Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes o No x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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. (Check one):
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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. Common Stock aggregate market value held by non-affiliates as of June 30, 2007: $17,881,411,475.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Class: Common Stock, par value $0.01 per share, 247,019,188 Shares outstanding as of February 15, 2008.

Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2008 Annual Meeting of Stockholders to be filed within 120 days after December 31, 2007 are incorporated by reference into Part III of this report.

(i)

EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively EOG), explores for, develops, produces and markets natural gas and crude oil primarily in major producing basins in the United States of America (United States), Canada, offshore Trinidad, the United Kingdom North Sea and, from time to time, select other international areas. EOG's principal producing areas are further described in "Exploration and Production" below. EOG's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports are made available, free of charge, through its website, as soon as reasonably practicable after such reports have been filed with the Securities and Exchange Commission (SEC). EOG's website address is http://www.eogresources.com.

At December 31, 2007, EOG's total estimated net proved reserves were 7,745 billion cubic feet equivalent (Bcfe), of which 6,669 billion cubic feet (Bcf) were natural gas reserves and 179 million barrels (MMBbl), or 1,076 Bcfe, were crude oil, condensate and natural gas liquids reserves (see "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 67% of EOG's reserves (on a natural gas equivalent basis) were located in the United States, 17% in Canada and 16% in Trinidad. As of December 31, 2007, EOG employed approximately 1,800 persons, including foreign national employees.

EOG's business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis. EOG focuses its drilling activity toward natural gas deliverability in addition to natural gas reserve replacement and to a lesser extent crude oil exploration and exploitation. EOG focuses on the cost-effective utilization of advances in technology associated with the gathering, processing and interpretation of three-dimensional (3-D) seismic data, the development of reservoir simulation models, the use of new and/or improved drill bits, mud motors and mud additives, horizontal drilling, well completion and formation logging techniques and reservoir fracturing methods. These advanced technologies are used, as appropriate, throughout EOG to reduce the risks associated with all aspects of oil and gas exploration, development and exploitation. EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. EOG also makes select strategic acquisitions that result in additional economies of scale or land positions which provide significant additional prospects. 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.

With respect to information on EOG's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by EOG's working interest in the wells or acreage.

EOG's operations are all natural gas and crude oil exploration and production related.

EOG's operations are focused on most of the productive basins in the United States and Canada.

At December 31, 2007, 84% of EOG's net proved United States and Canada reserves (on a natural gas equivalent basis) were natural gas and 16% were crude oil, condensate and natural gas liquids. Substantial portions of these reserves are in long-lived fields with well-established production characteristics. EOG believes that opportunities exist to increase production through continued development in and around many of these fields and through the application of new processes and technologies. EOG also maintains an active exploration program designed to extend fields and add new trends to its broad portfolio. The following is a summary of significant developments during 2007 and certain 2008 plans for EOG's United States and Canada operations.

1

United States. In the prolific Barnett Shale play of the Fort Worth Basin, EOG, which holds approximately 900,000 net acres, has become an industry leader in per well production rates through the application of advanced drilling and completion technology. In 2007, EOG continued a very active drilling program and had strong production growth. For the year, EOG drilled 293 net wells and grew production to a net average of 271 million cubic feet per day (MMcfd) of natural gas and 2.2 thousand barrels per day (MBbld) of crude oil, condensate and natural gas liquids. EOG ended 2007 with production of approximately 375 million cubic feet equivalent per day (MMcfed), net and expects to significantly grow production during 2008 with the plan to drill and complete over 400 net wells. Using innovative technology, EOG is generating significant new growth opportunities in the Fort Worth Basin that are expected to add to its future reserve and production growth potential.

The Upper Gulf Coast continued to be a growth area for EOG where 2007 net production grew 12% year over year and averaged 135 MMcfd of natural gas and 3.5 MBbld of crude oil, condensate and natural gas liquids. In 2007, EOG drilled 90 net wells in the Upper Gulf Coast area with 67 net wells in the Sligo, Minden, Carthage, Driscoll, Logansport and Appleby Fields of the Cotton Valley and Travis Peak formations in East Texas and North Louisiana. Mississippi remained a major growth area where 23 successful net wells were drilled in the Sligo and Hosston plays in South Williamsburg and two new discoveries were made in the Columbia and Whitesand Fields. EOG is currently one of the largest natural gas producers in Mississippi. EOG, which holds approximately 300,000 net acres in the Upper Gulf Coast area, will continue its growth in East Texas, Louisiana and Mississippi and plans to test several high potential impact new projects in 2008.

During 2007, EOG drilled 55 net wells in the Permian Basin, with 33 net wells drilled in the New Mexico Wolfcamp play. EOG has acquired 50,000 acres in the play and plans to drill a similar number of wells in 2008. EOG also had success with vertical oil wells in the Permo-Penn carbonates as well as horizontal wells in the Bone Spring sand. Net production averaged 82 MMcfd of natural gas and 6.9 MBbld of crude oil, condensate and natural gas liquids. Program economics remained strong through 2007 as significant acreage and new 3-D seismic data were acquired in several trends, setting up new plays for 2008 and beyond. EOG holds approximately 450,000 net acres in the Permian Basin.

EOG continued to expand its activities throughout the Rocky Mountain area where it holds approximately 1.3 million net acres. During 2007, 267 net wells were drilled. In the core areas, 187 net wells were drilled in the Uinta Basin, Utah, 38 net wells were drilled in the Moxa Arch area of Wyoming, 20 net wells were drilled in the Williston Basin, North Dakota and 19 net wells were drilled in the LaBarge Platform, Wyoming. Production from the Rocky Mountain area increased 15% with the increased drilling activity. The net average production for 2007 was 178 MMcfd of natural gas and 11.9 MBbld of crude oil, condensate and natural gas liquids. EOG expects to continue increasing exploitation drilling activity throughout the Rocky Mountain area during 2008, while maintaining an active exploration program. EOG ended 2007 producing approximately 7.0 MBbld, net, of crude oil from the Bakken play in North Dakota and will seek to significantly grow production during 2008 with 49 net wells planned.

In the Mid-Continent area, EOG drilled 117 net wells during 2007 in the Hugoton-Deep play in the Southwest Kansas/Oklahoma Panhandle and the Cleveland Horizontal play in the Texas Panhandle. The net average production for 2007 was 80 MMcfd of natural gas and 3.5 MBbld of crude oil and condensate which represents a 14% total production increase over 2006. EOG continued its strong exploration program in Southwest Kansas and was successful in finding several new Morrow and St. Louis plays. As part of the Hugoton-Deep play, EOG has eight years remaining on an approximately 900,000 gross acre, 10-year farm-in agreement from Anadarko Petroleum Company. EOG plans to continue exploiting these two core growth areas in 2008, while pursuing other exploration prospects throughout the Mid-Continent area. EOG holds approximately 500,000 net acres in the Mid-Continent area.

EOG had another successful year in South Texas and the Gulf of Mexico, drilling 91 net wells in 2007. South Texas onshore and Gulf of Mexico offshore net production averaged 209 MMcfd of natural gas and 7.8 MBbld of crude oil, condensate and natural gas liquids during 2007. The activity was focused in Webb, Zapata, San Patricio, Duval and Starr Counties, where EOG drilled successful wells in the Lobo, Roleta, Reklaw, Frio and Wilcox trends. EOG's application of horizontal drilling and completion technology in the Wilcox trend continues to expand into new areas. EOG is acquiring seismic data and leases to expand horizontal drilling technology to three additional trends in South Texas. Production from two deepwater Gulf of Mexico wells, drilled in the Atwater Valley area that was discovered in 2001, is expected to commence during the first quarter of 2008 at an initial rate of 10 MMcfd, net. Plans are to increase this rate to approximately 20 MMcfd, net after additional facilities are installed

2

in mid-2008. Approximately 92 net wells are planned during 2008 for South Texas and the Gulf of Mexico where EOG holds approximately 550,000 net acres.

In 2007, EOG drilled 51 net wells in the Appalachian Basin where it holds approximately 310,000 net acres. Net production averaged 17 MMcfd of natural gas and 60 barrels per day of crude oil and condensate. A majority of the wells were drilled in the shallow Devonian play and 10 gross wells were drilled to evaluate the deeper Marcellus Shale. In December 2007, EOG entered into an agreement to sell the majority of its producing shallow gas assets and surrounding acreage in the Appalachian Basin to a subsidiary of EXCO Resources, Inc., an independent oil and gas company, for approximately $395 million, subject to customary adjustments under the agreement. The Appalachian area being divested includes approximately 2,400 operated wells that accounted for approximately 1% of EOG's total 2007 production and approximately 2% of its total year-end 2007 proved reserves. The transaction closed on February 20, 2008. EOG retained certain of its undeveloped acreage in this area, including rights in the Marcellus Shale, and will continue its shale exploration program. During 2008, EOG will continue to drill and evaluate the Marcellus Shale in Pennsylvania using horizontal drilling and completion techniques.

As December 31, 2007, EOG held approximately 3,204,000 net undeveloped acres in the United States.

As EOG begins to operate in areas where there is limited infrastructure, EOG is placing more emphasis on gathering and processing operations to support its production activities. This additional emphasis resulted in the formation of Pecan Pipeline Company (Pecan) and Pecan Pipeline (North Dakota), Inc. (Pecan North Dakota), each a wholly owned subsidiary of EOG. Pecan has installed two natural gas gathering systems in the Barnett Shale play of North Texas, and Pecan North Dakota began the installation of an associated natural gas gathering and processing system in the Bakken Shale play of North Dakota. The Texas systems total approximately 21 miles of 10 inch and 20 inch diameter lines. At year-end 2007, throughput was approximately 27 MMcfd of natural gas. Additional pipeline and processing facilities are planned for North Texas during 2008. Initial operation of the North Dakota system is expected in the first quarter of 2008 with capacity to gather and process approximately 3 MMcfd of associated natural gas from the Bakken oil wells. During 2008, an expansion of this system is planned that is expected to increase capacity to approximately 20 MMcfd of associated natural gas.

Canada. EOG conducts operations through its subsidiary, EOG Resources Canada Inc. (EOGRC), from offices in Calgary, Alberta. During 2007, EOGRC continued its successful shallow gas strategy in Western Canada, drilling a total of 731 net wells. Key producing areas are the Southeast Alberta/Southwest Saskatchewan shallow natural gas trends (including the Drumheller, Twining and Halkirk areas), the Pembina/Highvale area of Central Alberta, the Grand Prairie/Wapiti area of Northwest Alberta and the Waskada area in Southwest Manitoba. EOGRC drilled one vertical and three horizontal shale gas wells in the Horn River Basin in Northeastern British Columbia during 2007 and has plans to drill several additional horizontal shale wells in 2008. Details on this play are expected to be released during 2008. In the fourth quarter of 2007, EOGRC divested all its exploration properties in the Northwest Territories as the timeframe for an export pipeline became longer and more problematic. A royalty review was undertaken by the Alberta government, which resulted in a revamping of the royalty structure within Alberta, effective January 2009. EOGRC's analysis determined that these changes will not have a material impact on net after royalty production, largely due to the fact that the new royalty structure is favorable to lower productivity, shallow gas wells at current pricing. EOGRC's net production during 2007 averaged 224 MMcfd of natural gas and 3.5 MBbld of crude oil, condensate and natural gas liquids. EOGRC plans to drill at least 600 net wells during 2008.

At December 31, 2007, EOGRC held approximately 1,250,000 net undeveloped acres in Canada.

EOG has operations offshore Trinidad and in the United Kingdom North Sea, and is evaluating additional exploration, development and exploitation opportunities in Trinidad, the United Kingdom and other international areas.

Trinidad. In November 1992, EOG, through its subsidiary, EOG Resources Trinidad Limited (EOGRT), acquired an exploration and production license in the South East Coast Consortium (SECC) Block offshore Trinidad. EOG currently has an 80% working interest in the Block, except in the Deep Ibis prospect in which EOG's working interest decreased as a result of a farm-out agreement with BP Trinidad Tobago LLC (BP). In the SECC Block, the Kiskadee, Ibis and Parula fields have been developed and are being produced. In June 2007, EOG finalized the development drilling of the Oilbird Field. Initial production is expected in the first quarter of 2008 pending completion of the new National Gas Company of Trinidad and Tobago (NGC) gas pipeline. Effective September 1,

3

2006, the Oilbird Field Unitization Agreement was executed as the Oilbird Field straddles the SECC Block and the Modified U(b) Block. The license covering the SECC Block will expire in December 2029.

In July 1996, EOG, through its subsidiary, EOG Resources Trinidad-U(a) Block Limited, signed a production sharing contract with the Government of Trinidad and Tobago for the Modified U(a) Block. EOG holds a 100% working interest in this Block. The Osprey field, located on the Modified U(a) Block, was discovered in 1998 and commenced production in 2002.

Surplus processing and transportation capacity at the Pelican field facilities (owned and operated by a subsidiary of the other participants in the SECC Block) is being used to process and transport EOG's natural gas production from the SECC Block and all of its crude oil and condensate production from the SECC Block, Modified U(a) Block and the Modified U(b) Block. Crude oil and condensate from EOG's Trinidad operations are being sold to the Petroleum Company of Trinidad and Tobago. In 2007, EOG agreed to purchase an 80% interest in the Pelican field facilities from the subsidiaries of the other participants in the SECC Block. The transaction is expected to close in the first quarter of 2008.

In April 2002, EOG, through its subsidiary, EOG Resources Trinidad-LRL Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for the Lower Reverse "L" (LRL) Block which is adjacent to the SECC Block. EOG holds a 100% working interest in the LRL Block. In November 2004, EOG drilled the LRL #2 well which encountered approximately 130 feet of net pay. EOG continues to evaluate development options for the LRL #2 discovery.

In October 2002, EOG, through its subsidiary, EOG Resources Trinidad U(b) Block Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for the Modified U(b) Block which is also adjacent to the SECC Block. EOG, as the operator, originally held a 55% working interest in the Modified U(b) Block. In May 2007, EOG acquired the remainder of the interest in the Modified U(b) Block from Primera Oil & Gas Ltd., a Trinidadian company, and now holds a 100% working interest in the Modified U(b) Block. In August 2007, EOG drilled the U(b)-2 exploratory well on this Block, and the well was determined to be non-commercial. As noted above, effective September 1, 2006, the Oilbird Field Unitization Agreement was executed as the Oilbird Field straddles the SECC Block and the Modified U(b) Block.

In July 2005, EOG, through its subsidiary, EOG Resources Trinidad Block 4(a) Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for Block 4(a). EOG, as the operator, originally held a 90% working interest in Block 4(a). In March 2007, EOG acquired the remaining 10% working interest from Primera Block 4(a) Limited, a Trinidadian company, and now holds a 100% working interest in Block 4(a). In the first quarter of 2006, two successful wells were drilled on Block 4(a). EOG's subsidiary has obtained approval to develop the discovery and has executed a 15-year gas sales contract with NGC for the sale of approximately 100 MMcfd, gross (78 MMcfd, net to EOG, based on current pricing and operating assumptions). EOG expects to begin initial delivery under the contract in early 2010 from its first discovery on Block 4(a), subject to completion of a pipeline by NGC.

Natural gas from EOG's Trinidad operations is being sold to the NGC under the following arrangements:

During 2007, EOG executed a one-year term sheet, effective July 1, 2007, with the Petroleum Company of Trinidad and Tobago that sets forth the pricing for the sales of crude oil and condensate produced in Trinidad. The pricing terms are based on the valuation of the distillation yield of the crude oil and condensate produced less a refining margin. This term sheet replaces the pricing provisions of a previous crude oil and condensate sales contract

5

that expired on June 30, 2007 and will be incorporated into a new crude oil and condensate sales contract which is expected to be finalized during the first quarter of 2008.

In 2007, EOG's average net production from Trinidad was 252 MMcfd of natural gas and 4.1 MBbld of crude oil and condensate.

At December 31, 2007, EOG held approximately 233,000 net undeveloped acres in Trinidad.

United Kingdom. In 2002, EOG's subsidiary, EOG Resources United Kingdom Limited (EOGUK), acquired a 25% non-operating working interest in a portion of Block 49/16, located in the Southern Gas Basin of the North Sea. In August 2004, production commenced in the Valkyrie field in the Southern Gas Basin.

In 2003, EOGUK acquired a 30% non-operating working interest in a portion of Blocks 53/1 and 53/2. These Blocks are also located in the Southern Gas Basin of the North Sea. Since November 2003, three successful exploratory wells have been drilled in the Arthur field, with production commencing in January 2005.

In 2006, EOG participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f. In 2007, a successful appraisal well was drilled on this prospect. The future development of this prospect is currently being evaluated. EOG also participated in the drilling of an unsuccessful exploratory well in August 2007 on the Eos prospect located in the Southern North Sea Block 45/11c.

In 2007, EOG delivered net average production of 23 MMcfd of natural gas in the United Kingdom.

At December 31, 2007, EOG held approximately 177,000 net undeveloped acres in the United Kingdom.

Other International. 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.

Wellhead Marketing. EOG's United States and Canada wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts based on prevailing market prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. In 2007, a large majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The remaining volumes were sold under a contract at prices partially dependent on the United States Henry Hub market prices. The pricing mechanisms for these contracts in Trinidad will remain the same in 2008. In 2007, a large majority of the wellhead natural gas volumes from the United Kingdom were sold on the spot market. The remaining volumes were sold by means of forward contracts. The marketing strategy for the wellhead natural gas volumes in the United Kingdom is expected to remain the same in 2008.

Substantially all of EOG's wellhead crude oil and condensate is sold under various terms and arrangements based on prevailing market prices.

During 2007, no single purchaser accounted for 10% or more of EOG's natural gas and crude oil revenues. EOG does not believe that the loss of any single purchaser would have a material adverse effect on its financial condition or results of operations.

6

The following table sets forth certain information regarding EOG's wellhead volumes of and average prices for natural gas per thousand cubic feet (Mcf), crude oil and condensate per barrel (Bbl) and natural gas liquids per Bbl. The table also presents natural gas equivalent volumes on a thousand cubic feet equivalent basis (Mcfe - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil, condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 2007.

(1) Million cubic feet equivalent per day; includes natural gas, crude oil, condensate and natural gas liquids.
(2) Dollars per thousand cubic feet or per barrel, as applicable.

7

United States Regulation of Natural Gas and Crude Oil Production. Natural gas and crude oil production operations are subject to various types of regulation, including regulation in the United States by state and federal agencies.

United States legislation affecting the oil and gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and liquid hydrocarbon resources through proration and restrictions on flaring, require drilling bonds and regulate environmental and safety matters.

A substantial portion of EOG's oil and gas leases in Utah, New Mexico, Wyoming and the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (BLM) and the Minerals Management Service (MMS), both federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous statutory and regulatory restrictions. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS.

BLM and MMS leases contain relatively standardized terms requiring compliance with detailed regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act (which are subject to change by the MMS). Such offshore operations are subject to numerous regulatory requirements, including the need for prior MMS approval for exploration, development, and production plans, stringent engineering and construction specifications applicable to offshore production facilities, regulations restricting the flaring or venting of production, and regulations governing the plugging and abandonment of offshore wells and the removal of all production facilities. Under certain circumstances, the MMS may require operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect EOG's interests.

Sales of crude oil, condensate and natural gas liquids by EOG are made at unregulated market prices.

The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978 (NGPA). These statutes are administered by the Federal Energy Regulatory Commission (FERC). Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by EOG of its own production. All other sales of natural gas by EOG, such as those of natural gas purchased from third parties, remain jurisdictional sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions. Consequently, all of EOG's sales of natural gas currently may be made at market prices, subject to applicable contract provisions. EOG's jurisdictional sales, however, are subject to the future possibility of greater federal oversight, including the possibility that the FERC might prospectively impose more restrictive conditions on such sales.

EOG owns, directly or indirectly, certain natural gas pipelines that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. EOG's gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.

EOG's natural gas gathering operations also may be, or become, subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. Additional rules and legislation pertaining to these matters are considered and/or adopted from time to time. Although

8

EOG cannot predict what effect, if any, such legislation might have on its operations, the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the state legislatures, the FERC, the state regulatory commissions and the federal and state courts. EOG cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being followed by the FERC will continue indefinitely.

Environmental Regulation - United States. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, affect EOG's operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations and could cause EOG to incur remediation or other corrective action costs in connection with a release of regulated substances, including crude oil, into the environment. In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, EOG could be responsible under environmental laws and regulations for oil and gas properties in which EOG owns an interest but is not the operator. Compliance with such laws and regulations increases EOG's overall cost of business, but has not had a material adverse effect on EOG's operations or financial condition. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program in order to comply with environmental laws and regulations but, inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance. EOG also could incur costs related to the clean up of sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such sites.

EOG is aware of the increasing focus of local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change issues. EOG believes that its strategy to reduce GHG emissions throughout our operations is in the best interest of the environment and a generally good business practice. EOG will continue to review the risks to the company associated with all environmental matters, including climate change.

Canadian Regulation of Natural Gas and Crude Oil Production. The crude oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. These regulatory authorities may impose regulations on or otherwise intervene in the oil and natural gas industry with respect to prices, taxes, transportation rates, the exportation of the commodity and, possibly, expropriation or cancellation of contract rights. Such regulations may be changed from time to time in response to complaints or economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for these commodities, could increase EOG's costs and may have a material adverse impact on EOG's operations and financial condition.

It is not expected that any of these controls or regulations will affect EOG operations in a manner materially different than they would affect other oil and gas companies of similar size; however, EOG is unable to predict what additional legislation or amendments may be enacted or how such additional legislation or amendments may affect EOG's operations and financial condition.

In addition, each province has regulations that govern land tenure, royalties, production rates and other matters. The royalty regime is a significant factor in the profitability of crude oil and natural gas production. Royalties payable on production from private lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

In October 2007, the Alberta Government announced a new oil and gas royalty framework to take effect in January 2009. The new framework establishes new royalties for conventional oil, natural gas and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects. Under the new framework, the formula for conventional oil and natural gas royalties will be set by a

9

sliding rate formula, dependant on the market price and production volumes. Royalty rates for conventional oil will range from 0% to 50%. New natural gas royalty rates will range from 5% to 50%.

The implementation of the new framework is subject to certain risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to existing legislation and regulation and development of proprietary software to support the calculation and collection of royalties. In addition, certain proposed changes contemplate further public and/or industry consultation. Accordingly, there may be modifications introduced to the new framework prior to its implementation in January 2009.

Environmental Regulation - Canada. All phases of the crude oil and natural gas industry in Canada are subject to environmental regulation pursuant to a variety of Canadian federal, provincial and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances to the environment. These laws and regulations also require that facility sites and other properties associated with EOG's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and approval of environmental assessments or permit applications. These laws and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment. Compliance with such laws and regulations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations or financial condition. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program in order to comply with environmental laws and regulations, but, inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance or the effect on EOG's operations and financial condition.

Spills and releases from EOG's properties may have resulted, or may result, in soil and groundwater contamination in certain locations. Such contamination is not unusual within the crude oil and natural gas industry. Any contamination found on, under or originating from the properties may be subject to remediation requirements under Canadian laws. In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under Canadian laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, EOG could be held responsible for oil and gas properties in which EOG owns an interest but is not the operator.

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other GHGs. In response to the Kyoto Protocol, the Canadian federal government introduced the Regulatory Framework for Air Emissions (Regulatory Framework) for regulating air pollution and industrial GHG emissions by establishing mandatory emissions reduction requirements on a sector basis. Sector-specific regulations are expected to come into effect in 2010 and targets would be based on percentages rather than absolute reductions. The Regulatory Framework also proposes a credit emissions trading system. Additionally, regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG by reducing specified gas emissions relative to gross domestic product to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020 and which imposes duties to report. The accompanying regulation, the Specified Gas Emitters Regulation, which became effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets. The direct and indirect costs of these regulations may adversely affect EOG's business, results of operations and financial condition.

Other International Regulation. EOG's exploration and production operations outside the United States and Canada are subject to various types of regulations imposed by the respective governments of the countries in which EOG's operations are conducted, and may affect EOG's operations and costs within that country. EOG currently has operations in Trinidad and the United Kingdom.

10

Energy Prices. Since EOG is primarily a natural gas producer, it is more significantly impacted by changes in prices of natural gas than changes in prices of crude oil, condensate or natural gas liquids. Average United States and Canada wellhead natural gas prices have fluctuated, at times rather dramatically, during the last three years. These fluctuations resulted in a 3% decrease in the average wellhead natural gas price for production in the United States and Canada received by EOG from 2006 to 2007, a decrease of 15% from 2005 to 2006, and an increase of 37% from 2004 to 2005. In 2007, a large majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The remaining volumes were sold under a contract at prices partially dependent on the United States Henry Hub market prices. The pricing mechanisms for these contracts in Trinidad will remain the same in 2008. In 2007, a large majority of the wellhead natural gas volumes from the United Kingdom were sold on the spot market. The remaining volumes were sold by means of forward contracts. The marketing strategy for the wellhead natural gas volumes in the United Kingdom is expected to remain the same in 2008. Crude oil and condensate prices also have fluctuated during the last three years. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, EOG is unable to predict what changes may occur in natural gas, crude oil and condensate, natural gas liquids, ammonia and methanol prices in the future. For additional discussion regarding changes in natural gas and crude oil prices and the risks that such changes may present to EOG, see ITEM1A. Risk Factors.

Including the impact of EOG's 2008 natural gas and crude oil hedges, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2008 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $20 million for net income and operating cash flow. EOG's price sensitivity in 2008 for each $1.00 per barrel change in wellhead crude oil price, combined with the related change in natural gas liquids prices, is approximately $10 million for net income and operating cash flow. For information regarding EOG's natural gas and crude oil hedge position as of December 31, 2007, see Note 11 to Consolidated Financial Statements.

Risk Management. 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. Under Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137, 138 and 149, these physical commodity contracts qualify for the normal purchases and normal sales exception and therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices. For a summary of EOG's financial commodity derivative contracts, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Derivative Transactions.

All of EOG's natural gas and crude oil activities are subject to the risks normally incident to the exploration for and development and production of natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and/or property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions. EOG's activities are also subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, insurance is maintained by EOG against some, but not all, of the risks. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance.

EOG's operations outside of the United States are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and currency exchange and repatriation losses, as well as changes in laws, regulations and policies governing operations of foreign companies. Please refer to Item 1A. Risk Factors for further discussion of the risks to which EOG is subject.

Texas Severance Tax Rate Reduction. Natural gas production from qualifying Texas wells spudded or completed after August 31, 1996, is entitled to a reduced severance tax rate for the first 120 consecutive months of

11

production. However, the cumulative value of the tax reduction cannot exceed 50 percent of the drilling and completion costs incurred on a well-by-well basis. For the impact on EOG, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Operating and Other Expenses.

The current executive officers of EOG and their names and ages (as of February 28, 2008) are as follows:

Mark G. Papa was elected Chairman of the Board and Chief Executive Officer of EOG in August 1999, President and Chief Executive Officer and Director in September 1998, President and Chief Operating Officer in September 1997, and President in December 1996, and was President-North America Operations from February 1994 to December 1996. Mr. Papa joined Belco Petroleum Corporation, a predecessor of EOG, in 1981. Mr. Papa is currently a director of Oil States International, Inc., an oilfield service company. Mr. Papa is EOG's principal executive officer.

Loren M. Leiker was elected Senior Executive Vice President, Exploration in February 2007. He was elected Executive Vice President, Exploration in May 1998 and was subsequently named Executive Vice President, Exploration and Development in January 2000. He was previously Senior Vice President, Exploration. Mr. Leiker joined EOG in April 1989.

Gary L. Thomas was elected Senior Executive Vice President, Operations in February 2007. He was elected Executive Vice President, North America Operations in May 1998 and was subsequently named Executive Vice President, Operations in May 2002. He was previously Senior Vice President and General Manager of EOG's Midland, Texas office. Mr. Thomas joined a predecessor of EOG in July 1978.

Robert K. Garrison was elected Executive Vice President, Exploration in February 2007. He was elected Senior Vice President and General Manager of EOG's Corpus Christi, Texas office in August 2004 and, prior to such election, was Vice President and General Manger of EOG's Corpus Christi, Texas office. Mr. Garrison joined EOG in April 1995.

Frederick J. Plaeger, II joined EOG as Senior Vice President and General Counsel in April 2007. He served as Vice President and General Counsel of Burlington Resources Inc., an independent oil and natural gas exploration and production company, from June 1998 until its acquisition by ConocoPhillips in March 2006. Mr. Plaeger engaged exclusively in leadership roles in professional legal associations from April 2006 until April 2007.

Timothy K. Driggers was elected Vice President and Chief Financial Officer in July 2007. He was elected Vice President and Controller of EOG in October 1999 and was subsequently named Vice President, Accounting and Land Administration in October 2000 and Vice President and Chief Accounting Officer in August 2003. Mr. Driggers is EOG's principal financial and accounting officer. Mr. Driggers joined EOG in October 1999.

12

ITEM 1A. Risk Factors

Our business and operations are subject to many risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could be materially and adversely affected and the trading price of our common stock could decline. The following risk factors should be read in conjunction with the other information contained in this report, including the consolidated financial statements and the related notes.

Prices for natural gas and crude oil fluctuate widely. Since we are primarily a natural gas company, we are more significantly affected by changes in natural gas prices than changes in the prices for crude oil, condensate or natural gas liquids. Among the factors that can cause these price fluctuations are:

• the level of consumer demand;

• weather conditions;

• domestic drilling activity;

• the price and availability of alternative fuels, including liquefied natural gas;

• the proximity to, and capacity of, transportation facilities;

• worldwide economic and political conditions;

• the effect of worldwide energy conservation measures; and

• the natural and extent of governmental regulation and taxation, including environmental regulations.

Our cash flow and earnings depend to a great extent on the prevailing prices for natural gas and crude oil. Prolonged or substantial declines in these commodity prices may materially and adversely affect our liquidity, the amount of cash flow we have available for capital expenditures, our ability to maintain our credit quality and access to the credit and capital markets and our results of operations.

The sale of our crude oil and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Moreover, we deliver crude oil and natural gas through gathering systems and pipelines that we do not own, and these facilities may be temporarily unavailable due to market conditions or mechanical reasons, or may not be available to us in the future. Any significant change in market factors affecting these facilities, the availability of these facilities or our failure or inability to obtain access to these facilities on terms acceptable to us or at all could materially and adversely affect our business and, in turn, our financial condition and results of operations.

Demand for natural gas and crude oil is, to a significant degree, dependent on weather and climate, which impacts the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by extreme weather conditions, such as hurricanes in the Gulf of Mexico, and sea level changes associated with climate change, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the installation of new facilities. Such extreme weather conditions and changes associated with climate change could materially and adversely affect our business and, in turn, our financial condition and results of operations.

Estimating quantities of proved natural gas and crude oil reserves and future net cash flows from such reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions or changes in conditions could cause the reported quantities of our reserves and future net cash flows from such reserves to be overstated or understated.

13

To prepare estimates of economically recoverable natural gas and crude oil reserves and future net cash flows from our reserves, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs. Our actual proved reserves and future net cash flows from such reserves most likely will vary from our estimates. Any significant variance could reduce our estimated quantities and present value of reserves, which could, in turn, materially and adversely affect our business, financial condition and results of operations and the trading price of our common stock.

The rate of production from crude oil and natural gas properties generally declines as reserves are depleted. Except to the extent that we conduct successful exploration and development activities, acquire additional properties containing proved reserves, or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. Our future natural gas and crude oil production, specifically maintaining our production at, or increasing our production from, current levels, is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.

Drilling natural gas and crude oil wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive natural gas and crude oil reservoirs. As a result, we may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents, among other factors, may cause our drilling activities to be unsuccessful and result in a partial or total loss of our investment. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, as our drilling operations may be curtailed, delayed or canceled, and the cost of such operations may increase, as a result of a variety of factors, including:

• unexpected drilling conditions;

• title problems;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions;

• compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities;

• costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment;

• lack of infrastructure; and

• lack of trained drilling personnel.

Our exploration, production and marketing operations are regulated extensively at the federal, state and local levels, as well as by the governments and regulatory agencies in foreign countries in which we do business. We have incurred and will continue to incur costs in our efforts to comply with the requirements of environmental and other regulations. Further, the regulatory environment in the natural gas and crude oil industry could change in ways that we cannot predict and that might substantially increase our costs of compliance.

As an owner or lessee and operator of natural gas and crude oil properties, we are subject to various federal, state, local and foreign regulations relating to discharge of materials into, and protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution cleanup resulting from operations, subject us to liability for pollution damages, and require suspension or cessation of operations in affected areas. Changes in, or additions to, regulations regarding the protection of the environment could materially and adversely affect our business, financial condition and results of operations.

14

EOG is aware of the increasing focus of national and international regulatory bodies on GHG emissions and climate change issues. We are also aware of legislation, recently proposed by the Canadian legislature, to reduce GHG emissions. Additionally, proposed United States policy, legislation or regulatory actions may also address GHG emissions. EOG will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary.

The exploration for, and production of, natural gas and crude oil can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, injure or kill people, and damage property and the environment. Moreover, our offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. The occurrence of any of these events and any costs or liabilities incurred as a result of such events would reduce the funds available to us for exploration, drilling and production and could, in turn, have a material adverse effect on our business, financial condition and results of operations.

From time to time, we use derivative instruments (primarily collars and price swaps) to hedge the impact of market fluctuations of natural gas and crude oil prices on our net income and cash flow. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges. In addition, we are subject to risks associated with differences in prices at different locations, particularly where transportation constraints restrict our ability to deliver natural gas and crude oil volumes to the delivery point to which the hedging transaction is indexed.

From time to time, we seek to acquire natural gas and crude oil properties. Although we perform reviews of properties to be acquired that we believe are consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, nor do they permit a buyer to become sufficiently familiar with the properties in order to assess fully their deficiencies and potential. Even when problems with a property are identified, we often assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements. Moreover, there are numerous uncertainties inherent in estimating quantities of proved natural gas and crude oil reserves, actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in the estimates. In addition, acquisitions may have material and adverse effects on our business and results of operations, particularly during the periods in which the operations of acquired properties are being integrated into our ongoing operations.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. The United States government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These actions could materially and adversely affect us in unpredictable ways, including the disruption of fuel supplies and markets, increased volatility in natural gas and crude oil prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, which, in turn, could materially and adversely affect our business, financial condition and results of operations.

15

We compete with major integrated and other independent oil and gas companies for acquisition of natural gas and crude oil leases, properties and reserves, equipment and labor required to explore, develop and operate those properties and the marketing of natural gas and crude oil production. Higher recent natural gas and crude oil prices have increased the costs of properties available for acquisition, and there are several companies with the financial resources to pursue acquisition opportunities.

In addition, many of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions and strong governmental relationships in countries in which we may seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for natural gas and crude oil, such as changing worldwide prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also compete with our competitors in attracting and retaining personnel, including geologists, geophysicists, engineers and other specialists.

We make, and will continue to make, substantial capital expenditures for the acquisition, development, production, exploration and abandonment of natural gas and crude oil reserves. We intend to finance our capital expenditures primarily through our cash flow from operations and commercial paper borrowings and, to a lesser extent and if and as necessary, bank borrowings and public and private equity and debt offerings.

Lower natural gas and crude oil prices, however, would reduce our cash flow. Further, if the condition of the capital markets materially declines, we might not be able to obtain financing on terms we consider acceptable. The recent credit crisis triggered by the subprime mortgage markets and corresponding reaction by lenders to risk, generally, may increase the interest rates that the lenders require us to pay. In addition, a substantial rise in interest rates would decrease our net cash flows available for reinvestment. Any of these factors could have a material and adverse effect on our business, financial condition and results of operations.

The reporting currency for our financial statements is the U.S. dollar. However, certain of our subsidiaries are located in countries other than the United States and have functional currencies other than the U.S. dollar. The assets, liabilities, revenues and expenses of certain of these foreign subsidiaries are denominated in currencies other than the U.S. dollar. To prepare our consolidated financial statements, we must translate those assets, liabilities, revenues and expenses into U.S. dollars at then-applicable exchange rates. Consequently, increases and decreases in the value of the U.S. dollar versus other currencies will affect the amount of these items in our consolidated financial statements, even if the value has not changed in the original currency. These translations could result in changes to our results of operations from period to period. For the fiscal year ended December 31, 2007, approximately 15% of our revenues related to operations of our foreign subsidiaries whose functional currency is not the U.S. dollar.

None.

Reserve Information. For estimates of EOG's net proved and proved developed reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see Supplemental Information to Consolidated Financial Statements.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates.

16

Reserve engineering is a subjective process of estimating underground accumulations of natural gas, crude oil, condensate and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. For related discussion, see ITEM 1A. Risk Factors.

In general, production from EOG's natural gas and crude oil properties declines as reserves are depleted. Except to the extent EOG acquires additional properties containing proved reserves or conducts successful exploration, exploitation and development activities, the proved reserves of EOG will decline as reserves are produced. Volumes generated from future activities of EOG are therefore highly dependent upon the level of success in finding or acquiring additional reserves and the costs incurred in so doing. EOG's estimates of reserves filed with other federal agencies agree with the information set forth in Supplemental Information to Consolidated Financial Statements. For related discussion, see ITEM 1A. Risk Factors.

Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2007. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.

Producing Well Summary. The following table reflects EOG's ownership in producing natural gas and crude oil wells located in the United States, Canada, Trinidad and the United Kingdom at December 31, 2007. Gross natural gas and crude oil wells include 2,583 with multiple completions.

17

Drilling and Acquisition Activities. During the years ended December 31, 2007, 2006 and 2005, EOG expended $3,599 million, $2,927 million and $1,838 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties, including asset retirement obligations of $31 million, $22 million and $20 million, respectively. EOG drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated:

(1) Includes the acquisition of additional interests in certain wells in which EOG previously owned an interest.

All of EOG's drilling activities are conducted on a contract basis with independent drilling contractors. EOG owns no drilling equipment.

The information required by this Item is set forth under the "Contingencies" caption in Note 7 of Notes to Consolidated Financial Statements and is incorporated by reference herein.

There were no matters submitted to a vote of security holders during the fourth quarter of 2007.

18

The following table sets forth, for the periods indicated, the high and low price per share for the common stock of EOG, as reported on the New York Stock Exchange Composite Tape, and the amount of common stock dividend declared per share.

On January 31, 2007, EOG's Board of Directors (Board) increased the quarterly cash dividend on the common stock from the previous $0.06 per share to $0.09 per share.

On February 7, 2008, the Board increased the quarterly cash dividend on the common stock from the previous $0.09 per share to $0.12 per share.

As of February 15, 2008, there were approximately 250 record holders of EOG's common stock, including individual participants in security position listings. There are an estimated 157,000 beneficial owners of EOG's common stock, including shares held in street name.

EOG currently intends to continue to pay quarterly cash dividends on its outstanding shares of common stock. However, the determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, the financial condition, funds from operations, level of exploration, exploitation and development expenditure opportunities and future business prospects of EOG.

19

The following table sets forth, for the periods indicated, EOG's share repurchase activity:

(1) The quarterly total number of shares of 13,276 consists solely of zero shares (15,558 shares for the full year 2007) that were returned to
      EOG in payment of the exercise price of employee stock options and 13,276 shares (110,895 shares for the full year 2007) that were
      withheld by or returned to EOG to satisfy tax withholding obligations that arose upon the exercise of employee stock options, stock-settled
      stock appreciation rights or the vesting of restricted stock or units.
(2) In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During 2007, EOG did not
      repurchase any shares under the Board authorized repurchase program.

20

The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that EOG specifically incorporates such information by reference into such a filing.

The performance graph shown below compares the cumulative five-year total return to stockholders on EOG's common stock as compared to the cumulative total returns on the Standard and Poor's 500 Index (S&P 500) and the Standard and Poor's 500 Oil & Gas Exploration & Production Index (S&P O&G E&P). The comparison was prepared based upon the following assumptions:

1. $100 was invested on December 31, 2002 in Common Stock of EOG, the S&P 500 and the S&P O&G E&P.
2. Dividends are reinvested.

Comparison of Five-Year Cumulative Total Returns
EOG, S&P 500 and S&P O&G E&P
(Performance Results Through December 31, 2007)

21

(In Thousands, Except Per Share Data)

(1) EOG adopted Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003.
(2) Years 2003 and 2004 restated for two-for-one stock split effective March 1, 2005.

22

EOG Resources, Inc., together with its subsidiaries (collectively 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.

Net income available to common stockholders for 2007 of $1,083 million was down 16% compared to 2006 net income available to common stockholders of $1,289 million. At December 31, 2007, EOG's total reserves were 7.7 trillion cubic feet equivalent, an increase of 944 billion cubic feet equivalent (Bcfe) from December 31, 2006.

Several important developments have occurred since January 1, 2007.

United States and Canada. 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 83% of total company production in 2007 as compared to 79% in 2006. Based on current trends, EOG expects its 2008 production profile to be similar. EOG's major producing areas are in Louisiana, New Mexico, Texas, Utah, Wyoming and western Canada.

In December 2007, EOG entered into an agreement to sell the majority of its producing shallow gas assets and surrounding acreage in the Appalachian Basin to a subsidiary of EXCO Resources, Inc., an independent oil and gas company, for approximately $395 million, subject to customary adjustments under the agreement. The Appalachian area being divested includes approximately 2,400 operated wells that accounted for approximately 1% of EOG's total 2007 production and approximately 2% of its total year-end 2007 proved reserves. The transaction closed on February 20, 2008. EOG retained certain of its undeveloped acreage in this area, including rights in the Marcellus Shale, and will continue its shale exploration program. On December 31, 2007, the book value of the assets and liabilities included in the sale were $254 million and $9 million, respectively.

International. Although EOG continues to focus on United States and Canada natural gas, EOG continues to see linkage between United States and Canada natural gas demand and Trinidad natural gas supply. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. Under the Atlantic LNG Train 4 (ALNG) contract, EOG delivered gas at the contractual rate of 30 million cubic feet per day (MMcfd), gross (12 MMcfd, net) beginning in May 2007 when the ALNG plant reached commercial status. In March 2007, EOG acquired the remaining 10% working interest from Primera Block 4(a) Limited, a Trinidadian company, and now holds a 100% working interest in Block 4(a). In July 2007, EOG executed a 15-year natural gas contract with the National Gas Company of Trinidad and Tobago (NGC) for the sale of approximately 100 MMcfd, gross (78 MMcfd, net to EOG, based on current pricing and operating assumptions). EOG expects to begin initial delivery under this contract in early 2010 from its first discovery on Block 4(a), subject to the completion of a pipeline by NGC.

In May 2007, EOG acquired the remainder of the interest in the Modified U(b) Block from Primera Oil & Gas Ltd., a Trinidadian company, and now holds a 100% working interest in the Modified U(b) Block. In August 2007, EOG drilled the U(b)-2 exploratory well on the Modified U(b) Block, and the well was determined to be non-commercial. In 2007, EOG agreed to purchase an 80% interest in the Pelican field facilities from the subsidiaries of the other participants in the South East Coast Consortium Block. The transaction is expected to close in the first quarter of 2008.

During 2007, EOG executed a one-year term sheet, effective July 1, 2007, with the Petroleum Company of Trinidad and Tobago that sets forth the pricing for the sales of crude oil and condensate produced in Trinidad. The pricing terms are based on the valuation of the distillation yield of the crude oil and condensate produced less a refining margin. This term sheet replaces the pricing provisions of a previous crude oil and condensate sales contract

23

that expired on June 30, 2007 and will be incorporated into a new crude oil and condensate sales contract which is expected to be finalized in the first quarter of 2008.

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, at the end of 2006. In 2007, a successful appraisal well was drilled on this prospect. The future development of this prospect is currently being evaluated. EOG also participated in the drilling of an unsuccessful exploratory well in August 2007 on the Eos prospect located in the Southern North Sea Block 45/11c.

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.

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. At December 31, 2007, EOG's debt-to-total capitalization ratio was 14%, up from 12% at year-end 2006. By primarily utilizing cash on hand, cash provided from its operating activities and proceeds from long-term debt borrowings, EOG funded $3.9 billion in exploration and development and other property, plant and equipment expenditures, paid down $158 million of debt, paid dividends to common and preferred stockholders of $84 million and paid $51 million for the redemption of preferred stock. As management continues to assess price forecast and demand trends for 2008, EOG believes that operations and capital expenditure activity can be largely funded by cash from operations.

For 2008, EOG's 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 EOG has one of the strongest prospect inventories in EOG's history.

On September 10, 2007, EOG completed its public offering of $600 million aggregate principal amount of 5.875% Senior Notes due 2017 (2017 Notes). Interest on the 2017 Notes is payable semi-annually on March 15 and September 15 of each year, beginning March 15, 2008. Net proceeds from the offering were approximately $595 million and were used for general corporate purposes, including repayment of outstanding commercial paper and borrowings under other uncommitted credit facilities.

On September 15, 2006, EOG filed an automatically effective shelf registration statement on Form S-3 (New Registration Statement) for the offer and sale from time to time of up to $688,237,500 of EOG's debt securities, preferred stock and/or common stock. The New Registration Statement was filed to replace EOG's then existing shelf registration statement which had been declared effective by the Securities and Exchange Commission (SEC) in October 2000 and under which EOG had sold no securities. As of December 31, 2007, and as a result of the issuance of the 2017 Notes, EOG may offer and sell up to $88,237,500 of debt securities, preferred stock and/or common stock under the New Registration Statement.

In 2007, EOG repurchased a total of 48,260 shares of its outstanding 7.195% Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 liquidation preference per share (Series B), for an aggregate purchase price, including premium and fees, of $51 million, plus accrued dividends up to the date of repurchase. EOG has included as a component of preferred stock dividends the $3 million of premium and fees associated with the repurchases. At December 31, 2007, 5,000 shares of the Series B with a book value of $5 million remained outstanding. Such remaining shares were subsequently repurchased in January 2008. See Note 3 to Consolidated Financial Statements.

24

Stock-Based Compensation. EOG adopted Statement of Financial Accounting Standards (SFAS) No. 123(R), "Share-Based Payment" effective January 1, 2006 using the modified prospective application method and accordingly has not restated any of its prior year results. See Note 6 to Consolidated Financial Statements. Stock-based compensation expense is included in the Consolidated Statements of Income and Comprehensive Income based upon job functions of employees receiving the grants. EOG compensation expense related to its stock-based compensation plans for the years ended December 31, was as follows (in millions):

25

The following review of operations for each of the three years in the period ended December 31, 2007 should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning with page F-1.

During 2007, net operating revenues increased $278 million, or 7%, to $4,191 million from $3,913 million in 2006. Total wellhead revenues, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, increased $474 million, or 13%, to $4,039 million from $3,565 million in 2006. Wellhead volume and price statistics for the years ended December 31, were as follows:

(1) Dollars per thousand cubic feet or per barrel, as applicable.
(2) Thousand barrels per day.
(3) Million cubic feet equivalent per day; 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.

26

2007 compared to 2006. Wellhead natural gas revenues for 2007 increased $248 million, or 9%, to $3,051 million from $2,803 million for 2006 due to increased natural gas deliveries ($278 million), partially offset by a lower composite average wellhead natural gas price ($30 million). The composite average wellhead natural gas price decreased to $5.69 per Mcf for 2007 from $5.74 per Mcf in 2006.

Natural gas deliveries increased 133 MMcfd, or 10%, to 1,470 MMcfd for 2007 from 1,337 MMcfd in 2006. The increase was due to higher production of 154 MMcfd in the United States, partially offset by lower production of 12 MMcfd in Trinidad, 7 MMcfd in the United Kingdom and 2 MMcfd in Canada. The increase in the United States was primarily attributable to increased production from Texas (119 MMcfd), the Rocky Mountain area (13 MMcfd), Kansas (13 MMcfd) and Mississippi (10 MMcfd). The decline in Trinidad was due to reduced 2007 deliveries to ALNG (10 MMcfd) and a decrease in contractual demand (2 MMcfd). During 2006, EOG supplied gas for use in ALNG's start-up phase. In 2007, ALNG remained 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 production in the United Kingdom was a result of production declines in both the Arthur and Valkyrie fields.

Wellhead crude oil and condensate revenues increased $153 million, or 24%, to $778 million from $625 million as compared to 2006, due to an increase in wellhead crude oil and condensate deliveries ($81 million) and a higher composite average wellhead crude oil and condensate price ($72 million). The increase in deliveries primarily reflects increased production in North Dakota. The composite average wellhead crude oil and condensate price for 2007 was $68.69 per barrel compared to $62.38 per barrel for 2006.

Natural gas liquids revenues increased $73 million, or 53%, to $210 million from $137 million as compared to 2006, due to increases in deliveries ($42 million) and the composite average price ($31 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale and South Texas areas.

During 2007, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $93 million, which included realized gains of $128 million. During 2006, EOG recognized gains on mark-to-market financial commodity derivative contracts of $334 million, which included realized gains of $215 million.

2006 compared to 2005. Wellhead natural gas revenues for 2006 decreased $136 million, or 5%, to $2,803 million from $2,939 million for 2005 due to a lower composite average wellhead natural gas price ($407 million) and a second quarter 2005 revenue adjustment related to an amended Trinidad take-or-pay contract ($19 million), partially offset by increased natural gas deliveries ($290 million). The composite average wellhead natural gas price decreased 13% to $5.74 per Mcf for 2006 from $6.62 per Mcf in 2005. The Trinidad take-or-pay contract adjustment increased the average Trinidad wellhead natural gas price by $0.23 per Mcf for 2005.

Natural gas deliveries increased 121 MMcfd, or 10%, to 1,337 MMcfd for 2006 from 1,216 MMcfd in 2005. The increase was due to higher production of 99 MMcfd in the United States and 33 MMcfd in Trinidad, partially offset by lower production of 9 MMcfd in the United Kingdom and 2 MMcfd in Canada. The increase in the United States was primarily attributable to increased production from Texas (83 MMcfd), the Rocky Mountain area (24 MMcfd) and Kansas (7 MMcfd), partially offset by decreased production in the Gulf of Mexico (16 MMcfd). The decrease in Gulf of Mexico production was partially due to continued shut-in production caused by infrastructure damage from hurricanes Katrina and Rita. The increase in Trinidad was due to the commencement of two contracts late in the fourth quarter of 2005 (43 MMcfd) and increased contractual demand (34 MMcfd), partially offset by a decrease in volumes as a result of the December 2005 completion of a cost recovery arrangement (44 MMcfd). The decrease in production in the United Kingdom was a result of production declines in both the Arthur and Valkyrie fields.

Wellhead crude oil and condensate revenues increased $54 million, or 9%, to $625 million from $571 million as compared to 2005, due to an increase in the composite average wellhead crude oil and condensate price ($78 million), partially offset by a decrease in the wellhead crude oil and condensate deliveries ($24 million). The composite average wellhead crude oil and condensate price for 2006 was $62.38 per barrel compared to $54.63 per barrel for 2005.

Natural gas liquids revenues increased $40 million, or 41%, to $137 million from $97 million as compared to 2005, due to increases in deliveries ($24 million) and the composite average price ($16 million).

27

During 2006, EOG recognized gains on mark-to-market financial commodity derivative contracts of $334 million, which included realized gains of $215 million. During 2005, EOG recognized gains on mark-to-market financial commodity derivative contracts of $10 million, which included realized gains of $10 million.

2007 compared to 2006. During 2007, operating expenses of $2,542 million were $533 million higher than the $2,009 million incurred in 2006. The following table presents the costs per Mcfe for the years ended December 31:

(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 net interest expense for 2007 as compared to 2006 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 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 $480 million in 2007 were $107 million higher than 2006 due primarily to higher operating and maintenance expenses in the United States ($62 million) and Canada ($13 million), higher lease and well administrative expenses ($18 million), higher workover expenditures in the United States ($7 million) and changes in the Canadian exchange rate ($7 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.

Transportation costs of $170 million in 2007 were $60 million higher than 2006 due primarily to increased production in the Fort Worth Basin Barnett Shale play and related costs associated with new marketing arrangements to transport the increased production 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 year to year.

28

DD&A expenses of $1,066 million in 2007 were $248 million higher than 2006 primarily due to higher unit rates described below and as a result of increased production in the United States ($122 million), partially offset by a decrease in production in the United Kingdom ($5 million). DD&A rates increased due primarily to a proportional increase in production from higher cost properties in the United States ($102 million), Canada ($17 million) and in the United Kingdom ($2 million). The exchange rates in Canada ($10 million) and in the United Kingdom ($2 million) also contributed to the DD&A expense increase.

G&A expenses of $205 million in 2007 were $40 million higher than 2006 due primarily to higher employee-related costs ($24 million), legal settlement costs ($4 million), insurance costs ($3 million) and office rent ($2 million). The increase in employee-related costs primarily reflects higher stock-based compensation expenses ($11 million).

Net interest expense of $47 million in 2007 increased $4 million compared to 2006 primarily due to a higher average debt balance ($13 million), partially offset by higher capitalized interest ($9 million).

Exploration costs of $150 million in 2007 were $5 million lower than 2006 due primarily to decreased geological and geophysical expenditures in the United States.

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 $148 million in 2007 were $39 million higher than 2006 due primarily to increased SFAS No. 144 related impairments ($27 million) and increased amortization of unproved leases in the United States ($7 million), the United Kingdom ($3 million) and Canada ($3 million). The increase in SFAS No. 144 related impairments is due to an increase in Canada ($15 million) primarily related to the Northwest Territories discovery (see Note 15 to Consolidated Financial Statements) and an increase in the United States ($12 million). Under SFAS No. 144, EOG recorded impairments of $82 million and $55 million for 2007 and 2006, 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 revenue and ad valorem/property taxes are generally determined based on the valuation of the underlying assets. Taxes other than income in 2007 increased $7 million to $208 million (5.2% of wellhead revenues) from $201 million (5.6% of wellhead revenues) in 2006.

Severance/production taxes increased primarily due to increased wellhead revenues in the United States ($27 million) and Trinidad ($2 million), partially offset by increased credits taken for Texas high cost gas severance tax rate reductions ($26 million). Ad valorem/property taxes increased primarily due to higher property valuation in Canada ($2 million).

Other income, net was $29 million in 2007 compared to $52 million in 2006. The decrease of $23 million was primarily due to lower interest income ($17 million), lower settlements received related to the Enron Corp. bankruptcy ($3 million) and lower equity income from the Nitrogen (2000) Unlimited ammonia plant ($2 million).

Income tax provision of $541 million in 2007 decreased $72 million compared to 2006 due primarily to decreased pretax income ($99 million), partially offset by higher foreign income taxes ($10 million) and increased state income taxes ($7 million). The net effective tax rate for 2007 increased to 33% from 32% in 2006.

29

2006 compared to 2005. During 2006, operating expenses of $2,009 million were $381 million higher than the $1,628 million incurred in 2005. The following table presents the costs per Mcfe for the years ended December 31:

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

The change in per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2006 as compared to 2005 were due primarily to the reasons set forth below.

Lease and well expenses of $373 million in 2006 were $86 million higher than 2005 due primarily to higher operating and maintenance expenses in the United States ($34 million) and Canada ($16 million); higher lease and well administrative expenses ($21 million), including stock-based compensation expense ($10 million); changes in the Canadian exchange rate ($6 million); and higher workover expenditures in the United States ($6 million).

Transportation costs of $110 million in 2006 were $23 million higher than 2005 due primarily to increased production in the Fort Worth Basin Barnett Shale play.

DD&A expenses of $817 million in 2006 were $163 million higher than 2005 primarily due to higher unit rates described below and as a result of increased production in the United States ($56 million) and Trinidad ($3 million), partially offset by a decrease in production in the United Kingdom ($4 million). DD&A rates increased due primarily to a gradual proportional increase in production from higher cost properties in the United States ($78 million) and Canada ($11 million), and a downward reserve revision in the United Kingdom ($11 million). The Canadian exchange rate also contributed to the DD&A expense increase ($9 million).

G&A expenses of $165 million in 2006 were $39 million higher than 2005 due primarily to higher employee-related costs ($31 million) and higher insurance costs ($4 million). The increase in employee-related costs primarily reflects higher stock-based compensation expenses ($17 million).

Net interest expense of $43 million in 2006 decreased $19 million compared to 2005 primarily due to a lower average debt balance ($9 million), costs in 2005 associated with the early retirement of the 6.00% Notes due 2008 ($8 million), and higher capitalized interest ($5 million).

Exploration costs of $155 million in 2006 were $22 million higher than 2005 due primarily to higher employee-related costs, including stock-based compensation expenses.

Impairments of $108 million in 2006 were $30 million higher than 2005 due primarily to increased SFAS No. 144 related impairments in the United States ($17 million) and Canada ($7 million) and higher amortization of unproved leases in Canada ($4 million) and the United States ($2 million). EOG recorded impairments of $55 million and $31 million for 2006 and 2005, respectively, under SFAS No. 144 for properties in the United States and Canada.

Taxes other than income of $201 million in 2006 were $2 million higher than 2005. Severance taxes in the United States decreased primarily due to increased credits taken for Texas high cost gas severance tax rate reductions ($14 million). Severance/production taxes in Trinidad increased due primarily to increased wellhead revenues from crude oil and condensate ($12 million), partially offset by changes to the tax legislation governing the Supplemental Petroleum Tax ($7 million). Ad valorem/property taxes increased primarily due to higher property valuation in the United States ($7 million) and Canada ($2 million).

30

Other income, net was $52 million in 2006 compared to $23 million in 2005. The increase of $29 million was primarily due to higher interest income ($19 million), settlements received related to the Enron Corp. bankruptcy ($4 million) and increased net foreign currency transaction gains ($3 million).

Income tax provision of $613 million in 2006 decreased $93 million compared to 2005 due primarily to a net decrease in foreign income taxes ($37 million), largely related to a Canadian federal tax rate reduction ($19 million) and an Alberta, Canada corporate tax rate reduction ($13 million), partially offset by a United Kingdom corporate tax rate increase ($7 million); reduced income taxes associated with the repatriation of foreign earnings in 2005 ($24 million); decreased pretax income ($18 million); and reduced state income taxes ($18 million), partially offset by a decrease in the Domestic Production Activities Deduction ($7 million). The effective tax rate for 2006 decreased to 32% from 36% in 2005.

The primary sources of cash for EOG during the three-year period ended December 31, 2007 were funds generated from operations, the issuance of long-term debt, proceeds from employee stock option exercises and the employee stock purchase plans, proceeds from the sale of oil and gas properties, excess tax benefits from stock-based compensation, net commercial paper, other uncommitted credit facilities and revolving credit facility borrowings. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; repayments of debt; dividend payments to stockholders; redemptions of preferred stock and debt issuance costs.

2007 compared to 2006. Net cash provided by operating activities of $2,893 million in 2007 increased $315 million compared to 2006 primarily reflecting an increase in wellhead revenues ($474 million) and a decrease in cash paid for income taxes ($157 million), partially offset by an increase in cash operating expenses ($180 million), a decrease in the net cash flows from settlement of financial commodity derivative contracts ($87 million) and unfavorable changes in working capital and other assets and liabilities ($55 million).

Net cash used in investing activities of $3,456 million in 2007 increased by $745 million compared to 2006 due primarily to increased additions to oil and gas properties and other property, plant and equipment.

Net cash provided by financing activities was $394 million in 2007 compared to net cash used in financing activities of $299 million in 2006. Cash provided by financing activities for 2007 included the issuance of long-term debt ($600 million), proceeds from employee stock option exercises and employee stock purchase plans ($55 million), excess tax benefits from stock-based compensation ($27 million) and Trinidad revolving credit facility borrowings ($10 million). Cash used by financing activities for 2007 included repayments of long-term borrowings ($158 million), cash dividend payments ($84 million), redemptions of preferred stock ($51 million) and debt issuance costs ($5 million).

2006 compared to 2005. Net cash provided by operating activities of $2,579 million in 2006 increased $209 million compared to 2005 primarily reflecting a favorable change in the net cash flows from settlement of financial commodity derivative contracts ($205 million), favorable changes in working capital and other liabilities ($162 million) and a decrease in cash paid for income taxes and interest expense ($54 million), partially offset by an increase in cash operating expenses ($173 million) and a decrease in wellhead revenues ($42 million).

Net cash used in investing activities of $2,710 million in 2006 increased by $1,032 million compared to 2005 due primarily to increased additions to oil and gas properties ($1,094 million) and decreased proceeds from sales of oil and gas properties ($51 million), partially offset by favorable changes in working capital related to investing activities ($125 million). Changes in Components of Working Capital Associated with Investing Activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent material and equipment used in drilling and related activities.

Cash used in financing activities of $299 million in 2006 increased $227 million compared to 2005. Cash used by financing activities for 2006 included repayments of long-term debt borrowings ($317 million), cash dividend payments ($60 million) and redemption of preferred stock, including premium paid ($50 million). Cash provided by financing activities for 2006 included borrowing under a revolving credit facility ($65 million),

31

proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan ($36 million) and excess tax benefits from stock-based compensation expenses ($28 million).

The table below sets out components of total expenditures for the years ended December 31, 2007, 2006 and 2005, along with the total budgeted for 2008, excluding acquisitions (in millions):

Exploration and development expenditures of $3,568 million for 2007 were $663 million higher than the prior year due primarily to increased drilling and facilities expenditures of $573 million resulting from higher drilling and facilities expenditures in the United States ($648 million); increased lease acquisitions in the United States ($57 million); increased dry hole costs in the United States ($19 million), Trinidad ($9 million) and the United Kingdom ($7 million); changes in the Canadian exchange rate ($18 million); and increased capitalized interest in the United States ($8 million). These increases were partially offset by lower drilling and facilities expenditures in Canada ($70 million), the United Kingdom ($12 million) and Trinidad ($7 million); decreased geological and geophysical expenditures in the United States ($7 million); and decreased lease acquisitions in the United Kingdom ($6 million). The 2007 exploration and development expenditures of $3,568 million includes $2,681 million in development, $838 million in exploration, $29 million in capitalized interest and $20 million in property acquisitions. The increase in expenditures for other property, plant and equipment primarily related to gathering systems and processing plants in the Fort Worth Basin Barnett Shale and Rocky Mountain areas. The 2006 exploration and development expenditures of $2,905 million includes $2,159 million in development, $704 million in exploration, $22 million in property acquisitions and $20 million in capitalized interest. The 2005 exploration and development expenditures of $1,818 million includes $1,260 million in development, $487 million in exploration, $56 million in property acquisitions and $15 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to 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.

During 2007, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $93 million, which included realized gains of $128 million. During 2006, EOG recognized gains on mark-to-market financial commodity derivative contracts of $334 million, which included realized gains of $215 million. See Note 11 to Consolidated Financial Statements.

32

Presented below is a comprehensive summary of EOG's 2008 and 2009 natural gas and crude oil financial price swap contracts at February 27, 2008, with notional volumes 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.