Edgar Filing: EOG RESOURCES INC

eogform10-k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-9743

EOG RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware		47-0684736
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: 713-651-7000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, par value $0.01 per share	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None.

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

Yes o No x

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

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

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

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

Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. Common Stock aggregate market value held by non-affiliates as of June 30, 2010: $24,920,717,309.

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, 254,279,287shares outstanding as of February 18, 2011.

Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2011 Annual Meeting of Stockholders to be filed within 120 days after December 31, 2010 are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

Page

PART I

ITEM 1.	Business	1
	General	1
	Business Segments	1
	Exploration and Production	1
	Marketing	6
	Wellhead Volumes and Prices	7
	Competition	8
	Regulation	8
	Other Matters	12
	Executive Officers of the Registrant	13
ITEM 1A.	Risk Factors	14
ITEM 1B.	Unresolved Staff Comments	20
ITEM 2.	Properties	21
	Oil and Gas Exploration and Production - Properties and Reserves	21
ITEM 3.	Legal Proceedings	24

PART II

ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and
	Issuer Purchases of Equity Securities	25
ITEM 6.	Selected Financial Data	28
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	49
ITEM 8.	Financial Statements and Supplementary Data	49
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	49
ITEM 9A.	Controls and Procedures	49
ITEM 9B.	Other Information	49

PART III

ITEM 10.	Directors, Executive Officers and Corporate Governance	50
ITEM 11.	Executive Compensation	50
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	50
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	51
ITEM 14.	Principal Accounting Fees and Services	51

PART IV

ITEM 15.

Exhibits, Financial Statement Schedules

SIGNATURES

(i)

PART I

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.

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 herein, including the consolidated financial statements and the related notes. Unless the context requires otherwise, "we," "us" and "our" refer to EOG Resources, Inc. and its subsidiaries.

A substantial or extended decline in crude oil or natural gas prices would have a material and adverse effect on us.

Prices for crude oil and natural gas fluctuate widely. Among the factors that can cause these price fluctuations are:

·	the level of consumer demand;

·	supplies of crude oil and natural gas;

·	weather conditions and changes in weather patterns;

·	domestic and international drilling activity;

·	the availability, proximity and capacity of transportation facilities;

·	worldwide economic and political conditions;

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

·	the nature and extent of governmental regulation and taxation, including environmental regulations;

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

·	the effect of worldwide energy conservation measures.

Our cash flow and results of operations depend to a great extent on the prevailing prices for crude oil and natural gas. Prolonged or substantial declines in crude oil and/or natural gas 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 crude oil and natural gas prices in the future such that the future cash flow from our crude oil and natural gas properties falls below the net book value of our properties, we may be required to write down the value of our crude oil and natural gas 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 crude oil and natural gas wells is a high-risk activity and subjects us to a variety of risks that we cannot control.

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

Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled, the cost of such operations may increase and/or our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:

·	unexpected drilling conditions;

·	title problems;

·	pressure or irregularities in formations;

·	equipment failures or accidents;

·	adverse weather conditions and changes in weather patterns;

·	compliance with, or changes in, environmental laws and regulations relating to air emissions, waste disposal and hydraulic fracturing, laws and regulations imposing conditions and restrictions on drilling and completion operations and other laws and regulations, such as tax laws and regulations;

·	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, crude oil hauling trucks and qualified drivers and related facilities and equipment to gather, process, compress, transport and market crude oil, natural gas and related commodities; and

·	costs of, or shortages or delays in the availability of, drilling rigs, pressure pumping equipment and supplies, tubular materials, water resources, disposal facilities, qualified personnel and other necessary equipment, supplies and services.

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.

Our ability to sell and deliver our crude oil and natural gas production could be materially and adversely affected if we fail to obtain adequate gathering, processing, compression and transportation services.

The sale of our crude oil and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of, 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.

If we fail to acquire or find sufficient additional reserves over time, our reserves and production will decline from their current levels.

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

We incur certain costs to comply with government regulations, particularly regulations relating to environmental protection and safety, and could incur even greater costs in the future.

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

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

We are 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, we are also aware of legislation proposed by U.S. lawmakers and by the Canadian federal and provincial governments to reduce GHG emissions.

Additionally, there have been various proposals to regulate hydraulic fracturing at the federal level. 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 the possible federal regulation of hydraulic fracturing, 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 the 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. For additional discussion regarding climate change and hydraulic fracturing, see Environmental Regulation – United States and Environmental Regulation – Canada under ITEM 1. Business – Regulation.

We will continue to monitor and assess any new policies, legislation, regulations and treaties in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. We are unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations and financial condition.

A portion of our crude oil and natural gas production may be subject to interruptions that could have a material and adverse effect on us.

A portion of our crude oil and natural gas 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 crude oil or natural gas 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.

We have limited control over the activities on properties we do not operate.

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.

If we acquire crude oil and natural gas properties, our failure to fully identify existing and potential problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.

From time to time, we seek to acquire crude oil and natural gas properties. Although we perform reviews of properties to be acquired in a manner that we believe is duly diligent and 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 crude oil and natural gas reserves (as discussed further below), 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.

We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms, if at all.

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

The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material and adverse effect on us.

We have various customers for the crude oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including several financial institutions and affiliates of financial institutions. Domestic and global economic conditions, including the financial condition of financial institutions generally, have weakened in recent years and remain relatively weak. In addition, there continues to be weakness and volatility in domestic and global financial markets relating to the credit crisis in recent years, 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 crude oil, natural gas 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.

Competition in the oil and gas exploration and production industry is intense, and many of our competitors have greater resources than we have.

We compete 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. In addition, many of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions and strong governmental relationships in countries in which we may seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. We also face competition, to a lesser extent, from competing energy sources, such as liquefied natural gas imported into the U.S. from other countries, and alternative energy sources.

Reserve estimates depend on many interpretations and assumptions that may turn out to be inaccurate. Any significant inaccuracies in these interpretations and assumptions could cause the reported quantities of our reserves to be materially misstated.

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

To prepare estimates of our economically recoverable liquids and natural gas reserves and future net cash flows from our reserves, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, many of which factors are or may be beyond our control. Our actual reserves and future net cash flows from such reserves most likely will vary from our estimates. Any significant variance, including any significant revisions to our existing reserve estimates, could materially and adversely affect our business, financial condition and results of operations and, in turn, the trading price of our common stock. For related discussion, see ITEM 2. Properties – Oil and Gas Exploration and Production – Properties and Reserves.

Weather and climate may have a significant and adverse impact on us.

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

In addition, our exploration, exploitation and development activities and equipment can be adversely affected by extreme weather conditions, such as winter storms and 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. Such 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 services. Such extreme weather conditions and changes in weather patterns may materially and adversely affect our business and, in turn, our financial condition and results of operations.

Our hedging activities may prevent us from benefiting fully from increases in crude oil and natural gas prices and may expose us to other risks, including counterparty risk.

We use derivative instruments (primarily financial collars, price swaps and basis swaps) to hedge the impact of fluctuations in crude oil and natural gas 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 crude oil and natural gas 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.

We operate in other countries and, as a result, are subject to certain political, economic and other risks.

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

·	increases in taxes and governmental royalties;

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

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

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

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

We do not insure against all potential losses and could be materially and adversely affected by unexpected liabilities or unexpected levels of liability.

The exploration for, and production and transportation of, crude oil and natural gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, result in injury or death, and damage property and the environment. Moreover, our onshore and offshore operations are subject to customary perils, including hurricanes and other adverse weather conditions. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. The occurrence of any of these events and any costs or liabilities incurred as a result of such events, if uninsured or in excess of our insurance coverage, would reduce the funds available to us for our exploration, exploitation, 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 depend to a significant extent upon the continued service and performance of our management team.

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.

Unfavorable currency exchange rate fluctuations could adversely affect our results of operations.

The reporting currency for our financial statements is the U.S. dollar. However, certain of our subsidiaries are located in countries other than the U.S. and have functional currencies other than the U.S. dollar. The assets, liabilities, revenues and expenses of certain of these foreign subsidiaries are denominated in currencies other than the U.S. dollar. To prepare our consolidated financial statements, we must translate those assets, liabilities, revenues and expenses into U.S. dollars at then-applicable exchange rates. Consequently, increases and decreases in the value of the U.S. dollar versus other currencies will affect the amount of these items in our consolidated financial statements, even if the amount has not changed in the original currency. These translations could result in changes to our results of operations from period to period. For the fiscal year ended December 31, 2010, approximately 8% of our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.

Terrorist activities and military and other actions could materially and adversely affect us.

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

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties

Oil and Gas Exploration and Production - Properties and Reserves

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

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 crude oil and condensate, natural gas liquids and natural gas 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 crude oil and natural gas properties declines as reserves are produced. Except to the extent EOG acquires additional properties containing proved reserves, conducts successful exploration, exploitation and development activities or, through engineering studies, identifies additional behind-pipe zones or secondary recovery reserves, the proved reserves of EOG will decline as reserves are produced. The volumes to be generated from future activities of EOG are therefore highly dependent upon the level of success in finding or acquiring additional reserves. For related discussion, see ITEM 1A. Risk Factors. EOG's estimates of reserves filed with other federal agencies agree with the information set forth in Supplemental Information to Consolidated Financial Statements.

Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2010. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.

		Developed		Undeveloped		Total
		Gross	Net	Gross	Net	Gross	Net

United States		1,787,931	1,325,254	6,187,339	4,403,325	7,975,270	5,728,579
Canada		1,225,970	1,024,942	1,318,441	1,258,372	2,544,411	2,283,314
Trinidad		72,951	64,336	48,520	38,816	121,471	103,152
United Kingdom		9,143	2,674	218,242	189,515	227,385	192,189
China		130,546	130,546	-	-	130,546	130,546
	Total	3,226,541	2,547,752	7,772,542	5,890,028	10,999,083	8,437,780

Most of our oil and gas leases, particularly in the United States, are subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. Company-wide, approximately 1,045,713 net acres will expire in 2011, 1,407,179 net acres will expire in 2012 and 1,092,688 net acres will expire in 2013 if production is not established or we take no other action to extend the terms of the leases or concessions. In the ordinary course of business, based on our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future.

Producing Well Summary. The following table reflects EOG’s ownership in producing crude oil and natural gas wells at December 31, 2010. EOG operated 15,951 gross and 14,114 net producing crude oil and natural wells. Gross crude oil and natural gas wells include 2,386 wells with multiple completions.

		Crude Oil		Natural Gas		Total
		Gross	Net	Gross	Net	Gross	Net

United States		2,198	1,497	8,360	6,578	10,558	8,075
Canada		607	503	7,009	6,334	7,616	6,837
Trinidad		13	10	22	18	35	28
United Kingdom		-	-	1	-	1	-
China		-	-	24	24	24	24
	Total	2,818	2,010	15,416	12,954	18,234	14,964

Drilling and Acquisition Activities. During the years ended December 31, 2010, 2009 and 2008, EOG expended $5.5 billion, $3.9 billion and $5.1 billion, respectively, for exploratory and development drilling and acquisition of leases and producing properties, including asset retirement obligations of $72 million, $84 million and $181 million, respectively. The following tables set forth the results of the gross crude oil and natural gas wells drilled and completed for the years ended December 31, 2010, 2009 and 2008:

			Gross Developed Wells Completed				Gross Exploratory Wells Completed
			Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2010
	United States		589	448	32	1,069	19	8	10	37
	Canada		128	25	-	153	1	-	-	1
	Trinidad		-	-	-	-	-	1	-	1
	United Kingdom		-	-	-	-	-	-	3	3
	China		-	-	-	-	-	2	-	2
		Total	717	473	32	1,222	20	11	13	44

2009
	United States		195	407	26	628	22	23	7	52
	Canada		38	60	-	98	3	-	-	3
	United Kingdom		-	-	-	-	1	-	1	2
		Total	233	467	26	726	26	23	8	57

2008
	United States		193	1,002	50	1,245	37	37	9	83
	Canada		30	496	-	526	-	7	-	7
		Total	223	1,498	50	1,771	37	44	9	90

The following tables set forth the results of the net crude oil and natural gas wells drilled and completed for the years ended December 31, 2010, 2009 and 2008:

			Net Developed Wells Completed				Net Exploratory Wells Completed
			Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2010
	United States		459	374	29	862	16	7	10	33
	Canada		128	25	-	153	1	-	-	1
	Trinidad		-	-	-	-	-	1	-	1
	United Kingdom		-	-	-	-	-	-	3	3
	China		-	-	-	-	-	2	-	2
		Total	587	399	29	1,015	17	10	13	40

2009
	United States		143	351	22	516	14	17	6	37
	Canada		38	48	-	86	3	-	-	3
	United Kingdom		-	-	-	-	1	-	1	2
		Total	181	399	22	602	18	17	7	42

2008
	United States		145	820	47	1,012	19	31	9	59
	Canada		26	441	-	467	-	7	-	7
		Total	171	1,261	47	1,479	19	38	9	66

EOG participated in the drilling of wells that were in progress at the end of the period as set out in the table below for the years ended December 31, 2010, 2009 and 2008:

		Wells in Progress at end of Period
		2010		2009		2008
		Gross	Net	Gross	Net	Gross	Net

United States		243	205	277	239	218	187
Canada		1	1	5	4	3	3
Trinidad		-	-	1	1	-	-
United Kingdom		3	2	1	-	2	1
China		4	4	4	4	-	-
	Total	251	212	288	248	223	191

EOG acquired wells, which includes the acquisition of additional interests in certain wells in which EOG previously owned an interest, as set out in the tables below for the years ended December 31, 2010, 2009 and 2008:

			Gross Acquired Wells			Net Acquired Wells
			Crude Oil	Natural Gas	Total	Crude Oil	Natural Gas	Total
2010
	Canada		1	-	1	1	-	1
		Total	1	-	1	1	-	1

2009
	United States		133	579	712	126	243	369
	Canada		-	2	2	-	1	1
		Total	133	581	714	126	244	370

2008
	United States		1	14	15	1	13	14
	Canada		-	66	66	-	59	59
	Trinidad		8	-	8	6	-	6
	China		-	22	22	-	22	22
		Total	9	102	111	7	94	101

All of EOG's drilling activities are conducted on a contractual basis with independent drilling contractors. EOG does not own drilling equipment. EOG's other property, plant and equipment primarily includes gathering, transportation and processing infrastructure assets which support EOG's exploration and production activities.

ITEM 3. Legal Proceedings

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.

PART II

ITEM 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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

		Price Range
		High		Low		Dividend Declared

2010
	First Quarter	$	100.44	$	86.78	$	0.155
	Second Quarter		114.95		93.28		0.155
	Third Quarter		108.47		85.42		0.155
	Fourth Quarter		102.06		86.00		0.155

2009
	First Quarter	$	72.83	$	45.03	$	0.145
	Second Quarter		79.12		53.09		0.145
	Third Quarter		84.43		60.29		0.145
	Fourth Quarter		101.76		79.37		0.145

On February 17, 2011, EOG's Board of Directors (Board) increased the quarterly cash dividend on the common stock from the current $0.155 per share to $0.16 per share effective beginning with the dividend to be paid on April 29, 2011 to stockholders of record as of April 15, 2011.

As of February 15, 2011, there were approximately 1,800 record holders and approximately 163,000 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.

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

Period	(a) Total Number of Shares Purchased (1)		(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (2)

October 1, 2010 - October 31, 2010		6,476	$	98.38		-		6,386,200
November 1, 2010 - November 30, 2010		2,628		92.91		-		6,386,200
December 1, 2010 - December 31, 2010		1,258		91.89		-		6,386,200
Total		10,362		96.21

(1)

The 10,362 total shares for the quarter ended December 31, 2010 and the 115,120 shares for the full year 2010 consist solely of shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock or restricted stock unit grants or (ii) in payment of the exercise price of employee stock options. These shares do not count against the 10 million aggregate share repurchase authorization of EOG's Board discussed below.

(2)	In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During 2010, EOG did not repurchase any shares under the Board-authorized repurchase program.

Comparative Stock Performance

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, 2005 in each of the following: Common Stock of EOG, the S&P 500 and the S&P O&G E&P.

2. Dividends are reinvested.

Comparison of Five-Year Cumulative Total Returns*

EOG, S&P 500 and S&P O&G E&P

(Performance Results Through December 31, 2010)

*Cumulative total return assumes reinvestment of dividends.

	2005		2006		2007		2008		2009		2010
EOG	$	100.00	$	85.38	$	122.57	$	91.91	$	135.44	$	127.99
S&P 500	$	100.00	$	113.62	$	117.63	$	72.36	$	89.33	$	100.75
S&P O&G E&P	$	100.00	$	104.65	$	151.15	$	98.91	$	140.55	$	153.58

ITEM 6. Selected Financial Data

(In Thousands, Except Per Share Data)

Year Ended December 31	2010		2009		2008		2007		2006
Statement of Income Data:
Net Operating Revenues	$	6,099,896	$	4,786,959	$	7,127,143	$	4,239,303	$	3,928,641
Operating Income	$	523,319	$	970,841	$	3,767,185	$	1,648,396	$	1,903,553

Net Income	$	160,654	$	546,627	$	2,436,919	$	1,089,918	$	1,299,885
Preferred Stock Dividends		-		-		443		6,663		10,995
Net Income Available to Common Stockholders	$	160,654	$	546,627	$	2,436,476	$	1,083,255	$	1,288,890
Net Income Per Share Available to Common Stockholders
Basic	$	0.64	$	2.20	$	9.88	$	4.45	$	5.33
Diluted	$	0.63	$	2.17	$	9.72	$	4.37	$	5.24
Dividends Per Common Share	$	0.62	$	0.58	$	0.51	$	0.36	$	0.24
Average Number of Common Shares
Basic		250,876		248,996		246,662		243,469		241,782
Diluted		254,500		251,884		250,542		247,637		246,100

At December 31	2010		2009		2008		2007		2006
Balance Sheet Data:
Total Property, Plant and Equipment, Net	$	18,680,900	$	16,139,225	$	13,657,302	$	10,429,254	$	7,944,047
Total Assets		21,624,233		18,118,667		15,951,226		12,088,907		9,402,160
Long-Term Debt and Current Portion of Long-Term Debt		5,223,341		2,797,000		1,897,000		1,185,000		733,442
Total Stockholders' Equity		10,231,632		9,998,042		9,014,497		6,990,094		5,599,671

ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Overview

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

Net income available to common stockholders for 2010 totaled $161 million as compared to $547 million for 2009. At December 31, 2010, EOG's total estimated net proved reserves were 1,950 million barrels of oil equivalent (MMBoe), an increase of 154 MMBoe from December 31, 2009.

Operations

Several important developments have occurred since January 1, 2010.

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 crude oil and natural gas production. EOG has placed an emphasis on applying its horizontal drilling expertise gained in natural gas resource plays to unconventional crude oil reservoirs. In 2010, EOG focused its efforts on developing its existing North American crude oil and condensate and natural gas liquids acreage and capturing additional North American horizontal crude oil plays. During 2010, the North Dakota Bakken and Fort Worth Basin Barnett Shale areas produced an increased amount of crude oil and condensate and natural gas liquids as compared to 2009. EOG holds approximately 520,000 net acres in the mature oil window of the Eagle Ford Shale Play near San Antonio, Texas, where it drilled 96 net wells and completed 80 net wells in 2010. EOG averaged 15.1 thousand barrels per day (MBbld) of crude oil and condensate and natural gas liquids production in this play in December 2010 and expects crude oil production from this play to continue to grow in 2011. In Canada, EOG departed from its historical vertical shallow natural gas drilling program to focus on bigger target horizontal natural gas growth in the Horn River Basin and horizontal crude oil growth within existing legacy fields, mainly in Waskada, Manitoba and Highvale, Alberta. In addition, EOG continues to evaluate certain potential exploration and development prospects. Production in the United States and Canada accounted for approximately 83% of total company production in 2010 as compared to 86% in 2009. For 2010, crude oil and condensate and natural gas liquids production accounted for approximately 27% of total company production as compared to 22% for 2009. Based on current trends, EOG expects its 2011 crude oil and condensate and natural gas liquids production to increase both in total and as a percentage of total company production as compared to 2010. EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

During the second quarter of 2010, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (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. Such intangible assets are included in Other Assets on the Consolidated Balance Sheets. 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.

As previously reported, EOG began marketing its Canadian shallow natural gas assets in July 2010. In the fourth quarter of 2010, EOG closed on transactions with three separate parties to sell these assets for approximately $344 million, including an estimate of customary adjustments under each respective sales agreement. EOG recorded a pretax impairment of $280 million to adjust the shallow natural gas assets sold to estimated fair value less estimated cost to sell. These assets represented approximately 4% of EOG's total 2009 production and approximately 3% of EOG's total year-end 2009 proved reserves. In addition, EOG received proceeds of approximately $329 million from the sale in 2010 of non-core producing properties and acreage, primarily in the Rocky Mountain area, Texas and Pennsylvania.

International. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (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.

In the United Kingdom (U.K.), EOG has ongoing production from the Valkyrie field in the Southern Gas Basin of the North Sea Block 49/16f. The last well in the Arthur field ceased production in 2010.

In 2006, EOG Resources United Kingdom Limited (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 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.

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.

Capital Structure

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. EOG's debt-to-total capitalization ratio was 34% and 22% at December 31, 2010 and 2009, respectively. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

During 2010, EOG funded $6.0 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement costs and non-cash acquisition costs), paid $153 million in dividends to common stockholders and purchased $11 million of treasury stock in connection with stock compensation plans, primarily by utilizing cash provided from its operating activities, proceeds from long-term debt borrowings described below and proceeds of $673 million from the sale of certain North American assets.

On November 23, 2010, EOG completed its public offering of $400 million aggregate principal amount of 2.500% Senior Notes due 2016 (2016 Notes), $750 million aggregate principal amount of 4.100% Senior Notes due 2021 (2021 Notes) (together, the Fixed Rate Notes) and $350 million aggregate principal amount of Floating Rate Senior Notes due 2014 (the Floating Rate Notes). Interest on the Fixed Rate Notes is payable semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2011. Interest on the Floating Rate Notes is payable quarterly in arrears on February 3, May 3, August 3 and November 3 of each year, beginning on February 3, 2011 and is based on the three-month London InterBank Offering Rate (LIBOR) plus 0.75% per annum. The interest rate on the Floating Rate Notes resets quarterly on the interest payment dates. Net proceeds from the offering of approximately $1,487 million were used for general corporate purposes, including the repayment of outstanding commercial paper borrowings. Contemporaneously with the offering of the Floating Rate Notes, EOG entered into an interest rate swap to fix the interest rate on the Floating Rate Notes at 1.87%.

On September 10, 2010, EOG entered into a second $1.0 billion unsecured Revolving Credit Agreement with domestic and foreign lenders (2010 Agreement). The 2010 Agreement matures on September 10, 2013 (subject to EOG's option to extend, on up to two occasions, the term for successive one-year periods). See Note 2 to Consolidated Financial Statements.

On May 20, 2010, EOG completed its public offering of $500 million aggregate principal amount of 2.95% Senior Notes due 2015 and $500 million aggregate principal amount of 4.40% Senior Notes due 2020 (together, Notes). Interest on the Notes is payable semi-annually in arrears on June 1 and December 1 of each year, beginning on December 1, 2010. Net proceeds from the offering of approximately $990 million were used for general corporate purposes, including the repayment of outstanding commercial paper borrowings.

The total anticipated 2011 capital expenditures are $6.4 to $6.6 billion, excluding acquisitions. The majority of 2011 expenditures will be focused on United States and Canada crude oil drilling activity and, to a lesser extent, natural gas drilling activity in the Haynesville, Marcellus and British Columbia Horn River Basin plays to hold acreage. EOG expects capital expenditures to be greater than cash flow from operating activities for 2011. EOG's business plan includes selling certain non-core natural gas assets in 2011 to partially cover the anticipated shortfall. However, EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its revolving credit facilities and equity and debt offerings.

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.

Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2010 should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning with page F-1.

Net Operating Revenues

During 2010, net operating revenues increased $1,313 million, or 27%, to $6,100 million from $4,787 million in 2009. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, natural gas liquids and natural gas, in 2010 increased $1,482 million, or 44%, to $4,881 million from $3,399 million in 2009. During 2010, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $62 million compared to net gains of $432 million in 2009. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as gathering fees associated with gathering third-party natural gas, in 2010 increased $503 million, or 123%, to $910 million from $407 million in 2009. Gains on property dispositions, net, of $224 million in 2010 primarily consist of gains on property dispositions in the Rocky Mountain area. Gains on property dispositions, net, in 2009 primarily consist of a pretax gain of $390 million realized on an exchange of properties in the Rocky Mountain area and a pretax gain of $146 million realized on the sale of EOG's California assets.

Wellhead volume and price statistics for the years ended December 31, 2010, 2009 and 2008 were as follows:

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

Average Crude Oil and Condensate Prices ($/Bbl) (3)
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

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

Average Natural Gas Liquids Prices ($/Bbl) (3)
United States	$	41.68	$	30.03	$	53.33
Canada		43.40		30.49		54.77
Composite		41.73		30.05		53.42

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

Average Natural Gas Prices ($/Mcf) (3)
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

Crude Oil Equivalent Volumes (MBoed) (4)
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 (4)		141.1		128.8		121.3

(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)	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).

(4)

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. Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of 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.

2010 compared to 2009. Wellhead crude oil and condensate revenues in 2010 increased $909 million, or 83%, to $1,999 million from $1,090 million in 2009, due to a higher composite average wellhead crude oil and condensate price ($533 million) and an increase of 20 MBbld, or 35%, in wellhead crude oil and condensate deliveries ($376 million). The increase in deliveries primarily reflects increased production in Texas (8 MBbld), North Dakota (7 MBbld), Canada (3 MBbld) and Trinidad (2 MBbld). Production increases in Texas were the result of increased production from the Fort Worth Basin Barnett Combo and the Eagle Ford plays. Production increases in North Dakota resulted from increased deliveries from the Bakken and Three Forks plays. EOG's composite average wellhead crude oil and condensate price for 2010 increased 36% to $74.29 per barrel compared to $54.46 per barrel in 2009.

Natural gas liquids revenues in 2010 increased $203 million, or 79%, to $462 million from $259 million in 2009, due to a higher composite average price ($129 million) and an increase of 7 MBbld, or 29%, in natural gas liquids deliveries ($74 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area. EOG's composite average natural gas liquids price in 2010 increased 39% to $41.73 per barrel compared to $30.05 per barrel in 2009.

Wellhead natural gas revenues in 2010 increased $369 million, or 18%, to $2,420 million from $2,051 million in 2009. The increase was due to a higher composite average wellhead natural gas price ($316 million) and increased natural gas deliveries ($53 million). EOG's composite average wellhead natural gas price increased 15% to $3.93 per thousand cubic feet (Mcf) in 2010 from $3.42 per Mcf in 2009.

Natural gas deliveries in 2010 increased 43 million cubic feet per day (MMcfd), or 3%, to 1,688 MMcfd from 1,645 MMcfd in 2009. The increase was primarily due to higher production in Trinidad (68 MMcfd), partially offset by decreased production in Canada (24 MMcfd) and the United States (1 MMcfd). The increase in Trinidad was primarily attributable to deliveries under a take-or-pay contract, which began January 1, 2010. The decrease in the United States was primarily attributable to decreased production in the Rocky Mountain area (28 MMcfd), offshore Gulf of Mexico (9 MMcfd), New Mexico (6 MMcfd), Texas (5 MMcfd), Kansas (5 MMcfd) and Mississippi (4 MMcfd), partially offset by increased production in Louisiana (45 MMcfd) and Pennsylvania (11 MMcfd).

During 2010, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $62 million, which included net realized gains of $7 million. During 2009, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $432 million, which included net realized gains of $1,278 million.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as gathering fees associated with gathering third-party natural gas. For the years ended December 31, 2010 and 2009, gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas. For the year ended December 31, 2008, gathering, processing and marketing revenues were primarily related to sales of third-party natural gas. The purchase and sale of third-party crude oil and natural gas are utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs.

During 2010, gathering, processing and marketing revenues and marketing costs increased primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs in 2010 totaled $25 million compared to $10 million in 2009, primarily as a result of higher crude oil marketing margins.

2009 compared to 2008. Wellhead crude oil and condensate revenues decreased $368 million, or 25%, to $1,090 million in 2009 from $1,458 million in 2008, due to a lower composite average wellhead crude oil and condensate price ($675 million), partially offset by an increase of 10 MBbld, or 21%, in wellhead crude oil and condensate deliveries ($307 million). The increase in deliveries primarily reflects increased production in North Dakota (8 MBbld) and Texas (2 MBbld). The composite average wellhead crude oil and condensate price for 2009 decreased 38% to $54.46 per barrel compared to $88.18 per barrel for 2008.

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

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

Natural gas deliveries increased 26 MMcfd, or 2%, to 1,645 MMcfd in 2009 from 1,619 MMcfd in 2008. The increase was primarily due to higher production of 55 MMcfd in Trinidad, partially offset by lower production of 28 MMcfd in the United States and 6 MMcfd in the United Kingdom. The increase in Trinidad was primarily due to a reduction in plant shutdowns for maintenance during 2009 (39 MMcfd) and increased net contractual deliveries (16 MMcfd). The decrease in the United States was primarily attributable to decreased production from Texas (26 MMcfd), New Mexico (6 MMcfd), Mississippi (4 MMcfd), Kansas (3 MMcfd) and Oklahoma (3 MMcfd), partially offset by increased production in Louisiana (6 MMcfd) and in the Rocky Mountain area (8 MMcfd). The decrease in production in the United Kingdom was a result of production declines in both the Arthur and Valkyrie fields.

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

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

Operating and Other Expenses

2010 compared to 2009. During 2010, operating expenses of $5,577 million were $1,761 million higher than the $3,816 million incurred in 2009. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2010 and 2009:

	2010		2009

Lease and Well	$	4.96	$	4.50
Transportation Costs		2.74		2.20
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties (1)		13.19		11.29
Other Property, Plant and Equipment		0.79		0.74
General and Administrative (G&A)		1.99		1.93
Net Interest Expense		0.92		0.78
Total (2)	$	24.59	$	21.44

(1)	The 2010 amount excludes the reductions in the estimated fair value of the contingent consideration liability of $24 million, or $0.17 per Boe relating to the acquisition of certain unproved acreage (see Note 12 to Consolidated Financial Statements).

(2)	Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

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 2010 compared to 2009 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 things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are 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. In general, operating costs for wells producing crude oil are higher than operating costs for wells producing natural gas.

Lease and well expenses of $698 million in 2010 increased $119 million from $579 million in 2009 primarily due to higher operating and maintenance expenses in the United States ($67 million) and Canada ($6 million), increased lease and well administrative expenses in the United States ($27 million), primarily due to higher costs associated with increased crude oil activities, unfavorable changes in the Canadian exchange rate ($14 million) and increased workover expenditures in the United States ($3 million) and Canada ($2 million).

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

Transportation costs of $385 million in 2010 increased $102 million from $283 million in 2009 primarily due to increased transportation costs in the Rocky Mountain area ($46 million), the Upper Gulf Coast area ($29 million) and the Fort Worth Basin Barnett Shale area ($29 million). These increases reflect costs associated with marketing arrangements to transport production to downstream markets. The increased transportation costs in the Rocky Mountain area also include costs associated with EOG's crude-by-rail operations, which began transporting crude oil from Stanley, North Dakota, to Cushing, Oklahoma, at the end of December 2009.

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells, reserve revisions (upward or downward) primarily related to well performance and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from year to year. DD&A of the cost of other property, plant and equipment is calculated using the straight-line depreciation method over the useful lives of the assets. Other property, plant and equipment consist of gathering and processing assets, compressors, crude-by-rail assets, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

DD&A expenses in 2010 increased $393 million to $1,942 million from $1,549 million in 2009. DD&A expenses associated with oil and gas properties in 2010 were $378 million higher than in 2009 primarily due to higher unit rates described below and as a result of increased production in the United States ($97 million), Trinidad ($12 million) and China ($2 million), partially offset by a decrease in production in Canada ($8 million). DD&A rates increased due primarily to a proportional increase in production from higher cost properties in the United States ($167 million), Canada ($86 million), Trinidad ($12 million) and China ($8 million) and unfavorable changes in the Canadian exchange rate ($28 million), partially offset by a change in the fair value of the contingent consideration liability ($24 million).

DD&A expenses associated with other property, plant and equipment were $15 million higher in 2010 than in 2009 primarily due to natural gas gathering systems and processing plants being placed in service in the Rocky Mountain area ($10 million) and the Fort Worth Basin Barnett Shale area ($4 million).

G&A expenses of $280 million in 2010 were $32 million higher than 2009 due primarily to higher employee-related costs ($10 million), higher legal and other professional fees ($7 million) and higher information systems costs ($3 million).

Net interest expense of $130 million in 2010 increased $29 million from $101 million in 2009 primarily due to a higher average debt balance ($50 million), partially offset by higher capitalized interest ($21 million).

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

Gathering and processing costs increased $9 million to $67 million in 2010 compared to $58 million in 2009. The increase reflects increased activities in the Fort Worth Basin Barnett Shale area ($6 million) and the Rocky Mountain area ($3 million).

Exploration costs of $187 million in 2010 increased $17 million from $170 million for the same prior year period primarily due to increased employee-related costs in the United States.

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

Impairments of $743 million in 2010 increased $437 million from $306 million in 2009 primarily due to increased impairments of proved properties and other property, plant and equipment in Canada. EOG recorded impairments of proved properties and other property, plant and equipment of $526 million and $94 million in 2010 and 2009, respectively. In 2010, EOG recorded a pretax impairment of $280 million to adjust certain Canadian shallow natural gas assets sold to estimated fair value less estimated cost to sell (see Note 17 to Consolidated Financial Statements). Additionally, EOG recorded pretax impairments of $170 million in the fourth quarter of 2010 related to certain North American onshore and offshore natural gas assets.

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

Taxes other than income in 2010 increased $143 million to $317 million (6.5% of wellhead revenues) from $174 million (5.1% of wellhead revenues) in 2009. The increase in taxes other than income was primarily due to increased severance/production taxes primarily as a result of increased wellhead revenues in the United States ($56 million), Trinidad ($22 million) and Canada ($6 million); a decrease in credits available to EOG in 2010 for Texas high cost gas severance tax rate reductions as a result of fewer wells qualifying for such credit ($43 million); and higher ad valorem/property taxes in the United States ($14 million).

Other income, net was $14 million in 2010 compared to $2 million in 2009. The increase of $12 million was primarily due to higher equity income from ammonia plants in Trinidad ($9 million).

Income tax provision of $247 million in 2010 decreased $78 million compared to 2009 due primarily to decreased pretax income. The net effective tax rate for 2010 increased to 61% from 37% in 2009. The increase in the 2010 net effective tax rate is primarily due to higher state income taxes and to the tax effects of increased earnings in Trinidad and Canadian book losses, which resulted largely from the impairment of certain Canadian shallow natural gas impairments. The statutory tax rates in the United States and Trinidad are higher than the Canadian statutory rate.

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

	2009		2008

Lease and Well	$	4.50	$	4.62
Transportation Costs		2.20		2.26
DD&A -
Oil and Gas Properties		11.29		10.41
Other Property, Plant and Equipment		0.74		0.54
G&A		1.93		2.01
Net Interest Expense		0.78		0.43
Total (1)	$	21.44	$	20.27

(1)	Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

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

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

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

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

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

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

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

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

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

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

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

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

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

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2010 were funds generated from operations, net proceeds from issuances of long-term debt, proceeds from the sale of oil and gas properties, proceeds from stock options exercised and employee stock purchase plan activity, net commercial paper borrowings and borrowings under other uncommitted credit facilities and revolving credit facilities. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; dividend payments to stockholders; and repayments of debt.

2010 compared to 2009. Net cash provided by operating activities of $2,709 million in 2010 decreased $213 million from $2,922 million in 2009 primarily reflecting an unfavorable change in the net cash flow from the settlement of financial commodity derivative contracts ($1,271 million), an increase in cash operating expenses ($410 million), an increase in cash paid for income taxes ($182 million), an increase in cash paid for interest expense ($46 million), and unfavorable changes in working capital and other assets and liabilities ($7 million), partially offset by an increase in wellhead revenues ($1,482 million).

Net cash used in investing activities of $4,903 million in 2010 increased by $1,488 million from $3,415 million for the same period of 2009 due primarily to an increase in additions to oil and gas properties ($2,034 million); the acquisition of Galveston LNG Inc. ($210 million); and an increase in additions to other property, plant and equipment ($45 million); partially offset by an increase in proceeds from sales of assets ($461 million); and favorable changes in working capital associated with investing activities ($327 million).

Net cash provided by financing activities of $2,303 million in 2010 included proceeds from the issuances of long-term debt ($2,479 million) and proceeds from stock options exercised and employee stock purchase plan activity ($35 million). Cash used in financing activities during 2010 included cash dividend payments ($153 million), the repayment of long-term debt ($37 million), treasury stock purchases in connection with stock compensation plans ($11 million) and debt issuance costs ($8 million).

2009 compared to 2008. Net cash provided by operating activities of $2,922 million in 2009 decreased $1,711 million from $4,633 million in 2008 primarily reflecting a decrease in wellhead revenues ($2,823 million); unfavorable changes in working capital and other assets and liabilities ($335 million); an increase in cash operating expenses ($125 million); and an increase in cash paid for interest expense ($53 million); partially offset by a favorable change in the net cash flow from the settlement of financial commodity derivative contracts ($1,414 million); an increase in gathering, processing and marketing revenues ($243 million); and a decrease in cash paid for income taxes ($43 million).

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

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

Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2010, 2009 and 2008 (in millions):

	Actual
		2010		2009		2008
Expenditure Category
Capital
Drilling and Facilities		$	4,634	$	2,417	$	3,990
Leasehold Acquisitions			399		424		521
Property Acquisitions (1)			18		707		109
Capitalized Interest			76		55		43
Subtotal			5,127		3,603		4,663
Exploration Costs			187		170		194
Dry Hole Costs			72		51		55
Exploration and Development Expenditures			5,386		3,824		4,912
Asset Retirement Costs			72		84		181
Total Exploration and Development Expenditures			5,458		3,908		5,093
Other Property, Plant and Equipment (2)			581		326		477
Total Expenditures		$	6,039	$	4,234	$	5,570

(1)

In 2009, property acquisitions included non-cash additions of $353 million related to a property exchange transaction in the Rocky Mountain area. In 2009 and 2010, property acquisitions also included non-cash additions for contingent consideration, with estimated fair values of $35 million and $3 million, respectively, related to the acquisition of the Haynesville Assets (see Note 17 to Consolidated Financial Statements).

(2)	In 2010, other property, plant and equipment included $210 million for the acquisition of Galveston LNG Inc. (see Note 17 to Consolidated Financial Statements).

Exploration and development expenditures of $5,386 million for 2010 were $1,562 million higher than the prior year due primarily to increased drilling and facilities expenditures in the United States ($1,932 million), Canada ($134 million), Trinidad ($104 million) and China ($15 million); unfavorable changes in the foreign currency exchange rate in Canada ($58 million); increased capitalized interest in the United States ($21 million); increased employee-related exploration costs in the United States ($11 million); and increased dry hole costs in the United Kingdom ($11 million) and Canada ($10 million). These increases were partially offset by decreased property acquisition expenditures in the United States ($689 million), decreased leasehold acquisition expenditures in the United States ($20 million) and decreased dry hole costs in the United States ($9 million). The 2010 exploration and development expenditures of $5,386 million included $4,366 million in development, $926 million in exploration, $76 million in capitalized interest and $18 million in property acquisitions. The increase in expenditures for other property, plant and equipment was primarily due to the acquisition of Galveston LNG Inc. The 2009 exploration and development expenditures of $3,824 million included $2,082 million in development, $980 million in exploration, $707 million in property acquisitions and $55 million in capitalized interest. The decrease in expenditures for other property, plant and equipment primarily related to gathering and processing assets in the Fort Worth Basin Barnett Shale area. The 2008 exploration and development expenditures of $4,912 million included $3,612 million in development, $1,148 million in exploration, $109 million in property acquisitions and $43 million in capitalized interest. The increase in expenditures for other property, plant and equipment primarily related to gathering and processing assets in the Fort Worth Basin Barnett Shale and Rocky Mountain areas.

The 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 and other property, plant and equipment expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in the United States, Canada, Trinidad, the United Kingdom and China, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

Derivative Transactions

Financial Price Swap Contracts. The total fair value of EOG's crude oil and natural gas financial price swap contracts is reflected in the Consolidated Balance Sheets at December 31, 2010 as an asset of $69 million and a liability of $21 million, respectively. Presented below is a comprehensive summary of EOG's crude oil and natural gas financial price swap contracts at February 24, 2011, with notional volumes expressed in barrels per day (Bbld) and in million British thermal units per day (MMBtud) and prices expressed in dollars per barrel ($/Bbl) and in dollars per million British thermal units ($/MMBtu), as applicable.

Financial Price Swap Contracts
	Crude Oil				Natural Gas
	Volume (Bbld)		Weighted Average Price ($/Bbl)		Volume (MMBtud)		Weighted Average Price ($/MMBtu)
2011 (1)
January 2011 (2)		17,000	$	90.44		275,000	$	5.19
February 1, 2011 through March 31, 2011 (3)		18,000		90.69		425,000		5.09
April 1, 2011 through December 31, 2011		20,000		91.48		425,000		5.09

2012 (4)
January 1, 2012 through December 31, 2012		2,000	$	100.50		250,000	$	5.56

(1)

Natural gas financial price swap contracts include unexercised swaption contracts which give counterparties the option of entering into price swap contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas financial price swap contracts will increase by 275,000 MMBtud at an average price of $4.90 per MMBtu for the period from April 1, 2011 through December 31, 2011.

(2)	The crude oil and natural gas contracts for January 2011 are closed.

(3)	The crude oil contracts for February 2011 through March 2011 will close February 28, 2011 and March 31, 2011, respectively. The natural gas contracts for February 2011 through March 2011 are closed.

(4)

Natural gas financial price swap contracts include unexercised swaption contracts which give counterparties the option of entering into price swap contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas financial price swap contracts will increase by 150,000 MMBtud at an average price of $5.64 per MMBtu for each month of 2012.

Financial Basis Swap Contracts. Prices received by EOG for its natural gas production generally vary from New York Mercantile Exchange (NYMEX) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas financial basis swap contracts in order to fix the differential between prices in the Rocky Mountain area and NYMEX Henry Hub prices. The total fair value of EOG's natural gas financial basis swap contracts is reflected in the Consolidated Balance Sheets at December 31, 2010 as a liability of $9 million. Presented below is a comprehensive summary of EOG's natural gas financial basis swap contracts at February 24, 2011. The weighted average price differential represents the amount of reduction to NYMEX gas prices per million British thermal units (MMBtu) for the notional volumes covered by the basis swap.

Natural Gas Financial Basis Swap Contracts

	Volume	Weighted Average Price Differential
	(MMBtud)	($/MMBtu)
2011
First Quarter (closed)	65,000	$(1.89)

Financing

EOG's debt-to-total capitalization ratio was 34% at December 31, 2010 compared to 22% at December 31, 2009. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

During 2010, total debt increased $2,463 million to $5,260 million. The estimated fair value of EOG's debt at December 31, 2010 and 2009 was $5,602 million and $3,056 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, upon interest rates available to EOG at year-end. EOG's debt is primarily at fixed interest rates. At December 31, 2010, a 1% decline in interest rates would result in a $330 million increase in the estimated fair value of the fixed rate obligations. See Note 2 to Consolidated Financial Statements.

During 2010, EOG utilized cash provided by operating activities, proceeds from the issuance of the Fixed Rate Notes, Floating Rate Notes and Notes described below, proceeds from asset sales and cash provided by borrowings from net commercial paper and other uncommitted credit facilities to fund its capital programs. While EOG maintains a $2.0 billion commercial paper program, the maximum outstanding at any time during 2010 was $1,039 million, and the amount outstanding at year-end was zero. The maximum amount outstanding under uncommitted credit facilities during 2010 was $14 million with no amounts outstanding at year-end. The average borrowings outstanding under the commercial paper program and the uncommitted credit facilities were $191 million and $0.1 million, respectively, during the year 2010. EOG considers this excess availability, which is backed by the two $1.0 billion unsecured Revolving Credit Agreements with domestic and foreign lenders described in Note 2 to Consolidated Financial Statements, to be ample to meet its ongoing operating needs.

On November 23, 2010, EOG completed its public offering of $400 million aggregate principal amount of 2.500% Senior Notes due 2016 (2016 Notes), $750 million aggregate principal amount of 4.100% Senior Notes due 2021 (2021 Notes) (together, the Fixed Rate Notes) and $350 million aggregate principal amount of Floating Rate Senior Notes due 2014 (the Floating Rate Notes). Interest on the Fixed Rate Notes is payable semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2011. Interest on the Floating Rate Notes is payable quarterly in arrears on February 3, May 3, August 3 and November 3 of each year, beginning on February 3, 2011 and is based on the three-month LIBOR plus 0.75% per annum. The interest rate on the Floating Rate Notes resets quarterly on the interest payment dates. Net proceeds from the offering of approximately $1,487 million were used for general corporate purposes, including the repayment of outstanding commercial paper borrowings. Contemporaneously with the offering of the Floating Rate Notes, EOG entered into an interest rate swap to fix the interest rate on the Floating Rate Notes at 1.87%.

On May 20, 2010, EOG completed its public offering of $500 million aggregate principal amount of 2.95% Senior Notes due 2015 and $500 million aggregate principal amount of 4.40% Senior Notes due 2020 (together, Notes). Interest on the Notes is payable semi-annually in arrears on June 1 and December 1 of each year, beginning on December 1, 2010. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings.

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

Contractual Obligations

The following table summarizes EOG's contractual obligations at December 31, 2010 (in thousands):

					2016 &
Contractual Obligations (1)	Total	2011	2012 - 2013	2014 - 2015	Beyond