ITEM 1. Business

General

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

At December 31, 2010, EOG's total estimated net proved reserves were 1,950 million barrels of oil equivalent (MMBoe), of which 386 million barrels (MMBbl) were crude oil and condensate reserves, 152 MMBbl were natural gas liquids reserves and 8,470 billion cubic feet (Bcf), or 1,412 MMBoe, were natural gas reserves (see Supplemental Information to Consolidated Financial Statements). At such date, approximately 82% of EOG's reserves (on a crude oil equivalent basis) were located in the United States, 11% in Canada and 7% in Trinidad. As of December 31, 2010, EOG employed approximately 2,290 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 and maximizing reserve recoveries. 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 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.

Business Segments

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

Exploration and Production

United States and Canada Operations

EOG's operations are focused on most of the productive basins in the United States and Canada, with a current focus on liquids-rich plays.

At December 31, 2010, 30% of EOG's net proved United States and Canada reserves (on a crude oil equivalent basis) were crude oil and condensate and natural gas liquids and 70% were natural gas reserves. Substantial portions of these reserves are in long-lived fields with well-established production characteristics. EOG believes that opportunities exist to increase production through continued development in and around many of these fields and through the utilization of the applicable technologies described above. EOG also maintains an active exploration program designed to extend fields and add new trends and resource plays to its broad portfolio. The following is a summary of significant developments during 2010 and certain 2011 plans for EOG's United States and Canada operations.

United States. In April 2010, EOG announced its acreage holdings in the Eagle Ford play and in May 2010, EOG opened an office in San Antonio, Texas, to focus on more fully exploiting its 595,000 net acres in the Eagle Ford play. The Eagle Ford has distinguished itself among other resource plays in the United States as it has crude oil, wet gas and dry gas trends. The economics of the crude oil and wet gas trends make this play one of the most impactful resource plays in the United States under current economic conditions. EOG holds 520,000 net acres in the crude oil trend and 26,000 net acres in the wet gas trend. EOG significantly increased its activity in this play during 2010, drilling 96 net wells and completing 80 net wells with 12 rigs running at year-end. At year-end, the net daily production was approximately 17.3 thousand barrels per day (MBbld) of crude oil and condensate and natural gas liquids and 13.7 million cubic feet per day (MMcfd) of natural gas. EOG will focus its attention in 2011 on exploitation and development of the Eagle Ford play by drilling approximately 250 net wells and on the delineation of the full extent of our large oil-rich acreage position.

In 2010, EOG increased activity in the liquids-rich Barnett Shale Combo play of the Fort Worth Basin where production grew by approximately 230% above 2009 levels. During the year, EOG completed 184 net Barnett Combo wells and increased its drilling potential in this liquids-rich play by expanding the core area from approximately 90,000 net acres to 175,000 net acres. EOG also completed 166 net Barnett gas wells. EOG's total 2010 Barnett Shale average net daily production increased to approximately 23.2 MBbld of crude oil and condensate and natural gas liquids and 404 MMcfd of natural gas. For 2011, EOG will continue to focus on growing liquids production from the Barnett Combo with plans to complete to sales an additional 262 net Barnett Combo wells. EOG's activity in the natural gas portion of the Barnett will significantly decrease during 2011 with plans to complete approximately 24 net gas wells to sales. With a large acreage position of approximately 600,000 net acres in the Fort Worth Basin Barnett Shale and a history of strong drilling results, EOG plans to continue significant drilling for years in the future.

Throughout the Rocky Mountain area, EOG continued its focus on exploring and developing its crude oil properties. During 2010, EOG increased its development program in the Williston Basin by drilling 111 net wells in the Bakken and Three Forks plays, while increasing its acreage position to 600,000 net acres available for exploration and development. EOG currently holds approximately 2.0 million net acres in the Rocky Mountain area. Exploration and development activities increased in the Niobrara Formation in both the DJ (Colorado and Wyoming) and North Park (Colorado) Basins with 31 net wells drilled. In 2010, EOG drilled 76 net wells on its Uinta Basin natural gas acreage, a decrease from the prior year. Overall during 2010, EOG drilled 222 net wells throughout the Rocky Mountain area. Total production increased 3% primarily through a 20% increase in liquids production. The net average production for 2010 was 41.5 MBbld of crude oil and condensate and natural gas liquids and 212 MMcfd of natural gas. For 2011, EOG intends to maintain its activity level in the Bakken and Three Forks plays of the Williston Basin, along with further exploration and development of its Niobrara acreage position in the DJ, North Park and Powder River Basins. Our primary focus remains on exploiting and expanding our crude oil resource positions and drilling activity will remain limited on our core natural gas assets within the Rocky Mountain area. EOG plans to drill approximately 159 net wells throughout the Rocky Mountain area during 2011.

In 2010, EOG continued to expand its activities in the Mid-Continent area with continued growth and extension of the Western Anadarko Basin and Hugoton Deep core areas. For the year, EOG averaged net production of 5.8 MBbld of crude oil and condensate and natural gas liquids and 60 MMcfd of natural gas. Total crude oil and condensate and natural gas liquids volumes increased 9% in 2010 compared to 2009. In Southwest Kansas, EOG continued to focus on high potential targets in the Morrow and St. Louis formations in a broad area, which is part of the 900,000 gross acres EOG controls in the Hugoton Deep play. In the Western Anadarko Basin, EOG continued successful horizontal exploitation of the Cleveland sandstone, drilling 14 net wells with initial per-well production rates of approximately 350 barrels of oil per day (Bbld), gross. Since 2002, EOG has drilled over 220 net wells in this play and holds approximately 65,000 acres throughout the trend. In addition, EOG made new discoveries in both the Marmaton Sandstone and Cherokee Skinner formations. A total of 16 net wells were drilled in 2010 in these formations with initial per-well production rates averaging 450 Bbld, gross. These new liquids-rich plays will be exploited by drilling approximately 32 net wells in 2011. EOG holds approximately 720,000 net acres in the Mid-Continent area.

In 2010, EOG drilled 34 net wells in the Permian Basin to test the Leonard-Avalon Shale, Bone Spring, Wolfcamp and Wolfberry formations. EOG is well positioned in three of these emerging plays: the Leonard-Avalon Shale and Bone Spring plays in the Delaware Basin and the Wolfcamp Shale play in the Midland Basin. Production for the year 2010 averaged 7.8 MBbld, net, of crude oil and condensate and natural gas liquids and 62 MMcfd, net, of natural gas. EOG now holds approximately 540,000 net acres throughout the Permian Basin, with approximately 120,000 acres within the Wolfcamp Shale formation and 120,000 acres within the limits of the Bone Spring and Leonard-Avalon formations. In 2011, EOG plans to continue the development, expansion and enhancement of the Wolfcamp, Leonard-Avalon and Bone Spring plays, while continuing to acquire strategic acreage positions to test new play concepts. Approximately 52 net Permian Basin wells are planned during 2011.

In the South Texas area, EOG drilled 48 net wells in 2010. Net production during 2010 averaged 6.8 MBbld of crude oil and condensate and natural gas liquids and 171 MMcfd of natural gas. EOG's activity was focused in Webb, Zapata, San Patricio, Nueces, Brooks and Kenedy Counties. EOG continued exploitation of the Lobo and Roleta sands, adding net reserves of 0.9 MMBbl of crude oil and condensate and natural gas liquids and 25.4 Bcf of natural gas. EOG continued developing reserves at Indian Point and East White Point under the Nueces Bay. EOG also exploited the liquids-rich Frio and Vicksburg trends in Brooks and Kenedy Counties, drilling 14 net wells in this 310,000 gross acre area which includes surrounding counties. EOG holds approximately 550,000 net acres in South Texas. Approximately 61 net wells are planned during 2011 for South Texas.

In the Upper Gulf Coast region, EOG drilled 63 net wells and averaged 206 MMcfd of natural gas and 2.6 MBbld of crude oil and condensate and natural gas liquids production in 2010. The Haynesville and Bossier Shale plays located near the Texas-Louisiana border were major growth drivers for EOG. The program has grown from drilling 13 net wells in 2009 to 53 net wells in 2010. EOG established a new Texas "sweet spot" in 2010 with exceptional well results, including numerous wells where initial production rates exceeded 20 MMcfd of natural gas. EOG now controls 183,000 net acres in this play and most of this acreage is within a well-defined production sweet spot. EOG holds approximately 390,000 net acres in the Upper Gulf Coast region. Approximately 45 net wells are planned during 2011 for the Upper Gulf Coast region.

During 2010, EOG continued the development of its Pennsylvania Marcellus Shale acreage, drilling a total of 33 net wells, including 18 net wells in Bradford County in northeast Pennsylvania which will be completed in 2011. The remaining 15 net wells were drilled in North Central Pennsylvania as part of EOG's joint venture with Seneca Resources Corporation. EOG holds a 50% working interest and is operator of this joint venture. Most of these joint venture wells have been completed and are producing. Several wells were turned to sales at rates in excess of 8 MMcfd, a substantial improvement from previous years. This rate increase is attributable to new completion procedures that were implemented in 2010. During 2010, EOG's production from the Marcellus Shale averaged 12 MMcfd, net. In 2011, EOG will continue to develop the Marcellus Shale by drilling an estimated 30 net wells. Those wells will be split between the joint venture area and Bradford County. EOG currently holds in excess of 200,000 net acres in the Pennsylvania Marcellus Shale.

At December 31, 2010, EOG held approximately 4.4 million net undeveloped acres in the United States.

During 2010, EOG continued the expansion of its gathering and processing activities in the Barnett Shale play of North Texas and the Bakken and Three Forks plays of North Dakota. In the Barnett Combo play, EOG expanded its natural gas processing plant capacity from 40 MMcfd to 80 MMcfd. EOG also continued its expansion of its Barnett Shale gathering system to transport production to its processing plant.

In the North Dakota Bakken play, EOG continued the expansion of its gathering system in the Bakken Core area, and committed to a third-party gatherer for the installation of a gathering system for its Bakken Lite area. The Bakken Lite system is expected to become operational in mid-2011. During February 2010, EOG placed in service a 76-mile, 12-inch diameter "dense phase" natural gas gathering pipeline connecting its Stanley, North Dakota, condensate recovery plant and gathering system with the Alliance Pipeline, near Upham, North Dakota. The Alliance Pipeline transports natural gas to the Chicago, Illinois, area.

At year-end 2010, the combined throughput of these gathering systems was approximately 80 MMcfd of natural gas. EOG expects to continue expanding its gathering and processing facilities to accommodate the drilling activity in the Barnett Shale and Bakken plays. The North Texas systems total over 80 miles of 8-inch, 10-inch and 20-inch diameter pipe, while the North Dakota system totals over 320 miles of 8-inch and 12-inch pipe.

Additionally, in support of its operations in the Williston Basin, EOG continued to increase usage of its crude oil loading facility near Stanley, North Dakota, transporting both its production and third-party production. Using this facility, EOG loaded 148 unit trains with crude oil for transport to Stroud, Oklahoma during 2010. Each unit train typically consists of 100 cars and has a total aggregate capacity of approximately 68,000 barrels of crude oil. In Stroud, Oklahoma, EOG owns a crude oil offloading facility and a pipeline to transport the crude oil to the Cushing, Oklahoma, trading hub. These facilities are now fully operational, with a capacity to transport approximately 70 MBbld of crude oil. As a part of these facilities, EOG also owns and operates approximately 24 miles of 8-inch and 12-inch crude oil pipeline.

Canada. EOG conducts operations through its wholly-owned subsidiary, EOG Resources Canada Inc. (EOGRC), from its offices in Calgary, Alberta. During 2010, EOGRC continued its focus on horizontal crude oil growth, mainly through its drilling activity in Waskada, Manitoba, and Highvale, Alberta, and on bigger target horizontal natural gas in the Horn River Basin of British Columbia. During 2010, EOGRC drilled or participated in 114 net wells, 108 of which were horizontal wells and six of which were vertical wells. Correspondingly, net crude oil and condensate and natural gas liquids production increased by 47% to 7.6 MBbld and net natural gas production decreased 11% to 200 MMcfd. The natural gas production volume decline also reflects the sales of several shallow gas properties consummated in the fourth quarter of 2010. EOG received proceeds of approximately $344 million from these sales transactions. The focus on crude oil production growth will continue in 2011 with 85 net wells planned in a combination of plays from the continued development in Manitoba and new targets in Alberta. EOG plans to drill four wells in the Horn River Basin in 2011.

During the second quarter of 2010, EOGRC agreed to acquire all of the outstanding common stock of Galveston LNG Inc., a Calgary-based corporation which, through its wholly-owned subsidiary, Kitimat LNG Inc. and affiliates, owns 49 percent of the planned liquefied natural gas (LNG) export terminal to be located at Bish Cove, near the Port of Kitimat, about 405 miles north of Vancouver, British Columbia. Planned capacity of the proposed Kitimat LNG terminal is about 700 million cubic feet of natural gas per day or five million metric tons of LNG per year. Preliminary total construction costs, currently estimated to be approximately $3 billion (Canadian), will be revised at the conclusion of front-end engineering and design. In addition, Galveston LNG Inc. also owns a 24.5 percent interest in the proposed Pacific Trail Pipelines (PTP), a total estimated $1 billion (Canadian), 300-mile project, originating at Summit Lake, British Columbia. The pipeline is intended to link Western Canada's natural gas producing regions to the Kitimat LNG terminal. An affiliate of Apache Corporation owns 51 percent of the planned Kitimat LNG terminal and a 25.5 percent interest in PTP and will be the operator of the Kitimat LNG terminal. During the fourth quarter of 2010, upon the achievement of certain commercial and regulatory milestones, EOGRC paid $210 million to complete the acquisition of Galveston LNG Inc. In connection with the acquisition, EOG recorded intangible assets related to certain leases, permits and other contracts. During the first quarter of 2011, EOGRC entered into an agreement to purchase an additional 24.5 percent interest in PTP for $24.5 million (subject to customary closing conditions). A portion of the purchase price ($14.7 million) will be paid at closing with the remaining amount ($9.8 million) to be paid contingent on the decision to proceed with the construction of the Kitimat LNG terminal. Subsequent to closing, EOGRC's ownership interest will be 49 percent. An affiliate of Apache Corporation entered into an agreement to purchase the remaining 25.5 percent interest in PTP, which will increase its ownership interest to 51 percent of the proposed project.

At December 31, 2010, EOGRC held approximately 1.3 million net undeveloped acres in Canada.

Operations Outside the United States and Canada

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

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

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

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

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

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

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

Several fields in the SECC Block, Modified U(a) Block and Modified U(b) Block, as well as the Pelican Field, have been developed and are producing. In the Pelican Field, EOG drilled a successful exploratory well that began producing in the first quarter of 2010. In Block 4(a), EOG completed installation of offshore facilities and began its development drilling program in December 2010 to supply natural gas under a contract with the National Gas Company of Trinidad and Tobago (NGC) into the North Eastern Offshore (NEO) pipeline being installed by NGC. EOG is sourcing the natural gas for this contract from its existing fields until the NEO pipeline is completed. Sales under the contract commenced on January 1, 2010.

Given EOG's current level of equity ownership in CNCL and N2000 and its ability to exercise significant influence over certain material actions, it accounts for these investments using the equity method. During 2010, EOG recognized equity income of $5 million and received cash dividends of $6 million from CNCL and recognized equity income of $8 million and received cash dividends of $10 million from N2000.

Natural gas from EOG's Trinidad operations currently is sold to NGC or its subsidiary. Certain agreements with NGC require EOG's Trinidad operations to deliver approximately 500 MMcfd (345 MMcfd, net) of natural gas, under current economic conditions, for at least the next three years. EOG intends to fulfill these natural gas delivery obligations by using production from existing reserves. Crude oil and condensate from EOG's Trinidad operations currently is sold to the Petroleum Company of Trinidad and Tobago.

In 2010, EOG's average net production from Trinidad was 341 MMcfd of natural gas and 4.7 MBbld of crude oil and condensate.

At December 31, 2010, EOG held approximately 39,000 net undeveloped acres in Trinidad.

United Kingdom. EOG's subsidiary, EOG Resources United Kingdom Limited (EOGUK), owns a 25% non-operating working interest in a portion of Block 49/16f, located in the Southern Gas Basin of the North Sea. During 2010, production continued in the Valkyrie field in the Southern Gas Basin.

EOGUK also owns 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. The last well in the Arthur Field ceased production in 2010.

In 2006, EOGUK participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f. EOG has a 25% non-operating interest in this block. A successful Columbus prospect appraisal well was drilled during the third quarter of 2007. The field operator expects to submit a revised field development plan to the U.K. Department of Energy and Climate Change (DECC) during the second quarter of 2011 and anticipates receiving approval of this plan by the end of 2011. The operator and partners are currently negotiating processing and transportation terms with export infrastructure owners.

In 2009, EOGUK drilled a successful exploratory well in its East Irish Sea blocks. Well 110/12-6, in which EOGUK has a 100% working interest, was an oil discovery and was designated the Conwy field. In 2010, EOGUK added an adjoining field in its East Irish Sea block, designated Corfe, to its overall development plans. During 2010, feasibility and front-end engineering design studies were completed, and all principal contracts are currently being negotiated for the development plan. A field development plan for the Conwy field was submitted to the DECC in the first quarter of 2011 and a separate plan is expected to be submitted for the Corfe field before the end of the first quarter of 2011. Regulatory approval of both plans is expected by the end of 2011. Installation of pipelines, drilling of development wells and initial production are planned for 2012. Two additional exploratory wells offsetting the Conwy field were drilled in the first quarter of 2010. Both wells were unsuccessful. The licenses for the East Irish Sea blocks were awarded to EOGUK in 2007.

In 2010, production averaged 4 MMcfd of natural gas, net, in the United Kingdom.

At December 31, 2010, EOG held approximately 190,000 net undeveloped acres in the United Kingdom.

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

During 2010, EOG drilled four horizontal wells, one of which was completed in 2010 and another which was completed in January 2011. In addition, EOG completed a horizontal well that was originally drilled in 2009. The wells completed in 2010 began production in the first and second quarters of 2010. EOG plans to complete two wells during the second quarter of 2011. EOG expects to complete its evaluation of the economic viability of this project during the first half of 2011.

In 2010, production averaged 10 MMcfd of natural gas, net, in China.

At December 31, 2010, EOG held approximately 130,000 net acres in China.

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

Marketing

Wellhead Marketing. 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 2010, EOG's United States and Canada wellhead natural gas production was sold on the spot market and under long-term natural gas contracts based on prevailing market prices. In many instances, the long-term contract prices closely approximated the prices received for natural gas sold on the spot market. In 2011, the pricing mechanism for such production is expected to remain the same.

In 2010, 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 are expected to remain the same in 2011.

In 2010, all wellhead natural gas volumes from the United Kingdom were sold on the spot market. The 2011 marketing strategy for the wellhead natural gas volumes from the United Kingdom is expected to remain the same.

In 2010, 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 2011.

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

During 2010, no single purchaser accounted for 10% or more of EOG's crude oil and condensate, natural gas liquids and natural gas 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.

Wellhead Volumes and Prices

The following table sets forth certain information regarding EOG's wellhead volumes of, and average prices for, crude oil and condensate, natural gas liquids and natural gas. The table also presents crude oil equivalent volumes which are determined using the ratio of 1.0 Bbl of crude oil and condensate or natural gas liquids to 6.0 Mcf of natural gas for each of the years ended December 31, 2010, 2009 and 2008.

Year Ended December 31	2010		2009		2008
Crude Oil and Condensate Volumes (MBbld) (1)
United States		63.2		47.9		39.5
Canada		6.7		4.1		2.7
Trinidad		4.7		3.1		3.2
Other International (2)		0.1		0.1		0.1
Total		74.7		55.2		45.5
Natural Gas Liquids Volumes (MBbld) (1)
United States		29.5		22.5		15.0
Canada		0.9		1.1		1.0
Total		30.4		23.6		16.0
Natural Gas Volumes (MMcfd) (1)
United States		1,133		1,134		1,162
Canada		200		224		222
Trinidad		341		273		218
Other International (2)		14		14		17
Total		1,688		1,645		1,619
Crude Oil Equivalent Volumes (MBoed) (3)
United States		281.5		259.4		248.4
Canada		40.9		42.6		40.6
Trinidad		61.5		48.5		39.5
Other International (2)		2.5		2.4		2.8
Total		386.4		352.9		331.3

Total MMBoe (3)		141.1		128.8		121.3

Average Crude Oil and Condensate Prices ($/Bbl) (4)
United States	$	74.88	$	54.42	$	87.68
Canada		72.66		57.72		89.70
Trinidad		68.80		50.85		92.90
Other International (2)		73.11		53.07		99.30
Composite		74.29		54.46		88.18
Average Natural Gas Liquids Prices ($/Bbl) (4)
United States	$	41.68	$	30.03	$	53.33
Canada		43.40		30.49		54.77
Composite		41.73		30.05		53.42
Average Natural Gas Prices ($/Mcf) (4)
United States	$	4.30	$	3.72	$	8.22
Canada		3.91		3.85		7.64
Trinidad		2.65		1.73		3.58
Other International (2)		4.90		4.34		8.18
Composite		3.93		3.42		7.51

(1) Thousand barrels per day or million cubic feet per day, as applicable.

(2) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.

(3) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

(4) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 11 to Consolidated Financial Statements).

Competition

EOG competes with major integrated oil and gas companies, government-affiliated 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 contract personnel (including geologists, geophysicists, engineers and other specialists) required to explore for, develop, produce and market crude oil and natural gas. Moreover, many of EOG's competitors have financial and other resources substantially greater than those EOG possesses and have established strategic long-term positions and strong governmental relationships in countries in which EOG may seek new or expanded entry. As a consequence, EOG may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights. In addition, many of EOG's larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. EOG also faces competition, to a lesser extent, from competing energy sources, such as liquefied natural gas imported into the United States from other countries, and alternative energy sources.

Regulation

United States Regulation of Crude Oil and Natural Gas Production. Crude oil and natural gas production operations are subject to various types of regulation, including regulation in the United States by federal and state 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 Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) (formerly, the Minerals Management Service), 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 BOEMRE.

BLM and BOEMRE 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 BOEMRE). Such offshore operations are subject to numerous regulatory requirements, including the need for prior BOEMRE approval for exploration, development and production plans; stringent engineering and construction specifications applicable to offshore production facilities; regulations restricting the flaring or venting of production; regulations governing the plugging and abandonment of offshore wells; and the removal of all production facilities. Under certain circumstances, the BOEMRE may require operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect EOG's interests.

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

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

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

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

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

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

In addition, each province has regulations that govern land tenure, royalties, production rates and other matters. The royalty system in Canada is a significant factor in the profitability of 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 royalties. Royalties payable on lands that the government has an interest in are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the federal and provincial governments of Canada have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing our revenues, earnings and cash flow.

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 crude oil and natural gas exploration, development and production operations. These laws and regulations 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 and, under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. 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. 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. Moreover, EOG is subject to the U.S. Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG) emissions and may in the future, as discussed further below, be subject to federal, state and local laws and regulations regarding hydraulic fracturing.

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

Climate Change. EOG is aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions, EOG is also aware of legislation proposed by United States lawmakers to reduce GHG emissions and a recent U.S. EPA rulemaking that may result in the regulation of GHGs as pollutants under the federal Clean Air Act. EOG supports efforts to understand and address the contribution of human activities to global climate change through the application of sound scientific research and analysis. Moreover, EOG believes that its strategy to reduce GHG emissions throughout its operations is in the best interest of the environment and a generally good business practice.

EOG has developed a system that is utilized in calculating GHG emissions from its operating facilities. This emissions management system calculates emissions based on recognized regulatory methodologies, where applicable, and on commonly accepted engineering practices. EOG is now reporting GHG emissions for facilities covered under the U.S. EPA's Mandatory Reporting of Greenhouse Gases Rule published on October 30, 2009. EOG is unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's business, results of operations, financial condition and competitive position.

Hydraulic Fracturing. There have been various proposals to regulate hydraulic fracturing at the federal level. Hydraulic fracturing technology, which has been used by the oil and gas industry for more than 60 years and is constantly being enhanced, enables EOG to produce crude oil and natural gas that would otherwise not be recovered. Specifically, hydraulic fracturing is a process in which pressurized fluid is pumped into underground formations to create tiny fractures or spaces that allow crude oil and natural gas to flow from the reservoir into the well so that it can be brought to the surface. The makeup of the fluid used in the hydraulic fracturing process is typically more than 99% water and sand, and less than 1% highly diluted chemical additives; lists of the chemical additives most typically used in fracturing fluids are available to the public via internet websites and in other publications sponsored by industry trade associations and through state agencies in those states that require the reporting of fracturing fluids. While the majority of the sand remains underground to hold open the fractures, a significant percentage of the water and chemical additives flow back and are then either recycled or safely disposed of at sites that are approved and permitted by the appropriate regulatory authorities. EOG regularly conducts audits of these disposal facilities to ensure compliance with all applicable regulations. Hydraulic fracturing generally takes place thousands of feet underground, a considerable distance below any drinking water aquifers, and there are impermeable layers of rock between the area fractured and the water aquifers.

Currently, the regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. Any new federal regulations that may be imposed on hydraulic fracturing could result in additional permitting and disclosure requirements (such as the reporting and public disclosure of the chemical additives used in the fracturing process) and in additional operating restrictions. In addition to these federal proposals, some states and local governments have considered imposing various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Such federal and state permitting and disclosure requirements and operating restrictions and conditions could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing.

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

Environmental Regulation - Canada. All phases of the oil and gas industry in Canada are subject to environmental regulation pursuant to a variety of Canadian federal, provincial and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances to the environment. These laws and regulations also require that facility sites and other properties associated with EOG's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and approval of environmental assessments or permit applications.

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

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

As noted above, EOG is aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. Canada is a signatory to the United Nations Framework Convention on Climate Change (also known as the Kyoto Protocol). The Canadian federal government has indicated an intention to work with the United States to regulate industrial emissions of GHG and air pollutants from a broad range of industrial sectors, with a stated goal to reduce Canada's total GHG emissions by 17% from 2005 levels by 2020. In addition, regulation of GHG emissions in Canada takes place at the provincial and municipal level. For example, the Alberta Government regulates GHG emissions under the Climate Change and Emissions Management Act, the Specified Gas Reporting Regulation, which imposes GHG emissions reporting requirements, and the Specified Gas Emitters Regulation, which imposes GHG emissions limits. British Columbia regulates GHG emissions under the Greenhouse Gas Reduction Targets Act, the Greenhouse Gas Reduction (Cap and Trade) Act, which imposes hard caps on GHG emissions, and the Reporting Regulation, which requires mandatory reporting of GHG emissions. In addition, the Government of Manitoba recently committed to moving forward with legislation enabling the creation of a cap and trade system to reduce GHG emissions in Manitoba.

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.

EOG is unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, including those regarding climate change and hydraulic fracturing, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's business, results of operations, financial condition and competitive position. EOG will continue to review the risks to its business and operations associated with all environmental matters, including climate change and hydraulic fracturing. In addition, EOG will continue to monitor and assess any new policies, legislation, regulations and treaties in the areas where it operates to determine the impact on its operations and take appropriate actions, where necessary.

Other Matters

Energy Prices. EOG is a crude oil and natural gas producer and is impacted by changes in prices for crude oil and condensate, natural gas liquids and natural gas. Crude oil and condensate and natural gas liquids production comprised a larger portion of EOG's production mix in 2010 than in prior years and is expected to comprise an even larger portion in 2011. Average crude oil and condensate prices received by EOG for production in the United States and Canada increased by 37% in 2010, decreased by 38% in 2009 and increased by 28% in 2008, each as compared to the immediately preceding year. The average New York Mercantile Exchange (NYMEX) crude oil strip price for 2011 has increased approximately 3% subsequent to December 31, 2010. 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 13% increase in the average wellhead natural gas price received by EOG for production in the United States and Canada in 2010, a decrease of 54% in 2009 and an increase of 30% in 2008, each as compared to the immediately preceding year. The average NYMEX natural gas strip price for 2011 has decreased by approximately 9% since December 31, 2010. 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 crude oil and condensate, natural gas liquids, natural gas, ammonia and methanol prices in the future. For additional discussion regarding changes in crude oil and natural gas prices and the risks that such changes may present to EOG, see ITEM 1A. Risk Factors.

Including the impact of EOG's 2011 crude oil hedges and based on EOG's tax position, EOG's price sensitivity in 2011 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the related change in natural gas liquids price, is approximately $26 million for net income and $38 million for cash flows from operating activities. Including the impact of EOG's 2011 natural gas hedges, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2011 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf increase or decrease in wellhead natural gas price is approximately $19 million for net income and $28 million for cash flows from operating activities. For information regarding EOG's crude oil and natural gas hedge positions as of December 31, 2010, 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 crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily collar, price swap and basis swap contracts, as a means to manage this price risk. See Note 11 to Consolidated Financial Statements. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. Under the provisions of the Derivatives and Hedging Topic of the Accounting Standards Codification, these physical commodity contracts qualify for the normal purchases and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices. For a summary of EOG's financial commodity derivative contracts at February 24, 2011, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Derivative Transactions. For a summary of EOG's financial commodity derivative contracts at December 31, 2010, see Note 11 to Consolidated Financial Statements.

All of EOG's crude oil and natural gas activities are subject to the risks normally incident to the exploration for, and development and production of, crude oil and natural gas, including blowouts, rig and well explosions, cratering, fires and loss of well control, each of which could result in damage to life, property and/or the environment. EOG's onshore and offshore operations are also subject to usual customary perils, including hurricanes and other adverse weather conditions. Moreover, EOG's activities are subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance.

Insurance is maintained by EOG against some, but not all, of these risks in accordance with what EOG believes are customary industry practices and in amounts and at costs that EOG believes to be prudent and commercially practicable. Specifically, EOG maintains commercial general liability and excess liability coverage provided by third-party insurers for bodily injury or death claims resulting from an incident involving EOG's onshore or offshore operations (subject to policy terms and conditions). Moreover, in the event an incident with respect to EOG's onshore or offshore operations results in negative environmental effects, EOG maintains operators extra expense coverage provided by third-party insurers for obligations, expenses or claims that EOG may incur from such an incident, including obligations, expenses or claims in respect of seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions). In the specific event of a well blowout or out-of-control well resulting in negative environmental effects, such operators extra expense coverage would be EOG's primary coverage, with the commercial general liability and excess liability coverage referenced above also providing certain coverage to EOG. With regard to offshore operations, all of EOG's offshore drilling activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors. The indemnification and other risk allocation provisions included in such contracts are negotiated on a contract-by-contract basis and are each based on the particular circumstances of the services being provided and the anticipated operations.

In addition to the above-described risks, EOG's operations outside the United States are subject to certain risks, including increases in taxes and governmental royalties, changes in laws and policies governing the operations of foreign-based companies, expropriation of assets, unilateral or forced renegotiation or modification of existing contracts with governmental entities and currency restrictions and exchange rate fluctuations. 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 natural gas wells spudded or completed after August 31, 1996 is entitled to a reduced severance tax rate for the first 120 consecutive months of production. However, the cumulative value of the tax reduction cannot exceed 50 percent of the drilling and completion costs incurred on a well-by-well basis. For a discussion of the impact on EOG, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Operating and Other Expenses.

Executive Officers of the Registrant

The current executive officers of EOG and their names and ages (as of February 24, 2011) are as follows:

Name	Age	Position

Mark G. Papa	64	Chairman of the Board and Chief Executive Officer; Director

Loren M. Leiker	57	Senior Executive Vice President, Exploration

Gary L. Thomas	61	Senior Executive Vice President, Operations

William R. Thomas	58	Senior Executive Vice President, Exploitation

Fredrick J. Plaeger, II	57	Senior Vice President and General Counsel

Timothy K. Driggers	49	Vice President and Chief Financial Officer

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

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

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

William R. Thomas was elected Senior Executive Vice President, Exploitation in February 2011. He was elected Senior Vice President and General Manager of EOG's Fort Worth, Texas office in June 2004 and was subsequently named Executive Vice President and General Manager of EOG's Fort Worth, Texas office in February 2007. Mr. Thomas joined a predecessor of EOG in January 1979.

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 officer. Mr. Driggers joined EOG in October 1999.

EOG - Eog Resources, Inc.