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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
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, 2008: $32,634,838,355.

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, 249,690,094 shares outstanding as of February 17, 2009.

Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2009 Annual Meeting of Stockholders to be filed within 120 days after December 31, 2008 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, Trinidad, the United Kingdom North Sea, 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 its 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, 2008, EOG's total estimated net proved reserves were 8,689 billion cubic feet equivalent (Bcfe), of which 7,339 billion cubic feet (Bcf) were natural gas reserves and 225 million barrels (MMBbl), or 1,350 Bcfe, were crude oil and condensate and natural gas liquids reserves (see "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 71% of EOG's reserves (on a natural gas equivalent basis) were located in the United States, 15% in Canada and 14% in Trinidad. As of December 31, 2008, 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, 2008, 82% of EOG's net proved United States and Canada reserves (on a natural gas equivalent basis) were natural gas and 18% 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 to its broad portfolio. The following is a summary of significant developments during 2008 and certain 2009 plans for EOG's United States and Canada operations.

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United States. EOG continues to grow production and future reserve potential in the Barnett Shale play of the Fort Worth Basin. In 2008, EOG began selling production from 410 net wells drilled during the year and grew production to a net average daily rate of 413 million cubic feet per day (MMcfd) of natural gas and 6.6 thousand barrels per day (MBbld) of crude oil and condensate and natural gas liquids. At year-end 2008, EOG's net production had increased to approximately 509 million cubic feet equivalent per day (MMcfed), and net acreage held was approximately 990,000 acres. During 2008, EOG continued to experience successful drilling in Johnson, Hill, and the western extension counties of the Barnett Shale gas play. Additionally, EOG saw successful drilling in the Barnett Combo play located in the northern portion of the Fort Worth Basin. The Barnett Combo play was previously known as the Barnett Oil play but, as a result of the wells in this play producing roughly one-third crude oil, one-third natural gas liquids and one-third natural gas, the name Combo seemed more appropriate. For 2009, EOG plans to begin selling production from approximately 260 net wells. With a focus on maximizing the recovery of hydrocarbons in place and cost reduction, EOG expects the Barnett Shale play to continue to add production and reserve growth to EOG for many years to come.

EOG significantly expanded its activities in 2008 throughout the Rocky Mountain area where it holds approximately 1.6 million net acres. During 2008, 353 net wells were drilled. In the core areas, 210 net wells were drilled in the Uinta Basin, Utah, 64 net wells were drilled in North Dakota and Montana in the Williston Basin, 45 net wells were drilled in the Moxa Arch area of Wyoming and 21 net wells were drilled in the LaBarge Platform, Wyoming. Production from the Rocky Mountain area increased 57% with this expanded drilling activity. The net average production for 2008 was 232 MMcfd of natural gas and 26.6 MBbld of crude oil and condensate and natural gas liquids. EOG ended 2008 producing approximately 24 MBbld, net of crude oil from the Bakken play in North Dakota and intends to drill over 45 net wells in the play in 2009. The majority of the production growth in the Rocky Mountain area was derived from very active drilling programs in the North Dakota Bakken and the Uinta Basin Mesaverde development plays. EOG expects to remain active in these two areas in 2009 and plans to continue its exploration program throughout the Rocky Mountain area.

In the Mid-Continent area, EOG drilled 106 net wells during 2008 in its core areas in Southwest Kansas, the Oklahoma Panhandle and the Texas Panhandle. The net average production for 2008 was 84 MMcfd of natural gas and 4.7 MBbld of crude oil and condensate which represents an 11% total production increase over 2007. EOG continued its strong exploration program in Southwest Kansas and was successful in finding several new Morrow and St. Louis plays. As part of the Hugoton-Deep play, EOG has seven years remaining on an approximately 900,000 gross acre, 10-year farm-in agreement from Anadarko Petroleum Company. In addition to its existing Cleveland Horizontal play in the Texas Panhandle, a new discovery in the Atoka formation was established and exploited in 2008. EOG holds approximately 100,000 net acres in the play. To date, 37 horizontal wells have been drilled with initial production rates up to 7.0 MMcfd of natural gas. Plans for 2009 are to continue exploiting these growth areas while pursuing other exploration prospects throughout the Mid-Continent area. EOG holds approximately 500,000 net acres in the Mid-Continent area.

EOG's South Texas and Gulf of Mexico areas had another successful year in 2008, drilling 89 net wells. South Texas and Gulf of Mexico net production averaged 207 MMcfd of natural gas and 6.8 MBbld of crude oil and condensate and natural gas liquids during 2008. 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's application of horizontal drilling technology in South Texas continues to increase, and the percentage of horizontal wells drilled in the area significantly increased in 2008. A number of additional trends will be exploited with the application of horizontal drilling in 2009. Production from two deepwater Gulf of Mexico wells, drilled in the Atwater Valley area, began in February 2008 at a peak rate of 117 MMcfd of natural gas, gross and 19 MMcfd, net to EOG. Approximately 68 net wells are planned during 2009 for South Texas and the Gulf of Mexico where EOG holds approximately 580,000 net acres.

During 2008, EOG drilled and participated in 48 net wells in the Permian Basin. Twenty-nine net wells were drilled in New Mexico, of which 20 were drilled in the Wolfcamp horizontal play, and the others were drilled in the Morrow, Bone Spring and Permo-Penn formations. Nineteen net wells were drilled in West Texas in multiple objectives. Net production averaged 79 MMcfd of natural gas and 6.8 MBbld of crude oil and condensate and natural gas liquids. Several new oil projects were identified and acreage assembled for testing in 2009. Over 330 square miles of 3-D seismic were acquired in 2008 to assist with these new projects. With the addition of 97,500 acres in 2008, EOG now has approximately 540,000 net acres in the Permian Basin. EOG expects to remain active in the Permian Basin in 2009 and will pursue several exploration prospects in these same areas.

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The Upper Gulf Coast continued to be a growth area for EOG where 2008 net production grew 6% year over year and averaged 146 MMcfd of natural gas and 3.1 MBbld of crude oil and condensate and natural gas liquids. EOG drilled 62 net wells with 36 net wells in the Cotton Valley and Travis Peak development programs located in East Texas and North Louisiana, at the Sligo, Driscoll, Appleby, and Waterman fields. Mississippi remained a growth area where 26 net wells were drilled in 2008 and horizontal development of the Selma Chalk at the Gwinville Field was also successful. EOG is further expanding horizontal drilling programs in this area with the development of approximately 116,000 net acres in the emerging Haynesville play where EOG is currently drilling its third horizontal well. EOG holds approximately 350,000 net acres in the Upper Gulf Coast area.

In February 2008, EOG completed the sale of approximately 2,400 shallow Devonian wells with net production of 17 MMcfd of natural gas in the Appalachian Basin. EOG retained the deep rights on the acreage involved in the sale. During the second half of the year, the focus was entirely on evaluating the Marcellus Shale, drilling six horizontal and three vertical wells. These wells tested acreage blocks in Bradford County, Pennsylvania, as well as blocks in the Seneca Resources Joint Venture in North Central Pennsylvania. EOG has tested wells in each of these areas that initially flowed at rates in excess of 3 MMcfd of natural gas. Plans for 2009 include the drilling of 14 gross wells (both horizontal and vertical) and developing the infrastructure necessary to market the gas from the drilling program. EOG holds approximately 220,000 net acres in this area.

At December 31, 2008, EOG held approximately 3,646,000 net undeveloped acres in the United States.

During 2008, EOG continued the growth of its gathering and processing activities in the Barnett Shale play of North Texas and the Bakken Shale play of North Dakota. In 2008, EOG placed into operation one natural gas processing plant in North Dakota, and constructed a second plant in North Texas that came online in early 2009. EOG installed an additional gathering system in the Barnett Combo play of North Texas to transport production to its processing plant and continued expansion of its system in the Bakken Shale play of North Dakota. The North Texas systems total over 70 miles of 8-inch, 10-inch and 20-inch diameter pipe, while the North Dakota system totals over 100 miles of 8-inch pipe. At year-end 2008, the combined throughput of these systems was 56 MMcfd of natural gas.

EOG expects to continue expanding these facilities to accommodate the drilling activity in the Barnett Shale and Bakken Shale plays. In the North Dakota Bakken Shale play, EOG received confirmation from the Federal Energy Regulatory Commission (FERC) on January 12, 2009, to install an approximately 80-mile, 12-inch diameter "dense phase" gas gathering pipeline connecting its Stanley, North Dakota gathering system with the Alliance Pipeline, near Upham, North Dakota, with start-up planned for the third quarter of 2009. The Alliance Pipeline transports natural gas to major markets in Chicago, Illinois. As a part of that project, EOG expects to replace its 20 MMcfd natural gas liquids processing plant, located near Stanley, North Dakota, with an 80 MMcfd refrigeration oil/condensate removal plant during the second quarter of 2009. In combination, these projects will allow EOG to efficiently transport the associated natural gas and natural gas liquids production from its Bakken oil wells.

Canada. EOG conducts operations through its subsidiary, EOG Resources Canada Inc. (EOGRC), from offices in Calgary, Alberta. During 2008, EOGRC continued with its shallow gas strategy in Western Canada, drilling a total of 474 net wells. Key producing areas are the Southeast Alberta/Southwest Saskatchewan shallow gas trends (including the Drumheller, Twining and Halkirk areas), the Pembina/Highvale area of Central Alberta, the Grande Prairie/Wapiti area of Northwest Alberta and the Waskada area of Southwest Manitoba. During 2008, increased capital was directed to oil development projects principally at the Waskada and Highvale large legacy fields, which were initially developed with vertical wells resulting in low recoveries. Horizontal drilling, coupled with specific zone targeting, along with new completion techniques, have yielded favorable results. As a result, EOG plans large field-scale redevelopments for 2009 and beyond.

In the Horn River Basin of Northeastern British Columbia, EOGRC drilled three vertical and five horizontal wells during 2008 and concluded completion operations on two horizontal wells drilled in 2007. Initial gas sales began in July 2008 and currently EOGRC has seven producing wells. Plans for 2009 include drilling seven horizontal wells to further test EOGRC's net acre position.

In 2008, total Canadian net production averaged 222 MMcfd of natural gas and 3.7 MBbld of crude oil and condensate and natural gas liquids. EOGRC plans to drill approximately 180 net wells in 2009.

At December 31, 2008, EOGRC held approximately 1,655,000 net undeveloped acres in Canada.

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

Trinidad. In November 1992, EOG, through its subsidiary, EOG Resources Trinidad Limited (EOGRT), acquired an exploration and production license in the South East Coast Consortium (SECC) Block offshore Trinidad. EOG currently has an 80% working interest in the SECC Block, except in the Deep Ibis area in which EOG's working interest decreased as a result of a farm-out agreement with BP Trinidad Tobago LLC. In the SECC Block, the Kiskadee, Ibis, Parula and Oilbird fields have been developed and are producing. Effective September 1, 2006, the Oilbird Field Unitization Agreement was executed as the Oilbird field straddles the SECC Block and the Modified U(b) Block discussed below. The license covering the SECC Block will expire in December 2029.

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

In April 2002, EOG, through its subsidiary, EOG Resources Trinidad-LRL Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for the Lower Reverse "L" (LRL) Block. In the second quarter of 2008, EOG relinquished its rights to the LRL Block.

In October 2002, EOG, through its subsidiary, EOG Resources Trinidad U(b) Block Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for the Modified U(b) Block which is adjacent to the SECC Block. EOG holds a 100% working interest in the Modified U(b) Block. As noted above, effective September 1, 2006, the Oilbird Field Unitization Agreement was executed as the Oilbird field straddles the SECC Block and the Modified U(b) Block. At October 2008, 3.7% of the original contract area has been retained for the development of the Oilbird field unit while 12.5% has been retained for further exploration.

In July 2005, EOG, through its subsidiary, EOG Resources Trinidad Block 4(a) Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for Block 4(a). EOG holds a 100% working interest in Block 4(a). In the first quarter of 2006, two successful wells were drilled on Block 4(a). EOG's subsidiary has obtained approval to develop the discovery and is currently constructing the offshore facilities. From its first discovery on Block 4(a), EOG expects to supply approximately 100 MMcfd, gross (82 MMcfd, net based on current pricing and operating assumptions) in early 2011 under a natural gas contract with the National Gas Company of Trinidad and Tobago (NGC), provided that the pipeline is completed by NGC. The contract is for a term of 15 years with a designated start date of January 1, 2010. EOG expects to begin delivery under this contract in early 2010 and shall initially source the natural gas from its existing fields until the NGC pipeline and development of Block 4(a) are completed. Since the net revenue interest is different on the existing fields, EOG's net deliveries would be 70 MMcfd, based on current pricing and operating assumptions until deliveries begin from Block 4(a).

In the first quarter of 2008, EOG, through its subsidiary, EOGRT, purchased an 80% working interest in the exploration and production license covering the Pelican field and its related facilities (Pelican License) from Trinidad and Tobago Marine Petroleum Company Limited, a subsidiary of the other participants in the SECC Block. The acquisition includes the subsurface rights, offshore facilities, the condensate transport line and the onshore storage facilities. The Pelican License will expire in December 2029.

EOG, through its subsidiary, EOGRT, 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). The shareholders' agreement governing CNCL requires the consent of the holders of 90% or more of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOGRT is able to exercise significant influence over the operating and financial policies of CNCL and, therefore, EOG accounts for the investment using the equity method. During 2008, EOG recognized equity income of $7 million and received cash dividends of $1 million from CNCL.

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EOG, through its subsidiary, EOG Resources NITRO2000 Ltd. (EOGNitro2000), owns a 10% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Nitrogen (2000) Unlimited (N2000). The shareholders' agreement governing N2000 requires the consent of the holders of 100% of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOGNitro2000 is able to exercise significant influence over the operating and financial policies of N2000 and, therefore, EOG accounts for the investment using the equity method. During 2008, EOG recognized equity income of $12 million and received cash dividends of $8 million from N2000.

Natural gas from EOG's Trinidad operations is sold to either NGC or its subsidiary under five gas sales contracts. Approximately 380 MMcfd, gross (225 MMcfd, net) are sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The remaining volumes (approximately 30 MMcfd, gross, 12 MMcfd, net) are sold under a contract for use in the Atlantic LNG Train 4 (ALNG) plant at prices partially dependent on the United States Henry Hub market prices. The pricing mechanisms for these contracts in Trinidad will remain the same in 2009.

In October 2008, EOG finalized crude oil and condensate sales contracts with the Petroleum Company of Trinidad and Tobago. The pricing terms are based on the valuation of the distillation yield of the crude oil and condensate produced less a refining margin.

In 2008, EOG's average net production from Trinidad was 218 MMcfd of natural gas and 3.2 MBbld of crude oil and condensate.

At December 31, 2008, 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.

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 are currently two producing wells in the Arthur field, one or both of which could cease production during the second half of 2009.

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 submitted a field development plan to the Department of Energy and Climate Change during the fourth quarter of 2008. EOGUK also participated in the drilling of an unsuccessful exploratory well in August 2007 on the Eos prospect located in the Southern North Sea Block 48/11c.

In the fourth quarter of 2008, EOGUK was awarded three Central North Sea operated licenses in the U.K. 25th Seaward Licensing Round. A rig was contracted to drill two operated wells in the East Irish Sea in 2009. The licenses for the East Irish Sea were awarded to EOG in 2007.

In 2008, EOG delivered net average production of 12 MMcfd of natural gas in the United Kingdom.

At December 31, 2008, EOG held approximately 249,000 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, The People's Republic of China. The acquisition includes production of approximately 9 MMcfed, net, on approximately 130,000 acres. In October 2008, EOG obtained the rights to an additional zone on the acreage purchased. EOG plans to drill its first horizontal well in 2009.

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.

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Wellhead Marketing. EOG's United States and Canada wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts based on prevailing market prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. In 2008, a large majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The remaining volumes were sold under a contract at prices partially dependent on the United States Henry Hub market prices. The pricing mechanisms for these contracts in Trinidad will remain the same in 2009. In 2008, a large majority of the wellhead natural gas volumes from the United Kingdom were sold on the spot market. The remaining volumes were sold by means of forward contracts. The marketing strategy for the wellhead natural gas volumes in the United Kingdom is expected to remain the same in 2009. In 2008, 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 2009.

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 natural gas production from third parties under buy/sell or other arrangements in order to balance firm transportation capacity with production in certain areas.

During 2008, no single purchaser accounted for 10% or more of EOG's natural gas and crude oil revenues. EOG does not believe that the loss of any single purchaser would have a material adverse effect on its financial condition or results of operations.

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The following table sets forth certain information regarding EOG's wellhead volumes of, and average prices for, natural gas per thousand cubic feet (Mcf), crude oil and condensate per barrel (Bbl) and natural gas liquids per Bbl. The table also presents natural gas equivalent volumes 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 delivered during each of the years ended December 31, 2008, 2007 and 2006.

(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.

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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 and regulations governing the plugging and abandonment of offshore wells; and the removal of all production facilities. Under certain circumstances, the MMS may require operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect EOG's interests.

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

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

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

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

EOG's natural gas gathering operations also may be, or become, subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. Additional rules and legislation pertaining to these matters are considered and/or adopted from time to time. Although 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 natural 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 natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being followed by the FERC will continue indefinitely.

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

EOG is aware of the increasing focus of local, state, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change issues. EOG is also aware of legislation proposed by United States lawmakers to reduce GHG emissions. Any direct and indirect costs of these regulations may adversely affect EOG's business, results of operations and financial condition. EOG believes that its strategy to reduce GHG emissions throughout our operations is in the best interest of the environment and a generally good business practice. EOG will continue to review the risks to its business and operations associated with all environmental matters, including climate change.

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

It is not expected that any of these controls or regulations will affect EOG'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 crude oil and natural gas 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

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royalties. Royalties payable on lands that the Crown 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 crude oil and natural 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 crude oil and natural 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, exploration wells must have a vertical depth greater than 2,000 meters with a Crown 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. The NGDDP applies to 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.

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

Spills and releases from EOG's properties may have resulted, or may result, in soil and groundwater contamination in certain locations. Such contamination is not unusual within the crude oil and natural gas industry. Any contamination found on, under or originating from the properties may be subject to remediation requirements under Canadian laws. In addition, EOG has acquired certain oil and gas properties from third parties whose actions

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with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under Canadian laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, EOG could be held responsible for oil and gas properties in which EOG owns an interest but is not the operator.

Canada is a signatory to the United Nations Framework Convention on Climate Change. 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 are expected to come into effect in 2010 and targets would be based on percentages rather than absolute reductions. The Federal Plan also proposes a credit emissions trading system. Additionally, regulation can take 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. Any direct and indirect costs of these regulations may adversely affect EOG's business, results of operations and financial condition.

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

Energy Prices. Since EOG is primarily a natural gas producer, it is more significantly impacted by changes in prices of natural gas than changes in prices of crude oil 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 30% increase in the average wellhead natural gas price for production in the United States and Canada received by EOG from 2007 to 2008, a decrease of 4% from 2006 to 2007, and a decrease of 15% from 2005 to 2006. The average New York Mercantile Exchange (NYMEX) natural gas price strip for 2009 has declined approximately 15% subsequent to December 31, 2008. Crude oil and condensate and natural gas liquids production comprised a larger portion of EOG's product mix in 2008 than in prior years and is expected to increase further in 2009. Average crude oil and condensate prices received by EOG for production in the United States increased by 27% in 2008, 10% in 2007 and 15% in 2006, each as compared to the immediately preceding year. The average NYMEX crude oil price strip for 2009 has declined approximately 10% subsequent to December 31, 2008. 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 2009 natural gas hedges, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2009 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 $17 million for net income and $25 million for operating cash flow. EOG's price sensitivity in 2009 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 $14 million for net income and $21 million for operating cash flow. For information regarding EOG's natural gas hedge position as of December 31, 2008, 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 the means to manage this price risk. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. Under Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, these physical commodity contracts qualify for the normal purchases and normal sales

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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.

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

Texas Severance Tax Rate Reduction. Natural gas production from qualifying Texas wells spudded or completed after August 31, 1996, is entitled to a reduced severance tax rate for the first 120 consecutive months of production. However, the cumulative value of the tax reduction cannot exceed 50 percent of the drilling and completion costs incurred on a well-by-well basis. For the impact on EOG, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Operating and Other Expenses.

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The current executive officers of EOG and their names and ages (as of February 25, 2009) are as follows:

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

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

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

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

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

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

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.

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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;

• domestic and international drilling activity;

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

• the availability, proximity and capacity of transportation facilities;

• worldwide economic and political conditions;

• the level and effect of trading in commodity futures markets, including 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, and the cost of such operations may increase, as a result of a variety of factors, including:

• unexpected drilling conditions;

• title problems;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions;

• compliance with environmental and other governmental requirements;

• 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.

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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 depleted. Except to the extent that we conduct successful exploration. exploitation and development activities, acquire additional properties containing proved reserves or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. 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.

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 United States (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, war and other political risks;

• increases in taxes and governmental royalties;

• renegotiation of 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.

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From time to time, we seek to acquire natural gas and crude oil properties. Although we perform reviews of properties to be acquired in a manner that we believe is consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, nor may they permit a buyer to become sufficiently familiar with the properties in order to assess fully their deficiencies and potential. Even when problems with a property are identified, we often may assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements. Moreover, there are numerous uncertainties inherent in estimating quantities of proved natural gas and crude oil reserves, actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing 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 and development activities and equipment can be adversely affected by extreme weather conditions, such as hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs, 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. Such extreme weather conditions could 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 recent credit crisis and corresponding reaction by lenders to risk and, related thereto, the recent weakness and volatility in domestic and global financial markets and economic conditions, 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. 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 recently weakened. In addition, there has been recent weakness and volatility in domestic and global financial markets,

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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 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 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 proved natural gas and liquids reserves and future net cash flows from such reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors, 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. Our actual proved reserves and future net cash flows from such reserves most likely will vary from our estimates. Any significant variance could materially and adversely affect our business, financial condition and results of operations and the trading price of our common stock.

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,

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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 natural gas and crude oil 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, financial condition and results of operations.

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. Changes in, or additions to, these regulations could materially and adversely affect our business, financial condition and results of operations.

EOG is aware of the increasing focus of local, state, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change issues. We are also aware of legislation proposed by U.S. lawmakers and by the Canadian legislature to reduce GHG emissions. EOG will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. Any direct and indirect costs of these regulations may materially and adversely affect EOG's business, results of operations and financial condition.

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.

The exploration for, and production of, natural gas and crude oil can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, injure or kill people, and damage property and the environment. Moreover, our 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

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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, 2008, approximately 11% 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 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, see "Supplemental Information to Consolidated Financial Statements."

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas, crude oil 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 depleted. 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.

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Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2008. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.

(1) EOG's China operations were acquired effective July 1, 2008.

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, 2008. Gross natural gas and crude oil wells include 2,380 with multiple completions.

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Drilling and Acquisition Activities. During the years ended December 31, 2008, 2007 and 2006, EOG expended $5.1 billion, $3.6 billion and $2.9 billion, respectively, for exploratory and development drilling and acquisition of leases and producing properties, including asset retirement obligations of $181 million, $31 million and $22 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.

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 2008.

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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.

On February 7, 2008, EOG's Board of Directors (Board) increased the quarterly cash dividend on the common stock from the previous $0.09 per share to $0.12 per share effective beginning with the dividend paid on April 30, 2008 and on July 29, 2008, increased the quarterly cash dividend on the common stock from the previous $0.12 per share to $0.135 per share effective beginning with the dividend paid on October 31, 2008.

On February 4, 2009, EOG's Board increased the quarterly cash dividend on the common stock from the previous $0.135 per share to $0.145 per share effective beginning with the dividend to be paid on April 30, 2009.

As of February 18, 2009, there were approximately 450 record holders and approximately 295,000 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 85,263 total shares for the quarter ended December 31, 2008 and the 194,761 shares for the full year 2008 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 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 2008, EOG did not repurchase any
      shares under the Board-authorized repurchase program.

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, 2003 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.

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Comparison of Five-Year Cumulative Total Returns
EOG, S&P 500 and S&P O&G E&P
(Performance Results Through December 31, 2008)

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

(1) Certain reclassifications have impacted Net Operating Revenues. See Note 1 to Consolidated Financial Statements.
(2) Year 2004 restated for two-for-one stock split effective March 1, 2005.

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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 North Sea and China. EOG operates under a consistent business and operational strategy that focuses predominantly on achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.

Net income available to common stockholders for 2008 of $2,436 million was up 125% compared to 2007 net income available to common stockholders of $1,083 million. At December 31, 2008, EOG's total reserves were 8.7 trillion cubic feet equivalent, an increase of 944 billion cubic feet equivalent (Bcfe) from December 31, 2007.

Several important developments have occurred since January 1, 2008.

United States and Canada. EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's natural gas and crude oil production. Production in the United States and Canada accounted for approximately 87% of total company production in 2008 as compared to 83% in 2007. In 2008, the Fort Worth Basin Barnett Shale and North Dakota Bakken areas produced an increasing amount of crude oil and natural gas liquids. For 2008, crude oil and natural gas liquids production accounted for approximately 19% of total company production as compared to 15% for 2007. Based on current trends, EOG expects its 2009 crude oil and natural gas liquids production to increase as compared to 2008. EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

In February 2008, EOG closed on the sale of the majority of its producing shallow gas assets and surrounding acreage in the Appalachian Basin to a subsidiary of EXCO Resources, Inc., an independent oil and gas company, for approximately $386 million ($40 million of which was received in 2007). The Appalachian area that was divested included approximately 2,400 operated wells that accounted for approximately 1% of EOG's total 2007 production and approximately 2% of its total year-end 2007 proved reserves. EOG retained certain of its undeveloped acreage in this area, including rights in the Marcellus Shale, and continued its shale exploration program in 2008.

In the third quarter of 2008, EOG commenced production in its British Columbia, Canada shale gas play. EOG holds approximately 158,000 net acres in this play at December 31, 2008 and expects to slowly increase production until 2012, when the construction of additional infrastructure for the play is expected to be completed.

International. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. In February 2008, EOG, through its subsidiary EOG Resources Trinidad Limited (EOGRT) purchased an 80% working interest in the exploration and production license covering the Pelican field and its related facilities from Trinidad and Tobago Marine Petroleum Company Limited. The acquisition includes the subsurface rights, offshore facilities, the condensate transport line and the onshore storage facilities.

In October 2008, EOG, through its subsidiaries, EOGRT, EOG Resources Trinidad-U(a) Block Limited and EOG Resources Trinidad U(b) Block Unlimited (EOGRT U(b)), finalized crude oil and condensate sales contracts with the Petroleum Company of Trinidad and Tobago. The pricing terms are based on the valuation of the distillation yield of the crude oil and condensate produced less a refining margin.

In April 2008, EOG's subsidiary, EOG Resources Trinidad-LRL Unlimited, relinquished its rights to Lower Reverse "L" Block and recorded an impairment of $20 million. In December 2008, EOG, through its subsidiaries EOGRT and EOGRT U(b), began production from the Oilbird field.

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EOG continues to expand its exploration prospect portfolio in the United Kingdom (U.K.) in addition to its ongoing production from the Valkyrie and Arthur fields in the Southern Gas Basin of the North Sea Block 23/16f. There are currently two producing wells in the Arthur field, one or both of which could cease production during the second half of 2009. During the fourth quarter of 2008, EOG recorded an impairment of $6 million ($3 million after-tax) for its Arthur field based on well performance. During 2008, a field development plan was submitted for the Columbus discovery in the Central North Sea. In the fourth quarter of 2008, EOGUK was awarded three Central North Sea operated licenses in the U.K. 25th Seaward Licensing Round. A rig was contracted to drill two operated wells in the East Irish Sea in 2009. The licenses for the East Irish Sea were awarded to EOG in 2007.

In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuanzhong Block exploration area in the Sichuan Basin, Sichuan Province, The People's Republic of China. The acquisition includes production of approximately 9 million cubic feet equivalent per day, net, on approximately 130,000 acres. In October 2008, EOG obtained the rights to additional zones on the acreage purchased. EOG plans to drill its first horizontal well in 2009.

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

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, 2008, EOG's debt-to-total capitalization ratio was 17%. During 2008, EOG funded $5.4 billion in exploration and development and other property, plant and equipment expenditures, paid $115 million in dividends to common and preferred stockholders, repaid $38 million of debt and paid $5 million for the redemption of all remaining shares of its outstanding 7.195% Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 liquidation preference per share (Series B), primarily by utilizing cash provided from its operating activities, proceeds from long-term debt borrowings and proceeds from the sale of its Appalachian assets.

For 2009, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.1 billion, excluding acquisitions. United States and Canada crude oil and natural gas drilling activity continues to be a key component of these expenditures. EOG intends to manage the 2009 capital budget in order to balance expenditures with operating cash flows. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

On September 30, 2008, EOG completed its public offering of $400 million aggregate principal amount of 6.125% Senior Notes due 2013 and $350 million aggregate principal amount of 6.875% Senior Notes due 2018 (collectively, Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning April 1, 2009. Net proceeds from the offering of approximately $743 million were used for general corporate purposes, including repayment of outstanding commercial paper and borrowings under other uncommitted credit facilities.

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The following review of operations for each of the three years in the period ended December 31, 2008 should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning with page F-1.

During 2008, net operating revenues increased $2,888 million, or 68%, to $7,127 million from $4,239 million in 2007. Total wellhead revenues, which are revenues generated from sales of EOG's production of natural gas, crude oil and condensate and natural gas liquids, increased $2,202 million, or 55%, to $6,222 million from $4,020 million in 2007. During 2008, EOG recognized net gains on mark-to-market commodity derivative contracts of $598 million compared to net gains of $93 million in 2007. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party natural gas and natural gas liquids as well as gathering fees associated with gathering third-party natural gas, increased $91 million, or 124%, to $165 million in 2008 from $74 million in 2007. Other, net operating revenues in 2008 primarily consist of the gain of $128 million on the sale of the Appalachian assets in February 2008. The following review of operations gives effect to the reclassifications discussed in Note 1 to Consolidated Financial Statements.

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Wellhead volume and price statistics for the years ended December 31, 2008, 2007 and 2006 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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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 the 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.

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

Gathering, processing and marketing revenues represent sales of third-party natural gas and natural gas liquids as well as gathering fees associated with gathering third-party natural gas. For the years ended December 31, 2008, 2007 and 2006, substantially all of such revenues were related to sales of third-party natural gas. Marketing costs represent the costs of purchasing third-party natural gas and the associated transportation costs.

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.

2007 compared to 2006. Wellhead natural gas revenues in 2007 increased $240 million, or 9%, to $3,033 million from $2,793 million in 2006 due to increased natural gas deliveries ($277 million), partially offset by a lower composite average wellhead natural gas price ($37 million). The composite average wellhead natural gas price decreased to $5.65 per Mcf in 2007 from $5.72 per Mcf in 2006.

Natural gas deliveries increased 133 MMcfd, or 10%, to 1,470 MMcfd in 2007 from 1,337 MMcfd in 2006. The increase was due to higher production of 154 MMcfd in the United States, partially offset by lower production of 12 MMcfd in Trinidad, 7 MMcfd in the United Kingdom and 2 MMcfd in Canada. The increase in the United States was primarily attributable to increased production from Texas (119 MMcfd), the Rocky Mountain area (13 MMcfd), Kansas (13 MMcfd) and Mississippi (10 MMcfd). The decline in Trinidad was due to reduced 2007 deliveries to ALNG (10 MMcfd) and a decrease in contractual demand (2 MMcfd). During 2006, EOG supplied gas for use in ALNG's start-up phase. In 2007, ALNG remained in the start-up phase, but did not require any gas from EOG until May 2007 when ALNG reached commercial status and EOG began supplying gas under the ALNG take-or-pay contract. The decrease in production in the United Kingdom was a result of production declines in both the Arthur and Valkyrie fields.

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

Natural gas liquids revenues increased $73 million, or 53%, to $210 million in 2007 from $137 million in 2006, due to increases in deliveries ($42 million) and a higher composite average price ($31 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale and South Texas areas.

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

Gathering, processing and marketing revenues less marketing costs in 2007 increased $4 million to $7 million in 2007 from $3 million in 2006 primarily as a result of increased natural gas marketing operations in the Gulf Coast area.

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 as compared to 2007 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 crude oil and natural gas wells, the cost of workovers, and lease and well administrative expenses. Operating and maintenance expenses include, among other expenses, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are costs of operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses of $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.

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

Transportation costs of $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 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 natural gas gathering and processing facilities, compressors, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

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 represent operation and maintenance expenses and administrative expenses associated with operating EOG's natural gas gathering and processing assets.

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 include amortization of unproved leases, as well as impairments under Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144), which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $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 SFAS No. 144 related impairment in Trinidad as a result of EOG's relinquishment of its rights to Lower Reverse "L" Block ($20 million) and an SFAS No. 144 related

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impairment in the United Kingdom for the Arthur field ($6 million), partially offset by decreased SFAS No. 144 related impairments in Canada ($20 million). Under SFAS No. 144, EOG recorded impairments of $86 million and $82 million for 2008 and 2007, respectively.

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

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.

2007 compared to 2006. During 2007, operating expenses of $2,591 million were $566 million higher than the $2,025 million incurred in 2006. The following table presents the costs per Mcfe for the years ended December 31, 2007 and 2006:

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 2007 as compared to 2006 are set forth below.

Lease and well expenses of $452 million in 2007 were $96 million higher than 2006 due primarily to higher operating and maintenance expenses in the United States ($53 million) and Canada ($13 million), higher lease and well administrative expenses ($17 million), higher workover expenditures in the United States ($7 million) and changes in the Canadian exchange rate ($7 million).

Transportation costs of $152 million in 2007 were $52 million higher than 2006 due primarily to increased production in the Fort Worth Basin Barnett Shale Play and related costs associated with new marketing arrangements to transport the increased production to new downstream markets.

DD&A expenses in 2007 increased $248 million to $1,066 million from $817 million in 2006. DD&A expenses associated with oil and gas properties were $235 million higher than in 2006 primarily due to higher unit rates described below and as a result of increased production in the United States ($117 million), partially offset by a decrease in production in the United Kingdom ($5 million). DD&A rates increased due primarily to a proportional increase in production from higher cost properties in the United States ($93 million), Canada ($18 million) and in the United Kingdom ($2 million). Changes in the exchange rates in Canada ($10 million) and in the United Kingdom ($1 million) also contributed to the DD&A expense increase.

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DD&A expenses associated with other property, plant and equipment were $13 million higher in 2007 than in 2006 primarily due to increased expenditures associated with natural gas gathering systems in the Fort Worth Basin Barnett Shale area.

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

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

Gathering and processing costs increased $10 million to $28 million in 2007 as compared to 2006. The increase primarily reflects increased activity in the Fort Worth Basin Barnett Shale area.

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

Impairments of $148 million in 2007 were $39 million higher than 2006 due primarily to increased SFAS No. 144 related impairments ($27 million) and increased amortization of unproved leases in the United States ($7 million), the United Kingdom ($3 million) and Canada ($3 million). The increase in SFAS No. 144 related impairments is due to an increase in Canada ($15 million) primarily related to the Northwest Territories discovery (see Note 16 to Consolidated Financial Statements) and an increase in the United States ($12 million). Under SFAS No. 144, EOG recorded impairments of $82 million and $55 million for 2007 and 2006, respectively.

Taxes other than income in 2007 increased $7 million to $208 million (5.2% of wellhead revenues) from $201 million (5.6% of wellhead revenues) in 2006. Severance/production taxes increased primarily due to increased wellhead revenues in the United States ($27 million) and Trinidad ($2 million), partially offset by increased credits taken for Texas high cost gas severance tax rate reductions ($26 million). Ad valorem/property taxes increased primarily due to higher property valuation in Canada ($2 million).

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

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

The primary sources of cash for EOG during the three-year period ended December 31, 2008 were funds generated from operations, the issuance of long-term debt, proceeds from stock options exercised and employee stock purchase plan activity, proceeds from the sale of oil and gas properties, excess tax benefits from stock-based compensation, 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; repayments of debt; dividend payments to stockholders; redemptions of preferred stock and debt issuance costs.

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).

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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 was $645 million in 2008 compared to $386 million in 2007. Cash provided by financing activities for 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).

2007 compared to 2006. Net cash provided by operating activities of $2,901 million in 2007 increased $305 million compared to 2006 primarily reflecting an increase in wellhead revenues ($466 million); a decrease in cash paid for income taxes ($157 million); and an increase in gathering, processing and marketing revenues ($44 million); partially offset by an increase in cash operating expenses ($172 million); an increase in marketing costs ($40 million); a decrease in the net cash flows from settlement of financial commodity derivative contracts ($87 million); and unfavorable changes in working capital and other assets and liabilities ($65 million).

Net cash used in investing activities of $3,456 million in 2007 increased by $745 million compared to 2006 due primarily to an increase in additions to oil and gas properties ($652 million) and an increase in additions to other property, plant and equipment ($177 million), partially offset by an increase in proceeds from sales of assets ($63 million).

Net cash provided by financing activities was $386 million in 2007 compared to net cash used in financing activities of $316 million in 2006. Cash provided by financing activities for 2007 included the issuance of long-term debt ($600 million), proceeds from stock options exercised and employee stock purchase plan activity ($55 million), excess tax benefits from stock-based compensation ($27 million) and Trinidad revolving credit facility borrowings ($10 million). Cash used in financing activities for 2007 included repayments of long-term borrowings ($158 million), cash dividend payments ($84 million), redemptions of preferred stock ($51 million), treasury stock purchases ($8 million) and debt issuance costs ($5 million).

The table below sets out components of total expenditures for the years ended December 31, 2008, 2007 and 2006, along with the total expenditures budgeted for 2009, excluding acquisitions (in millions):

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Exploration and development expenditures of $4,912 million for 2008 were $1,344 million higher than the prior year due primarily to increased drilling and facilities expenditures of $1,014 million resulting from higher drilling and facilities expenditures in the United States ($1,064 million), increased lease acquisitions in the United States ($143 million) and Canada ($96 million), increased producing property acquisitions in the United States ($66 million) and Canada ($12 million), increased geological and geophysical expenditures in the United States ($27 million) primarily attributable to the Fort Worth Basin Barnett Shale Play ($21 million), higher exploration employee-related costs ($15 million) and increased capitalized interest in the United States ($11 million). These increases were partially offset by decreased dry hole costs in the United States ($40 million) and Trinidad ($20 million). The 2008 exploration and development expenditures of $4,912 million includes $3,612 million in development, $1,148 million in exploration, $109 million in producing property acquisitions and $43 million in capitalized interest. The increase in expenditures for other property, plant and equipment primarily related to natural gas gathering systems and processing plants in the Fort Worth Basin Barnett Shale and Rocky Mountain areas. The 2007 exploration and development expenditures of $3,568 million includes $2,681 million in development, $838 million in exploration, $29 million in capitalized interest and $20 million in producing property acquisitions. The increase in expenditures for other property, plant and equipment primarily related to gathering systems and processing plants in the Fort Worth Basin Barnett Shale and Rocky Mountain areas. The 2006 exploration and development expenditures of $2,905 million includes $2,159 million in development, $704 million in exploration, $22 million in producing property acquisitions and $20 million in capitalized interest.

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

During 2008, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $598 million, which included realized losses of $137 million. During 2007, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $93 million, which included realized gains of $128 million. See Note 11 to Consolidated Financial Statements.

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Financial Collar Contracts. The total fair value of EOG's natural gas financial collar contracts at December 31, 2008 was a positive $44 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at February 25, 2009. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/MMBtu). The average floor price of EOG's outstanding natural gas financial collar contracts for 2010 is $10.00 per million British thermal units (MMBtu) and the average ceiling price is $12.32 per MMBtu.

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Financial Price Swap Contracts. The total fair value of EOG's natural gas financial price swap contracts at December 31, 2008 was a positive $805 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, 2009. The notional volumes are expressed in MMBtud and prices are expressed in $/MMBtu. The average price of EOG's natural gas financial price swap contracts for 2009 is $9.71 per MMBtu and for 2010 is $9.87 per MMBtu.