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 whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section  229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer x      Accelerated filer o      Non-accelerated filer o      Smaller reporting company o

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. Common Stock aggregate market value held by non-affiliates as of June 30, 2009: $16,923,094,790.

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, 252,578,053 shares outstanding as of February 19, 2010.

Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2010 Annual Meeting of Stockholders to be filed within 120 days after December 31, 2009 are incorporated by reference into Part III of this report.

(i)

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

At December 31, 2009, EOG's total estimated net proved reserves were 10,776 billion cubic feet equivalent (Bcfe), of which 8,898 billion cubic feet (Bcf) were natural gas reserves and 220 million barrels (MMBbl), or 1,317 Bcfe, were crude oil and condensate reserves and 93 MMBbl, or 561 Bcfe, were natural gas liquids reserves (see Supplemental Information to Consolidated Financial Statements). At such date, approximately 75% of EOG's reserves (on a natural gas equivalent basis) were located in the United States, 16% in Canada and 9% in Trinidad. As of December 31, 2009, EOG employed approximately 2,100 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 on the cost-effective utilization of advances in technology associated with the gathering, processing and interpretation of three-dimensional (3-D) seismic data, the development of reservoir simulation models, the use of new and/or improved drill bits, mud motors and mud additives, horizontal drilling, formation logging techniques and reservoir stimulation/completion methods. These advanced technologies are used, as appropriate, throughout EOG to reduce the risks associated with all aspects of oil and gas exploration, development and exploitation. EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. EOG also makes select strategic acquisitions that result in additional economies of scale or land positions which provide significant additional prospects. Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

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

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

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

At December 31, 2009, 81% of EOG's net proved United States and Canada reserves (on a natural gas equivalent basis) were natural gas and 19% were crude oil and condensate and natural gas liquids. Substantial portions of these reserves are in long-lived fields with well-established production characteristics. EOG believes that opportunities exist to increase production through continued development in and around many of these fields and through the utilization of the applicable technologies described above. EOG also maintains an active exploration program designed to extend fields and add new trends and resource plays to its broad portfolio. The following is a summary of significant developments during 2009 and certain 2010 plans for EOG's United States and Canada operations.

1

United States. In 2009, EOG completed 116 net gas wells in the Barnett Shale play of the Fort Worth Basin. EOG uses the term Combo wells to refer to wells that derive economic value from crude oil and condensate, natural gas liquids and associated natural gas in relatively equal portions. During 2009, EOG completed 94 net Combo wells in the Barnett Shale play. During the year, EOG's total production from the Barnett Shale play grew to an average net daily rate of 400 million cubic feet per day (MMcfd) of natural gas and 13.1 thousand barrels per day (MBbld) of crude oil and condensate and natural gas liquids. EOG's 2009 liquids production from the Barnett Shale play increased by approximately 97% compared to 2008. For 2010, EOG plans to drill approximately 234 net Barnett Shale Combo wells. Primary 2010 growth for EOG in the Barnett Shale will be provided by crude oil and natural gas liquids. During the third quarter of 2009, EOG acquired certain crude oil and natural gas properties and related assets in the Barnett Shale consisting of proved developed and undeveloped reserves and approximately 33,000 net unproved acres. With a total of approximately 840,000 net acres, EOG is one of the largest leaseholders in the Barnett Shale play, providing EOG with long-term reserve and production growth potential for years to come.

Throughout the Rocky Mountain area, EOG expanded its acreage position with the addition of prospective crude oil acreage in 2009. EOG now holds approximately 1.5 million net acres in the Rocky Mountain area, including over 500,000 net acres throughout the Williston Basin of North Dakota and Montana available for exploration in the Bakken and Three Forks plays. In addition, EOG also holds acreage in the Rocky Mountain area relating to certain potential exploration and development prospects which EOG is currently evaluating. During 2009, EOG drilled 106 net wells in the Uinta Basin, Utah, and 57 net wells in the Williston Basin. Production from the Rocky Mountain area increased 14% primarily through increased liquids production. The net average production for 2009 was 240 MMcfd of natural gas and 34.7 MBbld of crude oil and condensate and natural gas liquids. In December 2009, EOG and a third party exchanged certain natural gas related properties in the Rocky Mountain area. In 2010, EOG intends to increase its activity level in the Bakken and Three Forks plays in the Williston Basin by drilling over 95 net wells. EOG will have limited drilling activity on its core natural gas assets within the Rocky Mountain area and will primarily focus on exploiting and expanding the oil resource plays.

In 2009, EOG continued to expand its activities in the Mid-Continent area with continued growth and extension of the Western Anadarko Basin and Hugoton Deep core areas. For the year, EOG averaged net production of 76 MMcfd of natural gas and 5.3 MBbld of crude oil and condensate and natural gas liquids. Total crude oil and condensate and natural gas liquids volumes increased 15% in 2009 compared to 2008. In Southwest Kansas, EOG continued its active drilling program focused on high potential Morrow and St. Louis targets in a broad area, which is part of the 900,000 gross acres EOG controls in the Hugoton Deep play. In the Western Anadarko Basin, EOG continued its successful horizontal exploitation of the Cleveland sandstone, drilling 13 net wells with per well initial production rates of approximately 500 barrels of oil per day. Since 2002, EOG has drilled over 200 net wells in this play and holds approximately 65,000 acres throughout the trend. EOG significantly expanded its acreage position in the Western Anadarko Basin during 2009 with the addition of over 100,000 net acres focused on the extension of core plays, as well as multiple new liquids-rich plays which will be exploited in 2010 and beyond. EOG holds approximately 580,000 net acres in the Mid-Continent area.

In the South Texas area, EOG experienced continued success in 2009, drilling 54 net wells. During 2009, net production averaged 204 MMcfd of natural gas and 7.5 MBbld of crude oil and condensate and natural gas liquids. EOG's activity was focused in Webb, Zapata, San Patricio, Duval and Matagorda counties, where EOG drilled successful wells in the Lobo, Roleta, Frio and Wilcox trends. EOG continued to focus on horizontal drilling, targeting the Perdido, Wilcox and Lobo sands. EOG also continued directional drilling under Nueces Bay. EOG drilled a deeper pool wildcat discovery under Indian Point, along with additional development drilling, with seven wells drilled yielding over 34 Bcfe net proved reserves. EOG plans to significantly increase drilling activity in the South Texas area in 2010. Approximately 168 net wells are planned during 2010 for South Texas. EOG holds approximately 600,000 net acres in the South Texas area. In addition, EOG holds acreage in the South Texas area relating to certain potential exploration and development prospects which EOG is currently evaluating.

Also during 2009, EOG participated in 25 net wells and implemented five Wolfcamp waterfloods in the Permian Basin area. The wells drilled throughout the Permian Basin tested the Bone Spring, Wolfcamp, Permo-Penn and other objectives. Production for the year averaged approximately 69 MMcfd of natural gas and 7.1 MBbld of crude oil and condensate and natural gas liquids. EOG acquired approximately 230 square miles of 3-D data and added 100,000 net acres during 2009. EOG holds approximately 490,000 net acres throughout the Permian Basin area. In 2010, EOG plans to continue the development of existing Permian Basin plays, acquire acreage positions in new plays and test new play concepts.

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In the Upper Gulf Coast area, EOG averaged 144 MMcfd of natural gas and 2.8 MBbld of crude oil and condensate and natural gas liquids production in 2009. EOG drilled 31 net wells with 10 net wells being Travis Peak vertical stacked pays and Cotton Valley horizontal development wells located in East Texas and North Louisiana. A major growth driver for EOG in this area is the expanded Haynesville and Bossier Shale program that has grown from drilling two wells in late 2008 to 13 wells in 2009. EOG expects to drill 48 net Haynesville and Bossier Shale wells in 2010 on the 159,000 net acres held in the play. Mississippi development focused on a combined crude oil and natural gas discovery at Mechanicsburg Field, where EOG drilled eight wells. In the fourth quarter of 2009, EOG acquired 39,500 net unproved acres in Nacogdoches County, Texas, within the Haynesville and Bossier Shale formations and expects to acquire up to an additional 7,500 net acres as part of the same transaction during the first quarter of 2010. EOG holds approximately 370,000 net acres in the Upper Gulf Coast area.

During 2009, EOG continued the development of its Pennsylvania Marcellus Shale acreage, drilling a total of three gross vertical and 17 gross horizontal wells (13 net wells). Nine of the wells have been completed with most of those awaiting final construction of gas gathering system infrastructure to commence sales. The gas gathering systems being constructed by EOG should be completed by the end of the first quarter of 2010. Several wells tested at 24-hour rates in excess of 5 MMcfd. In 2010, EOG will continue to develop the Marcellus Shale, drilling an estimated 25 to 30 net wells. Most of the wells will be in the Seneca Joint Venture area in Clearfield, Elk and McKean Counties, Pennsylvania, where EOG holds a 50% working interest. Several wells are also planned for Bradford County, Pennsylvania, where EOG holds a 100% working interest. EOG currently holds approximately 225,000 net acres in the Pennsylvania Marcellus Shale.

At December 31, 2009, EOG held approximately 4,185,000 net undeveloped acres in the United States.

During 2009, EOG continued the expansion of its gathering and processing activities in the Barnett Shale play of North Texas and the Bakken play of North Dakota. In 2009, EOG placed into operation one 40 MMcfd natural gas processing plant in the Barnett Combo play of North Texas, and began construction of a second 40 MMcfd processing unit which is expected to begin operation during the second quarter of 2010. EOG also expanded its gathering system in the Barnett Combo play to transport production to its processing plant and continued expansion of its gathering system in the Bakken play.

In the North Dakota Bakken play, EOG constructed and placed in service during February 2010 a 76-mile, 12-inch diameter "dense phase" natural gas gathering pipeline connecting its Stanley, North Dakota, gathering system with the Alliance Pipeline, near Upham, North Dakota. The Alliance Pipeline transports natural gas to the Chicago, Illinois, area. EOG also replaced its 20 MMcfd natural gas liquids processing plant, located near Stanley, North Dakota, with an 80 MMcfd refrigeration oil/condensate removal plant. In combination, these projects will allow EOG to more efficiently transport the associated natural gas and natural gas liquids production from its Bakken oil wells. At year-end 2009, the combined throughput of these systems was 15 MMcfd of natural gas.

Additionally, in support of its operations in the Bakken play, EOG constructed a crude oil loading facility near Stanley, North Dakota, designed to load crude oil into 100-car unit trains for transport to Stroud, Oklahoma. At Stroud, Oklahoma, EOG constructed a crude oil offloading facility and a pipeline to transport the crude oil to the Cushing, Oklahoma, trading hub. The first shipment of crude oil through these facilities occurred at year-end 2009. When fully operational, the capacity of these facilities is expected to allow transport of approximately 60,000 barrels per day of Bakken crude oil.

EOG expects to continue expanding its gathering and processing facilities to accommodate the drilling activity in the Barnett Shale and Bakken plays. The North Texas systems total over 70 miles of 8-inch, 10-inch and 20-inch diameter pipe, while the North Dakota system totals 290 miles of 8-inch and 12-inch pipe.

3

At December 31, 2009, EOGRC held approximately 1,660,000 net undeveloped acres in Canada.

EOG has operations in Trinidad, the United Kingdom North Sea and East Irish Sea and the China Sichuan Basin, and is evaluating additional exploration, development and exploitation opportunities in those and other international areas.

Trinidad. EOG, through several of its subsidiaries, including EOG Resources Trinidad Limited,

• holds an 80% working interest in the South East Coast Consortium (SECC) Block offshore Trinidad, except in the Deep Ibis area in which EOG's working interest decreased as a result of a third-party farm-out agreement;

• holds an 80% working interest in the exploration and production license covering the Pelican field and its related facilities;

• holds a 100% working interest in a production sharing contract with the Government of Trinidad and Tobago for each of the Modified U(a) Block, Modified U(b) Block and Block 4(a);

• owns a 12% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Caribbean Nitrogen Company Limited (CNCL); and

• owns a 10% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Nitrogen (2000) Unlimited (N2000).

Several fields in the SECC Block, Modified U(a) Block and Modified U(b) Block as well as the Pelican Field have been developed and are producing. In the Pelican field, EOG drilled a successful exploratory well in late January 2010 that is expected to begin producing by the end of the first quarter of 2010. In Block 4(a), EOG installed offshore facilities and plans to drill development wells to supply natural gas under a contract with the National Gas Company of Trinidad and Tobago (NGC) if the North Eastern Offshore (NEO) pipeline is installed by NGC. The NEO pipeline has not been completed, and EOG plans to source the natural gas for this contract from its existing fields until the NEO pipeline is completed. Sales under the contract commenced on January 1, 2010. Given EOG's current level of equity ownership in CNCL and N2000 and its ability to exercise significant influence over certain material actions, it accounts for these investments using the equity method. During 2009, EOG recognized equity income of $0.5 million and received cash dividends of $3 million from CNCL and recognized equity income of $3 million and received cash dividends of $4 million from N2000.

Natural gas from EOG's Trinidad operations currently is sold to NGC or its subsidiary. Crude oil and condensate from EOG's Trinidad operations currently is sold to the Petroleum Company of Trinidad and Tobago.

In 2009, EOG's average net production from Trinidad was 273 MMcfd of natural gas and 3.1 MBbld of crude oil and condensate.

At December 31, 2009, EOG held approximately 156,000 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.

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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. There is currently one remaining producing well in the Arthur field and this well is expected to cease production during the first half of 2010.

In 2006, EOGUK participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f. A successful Columbus prospect appraisal well was drilled during the third quarter of 2007. The field operator expects to submit a revised field development plan to the United Kingdom (U.K.) Department of Energy and Climate Change during the second quarter of 2010 and anticipates receiving approval of this plan in late 2010. The operator and partners are currently evaluating an export route for production from the project.

During the third quarter of 2009, EOG completed a farm-in agreement with owners of the Central North Sea Block 15/30a Area AB. In December 2009, EOG, as operator, drilled an exploratory well on this prospect, which was declared a dry hole in January 2010.

During the second quarter of 2009, EOGUK drilled two exploratory wells in the East Irish Sea. Well 110/14b-7, in which EOGUK has a 70% working interest, was a dry hole while well 110/12-6, in which EOGUK has 100% working interest, was an oil discovery and was designated the Conwy field. Engineering studies were initiated with an intent to submit a field development plan to the U.K. Department of Energy and Climate Change during the first quarter of 2010. A rig has been contracted and has begun drilling two further exploratory wells offsetting the Conwy field. The first of the wells was declared a dry hole in February 2010. Results are expected for the second well by the end of the first quarter of 2010. The licenses for the East Irish Sea were awarded to EOGUK in 2007.

In 2009, production averaged 7 MMcfd of natural gas, net, in the United Kingdom.

At December 31, 2009, EOG held approximately 277,000 net undeveloped acres in the United Kingdom.

China. In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuanzhong Block exploration area in the Sichuan Basin, Sichuan Province, China. In October 2008, EOG obtained the rights to shallower zones on the acreage acquired.

During the second quarter of 2009, EOG completed a monitoring well and in the third quarter of 2009, drilled a horizontal well, which will be completed and tested during the first quarter of 2010. During the third quarter of 2009, EOG drilled a second monitoring well to evaluate one of the shallower zones and is currently drilling a second horizontal well that is expected to be completed during the third quarter of 2010.

In 2009, production averaged 8 million cubic feet equivalent per day of natural gas, net, in China.

At December 31, 2009, EOG held approximately 130,000 net acres in China.

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. In 2009, EOG's United States and Canada wellhead natural gas production was sold on the spot market and under long-term natural gas contracts based on prevailing market prices. In many instances, the long-term contract prices closely approximated the prices received for natural gas sold on the spot market. In 2010, the pricing mechanism for such production is expected to remain the same.

In 2009, 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 is expected to remain the same in 2010.

5

In 2009, over 90% 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 2010 marketing strategy for the wellhead natural gas volumes in the United Kingdom is to sell all natural gas on the spot market.

In 2009, all of the wellhead natural gas volumes from China were sold under a contract with prices based on the purchaser's pipeline sales prices to various local market segments. The pricing mechanism for the contract in China is expected to remain the same in 2010.

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

In certain instances, EOG purchases and sells third-party natural gas production in order to balance firm transportation capacity with production in certain areas.

During 2009, no single purchaser accounted for 10% or more of EOG's natural gas, crude oil and condensate and natural gas liquids revenues. EOG does not believe that the loss of any single purchaser would have a material adverse effect on its financial condition or results of operations.

6

The following table sets forth certain information regarding EOG's wellhead volumes of, and average prices for, natural gas per thousand cubic feet (Mcf), crude oil and condensate per barrel (Bbl) and natural gas liquids per Bbl. The table also presents natural gas equivalent volumes which are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil and condensate or natural gas liquids for each of the years ended December 31, 2009, 2008 and 2007.

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.
(3) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil and
      condensate and natural gas liquids.
(4) Dollars per thousand cubic feet or per barrel, as applicable.

7

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

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

A substantial portion of EOG's oil and gas leases in Utah, New Mexico, Wyoming and the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (BLM) and the Minerals Management Service (MMS), both federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous additional 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; 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 materially and adversely affect EOG's interests.

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

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EOG owns 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 materially and adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.

EOG's gathering operations also may be, or become, subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. Additional rules and legislation pertaining to these matters are considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, such legislation might have on its operations and financial condition, the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Proposals and proceedings that might affect the oil and gas industry are considered from time to time by Congress, the state legislatures, the FERC and the federal and state regulatory commissions and courts. EOG cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the oil and 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.

Compliance with such laws and regulations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, financial condition, results of operations or competitive position. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations but, inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance or the effect on EOG's operations, financial condition, results of operations and competitive position.

EOG is aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions, EOG is also aware of legislation proposed by United States lawmakers to reduce GHG emissions. EOG is unable to predict the timing, scope and effect of any such proposed laws, regulations and treaties, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's business, results of operations, financial condition and competitive position.

EOG supports efforts to understand and address the contribution of human activities to global climate change through the application of sound scientific research and analysis. Moreover, EOG believes that its strategy to reduce GHG emissions throughout its operations is in the best interest of the environment and a generally good business practice. EOG will continue to review the risks to its business and operations associated with all environmental matters, including climate change. In addition, EOG will continue to monitor and assess any new policies, legislation or regulations in the areas where it operates to determine the impact on its operations and take appropriate actions, where necessary.

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Canadian Regulation of Natural Gas and Crude Oil Production. The oil and 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 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 economic, political or other factors. The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for these commodities or increase EOG's costs and, therefore, may have a material adverse impact on EOG's operations and financial condition.

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

In addition, each province has regulations that govern land tenure, royalties, production rates and other matters. The royalty system in Canada is a significant factor in the profitability of natural gas and crude oil production. Royalties payable on production from freehold 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. Royalties payable on lands that the government has an interest in 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 and quality of the petroleum product produced. From time to time, the federal and provincial governments of Canada have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing our revenues, earnings and cash flow.

The Alberta Government implemented a new oil and gas royalty framework effective January 2009. The new framework establishes new royalties for conventional crude oil, natural gas and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects. Under the new framework, the formula for conventional oil and gas royalties uses a sliding rate formula, dependant on the market price and production volumes. Royalty rates for conventional crude oil range from 0% to 50% and natural gas royalty rates range from 5% to 50%.

The Deep Oil Exploration Program (DOEP) and the Natural Gas Deep Drilling Program (NGDDP) are new programs that began January 1, 2009 in Alberta. These programs provide upfront royalty adjustments to new wells. To qualify for royalty adjustments under the DOEP, exploratory oil wells must have a vertical depth greater than 2,000 meters with a government interest and must be spudded after January 1, 2009. These oil wells qualify for a royalty exemption on either the first 1,000,000 Canadian dollars of royalty or the first 12 months of production, whichever comes first. The NGDDP applies to natural gas wells producing at a vertical depth greater than 2,500 meters. The NGDDP will have an escalating royalty credit in line with progressively deeper wells from 625 Canadian dollars per meter to a maximum of 3,750 Canadian dollars per meter. There are additional benefits for the deepest wells. Both the DOEP and the NGDDP are five-year programs. Any wells spudded after December 31, 2013, or any wells for which EOG chooses the transition option described below, will not qualify under either program. No royalty adjustments will be granted under either the DOEP or the NGDDP after December 31, 2018.

In November 2008, the Alberta Government announced that companies drilling new natural gas and conventional crude oil wells at depths between 1,000 and 3,500 meters, which are spudded between November 19, 2008 and December 31, 2013, will have a one-time option of selecting new transitional royalty rates or the new royalty framework rates. The transition option provides lower royalties in the initial years of a well's life. For example, under the transition option, royalty rates for natural gas wells will range from 5% to 30%. The election is made prior to the end of the first calendar month in which the commodity is produced. All wells using the transitional royalty rates must shift to the new royalty framework rates on January 1, 2014.

EOG expects these regulations of the Alberta Government to have a marginally positive impact on EOG's financial condition and results of operations.

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Environmental Regulation - Canada. All phases of the oil and 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.

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

These laws and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment. Compliance with such laws and regulations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, financial condition, results of operations or competitive position. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations, but, inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance or the effect on EOG's operations, financial condition, results of operations and competitive position.

As noted above, EOG is aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. Canada is a signatory to the United Nations Framework Convention on Climate Change (also known as the Kyoto Protocol). The Canadian federal government has indicated an intention to regulate industrial emissions of GHG and air pollutants from a broad range of industrial sectors in the Regulatory Framework for Air Emissions released April 2007 and updated in a March 2008 document entitled Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions (collectively, Federal Plan). The Federal Plan outlines proposed policies to reduce the emissions of GHG and air pollutants by establishing mandatory emissions reduction requirements on a sector basis. Sector-specific regulations could come into effect as early as 2010 and targets are expected to be based on percentages rather than absolute reductions. EOG is also aware of legislation proposed by the Canadian legislature to reduce GHG emissions as well as proposed regulations that would establish a credit emissions trading system in Canada. Additionally, regulation of GHG emissions in Canada takes place at the provincial and municipal level. For example, the Alberta Government regulates GHG emissions under the Climate Change and Emissions Management Act, the Specified Gas Reporting Regulation, which imposes GHG emissions reporting requirements, and the Specified Gas Emitters Regulation, which imposes GHG emissions limits.

EOG is unable to predict the timing, scope and effect of any such proposed laws, regulations and treaties, but the direct and indirect costs of such enacted laws, regulations and treaties and, if enacted, proposed laws, regulations and treaties, could materially and adversely affect EOG's business, results of operations, financial condition and competitive position.

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, the United Kingdom and China.

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Energy Prices. Since EOG is primarily a natural gas producer, it is more significantly impacted by changes in natural gas prices than changes in prices for crude oil and 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 54% decrease in the average wellhead natural gas price for production in the United States and Canada received by EOG from 2008 to 2009, an increase of 30% from 2007 to 2008, and a decrease of 4% from 2006 to 2007. The average New York Mercantile Exchange (NYMEX) natural gas strip price for 2010 has decreased approximately 9% subsequent to December 31, 2009. Crude oil and condensate and natural gas liquids production comprised a larger portion of EOG's production mix in 2009 than in prior years and is expected to comprise an even larger portion in 2010. Average crude oil and condensate prices received by EOG for production in the United States decreased by 38% in 2009, increased by 27% in 2008 and increased by 10% in 2007, each as compared to the immediately preceding year. The average NYMEX crude oil strip price for 2010 has declined approximately 1% subsequent to December 31, 2009. Due to the many uncertainties associated with the world political environment, the availabilities of other worldwide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, EOG is unable to predict what changes may occur in natural gas, crude oil and condensate, natural gas liquids, ammonia and methanol prices in the future. For additional discussion regarding changes in natural gas and crude oil prices and the risks that such changes may present to EOG, see ITEM 1A. Risk Factors.

Including the impact of EOG's 2010 natural gas hedges, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2010 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 $30 million for net income and $45 million for cash flows from operating activities. EOG's price sensitivity in 2010 for each $1.00 per barrel change in wellhead crude oil and condensate price, combined with the related change in natural gas liquids price, is approximately $22 million for net income and $33 million for cash flows from operating activities. For information regarding EOG's natural gas hedge position as of December 31, 2009, see Note 11 to Consolidated Financial Statements.

Risk Management. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collar, price swap and basis swap contracts, as a means to manage this price risk. See Note 11 to Consolidated Financial Statements. 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 the provisions of the Derivatives and Hedging Topic of the Accounting Standards Codification, these physical commodity contracts qualify for the normal purchases and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices. For a summary of EOG's financial commodity derivative contracts, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Derivative Transactions.

All of EOG's natural gas and crude oil activities are subject to the risks normally incident to the exploration for, and development and production of, natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and/or property. EOG's onshore and offshore operations are subject to usual customary 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 these risks. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance.

In addition, 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, unilateral or forced renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and currency exchange and repatriation losses, as well as changes in laws, regulations and policies governing operations of foreign companies. Please refer to Item 1A. Risk Factors for further discussion of the risks to which EOG is subject.

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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 a discussion of the impact on EOG, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Operating and Other Expenses.

The current executive officers of EOG and their names and ages (as of February 25, 2010) are as follows:

Mark G. Papa was elected Chairman of the Board and Chief Executive Officer of EOG in August 1999, President and Chief Executive Officer and director in September 1998, President and Chief Operating Officer in September 1997 and President in December 1996, and was President-North America Operations from February 1994 to December 1996. Mr. Papa joined Belco Petroleum Corporation, a predecessor of EOG, in 1981. Mr. Papa is also a director of Oil States International, Inc., an oilfield service company, where he serves on the Compensation and Nominating and Corporate Governance committees. From July 2003 to April 2005, Mr. Papa served as a director of the general partner of Magellan Midstream Partners LP, a pipeline and terminal company, where he served as Chairman of the Compensation Committee and as a member of the Audit and Conflicts Committees. Mr. Papa is EOG's principal executive officer.

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

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

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

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

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

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ITEM 1A. Risk Factors

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

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

• the level of consumer demand;

• supplies of natural gas and crude oil;

• weather conditions and changes in weather patterns;

• domestic and international drilling activity;

• the price and availability of, and demand for, competing energy sources, including liquefied natural gas, and alternative energy sources;

• the availability, proximity and capacity of transportation facilities;

• worldwide economic and political conditions;

• the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others;

• the effect of worldwide energy conservation measures; and

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

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

In addition, if we expect significant sustained decreases in natural gas and crude oil prices in the future such that the future cash flow from our natural gas and crude oil properties falls below the net book value of our properties, we may be required to write down the value of our natural gas and crude oil properties. Any such future asset impairments could materially and adversely affect our results of operations and, in turn, the trading price of our common stock.

Drilling natural gas and crude oil wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive natural gas and crude oil reservoirs. As a result, we may not recover all or any portion of our investment in new wells.

Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled, the cost of such operations may increase and/or our results of operations and cash flows from such operations may be impacted, 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 and changes in weather patterns;

• compliance with, or changes in, environmental and other laws and regulations, such as tax laws and regulations;

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• the availability and timely issuance of required governmental permits and licenses;

• the availability of, costs associated with and terms of contractual arrangements for properties, including leases, pipelines and related facilities and equipment to gather, process, compress, transport and market natural gas, crude oil and related commodities;

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

• lack of necessary services and/or qualified personnel.

Our failure to recover our investment in wells, increases in the costs of our drilling operations or those of our third-party operators and/or curtailments, delays or cancellations of our drilling operations or those of our third-party operators may materially and adversely affect our business, financial condition and results of operations.

The sale of our natural gas and crude oil production depends on a number of factors beyond our control, including the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities owned by third parties. These facilities may be temporarily unavailable to us due to market conditions, mechanical reasons or other factors or conditions, and may not be available to us in the future on terms we consider acceptable, if at all. Any significant change in market or other conditions affecting these facilities or the availability of these facilities, including due to our failure or inability to obtain access to these facilities on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.

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

Our exploration, production and marketing operations are regulated extensively at the federal, state and local levels, as well as by the governments and regulatory agencies in the foreign countries in which we do business, and are subject to interruption or termination by governmental and regulatory authorities based on environmental or other considerations. Moreover, we have incurred and will continue to incur costs in our efforts to comply with the requirements of environmental, safety and other regulations. Further, the regulatory environment in the oil and gas industry could change in ways that we cannot predict and that might substantially increase our costs of compliance and, in turn, materially and adversely affect our business, results of operations, financial condition and competitive position.

Specifically, as an owner or lessee and operator of natural gas and crude oil properties, we are subject to various federal, state, local and foreign regulations relating to the discharge of materials into, and the protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution cleanup resulting from operations, subject us to liability for pollution damages and require suspension or cessation of operations in affected areas. Moreover, we are subject to the United States Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG) emissions. Changes in, or additions to, these regulations could materially and adversely affect our business, results of operations, financial condition and competitive position.

A portion of our natural gas and crude oil production may be interrupted, or shut in, from time to time for various reasons, including as a result of accidents, weather conditions, loss of gathering, processing, compression or transportation facility access or field labor issues, or intentionally as a result of market conditions such as natural gas or crude oil prices that we deem uneconomic. If a substantial amount of our production is interrupted, our cash flow and, in turn, our results of operations could be materially and adversely affected.

Our operations in jurisdictions outside the U.S. are subject to various risks inherent in foreign operations. These risks may include, among other risks:

• loss of revenue, equipment and property as a result of expropriation, acts of terrorism, war, civil unrest and other political risks;

• increases in taxes and governmental royalties;

• unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities;

• difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;

• changes in laws and policies governing operations of foreign-based companies; and

• currency restrictions and exchange rate fluctuations.

Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation. The realization of any of these factors could materially and adversely affect our business, financial condition and results of operations.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs and materially and adversely affect our financial condition and results of operations.

Demand for natural gas and crude oil is, to a significant degree, dependent on weather and climate, which impacts, among other things, the price we receive for the commodities we produce and, in turn, our cash flow and results of operations. For example, relatively warm temperatures during a winter season generally result in relatively lower demand for natural gas (as less natural gas is used to heat residences and businesses) and, as a result, relatively lower prices for natural gas production.

In addition, our exploration, exploitation and development activities and equipment can be adversely affected by extreme weather conditions and changes in weather patterns, such as hurricanes in the Gulf of Mexico and increases in storm intensity, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions and changes in weather patterns could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs, the installation and operation of gathering and production facilities and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. Such extreme weather conditions and changes in weather patterns may materially and adversely affect our business and, in turn, our financial condition and results of operations.

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

Lower natural gas and crude oil prices, however, would reduce our cash flow. Further, if the condition of the credit and capital markets materially declines, we might not be able to obtain financing on terms we consider acceptable, if at all. The weakness and volatility in domestic and global financial markets and economic conditions in recent years may increase the interest rates that lenders and commercial paper investors require us to pay and adversely affect our ability to finance our capital expenditures through equity or debt offerings or other borrowings. Moreover, a reduction in our cash flow (for example, as a result of lower natural gas and crude oil prices) and the corresponding adverse effect on our financial condition and results of operations may increase the interest rates that lenders and commercial paper investors require us to pay. In addition, a substantial rise in interest rates would decrease our net cash flows available for reinvestment. Any of these factors could have a material and adverse effect on our business, financial condition and results of operations.

We have various customers for the natural gas, crude oil and related commodities that we produce as well as various other contractual counterparties, including several financial institutions and affiliates of financial institutions. Domestic and global economic conditions, including the financial condition of financial institutions generally, have weakened in recent years and remain weak. In addition, there continues to be weakness and volatility in domestic and global financial markets, including the credit crisis and corresponding reaction by lenders to risk. These conditions and factors may adversely affect the ability of our customers and other contractual counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, as well as their ability to access the credit and capital markets for such purposes.

Moreover, our customers and other contractual counterparties may be unable to satisfy their contractual obligations to us for reasons unrelated to these conditions and factors, such as the unavailability of required facilities or equipment due to mechanical failure or market conditions. Furthermore, if a customer is unable to satisfy its contractual obligation to purchase natural gas, crude oil or related commodities from us, we may be unable to sell such production to

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another customer on terms we consider acceptable, if at all, due to the geographic location of such production, the availability, proximity or capacity of transportation facilities or market or other factors and conditions.

The inability of our customers and other contractual counterparties to pay amounts owed to us and to otherwise satisfy their contractual obligations to us may materially and adversely affect our business, financial condition, results of operations and cash flow.

We compete with major integrated oil and gas companies and other independent oil and gas companies for the acquisition of licenses and leases, properties and reserves and the equipment, materials, services and employees and other personnel (including geologists, geophysicists, engineers and other specialists) required to explore for, develop, produce and market natural gas and crude oil. In addition, many of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions and strong governmental relationships in countries in which we may seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for natural gas and crude oil, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. We also face competition from competing energy sources, such as liquefied natural gas imported into the U.S. from other countries and, to a lesser extent, alternative energy sources.

Estimating quantities of natural gas and liquids reserves and future net cash flows from such reserves is a complex, inexact process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors, made by our management and our independent petroleum consultants. Any significant inaccuracies in these interpretations or assumptions could cause the reported quantities of our reserves and future net cash flows from such reserves to be overstated or understated. Moreover, the data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

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

We use derivative instruments (primarily financial collars, price swaps and basis swaps) to hedge the impact of fluctuations in natural gas and crude oil prices on our results of operations and cash flow. To the extent that we engage in hedging activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of increases in natural gas and crude oil prices above the prices established by our hedging contracts. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.

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

Our business and prospects for future success, including the successful implementation of our strategies and handling of issues integral to our future success, depend to a significant extent upon the continued service and performance of our management team. The loss of any member of our management team, and our inability to attract, motivate and retain substitute management personnel with comparable experience and skills, could materially and adversely affect our business, financial condition and results of operations.

The reporting currency for our financial statements is the U.S. dollar. However, certain of our subsidiaries are located in countries other than the U.S. and have functional currencies other than the U.S. dollar. The assets, liabilities, revenues and expenses of certain of these foreign subsidiaries are denominated in currencies other than the U.S. dollar. To prepare our consolidated financial statements, we must translate those assets, liabilities, revenues and expenses into U.S. dollars at then-applicable exchange rates. Consequently, increases and decreases in the value of the U.S. dollar versus other currencies will affect the amount of these items in our consolidated financial statements, even if the amount has not changed in the original currency. These translations could result in changes to our results of operations from period to period. For the fiscal year ended December 31, 2009, approximately 9% of our revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.

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

None.

Reserve Information. For estimates of EOG's net proved and proved developed reserves of natural gas and liquids, including crude oil and condensate and natural gas liquids, as well as discussion of EOG's proved undeveloped reserves, the qualifications of the preparers of EOG's reserve estimates, EOG's independent petroleum consultants and EOG's processes and controls with respect to its reserve estimates, see "Supplemental Information to Consolidated Financial Statements."

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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 and condensate and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment.

As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. For related discussion, see ITEM 1A. Risk Factors.

In general, the rate of production from EOG's natural gas and crude oil properties declines as reserves are produced. Except to the extent EOG acquires additional properties containing proved reserves, conducts successful exploration, exploitation and development activities or, through engineering studies, identifies additional behind-pipe zones or secondary recovery reserves, 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. For related discussion, see ITEM 1A. Risk Factors. EOG's estimates of reserves filed with other federal agencies agree with the information set forth in Supplemental Information to Consolidated Financial Statements.

Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2009. 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, the United Kingdom and China at December 31, 2009. Gross natural gas and crude oil wells include 2,399 wells with multiple completions.

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Drilling and Acquisition Activities. During the years ended December 31, 2009, 2008 and 2007, EOG expended $3.9 billion, $5.1 billion and $3.6 billion, respectively, for exploratory and development drilling and acquisition of leases and producing properties, including asset retirement obligations of $84 million, $181 million and $31 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 contractual basis with independent drilling contractors. EOG does not own drilling equipment. EOG's other property, plant and equipment primarily includes gathering and processing infrastructure assets which support EOG's exploration and production activities.

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

There were no matters submitted to a vote of security holders during the fourth quarter of 2009.

EOG's common stock is traded on the New York Stock Exchange (NYSE) under the ticker symbol "EOG." The following table sets forth, for the periods indicated, the high and low sales price per share for EOG's common stock, as reported by the NYSE, and the amount of the cash dividend declared per share. The quarterly cash dividend on EOG's common stock has historically been declared in the quarter immediately preceding the quarter of payment and paid on January 31, April 30, July 31 and October 31 of each year (or, if such day is not a business day, the immediately preceding business day).

On February 9, 2010, EOG's Board of Directors (Board) increased the quarterly cash dividend on the common stock from the current $0.145 per share to $0.155 per share effective beginning with the dividend to be paid on April 30, 2010.

As of February 15, 2010, there were approximately 1,700 record holders and approximately 210,000 beneficial owners of EOG's common stock.

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

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

(1) The 12,115 total shares for the quarter ended December 31, 2009 and the 167,867 shares for the full year 2009 consist solely of shares that were withheld
      by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation
      rights or the vesting of restricted stock or restricted stock unit grants or (ii) in payment of the exercise price of employee stock options. These shares do not
      count against the 10 million aggregate share repurchase authorization of EOG's Board discussed below.
(2) In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During 2009, EOG did not repurchase any
      shares under the Board-authorized repurchase program.

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

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

1. $100 was invested on December 31, 2004 in each of the following: Common Stock of EOG, the S&P 500 and the S&P O&G E&P.
2. Dividends are reinvested.

Comparison of Five-Year Cumulative Total Returns*
EOG, S&P 500 and S&P O&G E&P
(Performance Results Through December 31, 2009)

*Cumulative total return assumes reinvestment of dividends.

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ITEM 6. Selected Financial Data
(In Thousands, Except Per Share Data)

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EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) oil and natural gas companies in the United States with proved reserves in the United States, Canada, Trinidad, the United Kingdom and China. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet. EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

Net income available to common stockholders for 2009 totaled $547 million as compared to $2,436 million for 2008. At December 31, 2009, EOG's total estimated net proved reserves were 10.8 trillion cubic feet equivalent, an increase of 2,087 billion cubic feet equivalent (Bcfe) from December 31, 2008.

Several important developments have occurred since January 1, 2009.

United States and Canada. EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's natural gas and crude oil production. In Canada, EOG departed from its historical vertical shallow natural gas drilling program to focus on bigger target horizontal gas growth in the Horn River Basin and horizontal oil growth within existing legacy fields, mainly in Waskada, Manitoba and Highvale, Alberta. In addition, EOG continues to evaluate certain potential exploration and development prospects. Production in the United States and Canada accounted for approximately 86% of total company production in 2009 as compared to 87% in 2008. In 2009, the Fort Worth Basin Barnett Shale and North Dakota Bakken areas produced an increasing amount of crude oil and condensate and natural gas liquids. For 2009, crude oil and condensate and natural gas liquids production accounted for approximately 22% of total company production as compared to 19% for 2008. Based on current trends, EOG expects its 2010 crude oil and condensate and natural gas liquids production to increase both in total and as a percentage of total company production as compared to 2009. EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

During the third quarter of 2009, EOG completed three transactions to acquire certain crude oil and natural gas properties and related assets located in Montague and Cooke Counties, Texas (Barnett Shale Combo Assets). The Barnett Shale Combo Assets consist of proved developed and undeveloped reserves and approximately 33,000 net unproved acres. Production from these assets averaged approximately 2,300 barrels of oil equivalent per day, net, at the time of acquisition. The aggregate purchase price of the transactions totaled $196.7 million, consisting of cash consideration of $107.1 million and 1,450,000 shares of EOG common stock valued at $89.6 million on the closing date of the applicable transaction.

In October 2009, EOG entered into an agreement to acquire unproved acreage located in Nacogdoches County, Texas within the Haynesville and Bossier Shale formations (Haynesville Assets). EOG acquired 39,500 net unproved acres at the principal and supplemental closings held in October 2009 and December 2009, respectively. The acquisition agreement provides for an additional one-time supplemental cash payment to the sellers of the Haynesville Assets that is contingent on the satisfaction of certain conditions (within a five-year period beginning on the principal closing date) set forth in the acquisition agreement with respect to future natural gas prices. EOG estimated the fair value of the contingent consideration as of the acquisition dates in accordance with the provisions of the Business Combinations Topic of the Accounting Standards Codification (ASC) and has included such amount in Other Liabilities on the Consolidated Balance Sheets. The fair value of such contingent consideration was $35.3 million at December 31, 2009. The aggregate consideration recorded in 2009 for the acquisition of the Haynesville Assets was $134 million, including the contingent consideration. Additionally, EOG expects to acquire up to an additional 7,500 net acres at a final closing expected to occur in the first quarter of 2010. The total price for the Haynesville Assets will not exceed $165 million.

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In November 2009, EOG entered into an agreement to sell its crude oil and natural gas related assets located in California for cash consideration of $202 million, subject to customary adjustments under the agreement. The assets sold included approximately 80 wells that accounted for less than 1% of EOG's total 2009 production. The transaction closed on December 10, 2009. EOG realized a pretax gain of $146 million on the sale.

In December 2009, EOG and a third party entered into an asset exchange agreement whereby the two parties exchanged certain natural gas related properties in the Rocky Mountain area. In accordance with provisions of the Business Combinations Topic of the ASC, EOG realized a pretax gain of $390 million on the exchange to reflect the excess of the fair value of the properties received over the book basis of the properties given up in the transaction.

In support of its operations in the North Dakota Bakken play, EOG constructed a crude oil loading facility near Stanley, North Dakota, designed to load crude oil into 100-car unit trains for transport to Stroud, Oklahoma. At Stroud, Oklahoma, EOG constructed a crude oil offloading facility and a pipeline to transport the crude oil to the Cushing, Oklahoma, trading hub. The first shipment of crude oil through these facilities occurred at year-end 2009. When fully operational, the capacity of these facilities is expected to allow transport of approximately 60,000 barrels per day of Bakken crude oil.

International. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. In the Pelican Field, EOG drilled a successful exploratory well in late January 2010 that is expected to begin producing by the end of the first quarter of 2010.

In the United Kingdom, EOG has ongoing production from the Valkyrie and Arthur fields in the Southern Gas Basin of the North Sea Block 23/16f. There is currently one producing well in the Arthur field, and such well is expected to cease production during the first half of 2010. The operator and partners of the non-EOG operated Columbus discovery in the Central North Sea are continuing to evaluate export routes for future production. In addition, the operator expects to submit a revised field development plan to the United Kingdom Department of Energy and Climate Change during the second quarter of 2010 and anticipates receiving approval in late 2010.

During the third quarter of 2009, EOG completed a farm-in agreement with the owners of the Central North Sea Block 15/30a Area AB. In December 2009, EOG began drilling an exploratory well on this prospect. The well was declared a dry hole in January 2010.

EOG continues to expand its exploration prospect portfolio in the United Kingdom. During the second quarter of 2009, EOG drilled two exploratory wells in the East Irish Sea. Well 110/14b-7, in which EOG has a 70% working interest, was a dry hole while well 110/12-6, in which EOG has 100% working interest, was an oil discovery. Engineering studies were initiated with an intent to submit a field development plan to the United Kingdom Department of Energy and Climate Change during the first quarter of 2010. A rig has been contracted and has begun drilling two further exploratory wells offsetting the oil discovery. The first well was declared a dry hole in February 2010 and results for the second well are expected by the end of the first quarter of 2010.

In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuanzhong Block exploration area in the Sichuan Basin, Sichuan Province, China. In October 2008, EOG obtained the rights to additional shallower zones on the acreage purchased. During the second quarter of 2009, EOG completed a monitoring well and in the third quarter of 2009, drilled a horizontal well. The horizontal well is being completed and will be tested during the first quarter of 2010. In addition, to evaluate one of the shallower zones, EOG drilled a second monitoring well during the third quarter of 2009 and is currently drilling a second horizontal well that it plans to complete during the third quarter of 2010.

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

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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, 2009, EOG's debt-to-total capitalization ratio was 22%. During 2009, EOG funded $3.8 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement costs and non-cash acquisition costs), paid $142 million in dividends to common stockholders and purchased $11 million of treasury stock, primarily by utilizing cash provided from its operating activities, proceeds from long-term debt borrowings, proceeds from the sale of its California assets and the issuance of 1.45 million shares of EOG common stock valued at $89.6 million.

Management has not finalized or recommended to EOG's Board a 2010 capital expenditures budget. Management continues to evaluate various factors impacting future natural gas and crude oil prices, including the quantities of natural gas in storage and North American natural gas supplies. In addition, EOG continues to evaluate certain potential exploration and development prospects. All of these factors and uncertainties impact future capital requirements. EOG expects to finalize a 2010 capital expenditures budget early in the second quarter. While EOG currently anticipates an increase in its 2010 capital expenditures budget as compared to its 2009 budget, EOG intends to maintain a strong balance sheet and a below average debt-to-capitalization ratio as compared to its peer group.

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 May 21, 2009, EOG completed its public offering of $900 million aggregate principal amount of 5.625% Senior Notes due 2019 (2019 Notes). Interest on the 2019 Notes is payable semi-annually in arrears on June 1 and December 1 of each year, beginning December 1, 2009. Net proceeds from the offering of approximately $891 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings.

The following review of operations for each of the three years in the period ended December 31, 2009 should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning with page F-1.

During 2009, net operating revenues decreased $2,340 million, or 33%, to $4,787 million from $7,127 million in 2008. Total wellhead revenues, which are revenues generated from sales of EOG's production of natural gas, crude oil and condensate and natural gas liquids, decreased $2,823 million, or 45%, to $3,399 million from $6,222 million in 2008. During 2009, EOG recognized net gains on mark-to-market commodity derivative contracts of $432 million compared to net gains of $598 million in 2008. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party natural gas, crude oil and condensate and natural gas liquids as well as gathering fees associated with gathering third-party natural gas, increased $242 million, or 147%, to $407 million in 2009 from $165 million in 2008. Gains on property dispositions, net in 2009 primarily consist of a pretax gain of $390 million realized on an exchange of properties in the Rocky Mountain area and a pretax gain of $146 million realized on the sale of EOG's California assets. Gains on property dispositions, net in 2008 primarily consist of the gain of $128 million on the sale of Appalachian assets in February 2008.

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Wellhead volume and price statistics for the years ended December 31, 2009, 2008 and 2007 were as follows:

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.
(3) Dollars per thousand cubic feet or per barrel, as applicable.
(4) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil and 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 and condensate or natural gas liquids.

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2009 compared to 2008. Wellhead natural gas revenues in 2009 decreased $2,401 million, or 54%, to $2,051 million from $4,452 million for 2008 due to a lower composite average wellhead natural gas price ($2,460 million), partially offset by increased natural gas deliveries ($59 million). EOG's composite average wellhead natural gas price decreased 54% to $3.42 per Mcf in 2009 from $7.51 per Mcf in 2008.

Natural gas deliveries increased 26 MMcfd, or 2%, to 1,645 MMcfd in 2009 from 1,619 MMcfd in 2008. The increase was primarily due to higher production of 55 MMcfd in Trinidad, partially offset by lower production of 28 MMcfd in the United States and 6 MMcfd in the United Kingdom. The increase in Trinidad was primarily due to a reduction in plant shutdowns for maintenance during 2009 (39 MMcfd) and increased net contractual deliveries (16 MMcfd). The decrease in the United States was primarily attributable to decreased production from Texas (26 MMcfd), New Mexico (6 MMcfd), Mississippi (4 MMcfd), Kansas (3 MMcfd) and Oklahoma (3 MMcfd), partially offset by increased production in Louisiana (6 MMcfd) and in the Rocky Mountain area (8 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 decreased $368 million, or 25%, to $1,090 million in 2009 from $1,458 million in 2008, due to a lower composite average wellhead crude oil and condensate price ($675 million), partially offset by an increase of 10 MBbld, or 21%, in wellhead crude oil and condensate deliveries ($307 million). The increase in deliveries primarily reflects increased production in North Dakota (8 MBbld) and Texas (2 MBbld). The composite average wellhead crude oil and condensate price for 2009 decreased 38% to $54.46 per barrel compared to $88.18 per barrel for 2008.

Natural gas liquids revenues decreased $53 million, or 17%, to $259 million in 2009 from $312 million in 2008, due to a lower composite average price ($201 million), partially offset by an increase of 8 MBbld, or 48%, in natural gas liquids deliveries ($148 million). The composite average natural gas liquids price for 2009 decreased 44% to $30.05 per barrel compared to $53.42 per barrel for 2008. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area.

During 2009, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $432 million, which included net realized gains of $1,278 million. During 2008, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $598 million, which included net realized losses of $137 million.

Gathering, processing and marketing revenues represent sales of third-party natural gas, crude oil and condensate and natural gas liquids as well as gathering fees associated with gathering third-party natural gas. For the year ended December 31, 2009, substantially all of such revenues were related to sales of third-party natural gas and crude oil. For the years ended December 31, 2008 and 2007, such revenues were primarily related to sales of third-party natural gas. Sales of third-party natural gas are utilized in order to balance firm transportation capacity with production in certain areas. Marketing costs represent the costs of purchasing third-party natural gas and crude oil and the associated transportation costs.

Gathering, processing and marketing revenues less marketing costs decreased $2 million to $10 million in 2009 compared to $12 million in 2008. The decrease resulted primarily from natural gas marketing operations in the Gulf Coast area.

2008 compared to 2007. Wellhead natural gas revenues in 2008 increased $1,419 million, or 47%, to $4,452 million from $3,033 million for 2007 due to a higher composite average wellhead natural gas price ($1,101 million) and increased natural gas deliveries ($318 million). EOG's composite average wellhead natural gas price increased 33% to $7.51 per Mcf in 2008 from $5.65 per Mcf in 2007.

Natural gas deliveries increased 149 MMcfd, or 10%, to 1,619 MMcfd in 2008 from 1,470 MMcfd in 2007. The increase was due to higher production of 191 MMcfd in the United States and initial production of 5 MMcfd in China, partially offset by lower production of 34 MMcfd in Trinidad, 11 MMcfd in the United Kingdom and 2 MMcfd in Canada. The increase in the United States was primarily attributable to increased production from Texas (140 MMcfd), the Rocky Mountain area (54 MMcfd), Mississippi (8 MMcfd) and Kansas (4 MMcfd), partially offset by decreased production due to the February 2008 sale of Appalachian assets (15 MMcfd). The decline in Trinidad was primarily due to decreased deliveries as a result of plant shutdowns due to unplanned maintenance activities (29 MMcfd) and reduced deliveries due to lower demand in 2008 (10 MMcfd), partially offset by increased deliveries to Atlantic LNG Train 4 (ALNG) (5 MMcfd). The decrease in production in the United Kingdom was a result of production declines in both the Arthur and Valkyrie fields.

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Wellhead crude oil and condensate revenues increased $680 million, or 87%, to $1,458 million in 2008 from $778 million in 2007, due to an increase of 14.3 MBbld, or 46%, in wellhead crude oil and condensate deliveries ($358 million) and a higher composite average wellhead crude oil and condensate price ($322 million). The increase in deliveries primarily reflects increased production in North Dakota (12 MBbld). The composite average wellhead crude oil and condensate price for 2008 increased 28% to $88.18 per barrel compared to $68.69 per barrel for 2007.

Natural gas liquids revenues increased $102 million, or 49%, to $312 million in 2008 from $210 million in 2007, due to increases in deliveries ($67 million) and a higher composite average price ($35 million). The composite average natural gas liquids price for 2008 increased 13% to $53.42 per barrel compared to $47.36 per barrel for 2007. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale and Rocky Mountain areas.

During 2008, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $598 million, which included net realized losses of $137 million. During 2007, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $93 million, which included net realized gains of $128 million.

Gathering, processing and marketing revenues less marketing costs increased $5 million to $12 million in 2008 compared to $7 million in 2007. The increase resulted primarily from natural gas marketing operations in the Gulf Coast area.

2009 compared to 2008. During 2009, operating expenses of $3,816 million were $456 million higher than the $3,360 million incurred in 2008. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the years ended December 31, 2009 and 2008:

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2009 compared to 2008 are set forth below.

Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain EOG's natural gas and crude oil 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.

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Lease and well expenses of $579 million in 2009 increased $20 million from $559 million in 2008 due primarily to higher operating and maintenance expenses in Canada ($16 million) and the United States ($14 million), partially offset by changes in the Canadian exchange rate ($8 million) and lower lease and well administrative expenses ($5 million).

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

Transportation costs of $283 million in 2009 increased $9 million from $274 million in 2008 primarily due to increased transportation costs in the Rocky Mountain area ($19 million), partially offset by decreased transportation costs in the Fort Worth Basin Barnett Shale area ($8 million).

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. DD&A of the cost of other property, plant and equipment is calculated using the straight-line depreciation method over the useful lives of the assets. Other property, plant and equipment consist of gathering and processing assets, compressors, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

DD&A expenses in 2009 increased $222 million to $1,549 million from $1,327 million in 2008. DD&A expenses associated with oil and gas properties were $192 million higher than in 2008 primarily due to higher unit rates described below and as a result of increased production in the United States ($42 million), Canada ($9 million) and Trinidad ($6 million), partially offset by a decrease in production in the United Kingdom ($3 million). DD&A rates increased due primarily to a proportional increase in production from higher cost properties in the United States ($105 million), Canada ($22 million) and Trinidad ($13 million), partially offset by changes in the Canadian exchange rate ($13 million).

DD&A expenses associated with other property, plant and equipment were $30 million higher in 2009 than in 2008 primarily due to increased expenditures associated with gathering and processing assets in the Fort Worth Basin Barnett Shale area ($16 million) and the Rocky Mountain area ($9 million).

G&A expenses of $248 million in 2009 were $5 million higher than 2008 due primarily to higher insurance costs ($3 million) and higher employee-related costs ($2 million).

Net interest expense of $101 million in 2009 increased $49 million from $52 million in 2008 primarily due to a higher average debt balance ($61 million), partially offset by higher capitalized interest ($12 million).

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

Gathering and processing costs increased $17 million to $58 million in 2009 compared to $41 million in 2008. The increase primarily reflects increased activities in the Fort Worth Basin Barnett Shale area ($8 million) and the Rocky Mountain area ($8 million).

Exploration costs of $170 million in 2009 decreased $24 million from $194 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the Fort Worth Basin Barnett Shale area.

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

Impairments of $306 million in 2009 increased $113 million from $193 million in 2008 primarily due to increased amortization of unproved property costs in the United States ($103 million) and increased impairments of proved properties in the United States ($32 million), partially offset by 2008 impairments in Trinidad as a result of EOG's relinquishment of its rights to Block Lower Reverse "L" (LRL) ($20 million) and in the United Kingdom for the Arthur field ($6 million). EOG recorded impairments of proved properties of $94 million and $86 million for 2009 and 2008, respectively.

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are determined based on wellhead revenues and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income in 2009 decreased $147 million to $174 million (5.1% of wellhead revenues) from $321 million (5.2% of wellhead revenues) in 2008. The decrease in taxes other than income was primarily due to decreased severance/production taxes primarily as a result of decreased wellhead revenues in the United States ($103 million), Trinidad ($13 million) and Canada ($3 million); an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions ($16 million); and lower ad valorem/property taxes in the United States ($15 million).

Other income, net was $2 million in 2009 compared to $31 million in 2008. The decrease of $29 million was primarily due to lower equity income from ammonia plants in Trinidad ($15 million), lower interest income ($8 million) and settlements received in 2008 related to the Enron Corp. bankruptcy ($3 million).

Income tax provision of $325 million in 2009 decreased $984 million compared to 2008 due primarily to decreased pretax income. The net effective tax rate for 2009 increased to 37% from 35% in 2008. The increase in the 2009 net effective tax rate is primarily as a result of higher state tax rates and the absence of 2008 tax benefits related to the impairment of LRL.

2008 compared to 2007. During 2008, operating expenses of $3,360 million were $769 million higher than the $2,591 million incurred in 2007. The following table presents the costs per Mcfe for the years ended December 31, 2008 and 2007:

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2008 compared to 2007 are set forth below.

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Lease and well expenses of $559 million in 2008 increased $107 million from $452 million in 2007 due primarily to higher operating and maintenance expenses ($78 million) and higher lease and well administrative expenses ($28 million), both in the United States.

Transportation costs of $274 million in 2008 increased $122 million from $152 million in 2007 primarily due to increased production and costs associated with marketing arrangements to transport production from the Fort Worth Basin Barnett Shale area ($64 million) and the Rocky Mountain area ($38 million) to downstream markets.

DD&A expenses in 2008 increased $261 million to $1,327 million from $1,066 million in 2007. DD&A expenses associated with oil and gas properties were $236 million higher than in 2007 primarily due to higher unit rates described below and as a result of increased production in the United States ($210 million), partially offset by a decrease in production in the United Kingdom ($10 million) and in Trinidad ($3 million). DD&A rates increased due primarily to a proportional increase in production from higher cost properties in the United States ($15 million) and Canada ($8 million). Changes in the Canadian exchange rate ($11 million) also contributed to the DD&A expense increase.

DD&A expenses associated with other property, plant and equipment were $25 million higher in 2008 than in 2007 primarily due to increased expenditures associated with natural gas gathering systems in the Fort Worth Basin Barnett Shale area.

G&A expenses of $244 million in 2008 were $38 million higher than 2007 due primarily to higher employee-related costs ($33 million). The increase in employee-related costs primarily reflects higher stock-based compensation expenses ($18 million).

Net interest expense of $52 million in 2008 increased $5 million from $47 million in 2007 primarily due to a higher average debt balance ($18 million), partially offset by higher capitalized interest ($13 million).

Gathering and processing costs increased $13 million to $41 million in 2008 as compared to $28 million in 2007. The increase primarily reflects increased activities in the Fort Worth Basin Barnett Shale and Rocky Mountain areas.

Exploration costs of $194 million in 2008 increased $44 million from $150 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($27 million) and higher employee-related costs ($15 million). The increase in geological and geophysical expenditures in the United States was primarily attributable to activities in the Fort Worth Basin Barnett Shale area ($21 million).

Impairments of $193 million in 2008 were $45 million higher than impairments of $148 million in 2007 due primarily to increased amortization costs as a result of increased leasehold acquisition expenditures in the United States ($30 million) and Canada ($12 million), an impairment in Trinidad recorded in the second quarter of 2008 as a result of EOG's relinquishment of its rights to LRL ($20 million) and an impairment in the United Kingdom for the Arthur field ($6 million), partially offset by decreased impairments in Canada ($20 million). EOG recorded impairments of proved properties of $86 million and $82 million for 2008 and 2007, respectively.

Taxes other than income in 2008 increased $113 million to $321 million (5.2% of wellhead revenues) from $208 million (5.2% of wellhead revenues) in 2007 primarily due to an increase in severance/production taxes in the United States as a result of increased wellhead revenues ($86 million), a decrease in credits taken in 2008 for Texas high cost gas severance tax rate reductions ($13 million) and increased ad valorem/property taxes as a result of higher property valuations in the United States ($20 million).

Income tax provision of $1,310 million in 2008 increased $769 million compared to 2007 due primarily to increased pretax income. The net effective tax rate for 2008 increased to 35% from 33% in 2007. The increase in the 2008 net effective tax rate is primarily due to a Canadian federal tax rate reduction in 2007.

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The primary sources of cash for EOG during the three-year period ended December 31, 2009 were funds generated from operations, net proceeds from the issuance of long-term debt, proceeds from the sale of oil and gas properties, proceeds from stock options exercised and employee stock purchase plan activity, net commercial paper borrowings and borrowings under other uncommitted credit facilities and revolving credit facilities. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; dividend payments to stockholders; repayments of debt; and redemptions of preferred stock.

Net cash used in investing activities of $3,415 million in 2009 decreased by $1,552 million from $4,967 million for the same period of 2008 due primarily to a decrease in additions to oil and gas properties ($1,542 million); a decrease in additions to other property, plant and equipment ($150 million); and favorable changes in working capital associated with investing activities ($34 million); partially offset by a decrease in proceeds from sales of assets ($172 million). Proceeds from sales of assets included net proceeds from the sale of EOG's California assets in December 2009 ($200 million) and net proceeds from the sale of EOG's Appalachian assets in February 2008 ($386 million).

Net cash provided by financing activities of $834 million in 2009 included the issuance of long-term debt ($900 million), excess tax benefits from stock-based compensation ($76 million) and proceeds from stock options exercised and employee stock purchase plan activity ($20 million). Cash used in financing activities during 2009 included cash dividend payments ($142 million), treasury stock purchases ($11 million) and debt issuance costs ($9 million).

2008 compared to 2007. Net cash provided by operating activities of $4,633 million in 2008 increased $1,732 million from $2,901 million in 2007 primarily reflecting an increase in wellhead revenues ($2,202 million); favorable changes in working capital and other assets and liabilities ($170 million); an increase in gathering, processing and marketing revenues ($91 million); and a decrease in cash paid for income taxes ($50 million); partially offset by an increase in cash operating expenses ($404 million); an increase in marketing costs ($86 million); an unfavorable change in the net cash flow from the settlement of financial commodity derivative contracts ($265 million); and an increase in cash paid for interest expense ($9 million).

Net cash used in investing activities of $4,967 million in 2008 increased by $1,511 million from $3,456 million for the same period of 2007 due primarily to an increase in additions to oil and gas properties ($1,317 million), unfavorable changes in working capital associated with investing activities ($296 million) and an increase in additions to other property, plant and equipment ($199 million), partially offset by an increase in proceeds from sales of assets ($300 million), primarily reflecting net proceeds from the sale of EOG's Appalachian assets.

Net cash provided by financing activities of $645 million in 2008 included the issuance of long-term debt ($750 million), proceeds from stock options exercised and employee stock purchase plan activity ($73 million) and excess tax benefits from stock-based compensation ($6 million). Cash used in financing activities during 2008 included cash dividend payments ($115 million), Trinidad revolving credit facility repayment ($38 million), treasury stock purchases ($18 million), debt issuance costs ($8 million) and the redemption of preferred stock ($5 million).

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The table below sets out components of total expenditures for the years ended December 31, 2009, 2008 and 2007 (in millions):

 (1) In 2009, property acquisitions includes non-cash additions of $353 million related to a property
       exchange transaction in the Rocky Mountain area and contingent consideration, with a fair value
       of $35 million, related to the acquisition of the Haynesville Assets.

Exploration and development expenditures of $3,824 million for 2009 were $1,088 million lower than the prior year due primarily to decreased drilling and facilities expenditures in the United States ($1,529 million), Canada ($44 million) and Trinidad ($41 million); decreased leasehold acquisition expenditures in Canada ($122 million); decreased geological and geophysical expenditures in the United States ($23 million); changes in the foreign currency exchange rate in Canada ($16 million); decreased property acquisition expenditures in Trinidad ($15 million), Canada ($14 million) and China ($10 million); and decreased dry hole costs in Canada ($11 million) and the United States ($4 million). These decreases were partially offset by increased property acquisition expenditures in the United States ($638 million), increased drilling and facilities expenditures in China ($41 million) and the United Kingdom ($10 million), increased leasehold acquisition expenditures in the United States ($29 million), increased capitalized interest in the United States ($15 million) and increased dry hole costs in the United Kingdom ($12 million). The 2009 exploration and development expenditures of $3,824 million include $2,082 million in development, $980 million in exploration, $707 million in property acquisitions and $55 million in capitalized interest. The decrease in expenditures for other property, plant and equipment primarily related to gathering and processing assets in the Fort Worth Basin Barnett Shale area. The 2008 exploration and development expenditures of $4,912 million include $3,612 million in development, $1,148 million in exploration, $109 million in property acquisitions and $43 million in capitalized interest. The increase in expenditures for other property, plant and equipment primarily related to gathering and processing assets in the Fort Worth Basin Barnett Shale and Rocky Mountain areas. The 2007 exploration and development expenditures of $3,568 million include $2,681 million in development, $838 million in exploration, $29 million in capitalized interest and $20 million in property acquisitions.

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

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During 2009, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $432 million, which included net realized gains of $1,278 million. During 2008, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $598 million, which included net realized losses of $137 million. See Note 11 to Consolidated Financial Statements.

Financial Collar Contracts. The total fair value of EOG's natural gas financial collar contracts at December 31, 2009 was a positive $34 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at February 25, 2010. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/MMBtu). The average floor price of EOG's outstanding natural gas financial collar contracts for 2010 is $9.34 per million British thermal units (MMBtu) and the average ceiling price is $11.54 per MMBtu.

Financial Price Swap Contracts. The total fair value of EOG's natural gas financial price swap contracts at December 31, 2009 was a positive $16 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at February 25, 2010. The average price of EOG's natural gas financial price swap contracts for 2010 is $9.21 per MMBtu.

On April 24, 2009, EOG settled its natural gas financial price swap contracts with notional volumes of 20,000 MMBtud for the July 1, 2010 to December 31, 2010 period and received proceeds of $12.1 million.

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Financial Basis Swap Contracts. Prices received by EOG for its natural gas production generally vary from New York Mercantile Exchange (NYMEX) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas financial basis swap contracts in order to fix the differential between prices in the Rocky Mountain area and NYMEX Henry Hub prices. The total fair value of EOG's natural gas financial basis swap contracts at December 31, 2009 was a negative $66 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial basis swap contracts at February 25, 2010. The weighted average price differential represents the amount of reduction to NYMEX gas prices per MMBtu for the notional volumes covered by the basis swap.