds from stock options exercised and excess tax benefits from stock-based compensation. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; and dividend payments to stockholders. During the first three months of 2008, EOG's cash balance increased $151 million to $205 million from $54 million at December 31, 2007.

Net cash provided by operating activities of $922 million for the first three months of 2008 increased $223 million compared to the same period of 2007 primarily reflecting an increase in wellhead revenues ($527 million), partially offset by an increase in cash operating expenses ($124 million), unfavorable changes in working capital and other assets and liabilities ($92 million), an increase in cash paid for income taxes ($36 million), a decrease in the net cash inflows from the settlement of financial commodity derivative contracts ($24 million) and an increase in cash paid for interest expense ($15 million).

Net cash used in investing activities of $807 million for the first three months of 2008 decreased by $51 million compared to the same period of 2007 due primarily to an increase in proceeds from sales of assets ($344 million), primarily reflecting net proceeds from the sale of EOG's Appalachian assets, partially offset by an increase in additions to oil and gas properties ($248 million).

Net cash provided by financing activities was $37 million for the first three months of 2008 compared to $83 million for the same period of 2007. Cash provided by financing activities for the first three months of 2008 included excess tax benefits from stock-based compensation ($35 million) and proceeds from stock options exercised ($30 million). Cash used by financing activities for the first three months of 2008 included cash dividend payments ($22 million) and the redemption of preferred stock ($5 million).

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Total Expenditures. The table below sets out components of total expenditures for the three-month periods ended March 31, 2008 and 2007 (in millions):

Exploration and development expenditures of $1,108 million for the first three months of 2008 were $270 million higher than the same period of 2007 due primarily to increased drilling and facilities expenditures of $148 million, increased lease acquisitions in Canada ($43 million) and in the United States ($25 million), changes in the Canadian exchange rate ($22 million) and increased geological and geophysical expenditures in the United States ($16 million) and in Canada ($4 million). The increased drilling and facilities expenditures of $148 million primarily resulted from higher drilling and facilities expenditures in the United States ($218 million), partially offset by lower drilling and facilities expenditures in Canada ($49 million) and Trinidad ($30 million). The exploration and development expenditures for the first three months of 2008 of $1,108 million include $801 million in development, $269 million in exploration, $29 million in property acquisitions and $9 million in capitalized interest. The increase in expenditures for other property, plant and equipment was primarily related to gathering systems and processing plants in the Fort Worth Basin Barnett Shale and Rocky Mountain areas. The exploration and development expenditures for the first three months of 2007 of $838 million include $670 million in development, $161 million in exploration, $6 million in capitalized interest and $1 million in property acquisitions.

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 North Sea, 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, 2007, 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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The total fair value of the natural gas and crude oil financial price swap contracts at March 31, 2008 was a negative $393 million. Since filing its Current Report on Form 8-K on May 1, 2008, EOG has not entered into additional natural gas or crude oil financial price swap contracts. Presented below is a comprehensive summary of EOG's 2008 and 2009 natural gas and crude oil financial price swap contracts at May 8, 2008, with notional volumes expressed in MMBtud and in barrels per day (Bbld), as applicable, and prices expressed in dollars per million British thermal units ($/MMBtu) and in dollars per barrel ($/Bbl), as applicable. Currently, EOG is not a party to any financial collar contracts. The average price of EOG's outstanding natural gas financial price swap contracts for 2008 is $8.52 per million British thermal units (MMBtu) and for 2009 is $8.80 per MMBtu. The average price of EOG's outstanding crude oil financial price swap contracts is $92.19 per barrel.

(1) The natural gas contracts for May 2008 are closed. The crude oil contracts for May 2008 will close on May 31, 2008.

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts, including, among others, statements 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 or 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 the expectations reflected in its forward-looking statements are based on reasonable assumptions, no assurance can be given that these

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expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

• the timing and extent of changes in commodity prices for crude oil, natural gas and related products, foreign currency exchange rates, interest rates and financial market conditions;

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

• the timing and impact of liquefied natural gas imports;

• changes in demand or prices for ammonia or methanol;

• 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 ability to achieve production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reservoir performance;

• the availability and cost of drilling rigs, experienced drilling crews, tubular steel and other materials, equipment and services used in drilling and well completions;

• the availability, terms and timing of mineral licenses and leases and governmental and other permits and rights of way;

• access to surface locations for drilling and production facilities;

• the availability and capacity of gathering, processing and pipeline transportation facilities;

• 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 and the enactment of new government policies, legislation and regulations, including environmental regulations;

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

• weather, including weather-related delays in the installation of gathering and production facilities.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur. EOG's 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 (i) the "Derivative Transactions," "Financing," "Foreign Currency Exchange Rate Risk" and "Outlook" sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity," on pages 32 through 36 of EOG's Annual Report on Form 10-K for the year ended December 31, 2007, filed on February 28, 2008; and (ii) Note 11, "Price, Interest Rate and Credit Risk Management Activities," on pages F-27 through F-29, to EOG's Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2007. There have been no material changes in this information. For additional information regarding EOG's financial commodity derivative contracts and physical commodity contracts, see (i) Note 1 to Consolidated Financial Statements in this Quarterly Report on Form 10-Q; (ii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Net Operating Revenues" in this Quarterly Report on Form 10-Q; and (iii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions" in this Quarterly Report on Form 10-Q.

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, EOG's principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date in ensuring 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 (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act) that occurred during the quarterly 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.

Issuer Purchases of Equity Securities