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 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, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):  Large Accelerated Filer x Accelerated Filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No x

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 February 16, 2007 and 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 February 16, 2007: $16,347,875,983 and as of June 30, 2006: $16,818,631,746.

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, on February 16, 2007, Shares Outstanding: 243,998,149.

Documents incorporated by reference. Portions of the following document are incorporated by reference into the indicated parts of this report: Proxy Statement for the April 24, 2007 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2006 (Proxy Statement) - Part III.

(i)

EOG Resources, Inc. (EOG), a Delaware corporation organized in 1985, together with its subsidiaries, 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 all 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, 2006, EOG's total estimated net proved reserves were 6,802 billion cubic feet equivalent (Bcfe), of which 6,095 billion cubic feet (Bcf) were natural gas reserves and 118 million barrels (MMBbl), or 707 Bcfe, were crude oil, condensate and natural gas liquids reserves (see "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 60% of EOG's reserves (on a natural gas equivalent basis) were located in the United States, 20% in Canada and 20% in Trinidad. As of December 31, 2006, EOG employed approximately 1,570 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, 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 tactical acquisitions that result in additional economies of scale or land positions with 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, 2006, 88% of EOG's net proved United States and Canada reserves (on a natural gas equivalent basis) were natural gas and 12% 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 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 2006 and certain 2007 plans for EOG's United States and Canada operations.

United States. During 2006, EOG substantially increased drilling activity, acreage position, reserve potential and production in the Fort Worth Basin Barnett Shale play (Fort Worth Barnett). The net average production from the Fort Worth Barnett for 2006 was 145 million cubic feet per day (MMcfd) of natural gas and 300 barrels per day (Bbld)

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of crude oil, condensate and natural gas liquids. EOG drilled 205 net Fort Worth Barnett wells during 2006 and grew production to over 200 MMcfd, net by year-end 2006. During the year, EOG leased more than 100,000 additional net acres and increased EOG's total leasehold to greater than 600,000 net acres. EOG will substantially increase drilling activity in the Forth Worth Barnett during 2007 with plans to drill approximately 380 gross wells and exit the year with over 300 MMcfd net production. EOG continues to generate new opportunities in the Fort Worth Barnett which EOG expects will add significant future reserve and production potential.

The Upper Gulf Coast continued to be a growth area for EOG where 2006 net production averaged 117 MMcfd of natural gas and 3.5 thousand barrels per day (MBbld) of crude oil, condensate and natural gas liquids. EOG drilled 60 net wells with 30 net wells in the Cotton Valley and Travis Peak development programs at the Sligo, Minden, Carthage and Appleby Fields. North Louisiana development activity included five net wells at Driscoll Mountain in the expanded Cotton Valley and 10 horizontal producers in Spider Field. EOG continues its growth in Mississippi where 13 successful net wells were drilled in 2006 in the Hosston play in South Williamsburg. EOG is currently one of the largest natural gas producers in Mississippi. EOG will continue its growth in East Texas, Louisiana and Mississippi with tests of several high potential impact new projects in 2007.

In the Permian Basin, EOG drilled 30 net horizontal gas wells in 2006 in the New Mexico Wolfcamp play. EOG has over 40,000 net acres in the play and plans to drill approximately 33 net wells in 2007. EOG has identified approximately 100 drilling locations in this play. Significant drilling and completion improvements have resulted in cost reductions, as well as quick spud-to-sales cycle times for these wells. This activity was complemented by a number of successful wells in the Permo-Penn Carbonate, Bone Spring Carbonate and Horizontal Bone Spring. EOG drilled 61 net wells in 2006, and net production averaged 87 MMcfd of natural gas and 7.1 MBbld of crude oil, condensate and natural gas liquids. Several additional horizontal plays, which could set up multiple drilling locations, will be tested in 2007 on over 20,000 acres controlled by EOG.

EOG increased drilling activity within its core areas of the Rocky Mountain area, drilling 179 net wells during 2006, including 84 net wells in the Uinta Basin, Utah, 40 net wells in the LaBarge Platform, Wyoming, 34 net wells in the Moxa Arch area, Wyoming, and seven net wells in the Williston Basin. The net average daily production for 2006 from the Rocky Mountain area was 165 MMcfd of natural gas and 8.6 MBbld of crude oil, condensate and natural gas liquids. EOG expects to continue increasing drilling activity in these core areas during 2007, while maintaining an active exploration and delineation program in other areas in Utah, Wyoming and North Dakota.

In the Mid-Continent area, EOG drilled 117 net wells in its core areas in 2006, most notably the Hugoton-Deep play in the Oklahoma Panhandle and the Cleveland Horizontal play in the Texas Panhandle. The net average production for 2006 was 74 MMcfd of natural gas and 2.4 MBbld of crude oil and condensate. In the Hugoton-Deep play, EOG shifted its prospecting into Southwest Kansas and was successful in finding several new Morrow plays. Net production from this area increased from 25 MMcfd in the beginning of 2006 to over 50 MMcfd by year-end. Nine years remain on the 900,000 acre, 10-year joint venture with Anadarko Petroleum Company. In the Cleveland Horizontal play, EOG drilled 28 net wells in 2006, bringing its total to 125 net wells drilled since 2003. EOG plans to continue exploiting these two core growth areas in 2007, while pursuing other exploration prospects throughout the Mid-Continent area.

EOG had another successful year in South Texas, drilling 84 net wells in 2006. South Texas onshore net production averaged 185 MMcfd of natural gas and 6.3 MBbld of crude oil, condensate and natural gas liquids during 2006. 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 has resulted in new opportunities for this mature play. EOG added significant lease positions and 3-D seismic in 2006 to sustain a long-term drilling program.

During 2006, EOG participated in two discoveries in the Gulf of Mexico. In the High Island area, one well is producing and another well is expected to be on sales during the first quarter of 2007. A development well is currently being drilled in High Island Block 130 and is expected to be completed by March 2007. Net production from these three wells is expected to be 10 MMcfd by mid-2007. Drilling and completion operations for a deepwater project are underway, and first production is projected for early 2008. At least two additional exploratory projects are planned for the Gulf of Mexico in 2007.

In 2006, EOG drilled 68 net wells in the Appalachian Basin. Net production averaged 19 MMcfd of natural gas and 60 Bbld of crude oil and condensate. EOG is planning a similar drilling program in 2007. The majority of the wells will be drilled in the shallow Devonian and 10 net wells are planned for the Marcellus Shale. The Marcellus wells will be drilled in Pennsylvania to evaluate EOG's acreage in the joint venture with Seneca Resources Corporation.

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At December 31, 2006, EOG held approximately 3,184,000 net undeveloped acres in the United States.

Canada. In Canada, EOG conducts operations through its subsidiary, EOG Resources Canada Inc. (EOGRC), from offices in Calgary, Alberta. During 2006, EOGRC continued its successful shallow gas strategy in Western Canada, drilling a total of 1,330 net wells. The 2006 shallow natural gas drilling program included 128 net Horseshoe Canyon coalbed methane wells. EOGRC participated in two exploratory wells in the Northwest Territories in 2006, resulting in a new pool discovery and a confirmation of an existing discovery made in 2004. EOGRC's net production during 2006 averaged 226 MMcfd of natural gas and 3.3 MBbld of crude oil, condensate and natural gas liquids. 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 plans to drill approximately 1,000 net wells in these areas during 2007.

At December 31, 2006, EOGRC held approximately 1,568,000 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 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). The SECC Deep Ibis well spudded in April 2006, was drilled to a depth of approximately 19,000 feet and was abandoned and classified as a dry hole in the third quarter of 2006. BP paid the entire cost for drilling the exploratory well. The Kiskadee, Ibis and Parula fields have been developed and are being produced. In 2006, EOG continued the development of the Oilbird field and expects initial production in the second quarter of 2007. Effective September 1, 2006, the Oilbird Field Unitization Agreement was executed as the Oilbird field straddles the SECC Block and the 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 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 both the SECC and Modified U(a) Blocks. Crude oil and condensate from EOG's Trinidad operations are being sold to the Petroleum Company of Trinidad and Tobago.

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 the fourth quarter of 2003, EOG drilled the first exploratory well, LRL #1, on this block. The well was determined to be non-commercial. In November 2004, EOG drilled the LRL #2 well which encountered approximately 130 feet of net pay. EOG is currently evaluating development options for the LRL #2 discovery. In December 2004, the LRL #3 exploratory well was drilled and determined to be a dry hole.

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 holds a 55% working interest in and operates the Modified U(b) Block. Primera Oil & Gas Ltd., a Trinidadian company, holds the remaining 45% working interest. In September 2004, EOG drilled the first exploratory well on this block, and the well was determined to be non-commercial. Effective September 1, 2006, the Oilbird Field Unitization Agreement was executed as the Oilbird field straddles the SECC Block and the U(b) Block.

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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, holds a 90% working interest in Block 4(a). Primera Block 4(a) Limited, a Trinidadian company, holds the remaining 10% working interest. 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 term sheet with the National Gas Company of Trinidad and Tobago (NGC) for the sale of the gas.

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

In 2006, EOG's average net production from Trinidad was 264 MMcfd of natural gas and 4.8 MBbld of crude oil and condensate.

At December 31, 2006, EOG held approximately 209,000 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.

During the fourth quarter of 2006, EOG participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f. The Columbus well was a farm-in opportunity and its future appraisal and development is currently being evaluated.

In 2006, EOG delivered net average production of 30 MMcfd of natural gas in the United Kingdom.

At December 31, 2006, EOG held approximately 352,000 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 at market-responsive prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. In 2006, 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 2007. In 2006, 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 2007.

Substantially all of EOG's wellhead crude oil and condensate is sold under various terms and arrangements at market-responsive prices.

During 2006, sales to a major integrated oil and gas company with investment grade credit ratings accounted for 11% of EOG's oil and gas revenues. No other individual purchaser accounted for 10% or more of EOG's oil and gas revenues for the same period. EOG does not believe that the loss of any single purchaser will have a material adverse effect on its financial condition or results of operations.

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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, 2006.

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Million cubic feet equivalent per day, includes natural gas, crude oil, condensate and natural gas liquids.
(3) Dollars per thousand cubic feet or per barrel, as applicable.
(4) Includes $0.23 per Mcf as a result of a revenue adjustment related to an amended Trinidad take-or-pay contract.

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EOG competes for reserve acquisitions and exploration/exploitation leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent EOG's exploration budget is lower than that of certain of its competitors, EOG may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms and quality of service, including pipeline connection times and distribution efficiencies. In addition, EOG faces competition from other worldwide energy supplies, such as liquefied natural gas imported into the United States from other countries. Please refer to ITEM 1A. Risk Factors beginning on page 13.

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, 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 facilities. Additional rules and legislation pertaining to these matters are considered and/or adopted from time to time. Although 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.

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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 gaseous emissions and climate change. EOG believes that its strategy, to reduce 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 global warming/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, increase EOG's costs and may have a material adverse impact on its operations.

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. EOG is unable to predict what additional legislation or amendments may be enacted.

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.

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. While compliance with such

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legislation can require significant expenditures, failure to comply with these environmental laws and regulations could result in the assessment of administrative, civil or criminal penalties, suspension or revocation of licenses and, in some instances, the issuance of injunctions to limit or cease operations.

Spills and releases from EOG's properties may have resulted or 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. 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.

In December 2002, the Canadian federal government ratified the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which requires Canada to reduce its greenhouse gas emissions to 6% below 1990 levels over the 2008-2012 periods. The Climate Change Plan for Canada, which was released in November 2002, outlined, in very general terms, the approach the Canadian government intended to take to implement its emissions reduction commitment. The Canadian government issued a further climate change plan, Moving Forward on Climate Change: A Plan for Honouring our Kyoto Commitment, in April of 2005. With the change in government at the federal level since the issuance of the 2005 plan, it is unclear how Canada intends to meet its Kyoto Protocol obligations. The final rules, once known, could affect operations and profitability.

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.

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 12% increase in the average wellhead natural gas price for production in the United States and Canada received by EOG from 2003 to 2004, an increase of 37% from 2004 to 2005, and a decrease of 15% from 2005 to 2006. In 2006, 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 2007. In 2006, 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 2007. 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, ammonia and methanol prices in the future.

Assuming a totally unhedged position for 2007, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2007 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 $27 million for net income and operating cash flow. EOG's price sensitivity in 2007 for each $1.00 per barrel change in wellhead crude oil price is approximately $6 million for net income and operating cash flow. Summarized below and in Note 11 to Consolidated Financial Statements is information regarding EOG's current 2007 natural gas and crude oil hedge position.

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 tomanage 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

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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 - 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 beginning on page 13 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 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 - Taxes Other Than Income Taxes.

Common Stock Rights Agreement. On February 14, 2000, EOG's Board of Directors (Board) declared a dividend of one preferred share purchase right (a Right, and the agreement governing the terms of such Rights, the Rights Agreement) for each outstanding share of common stock, par value $0.01 per share. The Board has adopted this Rights Agreement to protect shareholders from coercive or otherwise unfair takeover tactics. The dividend was distributed to the shareholders of record on February 24, 2000. In accordance with the Rights Agreement, each share of common stock issued in connection with the two-for-one stock split effective March 1, 2005, also had one Right associated with it. Each Right, expiring February 24, 2010, represents a right to buy from EOG one hundredth (1/100) of a share of Series E Junior Participating Preferred Stock (Series E) for $90, once the Rights become exercisable. This portion of a Series E share will give the shareholder approximately the same dividend, voting, and liquidation rights as would one share of common stock. Prior to exercise, the Right does not give its holder any dividend, voting, or liquidation rights. If issued, each one hundredth (1/100) of a Series E share (i) will not be redeemable; (ii) will entitle holders to quarterly dividend payments of $0.01 per share, or an amount equal to the dividend paid on one share of common stock, whichever is greater; (iii) will entitle holders upon liquidation either to receive $1 per share or an amount equal to the payment made on one share of common stock, whichever is greater; (iv) will have the same voting power as one share of common stock; and (v) if shares of EOG's common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock.

The Rights will not be exercisable until ten days after a public announcement that a person or group has become an acquiring person (Acquiring Person) by obtaining beneficial ownership of 10% or more of EOG's common stock, or if earlier, ten business days (or a later date determined by EOG's Board before any person or group becomes an Acquiring Person) after a person or group begins a tender or exchange offer which, if consummated, would result in that person or group becoming an Acquiring Person. On February 24, 2005, the Rights Agreement was amended to create an exception to the definition of Acquiring Person to permit a qualified institutional investor to hold 10% or more, but less than 20%, of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the following requirements: (i) the institutional investor is described in Rule 13d-1(b)(1) promulgated under the Securities Exchange Act of 1934 and is eligible to report (and, if such institutional investor is the beneficial owner of greater than 5% of EOG's common stock, does in fact report) beneficial ownership of common stock on Schedule 13G; (ii) the institutional investor is not required to file a Schedule 13D (or any successor or comparable report) with respect to its beneficial ownership of EOG's common stock; (iii) the institutional investor does not beneficially own 15% or more of EOG's common stock (including in such calculation the holdings of all of the institutional investor's affiliates and associates other than those which, under published interpretations of the United States Securities and Exchange Commission or its staff, are eligible to file separate reports on Schedule 13G with respect to their beneficial ownership of EOG's common stock); and (iv) the institutional investor does not beneficially own 20% or more of EOG's common stock (including in such calculation the holdings of all of the

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institutional investor's affiliates and associates). On June 15, 2005, the Rights Agreement was amended again to revise the exception to the definition of Acquiring Person to permit a qualified institutional investor to hold 10% or more but less than 30% of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the other requirements of the definition of qualified institutional investor described in the amendment.

If a person or group becomes an Acquiring Person, all holders of Rights, except the Acquiring Person may, for $90, purchase shares of EOG's common stock with a market value of $180 based on the market price of the common stock prior to such acquisition. If EOG is later acquired in a merger or similar transaction after the Rights become exercisable, all holders of Rights except the Acquiring Person may, for $90, purchase shares of the acquiring corporation with a market value of $180 based on the market price of the acquiring corporation's stock prior to such merger.

EOG's Board may redeem the Rights for $0.005 per Right at any time before any person or group becomes an Acquiring Person. If the Board redeems any Rights, it must redeem all of the Rights. Once the Rights are redeemed, the only right of the holders of Rights will be to receive the redemption price of $0.005 per Right. The redemption price has been adjusted for the two-for-one stock split effective March 1, 2005 and will be adjusted for any future stock split or stock dividends of EOG's common stock. After a person or group becomes an Acquiring Person, but before an Acquiring Person owns 50% or more of EOG's outstanding common stock, the Board may exchange the Rights for common stock or equivalent security at an exchange ratio of one share of common stock or an equivalent security for each such Right, other than Rights held by the Acquiring Person.

Preferred Stock. EOG currently has two authorized series of preferred stock. On February 14, 2000, EOG's Board, in connection with the Rights Agreement described above, authorized 1,500,000 shares of the Series E with the rights and preferences described above. On February 24, 2005, EOG's Board increased the authorized shares of Series E to 3,000,000 as a result of the two-for-one stock split of EOG's common stock effective March 1, 2005. Currently, there are no shares of the Series E outstanding.

On July 19, 2000, EOG's Board authorized 100,000 shares of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 Liquidation Preference per share (Series B). Dividends are payable on the shares only if declared by EOG's Board and will be cumulative. If declared, dividends will be payable at a rate of $71.95 per share, per year on March 15, June 15, September 15 and December 15 of each year beginning September 15, 2000. EOG may redeem all or part of the Series B at any time beginning on December 15, 2009 at $1,000 per share, plus accrued and unpaid dividends. The Series B is not convertible into, or exchangeable for, common stock of EOG. On October 11, 2006, EOG commenced a cash tender offer to purchase any and all of the 100,000 outstanding shares of the Series B at a price of $1,074.01 per share plus accrued and unpaid dividends up to the date of purchase. The tender offer expired on November 8, 2006, and on November 10, 2006, EOG redeemed 46,740 shares of the Series B for an aggregate purchase price, including redemption premium, fees and dividends, of $51 million. EOG has included as a component of preferred dividends the $4 million of premium and fees associated with the redemption of the Series B shares. A total of 53,260 shares of the Series B remain outstanding at December 31, 2006.

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The current executive officers of EOG and their names and ages 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, President in December 1996 and was President-North America Operations from February 1994 to September 1998. Mr. Papa joined Belco Petroleum Corporation, a predecessor of EOG, in 1981. Mr. Papa is EOG's principal executive officer.

Loren M. Leiker was elected Senior Executive Vice President, Exploration on February 26, 2007.  He was elected Executive Vice President, Exploration in May 1998 and was subsequently named Executive Vice President, Exploration and Development. He was previously Senior Vice President, Exploration. Mr. Leiker joined EOG in April 1989 as International Exploration Manager.

Edmund P. Segner, III was elected Senior Executive Vice President and Chief of Staff on February 26, 2007.  He was elected  President and Chief of Staff and Director of EOG in August 1999. He was elected Vice Chairman and Chief of Staff of EOG in September 1997. He was a director of EOG from January 1997 to October 1997. Mr. Segner is EOG's principal financial officer.

Gary L. Thomas was elected Senior Executive Vice President, Operations on February 26, 2007.  He was elected Executive Vice President, North America Operations in May 1998 and was subsequently named Executive Vice President, Operations. He was previously Senior Vice President and General Manager in Midland. Mr. Thomas joined a predecessor of EOG in July 1978.

Robert K. Garrison was elected Executive Vice President, Exploration on February 26, 2007.  He previously was elected Senior Vice President and General Manager in Corpus Christi in August 2004.  Prior to that he was Vice President and General Manager in Corpus Christi.

Barry Hunsaker, Jr. has been Senior Vice President and General Counsel since he joined EOG in May 1996.

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

There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are appointed or elected annually by the Board of Directors at its meeting immediately prior to the Annual Meeting of Shareholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been duly elected or appointed and shall have qualified.

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ITEM 1A. Risk Factors

Our business faces many risks. The risks described below may not be the only risks we face. Additional risks that we do not yet know of, or that we currently think are immaterial, may also impair our business operations or financial results. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer 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 nature and extent of governmental regulation and taxation.

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 adversely affect our liquidity, the amount of cash flow we have available for capital expenditures and our ability to maintain our credit quality and access to the credit and capital markets.

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. Any significant change in market factors affecting these infrastructure facilities or our failure to obtain these services on acceptable terms could materially harm our business. We deliver crude oil and natural gas through gathering systems and pipelines that we do not own. These facilities may be temporarily unavailable due to market conditions or mechanical reasons, or may not be available to us in the future.

Demand for natural gas and 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 severe weather, such as hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment.

Estimating quantities of proved crude oil and natural gas 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 of conditions could cause the quantities of our reserves to be overstated or understated.

To prepare estimates of economically recoverable crude oil and natural gas reserves and future net cash flows, 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. Actual results most likely will vary from our estimates. Any significant variance could reduce our estimated quantities and present value of reserves.

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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. Future crude oil and natural gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.

Drilling crude oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive crude oil and natural gas reservoirs. 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 may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled 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 other governments/authorities in countries in which we do business. We have and will continue to incur costs in our efforts to comply with the requirements of environmental and other regulations. Further, the crude oil and natural gas industry regulatory environment could change in ways that might substantially increase these costs.

As an owner or lessee and operator of oil and gas 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 clean-up 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 hurt our business.

The exploration for and production of crude oil and natural gas 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. 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 that we believe to be prudent. Losses and liabilities arising from such events could reduce our revenues and increase our costs to the extent not covered by insurance.

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The occurrence of any of these events and any costs incurred as a result of such events and the liabilities related thereto, would reduce the funds available for exploration, drilling and production and could have a material adverse effect on our financial position or 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 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 oil and gas volumes to the delivery point to which the hedging transaction is indexed.

From time to time, we seek to acquire oil and gas properties. Although we perform reviews of acquired properties 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 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.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs with respect to acquired properties. Actual results may vary substantially from those assumed in the estimates.

In addition, acquisitions may have adverse effects on our operating results, 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 the military or other actions taken in response to these acts, 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 adversely affect us in unpredictable ways, including the disruption of fuel supplies and markets, increased volatility in crude oil and natural gas prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terror.

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

Many of our competitors have financial and other resources substantially larger than those we possess and have established strategic long-term positions and maintain 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 crude oil and natural gas production, 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 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 our oil and gas reserves. We intend to finance our capital expenditures primarily through cash flow from operations, commercial paper and to a lesser extent and if necessary, bank borrowings, public and private equity and debt offerings. Lower crude oil and natural gas prices, however, would

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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. In addition, a substantial rise in interest rates would decrease our net cash flows available for reinvestment.

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. 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.

In general, production from EOG's oil and gas 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.

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Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2006. 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, 2006. Gross natural gas and crude oil wells include 2,365 with multiple completions.

Drilling and Acquisition Activities. During the years ended December 31, 2006, 2005 and 2004, EOG expended $2,996 million, $1,878 million and $1,510 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties, including asset retirement obligations of $22 million, $20 million and $16 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 included in this report as set forth in the Contingencies section in Note 7 of Notes to Consolidated Financial Statements on page F-23.

There were no matters submitted to a vote of security holders during the fourth quarter of 2006.

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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 February 1, 2006, EOG's Board of Directors (Board) increased the quarterly cash dividend on the common stock from the previous $0.04 per share to $0.06 per share.

On January 31, 2007, the Board increased the quarterly cash dividend on the common stock from the previous $0.06 per share to $0.09 per share.

As of February 16, 2007, there were approximately 260 record holders of EOG's common stock, including individual participants in security position listings. There are an estimated 123,000 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.

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

(1) The quarterly total number of shares of 3,759 consists solely of 1,430 shares (23,232 shares for the full year 2006) that were returned to EOG in
      payment of the exercise price of employee stock options and 2,329 shares (241,931 shares for the full year 2006) that were withheld by or returned
      to EOG to satisfy tax withholding obligations that arose upon the exercise of employee stock options 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 2006, EOG did not repurchase
      any shares under the Board authorized repurchase program.

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ITEM 6. Selected Financial Data
(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. Pro forma net
      income for 2002 is not presented since the pro forma application of SFAS No. 143 to the prior periods would not result in pro forma net income materially
      different from the actual amount reported.
(2) Years 2002 through 2004 restated for two-for-one stock split effective March 1, 2005.

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

Net income available to common for 2006 of $1,289 million was up 3% compared to 2005 net income available to common of $1,252 million. At December 31, 2006, EOG's total reserves were 6.8 trillion cubic feet equivalent, an increase of 607 billion cubic feet equivalent (Bcfe) from December 31, 2005.

Several important developments have occurred since January 1, 2006.

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 plans to continue to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas production. Production in the United States and Canada accounted for approximately 79% of total company production in both 2006 and 2005. Based on current trends, EOG expects its 2007 production profile to be similar. EOG's major producing areas are in Louisiana, New Mexico, Oklahoma, Texas, Utah, Wyoming and western Canada.

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

Beginning December 2005, ALNG began taking start-up gas and remained in the start-up phase through December 2006. In the first quarter of 2006, a subsidiary of EOG, EOG Resources Trinidad Block 4(a) Unlimited, drilled two successful wells on Block 4(a). The subsidiary obtained approval to develop Block 4(a) under a production sharing contract with the Government of Trinidad and Tobago signed in July 2005.

A subsidiary of EOG, EOG Resources Trinidad Limited, and the other participants in the South East Coast Consortium (SECC) Block signed a farm-out agreement covering the SECC Deep Ibis prospect with BP Trinidad and Tobago LLC (BP) during 2004. The SECC Deep Ibis well spud in April 2006, was drilled to a depth of approximately 19,000 feet and was abandoned and classified as a dry hole in the third quarter of 2006. BP paid the entire cost for drilling the SECC Deep Ibis exploratory well.

During 2006, notwithstanding difficulties in accessing rig slots in the Southern Gas Basin of the United Kingdom North Sea, Arthur 3 was drilled and completed and began producing in early third quarter. In addition to EOG's ongoing production from Valkyrie and Arthur Fields, EOG participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f. The Columbus well was a farm-in opportunity, and its future appraisal and development is currently being evaluated.

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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, 2006, EOG's debt-to-total capitalization ratio was 12%, down from 19% at year-end 2005. By primarily utilizing cash on hand and cash provided from its operating activities, EOG funded its $2,974 million exploration and development expenditures, paid down $317 million of debt, paid dividends to common shareholders of $60 million and redeemed $47 million of preferred stock. As management continues to assess price forecast and demand trends for 2007, EOG believes that operations and capital expenditure activity can be largely funded by cash from operations.

For 2007, EOG's estimated exploration and development expenditure budget is approximately $3.4 billion, excluding acquisitions. United States and Canada natural gas drilling activity continues to be a key component of 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 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 common stock. The New Registration Statement was filed to replace EOG's existing shelf registration statement declared effective by the Securities and Exchange Commission (SEC) in October 2000, under which EOG had sold no securities. As of February 26, 2007, the entire amount registered remains available under the New Registration Statement.

On October 11, 2006, EOG commenced a cash tender offer to purchase any and all of the 100,000 outstanding shares of the 7.195% Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 Liquidation Preference per share (Series B), at a price of $1,074.01 per share plus accrued and unpaid dividends up to the date of purchase. The tender offer expired on November 8, 2006, and on November 10, 2006, EOG redeemed 46,740 shares of the Series B for an aggregate purchase price, including redemption premium, fees and dividends, of $51 million. EOG has included as a component of preferred dividends the $4 million of premium and fees associated with the redemption of the Series B shares. A total of 53,260 shares of the Series B remain outstanding at December 31, 2006.

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. Prior to the adoption of SFAS No. 123(R), EOG recognized compensation expense for its stock-based compensation plans under the provisions of Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." Stock-based compensation expense prior to January 1, 2006 consisted of amounts recognized in connection with grants of restricted stock and units. The adoption of SFAS No. 123(R) resulted in EOG recognizing compensation expense on grants made under its employee stock option plans and its employee stock purchase plan. For periods subsequent to January 1, 2006, stock-based compensation expense is included in the Consolidated Statements of Income based upon job functions of employees receiving the grants. For the years ended December 31, 2006, 2005 and 2004, EOG compensation expense related to its stock-based compensation plans was as follows (in millions):

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The following review of operations for each of the three years in the period ended December 31, 2006 should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning with page F-1.

During 2006, net operating revenues increased $284 million, or 8%, to $3,904 million from $3,620 million in 2005. Total wellhead revenues, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, decreased $42 million, or 1%, to $3,565 million from $3,607 million in 2005. Wellhead volume and price statistics for the years ended December 31, were as follows:

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and
      natural gas liquids. Natural gas equivalents are determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil,
      condensate or natural gas liquids.
(4) Includes $0.23 per Mcf as a result of a revenue adjustment related to an amended Trinidad take-or-pay contract.

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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).

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.

2005 compared to 2004. Wellhead natural gas revenues for 2005 increased $1,097 million, or 60%, to $2,939 million from $1,842 million for 2004 due to a higher composite average wellhead natural gas price ($763 million), increased natural gas deliveries ($315 million) and a second quarter 2005 revenue adjustment related to an amended Trinidad take-or-pay contract ($19 million). The composite average wellhead natural gas price increased 36% to $6.62 per Mcf for 2005 from $4.86 per Mcf in 2004. Excluding the aforementioned adjustment, the composite average wellhead natural gas price increased 35% to $6.58 per Mcf for 2005. This adjustment increased the average Trinidad wellhead natural gas price by $0.23 per Mcf for 2005.

Natural gas deliveries increased 180 MMcfd, or 17%, to 1,216 MMcfd for 2005 from 1,036 MMcfd in 2004. The increase was due to higher production of 87 MMcfd in the United States, 45 MMcfd in Trinidad, 32 MMcfd in the United Kingdom and 16 MMcfd in Canada. The increase in the United States was primarily attributable to increased production from Texas (63 MMcfd) and Louisiana (20 MMcfd). The increase in Trinidad was due to the increased contractual requirements and demand related to the ammonia and methanol plants. The increase in the United Kingdom was due to the commencement of production from the Arthur field in January 2005 (24 MMcfd) and the full year production from the Valkyrie field, which commenced production in August 2004 (8 MMcfd). The increase in Canada was attributable to the drilling program, primarily in the Wapiti, Drumheller and Connorsville areas.

Wellhead crude oil and condensate revenues increased $168 million, or 42%, to $571 million from $403 million as compared to 2004, due to increases in both the composite average wellhead crude oil and condensate price ($151 million) and the wellhead crude oil and condensate deliveries ($17 million). The composite average wellhead crude oil and condensate price for 2005 was $54.63 per barrel compared to $40.22 per barrel for 2004.

Natural gas liquids revenues increased $42 million, or 76%, to $97 million from $55 million as compared to 2004, due to increases in the composite average price ($23 million) and deliveries ($19 million).

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During 2005, EOG recognized gains on mark-to-market financial commodity derivative contracts of $10 million, which included realized gains of $10 million. During 2004, EOG recognized losses on mark-to-market financial commodity derivative contracts of $33 million, which included realized losses of $82 million and collar premium payments of $1 million.

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 and impairments.

The change in per-unit rates of lease and well, transportation costs, DD&A, G&A, taxes other than income and net interest expense for 2006 as compared to 2005 were due primarily to the reasons 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 $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 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 (compressing natural gas to meet pipeline pressure requirements), dehydration (removing water from natural gas to meet pipeline requirements), gathering fees, fuel costs and transportation fees.

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 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.

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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).

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Taxes other than income of $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).

Net interest expense of $43 million in 2006 decreased $19 million compared to 2005 primarily due to 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 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 $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.

Other income, net was $60 million in 2006 compared to $36 million in 2005. The increase of $24 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), partially offset by lower gains on sales of properties ($5 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.

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2005 compared to 2004. During 2005, operating expenses of $1,628 million were $336 million higher than the $1,292 million incurred in 2004. 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 and impairments.

The per-unit rates of lease and well, including transportation, DD&A, taxes other than income and interest expense, net for 2005 compared to 2004 were due primarily to the reasons set forth below.

Lease and well expenses, including transportation, of $373 million were $102 million higher than 2004 due primarily to higher operating and maintenance expenses in the United States ($40 million); increased transportation related costs in the United States ($28 million) and the United Kingdom ($7 million); higher lease and well administrative expenses in the United States ($11 million); changes in the Canadian exchange rate ($6 million); and higher workover expenditures in the United States ($3 million) and Trinidad ($2 million).

DD&A expenses of $654 million in 2005 were $150 million higher than 2004 primarily as a result of increased production in the United States ($46 million), Canada ($6 million) and Trinidad ($5 million) and the commencement of production in the United Kingdom ($14 million). DD&A rates increased in the United States due to a gradual proportional increase in production from higher cost properties ($59 million) and in Canada predominantly from the development of acquired proved reserves ($9 million). The Canadian exchange rate also contributed to the DD&A expense increase ($8 million).

Taxes other than income of $199 million in 2005 were $65 million higher than 2004. Severance/production taxes increased due primarily to increased wellhead revenues in the United States ($41 million), Trinidad ($7 million) and Canada ($3 million), partially offset by the increase in credits taken for Texas high cost gas severance tax rate reductions ($10 million) and a production tax audit lawsuit in the first quarter of 2004 ($5 million). Other items contributing to the increase were an additional Trinidadian Supplemental Petroleum Tax expense as a result of 2005 tax legislation that increased the tax expense retroactively to January 2004 ($7 million) and 2004 production tax relief in Trinidad ($6 million). Ad valorem/property taxes increased primarily due to higher property valuation in the United States ($11 million).

Net interest expense in 2005 included costs associated with the early retirement of the 2008 Notes ($8 million) (see Note 2 to Consolidated Financial Statements). Excluding these early retirement costs, the 2005 net interest expense decreased $8 million compared to 2004 primarily due to higher capitalized interest ($5 million), an interest charge related to the results of a production tax audit lawsuit in the first quarter of 2004 ($2 million) and lower average debt balance in the United States ($1 million).

Exploration costs of $133 million in 2005 were $39 million higher than 2004 due primarily to increased geological and geophysical expenditures in the Fort Worth Basin Barnett Shale play.

Impairments of $78 million were $4 million lower than 2004 due primarily to lower amortization of unproved leases in the United States ($12 million) and lower impairments to the carrying value of certain long-lived assets in Canada ($8 million), partially offset by higher impairments to the carrying value of certain long-lived assets in the United States ($14 million) and higher amortization of unproved leases in Canada ($2 million). EOG recorded impairments of $31 million and $25 million for 2005 and 2004, respectively, under SFAS No. 144 for certain properties in the United States and Canada.

Other income, net of $36 million in 2005 increased $26 million compared to 2004 primarily as a result of higher gains on sales of properties ($7 million), interest income ($6 million) and equity income from investments in the Caribbean Nitrogen Company Limited (CNCL) and Nitrogen (2000) Unlimited (N2000) ammonia plants in 2005

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($5 million); decreased net foreign currency transaction losses ($4 million); and a gain on the sale of part of EOG's interest in the N2000 ammonia plant in the first quarter of 2005 ($2 million).

Income tax provision of $706 million increased $404 million as compared to 2004, due primarily to higher pretax income ($383 million) and income taxes associated with the repatriation of foreign earnings ($24 million). The effective tax rate for 2005 increased to 36% from 33% in 2004.

The primary sources of cash for EOG during the three-year period ended December 31, 2006 included funds generated from operations, funds from new borrowings, proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan, and proceeds from the sale of oil and gas properties. The primary uses of cash were funds used in operations, exploration and development expenditures, repayment of debt, dividend payments to shareholders and redemption of preferred stock.

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), 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).

2005 compared to 2004. Net cash provided by operating activities of $2,369 million in 2005 increased $925 million as compared to 2004 primarily reflecting an increase in wellhead revenues ($1,306 million), a favorable change in the net cash flows from settlement of financial commodity derivative contracts ($93 million) and favorable changes in working capital and other liabilities ($35 million), partially offset by an increase in cash operating expenses ($217 million) and an increase in cash paid for income taxes ($279 million).

Net cash used in investing activities of $1,678 million in 2005 increased by $281 million as compared to 2004 due primarily to increased additions to oil and gas properties ($308 million) and unfavorable changes in working capital related to investing activities ($28 million), partially offset by an increase in proceeds from the sale of oil and gas properties in 2005 ($40 million) and the sale of part of EOG's interest in the N2000 ammonia plant in 2005 ($18 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 $72 million in 2005 increased $29 million as compared to 2004. Cash provided by financing activities for 2005 included a long-term debt borrowing ($250 million) and proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan ($65 million). Cash used by financing activities for 2005 included repayments of long-term debt borrowings ($343 million) and cash dividend payments ($43 million).

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The table below sets out components of total exploration and development expenditures for the years ended December 31, 2006, 2005 and 2004, along with the total budgeted for 2007, excluding acquisitions (in millions):