10-K

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, 2011

or

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, 2011: $28,070,598,553.

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, 269,085,607shares outstanding as of February 17, 2012.

            Documents incorporated by reference.  Portions of the Definitive Proxy Statement for the registrant's 2012 Annual Meeting of Stockholders to be filed within 120 days after December 31, 2011 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	2
	Marketing	6
	Wellhead Volumes and Prices	7
	Competition	9
	Regulation	9
	Other Matters	13
	Executive Officers of the Registrant	14
ITEM 1A.	Risk Factors	15
ITEM 1B.	Unresolved Staff Comments	23
ITEM 2.	Properties	23
	Oil and Gas Exploration and Production - Properties and Reserves	23
ITEM 3.	Legal Proceedings	26
ITEM 4	Mine Safety Disclosures	26

PART II

ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and
	Issuer Purchases of Equity Securities	27
ITEM 6.	Selected Financial Data	30
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	51
ITEM 8.	Financial Statements and Supplementary Data	51
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	51
ITEM 9A.	Controls and Procedures	51
ITEM 9B.	Other Information	51

PART III

ITEM 10.	Directors, Executive Officers and Corporate Governance	52
ITEM 11.	Executive Compensation	52
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	52
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	53
ITEM 14.	Principal Accounting Fees and Services	53

PART IV

ITEM 15. Exhibits, Financial Statement Schedules 54

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), the Argentine Republic (Argentina) 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, 2011, EOG's total estimated net proved reserves were 2,054 million barrels of oil equivalent (MMBoe), of which 517 million barrels (MMBbl) were crude oil and condensate reserves, 228 MMBbl were natural gas liquids reserves and 7,851 billion cubic feet (Bcf), or 1,309 MMBoe, were natural gas reserves (see Supplemental Information to Consolidated Financial Statements).  At such date, approximately 85% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States, 9% in Canada and 6% in Trinidad.  Crude oil equivalent volumes are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet (Mcf) of natural gas.

As of December 31, 2011, EOG employed approximately 2,550 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 is focused on cost-effective utilization of advanced technology associated with three-dimensional seismic and microseismic data, the development of reservoir simulation models, the use of improved drill bits, mud motors and mud additives for horizontal drilling, formation evaluation, and horizontal 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.  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.  For financial information about our reportable segments (including financial information by segment geographic area), see Note 10 to Consolidated Financial Statements.  For information regarding the risks associated with EOG's foreign operations, see Item 1A. Risk Factors.

1

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, 2011, 39% of EOG's net proved reserves in the United States and Canada (on a crude oil equivalent basis) were crude oil and condensate and natural gas liquids and 61% 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 2011 and certain 2012 plans for EOG's United States and Canada operations.

United States.  The liquids-rich Eagle Ford Shale has proven to be among EOG's most economically attractive resource plays to date.  The Eagle Ford has well-defined crude oil, wet gas and dry gas trends.  EOG's total acreage position in all three hydrocarbon trends totals 647,000 net acres.  EOG has focused its drilling on its highly productive 572,000 net acreage position within the oil window where EOG has drilled a cumulative 356 net wells.  EOG's strategy is to maintain its entire ownership interests and not to dilute its position by taking on a joint venture partner in this play.  EOG is the largest oil producer in the Eagle Ford where its net production in 2011 was 30.2 thousand barrels per day (MBbld) of crude oil and condensate, 3.9 MBbld of natural gas liquids and 21 million cubic feet per day (MMcfd) of natural gas.  This represents more than a six-fold, year-over-year increase in production.  EOG drilled 269 net wells in 2011 and plans to drill and complete approximately 280 net wells in 2012.

In 2011, EOG increased activity in the liquids-rich Barnett Shale Combo play of the Fort Worth Basin where total production grew by approximately 105% above 2010 levels, including a 107% increase in liquids production.  During the year, EOG completed 269 net Barnett Combo wells and increased its drilling potential in this liquids-rich play by expanding the core area from approximately 175,000 to approximately 200,000 net acres.  EOG's total 2011 Barnett Shale average net daily production increased to approximately 37.7 MBbld of crude oil and condensate and natural gas liquids and 403 MMcfd of natural gas.  For 2012, EOG will continue to focus on this play with plans to complete to sales an additional 200 net Barnett Shale Combo wells.  In the natural gas portion of the Barnett Shale, EOG plans to complete to sales approximately 35 net wells.  The rich natural gas from the majority of these wells will be processed to recover natural gas liquids.  With a large acreage position of approximately 506,000 net acres in the Barnett Shale and a history of strong drilling results, EOG expects to continue to be an active driller in the Fort Worth Basin Barnett Shale for many years.

EOG maintained a strong and consistent development program throughout the Rocky Mountain area in 2011.  EOG continued its development programs in the Williston, DJ and Uinta basins, drilling 79 net wells, 36 net wells and 33 net wells, respectively.  EOG also resumed exploration and development activities in the Powder River Basin during 2011, drilling six net wells.  Net average production for the entire Rocky Mountain area for 2011 was 46.6 MBbld of crude oil and condensate and natural gas liquids, an increase of 13% over the prior year.  Natural gas production was down 17% from 2010 levels primarily due to divestitures and de-emphasized natural gas drilling.  EOG holds approximately 1.6 million net acres in the Rocky Mountain area.  For 2012, EOG intends to maintain a steady development program throughout the Rocky Mountain area where it plans to drill 123 net wells.

In 2011, EOG drilled and participated in 56 net wells in the Permian Basin to test the Leonard-Avalon Shale, Bone Spring and Wolfcamp formations.  EOG is well positioned in these three established plays: the Leonard-Avalon Shale and Bone Spring plays in the Delaware Basin and the Wolfcamp Shale in the Midland Basin.  Net production for the year 2011 averaged 10.5 MBbld of crude oil and condensate and natural gas liquids and 49 MMcfd of natural gas.  After divestitures in 2011, EOG now controls approximately 480,000 net acres throughout the Permian Basin, with approximately 130,000 acres within the Wolfcamp Shale formation and 106,000 acres within the limits of the Bone Spring and Leonard-Avalon Shale formations.  In 2012, EOG plans to continue the development, expansion and enhancement of the Wolfcamp, Leonard-Avalon and Bone Spring plays, by drilling 112 net wells, while continuing to look for new liquids-rich plays.

2

In 2011, EOG continued to expand its activities in the Mid-Continent area with continued growth and extension of its Western Anadarko Basin core area.  For the year, EOG averaged net production of 7.1 MBbld of crude oil and condensate and natural gas liquids and 52 MMcfd of natural gas.  Total crude oil and condensate and natural gas liquids volumes increased 22% in 2011 compared to 2010.  In 2011, EOG continued its successful horizontal exploitation of the Cleveland sandstone, drilling 11 net wells with initial average gross production rates of approximately 350 barrels per day (Bbld) of crude oil and condensate and natural gas liquids per well.  Since 2002, EOG has drilled over 230 net wells in this play and holds approximately 100,000 net acres throughout the trend.  In the recently discovered Marmaton Sandstone play, where it holds approximately 80,000 net acres, EOG drilled a total of 18 net wells in 2011 with an initial average gross production rate of 550 Bbld of crude oil and condensate and natural gas liquids per well.  In 2012, approximately 40 net wells are planned in order to further exploit these liquids-rich plays.

           In the South Texas area, EOG drilled 47 net wells in 2011.  Net production during 2011 averaged 6.4 MBbld of crude oil and condensate and natural gas liquids and 151 MMcfd of natural gas. EOG's activity was focused in Webb, Zapata, San Patricio, Nueces, Brooks and Kenedy counties.  EOG will continue to focus on drilling liquids-rich wells in the Lobo and Roleta trends, the Frio and Vicksburg trends and the Nueces Wilcox trend. EOG holds approximately 364,500 net acres in South Texas.  Approximately 43 net wells are planned for South Texas during 2012.  EOG's Gulf of Mexico production of crude oil, condensate and natural gas liquids averaged approximately 75 Bbld for the year ended December 31, 2011.  Thus, EOG's offshore operations in the Gulf of Mexico are immaterial in relation to EOG's overall operations and production; moreover, EOG does not have any plans for future offshore drilling in the Gulf of Mexico.

In the Upper Gulf Coast region, EOG drilled 47 net wells and net production averaged 227 MMcfd of natural gas and 1.0 MBbld of crude oil and condensate and natural gas liquids in 2011.  The Haynesville and Bossier Shale plays located near the Texas-Louisiana border continue to be core natural gas assets for EOG.  The drilling program has increased from 13 net wells in 2009 to 40 net wells in 2011.  EOG expanded the Texas "sweet spot" in 2011 with excellent well results in southern Nacogdoches and Angelina counties.  EOG now controls 175,000 net acres in this play, and most of this acreage is within a well-defined productive sweet spot.  EOG holds a total of approximately 384,000 net acres in the Upper Gulf Coast region.  Due to low natural gas prices, EOG plans to reduce activity and drill approximately 25 net wells in the Upper Gulf Coast region in 2012, including 15 net wells in the Haynesville.

During 2011, EOG continued the development of its Pennsylvania Marcellus Shale asset and drilled a total of 27 net wells.  Nine net wells were drilled in Bradford County in northeastern Pennsylvania, and seven net wells were completed.  The remaining 18 net wells were drilled in north central Pennsylvania, as part of EOG's joint venture with Seneca Resources Corporation where EOG is operator and holds a 50% working interest.  EOG's net natural gas production averaged 33 MMcfd in 2011, up from 12 MMcfd in 2010.  EOG currently holds in excess of 200,000 net acres in the Pennsylvania Marcellus Shale and plans to drill an estimated 35 net wells during 2012.

At December 31, 2011, EOG held approximately 3.6 million net undeveloped acres in the United States.

During 2011, EOG continued the expansion of its gathering and processing activities in the Barnett Shale of North Texas and the Bakken and Three Forks plays of North Dakota.  EOG also installed field gathering and conditioning facilities in the Eagle Ford play of South Texas.  EOG-owned natural gas processing capacity at December 31, 2011 in the Barnett Shale and Eagle Ford was 120 MMcfd and 135 MMcfd, respectively.

During June 2011, EOG sold its Stanley, North Dakota, condensate recovery unit and 76-mile, 12-inch diameter "dense phase" natural gas pipeline.  In connection with the sale, EOG entered into an agreement with the buyer to reserve capacity in both the condensate recovery unit and the pipeline.  The pipeline connects with the Alliance Pipeline which transports natural gas to the Chicago, Illinois, area.

Additionally, in support of its operations in the Williston Basin, EOG increased utilization of its crude oil loading facility near Stanley, North Dakota, to transport its oil production and oil purchased from third-party producers.  Using this facility during 2011, EOG loaded 200 unit trains (each unit train typically consists of 100 cars and has a total aggregate capacity of approximately 68,000 barrels of crude oil) with crude oil for transport to Stroud, Oklahoma, and certain destinations on the U.S. Gulf Coast.  In Stroud, Oklahoma, EOG owns a crude oil off-loading facility and a pipeline to transport the crude oil to the Cushing, Oklahoma, trading hub.  Together, these facilities have the capacity to load/unload approximately 70 MBbld of crude oil.

3

In the South Texas Eagle Ford, EOG established a crude oil loading facility in Harwood, Texas, that became operational in April 2011.  At this facility, crude oil is loaded onto unit trains of approximately 70 cars each, with capacity of approximately 46,000 barrels per train, and is shipped to destinations on the U.S. Gulf Coast.  During 2011, a total of 45 shipments were made from the Harwood facility.

In order to access more diverse markets for its crude-by-rail shipments, during 2011 EOG began construction of a crude oil unloading facility in St. James, Louisiana, where sales are based upon the Light Louisiana Sweet price.  This facility, which is scheduled to be operational in the second quarter of 2012, will have a capacity of approximately 100 MBbld, and be able to accommodatemultiple trains at a single time.

EOG believes that its crude-by-rail facilities uniquely position it to direct its crude oil shipments via rail car from North Dakota and Texas to the most favorable markets.

Since 2008, EOG has been operating its own sand mine and sand processing plant located in Hood County, Texas, helping to fulfill EOG's sand needs in the Barnett Shale Combo play.

During 2011, EOG increased its sand mining and processing operations to supply sand for its well completion operations.  EOG purchased a second processing plant in Hood County, Texas, in 2011, and began regular shipments of EOG-owned unprocessed sand from Wisconsin.  After final processing at the Hood County facility, the sand is being utilized in key EOG plays.

During December 2011, EOG completed and placed in operation its new state-of-the-art Chippewa Falls, Wisconsin, sand plant to process sand from a nearby EOG-owned sand mine.  The first unit train of processed sand was dispatched from Chippewa Falls at the beginning of January 2012.  The majority of the initial trains are destined for a new EOG sand facility in Refugio, Texas.  One to two sand unit trains of approximately 100 cars each are expected to arrive at Refugio every week as operations in Chippewa Falls ramp up.  From there, the sand will be shipped primarily to the South Texas Eagle Ford play.

Canada.  EOG conducts operations through its wholly-owned subsidiary, EOG Resources Canada Inc. (EOGRC), from its offices in Calgary, Alberta.  During 2011, EOGRC continued its focus on horizontal crude oil growth, mainly through its drilling activity in Waskada, Manitoba.  Other drilling activity was directed to acreage retention in its bigger target horizontal natural gas play in the Horn River Basin of British Columbia.  During 2011, EOGRC drilled or participated in 101 net wells, all of which were horizontal wells.  Correspondingly, net crude oil and condensate and natural gas liquids production increased by 16% to 8.8 MBbld.  Net natural gas production decreased 34% to 132 MMcfd, reflecting a de-emphasis on gas drilling and EOGRC's sale of several shallow gas properties in late 2010.  The focus on crude oil production growth will continue in 2012 with 133 net wells planned in a combination of plays from the continued development in Manitoba and new targets in Alberta.  EOG plans to drill seven net wells in the Horn River Basin for acreage retention in 2012.

At December 31, 2011, EOGRC held approximately 749,000 net undeveloped acres in Canada.

In March 2011, EOGRC purchased an additional 24.5% interest in the proposed Pacific Trail Pipelines (PTP) for $25.2 million.  The PTP is intended to link western Canada's natural gas producing regions to the planned liquefied natural gas (LNG) export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia (Kitimat LNG Terminal).  A portion of the purchase price ($15.3 million) was paid at closing with the remaining amount to be paid contingent on the decision to proceed with the construction of the Kitimat LNG Terminal.  Additionally, in March 2011, EOGRC and an affiliate of Apache Corporation (Apache), through a series of transactions, sold a portion of their interests in the Kitimat LNG Terminal and PTP to an affiliate of Encana Corporation (Encana).  Subsequent to these transactions, ownership interests in both the Kitimat LNG Terminal and PTP are: Apache (operator) 40%, EOGRC 30% and Encana 30%.  All future costs of the project will be paid by each party in proportion to its respective ownership percentage.  In the first quarter of 2011, EOGRC and Apache awarded a front-end engineering and design contract to a global engineering company with the final report expected in the second half 2012.  In October 2011, the Canadian National Energy Board granted a 20-year export license to ship LNG from the Kitimat LNG Terminal to international markets.

4

  Operations Outside the United States and Canada

EOG has operations offshore Trinidad, the U.K. North Sea and East Irish Sea, the China Sichuan Basin and the Neuquén Basin of Argentina, and is evaluating additional exploration, development and exploitation opportunities in these and other select 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 50% working interest in the exploration and production license covering the EMZ Area offshore Trinidad as a result of a third party farm-out agreement which was executed in the fourth quarter of 2011;

·   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 natural gas and crude oil and condensate.  In Block 4(a), EOG drilled and completed six development wells in the Toucan Field and one in the Sercan Field in 2011.  Production from both the Toucan Field and EMZ Area began in February 2012 to supply natural gas under a contract with the National Gas Company of Trinidad and Tobago (NGC).  EOG sourced the natural gas for this contract from its existing fields until the Toucan Field began producing.

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 in 2012 approximately 520 MMcfd (370 MMcfd, net) of natural gas, under current economic conditions.  EOG intends to fulfill these natural gas delivery obligations by using production from existing proved reserves.  Crude oil and condensate from EOG's Trinidad operations currently is sold to the Petroleum Company of Trinidad and Tobago.

In 2011, EOG's average net production from Trinidad was 344 MMcfd of natural gas and 3.4 MBbld of crude oil and condensate.

At December 31, 2011, 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 49/16a, located in the Southern Gas Basin of the North Sea.  During 2011, production continued from the Valkyrie field in this block.

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.

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 submitted 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 in the first half of 2012.  The operator and partners are continuing to negotiate processing and transportation terms with export infrastructure owners.

5

In 2009, EOGUK drilled a successful exploratory well in its East Irish Sea Blocks 110/7b and 110/12a.  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 2011, offshore facilities fabrication began, line pipe was fabricated and all principal facilities and drilling contracts were signed.  Field development plans for the Conwy and Corfe fields were submitted to the DECC during the first quarter of 2011.  Regulatory approval of both plans is expected during the first quarter of 2012.  Installation of facilities, pipelines and drilling of development wells are planned for 2012, with initial production expected during the first quarter of 2013.  The licenses for the East Irish Sea blocks were awarded to EOGUK in 2007.

In 2011, production averaged 3 MMcfd of natural gas, net, in the United Kingdom.

At December 31, 2011, EOG held approximately 95,000 net undeveloped acres in the United Kingdom.

China.  In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuanzhong Block exploration area in the Sichuan Basin, Sichuan Province, China.  In October 2008, EOG obtained the rights to shallower zones on the acreage acquired.  During the first quarter of 2011, EOG completed one horizontal well.

In 2011, production averaged 10 MMcfd of natural gas, net, in China.

At December 31, 2011, EOG held approximately 131,000 net acres in China.

Argentina. During 2011, EOG signed two exploration contracts and one farm-in agreement covering approximately 100,000 net acres in the Neuquén Basin in Neuquén Province, Argentina.  During the third quarter of 2011, EOG performed exploration activity on a portion of this acreage in preparation for drilling a well targeting the Vaca Muerta oil shale in the Aguada del Chivato Block.  EOG began drilling this well in January 2012.  In the first quarter of 2012, EOG plans to participate in drilling a second well in the Bajo del Toro Block targeting the Vaca Muerta oil shale.

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 2011, 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 2012, the pricing mechanism for such production is expected to remain the same.

In 2011, 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 United States Henry Hub market prices.  The pricing mechanisms for these contracts in Trinidad are expected to remain the same in 2012.

In 2011, all wellhead natural gas volumes from the United Kingdom were sold on the spot market.  The 2012 marketing strategy for the wellhead natural gas volumes from the United Kingdom is expected to remain the same.

In 2011, 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 2012.

6

In certain instances, EOG purchases and sells third-party crude oil and natural gas in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities.

During 2011, a single purchaser accounted for 10.1% of EOG's total wellhead crude oil and condensate, natural gas liquids and natural gas revenues and gathering, processing and marketing 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, 2011, 2010 and 2009.

Year Ended December 31				2011	2010	2009
Crude Oil and Condensate Volumes (MBbld) (1)
	United States:
		Eagle Ford		30.2	4.1	-
		Barnett		15.2	6.8	2.8
		Other		56.6	52.3	45.1
	United States			102.0	63.2	47.9
	Canada			7.9	6.7	4.1
	Trinidad			3.4	4.7	3.1
	Other International (2)			0.1	0.1	0.1
			Total	113.4	74.7	55.2
Natural Gas Liquids Volumes (MBbld) (1)
	United States:
		Eagle Ford		3.9	0.2	-
		Barnett		22.6	16.3	10.3
		Other		15.0	13.0	12.2
	United States			41.5	29.5	22.5
	Canada			0.9	0.9	1.1
			Total	42.4	30.4	23.6
Natural Gas Volumes (MMcfd) (1)
	United States:
		Eagle Ford		21	4	-
		Barnett		403	404	400
		Other		689	725	734
	United States			1,113	1,133	1,134
	Canada			132	200	224
	Trinidad			344	341	273
	Other International (2)			13	14	14
			Total	1,602	1,688	1,645
Crude Oil Equivalent Volumes (MBoed) (3)
	United States:
		Eagle Ford		37.7	5.0	-
		Barnett		105.0	90.5	79.8
		Other		186.4	186.0	179.6
	United States			329.1	281.5	259.4
	Canada			30.7	40.9	42.6
	Trinidad			60.7	61.5	48.5
	Other International (2)			2.2	2.5	2.4
			Total	422.7	386.4	352.9
Total MMBoe (3)				154.3	141.1	128.8

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Year Ended December 31	2011		2010		2009
Average Crude Oil and Condensate Prices ($/Bbl) (4)
United States	$	92.92	$	74.88	$	54.42
Canada		91.92		72.66		57.72
Trinidad		90.62		68.80		50.85
Other International (2)		100.11		73.11		53.07
Composite		92.79		74.29		54.46
Average Natural Gas Liquids Prices ($/Bbl) (4)
United States	$	50.37	$	41.68	$	30.03
Canada		52.69		43.40		30.49
Composite		50.41		41.73		30.05
Average Natural Gas Prices ($/Mcf) (4)
United States	$	3.92	$	4.30	$	3.72
Canada		3.71		3.91		3.85
Trinidad		3.53		2.65		1.73
Other International (2)		5.62		4.90		4.34
Composite		3.83		3.93		3.42

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

(2)   Other International includes EOG's United Kingdom and 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).

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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 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), the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), all 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 BSEE.

BLM and BOEM 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 BOEM or BSEE).  Such offshore operations are subject to numerous regulatory requirements, including the need for prior BOEM and/or BSEE 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 requirements for removal of all production facilities.  Under certain circumstances, the BOEM or BSEE may require operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect EOG's interests.

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

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

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

Proposals and proceedings that might affect the oil and gas industry are considered from time to time by Congress, the state legislatures, the FERC and 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 such legislative bodies and regulatory agencies and courts 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 EOG's 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 third-party 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 third-party 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

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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 or results of operations.  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 and results of operations.

Climate Change.  Local, state, national and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years.  In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions, recent U.S. EPA rulemaking 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 is 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 operations, financial condition and results of operations.

Hydraulic Fracturing.  Most onshore crude oil and natural gas wells drilled by EOG are completed and stimulated through the use of 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 from formations 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.  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.  The makeup of the fluid used in the hydraulic fracturing process is typically more than 99% water and sand, and less than 1% of 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 the components 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 reused 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 monitor compliance with all applicable regulations.

Currently, the regulation of hydraulic fracturing is primarily conducted at the state and local 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 imposed or 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; disclosure of the chemical additives used in hydraulic fracturing operations; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations.  Such federal, state and local 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.

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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 operations, financial condition and results of operations.

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 into 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 or results of operations.  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 and results of operations.

Local, state, national and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years.  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 is currently considering the creation of a cap-and-trade system to reduce GHG emissions in Manitoba.  Canada was an original signatory to the United Nations Framework Convention on Climate Change (also known as the Kyoto Protocol), but Canada recently announced its withdrawal from the Kyoto Protocol, effective December 2012.

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 of compliance within that country.  EOG currently has operations in Trinidad, the United Kingdom, China and Argentina.

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 operations, financial condition and results of operations.  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.

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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 2011 than in prior years and is expected to comprise an even larger portion in 2012.  Average crude oil and condensate prices received by EOG for production in the United States and Canada increased by 24% in 2011, increased by 37% in 2010 and decreased by 38% in 2009, each as compared to the immediately preceding year.  The average New York Mercantile Exchange (NYMEX) crude oil strip price for 2012 has increased approximately 7% subsequent to December 31, 2011.  Average United States and Canada wellhead natural gas prices have fluctuated, at times rather dramatically, during the last three years.  These fluctuations resulted in an 8% decrease in the average wellhead natural gas price received by EOG for production in the United States and Canada in 2011, an increase of 13% in 2010 and a decrease of 54% in 2009, each as compared to the immediately preceding year.  The average NYMEX natural gas strip price for 2012 has decreased by approximately 6% since December 31, 2011.  Due to the many uncertainties associated with the world political environment, the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in crude oil and condensate, natural gas liquids and natural gas 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 2012 crude oil derivative contracts and based on EOG's tax position, EOG's price sensitivity in 2012 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 $31 million for net income and $46 million for cash flows from operating activities.  Including the impact of EOG's 2012 natural gas derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2012 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 $11 million for net income and $16 million for cash flows from operating activities.  For a summary of EOG's financial commodity derivative contracts at February 24, 2012, 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, 2011, 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, option 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, 2012, 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, 2011, 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.

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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.  All of EOG's onshore and 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 the risk of 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, 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, 2012) are as follows:

Name	Age	Position
Mark G. Papa	65	Chairman of the Board and Chief Executive Officer; Director
William R. Thomas	59	President
Gary L. Thomas	62	Chief Operating Officer
Fredrick J. Plaeger, II	58	Senior Vice President and General Counsel
Timothy K. Driggers	50	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.

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

Gary L. Thomas was elected Chief Operating Officer in September 2011.  He was elected Executive Vice President, North America Operations in May 1998, Executive Vice President, Operations in May 2002, and served as Senior Executive Vice President, Operations from February 2007 to September 2011.  He also previously served as Senior Vice President and General Manager of EOG's Midland, Texas office.  Mr. Thomas joined a predecessor of EOG in July 1978.

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 (including prices for natural gas liquids and condensate) fluctuate widely.  Among the factors that can or could 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 alternative energy sources;

·   the nature and extent of governmental regulation (including environmental regulation and regulation of derivatives transactions and hedging activities) and taxation;

·   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.

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In addition, if we expect significant sustained decreases in crude oil and natural gas prices in the future such that the expected 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 reserves (including "dry holes").  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, such as winter storms, flooding and hurricanes, 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, rail cars, 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, sand, 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 in each case due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations.  For related discussion of the risks and potential losses and liabilities inherent in our crude oil and natural gas operations generally, see the immediately following risk factor.

Our crude oil and natural gas operations involve many risks and expose us to potential losses and liabilities, and insurance may not fully protect us against these risks and potential losses and liabilities.

Our onshore and offshore operations are subject to all of the risks associated with exploring and drilling for, and producing, gathering, processing and transporting, crude oil and natural gas, including the risks of:

            ·well blowouts and cratering;

            ·loss of well control;

            ·crude oil spills, natural gas leaks and pipeline ruptures;

            ·pipe failures and casing collapses;

            ●uncontrollable flows of crude oil, natural gas, formation water or drilling fluids;

            ·releases of chemicals or other hazardous substances;

            ●adverse weather conditions, such as winter storms, flooding and hurricanes, and other natural disasters;

            ·fires and explosions;

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·terrorism or vandalism;

·formations with abnormal pressures; and

·malfunctions of gathering, processing and other equipment.

If any of these events occur, we could incur losses and liabilities as a result of:

·injury or loss of life;

                ·damage to, or destruction of, property, equipment and crude oil and natural gas reservoirs;

                ·pollution or other environmental damage;

                ● regulatory investigations and penalties as well as clean-up and remediation responsibilities and costs;

·suspension or interruption of our operations, including due to injunction; and

·repairs necessary to resume operations.

We maintain insurance against many, but not all, such losses and liabilities 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 losses 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 onshore and offshore 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 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 by federal, state and local governments and regulatory agencies, both domestically and 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.

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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.

Local, state, national and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years.  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.  Most onshore crude oil and natural gas wells drilled by EOG are completed and stimulated through the use of hydraulic fracturing.  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 imposed or 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, disclosure of the chemical additives used in hydraulic fracturing operations 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.  Accordingly, our production of crude oil and natural gas could be materially and adversely affected.  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 proposed or 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.  For related discussion, see the risk factor below regarding the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act with respect to regulation of derivatives transactions and entities (such as EOG) that participate in such transactions.

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, but not limited to, 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.

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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.  In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil or natural gas prices.  These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, lower production 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 us 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, sales of assets and borrowings under other uncommitted credit facilities and, to a lesser extent and if and as necessary, bank borrowings, borrowings under our revolving credit facility 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.

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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 or in acquiring necessary services, equipment, supplies and personnel.  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 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.

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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, flooding 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.

Recent federal legislation and related regulations regarding derivatives transactions could have a material and adverse impact on our hedging activities.

As discussed in the risk factor immediately above, we use derivative instruments to hedge the impact of fluctuations in crude oil and natural gas prices on our results of operations and cash flow.  In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act, which, among other matters, establishes a comprehensive framework for the regulation of derivatives, or "swaps."  The U.S. Securities and Exchange Commission, which has jurisdiction over security-based swaps, and the Commodity Futures Trading Commission, which has jurisdiction over swaps, are in the process of adopting regulations to implement this new regulatory regime.  Once implemented, entities such as EOG that enter into swaps will be subject to, among other provisions, swap recordkeeping and reporting requirements; position limits for certain referenced futures contracts in the major energy markets and economically equivalent futures, options and swaps; and, subject to certain exceptions which may be applicable to EOG, swap clearing, trade execution and margin requirements (i.e., collateral posting requirements).  Our swap counterparties could be subject to even greater regulatory oversight and may be subject to regulated capital requirements.

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The applicability of such provisions (and the availability of certain exemptions) to EOG, our hedging activities and our hedging counterparties is currently uncertain, as many of the implementing regulations have not been finalized.  However, the legislation and related regulations could significantly increase our cost of compliance, increase the cost and alter the terms of derivatives transactions, and adversely impact the number and creditworthiness of available swap counterparties.  All of this could impact our available liquidity, require us to divert funds away from our exploration, development and production activities (e.g., in order to satisfy margin/collateral posting requirements) and reduce our ability to hedge and otherwise manage our financial and commercial risks related to crude oil and natural gas price fluctuations.  If we reduce our use of derivatives as a result of the legislation and related regulations, our results of operations may become more volatile and our cash flow may be less predictable, which could materially and adversely affect our ability to plan for and fund our capital expenditure requirements.  Any of the foregoing consequences could have a material and adverse effect on our business, financial condition and results of operations.

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.

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, 2011, approximately 5% of our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.

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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

Not applicable.

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.

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Acreage.  The following table summarizes EOG's developed and undeveloped acreage at December 31, 2011. 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		1,742,667	1,303,030	4,950,407	3,572,980	6,693,074	4,876,010
Canada		1,228,360	1,021,507	804,486	748,509	2,032,846	1,770,016
Trinidad		75,717	65,719	48,520	38,816	124,237	104,535
United Kingdom		8,797	2,570	118,333	94,730	127,130	97,300
China		130,546	130,546	-	-	130,546	130,546
	Total	3,186,087	2,523,372	5,921,746	4,455,035	9,107,833	6,978,407

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 between three and five years.  Company-wide, approximately 1.02 million net acres will expire in 2012, 0.9 million net acres will expire in 2013 and 0.6 million net acres will expire in 2014 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.  EOG operated 15,772 gross and 13,977 net producing crude oil and natural gas wells at December 31, 2011.  Gross crude oil and natural gas wells include 1,577 wells with multiple completions.

		Crude Oil		Natural Gas		Total
		Gross	Net	Gross	Net	Gross	Net
United States		2,905	2,076	7,096	5,830	10,001	7,906
Canada		698	587	6,888	6,192	7,586	6,779
Trinidad		13	10	29	25	42	35
United Kingdom		-	-	1	-	1	-
China		-	-	25	24	25	24
	Total	3,616	2,673	14,039	12,071	17,655	14,744

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Drilling and Acquisition Activities.  During the years ended December 31, 2011, 2010 and 2009, EOG expended $6.6 billion, $5.5 billion and $3.9 billion, respectively, for exploratory and development drilling and acquisition of leases and producing properties, including asset retirement obligations of $133 million, $72 million and $84 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, 2011, 2010 and 2009:

			Gross Development Wells Completed				Gross Exploratory Wells Completed
			Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2011
	United States		851	203	24	1,078	11	4	2	17
	Canada		105	9	-	114	2	-	-	2
	Trinidad		-	7	-	7	-	-	-	-
	China		-	-	-	-	-	1	2	3
		Total	956	219	24	1,199	13	5	4	22
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

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, 2011, 2010 and 2009:

			Net Development Wells Completed				Net Exploratory Wells Completed
			Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2011
	United States		687	138	18	843	9	3	2	14
	Canada		95	4	-	99	2	-	-	2
	Trinidad		-	7	-	7	-	-	-	-
	China		-	-	-	-	-	1	2	3
		Total	782	149	18	949	11	4	4	19
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

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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, 2011, 2010 and 2009:

		Wells in Progress at End of Period
		2011		2010		2009
		Gross	Net	Gross	Net	Gross	Net
United States		359	282	243	205	277	239
Canada		-	-	1	1	5	4
Trinidad		-	-	-	-	1	1
United Kingdom		3	2	3	2	1	-
China		1	1	4	4	4	4
	Total	363	285	251	212	288	248

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, 2011, 2010 and 2009:

			Gross Acquired Wells			Net Acquired Wells
			Crude Oil	Natural Gas	Total	Crude Oil	Natural Gas	Total
2011
	United States		8	-	8	4	-	4
	Canada		-	5	5	-	5	5
		Total	8	5	13	4	5	9
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

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, along with sand mine and sand processing 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.

ITEM 4.  Mine Safety Disclosures

The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this report.

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PART II

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

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
2011
	First Quarter	$	121.44	$	90.84	$	0.160
	Second Quarter		119.82		96.62		0.160
	Third Quarter		107.88		69.55		0.160
	Fourth Quarter		106.20		66.81		0.160
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

On February 16, 2012, EOG's Board of Directors (Board) increased the quarterly cash dividend on the common stock from the current $0.16 per share to $0.17 per share, effective beginning with the dividend to be paid on April 30, 2012 to stockholders of record as of April 16, 2012.

As of February 15, 2012, there were approximately 1,850 record holders and approximately 251,000 beneficial owners of EOG's common stock.

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

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

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, 2011 - October 31, 2011	2,196	$79.66	-	6,386,200
November 1, 2011 - November 30, 2011	8,756	98.52	-	6,386,200
December 1, 2011 - December 31, 2011	30,030	98.22	-	6,386,200
Total	40,982	97.29

(1) The 40,982 total shares for the quarter ended December 31, 2011 and the 267,430 shares for the full year 2011 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 2011, EOG did not repurchase any shares under the Board-authorized repurchase program.

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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, 2006 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, 2011)

 

*Cumulative total return assumes reinvestment of dividends.

	2006		2007		2008		2009		2010		2011
EOG	$	100.00	$	143.55	$	107.65	$	158.62	$	149.90	$	162.62
S&P 500	$	100.00	$	105.49	$	66.46	$	84.04	$	96.70	$	98.74
S&P O&G E&P	$	100.00	$	144.43	$	94.52	$	134.31	$	146.76	$	137.32

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ITEM 6.  Selected Financial Data

(In Thousands, Except Per Share Data)

Year Ended December 31	2011		2010		2009		2008		2007
Statement of Income Data:
Net Operating Revenues	$	10,126,115	$	6,099,896	$	4,786,959	$	7,127,143	$	4,239,303
Operating Income	$	2,113,309	$	523,319	$	970,841	$	3,767,185	$	1,648,396
Net Income	$	1,091,123	$	160,654	$	546,627	$	2,436,919	$	1,089,918
Preferred Stock Dividends		-		-		-		443		6,663
Net Income Available to Common Stockholders	$	1,091,123	$	160,654	$	546,627	$	2,436,476	$	1,083,255
Net Income Per Share Available to Common Stockholders
Basic	$	4.15	$	0.64	$	2.20	$	9.88	$	4.45
Diluted	$	4.10	$	0.63	$	2.17	$	9.72	$	4.37
Dividends Per Common Share	$	0.64	$	0.62	$	0.58	$	0.51	$	0.36
Average Number of Common Shares
Basic		262,735		250,876		248,996		246,662		243,469
Diluted		266,268		254,500		251,884		250,542		247,637

At December 31	2011		2010		2009		2008		2007
Balance Sheet Data:
Total Property, Plant and Equipment, Net	$	21,288,824	$	18,680,900	$	16,139,225	$	13,657,302	$	10,429,254
Total Assets		24,838,797		21,624,233		18,118,667		15,951,226		12,088,907
Long-Term Debt and Current Portion of Long-Term Debt		5,009,166		5,223,341		2,797,000		1,897,000		1,185,000
Total Stockholders' Equity		12,640,904		10,231,632		9,998,042		9,014,497		6,990,094

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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 for 2011 totaled $1,091 million as compared to $161 million for 2010.  At December 31, 2011, EOG's total estimated net proved reserves were 2,054 million barrels of oil equivalent (MMBoe), an increase of 104 MMBoe from December 31, 2010.  During 2011, net proved crude oil and condensate and natural gas liquids reserves increased by 207 million barrels (MMBbl) and net proved natural gas reserves decreased by 619 billion cubic feet (Bcf) or 103 MMBoe.

Operations

Several important developments have occurred since January 1, 2011.

United States and Canada.  EOG's efforts to identify plays with large 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 and completion expertise gained from its natural gas resource plays to unconventional crude oil and liquids-rich reservoirs.  In 2011, EOG focused its efforts on developing its existing North American crude oil and condensate and liquids-rich acreage.  In addition, EOG continues to evaluate certain potential liquids-rich exploration and development prospects.  During 2011, crude oil and condensate and natural gas liquids production accounted for approximately 37% of total company production as compared to 27% during 2010.  North American liquids production accounted for approximately 42% of total North American production during 2011 as compared to 31% in 2010.  This liquids growth reflects production from EOG's 572,000 net acre position in the oil window of the Eagle Ford Shale play near San Antonio, Texas, and increasing amounts of crude oil and condensate and natural gas liquids production in the Fort Worth Basin Barnett Shale area.  In 2011, EOG's net Eagle Ford Shale production averaged 34.1 thousand barrels per day (MBbld) of crude oil and condensate and natural gas liquids as compared to 4.3 MBbld in 2010.  Based on current trends, EOG expects its 2012 crude oil and condensate and natural gas liquids production to continue to increase both in total and as a percentage of total company production as compared to 2011.  EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.  EOG delivers its crude oil to various markets in the United States, including sales points on the Gulf Coast.  Most recently, with increases in crude oil production from the Eagle Ford Shale play, EOG has increased sales to the Gulf Coast and is receiving pricing for those sales based on the Light Louisiana Sweet price.  In order to create further market diversification for its growing crude oil production, EOG is expanding  its crude-by-rail system to have the capability to increase deliveries of crude oil to St. James, Louisiana, beginning in the second quarter of 2012.  In addition, to further reduce well completion costs, EOG began using sand from its Wisconsin sand mine and sand processing facilities in late 2011.

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In March 2011, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), purchased an additional 24.5% interest in the proposed Pacific Trail Pipelines (PTP) for $25.2 million.  The PTP is intended to link western Canada's natural gas producing regions to the planned liquefied natural gas (LNG) export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia (Kitimat LNG Terminal).  A portion of the purchase price ($15.3 million) was paid at closing with the remaining amount to be paid contingent on the decision to proceed with the construction of the Kitimat LNG Terminal.  Additionally, in March 2011, EOGRC and an affiliate of Apache Corporation (Apache), through a series of transactions, sold a portion of their interests in the Kitimat LNG Terminal and PTP to an affiliate of Encana Corporation (Encana).  Subsequent to these transactions, ownership interests in both the Kitimat LNG Terminal and PTP are:  Apache (operator) 40%, EOGRC 30% and Encana 30%.  All future costs of the project will be paid by each party in proportion to its respective ownership percentage.  In the first quarter of 2011, EOGRC and Apache awarded a front-end engineering and design contract to a global engineering company with the final report expected in the second half of 2012.  In October 2011, the Canadian National Energy Board granted a 20-year export license to ship LNG from the Kitimat LNG Terminal to international markets.

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 natural gas and crude oil and condensate.  In Block 4(a), EOG drilled and completed six development wells in the Toucan Field and one in the EMZ Area in 2011.  Production from all seven wells began in February 2012 to supply natural gas under a contract with the Natural Gas Company of Trinidad and Tobago.  EOG sourced the natural gas for this contract from its existing fields until the Toucan Field began producing.

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 submitted 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 in the first half of 2012.  The operator and partners are continuing to negotiate processing and transportation terms with export infrastructure owners.

In 2009, EOGUK drilled a successful exploratory well in its East Irish Sea Blocks 110/7b and 110/12a.  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 2011, offshore facilities fabrication began, line pipe was fabricated and all principal facilities and drilling contracts were signed.  Field development plans for the Conwy and Corfe fields were submitted to the DECC during the first quarter of 2011.  Regulatory approval of both plans is expected during the first quarter of 2012.  Installation of facilities, pipelines and drilling of development wells are planned for 2012 with initial production expected during the first quarter of 2013.  The licenses for the East Irish Sea blocks were awarded to EOGUK in 2007.

In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuanzhong Block exploration area in the Sichuan Basin, Sichuan Province, China.  In October 2008, EOG obtained the rights to shallower zones on the acreage acquired.  During the first quarter of 2011, EOG completed one horizontal well.

During 2011, EOG signed two exploration contracts and one farm-in agreement covering approximately 100,000 net acres in the Neuquén Basin in Neuquén Province, Argentina.  During the third quarter of 2011, EOG performed exploration activity on a portion of this acreage in preparation for drilling a well targeting the Vaca Muerta oil shale in the Aguada del Chivato Block.  EOG began drilling this well in January 2012.  In the first quarter of 2012, EOG plans to participate in the drilling of a second well in the Bajo de Toro Block targeting the Vaca Muerta oil shale.

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.

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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 28% and 34% at December 31, 2011 and 2010, respectively.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

During 2011, EOG funded $7.1 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid $220 million in long-term debt, paid $167 million in dividends to common stockholders and purchased $24 million of treasury stock in connection with stock compensation plans, primarily by utilizing cash provided from its operating activities, proceeds of $1,388 million from the sale of common stock and proceeds of $1,433 million from the sale of certain North American assets and the sale of a portion of EOG's interest in the Kitimat LNG Terminal and PTP.

On October 11, 2011, EOG entered into a $2.0 billion senior unsecured Revolving Credit Agreement (2011 Facility) with domestic and foreign lenders.  The 2011 Facility replaced EOG's two $1.0 billion senior unsecured credit facilities which were cancelled by EOG upon the closing of the 2011 Facility.  Unamortized fees relating to the cancelled facilities totaling $5.7 million were written off in the fourth quarter of 2011.  The 2011 Facility has a scheduled maturity date of October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods.

On March 7, 2011, EOG completed the sale of 13,570,000 shares of EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share.  Net proceeds from the sale of the Common Stock were approximately $1,388 million after deducting the underwriting discount and offering expenses. Proceeds from the sale were used for general corporate purposes, including funding capital expenditures.

Total anticipated 2012 capital expenditures are expected to range from $7.4 to $7.6 billion, excluding acquisitions.  The majority of 2012 expenditures will be focused on United States and Canada crude oil and liquids-rich gas drilling activity and, to a much 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 2012.  EOG's business plan includes selling certain non-core assets in 2012 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 the 2011 Facility 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.

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Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2011 should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning with page F-1.

Net Operating Revenues

During 2011, net operating revenues increased $4,026 million, or 66%, to $10,126 million from $6,100 million in 2010.  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 2011 increased $1,977 million, or 41%, to $6,858 million from $4,881 million in 2010.  During 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $626 million compared to net gains of $62 million in 2010.  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, increased $1,206 million, or 133%, during 2011, to $2,116 million from $910 million in 2010.  Gains on asset dispositions, net, totaled $493 million and $224 million in 2011 and 2010, respectively, primarily as a result of asset dispositions in the Rocky Mountain area and Texas in 2011 and in the Rocky Mountain area in 2010.

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Wellhead volume and price statistics for the years ended December 31, 2011, 2010 and 2009 were as follows:

Year Ended December 31	2011		2010		2009
Crude Oil and Condensate Volumes (MBbld) (1)
United States		102.0		63.2		47.9
Canada		7.9		6.7		4.1
Trinidad		3.4		4.7		3.1
Other International (2)		0.1		0.1		0.1
Total		113.4		74.7		55.2
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States	$	92.92	$	74.88	$	54.42
Canada		91.92		72.66		57.72
Trinidad		90.62		68.80		50.85
Other International (2)		100.11		73.11		53.07
Composite		92.79		74.29		54.46
Natural Gas Liquids Volumes (MBbld) (1)
United States		41.5		29.5		22.5
Canada		0.9		0.9		1.1
Total		42.4		30.4		23.6
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States	$	50.37	$	41.68	$	30.03
Canada		52.69		43.40		30.49
Composite		50.41		41.73		30.05
Natural Gas Volumes (MMcfd) (1)
United States		1,113		1,133		1,134
Canada		132		200		224
Trinidad		344		341		273
Other International (2)		13		14		14
Total		1,602		1,688		1,645
Average Natural Gas Prices ($/Mcf) (3)
United States	$	3.92	$	4.30	$	3.72
Canada		3.71		3.91		3.85
Trinidad		3.53		2.65		1.73
Other International (2)		5.62		4.90		4.34
Composite		3.83		3.93		3.42
Crude Oil Equivalent Volumes (MBoed) (4)
United States		329.1		281.5		259.4
Canada		30.7		40.9		42.6
Trinidad		60.7		61.5		48.5
Other International (2)		2.2		2.5		2.4
Total		422.7		386.4		352.9
Total MMBoe (4)		154.3		141.1		128.8

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

(2) Other International includes EOG's United Kingdom and 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.

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2011 compared to 2010.  Wellhead crude oil and condensate revenues in 2011 increased $1,839 million, or 92%, to $3,838 million from $1,999 million in 2010, due to an increase of 39 MBbld, or 52%, in wellhead crude oil and condensate deliveries ($1,074 million) and a higher composite average wellhead crude oil and condensate price ($765 million).  The increase in deliveries primarily reflects increased production in Texas (35 MBbld) and Colorado (3 MBbld).  Production increases in Texas were the result of increased production from the Eagle Ford Shale (26 MBbld) and Fort Worth Basin Barnett Combo (8 MBbld) plays.  EOG's composite average wellhead crude oil and condensate price for 2011 increased 25% to $92.79 per barrel compared to $74.29 per barrel in 2010.

Natural gas liquids revenues in 2011 increased $317 million, or 69%, to $779 million from $462 million in 2010, due to an increase of 12 MBbld, or 39%, in natural gas liquids deliveries ($183 million) and a higher composite average price ($134 million).  The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale (6 MBbld), the Eagle Ford Shale (4 MBbld) and the Rocky Mountain area (3 MBbld).  EOG's composite average natural gas liquids price in 2011 increased 21% to $50.41 per barrel compared to $41.73 per barrel in 2010.

Wellhead natural gas revenues in 2011 decreased $179 million, or 7%, to $2,241 million from $2,420 million in 2010.  The decrease was due to reduced natural gas deliveries ($123 million) and a lower composite average wellhead natural gas price ($56 million).  EOG's composite average wellhead natural gas price decreased 3% to $3.83 per Mcf in 2011 from $3.93 per Mcf in 2010.

Natural gas deliveries in 2011 decreased 86 MMcfd, or 5%, to 1,602 MMcfd from 1,688 MMcfd in 2010.  The decrease was primarily due to lower production in Canada (68 MMcfd) and the United States (20 MMcfd).  The decrease in Canada primarily reflects sales of certain shallow natural gas assets in 2010, partially offset by increased production from the Horn River Basin area.  The decrease in the United States was primarily attributable to decreased production in the Rocky Mountain area (36 MMcfd), Louisiana (17 MMcfd), Mississippi (11 MMcfd), New Mexico (8 MMcfd) and Kansas (5 MMcfd), partially offset by increased production in Texas (38 MMcfd) and Pennsylvania (23 MMcfd).

During 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $626 million, which included net realized gains of $181 million.  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.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas.  For the years ended December 31, 2011, 2010 and 2009, gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and 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 2011, 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 2011 increased $19 million to $44 million from $25 million in 2010, primarily as a result of increased crude oil marketing activities.

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.

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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 Mcf in 2010 from $3.42 per Mcf in 2009.

Natural gas deliveries in 2010 increased 43 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.

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.

Operating and Other Expenses

2011 compared to 2010.  During 2011, operating expenses of $8,013 million were $2,436 million higher than the $5,577 million incurred in 2010.The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2011 and 2010:

	2011		2010
Lease and Well	$	6.11	$	4.96
Transportation Costs		2.79		2.74
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties(1)		15.52		13.19
Other Property, Plant and Equipment		0.79		0.79
General and Administrative (G&A)		1.98		1.99
Net Interest Expense		1.36		0.92
Total (2)	$	28.55	$	24.59

(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 related to the acquisition of certain unproved acreage.

(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 2011 compared to 2010 are set forth below.

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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 costs 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 and maintenance 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 and maintenance costs for wells producing crude oil are higher than operating and maintenance costs for wells producing natural gas.

Lease and well expenses of $942 million in 2011 increased $244 million from $698 million in 2010 primarily due to higher operating and maintenance expenses in the United States ($188 million), increased lease and well administrative expenses in the United States ($33 million), increased workover expenditures in the United States ($11 million) and Canada ($4 million) and unfavorable changes in the Canadian exchange rate ($6 million), partially offset by lower operating and maintenance costs in Canada ($4 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 crude-by-rail operations.

Transportation costs of $430 million in 2011 increased $45 million from $385 million in 2010 primarily due to increased transportation costs in the Eagle Ford Shale ($30 million), the Upper Gulf Coast area ($16 million) and the Fort Worth Basin Barnett Shale area ($9 million), partially offset by decreased transportation costs in Canada ($4 million), the Rocky Mountain area ($2 million) and the South Texas area ($2 million).  The net increase in transportation costs primarily reflects increased volumes transported to downstream markets.

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

DD&A expenses in 2011 increased $574 million to $2,516 million from $1,942 million in 2010.  DD&A expenses associated with oil and gas properties in 2011 were $563 million higher than in 2010 primarily due to higher unit rates as described above ($375 million), increased production in the United States ($249 million), a reduction during 2010 in the fair value of the contingent consideration liability ($24 million) and unfavorable changes in the Canadian exchange rate ($11 million), partially offset by a decrease in production in Canada ($77 million).  DD&A rates increased due primarily to a proportional increase in production from higher cost properties in the United States ($306 million), Trinidad ($37 million) and Canada ($9 million).

DD&A expenses associated with other property, plant and equipment were $11 million higher in 2011 than in 2010 primarily due to gathering and processing assets being placed in service in the Eagle Ford Shale ($5 million) and the Rocky Mountain area ($3 million).

G&A expenses of $305 million in 2011 were $25 million higher than 2010 due primarily to higher employee-related costs.

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Net interest expense of $210 million in 2011 increased $80 million from $130 million in 2010 primarily due to a higher average debt balance ($56 million), lower capitalized interest ($18 million) and the write-off of fees associated with revolving credit facilities cancelled in 2011 in connection with the establishment of the 2011 Facility ($6 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 $14 million to $81 million in 2011 compared to $67 million in 2010.  The increase primarily reflects increased activities in the Fort Worth Basin Barnett Shale area ($10 million), the Eagle Ford Shale ($5 million) and Canada ($5 million), partially offset by decreased activities in the Upper Gulf Coast region ($5 million) and the Rocky Mountain area ($4 million).

Exploration costs of $172 million in 2011 decreased $15 million from $187 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States.

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties and other property, plant and equipment.  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 using the Income Approach as described in the Fair Value Measurement and Disclosures Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC).  For certain natural gas assets held for sale, EOG utilized accepted bids as the basis for determining fair value.

Impairments of $1,031 million in 2011 increased $288 million from $743 million in 2010 primarily due to increased impairments of proved properties and other property, plant and equipment in the United States.  EOG recorded impairments of proved properties and other property, plant and equipment of $834 million and $526 million in 2011 and 2010, respectively.  The 2011 amount includes impairments of $745 million related to certain North American natural gas assets as a result of declining commodity prices and accepted bids.

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 2011 increased $94 million to $411 million (6% of wellhead revenues) from $317 million (6.5% of wellhead revenues) in 2010.  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 ($101 million) and a decrease in credits available to EOG in 2011 for Texas high cost gas severance tax rate reductions as a result of fewer wells qualifying for such credit ($8 million), partially offset by lower ad valorem/property taxes in the United States ($9 million) and Canada ($4 million) and decreased severance/production taxes in Trinidad ($4 million).

Other income, net was $7 million in 2011 compared to $14 million in 2010.  The decrease of $7 million was primarily due to operating losses on EOG's investment in the PTP ($5 million) and an increase in foreign currency transaction losses ($5 million), partially offset by higher equity income from ammonia plants in Trinidad ($3 million).

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Income tax provision of $819 million in 2011 increased $572 million from $247 million in 2010 due primarily to greater pretax income.  The net effective tax rate for 2011 decreased to 43% from 61% in 2010.  The effective tax rate for 2011 exceeded the United States statutory tax rate (35%) due mostly to foreign earnings in Trinidad (55% statutory tax rate) combined with losses in Canada (27% statutory tax rate).

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 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
DD&A -
Oil and Gas Properties(1)		13.19		11.29
Other Property, Plant and Equipment		0.79		0.74
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 related to the acquisition of certain unproved acreage.

(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 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 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 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).

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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 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 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 16 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 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 was 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 assets.  The statutory tax rates in the United States and Trinidad are higher than the Canadian statutory rate.

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Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2011 were funds generated from operations, net proceeds from issuances of long-term debt, proceeds from asset sales, net proceeds from the sale of Common Stock, 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.

2011 compared to 2010.  Net cash provided by operating activities of $4,578 million in 2011 increased $1,869 million from $2,709 million in 2010 primarily reflecting an increase in wellhead revenues ($1,977 million), favorable changes in the net cash flow from the settlement of financial commodity derivative contracts ($174 million) and favorable changes in working capital and other assets and liabilities ($137 million), partially offset by an increase in cash operating expenses ($383 million), an increase in cash paid for interest expense ($40 million) and an increase in cash paid for income taxes ($27 million).

Net cash used in investing activities of $5,755 million in 2011 increased by $852 million from $4,903 million for the same period of 2010 due primarily to an increase in additions to oil and gas properties ($1,084 million), unfavorable changes in working capital associated with investing activities ($446 million) and an increase in additions to other property, plant and equipment ($286 million), partially offset by an increase in proceeds from sales of assets ($761 million) and the acquisition of Galveston LNG Inc. in 2010 ($210 million).

Net cash provided by financing activities of $1,009 million in 2011 included net proceeds from the sale of Common Stock ($1,388 million) and proceeds from stock options exercised and employee stock purchase plan activity ($36 million).  Cash used in financing activities during 2011 included the repayment of long-term debt ($220 million), cash dividend payments ($167 million), treasury stock purchases in connection with stock compensation plans ($24 million) and debt issuance costs associated with the establishment of the 2011 Facility ($5 million).

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).

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Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2011, 2010 and 2009 (in millions):

	Actual
		2011		2010		2009
Expenditure Category
Capital
Drilling and Facilities		$	5,878	$	4,634	$	2,417
Leasehold Acquisitions			301		399		424
Property Acquisitions (1)			4		18		707
Capitalized Interest			58		76		55
Subtotal			6,241		5,127		3,603
Exploration Costs			172		187		170
Dry Hole Costs			53		72		51
Exploration and Development Expenditures			6,466		5,386		3,824
Asset Retirement Costs			133		72		84
Total Exploration and Development Expenditures			6,599		5,458		3,908
Other Property, Plant and Equipment (2)			656		581		326
Total Expenditures		$	7,255	$	6,039	$	4,234

(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 16 to Consolidated Financial Statements).

(2) In 2010, other property, plant and equipment included $210 million for the acquisition of Galveston LNG Inc. (see Note 16 to Consolidated Financial Statements).

Exploration and development expenditures of $6,466 million for 2011 were $1,080 million higher than the prior year due primarily to increased drilling and facilities expenditures in the United States ($1,421 million) and the United Kingdom ($62 million), increased dry hole costs in China ($22 million) and unfavorable changes in the foreign currency exchange rate in Canada ($15 million).  These increases were partially offset by decreased drilling and facilities expenditures in Canada ($181 million) and China ($70 million); decreased leasehold acquisitions expenditures in the United States ($90 million) and Canada ($8 million); decreased dry hole costs in the United Kingdom ($22 million), Canada ($14 million) and Trinidad ($5 million); decreased capitalized interest in the United States ($18 million); decreased property acquisition expenditures in the United States ($14 million); and decreased exploration geological and geophysical expenditures in the United States ($13 million).  The 2011 exploration and development expenditures of $6,466 million included $5,797 million in development, $607 million in exploration, $58 million in capitalized interest and $4 million in property acquisitions.  In 2011, other property, plant and equipment expenditures included $231 million for sand mine and sand processing assets.  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.  In 2010, other property, plant and equipment expenditures included $210 million for 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.  In 2009,  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 expenditure budget as circumstances warrant.  While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

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Derivative Transactions

During 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $626 million, which included net realized gains of $181 million.  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.  See Note 11 to Consolidated Financial Statements.

Commodity Derivative Contracts.  The total fair value of EOG's crude oil and natural gas derivative contracts is reflected on the Consolidated Balance Sheets at December 31, 2011 as an asset of $486 million.  Presented below is a comprehensive summary of EOG's crude oil derivative contracts at February 24, 2012, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

Crude Oil Derivative Contracts
			Weighted
	Volume		Average Price
	(Bbld)		($/Bbl)
2012 (1)
January 2012 (closed)		34,000	$	104.95
February 2012		34,000		104.95
March 1, 2012 through June 30, 2012		52,000		105.80
July 1, 2012 through August 31, 2012		35,000		105.56
September 1, 2012 through December 31, 2012		17,000		103.59

(1)   EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Options covering a notional volume of 17,000 Bbld are exercisable on June 29, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 17,000 Bbld at an average price of $106.31 per barrel for the period July 1, 2012 through December 31, 2012.  Options covering a notional volume of 18,000 Bbld are exercisable on August 31, 2012.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 18,000 Bbld at an average price of $107.42 per barrel for the period September 1, 2012 through February 28, 2013.

Presented below is a comprehensive summary of EOG's natural gas derivative contracts as of February 24, 2012, with notional volumes expressed in MMBtu per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Derivative Contracts
	Volume (MMBtud)		Weighted Average Price ($/MMBtu)
2012 (1)
January 2012 through February 29, 2012 (closed)		525,000	$	5.44
March 1, 2012 through December 31, 2012		525,000		5.44
2013 (2)
January 1, 2013 through December 31, 2013		150,000	$	4.79
2014 (2)
January 1, 2014 through December 31, 2014		150,000	$	4.79

(1) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from March 1, 2012 through December 31, 2012.

(2) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2013 and 2014.

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Financing

EOG's debt-to-total capitalization ratio was 28% at December 31, 2011 compared to 34% at December 31, 2010.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

During 2011, total debt outstanding decreased $220 million to $5,040 million.  The estimated fair value of EOG's debt at December 31, 2011 and 2010 was $5,657 million and $5,602 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, 2011, a 1% decline in interest rates would result in a $315 million increase in the estimated fair value of the fixed rate obligations.  See Note 2 to Consolidated Financial Statements.

During 2011, EOG utilized cash provided by operating activities, proceeds from the public offering of EOG Common Stock described below and proceeds from asset sales and cash provided by borrowings from its commercial paper program to fund its capital programs.  While EOG maintains a $2.0 billion commercial paper program, the maximum outstanding at any time during 2011 was $182 million, and the amount outstanding at year-end was zero.  The average borrowings outstanding under the commercial paper program were $3 million during the year 2011.  EOG considers this excess availability, which is backed by the 2011 Facility described in Note 2 to Consolidated Financial Statements, to be ample to meet its ongoing operating needs.

On March 7, 2011, EOG completed the sale of 13,570,000 shares of Common Stock at the public offering price of $105.50 per share.  Net proceeds from the sale of the Common Stock were approximately $1,388 million after deducting the underwriting discount and offering expenses. Proceeds from the sale were used for general corporate purposes, including funding capital expenditures.

Contractual Obligations

The following table summarizes EOG's contractual obligations at December 31, 2011 (in thousands):

									2017 &
Contractual Obligations (1)	Total		2012			2013 - 2014		2015 - 2016	Beyond
Current and Long-Term Debt	$	5,040,000	$	-	$	900,000	$	900,000	$	3,240,000
Non-Cancelable Operating Leases		502,076		173,061		97,515		68,231		163,269
Interest Payments on Long-Term Debt		1,570,811		234,918		436,864		366,370		532,659
Transportation and Storage Service Commitments (2)		3,256,452		359,686		779,585		844,944		1,272,237
Drilling Rig Commitments (3)		339,206		230,541		105,319		3,346		-
Seismic Purchase Obligations		4,087		4,087		-		-		-
Fracturing Services Obligations		338,585		301,851		27,827		8,907		-
Other Purchase Obligations		120,108		116,533		3,489		86		-
Total Contractual Obligations	$	11,171,325	$	1,420,677	$	2,350,599	$	2,191,884	$	5,208,165

(1) This table does not include the liability for unrecognized tax benefits, EOG's pension or postretirement benefit obligations or liability for dismantlement, abandonment and asset retirement obligations (see Notes 5, 6 and 14, respectively, to Consolidated Financial Statements).

(2) Amounts shown are based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars and British pounds into United States dollars at December 31, 2011.  Management does not believe that any future changes in these rates before the expiration dates of these commitments will have a material adverse effect on the financial condition or results of operations of EOG.

(3) Amounts shown represent minimum future expenditures for drilling rig services.  EOG's expenditures for drilling rig services will exceed such minimum amounts to the extent EOG utilizes the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract or if EOG utilizes drilling rigs in addition to the drilling rigs subject to the particular contractual commitment (for example, pursuant to the exercise of an option to utilize additional drilling rigs provided for in the governing contract).

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Off-Balance Sheet Arrangements

EOG does not participate in financial transactions that generate relationships with unconsolidated entities or financial partnerships.  Such entities or partnerships, often referred to as variable interest entities (VIE) or special purpose entities (SPE), are generally established for the purpose of facilitating off-balance sheet arrangements or other limited purposes. EOG was not involved in any unconsolidated VIE or SPE financial transactions or any other "off-balance sheet arrangement" (as defined in Item 303(a)(4)(ii) of Regulation S-K) during any of the periods covered by this report, and currently has no intention of participating in any such transaction or arrangement in the foreseeable future.

Foreign Currency Exchange Rate Risk

During 2011, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Canada, Trinidad, the United Kingdom, China and Argentina.  The foreign currency most significant to EOG's operations during 2011 was the Canadian dollar.  The fluctuation of the Canadian dollar in 2011 impacted both the revenues and expenses of EOG's Canadian subsidiaries.  However, since Canadian commodity prices are largely correlated to United States prices, the changes in the Canadian currency exchange rate have less of an impact on the Canadian revenues than the Canadian expenses.  EOG continues to monitor the foreign currency exchange rates of countries in which it is currently conducting business and may implement measures to protect against the foreign currency exchange rate risk.

Effective March 9, 2004, EOG entered into a foreign currency swap transaction with multiple banks to eliminate exchange rate impacts that may result from the notes offered by one of its Canadian subsidiaries on the same date (see Note 2 to Consolidated Financial Statements).  EOG accounts for the foreign currency swap transaction using the hedge accounting method, pursuant to the provisions of the Derivatives and Hedging Topic of the ASC.  Under those provisions, as of December 31, 2011, EOG recorded the fair value of the foreign currency swap of $52 million in Other Liabilities on the Consolidated Balance Sheets.  Changes in the fair value of the foreign currency swap resulted in no net impact to Net Income on the Consolidated Statements of Income and Comprehensive Income.  The after-tax net impact from the foreign currency swap transaction resulted in a negative change of $1 million for the year ended December 31, 2011.  The change is included in Accumulated Other Comprehensive Income in the Stockholders' Equity section of the Consolidated Balance Sheets.

Outlook

Pricing.  Crude oil and natural gas prices have been volatile, and this volatility is expected to continue.  As a result of 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.  The market price of crude oil and condensate,  natural gas liquids and natural gas in 2012 will impact the amount of cash generated from operating activities, which will in turn impact EOG's financial position.  See Item 1A. Risk Factors.

Including the impact of EOG's 2012 crude oil derivative contracts and based on EOG's tax position, EOG's price sensitivity in 2012 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 $31 million for net income and $46 million for cash flows from operating activities.  Including the impact of EOG's 2012 natural gas derivative contracts, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2012 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 $11 million for net income and $16 million for cash flows from operating activities.  For information regarding EOG's crude oil and natural gas financial commodity derivative contracts as of February 24, 2012, see "Derivative Transactions" above.

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Capital. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States and Canada.  In particular, EOG will be focused on United States and Canada crude oil and liquids-rich drilling activity in its Eagle Ford, Bakken and Three Forks, Barnett Combo, Wolfcamp and Leonard Shale plays and, to a much lesser extent, United States and Canada natural gas drilling activity in the Haynesville, Marcellus and British Columbia Horn River Basin plays to hold acreage.  In order to diversify its overall asset portfolio, EOG expects to conduct exploratory activity in other areas outside of the United States and Canada and will continue to evaluate the potential for involvement in additional exploitation-type opportunities.

The total anticipated 2012 capital expenditures of $7.4 to $7.6 billion, excluding acquisitions, is structured to maintain the flexibility necessary under EOG's strategy of funding its exploration, development, exploitation and acquisition activities primarily from available internally generated cash flow and the sale of certain non-core assets.  EOG expects capital expenditures to be greater than cash flow from operating activities for 2012.  EOG's business plan includes selling certain non-core assets in 2012 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 the 2011 Facility and equity and debt offerings.

Operations.  EOG expects to increase overall production in 2012 by 5.5% over 2011 levels.  Total liquids production is expected to increase by 30%, comprised of an increase in crude oil and condensate and natural gas liquids production of 30% and 30%, respectively.  North American natural gas production is expected to decrease by 11% from 2011 levels.

Summary of Critical Accounting Policies

EOG prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes.  EOG identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of EOG's financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their deployment.  Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown.  Management routinely discusses the development, selection and disclosure of each of the critical accounting policies.  Following is a discussion of EOG's most critical accounting policies:

Proved Oil and Gas Reserves

EOG's engineers estimate proved oil and gas reserves, which directly impact financial accounting estimates, including depreciation, depletion and amortization.  Proved reserves represent estimated quantities of crude oil and condensate, natural gas liquids and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.  The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir.  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.  Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.  For related discussion, see ITEM 1A. Risk Factors.

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Oil and Gas Exploration Costs

EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.  Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred.  The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered proved commercial reserves.  Exploratory drilling costs are capitalized when drilling is complete if it is determined that there is economic producibility supported by either actual production, a conclusive formation test or by certain technical data if the discovery is located offshore.  If proved commercial reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of December 31, 2011 and 2010, EOG had exploratory drilling costs related to projects that have been deferred for more than one year (see Note 15 to Consolidated Financial Statements).  These costs meet the accounting requirements outlined above for continued capitalization.  Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

Depreciation, Depletion and Amortization for Oil and Gas Properties

The quantities of estimated proved oil and gas reserves are a significant component of EOG's calculation of depreciation, depletion and amortization expense and revisions in such estimates may alter the rate of future expense.  Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease, respectively.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method.  The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.  With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.  Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas Topic of the ASC.  The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.

Depreciation and amortization of other property, plant and equipment is calculated on a straight-line basis over the estimated useful life of the asset.

Impairments

Oil and gas lease acquisition costs are capitalized when incurred.  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.  If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties.  Lease rentals are expensed as incurred.

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When circumstances indicate that an asset 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, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated using the income approach described in the Fair Value Measurements and Disclosures Topic of the ASC.  In certain instances, EOG utilizes accepted bids as the basis for determining fair value.  Estimates of future undiscounted cash flows require significant judgment.  Crude oil and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future.  During the past five years, West Texas Intermediate crude oil spot prices have fluctuated from approximately $30 per barrel (Bbl) to $145 per Bbl and Henry Hub natural gas spot prices have ranged from approximately $1.83 per million British thermal units (MMBtu) to $13 per MMBtu.  EOG's proved reserves estimates, including the timing of future production, are also subject to significant judgment, and are frequently revised (upwards and downwards) as more information becomes available.  In the future, if actual crude oil and/or natural gas prices and/or actual production diverge negatively from EOG's current estimates, impairment charges may be necessary.

Stock-Based Compensation

In accounting for stock-based compensation, judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs required by those valuation methodologies.  Assumptions regarding expected volatility of EOG's Common Stock, the level of risk-free interest rates, expected dividend yields on EOG's Common Stock, the expected term of the awards and other valuation inputs are subject to change.  Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized on the Consolidated Statements of Income and Comprehensive Income.

Information Regarding Forward-Looking Statements

This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements.  EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements.  In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate income or cash flows or pay dividends are forward-looking statements.  Forward-looking statements are not guarantees of performance.  Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct.  Moreover, EOG's forward-looking statements may be affected by known and unknown risks, events or circumstances that may be outside EOG's control.  Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

·   the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;

·   the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

·   the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing;

·   the extent to which EOG is successful in its efforts to economically develop its acreage in, and to produce reserves and achieve anticipated production levels from, its existing and future crude oil and natural gas exploration and development projects, given the risks and uncertainties and capital expenditure requirements inherent in drilling, completing and operating crude oil and natural gas wells and the potential for interruptions of development and production, whether involuntary or intentional as a result of market or other conditions;

·   the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;

49

·   the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

·   the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way;

·   the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

·   EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

·   the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;

·   competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

·   the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

·   weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation of production, gathering, processing, compression and transportation facilities;

·   the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

·   EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;

·   the extent and effect of any hedging activities engaged in by EOG;

·   the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;

·   political developments around the world, including in the areas in which EOG operates;

·   the use of competing energy sources and the development of alternative energy sources;

·   the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;

·   acts of war and terrorism and responses to these acts; and

·   the other factors described under Item 1A, "Risk Factors", on pages 15 through 23 of this Annual Report on Form 10-K and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

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ITEM 7A.  Quantitative and Qualitative Disclosures About Market Risk

The information required by this Item is incorporated by reference from Item 7 of this report, specifically the information set forth under the captions "Derivative Transactions," "Financing," "Foreign Currency Exchange Rate Risk" and "Outlook" in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity."

ITEM 8.  Financial Statements and Supplementary Data

The information required by this Item is included in this report as set forth in the "Index to Financial Statements" on page F-1 and is incorporated by reference herein.

ITEM 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

ITEM 9A.  Controls and Procedures

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of December 31, 2011.  Based on this evaluation, EOG's principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of December 31, 2011 in ensuring that information that is required to be disclosed in the reports EOG files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to EOG's management as appropriate to allow timely decisions regarding required disclosure.

Management's Annual Report on Internal Control over Financial Reporting.  EOG's management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act).  Even an effective system of internal control over financial reporting, no matter how well designed, has inherent limitations, including the possibility of human error, circumvention of controls or overriding of controls and, therefore, can provide only reasonable assurance with respect to reliable financial reporting.  Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change.

EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2011.  In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.  Based on this assessment and such criteria, EOG's management believes that EOG's internal control over financial reporting was effective as of December 31, 2011.  See also "Management's Responsibility for Financial Reporting" appearing on page F-2 of this report, which is incorporated herein by reference.

The report of EOG's independent registered public accounting firm relating to the consolidated financial statements, financial statement schedule and effectiveness of internal control over financial reporting is set forth beginning on page F-3 of this report.

There were no changes in EOG's internal control over financial reporting that occurred during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

ITEM 9B.  Other Information

None.

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PART III

ITEM 10.  Directors, Executive Officers and Corporate Governance

The information required by this Item is incorporated by reference from (i) EOG's Definitive Proxy Statement with respect to its 2012 Annual Meeting of Stockholders to be filed not later than April 29, 2012 and (ii) Item 1 of this report, specifically the information therein set forth under the caption "Executive Officers of the Registrant."

Pursuant to Rule 303A.10 of the New York Stock Exchange and Item 406 of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, EOG has adopted a Code of Business Conduct and Ethics (Code of Conduct) that applies to all EOG directors, officers and employees, including EOG's principal executive officer, principal financial officer and principal accounting officer.  EOG has also adopted a Code of Ethics for Senior Financial Officers (Code of Ethics) that, along with EOG's Code of Conduct, applies to EOG's principal executive officer, principal financial officer, principal accounting officer and controllers.

You can access the Code of Conduct and Code of Ethics on the Corporate Governance page under Investors on EOG's website at www.eogresources.com, and any EOG stockholder who so requests may obtain a printed copy of the Code of Conduct and Code of Ethics by submitting a written request to EOG's Corporate Secretary.

EOG intends to disclose any amendments to the Code of Conduct or Code of Ethics, and any waivers with respect to the Code of Conduct or Code of Ethics granted to EOG's principal executive officer, principal financial officer, principal accounting officer, any of our controllers or any of our other employees performing similar functions, on its website at www.eogresources.com within four business days of the amendment or waiver.  In such case, the disclosure regarding the amendment or waiver will remain available on EOG's website for at least 12 months after the initial disclosure.  There have been no waivers granted with respect to EOG's Code of Conduct or Code of Ethics.

ITEM 11.  Executive Compensation

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2012 Annual Meeting of Stockholders to be filed not later than April 29, 2012.  The Compensation Committee Report and related information incorporated by reference herein shall not be deemed "soliciting material" or to be "filed" with the United States 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 incorporates such information by reference into such a filing.

ITEM 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this Item with respect to security ownership of certain beneficial owners and management is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2012 Annual Meeting of Stockholders to be filed not later than April 29, 2012.

Equity Compensation Plan Information

Stock Plans Approved by EOG Stockholders.  EOG's stockholders approved the EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) at the 2008 Annual Meeting of Stockholders in May 2008.  At the 2010 Annual Meeting of Stockholders in April 2010 (2010 Annual Meeting), an amendment to the 2008 Plan was approved, pursuant to which the number of shares of common stock available for future grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units and other stock-based awards under the 2008 Plan was increased by an additional 6.9 million shares, to an aggregate maximum of 12.9 million shares plus shares underlying forfeited or cancelled grants under the prior stock plans referenced below.  Under the 2008 Plan, grants may be made to employees and non-employee members of EOG's Board of Directors (Board).

At the 2010 Annual Meeting, an amendment to the Employee Stock Purchase Plan (ESPP) was approved to increase the shares available for grant by 1.0 million shares.  The ESPP was originally approved by EOG's stockholders in 2001, and would have expired on July 1, 2011.  The amendment also extended the term of the ESPP to December 31, 2019, unless terminated earlier by its terms or by EOG.

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The 1992 Stock Plan and the 1993 Nonemployee Directors Stock Option Plan have also been approved by EOG's stockholders.  Plans that have not been approved by EOG's stockholders are described below.

Stock Plans Not Approved by EOG Stockholders.  The Board approved the 1994 Stock Plan, which provides equity compensation to employees who are not officers within the meaning of Rule 16a-1 of the Securities Exchange Act of 1934, as amended.  Under the 1994 Stock Plan, employees have been granted stock options (rights to purchase shares of EOG common stock at a price not less than the market price of the stock on the date of grant).  These stock options vest on a graded vesting schedule up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements.  Terms for stock options granted under the 1994 Stock Plan have not exceeded a maximum term of 10 years.  Employees have also been granted shares of restricted stock and/or restricted stock units under the 1994 Stock Plan without cost to the employee.  The shares and units granted vest up to five years after the date of grant as defined in individual grant agreements.  Shares of restricted stock, upon vesting, are released to the employee.  Each restricted stock unit, upon vesting, is converted into one share of EOG common stock and released to the employee.  Upon the effective date of the 2008 Plan, no further grants were made under the 1994 Stock Plan.

In December 2008, the Board approved the amendment and continuation of the 1996 Deferral Plan as the "EOG Resources, Inc. 409A Deferred Compensation Plan" (Deferral Plan).  Under the Deferral Plan, payment of up to 50% of base salary, 100% of annual cash bonus, directors fees, vestings of restricted stock units granted to non-employee directors and 401(k) refunds resulting from excess deferrals in the EOG Resources, Inc. Savings Plan may be deferred into a phantom stock account. In the phantom stock account, deferrals are treated as if shares of EOG common stock were purchased at the closing stock price on the date of deferral.  Dividends are credited quarterly and treated as if reinvested in EOG common stock.  Payment of the phantom stock account is made in actual shares of EOG common stock in accordance with the Deferral Plan and the individual's deferral election.  A total of 120,000 shares have been registered for issuance under the Deferral Plan.  As of December 31, 2011, 118,985 phantom shares had been issued.

The following table sets forth data for EOG's equity compensation plans aggregated by the various plans approved by EOG's stockholders and those plans not approved by EOG's stockholders, in each case as of December 31, 2011.

Plan Category	(a) Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		(b) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Equity Compensation Plans Approved by EOG Stockholders		12,004,029	$	76.98		6,202,142	(1) (2)
Equity Compensation Plans Not Approved by EOG Stockholders		695,350	$	24.78		1,015	(3)
Total		12,699,379	$	74.12		6,203,157

(1) Of these securities, 789,650 shares remain available for purchase under the ESPP.

(2) Of these securities, 1,386,908 could be issued as restricted stock or restricted stock units under the 2008 Plan.

(3) Represents shares that remain available for issuance under the Deferral Plan (as described above).

ITEM 13.  Certain Relationships and Related Transactions, and Director Independence

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2012 Annual Meeting of Stockholders to be filed not later than April 29, 2012.

ITEM 14.  Principal Accounting Fees and Services

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2012 Annual Meeting of Stockholdersto be filed not later than April 29, 2012.

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PART IV

ITEM 15.  Exhibits, Financial Statement Schedules

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedule

See "Index to Financial Statements" set forth on page F-1.

(a)(3), (b)  Exhibits

See pages E-1 through E-7 for a listing of the exhibits.

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EOG RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS

                                                                                                                                                                                                                                                                                                                      Page

Consolidated Financial Statements:
Management's Responsibility for Financial Reporting		F-2
Report of Independent Registered Public Accounting Firm		F-3
Consolidated Statements of Income and Comprehensive Income for Each of the Three Years
	in the Period Ended December 31, 2011	F-5
Consolidated Balance Sheets - December 31, 2011 and 2010		F-6
Consolidated Statements of Stockholders' Equity for Each of the Three Years in the
	Period Ended December 31, 2011	F-7
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended
	December 31, 2011	F-8
Notes to Consolidated Financial Statements		F-9
Supplemental Information to Consolidated Financial Statements		F-33
Financial Statement Schedule:
Schedule II-Valuation and Qualifying Accounts		S-1

Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere on the consolidated financial statements or notes thereto.

F-1

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING

The following consolidated financial statements of EOG Resources, Inc., together with its subsidiaries (collectively, EOG), were prepared by management, which is responsible for the integrity, objectivity and fair presentation of such financial statements.  The statements have been prepared in conformity with generally accepted accounting principles in the United States of America and, accordingly, include some amounts that are based on the best estimates and judgments of management.

EOG's management is also responsible for establishing and maintaining adequate internal control over financial reporting.  The system of internal control of EOG is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.  This system consists of 1) entity level controls, including written policies and guidelines relating to the ethical conduct of business affairs, 2) general computer controls and 3) process controls over initiating, authorizing, recording, processing and reporting transactions.  Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error, circumvention of controls or overriding of controls and, therefore, can provide only reasonable assurance with respect to reliable financial reporting.  Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change.

The adequacy of EOG's financial controls and the accounting principles employed by EOG in its financial reporting are under the general oversight of the Audit Committee of the Board of Directors.  No member of this committee is an officer or employee of EOG.  Moreover, EOG's independent registered public accounting firm and internal auditors have full, free, separate and direct access to the Audit Committee and meet with the committee periodically to discuss accounting, auditing and financial reporting matters.

EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2011.  In making this assessment, EOG used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.  These criteria cover the control environment, risk assessment process, control activities, information and communication systems, and monitoring activities.  Based on this assessment and those criteria, management believes that EOG maintained effective internal control over financial reporting as of December 31, 2011.

Deloitte & Touche LLP, independent registered public accounting firm, was engaged to audit the consolidated financial statements (including financial statement schedule) of EOG, audit EOG's internal control over financial reporting and issue a report thereon.  In the conduct of the audits, Deloitte & Touche LLP was given unrestricted access to all financial records and related data, including minutes of all meetings of stockholders, the Board of Directors and committees of the Board.  Management believes that all representations made to Deloitte & Touche LLP during the audits were valid and appropriate.  Their audits were made in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Their report begins on page F-3.

MARK G. PAPA	TIMOTHY K. DRIGGERS
Chairman of the Board and	Vice President and Chief
Chief Executive Officer	Financial Officer

Houston, Texas

February 24, 2012

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

EOG Resources, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. and subsidiaries (the "Company") as of December 31, 2011 and 2010, and the related consolidated statements of income and comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company's internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company's internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

F-3

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EOG Resources, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Effective December 31, 2009, the Company adopted the updated oil and gas reserve estimation and disclosure rules.

/S/ DELOITTE & TOUCHE LLP

Houston, Texas

February 24, 2012

F-4

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In Thousands, Except Per Share Data)

Year Ended December 31	2011			2010			2009
Net Operating Revenues
Crude Oil and Condensate	$	3,838,284		$	1,998,771		$	1,089,711
Natural Gas Liquids		779,364			462,345			258,799
Natural Gas		2,240,540			2,420,099			2,050,963
Gains on Mark-to-Market Commodity Derivative Contracts		626,053			61,912			431,757
Gathering, Processing and Marketing		2,115,792			909,680			407,116
Gains on Asset Dispositions, Net		492,909			223,538			535,436
Other, Net		33,173			23,551			13,177
Total		10,126,115			6,099,896			4,786,959
Operating Expenses
Lease and Well		941,954			698,430			579,290
Transportation Costs		430,322			385,189			283,329
Gathering and Processing Costs		80,727			66,758			57,632
Exploration Costs		171,658			187,381			169,592
Dry Hole Costs		53,230			72,486			51,243
Impairments		1,031,037			742,647			305,832
Marketing Costs		2,072,137			884,212			397,375
Depreciation, Depletion and Amortization		2,516,381			1,941,926			1,549,188
General and Administrative		304,811			280,474			248,274
Taxes Other Than Income		410,549			317,074			174,363
Total		8,012,806			5,576,577			3,816,118
Operating Income		2,113,309			523,319			970,841
Other Income, Net		6,853			14,243			2,071
Income Before Interest Expense and Income Taxes		2,120,162			537,562			972,912
Interest Expense
Incurred		268,104			205,886			155,820
Capitalized		(57,741	)		(76,300	)		(54,919	)
Net Interest Expense		210,363			129,586			100,901
Income Before Income Taxes		1,909,799			407,976			872,011
Income Tax Provision		818,676			247,322			325,384
Net Income	$	1,091,123		$	160,654		$	546,627
Net Income Per Share
Basic	$	4.15		$	0.64		$	2.20
Diluted	$	4.10		$	0.63		$	2.17
Dividends Declared per Common Share	$	0.64		$	0.62		$	0.58
Average Number of Common Shares
Basic		262,735			250,876			248,996
Diluted		266,268			254,500			251,884
Comprehensive Income
Net Income	$	1,091,123		$	160,654		$	546,627
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		(32,597	)		96,179			308,286
Foreign Currency Swap Transaction		(1,571	)		4,447			6,336
Income Tax Related to Foreign Currency Swap Transaction		404			(1,203	)		(1,519	)
Interest Rate Swap Transaction		(5,223	)		1,843			-
Income Tax Related to Interest Rate Swap Transaction		1,878			(664	)		-
Other		(1,216	)		(251	)		(1,170	)
Comprehensive Income	$	1,052,798		$	261,005		$	858,560

The accompanying notes are an integral part of these consolidated financial statements.

F-5

EOG RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Data)

At December 31	2011			2010
ASSETS
Current Assets
Cash and Cash Equivalents	$	615,726		$	788,853
Accounts Receivable, Net		1,451,227			1,113,279
Inventories		590,594			415,792
Assets from Price Risk Management Activities		450,730			48,153
Income Taxes Receivable		26,609			54,916
Deferred Income Taxes		-			9,260
Other		119,052			97,193
Total		3,253,938			2,527,446
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		33,664,435			29,263,809
Other Property, Plant and Equipment		2,149,989			1,733,073
Total Property, Plant and Equipment		35,814,424			30,996,882
Less:  Accumulated Depreciation, Depletion and Amortization		(14,525,600	)		(12,315,982	)
Total Property, Plant and Equipment, Net		21,288,824			18,680,900
Other Assets		296,035			415,887
Total Assets	$	24,838,797		$	21,624,233
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,033,615		$	1,664,944
Accrued Taxes Payable		147,105			82,168
Dividends Payable		42,578			38,962
Liabilities from Price Risk Management Activities		-			28,339
Deferred Income Taxes		135,989			41,703
Current Portion of Long-Term Debt		-			220,000
Other		163,032			143,983
Total		2,522,319			2,220,099
Long-Term Debt		5,009,166			5,003,341
Other Liabilities		799,189			667,455
Deferred Income Taxes		3,867,219			3,501,706
Commitments and Contingencies (Note 7)
Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 269,323,084 Shares and 254,223,521 Shares Issued at December 31, 2011 and 2010, respectively		202,693			202,542
Additional Paid in Capital		2,272,052			729,992
Accumulated Other Comprehensive Income		401,746			440,071
Retained Earnings		9,789,345			8,870,179
Common Stock Held in Treasury, 303,633 Shares and 146,186 Shares at December 31, 2011 and 2010, respectively		(24,932	)		(11,152	)
Total Stockholders' Equity		12,640,904			10,231,632
Total Liabilities and Stockholders' Equity	$	24,838,797		$	21,624,233

The accompanying notes are an integral part of these consolidated financial statements.

F-6

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In Thousands, Except Per Share Data)

						Accumulated						Common
			Additional			Other						Stock			Total
	Common		Paid In			Comprehensive			Retained			Held In			Stockholders'
	Stock		Capital			Income (Loss)			Earnings			Treasury			Equity
Balance at December 31, 2008	$	202,498	$	323,805		$	27,787		$	8,466,143		$	(5,736	)	$	9,014,497
Net Income		-		-			-			546,627			-			546,627
Common Stock Issued Under Stock Plans		3		18,641			-			-			-			18,644
Common Stock Dividends Declared, $0.58 Per Share		-		-			-			(146,023	)		-			(146,023	)
Foreign Currency Translation Adjustments		-		-			308,286			-			-			308,286
Foreign Currency Swap Transaction, Net of Tax		-		-			4,817			-			-			4,817
Defined Benefit Pension and Post Retirement Plans, Net of Tax		-		-			(1,170	)		-			-			(1,170	)
Change in Treasury Stock - Stock Compensation Plans, Net		-		(4,240	)		-			-			(4,923	)		(9,163	)
Excess Tax Benefits from Stock-Based Compensation		-		76,134			-			-			-			76,134
Restricted Stock and Restricted Stock Units, Net		10		(2,483	)		-			-			2,473			-
Stock-Based Compensation Expenses		-		95,037			-			-			-			95,037
Shares Issued for Property Acquisition		15		89,566			-			-			-			89,581
Treasury Stock Issued as Compensation		-		242			-			-			533			775
Balance at December 31, 2009		202,526		596,702			339,720			8,866,747			(7,653	)		9,998,042
Net Income		-		-			-			160,654			-			160,654
Common Stock Issued Under Stock Plans		10		34,552			-			-			-			34,562
Common Stock Dividends Declared, $0.62 Per Share		-		-			-			(157,222	)		-			(157,222	)
Foreign Currency Translation Adjustments		-		-			96,179			-			-			96,179
Foreign Currency Swap Transaction, Net of Tax		-		-			3,244			-			-			3,244
Defined Benefit Pension and Post Retirement Plans, Net of Tax		-		-			(251	)		-			-			(251	)
Interest Rate Swap, Net of Tax		-		-			1,179			-			-			1,179
Change in Treasury Stock - Stock Compensation Plans, Net		-		(7,257	)		-			-			(4,039	)		(11,296	)
Excess Tax Expense from Stock-Based Compensation		-		(837	)		-			-			-			(837	)
Restricted Stock and Restricted Stock Units, Net		6		(505	)		-			-			499			-
Stock-Based Compensation Expenses		-		107,314			-			-			-			107,314
Treasury Stock Issued as Compensation		-		23			-			-			41			64
Balance at December 31, 2010		202,542		729,992			440,071			8,870,179			(11,152	)		10,231,632
Net Income		-		-			-			1,091,123			-			1,091,123
Common Stock Issued Under Stock Plans		10		35,903			-			-			-			35,913
Common Stock Dividends Declared, $0.64 Per Share		-		-			-			(171,957	)		-			(171,957	)
Foreign Currency Translation Adjustments		-		-			(32,597	)		-			-			(32,597	)
Foreign Currency Swap Transaction, Net of Tax		-		-			(1,167	)		-			-			(1,167	)
Defined Benefit Pension and Post Retirement Plans, Net of Tax		-		-			(1,216	)		-			-			(1,216	)
Interest Rate Swap, Net of Tax		-		-			(3,345	)		-			-			(3,345	)
Change in Treasury Stock - Stock Compensation Plans, Net		-		(18,622	)		-			-			(5,413	)		(24,035	)
Excess Tax Expense from Stock-Based Compensation		-		25			-			-			-			25
Restricted Stock and Restricted Stock Units, Net		5		8,410			-			-			(8,415	)		-
Stock-Based Compensation Expenses		-		128,205			-			-			-			128,205
Common Stock Sold		136		1,388,129			-			-			-			1,388,265
Treasury Stock Issued as Compensation		-		10			-			-			48			58
Balance at December 31, 2011	$	202,693	$	2,272,052		$	401,746		$	9,789,345		$	(24,932	)	$	12,640,904

The accompanying notes are an integral part of these consolidated financial statements.

F-7

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

Year Ended December 31	2011			2010			2009
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	1,091,123		$	160,654		$	546,627
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		2,516,381			1,941,926			1,549,188
Impairments		1,031,037			742,647			305,832
Stock-Based Compensation Expenses		128,345			107,378			95,180
Deferred Income Taxes		499,300			76,245			174,392
Gains on Asset Dispositions, Net		(492,909	)		(223,538	)		(535,436	)
Other, Net		15,139			(468	)		6,761
Dry Hole Costs		53,230			72,486			51,243
Mark-to-Market Commodity Derivative Contracts
Total Gains		(626,053	)		(61,912	)		(431,757	)
Realized Gains		180,701			7,033			1,277,584
Excess Tax Benefits from Stock-Based Compensation		-			-			(76,134	)
Other, Net		26,454			17,273			18,862
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(339,780	)		(339,126	)		(47,818	)
Inventories		(176,623	)		(171,791	)		(50,146	)
Accounts Payable		351,087			654,688			(153,565	)
Accrued Taxes Payable		92,589			(53,098	)		90,929
Other Assets		(23,625	)		(32,169	)		(5,515	)
Other Liabilities		14,986			19,342			(12,305	)
Changes in Components of Working Capital Associated with Investing and Financing Activities		237,028			(208,968	)		118,517
Net Cash Provided by Operating Activities		4,578,410			2,708,602			2,922,439
Investing Cash Flows
Additions to Oil and Gas Properties		(6,294,397	)		(5,210,612	)		(3,176,783	)
Additions to Other Property, Plant and Equipment		(656,415	)		(370,770	)		(326,226	)
Acquisition of Galveston LNG Inc.		-			(210,000	)		-
Proceeds from Sales of Assets		1,433,137			672,593			212,000
Changes in Components of Working Capital Associated with Investing Activities		(237,267	)		208,933			(118,221	)
Other, Net		-			7,082			(5,321	)
Net Cash Used in Investing Activities		(5,754,942	)		(4,902,774	)		(3,414,551	)
Financing Cash Flows
Common Stock Sold		1,388,265			-			-
Long-Term Debt Borrowings		-			2,478,659			900,000
Long-Term Debt Repayments		(220,000	)		(37,000	)		-
Dividends Paid		(167,169	)		(153,240	)		(142,260	)
Excess Tax Benefits from Stock-Based Compensation		-			-			76,134
Treasury Stock Purchased		(23,922	)		(11,295	)		(10,986	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		35,913			34,560			20,465
Debt Issuance Costs		(4,787	)		(8,300	)		(8,895	)
Other, Net		239			35			(296	)
Net Cash Provided by Financing Activities		1,008,539			2,303,419			834,162
Effect of Exchange Rate Changes on Cash		(5,134	)		(6,145	)		12,390
(Decrease) Increase in Cash and Cash Equivalents		(173,127	)		103,102			354,440
Cash and Cash Equivalents at Beginning of Year		788,853			685,751			331,311
Cash and Cash Equivalents at End of Year	$	615,726		$	788,853		$	685,751

The accompanying notes are an integral part of these consolidated financial statements.

F-8

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  Summary of Significant Accounting Policies

Principles of Consolidation.  The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries.  Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method.  All intercompany accounts and transactions have been eliminated.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Financial Instruments.  EOG's financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt, along with associated foreign currency and interest rate swaps.  The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable, foreign currency and interest rate swaps and accounts payable approximate fair value (see Notes 2 and 11).

Cash and Cash Equivalents.  EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.

Oil and Gas Operations.  EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.

Oil and gas lease acquisition costs are capitalized when incurred.  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.  If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred.  The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered proved commercial reserves.  If proved commercial reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 15).  Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method.  The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.  With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.  Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

F-9

Oil and gas properties are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC).  The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.

When circumstances indicate that an asset 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, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated using the income approach described in the Fair Value Measurements and Disclosures Topic of the ASC.  If applicable, EOG utilizes accepted bids as the basis for determining fair value.

Inventories, consisting primarily of tubular goods, materials for completion operations and well equipment held for use in the exploration for, and development and production of, crude oil and natural gas reserves, are carried at cost with adjustments made, as appropriate, to recognize any reductions in value.

Arrangements for crude oil and condensate, natural gas liquids and natural gas sales are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered.  A significant majority of the purchasers of these products have investment grade credit ratings and material credit losses have been rare.  Revenues are recorded on the entitlement method based on EOG's percentage ownership of current production.  Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold on that owner's behalf may differ from that owner's ownership percentage.  Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs.  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.

Other Property, Plant and Equipment.  Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, crude-by-rail assets, sand mine and sand processing assets, computer hardware and software, vehicles, and furniture and fixtures.  Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 40 years.

Capitalized Interest Costs.  Interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties.  The amount capitalized is an allocation of the interest cost incurred during the reporting period.  Capitalized interest is computed only during the exploration and development phases and ceases once production begins.  The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings.

Accounting for Risk Management Activities.  Derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  During the three-year period ended December 31, 2011, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges, and accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change.  The gains or losses are recorded as Gains on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income.  The related cash flow impact is reflected as cash flows from operating activities.  See Note 11.  EOG is party to a foreign currency swap transaction and an interest rate swap transaction (see Note 2).  EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement.

F-10

Income Taxes.  Income taxes are accounted for using the asset and liability approach.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis (see Note 5).

Foreign Currency Translation.  The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for certain of its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary, for which the functional currency is the British pound.  For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year.  Translation adjustments are included in Accumulated Other Comprehensive Income on the Consolidated Balance Sheets.  Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period.

Net Income Per Share.  Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods.  Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the periods plus the assumed issuance of common shares for all potentially dilutive securities (see Note 8).

Stock-Based Compensation.  EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (see Note 6).

Recently Issued Accounting Standards.  In May 2011, the FASB issued Accounting Standards Update (ASU) 2011-04, "Fair Value Measurement (Topic 820):  Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs".  ASU 2011-04 amends the Fair Value Measurements and Disclosures Topic of the ASC to clarify the FASB's intent about the application of existing fair value measurement requirements and change certain principles or requirements for measuring fair value or disclosing information about fair value measurements.  ASU 2011-04 is effective for interim and annual fiscal periods beginning after December 15, 2011.  EOG does not expect that the adoption of ASU 2011-04 will have a material impact on its financial statements, but it may result in additional disclosures regarding fair value measurements.

In June 2011, the FASB issued ASU 2011-05 "Comprehensive Income (Topic 220): Presentation of Comprehensive Income."  ASU 2011-05 is intended to increase the prominence of comprehensive income in the financial statements by requiring that an entity that reports items of comprehensive income do so in either one continuous or two consecutive financial statements.  ASU 2011-05 also requires separate presentation on the face of the financial statements for items reclassified from other comprehensive income into net income.  Subsequently, in December 2011, the FASB deferred the effective date of the provisions of ASU 2011-05 relating to the presentation of reclassification adjustments out of accumulated other comprehensive income. The provisions of ASU 2011-05 not deferred by the FASB are effective for interim and annual fiscal periods beginning after December 15, 2011.  Retroactive application is required.  EOG does not expect that the adoption of ASU 2011-05 will have a material impact on its financial statements, but it may result in additional disclosures regarding components of comprehensive income.

F-11

2.  Long-Term Debt

Long-Term Debt at December 31, 2011 and 2010 consisted of the following (in thousands):

		2011		2010
6.125% Senior Notes due 2013		$	400,000	$	400,000
Floating Rate Senior Notes due 2014			350,000		350,000
2.95% Senior Notes due 2015			500,000		500,000
2.500% Senior Notes due 2016			400,000		400,000
5.875% Senior Notes due 2017			600,000		600,000
6.875% Senior Notes due 2018			350,000		350,000
5.625% Senior Notes due 2019			900,000		900,000
4.40% Senior Notes due 2020			500,000		500,000
4.100% Senior Notes due 2021			750,000		750,000
6.65% Senior Notes due 2028			140,000		140,000
7.00% Subsidiary Debt due 2011			-		220,000
4.75% Subsidiary Debt due 2014			150,000		150,000
Total Long-Term Debt			5,040,000		5,260,000
Less:	Current Portion of Long-Term Debt		-		220,000
	Unamortized Debt Discount		30,834		36,659
Total Long-Term Debt, Net		$	5,009,166	$	5,003,341

At December 31, 2011, the aggregate annual maturities of long-term debt were zero in 2012, $400 million in 2013, $500 million in 2014, $500 million in 2015 and $400 million in 2016.  On December 1, 2011, a wholly-owned subsidiary of EOG repaid at maturity $220 million principal amount of 7% notes, plus accrued and unpaid interest.  All subsidiary debt is guaranteed by EOG.

During 2011 and 2010, EOG utilized commercial paper and short-term borrowings under uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes.  EOG had no outstanding borrowings from commercial paper or under uncommitted credit facilities at December 31, 2011.  The average borrowings outstanding under the commercial paper program and uncommitted credit facilities were $3 million and zero, respectively, during the year ended December 31, 2011.  The weighted average interest rates for commercial paper borrowings for 2011 was 0.34%.

On October 11, 2011, EOG entered into a $2.0 billion senior unsecured Revolving Credit Agreement (2011 Facility) among EOG, JPMorgan Chase Bank, N.A., as Administrative Agent, the financial institutions as bank parties thereto (Banks) and the other parties thereto.  The 2011 Facility replaces EOG's $1.0 billion senior unsecured Revolving Credit Agreement, dated as of June 28, 2005, which had a scheduled maturity date of June 28, 2012 (2005 Facility), and EOG's $1.0 billion senior unsecured Revolving Credit Agreement, dated as of September 10, 2010, which had a scheduled maturity date of September 10, 2013 (2010 Facility).  There were no borrowings outstanding under either the 2005 Facility or the 2010 Facility as of the closing of the 2011 Facility and the termination of the 2005 Facility and the 2010 Facility.  The 2011 Facility has a scheduled maturity date of October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the Banks holding greater than 50% of the commitments then outstanding under the 2011 Facility.  The 2011 Facility commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions.  Advances under the 2011 Facility will accrue interest based, at EOG's option, on either the London InterBank Offering Rate (LIBOR) plus an applicable margin (Eurodollar rate), or the base rate (as defined in the 2011 Facility) plus an applicable margin.  The applicable margin used in connection with interest rates and fees will be based on EOG's credit rating at the applicable time.  At December 31, 2011, there were no borrowings or letters of credit outstanding under the 2011 Facility.  The Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2011 Facility, would have been 1.17% and 3.25%, respectively.

F-12

The 2011 Facility contains representations, warranties, covenants and events of default that are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a total debt-to-total capitalization ratio of no greater than 65%.  At December 31, 2011 and during the year then ended, EOG believes that it was in compliance with this financial debt covenant.

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.  Interest on the Floating Rate Notes is payable quarterly and is based on 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% (see Note 11).

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.  Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes, including the repayment of outstanding commercial paper borrowings.

On May 12, 2010, EOG Resources Trinidad Limited, a wholly owned foreign subsidiary of EOG, repaid at maturity the remaining $37 million outstanding balance of its $75 million Revolving Credit Agreement, thereby canceling this agreement.  The weighted average interest rate for the amount outstanding during the year ended December 31, 2010 was 2.74%.

The 2.95% Senior Notes due 2015, the 2016 Notes, the 4.40% Senior Notes due 2020 and the 2021 Notes were issued through public offerings and have effective interest rates of 3.148%, 2.698%, 4.565%, and 4.276%, respectively.

EOG Resources Canada Inc., a wholly-owned subsidiary of EOG, has outstanding notes with an aggregate principal amount of $150 million, an interest rate of 4.75% and a maturity date of March 15, 2014.  In conjunction with the offering, EOG entered into a foreign currency swap transaction with multiple banks for the equivalent amount of the notes and related interest, which has in effect converted this indebtedness into $201.3 million Canadian dollars with a 5.275% interest rate.  EOG accounts for the foreign currency swap transaction using the hedge accounting method (see Note 11).

Fair Value of Debt.  At December 31, 2011 and 2010, EOG had outstanding $5,040 million and $5,260 million, respectively, aggregate principal amount of debt, which had estimated fair values of approximately $5,657 million and $5,602 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.

3.  Stockholders' Equity

Common Stock.  On March 7, 2011, EOG completed the public offering and sale of 13,570,000 shares of EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share.  Net proceeds from the sale of the Common Stock were approximately $1,388 million after deducting the underwriting discount and offering expenses.  Proceeds from the sale were used for general corporate purposes, including funding capital expenditures.

F-13

In September 2001, EOG's Board of Directors (Board) authorized the purchase of an aggregate maximum of 10 million shares of Common Stock that superseded all previous authorizations.  At December 31, 2011, 6,386,200 shares remained available for purchase under this authorization.  EOG last purchased shares of its Common Stock under this authorization in March 2003.  In addition, shares of Common Stock are from time to time withheld by, or returned to, EOG in satisfaction of tax withholding obligations arising upon the exercise of employee stock options or stock-settled stock appreciation rights, the vesting of restricted stock or restricted stock unit grants or in payment of the exercise price of employee stock options.  Such shares withheld or returned do not count against the Board authorization discussed above.  Shares purchased, withheld and returned are held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock plans and any other approved transactions or activities for which such shares of Common Stock shall be required.

The Board increased the quarterly cash dividend on the Common Stock to $0.155 per share on February 9, 2010, $0.16 per share on February 17, 2011 and to $0.17 per share on February 16, 2012.

The following summarizes Common Stock activity for each of the years ended December 31, 2009, 2010 and 2011 (in thousands):

		Common Shares
		Issued	Treasury	Outstanding
Balance at December 31, 2008		249,759	(127)	249,632
	Common Stock Issued Under Equity Compensation Plans	1,347	-	1,347
	Treasury Stock Purchased (1)	-	(168)	(168)
	Common Stock Issued Under Employee Stock Purchase Plan	71	-	71
	Treasury Stock Issued Under Other Equity Compensation Plans	-	177	177
	Common Stock Issued for Property Acquisition	1,450	-	1,450
Balance at December 31, 2009		252,627	(118)	252,509
	Common Stock Issued Under Equity Compensation Plans	1,482	-	1,482
	Treasury Stock Purchased (1)	-	(115)	(115)
	Common Stock Issued Under Employee Stock Purchase Plan	114	-	114
	Treasury Stock Issued Under Other Equity Compensation Plans	-	87	87
Balance at December 31, 2010		254,223	(146)	254,077
	Common Stock Issued Under Equity Compensation Plans	1,395	-	1,395
	Treasury Stock Purchased (1)	-	(267)	(267)
	Common Stock Issued Under Employee Stock Purchase Plan	135	-	135
	Treasury Stock Issued Under Other Equity Compensation Plans	-	109	109
	Common Stock Sold	13,570	-	13,570
Balance at December 31, 2011		269,323	(304)	269,019

(1) Represents shares that were withheld by, or returned to, EOG in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights, the vesting of restricted stock or restricted stock unit grants or in payment of the exercise price of employee stock options.

Preferred Stock.  EOG currently has one authorized series of preferred stock.  In February 2000, EOG's Board, in connection with a rights agreement, authorized 1,500,000 shares of the Series E Junior Participating Preferred Stock (Series E).  In February 2005, EOG's Board increased the authorized shares of the Series E to 3,000,000 in connection with the two-for-one stock split of the Common Stock effected in March 2005.  As of December 31, 2011, there were no shares of the Series E outstanding.  The rights agreement and the related preferred share purchase rights expired on February 24, 2010.

F-14

4.  Other Income, Net

Other income, net for 2011 included equity income from investments in ammonia plants in Trinidad ($17 million), operating losses on EOG's investment in Pacific Trail Pipelines (PTP) in Canada ($5 million) and losses on sales of warehouse stock ($5 million).  Other income, net for 2010 included equity income from investments in ammonia plants in Trinidad ($13 million), net foreign currency transaction gains ($4 million) and losses on sales of warehouse stock ($4 million).

5.  Income Taxes

The principal components of EOG's net deferred income tax liabilities at December 31, 2011 and 2010 were as follows (in thousands):

	2011			2010
Current Deferred Income Tax Assets (Liabilities)
Commodity Hedging Contracts	$	-		$	(7,141	)
Deferred Compensation Plans		-			13,216
Other		-			3,185
Total Net Current Deferred Income Tax Assets	$	-		$	9,260
Noncurrent Deferred Income Tax Assets (Liabilities)
United Kingdom Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	(57,850	)	$	(16,611	)
United Kingdom Net Operating Loss		62,477			17,329
United Kingdom Other		314			226
Total Net Noncurrent Deferred Income Tax Assets	$	4,941		$	944
Current Deferred Income Tax (Assets) Liabilities
Commodity Hedging Contracts	$	158,302		$	-
Deferred Compensation Plans		(28,346	)		-
Timing Differences Associated with Different Year-ends in Foreign Jurisdictions		6,251			41,027
Other		(218	)		676
Total Net Current Deferred Income Tax Liabilities	$	135,989		$	41,703
Noncurrent Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,485,436		$	4,373,110
Non-Producing Leasehold Costs		(66,926	)		(78,846	)
Seismic Costs Capitalized for Tax		(111,862	)		(92,901	)
Equity Awards		(120,852	)		(99,447	)
Capitalized Interest		106,265			94,957
Net Operating Loss		(1,152,386	)		(498,893	)
Alternative Minimum Tax Credit Carryforward		(298,350	)		(214,873	)
Other		25,894			18,599
Total Net Noncurrent Deferred Income Tax Liabilities	$	3,867,219		$	3,501,706
Total Net Deferred Income Tax Liabilities	$	3,998,267		$	3,533,205

F-15

The components of Income Before Income Taxes for the years indicated below were as follows (in thousands):

	2011			2010			2009
United States	$	2,156,147		$	646,495		$	784,248
Foreign		(246,348	)		(238,519	)		87,763
Total	$	1,909,799		$	407,976		$	872,011

The principal components of EOG's Income Tax Provision for the years indicated below were as follows (in thousands):

	2011			2010			2009
Current:
Federal	$	94,244		$	17,154		$	95,194
State		1,083			(1,642	)		8,783
Foreign		224,049			155,565			47,015
Total		319,376			171,077			150,992
Deferred:
Federal		608,181			190,602			166,045
State		40,321			60,619			31,580
Foreign		(149,202	)		(174,976	)		(23,233	)
Total		499,300			76,245			174,392
Income Tax Provision	$	818,676		$	247,322		$	325,384

The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows:

		2011	2010	2009
Statutory Federal Income Tax Rate		35.00%	35.00%	35.00%
State Income Tax, Net of Federal Benefit		1.41	9.39	3.00
Income Tax Provision Related to Foreign Operations		0.88	(0.03)	(1.40)
Income Tax Provision Related to Trinidad Operations		3.37	6.26	0.60
Canadian Shallow Natural Gas Impairments		1.85	9.49	-
Other		0.36	0.51	0.11
	Effective Income Tax Rate	42.87%	60.62%	37.31%

The difference in the effective tax rate and the United States federal statutory rate of 35% is attributed principally to state and foreign income taxes.  The decrease in the state tax expense is attributable largely to the redetermination of the deferred state tax liability, which was reduced to reflect lower statutory state tax rates in North Dakota.  Foreign taxes had a smaller effect on EOG's worldwide tax rate due to smaller Canadian impairments, which are tax-effected at a statutory rate of 27%, and to higher domestic earnings.

The balance of unrecognized tax benefits at December 31, 2011 was $33 million, all of which, if recognized, would affect the effective tax rate.  EOG records interest and penalties related to unrecognized tax benefits to its income tax provision.  Currently, there are no amounts of interest or penalties recognized in the Consolidated Statements of Income and Comprehensive Income or in the Consolidated Balance Sheets.  EOG does not anticipate that the amount of the unrecognized tax benefits will significantly change during the next twelve months.  EOG and its subsidiaries file income tax returns in the United States and various state, local and foreign jurisdictions.  EOG is generally no longer subject to income tax examinations by tax authorities in the United States (federal), Canada, the United Kingdom, Trinidad and China for taxable years before 2005, 2007, 2010, 2004 and 2008, respectively.

F-16

EOG's foreign subsidiaries' undistributed earnings of approximately $2.3 billion at December 31, 2011 are considered to be indefinitely invested outside the United States and, accordingly, no United States federal or state income taxes have been provided thereon.  Upon distribution of those earnings, EOG may be subject to both foreign withholding taxes and United States income taxes, net of allowable foreign tax credits.  The amount of such additional taxes would be dependent on several factors, including the size and timing of the distribution, the particular foreign jurisdiction from which the distribution is made, and the availability of foreign tax credits.  As a result, the determination of the potential amount of unrecognized withholding and deferred income taxes is not practicable, though additional taxes resulting from a repatriation of foreign earnings could be significant.

In 2011, EOG generated a regular tax net operating loss (NOL) of $1.8 billion.  This NOL, along with the 2010 NOL of $1.4 billion, is expected to be carried forward and applied against regular taxable income in future periods.  To the extent not utilized, these NOL carryforwards will expire in 2030 and 2031, respectively.  Additionally, as of December 31, 2011, EOG had state income tax NOLs of approximately $700 million, which, if unused, expire between 2015 and 2031.  The Stock Compensation Topic of the ASC provides that when settlement of a stock award contributes to a NOL carryforward, neither the associated excess tax benefit nor the credit to additional paid in capital (APIC) should be recorded until the stock award deduction reduces income taxes payable.  Upon utilization of the NOLs in future periods, a benefit of $40 million will be reflected in APIC (including $23 million and $17 million related to 2011 and 2010, respectively).  In 2011, EOG paid alternative minimum tax (AMT) of $104 million.  The AMT paid in 2011, along with AMT of $194 million paid in prior years, will be carried forward indefinitely as a credit available to offset regular income taxes in future periods.

The ability of EOG to utilize both the regular tax NOL carryfowards and the AMT credit carryforwards to reduce regular federal taxable income and federal income taxes, respectively, may become subject to various limitations under the Internal Revenue Code.  Such limitations may arise if certain ownership changes (as defined for income tax purposes) were to occur.  As of December 31, 2011, we do not believe that an ownership change has occurred which would limit either carryforward.

During 2011, EOG's United Kingdom subsidiary incurred a tax NOL of approximately $71 million which, along with the 2010 NOL of $30 million, will be carried forward indefinitely.  In July 2011, the United Kingdom increased the statutory income tax rate applying to oil and gas activities from 50% to 62%, effective March 2011.  In December 2011, the United Kingdom increased from 6% to 10% a statutory deduction referred to as "Uplift," which is an upward adjustment to certain unused NOLs.  The increase in the Uplift percentage is effective January 1, 2012. These two changes did not have a material impact on EOG's 2011 earnings or cash flow.

6.  Employee Benefit Plans

Stock-Based Compensation

During 2011, EOG maintained various stock-based compensation plans as discussed below.  EOG recognizes compensation expense on grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock and restricted stock units and grants made under its Employee Stock Purchase Plan (ESPP).  Stock-based compensation expense is calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate.  Compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval.

Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon job functions of the employees receiving the grants.  Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2011, 2010 and 2009 was as follows (in millions):

	2011		2010		2009
Lease and Well	$	33	$	27	$	23
Gathering and Processing Costs		1		1		-
Exploration Costs		26		24		21
General and Administrative		68		55		51
Total	$	128	$	107	$	95

F-17

The EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, SARs, restricted stock, restricted stock units and other stock-based awards up to an aggregate maximum of 12.9 million shares plus shares underlying forfeited or cancelled grants under prior stock plans.  At December 31, 2011, approximately 5.4 million shares of Common Stock remained available for grant under the 2008 Plan.  Effective with the adoption of the 2008 Plan, EOG's policy is to issue shares related to the 2008 Plan from either previously authorized unissued shares or treasury shares, to the extent treasury shares are available.

During 2011, 2010 and 2009, EOG issued shares in connection with stock option/SAR exercises, restricted stock grants, restricted stock unit releases and ESPP purchases.  EOG recognized, as an adjustment to APIC, federal income tax (expense)/benefits of $25,000, $(1) million and $76 million for 2011, 2010 and 2009, respectively, related to the exercise of stock options/SARs and the release of restricted stock and restricted stock units.

Stock Options and Stock Appreciation Rights and Employee Stock Purchase Plan.  Participants in EOG's stock plans (including the 2008 Plan) have been or may be granted options to purchase shares of Common Stock.  In addition, participants in EOG's stock plans (including the 2008 Plan) have been or may be granted SARs, representing the right to receive shares of Common Stock based on the appreciation in the stock price from the date of grant on the number of SARs granted.  Stock options and SARs are granted at a price not less than the market price of the Common Stock on the date of grant.  Stock options and SARs granted vest on a graded vesting schedule up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements.  Terms for stock options and SARs granted have not exceeded a maximum term of 10 years.  EOG's ESPP allows eligible employees to semi-annually purchase, through payroll deductions, shares of Common Stock at 85 percent of the fair market value at specified dates.  Contributions to the ESPP are limited to 10 percent of the employee's pay (subject to certain ESPP limits) during each of the two six-month offering periods each year.

The fair value of all ESPP grants is estimated using the Black-Scholes-Merton model.  The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option pricing model.  Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $48 million, $41 million and $38 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2011, 2010 and 2009 were as follows:

	Stock Options/SARs									ESPP
	2011			2010			2009			2011			2010			2009
Weighted Average Fair Value of Grants	$	29.92		$	32.12		$	30.13		$	22.75		$	25.45		$	25.78
Expected Volatility		40.96	%		39.70	%		41.90	%		29.82	%		38.30	%		78.89	%
Risk-Free Interest Rate		0.58	%		0.87	%		1.42	%		0.14	%		0.18	%		0.25	%
Dividend Yield		0.70	%		0.70	%		0.70	%		0.70	%		0.70	%		1.00	%
Expected Life	5.6 yrs			5.5 yrs			5.5 yrs			0.5 yrs			0.5 yrs			0.5 yrs

Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's Common Stock.  The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant.  The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants.

F-18

The following table sets forth the stock option and SAR transactions for the years ended December 31, 2011, 2010 and 2009 (stock options and SARs in thousands):

	2011					2010					2009
	Number			Weighted		Number			Weighted		Number			Weighted
	of Stock			Average		of Stock			Average		Of Stock			Average
	Options/			Grant		Options/			Grant		Options/			Grant
	SARs			Price		SARs			Price		SARs			Price
Outstanding at January 1		8,445		$	64.49		8,335		$	57.08		7,802		$	52.56
Granted		1,509			85.29		1,450			93.07		1,270			80.95
Exercised (1)		(1,399	)		50.86		(1,144	)		43.38		(636	)		46.56
Forfeited		(181	)		87.74		(196	)		84.22		(101	)		74.07
Outstanding at December 31		8,374			70.01		8,445			64.49		8,335			57.08
Stock Options/SARs Exercisable at December 31		5,148			59.19		5,439			51.71		5,394			44.45

(1) The total intrinsic value of stock options/SARs exercised during the years 2011, 2010 and 2009 was $78.4 million, $66.0 million and $21.4 million, respectively.  The intrinsic value is based upon the difference between the market price of Common Stock on the date of exercise and the grant price of the stock options/SARs.

At December 31, 2011, there were 8,123,226 stock options/SARs vested or expected to vest with a weighted average grant price of $69.48 per share, an intrinsic value of $238.5 million and a weighted average remaining contractual life of 3.6 years.

The following table summarizes certain information for the stock options and SARs outstanding at December 31, 2011 (stock options and SARs in thousands):

Stock Options/SARs Outstanding									Stock Options/SARs Exercisable
				Weighted							Weighted
				Average		Weighted					Average		Weighted
Range of		Stock		Remaining		Average		Aggregate	Stock		Remaining		Average		Aggregate
Grant		Options/		Life		Grant		Intrinsic	Options/		Life		Grant		Intrinsic
Prices		SARs		(Years)		Price		Value(1)	SARs		(Years)		Price		Value(1)
$	16.00 to $ 48.99		1,431		1	$	20.30			1,431		1	$	20.30
49.00 to  69.99			1,623		1		61.99			1,609		1		61.94
70.00 to  81.99			1,674		4		78.17			1,159		4		76.66
82.00 to  88.99			2,174		6		85.44			576		4		88.73
89.00 to 136.99			1,472		5		95.09			373		5		96.56
			8,374		4		70.01	$241,474		5,148		2		59.19	$203,646

(1) Based upon the difference between the closing market price of Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs.

At December 31, 2011, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $87.9 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.8 years.

At December 31, 2011, approximately 790,000 shares of Common Stock remained available for issuance under the ESPP.  The following table summarizes ESPP activities for the years ended December 31, 2011, 2010 and 2009 (in thousands, except number of participants):

	2011		2010		2009
Approximate Number of Participants		1,525		1,236		1,128
Shares Purchased		135		114		72
Aggregate Purchase Price	$	10,947	$	9,172	$	4,150

F-19

Restricted Stock and Restricted Stock Units.  Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them.  The restricted stock and restricted stock units generally vest five years after the date of grant, except for certain bonus grants, and as defined in individual grant agreements.  Upon vesting of restricted stock, shares of Common Stock are released to the employee.  Upon vesting, restricted stock units are converted into shares of Common Stock and released to the employee.  Stock-based compensation expense related to restricted stock and restricted stock units totaled $80 million, $66 million and $57 million for the years ended December 31, 2011, 2010 and 2009, respectively.

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2011, 2010 and 2009 (shares and units in thousands):

	2011					2010					2009
				Weighted					Weighted					Weighted
	Number of			Average		Number of			Average		Number of			Average
	Shares and			Grant Date		Shares and			Grant Date		Shares and			Grant Date
	Units			Fair Value		Units			Fair Value		Units			Fair Value
Outstanding at January 1		4,009		$	79.13		3,636		$	73.69		3,048		$	70.24
Granted		932			90.87		850			93.39		1,197			63.13
Released (1)		(457	)		66.10		(364	)		58.00		(553	)		31.35
Forfeited		(244	)		82.45		(113	)		79.37		(56	)		78.18
Outstanding at December 31 (2)		4,240			82.93		4,009			79.13		3,636			73.69

(1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2011, 2010 and 2009 was $44.4 million, $35.2 million and $36.9 million, respectively.  The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.

(2) The aggregate intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2011 and 2010 was approximately $417.7 million and $366.4 million, respectively.

At December 31, 2011, unrecognized compensation expense related to restricted stock and restricted stock units totaled $132.6 million.  Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.4 years.

Pension Plans.  EOG has a non-contributory defined contribution pension plan and a matched defined contribution savings plan in place for most of its employees in the United States (such plans were merged into a single plan, effective as of January 1, 2012).  EOG's contributions to these pension plans are based on various percentages of compensation and, in some instances, are based upon the amount of the employees' contributions.  EOG's total costs recognized for these plans were $27.1 million, $23.4 million and $21.8 million for 2011, 2010 and 2009, respectively.

In addition, EOG's Canadian subsidiary maintains both a non-contributory defined benefit pension plan and a non-contributory defined contribution pension plan, as well as a matched defined contribution savings plan.  EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan.  EOG's United Kingdom subsidiary maintains a pension plan which includes a non-contributory defined contribution pension plan and a matched defined contribution savings plan.  With the exception of Canada's non-contributory defined benefit pension plan, which is closed to new employees, these pension plans are available to most employees of the Canadian, Trinidadian and United Kingdom subsidiaries.  EOG's combined contributions to these plans were $2.5 million, $2.8 million and $2.6 million for 2011, 2010 and 2009, respectively.

For the Canadian and Trinidadian defined benefit pension plans, the benefit obligation, fair value of plan assets and prepaid/(accrued) benefit cost totaled $11.3 million, $8.2 million and $(1.6) million, respectively, at December 31, 2011 and $10.3 million, $8.7 million and $(0.8) million, respectively, at December 31, 2010.

Postretirement Health Care.  EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents, the costs of which are not material.

F-20

7.  Commitments and Contingencies

Letters of Credit.  At December 31, 2011, EOG had standby letters of credit and guarantees outstanding totaling approximately $585 million, of which $150 million represents guarantees of subsidiary indebtedness (see Note 2) and $435 million primarily represents guarantees of payment obligations on behalf of subsidiaries.  At December 31, 2010, EOG had standby letters of credit and guarantees outstanding totaling approximately $657 million, of which $370 million represents guarantees of subsidiary indebtedness (see Note 2) and $287 million primarily represents guarantees of payment obligations on behalf of subsidiaries.  As of February 24, 2012, there were no demands for payment under these guarantees.

Minimum Commitments.  At December 31, 2011, total minimum commitments from long-term non-cancelable operating leases, drilling rig commitments, seismic purchase obligations, fracturing services obligations, other purchase obligations and transportation and storage service commitments, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars and British pounds into United States dollars at December 31, 2011, are as follows (in thousands):

	Total Minimum
	Commitments
2012	$	1,185,759
2013 - 2014		1,013,735
2015 - 2016		925,514
2017 and beyond		1,435,506
	$	4,560,514

Included in the table above are leases for buildings, facilities and equipment with varying expiration dates through 2026.  Rental expenses associated with existing leases amounted to $149 million, $95 million and $77 million for 2011, 2010 and 2009, respectively.

Contingencies.  There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes.  While the ultimate outcome and impact on EOG cannot be predicted, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow.  EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

8.  Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2011, 2010 and 2009 (in thousands, except per share data):

	2011		2010		2009
Numerator for Basic and Diluted Earnings per Share -
Net Income	$	1,091,123	$	160,654	$	546,627
Denominator for Basic Earnings per Share -
Weighted Average Shares		262,735		250,876		248,996
Potential Dilutive Common Shares -
Stock Options/SARs		1,707		1,991		1,691
Restricted Stock and Restricted Stock Units		1,826		1,633		1,197
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares		266,268		254,500		251,884
Net Income Per Share
Basic	$	4.15	$	0.64	$	2.20
Diluted	$	4.10	$	0.63	$	2.17

F-21

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive.  The excluded stock options and SARs totaled 0.4 million, 0.3 million and 2.5 million for the years ended December 31, 2011, 2010 and 2009, respectively.

9.  Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	2011		2010		2009
Interest, Net of Capitalized Interest	$	186,718	$	146,731	$	100,939
Income Taxes, Net of Refunds Received	$	260,224	$	233,462	$	51,684

EOG's accrued capital expenditures at December 31, 2011, 2010 and 2009 were $663 million, $709 million and $334 million, respectively.

Non-cash investing and financing activities for the year ended December 31, 2009 included the following (see Note 16):

·   the issuance of 1,450,000 shares of Common Stock valued at $90 million at the transaction closing date in connection with EOG's purchase of certain proved developed and undeveloped reserves and unproved acreage; and

·   non-cash additions to EOG's oil and gas properties in the amount of $353 million in connection with EOG's asset exchange agreement in respect of certain natural gas-related properties.

F-22

10.  Business Segment Information

EOG's operations are all crude oil and natural gas exploration and production related. The Segment Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual financial statements.  Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance.  EOG's chief operating decision making process is informal and involves the Chairman of the Board and Chief Executive Officer and other key officers.  This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States, Canada, Trinidad, the United Kingdom and China.  For segment reporting purposes, the chief operating decision maker considers the major United States producing areas to be one operating segment.

Financial information by reportable segment is presented below as of and for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	United									Other
	States			Canada			Trinidad			International (1)			Total
2011
Crude Oil and Condensate	$	3,458,248		$	264,895		$	112,554		$	2,587		$	3,838,284
Natural Gas Liquids		762,730			16,634			-			-			779,364
Natural Gas		1,593,964			178,324			442,589			25,663			2,240,540
Gains on Mark-to-Market Commodity Derivative Contracts		626,053			-			-			-			626,053
Gathering, Processing and Marketing		2,115,768			-			24			-			2,115,792
Gains on Asset Dispositions, Net		475,878			17,033			(2	)		-			492,909
Other, Net		32,329			258			586			-			33,173
Net Operating Revenues (2)		9,064,970			477,144			555,751			28,250			10,126,115
Depreciation, Depletion and Amortization		2,131,706			260,084			107,141			17,450			2,516,381
Operating Income (Loss)		2,252,508			(459,520	)		383,992			(63,671	)		2,113,309
Interest Income		436			342			101			140			1,019
Other Income (Expense)		(6,480	)		(2,375	)		18,755			(4,066	)		5,834
Net Interest Expense		214,360			23,085			-			(27,082	)		210,363
Income (Loss) Before Income Taxes		2,032,104			(484,638	)		402,848			(40,515	)		1,909,799
Income Tax Provision (Benefit)		732,362			(125,474	)		204,698			7,090			818,676
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		5,790,590			259,634			132,159			58,784			6,241,167
Total Property, Plant and Equipment, Net		18,711,774			1,760,066			627,794			189,190			21,288,824
Total Assets		21,313,158			2,131,949			1,085,664			308,026			24,838,797

F-23

	United								Other
	States			Canada			Trinidad		International (1)			Total
2010
Crude Oil and Condensate	$	1,700,770		$	178,349		$	117,605	$	2,047		$	1,998,771
Natural Gas Liquids		448,647			13,698			-		-			462,345
Natural Gas		1,778,823			285,369			330,247		25,660			2,420,099
Gains on Mark-to-Market Commodity Derivative Contracts		61,912			-			-		-			61,912
Gathering, Processing and Marketing		909,660			-			20		-			909,680
Gains on Asset Dispositions, Net		196,774			23,112			3,652		-			223,538
Other, Net		19,886			(31	)		3,696		-			23,551
Net Operating Revenues (2)		5,116,472			500,497			455,220		27,707			6,099,896
Depreciation, Depletion and Amortization		1,539,240			315,849			71,085		15,752			1,941,926
Operating Income (Loss)		787,422			(516,874	)		312,128		(59,357	)		523,319
Interest Income		152			387			120		164			823
Other Income (Expense)		(3,905	)		2,067			14,022		1,236			13,420
Net Interest Expense		112,226			34,350			448		(17,438	)		129,586
Income (Loss) Before Income Taxes		671,443			(548,770	)		325,822		(40,519	)		407,976
Income Tax Provision (Benefit)		255,945			(146,495	)		140,934		(3,062	)		247,322
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		4,491,897			446,626			134,198		65,405			5,138,126
Total Property, Plant and Equipment, Net		15,747,808			2,189,961			595,970		147,161			18,680,900
Total Assets		17,762,533			2,598,412			954,391		308,897			21,624,233
2009
Crude Oil and Condensate	$	945,224		$	86,140		$	57,089	$	1,258		$	1,089,711
Natural Gas Liquids		246,821			11,978			-		-			258,799
Natural Gas		1,540,042			315,792			172,560		22,569			2,050,963
Gains on Mark-to-Market Commodity Derivative Contracts		431,757			-			-		-			431,757
Gathering, Processing and Marketing		407,097			-			19		-			407,116
Gains on Asset Dispositions, Net		535,295			141			-		-			535,436
Other, Net		9,693			(16	)		3,500		-			13,177
Net Operating Revenues (2)		4,115,929			414,035			233,168		23,827			4,786,959
Depreciation, Depletion and Amortization		1,282,180			211,514			47,119		8,375			1,549,188
Operating Income (Loss)		896,937			(31,767	)		143,993		(38,322	)		970,841
Interest Income		137			612			146		205			1,100
Other Income (Expense)		(7,396	)		5,212			4,387		(1,232	)		971
Net Interest Expense		84,411			28,934			1,332		(13,776	)		100,901
Income (Loss) Before Income Taxes		805,267			(54,877	)		147,194		(25,573	)		872,011
Income Tax Provision (Benefit)		290,473			(27,073	)		57,363		4,621			325,384
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		2,770,482			268,604			31,219		55,235			3,125,540
Total Property, Plant and Equipment, Net		12,769,240			2,740,473			532,989		96,523			16,139,225
Total Assets		14,108,129			2,888,949			813,901		307,688			18,118,667

(1) Other International primarily includes EOG's United Kingdom and China operations.

(2) EOG had no purchasers in 2011, 2010 or 2009 whose sales totaled 10 percent or more of consolidated Net Operating Revenues.

F-24

11.  Risk Management Activities

Commodity Price Risks.  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 price swap, collar, option and basis swap contracts, as a means to manage this price risk.  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.  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.

During 2011, 2010 and 2009, EOG elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounted for these financial commodity derivative contracts using the mark-to-market accounting method.  During 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $626 million, which included net realized gains of $181 million.  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 losses of $1,278 million.

At December 31, 2011, the fair value of EOG's financial commodity derivative contracts was reflected on the Consolidated Balance Sheets as Current Assets - Assets from Price Risk Management Activities ($451 million) and Other Assets ($35 million).  At December 31, 2010, the fair value of EOG's financial commodity derivative contracts was reflected on the Consolidated Balance Sheets as Current Assets - Assets From Price Risk Management Activities ($48 million), Other Assets ($20 million), Current Liabilities - Liabilities from Price Risk Management Activities ($28 million) and Other Liabilities ($1 million).

Commodity Derivative Contracts.  Presented below is a comprehensive summary of EOG's crude oil derivative contracts at December 31, 2011, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl)

Crude Oil Derivative Contracts
			Weighted
	Volume		Average Price
	(Bbld)		($/Bbl)
2012 (1)
January 1, 2012 through June 30, 2012		34,000	$	104.95
July 1, 2012 through December 31, 2012		17,000		103.59

(1)   EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Such options are exercisable on June 29, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 17,000 Bbld at an average price of $106.31 per barrel for the period July 1, 2012 through December 31, 2012.

F-25

Presented below is a comprehensive summary of EOG's natural gas derivative contracts as of December 31, 2011, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Derivative Contracts
	Volume (MMBtud)		Weighted Average Price ($/MMBtu)
2012 (1)
January 2012 (closed)		525,000	$	5.44
February 1, 2012 through December 31, 2012		525,000		5.44
2013 (2)
January 1, 2013 through December 31, 2013		150,000	$	4.79
2014 (2)
January 1, 2014 through December 31, 2014		150,000	$	4.79

(1) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from February 1, 2012 through December 31, 2012.

(2) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2013 and 2014.

Foreign Currency Exchange Rate Derivative.EOG is party to a foreign currency aggregate swap transaction with multiple banks to eliminate any exchange rate impacts that may result from the $150 million principal amount of notes issued by one of EOG's Canadian subsidiaries.  EOG accounts for the foreign currency swap transaction using the hedge accounting method.  The fair value of the foreign currency swap was $(52) million at December 31, 2011 and $(55) million at December 31, 2010.  The after-tax net impact from the foreign currency swap resulted in a decrease in Other Comprehensive Income (OCI) of $1 million for the year ended December 31, 2011 and an increase in OCI of $3 million and $5 million for the years ended December 31, 2010 and 2009, respectively.

Interest Rate Derivative.  EOG is a party to an interest rate swap transaction with a counterparty bank.  The interest rate swap transaction was entered into in order to mitigate EOG's exposure to volatility in interest rates related to EOG's Floating Rate Notes issued on November 23, 2010.  The interest rate swap has a notional amount of $350 million and a fair value of $(3) million and $2 million at December 31, 2011 and 2010, respectively.  EOG accounts for the interest rate swap transaction using the hedge accounting method.  The after-tax impact from the interest rate swap resulted in a decrease in OCI of $3 million for the year ended December 31, 2011 and an increase in OCI of $1 million for the year ended December 31, 2010.

F-26

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding derivative financial instruments at December 31, 2011 and 2010, respectively.  Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

		Fair Value at December 31,
Description	Location on Balance Sheet	2011		2010
Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities	$	451	$	51
Noncurrent portion	Other Assets	$	35	$	18
Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities	$	-	$	30
Foreign currency swap -
Noncurrent portion	Other Liabilities	$	52	$	55
Interest rate swap -
Noncurrent portion	Other Assets	$	-	$	2
Other Liabilities		$	3	$	-

Credit Risk.  Notional contract amounts are used to express the magnitude of commodity price, foreign currency and interest rate swap agreements.  The amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 12).  EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions.  In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk.  At December 31, 2011, no individual purchaser's net accounts receivable balance related to United States, Canada and United Kingdom hydrocarbon sales accounted for 10% or more of the total balance.  At December 31, 2010, a crude oil marketing company's net accounts receivable balance related to United States, Canada and United Kingdom hydrocarbon sales accounted for 13% of the total balance.  The related amounts were collected during early 2011.  In 2011 and 2010, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago and all natural gas from EOG's China operations was sold to Petrochina Company Limited.

All of EOG's outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties.  The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings.  In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDA to be settled immediately.  See Note 12 for the aggregate fair value of all derivative instruments with credit-risk related contingent features that are in a net liability position at December 31, 2011 and 2010.  EOG had no collateral posted at both December 31, 2011 and 2010.

At December 31, 2011 and 2010, EOG had an allowance for doubtful accounts of $3 million and $14 million, respectively.

F-27

Substantially all of EOG's accounts receivable at December 31, 2011 and 2010 resulted from hydrocarbon sales and/or joint interest billings to third-party companies, including foreign state-owned entities in the oil and gas industry.  This concentration of customers and joint interest owners may impact EOG's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.  In determining whether or not to require collateral or other credit enhancements from a customer or joint interest owner, EOG typically analyzes the entity's net worth, cash flows, earnings and credit ratings.  Receivables are generally not collateralized.  During the three-year period ended December 31, 2011, credit losses incurred on receivables by EOG have been immaterial.

12.  Fair Value Measurements

Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets.  An established fair value hierarchy prioritizes the relative reliability of inputs used in fair value measurements.  The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date.  Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy.  EOG gives consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value.

The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2011 and 2010 (in millions):

	Fair Value Measurements Using:
	Quoted		Significant
	Prices in		Other		Significant
	Active		Observable		Unobservable
	Markets		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
At December 31, 2011
Financial Assets:
Crude Oil and Natural Gas Derivative Contracts	$	-	$	110	$	-	$	110
Crude Oil and Natural Gas Options/Swaptions		-		376		-		376
Financial Liabilities:
Foreign Currency Rate Swap	$	-	$	52	$	-	$	52
Interest Rate Swap		-		3		-		3
At December 31, 2010
Financial Assets:
Natural Gas Derivative Contracts	$	-	$	62	$	-	$	62
Natural Gas Options/Swaptions		-		6		-		6
Interest Rate Swap		-		2		-		2
Financial Liabilities:
Crude Oil and Natural Gas Derivative Contracts	$	-	$	29	$	-	$	29
Foreign Currency Rate Swap		-		55		-		55
Contingent Consideration		-		-		14		14

The estimated fair value of crude oil and natural gas derivative contracts and interest rate swap contracts (see Note 11) was based upon forward commodity price and interest rate curves based on quoted market prices.  The estimated fair value of the foreign currency rate swap was based upon forward currency rates.

F-28

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment.  Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives.  A reconciliation of EOG's asset retirement obligations is presented in Note 14.

During 2011, proved oil and gas properties with a carrying amount of $1,450 million were written down to their fair value of $616 million, resulting in pretax impairment charges of $834 million.  In connection with a $278 million impairment of certain natural gas assets in the U.S. during 2011, EOG utilized accepted bids as the basis for determining fair value.  During 2010, proved oil and gas properties and other property, plant and equipment with a carrying amount of $1,013 million were written down to their fair value of $487 million, resulting in pretax impairment charges of $418 million in Canada, $107 million in the United States and $1 million in Trinidad.  In connection with the $280 million impairment of shallow natural gas assets sold in Canada during the fourth quarter of 2010, EOG utilized accepted bids adjusted for estimates of customary closing adjustments less selling costs as the basis for determining fair value.  Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.  In connection with certain impairments of proved oil and gas properties and other property, plant and equipment, EOG utilized an accepted offer from a third-party buyer.

13.  Accounting for Certain Long-Lived Assets

EOG reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset.  During 2011, 2010 and 2009, such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to lower commodity prices, downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields.  Several impairments over this period were recognized in connection with the signing of purchase and sale agreements.  As a result, EOG recorded pretax charges of $403 million, $107 million and $90 million in the United States during 2011, 2010 and 2009, respectively, and $428 million, $418 million and $4 million in Canada during 2011, 2010 and 2009, respectively.  Additionally, EOG recorded pretax charges of $3 million in Other International during 2011 and $1 million in Trinidad during 2010.  The pretax charges are included in Impairments on the Consolidated Statements of Income and Comprehensive Income.  The carrying values for assets determined to be impaired were adjusted to estimated fair value using the income approach.  If applicable, EOG utilizes accepted bids as the basis for determining fair value.  Amortization of unproved oil and gas property costs, including amortization of capitalized interest, was $197 million, $217 million and $212 million for 2011, 2010 and 2009, respectively.

F-29

14.  Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2011 and 2010 (in thousands):

	2011			2010
Carrying Amount at Beginning of Period	$	498,288		$	456,484
Liabilities Incurred		68,703			39,480
Liabilities Settled (1)		(66,129	)		(30,763	)
Accretion		27,907			25,456
Revisions		58,786			1,640
Foreign Currency Translations		(471	)		5,991
Carrying Amount at End of Period	$	587,084		$	498,288
Current Portion	$	29,527		$	32,005
Noncurrent Portion	$	557,557		$	466,283

(1)      Includes settlements related to asset sales.

The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

15.  Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2011, 2010 and 2009 are presented below (in thousands):

	2011			2010			2009
Balance at January 1	$	99,801		$	118,459		$	85,255
Additions Pending the Determination of Proved Reserves		31,271			94,090			75,362
Reclassifications to Proved Properties		(29,227	)		(93,333	)		(40,614	)
Charged to Dry Hole Costs		(42,178	)		(20,267	)		(11,223	)
Foreign Currency Translations		1,444			852			9,679
Balance at December 31	$	61,111		$	99,801		$	118,459

F-30

The following table provides an aging of capitalized exploratory well costs at December 31, 2011, 2010 and 2009 (in thousands, except well count):

	2011			2010			2009
Capitalized exploratory well costs that have been capitalized for a period less than one year	$	17,009		$	43,408		$	51,141
Capitalized exploratory well costs that have been capitalized for a period greater than one year		44,102	(1)		56,393	(2)		67,318	(3)
Total	$	61,111		$	99,801		$	118,459
Number of exploratory wells that have been capitalized for a period greater than one year		4			4			4

(1) Consists of costs related to an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($20 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($9 million), and a shale project in British Columbia, Canada (B.C.) ($6 million).  In the Central North Sea project, the operator and partners are currently negotiating processing and transportation terms with export infrastructure owners.  The operator submitted 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 during the first half of 2012.  In the East Irish Sea project, EOG submitted field development plans to the DECC during the first quarter of 2011 and expects regulatory approval during the first quarter of 2012. Installation of facilities, pipelines and drilling of development wells are planned for 2012 with initial production expected during the first quarter of 2013.  The evaluation of the Sichuan Basin project is expected to be completed by mid-2012.  In the B.C. shale project, EOG drilled four additional wells during the first half of 2011 and plans to drill seven wells in the first half of 2012 to retain land and further evaluate the project.  The related well completion activities are not expected to commence until 2013 or later.

(2) Consists of costs related to an outside operated, offshore Central North Sea project in the U.K. ($21 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($20 million), and a shale project in B.C. ($6 million).

(3) Consists of costs related to three shale projects in B.C. ($45 million) and an outside operated, offshore Central North Sea project in the U.K. ($22 million).

16.  Acquisitions and Divestitures

During 2011, EOG received proceeds of approximately $1.4 billion from sales of producing properties and acreage and certain midstream assets, primarily in the Rocky Mountain area and Texas, and the sale of a portion of EOG's interest in the planned Kitimat liquefied natural gas (LNG) Terminal and the proposed Pacific Trail Pipelines (PTP).  During 2010, EOG received proceeds of approximately $673 million from the sale of producing properties and acreage, primarily Canadian shallow natural gas assets and properties in the Rocky Mountain area, Texas, and Pennsylvania.

During the fourth quarter of 2010, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), paid $210 million to acquire Galveston LNG Inc., a Calgary-based corporation which owned 49% of the LNG export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia.  In addition, Galveston LNG Inc. also owned a 24.5% interest in the PTP originating at Summit Lake, British Columbia.  The pipeline is intended to link Western Canada's natural gas producing regions to the Kitimat LNG Terminal.  At the time EOG completed the acquisition, an affiliate of Apache Corporation (Apache) owned 51% of the Kitimat LNG Terminal and a 25.5% interest in PTP.  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 purchased an additional 24.5% interest in PTP for $25.2 million.  A portion of the purchase price ($15.3 million) was paid at closing with the remaining amount to be paid contingent on the decision to proceed with the construction of the Kitimat LNG Terminal.  Additionally, in March 2011, EOGRC and Apache, through a series of transactions, sold a portion of their interests in the Kitimat LNG Terminal and PTP to an affiliate of Encana Corporation (Encana).  Subsequent to these transactions, ownership interests in both the Kitimat LNG Terminal and PTP are:  Apache (operator) 40%, EOGRC 30% and Encana 30%.  All future costs of the project will be paid by each party in proportion to its respective ownership percentage.

F-31

In the fourth quarter of 2010, EOG completed the sales of certain of its Canadian shallow natural gas assets in three separate transactions.  Proceeds from the sales were approximately $344 million.  In 2010, 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.

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

In December 2009, EOG sold its crude oil and natural gas related assets located in California for consideration of $202 million.  EOG realized a pretax gain in 2009 of approximately $146 million on the sale.

In October 2009, EOG entered into an agreement to acquire unproved acreage located in Nacogdoches County, Texas, within the Haynesville and Bossier Shale formations (Haynesville Assets).  EOG acquired the unproved acreage at principal, supplemental and final closings held in October 2009, December 2009 and February 2010, respectively.  The acquisition agreement provides for an additional one-time supplemental cash payment to the sellers of the Haynesville Assets that is contingent on the satisfaction of certain conditions (within a five-year period beginning on the principal closing date) set forth in the acquisition agreement with respect to future natural gas prices.  The aggregate consideration recorded in 2009 and 2010 for the acquisition of the Haynesville Assets was $134 million and $18 million, respectively.

During the third quarter of 2009, EOG completed three transactions to acquire certain crude oil and natural gas properties and related assets located in Montague and Cooke Counties, Texas.  The aggregate purchase price of the transactions totaled $197 million, consisting of cash consideration of $107 million and 1,450,000 shares of EOG Common Stock valued at $89.6 million on the closing date of the applicable transaction.

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EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands, Except Per Share Data Unless Otherwise Indicated)

(Unaudited)

Oil and Gas Producing Activities

In December 2008, the United States Securities and Exchange Commission (SEC) released a final rule, "Modernization of Oil and Gas Reporting," which amended the oil and gas reporting requirements effective January 1, 2010.  The key revisions include:

·   using a 12-month average price to determine reserves;

·   including nontraditional resources in reserves if they are intended to be upgraded to synthetic oil and gas;

·   the ability to use reliable technologies to determine and estimate reserves;

·   permitting the optional disclosure of probable and possible reserves;

·   reporting the independence and qualifications of the reserve preparer or auditor and filing a report as an exhibit when a third party is relied upon to prepare reserve estimates or conduct reserve audits; and

·   disclosing the development of any proved undeveloped reserves, including the total quantity of proved undeveloped reserves at year-end, material changes to proved undeveloped reserves during the year, investments and progress toward the development of proved undeveloped reserves and an explanation of the reasons why material concentrations of proved undeveloped reserves have remained undeveloped for five years or more after disclosure as proved undeveloped reserves

In January 2010, the Financial Accounting Standards Board (FASB) issued FASB Accounting Standards Update (ASU) No. 2010-03, "Oil and Gas Reserve Estimations and Disclosures" (ASU 2010-03).  ASU 2010-03 aligns the current oil and gas reserve estimation and disclosure requirements of the Extractive Industries - Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule, "Modernization of Oil and Gas Reporting."  ASU No. 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009.

Oil and Gas Reserves.  Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir.  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.  Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.  Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.  See ITEM 1A. Risk Factors.

Proved reserves represent estimated quantities of crude oil, natural gas liquids and natural gas that geoscience and engineering data can estimate, with reasonable certainty, to be economically producible from a given day forward from known reservoirs under economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

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EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.  Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

In making estimates of proved undeveloped reserves, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its entire inventory of prospects.  In making a determination as to which of these locations would penetrate undrilled portions of the formation that can be judged, with reasonable certainty, to be continuous and contain economically producible crude oil and natural gas, studies are conducted using numerous data elements and analysis techniques.  EOG technical staff estimates the hydrocarbons in place, by mapping the entirety of the play in question using seismic techniques, typically employing two-dimensional and three-dimensional data.  This analysis is integrated with other static data including, but not limited to, core analysis, mechanical properties of the formation, thermal maturity indicators, and well logs of existing penetrations.  Highly specialized equipment is utilized to prepare rock samples in assessing microstructures which contribute to porosity and permeability.

Analysis of dynamic data is then incorporated to arrive at the estimated fractional recovery of hydrocarbons in place.  Data and analysis techniques employed include, but are not limited to, well testing, static bottom hole pressure, flowing bottom hole pressure, historical production trends using extant completion techniques (typically from vertical wells), pressure transient analysis and rate transient analysis.  Application of proprietary rate transient analysis techniques allow for quantification of estimates of contribution to production from both fractures and rock matrices.

The impact of optimal completion techniques is a key factor in determining if prospective locations are reasonably certain of being economically producible.  EOG's technical staff estimates recovery improvement that might be achieved when employing horizontal wells with multi-stage fracture stimulation.  In the early stages of development, EOG determines the optimal length of the horizontal lateral and multi-stage fracture stimulation using the aforementioned analysis techniques along with pilot drilling programs and gathering of microseismic data.

The process of analyzing static and dynamic data, well completion optimization and the results of early development provides the appropriate level of certainty as well as support for the economic producibilty of the plays in which proved undeveloped reserves are reflected.  EOG has found that this approach has been proven effective based on successful application in analogous reservoirs in resource plays.

EOG has formulated development plans for all locations related to its proved undeveloped reserves.  

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EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices, production volumes and the length, both vertical and horizontal, of wells.  Canadian reserves, as presented on a net basis, assume prices and legislated future royalty rates and EOG's estimate of future production volumes.  Similarly, certain of EOG's Trinidad reserves are held under production sharing contracts where EOG's interest varies with prices and production volumes.  Trinidad reserves, as presented on a net basis, assume prices in existence at the time the estimates were made and EOG's estimate of future production volumes.  Future fluctuations in prices, production rates or changes in political or regulatory environments could cause EOG's share of future production from Canadian and Trinidadian reserves to be materially different from that presented.

Estimates of proved reserves at December 31, 2011, 2010 and 2009 were based on studies performed by the engineering staff of EOG.  The Engineering and Acquisitions Department is directly responsible for EOG's reserve evaluation process and consists of seven professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and three are Registered Professional Engineers.  The Manager, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process.  The Manager, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 26 years of experience in reserve evaluations and is a Registered Professional Engineer in the State of Texas.

EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions Department in compliance with EOG's internal controls for such process.  Reserve information as well as models used to estimate such reserves are stored on secured databases.  Non-technical inputs used in reserve estimation models, including crude oil, natural gas liquids and natural gas prices, production costs, future capital expenditures and EOG's net ownership percentages are obtained from other departments within EOG.  EOG's Internal Audit Department conducts testing with respect to such non-technical inputs.  Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent petroleum consultants, to perform independent reserves evaluation of select EOG properties of not less than 75% of proved reserves.  EOG's Board of Directors requires that D&M's and EOG's reserve quantities for the properties evaluated by D&M vary by no more than 5% in the aggregate.  Once completed, EOG's year-end reserves are presented to senior management, including the Chairman of the Board and Chief Executive Officer; the President; the Chief Operating Officer; and the Vice President and Chief Financial Officer for approval.

Opinions by D&M for the years ended December 31, 2011, 2010 and 2009 covered producing areas containing 85%, 77% and 81%, respectively, of proved reserves of EOG on a net-equivalent-barrel-of-oil basis.  D&M's opinions indicate that the estimates of proved reserves prepared by EOG's Engineering and Acquisitions Department for the properties reviewed by D&M, when compared in total on a net-equivalent-barrel-of-oil basis, do not differ materially from the estimates prepared by D&M.  Such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the Engineering and Acquisitions Department of EOG.  All reports by D&M were developed utilizing geological and engineering data provided by EOG.  The report of D&M dated February 1, 2012, which contains further discussion of the reserve estimates and evaluations prepared by D&M, as well as the qualifications of D&M's technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 23.2 to this Annual Report on Form 10-K and incorporated herein by reference.

No major discovery or other favorable or adverse event subsequent to December 31, 2011 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

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EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2011, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2011, as estimated by the Engineering and Acquisitions Department of EOG:

NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY

		United			Other
		States	Canada	Trinidad	International (1)	Total
NET PROVED RESERVES
Crude Oil (MBbl) (2)
Net proved reserves at December 31, 2008		133,362	7,498	8,326	65	149,251
	Revisions of previous estimates	4,402	(183)	(1,760)	17	2,476
	Purchases in place	15,666	-	-	-	15,666
	Extensions, discoveries and other additions	58,258	19,783	-	-	78,041
	Sales in place	(5,742)	(20)	-	-	(5,762)
	Production	(17,494)	(1,492)	(1,123)	(24)	(20,133)
Net proved reserves at December 31, 2009		188,452	25,586	5,443	58	219,539
	Revisions of previous estimates	(8,313)	(104)	(754)	20	(9,151)
	Purchases in place	13	-	-	-	13
	Extensions, discoveries and other additions	199,479	3,198	1,751	48	204,476
	Sales in place	(1,082)	(589)	-	-	(1,671)
	Production	(23,092)	(2,455)	(1,709)	(28)	(27,284)
Net proved reserves at December 31, 2010		355,457	25,636	4,731	98	385,922
	Revisions of previous estimates	(21,188)	(4,611)	18	25	(25,756)
	Purchases in place	9	-	-	-	9
	Extensions, discoveries and other additions	202,552	449	-	-	203,001
	Sales in place	(4,301)	-	-	-	(4,301)
	Production	(37,233)	(2,882)	(1,242)	(25)	(41,382)
Net proved reserves at December 31, 2011		495,296	18,592	3,507	98	517,493
Natural Gas Liquids (MBbl) (2)
Net proved reserves at December 31, 2008		72,484	3,297	-	-	75,781
	Revisions of previous estimates	6,109	(926)	-	-	5,183
	Purchases in place	5,801	-	-	-	5,801
	Extensions, discoveries and other additions	18,546	24	-	-	18,570
	Sales in place	(3,231)	(30)	-	-	(3,261)
	Production	(8,220)	(393)	-	-	(8,613)
Net proved reserves at December 31, 2009		91,489	1,972	-	-	93,461
	Revisions of previous estimates	27,490	(196)	-	-	27,294
	Purchases in place	-	-	-	-	-
	Extensions, discoveries and other additions	42,221	21	-	-	42,242
	Sales in place	(2)	(6)	-	-	(8)
	Production	(10,764)	(316)	-	-	(11,080)
Net proved reserves at December 31, 2010		150,434	1,475	-	-	151,909
	Revisions of previous estimates	35,999	43	-	-	36,042
	Purchases in place	17	-	-	-	17
	Extensions, discoveries and other additions	65,288	-	-	-	65,288
	Sales in place	(10,008)	-	-	-	(10,008)
	Production	(15,144)	(316)	-	-	(15,460)
Net proved reserves at December 31, 2011		226,586	1,202	-	-	227,788

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EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

		United			Other
		States	Canada	Trinidad	International (1)	Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 2008		4,889.0	1,237.2	1,198.1	14.9	7,339.2
	Revisions of previous estimates	(378.0)	(447.2)	(104.9)	3.0	(927.1)
	Purchases in place	450.8	-	-	-	450.8
	Extensions, discoveries and other additions	1,925.0	846.5	-	-	2,771.5
	Sales in place	(114.4)	(5.1)	-	-	(119.5)
	Production	(422.3)	(81.9)	(107.4)	(5.2)	(616.8)
Net proved reserves at December 31, 2009		6,350.1	1,549.5	985.8	12.7	8,898.1
	Revisions of previous estimates	(222.7)	(29.9)	(88.6)	1.9	(339.3)
	Purchases in place	-	-	-	-	-
	Extensions, discoveries and other additions	821.3	3.4	63.0	7.9	895.6
	Sales in place	(34.6)	(316.2)	-	-	(350.8)
	Production	(422.6)	(73.0)	(132.6)	(5.2)	(633.4)
Net proved reserves at December 31, 2010		6,491.5	1,133.8	827.6	17.3	8,470.2
	Revisions of previous estimates	(344.0)	(49.8)	(24.2)	1.3	(416.7)
	Purchases in place	3.0	-	-	-	3.0
	Extensions, discoveries and other additions	634.6	-	74.7	4.5	713.8
	Sales in place	(323.6)	-	-	-	(323.6)
	Production	(415.7)	(48.1)	(127.4)	(4.6)	(595.8)
Net proved reserves at December 31, 2011		6,045.8	1,035.9	750.7	18.5	7,850.9
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2008		1,020,671	217,002	208,013	2,548	1,448,234
	Revisions of previous estimates	(52,487)	(75,638)	(19,250)	515	(146,860)
	Purchases in place	96,605	-	-	-	96,605
	Extensions, discoveries and other additions	397,642	160,882	-	-	558,524
	Sales in place	(28,032)	(898)	-	-	(28,930)
	Production	(96,107)	(15,540)	(19,016)	(891)	(131,554)
Net proved reserves at December 31, 2009		1,338,292	285,808	169,747	2,172	1,796,019
	Revisions of previous estimates	(17,945)	(5,288)	(15,513)	342	(38,404)
	Purchases in place	14	-	-	-	14
	Extensions, discoveries and other additions	378,582	3,789	12,250	1,363	395,984
	Sales in place	(6,860)	(53,288)	-	-	(60,148)
	Production	(104,277)	(14,937)	(23,815)	(901)	(143,930)
Net proved reserves at December 31, 2010		1,587,806	216,084	142,669	2,976	1,949,535
	Revisions of previous estimates	(42,526)	(12,865)	(4,011)	239	(59,163)
	Purchases in place	521	-	-	-	521
	Extensions, discoveries and other additions	373,602	448	12,455	750	387,255
	Sales in place	(68,247)	-	-	-	(68,247)
	Production	(121,648)	(11,219)	(22,484)	(787)	(156,138)
Net proved reserves at December 31, 2011		1,729,508	192,448	128,629	3,178	2,053,763

(1) Other International includes EOG's United Kingdom and China operations.

(2) Thousand barrels or thousand 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.

(3) Billion cubic feet.

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EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2011, EOG added 387 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Barnett Combo and Bakken shale plays.  Approximately 69% of the 2011 reserve additions were crude oil and condensate and natural gas liquids and over 96% were in the United States.  Sales in place of 68 MMBoe were primarily related to the disposition of certain producing natural gas assets in East Texas, the Rocky Mountain region and other producing basins in the United States.  Revisions of previous estimates of negative 59 MMBoe for 2011 included a negative revision of 16 MMBoe primarily due to a decrease in the average natural gas price used in the December 31, 2011 reserves estimation as compared to the price used in the prior year estimate.  Revisions other than price resulted from negative performance revisions for certain crude oil and natural gas properties in the United States, Canada and Trinidad.

During 2010, EOG added 396 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Bakken, Barnett Combo and Haynesville shale plays.  Approximately 62% of the 2010 reserve additions were crude oil and condensate and natural gas liquids and over 95% were in the United States.  Sales in place of 60 MMBoe were primarily related to the Canadian shallow natural gas assets and certain producing natural gas assets in East Texas.  Revisions of previous estimates of negative 38 MMBoe for 2010 included a positive revision of 28 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2010 reserves estimation as compared to the price used in the prior year estimate.  Revisions other than price resulted from negative performance revisions for certain natural gas properties in the United States, Canada and Trinidad and the removal of proved undeveloped natural gas drilling locations from the five-year drilling plan to focus on crude oil and liquids-rich drilling as part of EOG's overall strategy.

During 2009, EOG added 558 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Haynesville, Horn River, Barnett, Bakken and Marcellus shale plays.  Approximately 82% of the 2009 reserve additions were natural gas.  EOG's revisions of previous estimates for 2009 of negative 147 MMBoe included negative revisions of approximately 131 MMBoe, which were primarily due to the decrease in the average natural gas price used in the December 31, 2009 reserves estimation as compared to the price used in the prior year estimate.  Purchases in place include the reserves acquired in the Rocky Mountain property exchange and the acquisition of certain Barnett Shale Combo Assets in Montague and Cooke Counties, Texas.  Sales in place primarily include reserves from the properties relinquished in the Rocky Mountain property exchange and from the California asset sale.  See Note 16 to Consolidated Financial Statements.

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EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

		United			Other
		States	Canada	Trinidad	International (1)	Total
NET PROVED DEVELOPED RESERVES
Liquids (MBbl) (2)
	December 31, 2008	159,607	10,416	6,756	65	176,844
	December 31, 2009	189,322	10,831	3,966	58	204,177
	December 31, 2010	253,308	12,758	3,853	98	270,017
	December 31, 2011	338,144	9,220	2,657	97	350,118
Natural Gas (Bcf) (3)
	December 31, 2008	3,544.7	1,103.7	889.0	14.9	5,552.3
	December 31, 2009	3,330.1	681.0	609.4	12.7	4,633.2
	December 31, 2010	3,519.7	401.6	519.2	17.3	4,457.8
	December 31, 2011	3,234.9	295.8	606.3	18.6	4,155.6
Oil Equivalents (MBoe) (2)
	December 31, 2008	750,389	194,360	154,939	2,548	1,102,236
	December 31, 2009	744,339	124,323	105,540	2,172	976,374
	December 31, 2010	839,928	79,701	90,382	2,976	1,012,987
	December 31, 2011	877,301	58,524	103,710	3,178	1,042,713
NET PROVED UNDEVELOPED RESERVES
Liquids (MBbl) (2)
	December 31, 2008	46,239	379	1,570	-	48,188
	December 31, 2009	90,619	16,727	1,477	-	108,823
	December 31, 2010	252,583	14,352	879	-	267,814
	December 31, 2011	383,739	10,574	850	-	395,163
Natural Gas (Bcf) (3)
	December 31, 2008	1,344.3	133.6	309.0	-	1,786.9
	December 31, 2009	3,020.0	868.5	376.4	-	4,264.9
	December 31, 2010	2,971.7	732.2	308.5	-	4,012.4
	December 31, 2011	2,810.8	740.1	144.4	-	3,695.3
Oil Equivalents (MBoe) (2)
	December 31, 2008	270,282	22,642	53,074	-	345,998
	December 31, 2009	593,953	161,486	64,207	-	819,646
	December 31, 2010	747,878	136,383	52,287	-	936,548
	December 31, 2011	852,207	133,924	24,919	-	1,011,050

(1) Other International includes EOG's United Kingdom and China operations.

(2) Thousand barrels or thousand 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.

(3) Billion cubic feet.

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EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the twelve-month period ended December 31, 2011, total proved undeveloped reserves (PUDs) increased by 75 MMBoe to 1,011 MMBoe.  EOG added approximately 36 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on page F-34 of this Annual Report on Form 10-K), EOG added 199 MMBoe.  The proved undeveloped reserve additions were primarily in the Eagle Ford and Barnett Combo shale plays, and over 78% of the additions were crude oil and condensate and natural gas liquids.  During 2011, EOG drilled and transferred 144 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,619 million.  Revisions of PUDs totaled negative 7 MMBoe, primarily due to removal of certain natural gas PUDs from the five-year drilling plan.  During 2011, EOG sold 9 MMBoe of PUDs.

For the twelve-month period ended December 31, 2010, total PUDs increased by 117 MMBoe to 937 MMBoe.  EOG added approximately 37 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on page F-34 of this Annual Report on Form 10-K), EOG added 218 MMBoe.  The proved undeveloped reserve additions were primarily in the Eagle Ford, Bakken, Barnett Combo and Haynesville shale plays, and nearly 73% of the additions were crude oil and condensate and natural gas liquids.  During 2010, EOG drilled and transferred 118 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,280 million.  Revisions of PUDs totaled negative 12 MMBoe, primarily due to removal of certain natural gas PUDs from the five-year drilling plan.  During 2010, EOG sold 8 MMBoe of PUDs.

For the twelve-month period ended December 31, 2009, total PUDs increased by 474 MMBoe to 820 MMBoe.  Based on the definition of PUDs and its applicability to large resource plays (see discussion of technology employed on page F-34 of this Annual Report on Form 10-K), EOG added 445 MMBoe of PUDs, primarily in the Haynesville, Horn River, Barnett Combo and Marcellus shale plays.  Purchases in place included 70 MMBoe of PUDs from the Rocky Mountain property exchange and the acquisition of Barnett Combo assets (see Note 16 to Consolidated Financial Statements).  During 2009, EOG drilled and transferred approximately 29 MMBoe of PUDs to proved developed reserves at a total capital cost of $280 million.  Revisions of PUDs totaled negative 9 MMBoe.

As of December 31, 2011, EOG did not have a material amount of reserves that have remained undeveloped for five years or more.

F-40

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Capitalized Costs Relating to Oil and Gas Producing Activities.  The following table sets forth the capitalized costs relating to EOG's crude oil and natural gas producing activities at December 31, 2011 and 2010:

	2011			2010
Proved properties	$	32,353,380		$	27,693,700
Unproved properties		1,311,055			1,570,109
Total		33,664,435			29,263,809
Accumulated depreciation, depletion and amortization		(13,981,143	)		(11,859,870	)
Net capitalized costs	$	19,683,292		$	17,403,939

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities.  The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive Industries - Oil and Gas Topic of the ASC.

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property.

Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses.

Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

F-41

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2011, 2010 and 2009:

	United							Other
	States		Canada			Trinidad		International (1)			Total
2011
Acquisition Costs of Properties
Unproved	$	295,160	$	6,216		$	-	$	(604	)	$	300,772
Proved		4,219		28			-		-			4,247
Subtotal		299,379		6,244			-		(604	)		305,019
Exploration Costs		311,369		31,472			2,549		18,164			363,554
Development Costs (2)		5,410,378		302,564			138,905		78,744			5,930,591
Total	$	6,021,126	$	340,280		$	141,454	$	96,304		$	6,599,164
2010
Acquisition Costs of Properties
Unproved	$	403,509	$	13,956		$	-	$	(107	)	$	417,358
Proved		-		-			-		-			-
Subtotal		403,509		13,956			-		(107	)		417,358
Exploration Costs		454,379		38,604			23,386		86,784			603,153
Development Costs (3)		3,892,403		417,176			114,986		13,429			4,437,994
Total	$	4,750,291	$	469,736		$	138,372	$	100,106		$	5,458,505
2009
Acquisition Costs of Properties
Unproved	$	648,331	$	17,806		$	800	$	(311	)	$	666,626
Proved (4)		464,362		(33	)		-		-			464,329
Subtotal		1,112,693		17,773			800		(311	)		1,130,955
Exploration Costs		473,489		51,164			14,263		71,872			610,788
Development Costs (5)		1,898,859		237,613			27,369		1,914			2,165,755
Total	$	3,485,041	$	306,550		$	42,432	$	73,475		$	3,907,498

(1) Other International primarily consists of EOG's United Kingdom and China operations.

(2) Includes Asset Retirement Costs of $52 million, $70 million, $7 million and $4 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

(3) Includes Asset Retirement Costs of $71 million, $2 million, $(3) million and $2 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

(4) Includes non-cash acquisition costs of $353 million related to a property exchange transaction in the Rocky Mountain area.

(5) Includes Asset Retirement Costs of $60 million, $18 million, $6 million and zero for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

F-42

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Results of Operations for Oil and Gas Producing Activities (1).  The following tables set forth results of operations for oil and gas producing activities for the years ended December 31, 2011, 2010 and 2009:

	United							Other
	States		Canada			Trinidad		International (2)			Total
2011
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	5,814,942	$	459,853		$	555,143	$	28,250		$	6,858,188
Other		32,329		258			586		-			33,173
Total		5,847,271		460,111			555,729		28,250			6,891,361
Exploration Costs		148,199		10,479			2,520		10,460			171,658
Dry Hole Costs		30,521		432			-		22,277			53,230
Transportation Costs		421,060		5,969			1,620		1,673			430,322
Production Costs		1,096,955		174,973			49,318		10,964			1,332,210
Impairments		575,976		452,103			-		2,958			1,031,037
Depreciation, Depletion and Amortization		2,011,080		258,772			106,802		17,160			2,393,814
Income (Loss) Before Income Taxes		1,563,480		(442,617	)		395,469		(37,242	)		1,479,090
Income Tax Provision (Benefit)		569,153		(121,044	)		202,815		(13,056	)		637,868
Results of Operations	$	994,327	$	(321,573	)	$	192,654	$	(24,186	)	$	841,222
2010
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	3,928,240	$	477,416		$	447,852	$	27,707		$	4,881,215
Other		19,886		(31	)		3,696		-			23,551
Total		3,948,126		477,385			451,548		27,707			4,904,766
Exploration Costs		156,252		17,597			2,277		11,255			187,381
Dry Hole Costs		30,927		14,875			5,000		21,684			72,486
Transportation Costs		372,466		9,892			1,348		1,483			385,189
Production Costs		763,769		174,667			51,125		8,504			998,065
Impairments		271,466		451,703			1,465		418			725,052
Depreciation, Depletion and Amortization		1,430,408		314,663			70,553		15,399			1,831,023
Income (Loss) Before Income Taxes		922,838		(506,012	)		319,780		(31,036	)		705,570
Income Tax Provision (Benefit)		375,855		(151,315	)		140,413		(14,245	)		350,708
Results of Operations	$	546,983	$	(354,697	)	$	179,367	$	(16,791	)	$	354,862
2009
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	2,732,088	$	413,910		$	229,649	$	23,826		$	3,399,473
Other		9,692		(15	)		3,500		-			13,177
Total		2,741,780		413,895			233,149		23,826			3,412,650
Exploration Costs		137,696		18,675			5,107		8,114			169,592
Dry Hole Costs		39,570		1,461			-		10,212			51,243
Transportation Costs		270,940		9,317			1,141		1,931			283,329
Production Costs		556,236		145,292			27,616		9,452			738,596
Impairments		272,195		32,996			-		641			305,832
Depreciation, Depletion and Amortization		1,188,243		210,509			46,608		7,966			1,453,326
Income (Loss) Before Income Taxes		276,900		(4,355	)		152,677		(14,490	)		410,732
Income Tax Provision (Benefit)		106,537		(1,276	)		58,681		(6,067	)		157,875
Results of Operations	$	170,363	$	(3,079	)	$	93,996	$	(8,423	)	$	252,857

(1) Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2011.

(2) Other International primarily consists of EOG's United Kingdom and China operations.

F-43

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2011, 2010 and 2009:

	United						Other
	States		Canada		Trinidad		International (1)		Composite
Year Ended December 31, 2011	$	6.19	$	14.26	$	0.78	$	13.82	$	6.03
Year Ended December 31, 2010	$	5.00	$	10.28	$	0.65	$	9.34	$	4.85
Year Ended December 31, 2009	$	4.43	$	8.41	$	0.74	$	10.52	$	4.40

(1)      Other International primarily consists of EOG's United Kingdom and China operations.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves.  The following information has been developed utilizing procedures prescribed by the Extractive Industries - Oil and Gas Topic of the ASC and based on crude oil, natural gas liquids and natural gas reserves and production volumes estimated by the Engineering and Acquisitions Department of EOG.  The estimates were based on a 12-month average for commodity prices for the years 2011, 2010 and 2009.  The following information  may be useful for certain comparison purposes, but should not be solely relied upon in evaluating EOG or its performance.  Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections.  It is expected that material revisions to some estimates of crude oil, natural gas liquids and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions.  Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

F-44

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2011, 2010 and 2009:

	United									Other
	States			Canada			Trinidad			International (1)			Total
2011
Future cash inflows (2)	$	84,518,638		$	5,056,501		$	2,851,545		$	103,853		$	92,530,537
Future production costs		(33,294,343	)		(2,315,110	)		(388,199	)		(62,938	)		(36,060,590	)
Future development costs		(13,811,449	)		(1,566,917	)		(149,884	)		(331	)		(15,528,581	)
Future income taxes		(10,539,182	)		(81,590	)		(794,856	)		(2,457	)		(11,418,085	)
Future net cash flows		26,873,664			1,092,884			1,518,606			38,127			29,523,281
Discount to present value at 10% annual rate		(12,498,010	)		(456,537	)		(334,399	)		(9,054	)		(13,298,000	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	14,375,654		$	636,347		$	1,184,207		$	29,073		$	16,225,281
2010
Future cash inflows (3)	$	62,063,123		$	6,040,422		$	2,760,819		$	91,805		$	70,956,169
Future production costs		(22,616,039	)		(2,711,415	)		(384,147	)		(48,953	)		(25,760,554	)
Future development costs		(9,596,005	)		(1,716,734	)		(198,072	)		(334	)		(11,511,145	)
Future income taxes		(8,503,301	)		(129,816	)		(850,699	)		(3,598	)		(9,487,414	)
Future net cash flows		21,347,778			1,482,457			1,327,901			38,920			24,197,056
Discount to present value at 10% annual rate		(10,718,854	)		(736,222	)		(339,035	)		(11,121	)		(11,805,232	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	10,628,924		$	746,235		$	988,866		$	27,799		$	12,391,824
2009
Future cash inflows (4)	$	34,506,336		$	6,887,530		$	2,133,778		$	52,738		$	43,580,382
Future production costs		(11,977,152	)		(2,537,001	)		(398,318	)		(27,791	)		(14,940,262	)
Future development costs		(5,696,619	)		(2,255,088	)		(264,104	)		(346	)		(8,216,157	)
Future income taxes		(5,307,041	)		(249,986	)		(525,873	)		(4,276	)		(6,087,176	)
Future net cash flows		11,525,524			1,845,455			945,483			20,325			14,336,787
Discount to present value at 10% annual rate		(5,702,608	)		(808,211	)		(279,920	)		(5,030	)		(6,795,769	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	5,822,916		$	1,037,244		$	665,563		$	15,295		$	7,541,018

(1) Other International includes EOG's United Kingdom and China operations.

(2) Estimated crude oil prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $97.75, $90.70, $92.50 and $102.86, respectively.  Estimated natural gas liquids prices used to calculate 2011 future cash inflows for the United States and Canada were $51.77  and $46.97, respectively.  Estimated natural gas prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $4.03, $3.28, $3.37, and $5.07, respectively.

(3) Estimated crude oil prices used to calculate 2010 future cash inflows for the United States, Canada, Trinidad and Other International were $76.38, $72.59, $69.56 and $73.88, respectively.  Estimated natural gas liquids prices used to calculate 2010 future cash inflows for the United States and Canada were $43.85 and $26.56, respectively.  Estimated natural gas prices used to calculate 2010 future cash inflows for the United States, Canada, Trinidad and Other International were $4.36, $3.67, $2.94 and $5.02, respectively.

(4) Estimated crude oil prices used to calculate 2009 future cash inflows for the United States, Canada, Trinidad and Other International were $53.64, $56.85, $51.35 and $52.87, respectively.  Estimated natural gas liquids prices used to calculate 2009 future cash inflows for the United States and Canada were $28.75 and $19.31, respectively.  Estimated natural gas prices used to calculate 2009 future cash inflows for the United States, Canada, Trinidad and Other International were $3.43, $3.50, $1.88 and $3.92, respectively.

F-45

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Changes in Standardized Measure of Discounted Future Net Cash Flows.  The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2011:

	United									Other
	States			Canada			Trinidad			International			Total
December 31, 2008	$	6,307,712		$	1,751,152		$	601,053		$	19,984		$	8,679,901
Sales and transfers of oil and gas produced, net of production costs		(1,904,912	)		(259,301	)		(200,892	)		(12,443	)		(2,377,548	)
Net changes in prices and production costs		(1,482,778	)		(902,629	)		338,053			(13,868	)		(2,061,222	)
Extensions, discoveries, additions and improved recovery, net of related costs		1,702,471			259,305			-			-			1,961,776
Development costs incurred		344,500			14,200			-			-			358,700
Revisions of estimated development cost		595,875			68,883			(3,380	)		4,555			665,933
Revisions of previous quantity estimates		(422,294	)		(425,018	)		(124,222	)		1,016			(970,518	)
Accretion of discount		829,631			199,330			84,521			3,232			1,116,714
Net change in income taxes		261,513			259,169			(105,766	)		9,847			424,763
Purchases of reserves in place		209,130			-			-			-			209,130
Sales of reserves in place		(264,482	)		(13,912	)		-			-			(278,394	)
Changes in timing and other		(353,450	)		86,065			76,196			2,972			(188,217	)
December 31, 2009		5,822,916			1,037,244			665,563			15,295			7,541,018
Sales and transfers of oil and gas produced, net of production costs		(2,792,005	)		(292,857	)		(395,379	)		(17,720	)		(3,497,961	)
Net changes in prices and production costs		2,468,907			(559	)		721,796			7,259			3,197,403
Extensions, discoveries, additions and improved recovery, net of related costs		4,319,659			75,162			183,453			-			4,578,274
Development costs incurred		864,700			175,100			67,300			-			1,107,100
Revisions of estimated development cost		(257,360	)		260,290			(767	)		9			2,172
Revisions of previous quantity estimates		(164,748	)		(38,382	)		(175,002	)		4,006			(374,126	)
Accretion of discount		755,001			102,022			101,549			1,778			960,350
Net change in income taxes		(1,171,384	)		101,966			(258,354	)		2,469			(1,325,303	)
Purchases of reserves in place		265			-			-			-			265
Sales of reserves in place		(54,057	)		(290,592	)		-			-			(344,649	)
Changes in timing and other		837,030			(383,159	)		78,707			14,703			547,281
December 31, 2010		10,628,924			746,235			988,866			27,799			12,391,824
Sales and transfers of oil and gas produced, net of production costs		(4,296,926	)		(278,910	)		(504,205	)		(15,614	)		(5,095,655	)
Net changes in prices and production costs		716,682			(57,545	)		331,196			3,328			993,661
Extensions, discoveries, additions and improved recovery, net of related costs		6,223,552			22,591			102,548			-			6,348,691
Development costs incurred		1,422,500			48,200			74,800			-			1,545,500
Revisions of estimated development cost		(210,919	)		64,001			(14,074	)		2			(160,990	)
Revisions of previous quantity estimates		(482,496	)		(70,718	)		(56,884	)		801			(609,297	)
Accretion of discount		1,352,740			62,725			159,715			2,782			1,577,962
Net change in income taxes		(1,049,641	)		(118,988	)		9,511			13			(1,159,105	)
Purchases of reserves in place		5,241			-			-			-			5,241
Sales of reserves in place		(658,468	)		-			-			-			(658,468	)
Changes in timing and other		724,465			218,756			92,734			9,962			1,045,917
December 31, 2011	$	14,375,654		$	636,347		$	1,184,207		$	29,073		$	16,225,281

F-46

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

Unaudited Quarterly Financial Information

(In Thousands, Except Per Share Data)

Quarter Ended	Mar 31		Jun 30		Sep 30			Dec 31
2011
Net Operating Revenues	$	1,897,106	$	2,570,250	$	2,885,744		$	2,773,015
Operating Income	$	272,451	$	588,253	$	950,030		$	302,575
Income Before Income Taxes	$	225,722	$	543,224	$	899,221		$	241,632
Income Tax Provision		91,749		247,650		358,343			120,934
Net Income	$	133,973	$	295,574	$	540,878		$	120,698
Net Income Per Share (1)
Basic	$	0.52	$	1.11	$	2.03		$	0.45
Diluted	$	0.52	$	1.10	$	2.01		$	0.45
Average Number of Common Shares
Basic		255,200		265,830		266,053			266,277
Diluted		258,819		269,332		269,292			269,524
2010
Net Operating Revenues	$	1,370,693	$	1,357,968	$	1,582,075		$	1,789,160
Operating Income (Loss)	$	219,902	$	140,501	$	(11,695	)	$	174,611
Income (Loss) Before Income Taxes	$	197,157	$	110,059	$	(38,813	)	$	139,573
Income Tax Provision		79,142		50,187		32,093			85,900
Net Income (Loss)	$	118,015	$	59,872	$	(70,906	)	$	53,673
Net Income (Loss) Per Share (1)
Basic	$	0.47	$	0.24	$	(0.28	)	$	0.21
Diluted	$	0.46	$	0.24	$	(0.28	)	$	0.21
Average Number of Common Shares
Basic		250,370		250,825		251,015			251,365
Diluted		253,869		254,503		251,015			254,721

(1) The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.

F-47

Sched

Schedule II

EOG RESOURCES, INC.

VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2011, 2010 and 2009

(In Thousands)

Column A	Column B		Column C		Column D			Column E
			Additions
	Balance at		Charged to		Deductions			Balance at
	Beginning of		Costs and		From			End of
Description	Year		Expenses		Reserves			Year
2011
Allowance deducted from Accounts Receivable	$	13,642	$	778	$	11,711	(1)	$	2,709
2010
Allowance deducted from Accounts Receivable	$	13,228	$	885	$	471		$	13,642
2009
Allowance deducted from Accounts Receivable	$	13,131	$	145	$	48		$	13,228

(1)   Primarily reflects amounts related to bankruptcies which occurred in December 2001.

S-1

EXHIBITS

Exhibits not incorporated herein by reference to a prior filing are designated by (i) an asterisk (*) and are filed herewith; or (ii) a pound sign (#) and are not filed herewith, and, pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, the registrant hereby agrees to furnish a copy of such exhibit to the United States Securities and Exchange Commission (SEC) upon request.

Exhibit Number		Description
3.1(a)	-	Restated Certificate of Incorporation, dated September 3, 1987 (Exhibit 3.1(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).
3.1(b)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated May 5, 1993 (Exhibit 4.1(b) to EOG's Registration Statement on Form S-8, SEC File No. 33-52201, filed February 8, 1994).
3.1(c)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated June 14, 1994 (Exhibit 4.1(c) to EOG's Registration Statement on Form S-8, SEC File No. 33-58103, filed March 15, 1995).
3.1(d)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated June 11, 1996 (Exhibit 3(d) to EOG's Registration Statement on Form S-3, SEC File No. 333-09919, filed August 9, 1996).
3.1(e)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated May 7, 1997 (Exhibit 3(e) to EOG's Registration Statement on Form S-3, SEC File No. 333-44785, filed January 23, 1998).
3.1(f)	-	Certificate of Ownership and Merger Merging EOG Resources, Inc. into Enron Oil & Gas Company, dated August 26, 1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999) (SEC File No. 001-09743).
3.1(g)	-	Certificate of Designations of Series E Junior Participating Preferred Stock, dated February 14, 2000 (Exhibit 2 to EOG's Registration Statement on Form 8-A, SEC File No. 001-09743, filed February 18, 2000).
3.1(h)	-	Certificate of Elimination of the Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, dated September 13, 2000 (Exhibit 3.1(j) to EOG's Registration Statement on Form S-3, SEC File No. 333-46858, filed September 28, 2000).
3.1(i)	-	Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series C, dated September 13, 2000 (Exhibit 3.1(k) to EOG's Registration Statement on Form S-3, SEC File No. 333-46858, filed September 28, 2000).
3.1(j)	-	Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series D, dated February 24, 2005 (Exhibit 3.1(k) to EOG's Annual Report on Form 10-K for the year ended December 31, 2004) (SEC File No. 001-09743).
3.1(k)	-	Amended Certificate of Designations of Series E Junior Participating Preferred Stock, dated March 7, 2005 (Exhibit 3.1(m) to EOG's Annual Report on Form 10-K for the year ended December 31, 2007).
3.1(l)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated May 3, 2005 (Exhibit 3.1(l) to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005) (SEC File No. 001-09743).
3.1(m)	-	Certificate of Elimination of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated March 6, 2008 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed March 6, 2008).
3.2	-	Bylaws, as amended and restated effective as of February 26, 2009 (Exhibit 3.2(a) to EOG's Current Report on Form 8-K, filed March 4, 2009).
4.1	-	Specimen of Certificate evidencing EOG's Common Stock (Exhibit 3.3 to EOG's Annual Report on Form 10-K for the year ended December 31, 1999) (SEC File No. 001-09743).

E-1

Exhibit Number		Description
4.2	-	Indenture, dated as of September 1, 1991, between Enron Oil & Gas Company (predecessor to EOG) and The Bank of New York Mellon Trust Company, N.A. (as successor in interest to JPMorgan Chase Bank, N.A. (formerly, Texas Commerce Bank National Association)), as Trustee (Exhibit 4(a) to EOG's Registration Statement on Form S-3, SEC File No. 33-42640, filed September 6, 1991).
4.3(a)	-	Officers' Certificate Establishing 6.125% Senior Notes due 2013 and 6.875% Senior Notes due 2018, dated September 30, 2008 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed September 30, 2008).
4.3(b)	-	Form of Global Note with respect to the 6.125% Senior Notes due 2013 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed September 30, 2008).
4.3(c)	-	Form of Global Note with respect to the 6.875% Senior Notes due 2018 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed September 30, 2008).
4.4(a)	-	Officers' Certificate Establishing 5.875% Senior Notes due 2017 of EOG, dated September 10, 2007 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed September 10, 2007).
4.4(b)	-	Form of Global Note with respect to the 5.875% Senior Notes due 2017 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed September 10, 2007).
#4.5(a)	-	Certificate, dated April 3, 1998, of the Senior Vice President and Chief Financial Officer of Enron Oil & Gas Company (predecessor to EOG) establishing the terms of the 6.65% Notes due April 1, 2028.
#4.5(b)	-	Global Note with respect to the 6.65% Notes due April 1, 2028 of Enron Oil & Gas Company (predecessor to EOG).
#4.6(a)	-	Indenture, dated as of November 15, 2001, between EOG Company of Canada, as Issuer, and Wells Fargo Bank, National Association, as successor Trustee, with respect to the 7.00% Senior Notes due 2011 of EOG Company of Canada.
#4.6(b)	-	First Supplemental Indenture, dated as of April 2, 2002, to the Indenture, dated as of November 15, 2001, between EOG Company of Canada, as Issuer, and Wells Fargo Bank, National Association, as successor Trustee, with respect to the 7.00% Senior Notes due 2011 of EOG Company of Canada.
#4.7	-	Indenture, dated as of March 1, 2004, between EOG Resources Canada Inc., as Issuer, and The Bank of New York Trust Company, N.A., as Trustee, with respect to the 4.75% Senior Notes due 2014 of EOG Resources Canada Inc.
4.8	-	Indenture, dated as of May 18, 2009, between EOG and Wells Fargo Bank, NA, as Trustee (Exhibit 4.9 to EOG's Registration Statement on Form S-3, SEC File No. 333-159301, filed May 18, 2009).
4.9(a)	-	Officers' Certificate Establishing 5.625% Senior Notes due 2019 of EOG, dated May 21, 2009 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed May 21, 2009).
4.9(b)	-	Form of Global Note with respect to the 5.625% Senior Notes due 2019 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed May 21, 2009).
4.10(a)	-	Officers’ Certificate Establishing 2.95% Senior Notes due 2015 and 4.40% Senior Notes due 2020, dated May 20, 2010 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed May 26, 2010).
4.10(b)	-	Form of Global Note with respect to the 2.95% Senior Notes due 2015 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed May 26, 2010).

E-2

Exhibit Number		Description
4.10(c)	-	Form of Global Note with respect to the 4.40% Senior Notes due 2020 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed May 26, 2010).
4.11(a)	-	Officers' Certificate Establishing 2.500% Senior Notes due 2016, 4.100% Senior Notes due 2021 and Floating Rate Senior Notes due 2014, dated November 23, 2010 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed November 24, 2010).
4.11(b)	-	Form of Global Note with respect to the 2.500% Senior Notes due 2016 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed November 24, 2010).
4.11(c)	-	Form of Global Note with respect to the 4.100% Senior Notes due 2021 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed November 24, 2010).
4.11(d)	-	Form of Global Note with respect to the Floating Rate Senior Notes due 2014 of EOG (Exhibit 4.5 to EOG's Current Report on Form 8-K, filed November 24, 2010).
10.1(a)+	-	EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, effective as of May 8, 2008 (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed May 14, 2008).
10.1(b)+	-	First Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as of September 4, 2008 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2008).
10.1(c)+	-	Second Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as of January 1, 2010 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).
10.1(d)+	-	Form of Stock Option Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (effective for grants made prior to February 23, 2011) (Exhibit 10.2 to EOG's Current Report on Form 8-K, filed May 14, 2008).
10.1(e)+	-	Form of Stock Option Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (effective for grants made on or after February 23, 2011) (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).
10.1(f)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (effective for grants made prior to February 23, 2011) (Exhibit 10.3 to EOG's Current Report on Form 8-K, filed May 14, 2008).
10.1(g)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (effective for grants made on or after February 23, 2011) (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).
10.1(h)	-	Form of Nonemployee Director Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed May 14, 2008).
10.1(i)+	-	Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.5 to EOG's Current Report on Form 8-K, filed May 14, 2008).
10.1(j)+	-	Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.6 to EOG's Current Report on Form 8-K, filed May 14, 2008).

E-3

Exhibit Number		Description
10.1(k)	-	Form of Nonemployee Director Restricted Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.7 to EOG's Current Report on Form 8-K, filed May 14, 2008).
10.2(a)+	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Plan Document, effective as of December 16, 2008 (Exhibit 10.2(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).
*10.2(b)+	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Adoption Agreement, originally dated as of December 16, 2008 (and as amended through February 24, 2012 (including an amendment to Item 7 thereof, effective January 1, 2012, with respect to the deferral of restricted stock units)) (originally filed as Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).
10.3(a)+	-	Amended and Restated Enron Oil & Gas Company 1994 Stock Plan (Exhibit 4.3 to EOG's Registration Statement on Form S-8, SEC File No. 33-58103, filed March 15, 1995).
10.3(b)+	-	Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 12, 1995 (Exhibit 4.3(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1995) (SEC File No. 001-09743).
10.3(c)+	-	Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 10, 1996 (Exhibit 4.3(a) to EOG's Registration Statement on Form S-8, SEC File No. 333-20841, filed January 31, 1997).
10.3(d)+	-	Third Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 9, 1997 (Exhibit 4.3(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997) (SEC File No. 001-09743).
10.3(e)+	-	Fourth Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of May 5, 1998 (Exhibit 4.3(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998) (SEC File No. 001-09743).
10.3(f)+	-	Fifth Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 8, 1998 (Exhibit 4.3(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998) (SEC File No. 001-09743).
10.3(g)+	-	Sixth Amendment to Amended and Restated EOG Resources, Inc. 1994 Stock Plan, dated effective as of May 8, 2001 (Exhibit 10.1(g) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001) (SEC File No. 001-09743).
10.3(h)+	-	Seventh Amendment to Amended and Restated EOG Resources, Inc. 1994 Stock Plan, dated effective as of December 30, 2005 (Exhibit 10.1(h) to EOG's Annual Report on Form 10-K for the year ended December 31, 2005) (SEC File No. 001-09743).
10.4(a)	-	EOG Resources, Inc. 1993 Nonemployee Directors Stock Option Plan, as amended and restated effective May 7, 2002 (Exhibit A to EOG's Proxy Statement, filed March 28, 2002, with respect to EOG's 2002 Annual Meeting of Stockholders) (SEC File No. 001-09743).
10.4(b)	-	First Amendment to EOG Resources, Inc. 1993 Nonemployee Directors Stock Option Plan, dated effective as of December 30, 2005 (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2005) (SEC File No. 001-09743).
10.5(a)+	-	EOG Resources, Inc. 1992 Stock Plan, as amended and restated effective May 4, 2004 (Exhibit B to EOG's Proxy Statement, filed March 29, 2004, with respect to EOG's 2004 Annual Meeting of Stockholders) (SEC File No. 001-09743).

E-4

Exhibit Number		Description
10.5(b)+	-	First Amendment to EOG Resources, Inc. 1992 Stock Plan, dated effective as of December 30, 2005 (Exhibit 10.3(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2005) (SEC File No. 001-09743).
10.6(a)+	-	Executive Employment Agreement between EOG and Mark G. Papa, effective as of June 15, 2005 (Exhibit 99.1 to EOG's Current Report on Form 8-K filed, June 21, 2005) (SEC File No. 001-09743).
10.6(b)+	-	First Amendment to Executive Employment Agreement between EOG and Mark G. Papa, effective as of March 16, 2009 (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed March 18, 2009).
10.6(c)+	-	Amended and Restated Change of Control Agreement between EOG and Mark G. Papa, effective as of June 15, 2005 (Exhibit 99.6 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.6(d)+	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Mark G. Papa, effective as of April 30, 2009 (Exhibit 10.1(b) to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).
10.6(e)+	-	Second Amendment to Amended and Restated Change of Control Agreement between EOG and Mark G. Papa, effective as of September 13, 2011 (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed September 13, 2011).
10.7(a)+	-	Executive Employment Agreement between EOG and Loren M. Leiker, effective as of June 15, 2005 (Exhibit 99.3 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.7(b)+	-	First Amendment to Executive Employment Agreement between EOG and Loren M. Leiker, effective as of March 16, 2009 (Exhibit 10.2 to EOG's Current Report on Form 8-K, filed March 18, 2009).
10.7(c)+	-	Amended and Restated Change of Control Agreement between EOG and Loren M. Leiker, effective as of June 15, 2005 (Exhibit 99.8 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.7(d)+	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Loren M. Leiker, effective as of April 30, 2009 (Exhibit 10.2(b) to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).
10.8(a)+	-	Executive Employment Agreement between EOG and Gary L. Thomas, effective as of June 15, 2005 (Exhibit 99.4 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.8(b)+	-	First Amendment to Executive Employment Agreement between EOG and Gary L. Thomas, effective as of March 16, 2009 (Exhibit 10.3 to EOG's Current Report on Form 8-K, filed March 18, 2009).
10.8(c)+	-	Amended and Restated Change of Control Agreement between EOG and Gary L. Thomas, effective as of June 15, 2005 (Exhibit 99.9 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.8(d)+	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Gary L. Thomas, effective as of April 30, 2009 (Exhibit 10.3(b) to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).
10.8(e)+	-	Second Amendment to Amended and Restated Change of Control Agreement between EOG and Gary L. Thomas, effective as of September 13, 2011 (Exhibit 10.3 to EOG's Current Report on Form 8-K, filed September 13, 2011).

E-5

Exhibit Number		Description
10.9(a)+	-	Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of June 15, 2005 (Exhibit 99.11 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.9(b)+	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of April 30, 2009 (Exhibit 10.5 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).
10.9(c)+	-	Second Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of September 13, 2011 (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed September 13, 2011).
10.10(a)+	-	Executive Employment Agreement between EOG and Frederick J. Plaeger, II, effective as of April 23, 2007 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007).
10.10(b)+	-	First Amendment to Executive Employment Agreement between EOG and Frederick J. Plaeger, II, effective as of April 30, 2009 (Exhibit 10.4(a) to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).
10.10(c)+	-	Change of Control Agreement between EOG and Frederick J. Plaeger, II, effective as of April 23, 2007 (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007).
10.10(d)+	-	First Amendment to Change of Control Agreement between EOG and Frederick J. Plaeger, II, effective as of April 30, 2009 (Exhibit 10.4(b) to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).
10.10(e)+	-	Second Amendment to Change of Control Agreement between EOG and Frederick J. Plaeger, II, effective as of September 13, 2011 (Exhibit 10.5 to EOG's Current Report on Form 8-K, filed September 13, 2011).
10.11(a)+	-	Executive Employment Agreement between EOG and William R. Thomas, effective as of February 1, 2011 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).
10.11(b)+	-	Change of Control Agreement between EOG and William R. Thomas, effective as of January 12, 2011 (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).
10.11(c)+	-	First Amendment to Change of Control Agreement between EOG and William R. Thomas, effective as of September 13, 2011 (Exhibit 10.2 to EOG's Current Report on Form 8-K, filed September 13, 2011).
10.12(a)+	-	EOG Resources, Inc. Change of Control Severance Plan, as amended and restated effective as of June 15, 2005 (Exhibit 99.12 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.12(b)+	-	First Amendment to the EOG Resources, Inc. Change of Control Severance Plan, effective as of April 30, 2009 (Exhibit 10.6 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).
10.13+	-	EOG Resources, Inc. Amended and Restated Executive Officer Annual Bonus Plan (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).
10.14(a)+	-	EOG Resources, Inc. Employee Stock Purchase Plan (Exhibit 4.4 to EOG’s Registration Statement on Form S-8, SEC File No. 333-62256, filed June 4, 2001).
10.14(b)+	-	Amendment to EOG Resources, Inc. Employee Stock Purchase Plan, dated effective as of January 1, 2010 (Exhibit 4.3(b) to EOG’s Registration Statement on Form S-8, SEC File No. 333-166518, filed May 4, 2010).

E-6

Exhibit Number		Description
10.15	-	Revolving Credit Agreement, dated as of October 11, 2011, among EOG, JPMorgan Chase Bank, N.A., as Administrative Agent, the financial institutions as bank parties thereto, and the other parties thereto (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed October 12, 2011).
10.16	-	Revolving Credit Agreement, dated as of September 10, 2010, among EOG, Bank of America, N.A., as Administrative Agent, the financial institutions as bank parties thereto, and the other parties thereto (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed September 14, 2010).
*     12	-	Computation of Ratio of Earnings to Fixed Charges and to Combined Fixed Charges and Preferred Stock Dividends.
*     21	-	Subsidiaries of EOG, as of December 31, 2011.
*     23.1	-	Consent of DeGolyer and MacNaughton.
*     23.2	-	Opinion of DeGolyer and MacNaughton dated February 1, 2012.
*     23.3	-	Consent of Deloitte & Touche LLP.
*     24	-	Powers of Attorney.
*     31.1	-	Section 302 Certification of Annual Report of Principal Executive Officer.
*     31.2	-	Section 302 Certification of Annual Report of Principal Financial Officer.
*     32.1	-	Section 906 Certification of Annual Report of Principal Executive Officer.
*     32.2	-	Section 906 Certification of Annual Report of Principal Financial Officer.
*     95	-	Mine Safety Disclosure Exhibit.
*  **101.INS	-	XBRL Instance Document.
*  **101.SCH	-	XBRL Schema Document.
*  **101.CAL	-	XBRL Calculation Linkbase Document.
*  **101.LAB	-	XBRL Label Linkbase Document.
*  **101.PRE	-	XBRL Presentation Linkbase Document.
*  **101.DEF	-	XBRL Definition Linkbase Document.

*Exhibits filed herewith

**Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language):  (i) the Consolidated Statements of Income and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2011, (ii) the Consolidated Balance Sheets - December 31, 2011 and 2010, (iii) the Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2011, (iv) the Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2011 and (v) Notes to Consolidated Financial Statements.

+ Management contract, compensatory plan or arrangement

E-7

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		EOG RESOURCES, INC.
		(Registrant)
Date: February 24, 2012	By:	/s/ TIMOTHY K. DRIGGERS                                                         Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities with EOG Resources, Inc. indicated and on the 24th day of February, 2012.

	Signature	Title
	/s/ MARK G. PAPA	Chairman of the Board and Chief Executive Officer and
	(Mark G. Papa)	Director (Principal Executive Officer)
	/s/ TIMOTHY K. DRIGGERS	Vice President and Chief Financial Officer
	(Timothy K. Driggers)	(Principal Financial Officer)
	/s/ ANN D. JANSSEN	Vice President, Accounting
	(Ann D. Janssen)	(Principal Accounting Officer)
	*	Director
	(George A. Alcorn)
	*	Director
	(Charles R. Crisp)
	*	Director
	(James C. Day)
	*	Director
	(H. Leighton Steward)
	*	Director
	(Donald F. Textor)
	*	Director
	(Frank G. Wisner)
*By	/s/ MICHAEL P. DONALDSON
	(Michael P. Donaldson)
	(Attorney-in-fact for persons indicated)

EOG RESOURCES, INC. AND SUBSIDIARIES

EXHIBITS TO FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011

INDEX OF EXHIBITS

Exhibit Number		Description
*     10.2(b)+	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Adoption Agreement, originally dated as of December 16, 2008 (and as amended through February 24, 2012 (including an amendment to Item 7 thereof, effective January 1, 2012, with respect to the deferral of restricted stock units)) (originally filed as Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).
*     12	-	Computation of Ratio of Earnings to Fixed Charges and to Combined Fixed Charges and Preferred Stock Dividends.
*     21	-	Subsidiaries of EOG, as of December 31, 2011.
*     23.1	-	Consent of DeGolyer and MacNaughton.
*     23.2	-	Opinion of DeGolyer and MacNaughton dated February 1, 2012.
*     23.3	-	Consent of Deloitte & Touche LLP.
*     24	-	Powers of Attorney.
*     31.1	-	Section 302 Certification of Annual Report of Principal Executive Officer.
*     31.2	-	Section 302 Certification of Annual Report of Principal Financial Officer.
*     32.1	-	Section 906 Certification of Annual Report of Principal Executive Officer.
*     32.2	-	Section 906 Certification of Annual Report of Principal Financial Officer.
*     95	-	Mine Safety Disclosure Exhibit.
*  **101.INS	-	XBRL Instance Document.
*  **101.SCH	-	XBRL Schema Document.
*  **101.CAL	-	XBRL Calculation Linkbase Document.
*  **101.LAB	-	XBRL Label Linkbase Document.
*  **101.PRE	-	XBRL Presentation Linkbase Document.
*  **101.DEF	-	XBRL Definition Linkbase Document.

*Exhibits filed herewith

**Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language):  (i) the Consolidated Statements of Income and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2011, (ii) the Consolidated Balance Sheets - December 31, 2011 and 2010, (iii) the Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2011, (iv) the Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2011 and (v) Notes to Consolidated Financial Statements.

EX-10.2

Exhibit 10.2b

NONQUALIFIED SUPPLEMENTAL

DEFERRED COMPENSATION PLAN

ADOPTION AGREEMENT

This adoption agreement and the accompanying plan document have not been approved by the Department of Labor, Internal Revenue Service, Securities Exchange Commission, or any other governmental entity.  Employers may not rely on this document or the accompanying plan document to ensure any particular tax consequences with respect to the Employer’s particular situation, nor do these documents constitute legal or tax advice.  Pen-Cal and its employees cannot provide legal or tax advice in connection with these documents.  Employers must determine the extent to which the Plan is subject to Federal or state securities laws.  You should have your attorney review this document and the accompanying plan document before adopting the documents.  This adoption agreement and accompanying plan document cannot be used in order to avoid penalties that may be imposed on the taxpayer.

NONQUALIFIED SUPPLEMENTAL

DEFERRED COMPENSATION PLAN

ADOPTION AGREEMENT

ADOPTION OF PLAN -- [Select one]

 o Adoption - The undersigned       (the “Employer”) hereby adopts as a Nonqualified Deferred Compensation Plan for the individuals identified in Item 5 herein the form of Plan known as the Nonqualified Supplemental Deferred Compensation Plan.

 x Amendment of Previous Nonqualified Deferred Compensation Plan –  With “Grandfathered” Amounts - EOG Resources, Inc. (the “Employer”) previously has adopted a Nonqualified Deferred Compensation Plan, known as the EOG Resources, Inc. 1996 Deferral Plan [enter name of previous plan], and the execution of this Adoption Agree­ment constitutes an amendment to that Plan, effective only for Deferrals, Contributions, earnings, gains, losses, depreciation and appreciation vested and credited thereto or debited therefrom on and after the Effective Date listed in Section 2 below, or, if otherwise determined by the Employer, on and after January 1, 2005 with respect to Plan provisions required under Section 409A of the Internal Revenue Code and the regulations thereunder.  All other amounts in the plan shall be subject to the provisions of the previous plan document.  This option is appropriate if the previous plan contains grandfathered amounts not subject to Section 409A of the Internal Revenue Code.  Grandfathered amounts were contributed to the plan prior to January 1, 2005 under the terms of the plan in effect prior to October 4, 2004, and those plan terms have not since been materially modified.  Grandfathered amounts and earnings will be administered under the terms of the prior plan document.

 o Restatement of Previous Nonqualified Deferred Compensation Plan –                     (the “Employer”) previously has adopted a Nonqualified Deferred Compensation Plan, known as the       [enter name of previous plan], and the execution of this Adoption Agree­ment constitutes a restatement of that Plan, effective as of the Effective Date listed in Section 2 below for all funds under the Plan.  This option is appropriate if the previous plan does not contain “grandfathered” amounts (see description above), or if Employer wishes to apply Section 409A rules to all amounts in the plan (even pre-2005 amounts), or if previous plan has been materially modified and thus become subject to Section 409A.

NAME OF PLAN

The name of this Plan as adopted by the Employer is the [enter name of Plan] EOG Resources, Inc. 409A Deferred Compensation Plan (the “Plan”).

INDIVIDUALIZED PLAN INFORMATION

With respect to the variable features contained in the Plan, the Employer hereby makes the following selections granted under the provisions of the Plan:

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1. Adopting Entity.  The Employer adopts the Plan as:

List type of business entity (corporation, partnership, controlled group of corporations, etc.) Corporation

List each Employer adopting the Plan and Employer Identification Number (EIN):

Name of Employer:	EOG Resources, Inc.	EIN:	76-0493859
Name of Employer:	EOG Resources Expat Services, Inc.	EIN:	76-0493859
Name of Employer:		EIN:
Name of Employer:		EIN:
Name of Employer:		EIN:

    (attach additional lists as necessary)

The adopting Employers and the Employer are referred to herein collectively as the “Employer.”

Select state of controlling law (see Section 10.7 of Plan Document):

o           State of incorporation;        

x          State of domicile                                Texas

2. Effective Date.  The “Effective Date” of the adoption of this Plan, this Plan amendment or this Plan restatement is [enter date], January 1, 2012.

3. Plan Year.  The “Plan year” of the Plan shall be [select one]:

 x the calendar year.

 o the fiscal year or other 12- month period ending on the last day of       [specify month].

 o a short Plan year beginning on      ,       and ending on      ,      ; and thereafter the Plan year shall be as indicated in (a) or (b) above.

4. Plan Administrator.  The “Administrator” of the Plan is the Plan Committee, which shall consist of not more than 3 persons appointed by the Chief Executive Officier, and such other person(s) or entity as the Employer shall appoint from time to time.

5. Eligible Individuals.  The following shall be eligible to participate in the Plan:  [select all that apply – do not list individual names]:

 x A select group of management or highly-compensated Employees as designated by the Employer in separate resolutions or agreements;

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 o Employee Board Members;

 x Non-Employee Board Members;

 o Other Service Providers (i.e., independent contractors, consultants, etc.)

 o Employees or other Service Providers above the following Compensation threshold:  [enter dollar amount]  $       ;

 o Employees with the following job titles:  [enter job title(s); for example, “Vice President and above”]      

 o Other: [enter description]     

6. Eligibility Timing.  Eligibility timing selected below shall apply uniformly to all Participant Deferrals (including Performance-Based Bonus Deferrals), as well as Employer Matching Contributions and Other Employer Contributions, unless otherwise indicated.  If the Employer wishes to provide for separate eligibility rules for different types of Compensation (for example, Salary vs. Bonus), or for types of Contributions (for example, Employer Matching Contributions vs. Participant Deferrals), mark “Other” below and attach exhibits as necessary[select one]:

 o Eligible immediately upon properly completed designation by the Plan administrator or Employer;

 o Eligible after the following period of employment, Board service, etc. [enter number of days, months or years, for example, 90 days]      ;

 x Other  [enter description]: As Designated by the Plan Committee.

7. Types and Amounts of Participant Deferrals [select all that apply and enter minimum and maximum percentages in increments of one percent (for example, Salary minimum 0% maximum 100%).   Note that no Deferral election can reduce a Participant’s Compensation below the amount necessary to satisfy required withholding for FICA/Medicare/income taxes,  required Participant Contributions into another Employer-sponsored benefit plan such as medical insurance, 401(k) loan repayments, etc.]:

 x Salary [select one]:

 x   percentage [enter minimum 1% and maximum 50%]

or

 x   fixed dollar amount  [enter minimum $2,000].

 o Non-Performance-Based Bonus [select one]:

 o   percentage [enter minimum      % and maximum      %]

or

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 o   fixed dollar amount  [enter minimum $     ].

 x Performance-Based Bonus [select one and enter performance period (for example, 12-month period ending each March 31 ]: performance period from January 1 to December 31.

 x   percentage [enter minimum 1% and maximum 100%]

or

 x   fixed dollar amount  [enter minimum $2,000].

 o Commissions [select one]:

o   percentage [enter minimum      % and, maximum      %]

or

 o   fixed dollar amount  [enter minimum $     ].

 x Board of Directors Fees/Retainer (note – should not include expense reimbursements):

 x   percentage [enter minimum 1% and, maximum 100%]

or

 x   fixed dollar amount  [enter minimum $2,000].

 o Other Service Provider Fees or other earned income from the Employer:

 o   percentage [enter minimum      % and, maximum      %]

or

 o   fixed dollar amount  [enter minimum $     ].

 x 401(k) Refund (amount deferred from Participant’s regular Compensation equal in value to any refund paid to Participant in that year resulting from excess deferrals in Employer’s 401(k) plan – see Subsection 2.9 of Plan document for definition.)

 o Social Security Trigger (amount deferred pursuant to an election by the Participant to defer a separate percentage of Compensation only from that portion of Compensation that exceeds the Social Security Taxable Wage Base for the upcoming year).

 x Other [enter description]:  Amounts to be contributed by EOG on the Participants' behalf into the Deferred Compensation Plan due to exceeding plan limits in the Money Purchase Pension and Savings Plans

 x Deferral of restricted stock units.

NOTE:  Special Rules for Multi-Year RSU Grants Structured To Provide For Annual Vesting of a Specified Portion of the Total Grant:

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o  Check this box if the Employer wishes to allow for deferral of restricted stock units that are structured so that a specified portion of the RSU grant vests annually (for example, an RSU grant over a four-year period vesting 25% annually).  Under this type of grant, the election to defer may be made separately with respect to each portion of the grant that vests in  a given year. However, each election for each portion of the grant must be made either: (i) within 30 days of the date of grant or each anniversary thereof, and only if the RSU is structured so that vesting is contingent on the employee performing services for at least an additional 12 months subsequent to the election; or (ii) 12 months before the payment date of the RSU (vesting date is treated as the payment date for these purposes), but the election will not take effect for 12 months, and the subsequent payout date must be at least five years later than the previous payment date).

8. Definition of Compensation for Purposes of Making Plan Contributions [select one]:

 o Same definition of Compensation as in Employer’s 401(k) or other applicable qualified retirement plan.

 x Participant’s total wages, salary, commissions, overtime, bonus, etc. for a given year which the Employer is required to report on Form W-2 or other appropriate form, (or, in the case of Board members, Board fees and retainer only, but not including expense reimbursements)(or, in the case of Other Service Providers, the Participant’s total remuneration from the Employer for a given year pursuant to the agreement to provide services to the Employer), earned while the Participant is an Eligible Individual as determined by the Employer.

 o Other [enter description]:       

9. Expiration of Participant’s Deferral Elections [select all that apply]:

 x Renewed Each Year:  Participant’s Deferral Elections must be renewed each year during the open enrollment period ending no later than December 31 prior to the effective Plan year (or, in the case of Performance-Based Bonuses, no less than 6 months prior to the end of the applicable performance period).

 x   For all types of Compensation Deferrals.

 o   For Salary Deferrals only -- other types of Deferrals are “evergreen”.

 o  For Performance-Based Bonus only -- other types of Deferrals are “evergreen”.

 o   Other: [specify]     

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 o Evergreen:  Participant’s Deferral Elections will be “evergreen” (i.e., will continue indefinitely until the Participant’s Termination Date unless changed by the Participant – so each year the Participant will be deemed to have the same election in place as the prior year unless actively changed by the Participant during the open enrollment period ending no later than December 31 prior to the effective Plan year or, in the case of Performance-Based Bonuses, no less than 6 months prior to the end of the applicable performance period).

 o   For all types of Compensation Deferrals.

 o   For Salary Deferrals only -- other types of Deferrals are renewed each year.

 o   For Performance-Based Bonus only -- other types of Deferrals are renewed each year.

 o   Other: [specify] __________     

10. Employer Contributions [select all that apply]:.

 o (a) No Employer Contributions.

 o (b) Matching Contributions [enter description of matching formula below and also complete Items 11 and 12]

                                _________________________________________________________________

                                _________________________________________________________________

 x (c) Employer Contributions other than Matching Contributions [enter description of Employer Contribution formula below and complete Item 13]

         Amount or formula for determining and allocating such contributions should be documented in writing when determined, and such writings will form part of the Plan).

11. Employees Eligible to Receive Employer Matching Contributions.  Matching Contributions made for each Plan Year (if applicable)  shall be allocated and credited to the Accounts of the following Participants: [Select one if applicable]

 o Participants who were employed by the Employer (or, in the case of non-Employee Board Members, served on the Board) during that Plan Year, or, in the case of Other Service Providers, who provided services to the Employer during that Plan Year.

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 o Participants who were employed by the Employer (or, in the case of non-Employee Board Members, served on the Board) on the last day of the Plan Year, or, in the case of Other Service Providers, who provided services to the Employer on the last day of the Plan Year.

 o Participants who were employed by the Employer (or, in the case of non-Employee Board Members, served on the Board) on the last day of the Plan Year or who retired, died or were Disabled during the Plan Year, or, in the case of Other Service Providers, who provided services to the Employer on the last day of the Plan Year or who died or were Disabled during the Plan Year.  [If this option is selected, complete Item 29 -- definition of “Disability”.]

12.           Vesting Schedule of Employer Matching Contributions.  If Matching Contributionsare made to the Plan, select the rate at which such Contributions will vest [select one]:

 o Immediate 100% vesting for all Participants.

 o “Cliff” vesting (0%  up to cliff; 100% after cliff) [select one]:

 o   1 year cliff (less than 1 year 0%; 1 or more years 100%)

 o   2 year cliff (less than 2 years 0%; 2 or more years 100%)

 o   Other cliff (enter number of years:  less than       years 0%;       or more years 100%)

 o “Graded” vesting  [enter vesting percentages]:

1 year       %                                6 years        %                                11 years      %

2 years      %                                7 years        %                                12 years      %

3 years      %                                8 years        %                                13 years      %

4 years      %                                9 years        %                                14 years      %

5 years      %                                10 years      %                                15 years      %

 o Other vesting schedule: [describe schedule – subject to approval]      

13. Vesting Schedule of Employer Contributions (Other Than Matching Contributions).  If Employer Contributions (other than Matching Contributions) are made to the Plan, select the rate at which such Contributions will vest [select one]:

 o Immediate 100% vesting for all Participants.

 o “Cliff” vesting (0%  up to cliff; 100% after cliff) [select one]:

 o   1 year cliff (less than 1 year 0%; 1 or more years 100%)

 o   2 year cliff (less than 2 years 0%; 2 or more years 100%)

 o   Other cliff (enter number of years:  less than       years 0%;       or more years 100%)

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 o “Graded” vesting  [enter vesting percentages]:

1 year       %                                6 years        %                                11 years      %

2 years      %                                7 years        %                                12 years      %

3 years      %                                8 years        %                                13 years      %

4 years      %                                9 years        %                                14 years      %

5 years      %                                10 years      %                                15 years      %

 x Other vesting schedule: [describe schedule – subject to approval] To be determined by the Employer at the time of contribution.

14. Vesting Years.  A “Vesting Year” described above for purposes of determining vesting under the Plan shall be computed in accordance with:  [select one – if this is an amendment or restatement of a prior plan, definition from prior plan will override this definition.]

 o Years of service (12-consecutive-month periods) with the Employer since date of hire (or date of commencement of Board service).

 o Years of participation in the Plan (12-consecutive-month period between date Participant enters Plan and anniversary of such date) (if this is an amendment or restatement of a prior Plan, years of participation in prior plan will be included) (additional fees will apply if this item is selected).

 o Plan Years since each Plan Year’s total Contributions were made (“rolling vesting”) (additional fees will apply if this item is selected).  [If this option is selected, select either (a) or (b) below:]

 o (a) Vesting will be credited/updated on the last day of the Plan year.

 o (b) Vesting will be credited/updated on the anniversary of the date the Contribution is credited.

 15. Full Vesting Upon Occurrence of Specific Event.  [select all that apply]

o 100% vesting upon Normal Retirement [describe criteria such as age (can be partial year), years of service with the Employer (must be whole years of service), or years of participation in the Plan (must be whole years of participation)]

                                                ______

o 100% vesting upon Early Retirement [describe criteria such as age (must be whole years), years of service with the Employer (must be whole years of service), or years of participation in the Plan (must be whole years of participation)]

                                                ______

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 o 100% vesting upon Death.

 o 100% vesting upon Disability [complete Item 29 – definition of “Disability”].

 o 100% vesting upon Change in Control of the Employer [complete Items 27 and 28 – definition of “Change in Control”]

 o 100% vesting upon occurrence of other event:  [describe event]

                                                ______

16. Service Before Plan’s Establishment Excluded.  Years of service earned prior to establishment of the Plan shall be disregarded for purposes of determining vesting under the Plan:

  o        Yes (this may be elected only if this is the establishment of a new Plan).

  x       No.

17. Forfeitures for Misconduct or Violation of Non-Compete.  Participants terminating employment prior to becoming 100% vested will forfeit the forfeitable percentage of their Accounts as indicated in accordance with the vesting schedule selected in Items 12 and/or 13.  Participants may also forfeit 100% of their Matching and Employer Contribution Accounts (if applicable) under the following circumstances:  [select any that apply]:

 x Misconduct (termination for Cause). [enter definition of Misconduct or Cause below]

Upon a Participant's Termination for Cause, the Participant shall be entitled to receive in a single sum the elective deferred compensation credited to the Account; however, no interest or Employer Contributions shall be credited to the Account.  If the termination is as the result of the Participant's fraud against or theft from the Company, the damages sustained by the Company shall be deducted from the amount payable.

 o Engaging in competition with the Employer.  [enter definition of engaging in competition below]

                                _________________________________________________________________

                                _________________________________________________________________

18. Employer Stock as Deemed Investment Option.  If Employer stock will be a deemed investment option, indicate below how shares are to be tracked:  [select one]

 x Partial and whole shares.

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 o Unitized fund.

19. In-Service Distributions.  If the Employer elects below, the Plan will allow distributions of Participant Deferral Contributions to be made to Participants while they are still employed (“In-Service Distributions”), if they elect a fixed distribution date during the regular election period.    [Select one]

 o No, In-Service Distributions will not be permitted.

 x Yes, In-Service Distributions will be permitted.  [select one ].

x   For All Participant Deferral Contributions

o   For Participant Compensation Deferral Contributions (other than Performance-Based Bonus) only.

o   For Participant Performance-Based Bonus Deferral Contributions.

o   For Employer Contributions. [if selected, employer contributions must be 100% vested, and additional fees may apply].  If Employer wishes to limit in-service withdrawals to specific types of Employer Contributions, enter details below:

_________________________________________________________________

[Note – if “Yes” is elected above and the Plan will allow In-Service Distributions, please indicate if Participant will be permitted to make a “pushback” subsequent election to defer the original distribution date at least five years in accordance with Plan provisions (see subsection 9.1 of Plan document – note that election must be made 12 months prior to original distribution date and election will not take effect for 12 months)   x  Yes  o  No ]

Please indicate the number of years a Participant must defer payment(s) until  In-Service Distribution(s) may begin:

o   2 Years after the Calendar Year for which the deferral is effective

x   1 Years after the Calendar Year for which the deferral is effective

Please indicate if separate In-Service Distribution Dates are allowed for each Type of Participant Deferral selected in Item 7:

o  No (single distribution date allowed per Plan Year)

x   Yes (requires additional tracked sources per Plan Year)

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20. In-Service Distributions – Form and Timing of Payment.  In-Service Distributions shall be made to Participants in the following form: [Select one]

  o Lump Sums Only

  x Either 100% in Lump Sums or 100% in Installments.

[Note – if Installments are elected above, please indicate if Participant will be permitted to make a subsequent election to change the installments in accordance with Plan provisions (see subsection 9.2 of Plan document)    x  Yes  o  No ]

21. Unforeseeable Emergency  Distributions Dates.  If the Employer elects below, the Plan will allow distributions to be made to Participants while they are still employed if they meet the criteria for an unforeseeable emergency financial hardship (“Unforeseeable Emergency Distributions”).  Both Participant Deferral Contributions and Vested Employer Contributions can be distributed in the event of an eligible Unforeseeable Emergency Distribution event. [Select one]

 o No, Unforeseeable Emergency Distributions will not be permitted.

 x Yes, Unforeseeable Emergency Distributions will be permitted.  [select one below].

 o   For active Participants only.

 x   For active Participants, terminated Participants and Beneficiaries.

22. Form of Distributions (at Termination of Employment or Death).  Distributions will be made to Participants upon Termination of Employment with the Employer or Death of the Participant as follows [select one]

 o Lump sum only.

 x Lump sum unless installments elected, but can only receive installments if Participant meets the following criteria [select all that apply– if item not selected below, then Participants in that category will receive lump sum only]:

x   Retirement [describe criteria such as age (can be partial year), years of service with the Employer (must be whole years of service), or years of participation in the Plan (must be whole years of participation)]65 years of age

x   Early Retirement [describe criteria such as age (must be whole years), years of service with the Employer (must be whole years of service), or years of participation in the Plan (must be whole years of participation)] 55 years of age with 5 years of service.

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x   Termination (other than for Misconduct, Cause or Violation of Non-Compete)

 o Lump sum unless installments elected, and Participant may receive installments regardless of reason for Termination of Employment.

[Note – if Installments are elected above, please complete Item 26 and indicate if Participant will be permitted to make a subsequent election to change the number of installments in accordance with Plan provisions (see subsection 9.2 of Plan document)      x Yes   o    No ]

23.   Distribution Upon Disability.  If the Employer selects below, the Plan will allow dis-tributions to be made to Participants upon Disability but while they are still employedif they meet the criteria for Disability in Item 29 below.  The form of distribution willbe the same as for Termination of Employment, or as elected by the Participant.

 o No, distribution upon Disability will not be permitted.

 x Yes, distributions upon Disability will be permitted.  [complete Item 29 – definition of “Disability”].

24.    Expiration of Participant’s Distribution Elections [select one]:

  x Renewed Each Year:  Participant’s Distribution Election must be selected each year during the open enrollment period for the following year’s contributions – if no new election is made, that year’s contributions default to payment in the form of a lump sum.  In-Service Distribution Elections must be made by participants each year.

  o Evergreen:  Participant’s Distribution Election will be “evergreen” (i.e., will continue indefinitely for each year’s contributions until the Participant’s Termination Date unless changed by the Participant – so each year the Participant will be deemed to have the same distribution election in place as the prior year unless actively changed by the Participant at open enrollment, and the change will only be applicable to future contributions).  In-Service Distribution Elections may not be treated as evergreen.

25. Distributions Upon Change in Control:  If Employer elects below, distributions will be made to Participants upon Change in Control of the Employer (without a termination of employment of the Participant), as follows [select one, and complete Items 27 and 28 below (definition of “Change in Control”) ]

 o No, Distributions upon Change in Control will not be permitted.

 x Yes, Distributions upon Change in Control will be permitted, in a lump sum only.

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 o Yes, Distributions upon Change in Control will be permitted, in a lump sum or in installments as elected by the Participant.

26. Length of Installments (if Installment Distributions permitted in Item 20, 22 and/or Item 25 above)  [indicate length below]:

Annual installments over no fewer than 2 [enter minimum number of years – must be at least 2] and no more than 15 years at Participant’s election [enter maximum number of years].

27. “Change in Control” – Dates of Distribution.  Distributions upon a Change in Control shall occur upon the date that [select all that apply – see Subsection 9.9  of the Plan document for more details]:

 x A person or group acquires more than 50% of the total fair market value or voting power of the stock of the corporation (select definition of “corporation” in Item 28 below).

 x A person or group acquires ownership of stock of the corporation with at least 30% of the total voting power of the corporation (select definition of “corporation” in Item 28 below).

 x A person or group acquires assets from the corporation having a total fair market value of at least 40% of the value of all assets of the corporation immediately prior to such acquisition.  (select definition of “corporation” in Item 28 below).

 x A majority of the corporation’s board of directors is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the board as constituted prior to the appointment or election (select definition of “corporation” in Item 28 below).

28. “Change in Control” – Which Corporation the Change Relates.  Distributions upon a Change in Control shall be made only if the Change in Control relates to the corporation selected below:  [select all that apply]:  

 o (a) The corporation for whom the Participant is performing services at the time of the Change in Control event.

 x (b) The corporation liable for payments from the Plan to the Participant.

 o (c) A corporation that is a majority shareholder of a corporation described in (a) of (b) above.

 o (d) Any corporation in the chain of corporations in which each corporation is a majority shareholder of another corporation in the chain, ending in a corporation described in (a) or (b) above.

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29. Definition of “Disability.” A Participant shall be considered “Disabled” if [select one]:

 o by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of at least 12 months, the Participant is receiving income replacement benefits for at least 3 months under accident and health plans of the Employer;

 o the Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months;

 o the Participant is deemed to be totally disabled by the Social Security Administration;

 x the Participant is determined to be disabled in accordance with a disability insurance program, provided that the definition of disability under such disability insurance program complies with the requirements of one of the three preceding definitions above.

30. Distributions to “Key Employees” -- Investment.  In order to comply with Internal Revenue Code Section 409A, distributions to “key employees” (see subsection 9.3 of the Plan Document for definition) of publicly traded companies made due to employment termination cannot be made within 6 months of the employment termination date.  If distribution to a key employee must be delayed to comply with this 6-month rule, indicate below how Account balances of such a Participant will be invested during the period of delay [select one]:

 o Valued as of most recent Valuation Date and held at the Employer without allocation of additional gains or losses after such Valuation Date  until payment can be made.

 x Remain invested as if termination date had not occurred, then valued as of most recent Valuation Date and distributed.

31. QDRO Distributions.  The Employer may elect whether distributions from a Participant’s Account shall be permitted upon receipt by the Plan Administrator of a Qualified Domestic Relations Order relating to a marital dissolution or separation that provides for payment of all or a portion of a Participant’s Accounts to an alternate payee (spouse, former spouse, children, etc.).  [Indicate below whether QDRO distributions will be permitted]:

 o No, QDRO Distributions will not be permitted.

 x Yes, QDRO Distributions will be permitted.

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32. Additional Survivor Death Benefit from Life Insurance.  In the event that life insurance is utilized as a funding vehicle for the Plan, the Employer may wish to provide additional Survivor Benefit from the following options:  [select one]

 x No additional Survivor Benefit offered, but rather Participant’s vested Account balance.

 o Face value of life insurance policy of Participant, if any.

 o Greater of (a) face value of life insurance policy of Participant, if any, or (b) Participant’s vested Account balance.

 o Other: [enter amount or formula]      

33.  Payment of Plan Expenses.  Plan expenses may be paid as follows: [select one]

 x Directly by the Employer.

 o Deducted from the Participant accounts and Plan’s trust or other custodial account (mutual fund plans only, if applicable).

34.   “De Minimis” Small Amount Cashouts.  If selected by the Employer, Participantaccount balances that do not exceed a certain threshold amount will be automaticallycashed out upon the Participant‘s Termination of Employment or Death, as providedbelow [select one]

  x Yes, amounts that do not exceed a threshold dollar amount will automatically be cashed out [IRS 402(g) limit OR $       [enter dollar amount, not to exceed the IRS 402(g) limit for a given year]

  o No, no “de minimis” small amounts will be cashed out.

By signing this Adoption Agreement, the Employer certifies that it has consulted with legal counsel regarding the effects of the Plan, as applicable, on all parties.  The Employer further certifies that it has and will limit participation in the Plan to a select group of management or highly compensated Employees, Board Members or Other Service Providers, as determined by the Employer in consultation with legal counsel.  The Employer further certifies that it is the Employer’s sole responsibility to ensure that each Participant with the right to direct deemed investments under the Plan that are based on securities issued by the Employer or a member of its controlled group (as defined in Code Section 414(b) and (c)) will receive a prospectus for any such deemed investment option based on such Employer securities.

The Employer is solely responsible for its compliance with applicable laws, including Federal and state securities and other applicable laws.

Only those elections that are completed shall be considered as provisions applicable to and forming a part of the Plan.

-15-

This Adoption Agreement may only be used in conjunction with the Plan document.  All selections in the Adoption Agreement providing for customized or “other” plan provisions are subject to review for administrative feasibility, and may be subject to additional fees.

Terms used in this Adoption Agreement which are defined in the Plan document shall have the meaning given them therein.

The Employer hereby acknowledges that it is adopting this Nonqualified Supplemental Deferred Compensation Plan.  Federal legislation or other changes in the law relating to nonqualified deferred compensation or other employee benefit plans may require that the Plan be amended.

*      *      *

The undersigned duly authorized owner, or officer of the Employer hereby executes the Plan on behalf of the Employer.

 Dated this 15th day of November, 2011.

EOG Resources, Inc.

Employer

/s/ Patricia Edwards

    By Patricia Edwards

    Its V.P Human Resources and Administration

-16-

EX-12

EXHIBIT 12

EOG RESOURCES, INC.

Computation of Ratio of Earnings to Fixed Charges and

Combined Fixed Charges and to Preferred Stock Dividends

(In Thousands)

(Unaudited)

Year Ended December 31		2011			2010			2009			2008			2007
EARNINGS AVAILABLE FOR
FIXED CHARGES:
Net Income		$	1,091,123		$	160,654		$	546,627		$	2,436,919		$	1,089,918
Less:	Capitalized Interest Expense		(57,741	)		(76,300	)		(54,919	)		(42,628	)		(29,324	)
Add:	Fixed Charges		315,702			237,590			181,426			117,568			96,228
Income Tax Provision			818,676			247,322			325,384			1,309,620			540,950
TOTAL EARNINGS AVAILABLE FOR FIXED    CHARGES		$	2,167,760		$	569,266		$	998,518		$	3,821,479		$	1,697,772
FIXED CHARGES:
Interest Expense		$	197,572		$	125,073		$	97,751		$	49,899		$	45,628
Capitalized Interest			57,741			76,300			54,919			42,628			29,324
Capitalized Expense Related to Indebtedness			12,791			4,513			3,150			1,759			1,150
Rental Expense Representative of Interest Factor			47,598			31,704			25,606			23,282			20,126
TOTAL FIXED CHARGES			315,702			237,590			181,426			117,568			96,228
Preferred Stock Dividends on a Pre-tax Basis			-			-			-			681			9,970
COMBINED TOTAL FIXED CHARGES AND
PREFERRED STOCK DIVIDENDS		$	315,702		$	237,590		$	181,426		$	118,249		$	106,198
RATIO OF EARNINGS TO
FIXED CHARGES			6.87			2.40			5.50			32.50			17.64
RATIO OF EARNINGS TO COMBINED FIXED
CHARGES AND PREFERRED STOCK
DIVIDENDS			6.87			2.40			5.50			32.32			15.99

EX-21

EXHIBIT 21

EOG Resources, Inc.

Subsidiaries

As of December 31, 2011

Company Name	Place Of Incorporation
3246988 Nova Scotia Company	Nova Scotia
Energy Search, Incorporated	Tennessee
EOG – Canada, Inc.	Delaware
EOG Argentina S.R.L.	Argentina
EOG Canada Company Ltd.	Alberta
EOG Canada Holdings I Inc.	Alberta
EOG Canada Holdings II Inc.	Alberta
EOG Canada Holdings ULC	Alberta
EOG Canada Investments ULC	Alberta
EOG Company of Canada	Nova Scotia
EOG Expat Services, Inc.	Delaware
EOG Resources (Nevis) Block 4 (a) Limited	Nevis
EOG Resources Appalachian LLC	Delaware
EOG Resources Argentina Limited	Cayman Islands
EOG Resources Argentina S.R.L.	Argentina
EOG Resources Canada	Alberta
EOG Resources Canada Company	Nova Scotia
EOG Resources Canada Holdings ULC	Alberta
EOG Resources Canada Inc.	Alberta
EOG Resources Canada Investments ULC	Alberta
EOG Resources Canada LNG	Alberta
EOG Resources China Limited	Hong Kong
EOG Resources International, Inc.	Delaware
EOG Resources LNG ULC (f/k/a Kitimat ULC)	Alberta
EOG Resources Marketing, Inc.	Delaware
EOG Resources Nevis U (b) Block Limited	Nevis
EOG Resources Nitro2000 Ltd.	Nevis
EOG Resources Poland International LLC Sp. z o.o.	Poland
EOG Resources Railyard (Louisiana) LLC	Delaware
EOG Resources Railyard (North Dakota), Inc.	Delaware
EOG Resources Railyard (Oklahoma), Inc.	Delaware
EOG Resources Railyard (Texas) LLC	Delaware
EOG Resources Railyard, Inc.	Delaware
EOG Resources Trinidad – LRL Unlimited	Trinidad
EOG Resources Trinidad – U(a) Block Limited	Cayman Islands
EOG Resources Trinidad Block 4(a) Unlimited	Trinidad
EOG Resources Trinidad Limited	Trinidad
EOG Resources Trinidad U(b) Block Unlimited	Trinidad
EOG Resources Trinidad-LRL Limited	Nevis
EOG Resources Tunisia International Ltd.	Cayman Islands
EOG Resources Turkey Limited	Cayman Islands
EOG Resources U.K. Holdings Limited	United Kingdom
EOG Resources U.K. Investments Limited	United Kingdom
EOG Resources United Kingdom Limited	United Kingdom
EOGI Argentina International Ltd.	Cayman Islands
EOGI China International Ltd.	Cayman Islands
EOGI International Company	Cayman Islands
EOGI International, Inc.	Delaware
EOGI Poland International Ltd.	Cayman Islands
EOGI Trinidad – U(a) Block Company	Cayman Islands
EOGI Tunisia International Ltd.	Cayman Islands
EOGI Turkey International Ltd.	Cayman Islands
Globe TAS LLC	Delaware
Hawthorn Oil Transportation, Inc.	Delaware
Hawthorn Oil Transportation (North Dakota), Inc.	Delaware
Hawthorn Oil Transportation (Oklahoma), Inc.	Delaware
Hawthorn Oil Transportation (Texas), Inc.	Delaware
Murrott Capital Ltd.	Nevis
Nilo Operating Company	Delaware
Online Energy Solutions, Inc.	Delaware
Pecan Pipeline (North Dakota), Inc.	Delaware
Pecan Pipeline (RM), Inc.	Delaware
Pecan Pipeline Company	Delaware

EX-23.1

EXHIBIT 23.1

DEGOLYER AND MACNAUGHTON

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 20, 2012

EOG Resources, Inc.

1111 Bagby, Sky Lobby 2

Houston, Texas 77002

Ladies and Gentlemen:

We hereby consent to the inclusion of references to our firm and to the opinions as mentioned below delivered to EOG Resources, Inc. (EOG) regarding our comparison of estimates prepared by us with those furnished to us by EOG of the proved crude oil, condensate, natural gas liquids, and natural gas reserves of certain selected properties owned by EOG in the section entitled "Supplemental Information to Consolidated Financial Statements - Oil and Gas Producing Activities" in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2011 to be filed with the United States Securities and Exchange Commission on or about February 23, 2012. The opinions are contained in our letter reports dated February 4, 2010, January 31, 2011 and February 1, 2012 with respect to the reserve estimates as of December 31, 2009, December 31, 2010, and December 31, 2011, respectively. Additionally, we hereby consent to the incorporation by reference of such references to our firm and to our opinions in EOG's previously filed Registration Statement Nos. 333-150791, 33-48358, 33-52201, 33-58103, 33-62005, 333-20841, 333-31715, 333-69483, 333-62256, 333-84014, 333-88924, 333-116701, 333-163947, 333-166517 and 333-166518.

Very truly yours,

/s/ DeGOLYER and MacNAUGHTON

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-23.2

EXHIBIT 23.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 1, 2012

EOG Resources, Inc.

1111 Bagby Street, Sky Lobby 2

Houston, Texas 77002

Gentlemen:

Pursuant to your request, we have conducted a reserves audit of the net proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of December 31, 2011, of certain properties owned by EOG Resources, Inc. (EOG) in the United States, Canada, China and Trinidad. The properties consist of working and royalty interests located in Louisiana, Montana, North Dakota, Pennsylvania, Texas, Utah and Wyoming; in British Columbia and Manitoba, Canada; China; and offshore from Trinidad. This evaluation was completed on January 31, 2012. EOG has represented that these properties account for 83.1 percent on a net equivalent barrel basis of EOG’s net proved reserves as of December 31, 2011, and that the net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided to us by EOG that it represents to be EOG’s estimates of the net reserves, as of December 31, 2011, for the same properties as those which we evaluated.

Reserves included herein are expressed as net reserves as represented by EOG. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2011. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by EOG after deducting all interests owned by others.

Estimates of oil, condensate, NGL, and natural gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with EOG personnel, EOG files, from records on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by Petroleum Information/Dwights LLC; Copyright 2011 Petroleum Information/Dwights LLC. In the preparation of this report we have relied, without independent verification, upon such information furnished by EOG with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Definition of Reserves

Petroleum reserves estimated by EOG and by us included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by EOG and by us in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil and Condensate Prices

EOG has represented that the oil and condensate prices were based on a 12-month average price (reference price), calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. EOG supplied differentials by field to a reference price of $96.19 per barrel and the prices were held constant thereafter. The volume-weighted average price for the proved reserves was $98.33 per barrel.

NGL Prices

EOG has represented that the NGL prices were based on a 12-month average price (reference price), calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. EOG supplied differentials by field to a reference price of $51.94 per barrel and the prices were held constant thereafter. The volume-weighted average price for the proved reserves was $51.55 per barrel.

Natural Gas Prices

EOG has represented that the natural gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The gas prices were calculated for each property using differentials to the reference price of $4.12 per Mcf furnished by EOG and held constant thereafter. The volume-weighted average price for the proved reserves was $3.80 per Mcf.

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by EOG, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2011 estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

EOG has represented that its estimated net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves of the SEC. EOG represents that its estimates of the net proved reserves attributable to these properties which represent 83.1 percent of EOG’s reserves on a net equivalent basis are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by EOG Net Proved Reserves as of December 31, 2011
	Oil, and Condendsate (Mbbl)	NGL (Mbbl)	Natural Gas (MMcf)	Oil Equivalent (Mboe)
Properties Reviewed by DeGolyer and MacNaughton
Proved Developed	175,315	105,454	3,082,012	794,437
Proved Undeveloped	278,472	88,341	3,267,670	911,425
Total Proved	453,787	193,795	6,349,682	1,705,862
Note: Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

Our estimates of EOG’s net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves of the SEC and are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2011
	Oil, and Condendsate (Mbbl)	NGL (Mbbl)	Natural Gas (MMcf)	Oil Equivalent (Mboe)
Proved Developed	161,319	103,007	2,913,939	749,982
Proved Undeveloped	316,903	78,409	3,193,997	927,645
Total Proved	478,222	181,416	6,107,936	1,677,627
Note: Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

In our opinion, the information relating to estimated proved reserves of oil, condensate, and natural gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9, of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a)(1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

In comparing the detailed net proved reserves estimates prepared by us and by EOG, we have found differences, both positive and negative, resulting in an aggregate difference of 4.3 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by EOG on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by us.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in EOG. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of EOG. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/ Paul J. Szatkowski

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.   That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to EOG dated February 1, 2012, and that I, as Senior Vice President, was responsible for the preparation of this report.

2.   That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 37 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Paul J. Szatkowski

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton

EX-23.3

EXHIBIT 23.3

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-163947 on Form S-3 and the following Registration Statements of Form S-8: 333-150791, 33-48358, 033-52201, 033-58103, 033-62005, 333-20841, 333-31715, 333-69483, 333-62256,  333-84014, 333-88924, 333-116701, 333-166517, and 333-166518, of EOG Resources, Inc, of our report dated February 23, 2012, relating to the consolidated financial statements and financial statement schedule of EOG Resources, Inc. and subsidiaries (which report expresses an unqualified opinion and includes an explanatory paragraph relating to EOG Resources, Inc.’s adoption of the updated oil and gas reserve estimation and disclosure rules on December 31, 2009), and the effectiveness of EOG Resources Inc.’s internal control over financial reporting, appearing in the Annual Report on Form 10-K of EOG Resources, Inc. for the year ended December 31, 2011.

/S/ DELOITTE & TOUCHE LLP

Houston, Texas

February 24, 2012

EX-24

EXHIBIT 24

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that, in connection with (i) the registration by EOG Resources, Inc., a Delaware corporation (the “Company”), under the Securities Act of 1933 (as amended) of 150,000 shares of the Common Stock, $.01 par value per share, of the Company (the “Common Stock”), to be offered and issued by the Company from time to time pursuant to the EOG Resources, Inc. 409A Deferred Compensation Plan (formerly known as the EOG Resources, Inc. 1996 Deferral Plan (as amended)) (the “Deferral Plan”) and (ii) the filing by the Company of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2011 with the U.S. Securities and Exchange Commission (“SEC”), the undersigned director of the Company hereby constitutes and appoints Frederick J. Plaeger, II, Timothy K. Driggers and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file (a) one or more registration statements on Form S-8 (or one or more amendments to the Company’s existing registration statement on Form S-8 (SEC File No. 333-84014) with respect to the Deferral Plan) relating to such shares of Common Stock to be offered and issued by the Company pursuant to the Deferral Plan and (b) such Annual Report on Form 10-K, in each case with the SEC, together with all amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 22nd day of February, 2012.

/s/ George A. Alcorn

GEORGE A. ALCORN

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that, in connection with (i) the registration by EOG Resources, Inc., a Delaware corporation (the “Company”), under the Securities Act of 1933 (as amended) of 150,000 shares of the Common Stock, $.01 par value per share, of the Company (the “Common Stock”), to be offered and issued by the Company from time to time pursuant to the EOG Resources, Inc. 409A Deferred Compensation Plan (formerly known as the EOG Resources, Inc. 1996 Deferral Plan (as amended)) (the “Deferral Plan”) and (ii) the filing by the Company of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2011 with the U.S. Securities and Exchange Commission (“SEC”), the undersigned director of the Company hereby constitutes and appoints Frederick J. Plaeger, II, Timothy K. Driggers and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file (a) one or more registration statements on Form S-8 (or one or more amendments to the Company’s existing registration statement on Form S-8 (SEC File No. 333-84014) with respect to the Deferral Plan) relating to such shares of Common Stock to be offered and issued by the Company pursuant to the Deferral Plan and (b) such Annual Report on Form 10-K, in each case with the SEC, together with all amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 22nd day of February, 2012.

/s/ Charles R. Crisp

CHARLES R. CRISP

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that, in connection with (i) the registration by EOG Resources, Inc., a Delaware corporation (the “Company”), under the Securities Act of 1933 (as amended) of 150,000 shares of the Common Stock, $.01 par value per share, of the Company (the “Common Stock”), to be offered and issued by the Company from time to time pursuant to the EOG Resources, Inc. 409A Deferred Compensation Plan (formerly known as the EOG Resources, Inc. 1996 Deferral Plan (as amended)) (the “Deferral Plan”) and (ii) the filing by the Company of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2011 with the U.S. Securities and Exchange Commission (“SEC”), the undersigned director of the Company hereby constitutes and appoints Frederick J. Plaeger, II, Timothy K. Driggers and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file (a) one or more registration statements on Form S-8 (or one or more amendments to the Company’s existing registration statement on Form S-8 (SEC File No. 333-84014) with respect to the Deferral Plan) relating to such shares of Common Stock to be offered and issued by the Company pursuant to the Deferral Plan and (b) such Annual Report on Form 10-K, in each case with the SEC, together with all amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 21st day of February, 2012.

/s/ James C. Day

JAMES C. DAY

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that, in connection with (i) the registration by EOG Resources, Inc., a Delaware corporation (the “Company”), under the Securities Act of 1933 (as amended) of 150,000 shares of the Common Stock, $.01 par value per share, of the Company (the “Common Stock”), to be offered and issued by the Company from time to time pursuant to the EOG Resources, Inc. 409A Deferred Compensation Plan (formerly known as the EOG Resources, Inc. 1996 Deferral Plan (as amended)) (the “Deferral Plan”) and (ii) the filing by the Company of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2011 with the U.S. Securities and Exchange Commission (“SEC”), the undersigned director of the Company hereby constitutes and appoints Frederick J. Plaeger, II, Timothy K. Driggers and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file (a) one or more registration statements on Form S-8 (or one or more amendments to the Company’s existing registration statement on Form S-8 (SEC File No. 333-84014) with respect to the Deferral Plan) relating to such shares of Common Stock to be offered and issued by the Company pursuant to the Deferral Plan and (b) such Annual Report on Form 10-K, in each case with the SEC, together with all amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 22nd day of February, 2012.

/s/ H. Leighton Steward

H. LEIGHTON STEWARD

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that, in connection with (i) the registration by EOG Resources, Inc., a Delaware corporation (the “Company”), under the Securities Act of 1933 (as amended) of 150,000 shares of the Common Stock, $.01 par value per share, of the Company (the “Common Stock”), to be offered and issued by the Company from time to time pursuant to the EOG Resources, Inc. 409A Deferred Compensation Plan (formerly known as the EOG Resources, Inc. 1996 Deferral Plan (as amended)) (the “Deferral Plan”) and (ii) the filing by the Company of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2011 with the U.S. Securities and Exchange Commission (“SEC”), the undersigned director of the Company hereby constitutes and appoints Frederick J. Plaeger, II, Timothy K. Driggers and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file (a) one or more registration statements on Form S-8 (or one or more amendments to the Company’s existing registration statement on Form S-8 (SEC File No. 333-84014) with respect to the Deferral Plan) relating to such shares of Common Stock to be offered and issued by the Company pursuant to the Deferral Plan and (b) such Annual Report on Form 10-K, in each case with the SEC, together with all amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 22nd day of February, 2012.

/s/ Donald F. Textor

DONALD F. TEXTOR

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that, in connection with (i) the registration by EOG Resources, Inc., a Delaware corporation (the “Company”), under the Securities Act of 1933 (as amended) of 150,000 shares of the Common Stock, $.01 par value per share, of the Company (the “Common Stock”), to be offered and issued by the Company from time to time pursuant to the EOG Resources, Inc. 409A Deferred Compensation Plan (formerly known as the EOG Resources, Inc. 1996 Deferral Plan (as amended)) (the “Deferral Plan”) and (ii) the filing by the Company of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2011 with the U.S. Securities and Exchange Commission (“SEC”), the undersigned director of the Company hereby constitutes and appoints Frederick J. Plaeger, II, Timothy K. Driggers and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file (a) one or more registration statements on Form S-8 (or one or more amendments to the Company’s existing registration statement on Form S-8 (SEC File No. 333-84014) with respect to the Deferral Plan) relating to such shares of Common Stock to be offered and issued by the Company pursuant to the Deferral Plan and (b) such Annual Report on Form 10-K, in each case with the SEC, together with all amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 20th day of February, 2012.

/s/ Frank G. Wisner

FRANK G. WISNER

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, Mark G. Papa, certify that:

1.      I have reviewed this Annual Report on Form 10-K of EOG Resources, Inc.;

2.      Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.      Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.      The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.      The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 24, 2012

/s/ MARK G. PAPA                                                              

Mark G. Papa

Chairman of the Board and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Timothy K. Driggers, certify that:

1.      I have reviewed this Annual Report on Form 10-K of EOG Resources, Inc.;

2.      Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.      Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.      The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.      The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 24, 2012

/s/ TIMOTHY K. DRIGGERS                                                                

Timothy K. Driggers

Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PERIODIC REPORT

I, Mark G. Papa, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that:

(1) The Annual Report on Form 10-K of the Company for the year ended December 31, 2011 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  February 24, 2012

/s/ MARK G. PAPA                                                                

Mark G. Papa

Chairman of the Board and Chief Executive Officer

(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF PERIODIC REPORT

I, Timothy K. Driggers, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that:

(1) The Annual Report on Form 10-K of the Company for the year ended December 31, 2011 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  February 24, 2012

/s/ TIMOTHY K. DRIGGERS                                                                

Timothy K. Driggers

Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-95

EXHIBIT 95

Mine Safety Disclosure Exhibit

Under the Dodd-Frank Wall Street Reform and Consumer Protection Act and the related rules promulgated thereunder by the United States Securities and Exchange Commission (SEC), each operator of a coal or other mine is required to disclose certain mine safety matters in its periodic reports filed with the SEC.

EOG has sand mining operations in Texas and Wisconsin, which support EOG's exploration operations.  EOG's sand mining operations are subject to regulation by the federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Act).  MSHA inspects mining facilities on a regular basis and issues citations and orders when it believes a violation has occurred under the Mine Act.

EOG was the operator of the following sand mining facilities during the year ended December 31, 2011:

·   Hood County Sand Pit - Hood County, TX (MSHA ID 41-04696);

·   Rawhide Sand Plant - Hood County, TX (MSHA ID 41-04777);

·   Chippewa Falls Sand Plant - Chippewa County, WI (MSHA ID 47-03624); and

·   KMM-FS Plant - Chippewa County, WI (MSHA ID 47-03598) (EOG ceased serving as the operator of this facility, effective July 18, 2011).

__________

On June 30, 2011, EOG received a citation from MSHA for a violation of a mandatory health or safety standard at its KMM-FS Plant (Chippewa County, WI) that was deemed by the MSHA inspector to be significant and substantial under Section 104 of the Mine Act.  EOG immediately remedied the violation, and the citation was terminated on the same day it was issued.  In connection with the citation, EOG was assessed and paid a $100 penalty.

__________

Except as described above, for the year ended December 31, 2011, EOG did not receive any of the following from MSHA: (i) a citation for a violation of a mandatory health or safety standard that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard under Section 104 of the Mine Act; (ii) an order issued under Section 104(b) of the Mine Act; (iii) a citation or order for unwarrantable failure to comply with mandatory health or safety standards under Section 104(d) of the Mine Act; (iv) written notice of a flagrant violation under Section 110(b)(2) of the Mine Act; (v) an imminent danger order issued under Section 107(a) of the Mine Act; (vi) any proposed assessments under the Mine Act; (vii) written notice of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under Section 104(e) of the Mine Act; or (viii) written notice of the potential to have such a pattern. Moreover, for the year ended December 31, 2011, EOG did not experience a mining-related fatality.

In addition, as of December 31, 2011, EOG did not have any legal action pending before the Federal Mine Safety and Health Review Commission (Mine Commission), and did not have any legal actions instituted or resolved before the Mine Commission during the year ended December 31, 2011.

XML

Oil and Gas Exploration and Production Industries Disclosures (Tables)

12 Months Ended

Dec. 31, 2011

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Net Proved and Proved Development Reserve Summary

The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2011, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2011, as estimated by the Engineering and Acquisitions Department of EOG:

NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY

		United			Other
		States	Canada	Trinidad	International (1)	Total
NET PROVED RESERVES
Crude Oil (MBbl) (2)
Net proved reserves at December 31, 2008		133,362	7,498	8,326	65	149,251
	Revisions of previous estimates	4,402	(183)	(1,760)	17	2,476
	Purchases in place	15,666	-	-	-	15,666
	Extensions, discoveries and other additions	58,258	19,783	-	-	78,041
	Sales in place	(5,742)	(20)	-	-	(5,762)
	Production	(17,494)	(1,492)	(1,123)	(24)	(20,133)
Net proved reserves at December 31, 2009		188,452	25,586	5,443	58	219,539
	Revisions of previous estimates	(8,313)	(104)	(754)	20	(9,151)
	Purchases in place	13	-	-	-	13
	Extensions, discoveries and other additions	199,479	3,198	1,751	48	204,476
	Sales in place	(1,082)	(589)	-	-	(1,671)
	Production	(23,092)	(2,455)	(1,709)	(28)	(27,284)
Net proved reserves at December 31, 2010		355,457	25,636	4,731	98	385,922
	Revisions of previous estimates	(21,188)	(4,611)	18	25	(25,756)
	Purchases in place	9	-	-	-	9
	Extensions, discoveries and other additions	202,552	449	-	-	203,001
	Sales in place	(4,301)	-	-	-	(4,301)
	Production	(37,233)	(2,882)	(1,242)	(25)	(41,382)
Net proved reserves at December 31, 2011		495,296	18,592	3,507	98	517,493
Natural Gas Liquids (MBbl) (2)
Net proved reserves at December 31, 2008		72,484	3,297	-	-	75,781
	Revisions of previous estimates	6,109	(926)	-	-	5,183
	Purchases in place	5,801	-	-	-	5,801
	Extensions, discoveries and other additions	18,546	24	-	-	18,570
	Sales in place	(3,231)	(30)	-	-	(3,261)
	Production	(8,220)	(393)	-	-	(8,613)
Net proved reserves at December 31, 2009		91,489	1,972	-	-	93,461
	Revisions of previous estimates	27,490	(196)	-	-	27,294
	Purchases in place	-	-	-	-	-
	Extensions, discoveries and other additions	42,221	21	-	-	42,242
	Sales in place	(2)	(6)	-	-	(8)
	Production	(10,764)	(316)	-	-	(11,080)
Net proved reserves at December 31, 2010		150,434	1,475	-	-	151,909
	Revisions of previous estimates	35,999	43	-	-	36,042
	Purchases in place	17	-	-	-	17
	Extensions, discoveries and other additions	65,288	-	-	-	65,288
	Sales in place	(10,008)	-	-	-	(10,008)
	Production	(15,144)	(316)	-	-	(15,460)
Net proved reserves at December 31, 2011		226,586	1,202	-	-	227,788

		United			Other
		States	Canada	Trinidad	International (1)	Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 2008		4,889.0	1,237.2	1,198.1	14.9	7,339.2
	Revisions of previous estimates	(378.0)	(447.2)	(104.9)	3.0	(927.1)
	Purchases in place	450.8	-	-	-	450.8
	Extensions, discoveries and other additions	1,925.0	846.5	-	-	2,771.5
	Sales in place	(114.4)	(5.1)	-	-	(119.5)
	Production	(422.3)	(81.9)	(107.4)	(5.2)	(616.8)
Net proved reserves at December 31, 2009		6,350.1	1,549.5	985.8	12.7	8,898.1
	Revisions of previous estimates	(222.7)	(29.9)	(88.6)	1.9	(339.3)
	Purchases in place	-	-	-	-	-
	Extensions, discoveries and other additions	821.3	3.4	63.0	7.9	895.6
	Sales in place	(34.6)	(316.2)	-	-	(350.8)
	Production	(422.6)	(73.0)	(132.6)	(5.2)	(633.4)
Net proved reserves at December 31, 2010		6,491.5	1,133.8	827.6	17.3	8,470.2
	Revisions of previous estimates	(344.0)	(49.8)	(24.2)	1.3	(416.7)
	Purchases in place	3.0	-	-	-	3.0
	Extensions, discoveries and other additions	634.6	-	74.7	4.5	713.8
	Sales in place	(323.6)	-	-	-	(323.6)
	Production	(415.7)	(48.1)	(127.4)	(4.6)	(595.8)
Net proved reserves at December 31, 2011		6,045.8	1,035.9	750.7	18.5	7,850.9
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2008		1,020,671	217,002	208,013	2,548	1,448,234
	Revisions of previous estimates	(52,487)	(75,638)	(19,250)	515	(146,860)
	Purchases in place	96,605	-	-	-	96,605
	Extensions, discoveries and other additions	397,642	160,882	-	-	558,524
	Sales in place	(28,032)	(898)	-	-	(28,930)
	Production	(96,107)	(15,540)	(19,016)	(891)	(131,554)
Net proved reserves at December 31, 2009		1,338,292	285,808	169,747	2,172	1,796,019
	Revisions of previous estimates	(17,945)	(5,288)	(15,513)	342	(38,404)
	Purchases in place	14	-	-	-	14
	Extensions, discoveries and other additions	378,582	3,789	12,250	1,363	395,984
	Sales in place	(6,860)	(53,288)	-	-	(60,148)
	Production	(104,277)	(14,937)	(23,815)	(901)	(143,930)
Net proved reserves at December 31, 2010		1,587,806	216,084	142,669	2,976	1,949,535
	Revisions of previous estimates	(42,526)	(12,865)	(4,011)	239	(59,163)
	Purchases in place	521	-	-	-	521
	Extensions, discoveries and other additions	373,602	448	12,455	750	387,255
	Sales in place	(68,247)	-	-	-	(68,247)
	Production	(121,648)	(11,219)	(22,484)	(787)	(156,138)
Net proved reserves at December 31, 2011		1,729,508	192,448	128,629	3,178	2,053,763

(1) Other International includes EOG's United Kingdom and China operations.

(2) Thousand barrels or thousand 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.

(3) Billion cubic feet.

		United			Other
		States	Canada	Trinidad	International (1)	Total
NET PROVED DEVELOPED RESERVES
Liquids (MBbl) (2)
	December 31, 2008	159,607	10,416	6,756	65	176,844
	December 31, 2009	189,322	10,831	3,966	58	204,177
	December 31, 2010	253,308	12,758	3,853	98	270,017
	December 31, 2011	338,144	9,220	2,657	97	350,118
Natural Gas (Bcf) (3)
	December 31, 2008	3,544.7	1,103.7	889.0	14.9	5,552.3
	December 31, 2009	3,330.1	681.0	609.4	12.7	4,633.2
	December 31, 2010	3,519.7	401.6	519.2	17.3	4,457.8
	December 31, 2011	3,234.9	295.8	606.3	18.6	4,155.6
Oil Equivalents (MBoe) (2)
	December 31, 2008	750,389	194,360	154,939	2,548	1,102,236
	December 31, 2009	744,339	124,323	105,540	2,172	976,374
	December 31, 2010	839,928	79,701	90,382	2,976	1,012,987
	December 31, 2011	877,301	58,524	103,710	3,178	1,042,713
NET PROVED UNDEVELOPED RESERVES
Liquids (MBbl) (2)
	December 31, 2008	46,239	379	1,570	-	48,188
	December 31, 2009	90,619	16,727	1,477	-	108,823
	December 31, 2010	252,583	14,352	879	-	267,814
	December 31, 2011	383,739	10,574	850	-	395,163
Natural Gas (Bcf) (3)
	December 31, 2008	1,344.3	133.6	309.0	-	1,786.9
	December 31, 2009	3,020.0	868.5	376.4	-	4,264.9
	December 31, 2010	2,971.7	732.2	308.5	-	4,012.4
	December 31, 2011	2,810.8	740.1	144.4	-	3,695.3
Oil Equivalents (MBoe) (2)
	December 31, 2008	270,282	22,642	53,074	-	345,998
	December 31, 2009	593,953	161,486	64,207	-	819,646
	December 31, 2010	747,878	136,383	52,287	-	936,548
	December 31, 2011	852,207	133,924	24,919	-	1,011,050

(1) Other International includes EOG's United Kingdom and China operations.

(2) Thousand barrels or thousand 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.

(3) Billion cubic feet.

Capitalized Costs Relating to Oil an d Gas Producing Activities

The following table sets forth the capitalized costs relating to EOG's crude oil and natural gas producing activities at December 31, 2011 and 2010:

	2011			2010
Proved properties	$	32,353,380		$	27,693,700
Unproved properties		1,311,055			1,570,109
Total		33,664,435			29,263,809
Accumulated depreciation, depletion and amortization		(13,981,143	)		(11,859,870	)
Net capitalized costs	$	19,683,292		$	17,403,939

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2011, 2010 and 2009:

	United							Other
	States		Canada			Trinidad		International (1)			Total
2011
Acquisition Costs of Properties
Unproved	$	295,160	$	6,216		$	-	$	(604	)	$	300,772
Proved		4,219		28			-		-			4,247
Subtotal		299,379		6,244			-		(604	)		305,019
Exploration Costs		311,369		31,472			2,549		18,164			363,554
Development Costs (2)		5,410,378		302,564			138,905		78,744			5,930,591
Total	$	6,021,126	$	340,280		$	141,454	$	96,304		$	6,599,164
2010
Acquisition Costs of Properties
Unproved	$	403,509	$	13,956		$	-	$	(107	)	$	417,358
Proved		-		-			-		-			-
Subtotal		403,509		13,956			-		(107	)		417,358
Exploration Costs		454,379		38,604			23,386		86,784			603,153
Development Costs (3)		3,892,403		417,176			114,986		13,429			4,437,994
Total	$	4,750,291	$	469,736		$	138,372	$	100,106		$	5,458,505
2009
Acquisition Costs of Properties
Unproved	$	648,331	$	17,806		$	800	$	(311	)	$	666,626
Proved (4)		464,362		(33	)		-		-			464,329
Subtotal		1,112,693		17,773			800		(311	)		1,130,955
Exploration Costs		473,489		51,164			14,263		71,872			610,788
Development Costs (5)		1,898,859		237,613			27,369		1,914			2,165,755
Total	$	3,485,041	$	306,550		$	42,432	$	73,475		$	3,907,498

(1) Other International primarily consists of EOG's United Kingdom and China operations.

(2) Includes Asset Retirement Costs of $52 million, $70 million, $7 million and $4 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

(3) Includes Asset Retirement Costs of $71 million, $2 million, $(3) million and $2 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

(4) Includes non-cash acquisition costs of $353 million related to a property exchange transaction in the Rocky Mountain area.

(5) Includes Asset Retirement Costs of $60 million, $18 million, $6 million and zero for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

Results of Operations for Oil and Gas Producing Activities

The following tables set forth results of operations for oil and gas producing activities for the years ended December 31, 2011, 2010 and 2009:

	United							Other
	States		Canada			Trinidad		International (2)			Total
2011
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	5,814,942	$	459,852		$	555,143	$	28,251		$	6,858,188
Other		32,329		258			586		-			33,173
Total		5,847,271		460,110			555,729		28,251			6,891,361
Exploration Costs		148,199		10,479			2,520		10,460			171,658
Dry Hole Costs		30,521		432			-		22,277			53,230
Transportation Costs		421,060		5,969			1,620		1,673			430,322
Production Costs		1,096,955		174,973			49,318		10,964			1,332,210
Impairments		575,976		452,103			-		2,958			1,031,037
Depreciation, Depletion and Amortization		2,011,080		258,772			106,802		17,160			2,393,814
Income (Loss) Before Income Taxes		1,563,480		(442,618	)		395,469		(37,241	)		1,479,090
Income Tax Provision (Benefit)		569,153		(121,044	)		202,815		(13,056	)		637,868
Results of Operations	$	994,327	$	(321,574	)	$	192,654	$	(24,185	)	$	841,222
2010
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	3,928,240	$	477,416		$	447,852	$	27,707		$	4,881,215
Other		19,886		(31	)		3,696		-			23,551
Total		3,948,126		477,385			451,548		27,707			4,904,766
Exploration Costs		156,252		17,597			2,277		11,255			187,381
Dry Hole Costs		30,927		14,875			5,000		21,684			72,486
Transportation Costs		372,466		9,892			1,348		1,483			385,189
Production Costs		763,769		174,667			51,125		8,504			998,065
Impairments		271,466		451,703			1,465		418			725,052
Depreciation, Depletion and Amortization		1,430,408		314,663			70,553		15,399			1,831,023
Income (Loss) Before Income Taxes		922,838		(506,012	)		319,780		(31,036	)		705,570
Income Tax Provision (Benefit)		375,855		(151,315	)		140,413		(14,245	)		350,708
Results of Operations	$	546,983	$	(354,697	)	$	179,367	$	(16,791	)	$	354,862
2009
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	2,732,088	$	413,910		$	229,649	$	23,826		$	3,399,473
Other		9,692		(15	)		3,500		-			13,177
Total		2,741,780		413,895			233,149		23,826			3,412,650
Exploration Costs		137,696		18,675			5,107		8,114			169,592
Dry Hole Costs		39,570		1,461			-		10,212			51,243
Transportation Costs		270,940		9,317			1,141		1,931			283,329
Production Costs		556,236		145,292			27,616		9,452			738,596
Impairments		272,195		32,996			-		641			305,832
Depreciation, Depletion and Amortization		1,188,243		210,509			46,608		7,966			1,453,326
Income (Loss) Before Income Taxes		276,900		(4,355	)		152,677		(14,490	)		410,732
Income Tax Provision (Benefit)		106,537		(1,276	)		58,681		(6,067	)		157,875
Results of Operations	$	170,363	$	(3,079	)	$	93,996	$	(8,423	)	$	252,857

(1) Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2011.

(2) Other International primarily consists of EOG's United Kingdom and China operations.

Production Costs Per Barrel of Oil Equivalent

The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2011, 2010 and 2009:

	United						Other
	States		Canada		Trinidad		International (1)		Composite
Year Ended December 31, 2011	$	6.19	$	14.26	$	0.78	$	13.82	$	6.03
Year Ended December 31, 2010	$	5.00	$	10.28	$	0.65	$	9.34	$	4.85
Year Ended December 31, 2009	$	4.43	$	8.41	$	0.74	$	10.52	$	4.40

(1)      Other International primarily consists of EOG's United Kingdom and China operations.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2011, 2010 and 2009:

	United									Other
	States			Canada			Trinidad			International (1)			Total
2011
Future cash inflows (2)	$	84,518,638		$	5,056,501		$	2,851,545		$	103,853		$	92,530,537
Future production costs		(33,294,343	)		(2,315,110	)		(388,199	)		(62,938	)		(36,060,590	)
Future development costs		(13,811,449	)		(1,566,917	)		(149,884	)		(331	)		(15,528,581	)
Future income taxes		(10,539,182	)		(81,590	)		(794,856	)		(2,457	)		(11,418,085	)
Future net cash flows		26,873,664			1,092,884			1,518,606			38,127			29,523,281
Discount to present value at 10% annual rate		(12,498,010	)		(456,537	)		(334,399	)		(9,054	)		(13,298,000	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	14,375,654		$	636,347		$	1,184,207		$	29,073		$	16,225,281
2010
Future cash inflows (3)	$	62,063,123		$	6,040,422		$	2,760,819		$	91,805		$	70,956,169
Future production costs		(22,616,039	)		(2,711,415	)		(384,147	)		(48,953	)		(25,760,554	)
Future development costs		(9,596,005	)		(1,716,734	)		(198,072	)		(334	)		(11,511,145	)
Future income taxes		(8,503,301	)		(129,816	)		(850,699	)		(3,598	)		(9,487,414	)
Future net cash flows		21,347,778			1,482,457			1,327,901			38,920			24,197,056
Discount to present value at 10% annual rate		(10,718,854	)		(736,222	)		(339,035	)		(11,121	)		(11,805,232	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	10,628,924		$	746,235		$	988,866		$	27,799		$	12,391,824
2009
Future cash inflows (4)	$	34,506,336		$	6,887,530		$	2,133,778		$	52,738		$	43,580,382
Future production costs		(11,977,152	)		(2,537,001	)		(398,318	)		(27,791	)		(14,940,262	)
Future development costs		(5,696,619	)		(2,255,088	)		(264,104	)		(346	)		(8,216,157	)
Future income taxes		(5,307,041	)		(249,986	)		(525,873	)		(4,276	)		(6,087,176	)
Future net cash flows		11,525,524			1,845,455			945,483			20,325			14,336,787
Discount to present value at 10% annual rate		(5,702,608	)		(808,211	)		(279,920	)		(5,030	)		(6,795,769	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	5,822,916		$	1,037,244		$	665,563		$	15,295		$	7,541,018

(1) Other International includes EOG's United Kingdom and China operations.

(2) Estimated crude oil prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $97.75, $90.70, $92.50 and $102.86, respectively.  Estimated natural gas liquids prices used to calculate 2011 future cash inflows for the United States and Canada were $51.77  and $46.97, respectively.  Estimated natural gas prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $4.03, $3.28, $3.37, and $5.07, respectively.

(3) Estimated crude oil prices used to calculate 2010 future cash inflows for the United States, Canada, Trinidad and Other International were $76.38, $72.59, $69.56 and $73.88, respectively.  Estimated natural gas liquids prices used to calculate 2010 future cash inflows for the United States and Canada were $43.85 and $26.56, respectively.  Estimated natural gas prices used to calculate 2010 future cash inflows for the United States, Canada, Trinidad and Other International were $4.36, $3.67, $2.94 and $5.02, respectively.

(4) Estimated crude oil prices used to calculate 2009 future cash inflows for the United States, Canada, Trinidad and Other International were $53.64, $56.85, $51.35 and $52.87, respectively.  Estimated natural gas liquids prices used to calculate 2009 future cash inflows for the United States and Canada were $28.75 and $19.31, respectively.  Estimated natural gas prices used to calculate 2009 future cash inflows for the United States, Canada, Trinidad and Other International were $3.43, $3.50, $1.88 and $3.92, respectively.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2011:

	United									Other
	States			Canada			Trinidad			International			Total
December 31, 2008	$	6,307,712		$	1,751,152		$	601,053		$	19,984		$	8,679,901
Sales and transfers of oil and gas produced, net of production costs		(1,904,912	)		(259,301	)		(200,892	)		(12,443	)		(2,377,548	)
Net changes in prices and production costs		(1,482,778	)		(902,629	)		338,053			(13,868	)		(2,061,222	)
Extensions, discoveries, additions and improved recovery, net of related costs		1,702,471			259,305			-			-			1,961,776
Development costs incurred		344,500			14,200			-			-			358,700
Revisions of estimated
development cost		595,875			68,883			(3,380	)		4,555			665,933
Revisions of previous quantity estimates		(422,294	)		(425,018	)		(124,222	)		1,016			(970,518	)
Accretion of discount		829,631			199,330			84,521			3,232			1,116,714
Net change in income taxes		261,513			259,169			(105,766	)		9,847			424,763
Purchases of reserves in place		209,130			-			-			-			209,130
Sales of reserves in place		(264,482	)		(13,912	)		-			-			(278,394	)
Changes in timing and other		(353,450	)		86,065			76,196			2,972			(188,217	)
December 31, 2009		5,822,916			1,037,244			665,563			15,295			7,541,018
Sales and transfers of oil and gas produced, net of production costs		(2,792,005	)		(292,857	)		(395,379	)		(17,720	)		(3,497,961	)
Net changes in prices and production costs		2,468,907			(559	)		721,796			7,259			3,197,403
Extensions, discoveries, additions and improved recovery, net of related costs		4,319,659			75,162			183,453			-			4,578,274
Development costs incurred		864,700			175,100			67,300			-			1,107,100
Revisions of estimated development cost		(257,360	)		260,290			(767	)		9			2,172
Revisions of previous quantity estimates		(164,748	)		(38,382	)		(175,002	)		4,006			(374,126	)
Accretion of discount		755,001			102,022			101,549			1,778			960,350
Net change in income taxes		(1,171,384	)		101,966			(258,354	)		2,469			(1,325,303	)
Purchases of reserves in place		265			-			-			-			265
Sales of reserves in place		(54,057	)		(290,592	)		-			-			(344,649	)
Changes in timing and other		837,030			(383,159	)		78,707			14,703			547,281
December 31, 2010		10,628,924			746,235			988,866			27,799			12,391,824
Sales and transfers of oil and gas produced, net of production costs		(4,296,926	)		(278,910	)		(504,205	)		(15,614	)		(5,095,655	)
Net changes in prices and production costs		716,682			(57,545	)		331,196			3,328			993,661
Extensions, discoveries, additions and improved recovery, net of related costs		6,223,552			22,591			102,548			-			6,348,691
Development costs incurred		1,422,500			48,200			74,800			-			1,545,500
Revisions of estimated development cost		(210,919	)		64,001			(14,074	)		2			(160,990	)
Revisions of previous quantity estimates		(482,496	)		(70,718	)		(56,884	)		801			(609,297	)
Accretion of discount		1,352,740			62,725			159,715			2,782			1,577,962
Net change in income taxes		(1,049,641	)		(118,988	)		9,511			13			(1,159,105	)
Purchases of reserves in place		5,241			-			-			-			5,241
Sales of reserves in place		(658,468	)		-			-			-			(658,468	)
Changes in timing and other		724,465			218,756			92,734			9,962			1,045,917
December 31, 2011	$	14,375,654		$	636,347		$	1,184,207		$	29,073		$	16,225,281

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Exploratory Well Costs (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Notes To Financial Statements [Abstract]
Balance at January 1	$ 99,801,000	$ 118,459,000	$ 85,255,000
Additions Pending the Determination of Proved Reserves	31,271,000	94,090,000	75,362,000
Reclassifications to Proved Properties	(29,227,000)	(93,333,000)	(40,614,000)
Charged to Dry Hole Costs	(42,178,000)	(20,267,000)	(11,223,000)
Foreign Currency Translations	1,444,000	852,000	9,679,000
Balance at December 31	61,111,000	99,801,000	118,459,000
Capitalized exploratory well costs that have been capitalized for a period less than one year	17,009,000	43,408,000	51,141,000
Capitalized exploratory well costs that have been capitalized for a period greater than one year	44,102,000	56,393,000	67,318,000
Number of suspended wells that have been capitalized for a period greater than one year	4	4	4
Number of suspended wells related to an outside operated, offshore Central North Sea project in the United Kingdom	1	1	1
Number of suspended wells related to an East Irish Sea Project in the United Kingdom	1	1
Number of suspended wells related to a project in the Sichuan Basin, China	1	1
Number of suspended wells related to shale projects in British Columbia	1	1	3
Suspended well costs related to an outside operated, offshore Central North Sea project in the United Kingdom	20,000,000	21,000,000	22,000,000
Suspended well costs related to an East Irish Sea project in the United Kingdom	9,000,000	9,000,000
Suspended well costs related to a project in the Sichuan Basin, Sichuan Province, China	9,000,000	20,000,000
Suspended well costs related to shale projects in British Columbia	$ 6,000,000	$ 6,000,000	$ 45,000,000

XML

Supplemental Cash Flow Information (Details) (USD $) Share data in Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Notes To Financial Statements [Abstract]
Interest, Net of Capitalized Interest	$ 186,718,000	$ 146,731,000	$ 100,939,000
Income Taxes, Net of Refunds Received	260,224,000	233,462,000	51,684,000
Cash Flow, Non-cash Investing and Financing Activities Disclosure
Issuance of shares of EOG common stock in connection with the purchase of reserves and acreage (shares in thousands)			1,450
Value of EOG common stock issued in connection with the purchase of reserves and acreage			90,000,000
Non-cash additions to oil and gas properties in connection with contingent consideration			353,000,000
Accrued Capital Expenditures	$ 663,000,000	$ 709,000,000	$ 334,000,000

XML

Property Acquisitions and Divestitures (Details) (USD $)	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010
Notes To Financial Statements [Abstract]
Estimated Proceeds from Sales of Producing Properties and Acreage on Certain Midstream Assets		$ 1,400,000,000
Proceeds received on sale of Canadian shallow gas assets			344,000,000
Impairment recorded to adjust Canadian shallow gas assets to fair value, less cost to sell			280,000,000
Aggregate proceeds received on sales non-core producing properties and acreage			673,000,000
Interest in planned liquefied natural gas plant (in hundredths)			49.00%
Percentage of planned natural gas pipeline owned by operator (in hundredths)			51.00%
Percentage of planned LNG export terminal owned by operator (in hundredths)			25.50%
Purchase price to acquire common stock of Galveston LNG			210,000,000
Additional interest acquired in planned natural gas pipeline (in hundredths)			24.50%
Purchase price to acquire additional interest in planned natural gas pipeline		25,200,000
Portion of purchase price to acquire additional interest in planned natural gas pipeline paid at closing		15,300,000
Interest in planned natural gas pipeline after acquisition of additional ownership interest in first quarter of 2011 (in hundredths)		24.50%
Pretax gain realized on a natural gas property exchange	390,000,000
Consideration received for sale of California crude oil and natural gas related assets	202,000,000
Pretax gain recognized from sale of California assets	146,000,000
Haynesville asset acquisition total consideration recorded	134,000,000		18,000,000
Barnett Shale Combo Aggregate Purchase Price	197,000,000
Barnett Shale Combo cash consideration paid	107,000,000
Shares exchanged for Barnett Shale Combo purchase	1,450,000
Common stock exchanged for Barnett Shale Combo purchase on the closing date	$ 89,600,000
Operator Ownership Interest in Proposed LNG Terminal and Pipeline Project Subsequent to Sell-Down		40.00%
Company's Interest in Propesed LNG Terminal and Pipeline Subsequent to Sell-down		30.00%
Interest in LNG Terminal and Pipeline Project Acquired by Third-party-in Sell-down Transactions		30.00%

XML

Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Notes To Financial Statements [Abstract]
Standby letters of credit and guarantees outstanding	$ 585,000,000	$ 657,000,000
Subsidiary indebtedness guaranteed	150,000,000	370,000,000
Subsidiary payment obligations guaranteed	435,000,000	287,000,000
Total Minimum Commitments [Abstract]
2012	1,185,759,000
2013 - 2014	1,013,735,000
2015 - 2016	925,514,000
2017 and beyond	1,435,506,000
Total Minimum Commitments	4,560,514,000
Rental expenses associated with existing leases	$ 149,000,000	$ 95,000,000	$ 77,000,000

XML

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Net Cash Paid For Interest and Income Taxes Table

Net cash paid for interest and income taxes was as follows for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	2011		2010		2009
Interest, Net of Capitalized Interest	$	186,718	$	146,731	$	100,939
Income Taxes, Net of Refunds Received	$	260,224	$	233,462	$	51,684

XML

Oil and Gas Exploration and Production Industries Disclosures, Costs Incurred (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
United States [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Proved	$ 4,219,000	$ 0	$ 464,362,000
Acquisition Costs of Properties - Unproved	295,160,000	403,509,000	648,331,000
Exploration Costs	311,369,000	454,379,000	473,489,000
Development Costs	5,410,378,000	3,892,403,000	1,898,859,000
Total	6,021,126,000	4,750,291,000	3,485,041,000
Asset Retirement Costs Included In Development	52,000,000	71,000,000	60,000,000
Noncash acquisition costs			353,000,000
Canada [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Proved	28,000	0	(33,000)
Acquisition Costs of Properties - Unproved	6,216,000	13,956,000	17,806,000
Exploration Costs	31,472,000	38,604,000	51,164,000
Development Costs	302,564,000	417,176,000	237,613,000
Total	340,280,000	469,736,000	306,550,000
Asset Retirement Costs Included In Development	70,000,000	2,000,000	18,000,000
Trinidad [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Proved	0	0	0
Acquisition Costs of Properties - Unproved	0	0	800,000
Exploration Costs	2,549,000	23,386,000	14,263,000
Development Costs	138,905,000	114,986,000	27,369,000
Total	141,454,000	138,372,000	42,432,000
Asset Retirement Costs Included In Development	7,000,000	(3,000,000)	6,000,000
Other International [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Proved	0	0	0
Acquisition Costs of Properties - Unproved	(604,000)	(107,000)	(311,000)
Exploration Costs	18,164,000	86,784,000	71,872,000
Development Costs	78,744,000	13,429,000	1,914,000
Total	96,304,000	100,106,000	73,475,000
Asset Retirement Costs Included In Development	$ 4,000,000	$ 2,000,000	$ 0

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Schedule II - Valuation and Qualiying Accounts

12 Months Ended

Dec. 31, 2011

Schedule II - Valuation and Qualifying Accounts [Abstract]

Schedule Of Valuation And Qualifying Accounts Disclosure [Text Block]

Schedule II

EOG RESOURCES, INC.

VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2011, 2010 and 2009

(In Thousands)

Column A	Column B		Column C		Column D			Column E
			Additions
	Balance at		Charged to		Deductions			Balance at
	Beginning of		Costs and		From			End of
Description	Year		Expenses		Reserves			Year
2011
Allowance deducted from Accounts Receivable	$	13,642	$	778	$	11,711	(1)	$	2,709
2010
Allowance deducted from Accounts Receivable	$	13,228	$	885	$	471		$	13,642
2009
Allowance deducted from Accounts Receivable	$	13,131	$	145	$	48		$	13,228

(1)   Primarily reflects amounts related to bankruptcies which occurred in December 2001.

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Risk Management Activities (Details) (USD $)	12 Months Ended							12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Crude Oil and Natural Gas Derivative Contracts [Member]	Dec. 31, 2010 Crude Oil and Natural Gas Derivative Contracts [Member]	Dec. 31, 2011 Foreign Currency Swap [Member]	Dec. 31, 2010 Foreign Currency Swap [Member]	Dec. 31, 2012 Natural Gas Derivative Contracts January [Member]	Dec. 31, 2012 Natural Gas Derivative Contracts - February - December [Member]	Dec. 31, 2014 Natural Gas Derivative Contracts January - December [Member]	Dec. 31, 2013 Natural Gas Derivative Contracts January - December [Member]	Dec. 31, 2012 Crude Oil Derivative Contracts January - June [Member]	Dec. 31, 2012 Crude Oil Dervative Contracts July - December [Member]
Notes To Financial Statements [Abstract]
Gains on Mark-to-Market Commodity Derivative Contracts	$ (626,053,000)	$ (61,912,000)	$ (431,757,000)
Realized Gains (Losses)	180,701,000	7,033,000	1,277,584,000
Assets from Price Risk Management Activities	450,730,000	48,153,000		451,000,000	51,000,000
Liabilities from Price Risk Management Activities	0	28,339,000		0	30,000,000
Other Assets	35,000,000	20,000,000
Other Liabilities		1,000,000
Derivative [Line Items]
Volume (MMBtud)								525000	525000	150000	150000
Volume (Bbld)												34000	17000
Volumes (MMBtud) - Derivative Contracts									425,000	150,000	150,000
Average Price ($/MMBtu) - Derivative Contracts									5.44	4.79	4.79
Weighted Average Price ($/Bbl)												104.95	103.59
Derivative Weighted Average Price Natural Gas ($/MMBtu)								5.44	5.44	4.79	4.79
Principal amount of notes issued by Canadian subsidiary, whose exchange rate is hedged by foreign currency swap transaction	150,000,000
Volumes (Bbld) - Derivative Contacts													17,000
Average Price ($/Bbl) - Derivative Contracts													106.31
Derivatives, Fair Value [Line Items]
Derivatives Assets, Current	450,730,000	48,153,000		451,000,000	51,000,000
Other Assets	0	2,000,000		35,000,000	18,000,000
Derivative Liabilities, Current	0	28,339,000		0	30,000,000
Other Liabilities	3,000,000	0				53,000,000	55,000,000
Receivable Major Customer Percentage	10.00%	13.00%
Interest Rate Cash Flow Hedges [Abstract]
Interest Rate Swap, Notional Amount	350,000,000
Interest Rate Swap, at Fair Value	(3,000,000)	2,000,000
After-tax net impact from interest rate swap	(3,000,000)	1,000,000
Fair Value Of The Foreign Currency Swap	(52,000,000)	(55,000,000)
After-Tax Impact Other Comprehensive Income Increase (Decrease) From The Foreign Currency Swap Transaction	$ (1,000,000)	$ 3,000,000	$ 5,000,000

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Stockholder's Equity (Details) (USD $)	2 Months Ended	1 Months Ended		12 Months Ended
	Feb. 16, 2012	Feb. 11, 2011	Feb. 09, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Notes To Financial Statements [Abstract]
An aggregate maximum of shares of common stock authorized for repurchase				10,000,000
Remaining shares available for purchase under share repurchase authorization				6,386,200
Dividends Common Stock Cash	$ 0.17	$ 0.16	$ 0.155
Common Stock Dividends Declared				$ 0.64	$ 0.62	$ 0.58
Common Stock Issued Under Equity Compensation Plans				1,395,000	1,482,000	1,347,000
Treasury Stock Purchased				(267,000)	(115,000)	(168,000)
Common Stock Issued Under Employee Stock Purchase Plan				135,000	114,000	71,000
Treasury Stock Issued Under Other Equity Compensation Plans				109,000	87,000	177,000
Common Stock Sold				13,570,000
Common Shares Issued During Period				269,323,084	254,223,521	252,627,000	249,759,000
Common Stock Issued for Property Acquisition						1,450,000
Treasury Shares Outstanding				303,633	146,186	(118,000)	(127,000)
Common Shares Outstanding				269,019,000	254,077,000	252,509,000	249,632,000
Series E Junior Participating Preferred Stock (Series E)				1,500,000
Series E Junior Participating Preferred Stock (Series E), total following two-for-one stock split				3,000,000
Common Stock Activity [Abstract]
Shares of Common Stock Sold				13,570,000
Public Offering Price of Common Stock Sold				$ 105.50
Common Stock, Par (in dollars per share)				$ 0.01	$ 0.01
Proceeds From Issuance Or Sale Of Equity				$ 1,388,265,000	$ 0	$ 0

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Asset Retirement Obligation Roll Forward Analysis Table

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2011 and 2010 (in thousands):

	2011			2010
Carrying Amount at Beginning of Period	$	498,288		$	456,484
Liabilities Incurred		68,703			39,480
Liabilities Settled (1)		(66,129	)		(30,763	)
Accretion		27,907			25,456
Revisions		58,786			1,640
Foreign Currency Translations		(471	)		5,991
Carrying Amount at End of Period	$	587,084		$	498,288
Current Portion	$	29,527		$	32,005
Noncurrent Portion	$	557,557		$	466,283

(1)      Includes settlements related to asset sales.

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Accounting For Certain Long-Lived Assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Amortization of unproved oil and gas property costs, including capitalized interest	$ 197	$ 217	$ 212
United States [Member]
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Pretax impairment charges on proved oil and gas properties and other property, plant and equipment	403	107	90
Canada [Member]
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Pretax impairment charges on proved oil and gas properties and other property, plant and equipment	428	418	4
Trinidad [Member]
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Pretax impairment charges on proved oil and gas properties and other property, plant and equipment		1
Other International [Member]
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Pretax impairment charges on proved oil and gas properties and other property, plant and equipment	$ 3

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Schedule II - Valuation and Qualifying Accounts (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Year	$ 13,642	$ 13,228	$ 13,131
Additions Charged to Costs and Expenses	778	885	145
Deductions From Reserves	11,711	471	48
Balance at End of Year	$ 2,709	$ 13,642	$ 13,228

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Net Income Per Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Numerator for Basic and Diluted Earnings per Share - [Abstract]
Net Income	$ 1,091,123	$ 160,654	$ 546,627
Denominator for Basic Earnings per Share - [Abstract]
Weighted Average Shares	262,735,000	250,876,000	248,996,000
Potential Dilutive Common Shares -[Abstract]
Stock Options/SARs	1,707,000	1,991,000	1,691,000
Restricted Stock and Restricted Stock Units	1,826,000	1,633,000	1,197,000
Denominator for Diluted Earnings per Share - [Abstract]
Adjusted Diluted Weighted Average Shares	266,268,000	254,500,000	251,884,000
Net Income Per Share Available to Common Stockholders [Abstract]
Basic	$ 4.15	$ 0.64	$ 2.20
Diluted	$ 4.10	$ 0.63	$ 2.17
Antidilutive Stock Options and SARs excluded from Diluted Earnings Per Share Calculation	400,000	300,000	2,500,000

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Long-Term Debt

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Long-Term Debt [Text Block]

2.  Long-Term Debt

Long-Term Debt at December 31, 2011 and 2010 consisted of the following (in thousands):

		2011		2010
6.125% Senior Notes due 2013		$	400,000	$	400,000
Floating Rate Senior Notes due 2014			350,000		350,000
2.95% Senior Notes due 2015			500,000		500,000
2.500% Senior Notes due 2016			400,000		400,000
5.875% Senior Notes due 2017			600,000		600,000
6.875% Senior Notes due 2018			350,000		350,000
5.625% Senior Notes due 2019			900,000		900,000
4.40% Senior Notes due 2020			500,000		500,000
4.100% Senior Notes due 2021			750,000		750,000
6.65% Senior Notes due 2028			140,000		140,000
7.00% Subsidiary Debt due 2011			-		220,000
4.75% Subsidiary Debt due 2014			150,000		150,000
Total Long-Term Debt			5,040,000		5,260,000
Less:	Current Portion of Long-Term Debt		-		220,000
	Unamortized Debt Discount		30,834		36,659
Total Long-Term Debt, Net		$	5,009,166	$	5,003,341

At December 31, 2011, the aggregate annual maturities of long-term debt were zero in 2012, $400 million in 2013, $500 million in 2014, $500 million in 2015 and $400 million in 2016.  On December 1, 2011, a wholly-owned subsidiary of EOG repaid at maturity $220 million principal amount of 7% notes, plus accrued and unpaid interest.  All subsidiary debt is guaranteed by EOG.

During 2011 and 2010, EOG utilized commercial paper and short-term borrowings under uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes.  EOG had no outstanding borrowings from commercial paper or under uncommitted credit facilities at December 31, 2011.  The average borrowings outstanding under the commercial paper program and uncommitted credit facilities were $3 million and zero, respectively, during the year ended December 31, 2011.  The weighted average interest rates for commercial paper borrowings for 2011 was 0.34%.

On October 11, 2011, EOG entered into a $2.0 billion senior unsecured Revolving Credit Agreement (2011 Facility) among EOG, JPMorgan Chase Bank, N.A., as Administrative Agent, the financial institutions as bank parties thereto (Banks) and the other parties thereto.  The 2011 Facility replaces EOG's $1.0 billion senior unsecured Revolving Credit Agreement, dated as of June 28, 2005, which had a scheduled maturity date of June 28, 2012 (2005 Facility), and EOG's $1.0 billion senior unsecured Revolving Credit Agreement, dated as of September 10, 2010, which had a scheduled maturity date of September 10, 2013 (2010 Facility).  There were no borrowings outstanding under either the 2005 Facility or the 2010 Facility as of the closing of the 2011 Facility and the termination of the 2005 Facility and the 2010 Facility.  The 2011 Facility has a scheduled maturity date of October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the Banks holding greater than 50% of the commitments then outstanding under the 2011 Facility.  The 2011 Facility commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions.  Advances under the 2011 Facility will accrue interest based, at EOG's option, on either the London InterBank Offering Rate (LIBOR) plus an applicable margin (Eurodollar rate), or the base rate (as defined in the 2011 Facility) plus an applicable margin.  The applicable margin used in connection with interest rates and fees will be based on EOG's credit rating at the applicable time.  At December 31, 2011, there were no borrowings or letters of credit outstanding under the 2011 Facility.  The Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2011 Facility, would have been 1.17% and 3.25%, respectively.

The 2011 Facility contains representations, warranties, covenants and events of default that are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a total debt-to-total capitalization ratio of no greater than 65%.  At December 31, 2011 and during the year then ended, EOG believes that it was in compliance with this financial debt covenant.

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.  Interest on the Floating Rate Notes is payable quarterly and is based on 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% (see Note 11).

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.  Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes, including the repayment of outstanding commercial paper borrowings.

On May 12, 2010, EOG Resources Trinidad Limited, a wholly owned foreign subsidiary of EOG, repaid at maturity the remaining $37 million outstanding balance of its $75 million Revolving Credit Agreement, thereby canceling this agreement.  The weighted average interest rate for the amount outstanding during the year ended December 31, 2010 was 2.74%.

The 2.95% Senior Notes due 2015, the 2016 Notes, the 4.40% Senior Notes due 2020 and the 2021 Notes were issued through public offerings and have effective interest rates of 3.148%, 2.698%, 4.565%, and 4.276%, respectively.

EOG Resources Canada Inc., a wholly-owned subsidiary of EOG, has outstanding notes with an aggregate principal amount of $150 million, an interest rate of 4.75% and a maturity date of March 15, 2014.  In conjunction with the offering, EOG entered into a foreign currency swap transaction with multiple banks for the equivalent amount of the notes and related interest, which has in effect converted this indebtedness into $201.3 million Canadian dollars with a 5.275% interest rate.  EOG accounts for the foreign currency swap transaction using the hedge accounting method (see Note 11).

Fair Value of Debt.  At December 31, 2011 and 2010, EOG had outstanding $5,040 million and $5,260 million, respectively, aggregate principal amount of debt, which had estimated fair values of approximately $5,657 million and $5,602 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.

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Other Income, Net (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Component of Other Income, Nonoperating [Line Items]
Other Income, Net	$ 6,853	$ 14,243	$ 2,071
Equity income from investments [Member]
Component of Other Income, Nonoperating [Line Items]
Other Income, Net	17,000	13,000
Foreign Currency Gain (Loss) [Member]
Component of Other Income, Nonoperating [Line Items]
Other Income, Net		4,000
Gain Loss On Sale Of Other Assets [Member]
Component of Other Income, Nonoperating [Line Items]
Other Income, Net	(5,000)
Sales of Warehouse Stock Gains (Losses) [Member]
Component of Other Income, Nonoperating [Line Items]
Other Income, Net	$ (5,000)	$ (4,000)

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Deferred Income Tax Liabilities, Net Table

The principal components of EOG's net deferred income tax liabilities at December 31, 2011 and 2010 were as follows (in thousands):

	2011			2010
Current Deferred Income Tax Assets (Liabilities)
Commodity Hedging Contracts	$	-		$	(7,141	)
Deferred Compensation Plans		-			13,216
Other		-			3,185
Total Net Current Deferred Income Tax Assets	$	-		$	9,260
Noncurrent Deferred Income Tax Assets (Liabilities)
United Kingdom Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	(57,850	)	$	(16,611	)
United Kingdom Net Operating Loss		62,477			17,329
United Kingdom Other		314			226
Total Net Noncurrent Deferred Income Tax Assets	$	4,941		$	944
Current Deferred Income Tax (Assets) Liabilities
Commodity Hedging Contracts	$	158,302		$	-
Deferred Compensation Plans		(28,346	)		-
Timing Differences Associated with Different Year-ends in Foreign Jurisdictions		6,251			41,027
Other		(218	)		676
Total Net Current Deferred Income Tax Liabilities	$	135,989		$	41,703
Noncurrent Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,485,435		$	4,373,110
Non-Producing Leasehold Costs		(66,926	)		(78,846	)
Seismic Costs Capitalized for Tax		(111,862	)		(92,901	)
Equity Awards		(120,852	)		(99,447	)
Capitalized Interest		106,265			94,957
Net Operating Loss		(1,152,386	)		(498,893	)
Alternative Minimum Tax Credit Carryforward		(298,350	)		(214,873	)
Other		25,894			18,599
Total Net Noncurrent Deferred Income Tax Liabilities	$	3,867,219		$	3,501,706
Total Net Deferred Income Tax Liabilities	$	3,998,267		$	3,533,205

Components Of Income Before Income Taxes Table

The components of Income Before Income Taxes for the years indicated below were as follows (in thousands):

	2011			2010			2009
United States	$	2,156,147		$	646,495		$	784,248
Foreign		(246,348	)		(238,519	)		87,763
Total	$	1,909,799		$	407,976		$	872,011

Components of Income Tax Provision Table

The principal components of EOG's Income Tax Provision for the years indicated below were as follows (in thousands):

	2011			2010			2009
Current:
Federal	$	94,244		$	17,154		$	95,194
State		1,083			(1,642	)		8,783
Foreign		224,049			155,565			47,015
Total		319,376			171,077			150,992
Deferred:
Federal		608,181			190,602			166,045
State		40,321			60,619			31,580
Foreign		(149,202	)		(174,976	)		(23,233	)
Total		499,300			76,245			174,392
Income Tax Provision	$	818,676		$	247,322		$	325,384

Tax Rate Reconciliation Table

The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows:

		2011	2010	2009
Statutory Federal Income Tax Rate		35.00%	35.00%	35.00%
State Income Tax, Net of Federal Benefit		1.41	9.39	3.00
Income Tax Provision Related to Foreign Operations		0.88	(0.03)	(1.40)
Income Tax Provision Related to Trinidad Operations		3.37	6.26	0.60
Canadian Shallow Natural Gas Impairments		1.85	9.49	-
Other		0.36	0.51	0.11
	Effective Income Tax Rate	42.87%	60.62%	37.31%

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Stockholder's Equity (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Common stock activity

The following summarizes Common Stock activity for each of the years ended December 31, 2009, 2010 and 2011 (in thousands):

		Common Shares
		Issued	Treasury	Outstanding
Balance at December 31, 2008		249,759	(127)	249,632
	Common Stock Issued Under Equity Compensation Plans	1,347	-	1,347
	Treasury Stock Purchased (1)	-	(168)	(168)
	Common Stock Issued Under Employee Stock Purchase Plan	71	-	71
	Treasury Stock Issued Under Other Equity Compensation Plans	-	177	177
	Common Stock Issued for Property Acquisition	1,450	-	1,450
Balance at December 31, 2009		252,627	(118)	252,509
	Common Stock Issued Under Equity Compensation Plans	1,482	-	1,482
	Treasury Stock Purchased (1)	-	(115)	(115)
	Common Stock Issued Under Employee Stock Purchase Plan	114	-	114
	Treasury Stock Issued Under Other Equity Compensation Plans	-	87	87
Balance at December 31, 2010		254,223	(146)	254,077
	Common Stock Issued Under Equity Compensation Plans	1,395	-	1,395
	Treasury Stock Purchased (1)	-	(267)	(267)
	Common Stock Issued Under Employee Stock Purchase Plan	135	-	135
	Treasury Stock Issued Under Other Equity Compensation Plans	-	109	109
	Common Stock Sold	13,570	-	13,570
Balance at December 31, 2011		269,323	(304)	269,019

(1) Represents shares that were withheld by, or returned to, EOG in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights, the vesting of restricted stock or restricted stock unit grants or in payment of the exercise price of employee stock options.

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Oil and Gas Exploration and Production Industries Disclosures (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 Bcf	Dec. 31, 2010 Bcf	Dec. 31, 2009 Bcf	Dec. 31, 2008 Bcf
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties	32,353,380	27,693,700
Unproved properties	1,311,055	1,570,109
Total	33,664,435	29,263,809
Accumulated depreciation, depletion and amortization	(13,981,143)	(11,859,870)
Net capitalized costs	19,683,292	17,403,939
United States [Member] | Crude Oil (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	355,457.0	188,452.0	133,362.0
Revisions of previous estimates	(21,188.0)	(8,313.0)	4,402.0
Purchases in place	9	13	15,666.0
Extensions, discoveries and other additions	202,552.0	199,479.0	58,258.0
Sales in place	(4,301.0)	(1,082.0)	(5,742.0)
Production	(37,233.0)	(23,092.0)	(17,494.0)
Net proved reserves - end of period	495,296.0	355,457.0	188,452.0
United States [Member] | Natural Gas Liquids (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	150,434.0	91,489.0	72,484.0
Revisions of previous estimates	35,999.0	27,490.0	6,109.0
Purchases in place	17	0	5,801.0
Extensions, discoveries and other additions	65,288.0	42,221.0	18,546.0
Sales in place	(10,008.0)	(2)	(3,231.0)
Production	(15,144.0)	(10,764.0)	(8,220.0)
Net proved reserves - end of period	226,586.0	150,434.0	91,489.0
United States [Member] | Natural Gas (Bcf) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	6,491.5	6,350.1	4,889.0
Revisions of previous estimates	(344.0)	(222.7)	(378.0)
Purchases in place	3.0	0.0	450.8
Extensions, discoveries and other additions	634.6	821.3	1,925.0
Sales in place	(323.6)	(34.6)	(114.4)
Production	(415.7)	(422.6)	(422.3)
Net proved reserves - end of period	6,045.8	6,491.5	6,350.1	4,889.0
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	3,234.9	3,519.7	3,330.1	3,544.7
Net proved undeveloped reserves	2,810.8	2,971.7	3,020.0	1,344.3
United States [Member] | Oil Equivalents (MBoe) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	1,587,806.0	1,338,292.0	1,020,671.0
Revisions of previous estimates	(42,526.0)	(17,945.0)	(52,487.0)
Purchases in place	521.0	14	96,605.0
Extensions, discoveries and other additions	373,602.0	378,582.0	397,642.0
Sales in place	(68,247.0)	(6,860.0)	(28,032.0)
Production	(121,648.0)	(104,277.0)	(96,107.0)
Net proved reserves - end of period	1,729,508.0	1,587,806.0	1,338,292.0	1,020,671.0
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	877,301.0	839,928.0	744,339.0	750,389.0
Net proved undeveloped reserves	852,207.0	747,878.0	593,953.0	270,282.0
United States [Member] | Liquids (MBbl) [Member]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	338,144.0	253,308.0	189,322.0	159,607.0
Net proved undeveloped reserves	383,739.0	252,583.0	90,619.0	46,239.0
Canada [Member] | Crude Oil (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	25,636.0	25,586.0	7,498.0
Revisions of previous estimates	(4,611.0)	(104.0)	(183.0)
Purchases in place	0	0	0
Extensions, discoveries and other additions	449.0	3,198.0	19,783.0
Sales in place	0	(589.0)	(20)
Production	(2,882.0)	(2,455.0)	(1,492.0)
Net proved reserves - end of period	18,592.0	25,636.0	25,586.0
Canada [Member] | Natural Gas Liquids (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	1,475.0	1,972.0	3,297.0
Revisions of previous estimates	43	(196.0)	(926.0)
Purchases in place	0	0	0
Extensions, discoveries and other additions	0	21	24
Sales in place	0	(6)	(30)
Production	(316.0)	(316.0)	(393.0)
Net proved reserves - end of period	1,202.0	1,475.0	1,972.0
Canada [Member] | Natural Gas (Bcf) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	1,133.8	1,549.5	1,237.2
Revisions of previous estimates	(49.8)	(29.9)	(447.2)
Purchases in place	0.0	0.0	0.0
Extensions, discoveries and other additions	0.0	3.4	846.5
Sales in place	0.0	(316.2)	(5.1)
Production	(48.1)	(73.0)	(81.9)
Net proved reserves - end of period	1,035.9	1,133.8	1,549.5	1,237.2
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	295.8	401.6	681.0	1,103.7
Net proved undeveloped reserves	740.1	732.2	868.5	133.6
Canada [Member] | Oil Equivalents (MBoe) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	216,084.0	285,808.0	217,002.0
Revisions of previous estimates	(12,865.0)	(5,288.0)	(75,638.0)
Purchases in place	0	0	0
Extensions, discoveries and other additions	448.0	3,789.0	160,882.0
Sales in place	0	(53,288.0)	(898.0)
Production	(11,219.0)	(14,937.0)	(15,540.0)
Net proved reserves - end of period	192,448.0	216,084.0	285,808.0	217,002.0
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	58,524.0	79,701.0	124,323.0	194,360.0
Net proved undeveloped reserves	133,924.0	136,383.0	161,486.0	22,642.0
Canada [Member] | Liquids (MBbl) [Member]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	9,220.0	12,758.0	10,831.0	10,416.0
Net proved undeveloped reserves	10,574.0	14,352.0	16,727.0	379.0
Trinidad [Member] | Crude Oil (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	4,731.0	5,443.0	8,326.0
Revisions of previous estimates	18	(754.0)	(1,760.0)
Purchases in place	0	0	0
Extensions, discoveries and other additions	0	1,751.0	0
Sales in place	0	0	0
Production	(1,242.0)	(1,709.0)	(1,123.0)
Net proved reserves - end of period	3,507.0	4,731.0	5,443.0
Trinidad [Member] | Natural Gas Liquids (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	0	0	0
Revisions of previous estimates	0	0	0
Purchases in place	0	0	0
Extensions, discoveries and other additions	0	0	0
Sales in place	0	0	0
Production	0	0	0
Net proved reserves - end of period	0	0	0
Trinidad [Member] | Natural Gas (Bcf) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	827.6	985.8	1,198.1
Revisions of previous estimates	(24.2)	(88.6)	(104.9)
Purchases in place	0.0	0.0	0.0
Extensions, discoveries and other additions	74.7	63.0	0.0
Sales in place	0.0	0.0	0.0
Production	(127.4)	(132.6)	(107.4)
Net proved reserves - end of period	750.7	827.6	985.8	1,198.1
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	606.3	519.2	609.4	889.0
Net proved undeveloped reserves	144.4	308.5	376.4	309.0
Trinidad [Member] | Oil Equivalents (MBoe) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	142,669.0	169,747.0	208,013.0
Revisions of previous estimates	(4,011.0)	(15,513.0)	(19,250.0)
Purchases in place	0	0	0
Extensions, discoveries and other additions	12,455.0	12,250.0	0
Sales in place	0	0	0
Production	(22,484.0)	(23,815.0)	(19,016.0)
Net proved reserves - end of period	128,629.0	142,669.0	169,747.0	208,013.0
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	103,710.0	90,382.0	105,540.0	154,939.0
Net proved undeveloped reserves	24,919.0	52,287.0	64,207.0	53,074.0
Trinidad [Member] | Liquids (MBbl) [Member]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	2,657.0	3,853.0	3,966.0	6,756.0
Net proved undeveloped reserves	850.0	879.0	1,477.0	1,570.0
Other International [Member] | Crude Oil (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	98	58	65
Revisions of previous estimates	25	20	17
Purchases in place	0	0	0
Extensions, discoveries and other additions	0	48	0
Sales in place	0	0	0
Production	(25)	(28)	(24)
Net proved reserves - end of period	98	98	58
Other International [Member] | Natural Gas Liquids (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	0	0	0
Revisions of previous estimates	0	0	0
Purchases in place	0	0	0
Extensions, discoveries and other additions	0	0	0
Sales in place	0	0	0
Production	0	0	0
Net proved reserves - end of period	0	0	0
Other International [Member] | Natural Gas (Bcf) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	17.3	12.7	14.9
Revisions of previous estimates	1.3	1.9	3.0
Purchases in place	0.0	0.0	0.0
Extensions, discoveries and other additions	4.5	7.9	0.0
Sales in place	0.0	0.0	0.0
Production	(4.6)	(5.2)	(5.2)
Net proved reserves - end of period	18.5	17.3	12.7	14.9
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	18.6	17.3	12.7	14.9
Net proved undeveloped reserves	0.0	0.0	0.0	0.0
Other International [Member] | Oil Equivalents (MBoe) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	2,976.0	2,172.0	2,548.0
Revisions of previous estimates	239.0	342.0	515.0
Purchases in place	0	0	0
Extensions, discoveries and other additions	750.0	1,363.0	0
Sales in place	0	0	0
Production	(787.0)	(901.0)	(891.0)
Net proved reserves - end of period	3,178.0	2,976.0	2,172.0	2,548.0
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	3,178.0	2,976.0	2,172.0	2,548.0
Net proved undeveloped reserves	0	0	0	0
Other International [Member] | Liquids (MBbl) [Member]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	97	98	58	65
Net proved undeveloped reserves	0	0	0	0

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Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Deferred tax assets net current classification [Abstract]
Commodity Hedging Contracts	$ 0	$ (7,141,000)
Deferred Compensation Plans	(28,346,000)	13,216,000
Other	0	3,185,000
Total Net Current Deferred Income Tax Assets	0	9,260,000
Deferred tax assets net noncurrent classification [Abstract]
United Kingdom Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	(57,850,000)	(16,611,000)
United Kingdom Net Operating Loss	62,477,000	17,329,000
United Kingdom Other	314,000	226,000
Total Net Noncurrent Deferred Income Tax Assets	4,941,000	944,000
Deferred tax liabilities net current classification [Abstract]
Commodity Hedging Contracts	158,302,000	0
Deferred Compensation Plans	(28,346,000)	13,216,000
Timing Differences Associated With Different Year-ends in Foreign Jurisdictions	6,251,000	41,027,000
Other	(218,000)	676,000
Total Net Current Deferred Income Tax Assets	135,989,000	41,703,000
Deferred tax liabilities net noncurrent classification [Abstract]
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	5,485,436,000	4,373,110,000
Non-Producing Leasehold Costs	(66,926,000)	(78,846,000)
Seismic Costs Capitalized for Tax	(111,862,000)	(92,901,000)
Equity Awards	(120,852,000)	(99,447,000)
Capitalized Interest	106,265,000	94,957,000
Net Operating Loss	(1,152,386,000)	(498,893,000)
Alternative Minimum Tax Credit Carryforward	(298,350,000)	(214,873,000)
Other	25,894,000	18,599,000
Total Net Noncurrent Deferred Income Tax Liabilities	3,867,219,000	3,501,706,000
Total Net Deferred Income Tax Liabilities	3,998,267,000	3,533,205,000
Income Before Income Taxes [Abstract]
United States	2,156,147,000	646,495,000	784,248,000
Foreign	(246,348,000)	(238,519,000)	87,763,000
Total	1,909,799,000	407,976,000	872,011,000
Current income tax provision [Abstract]
Federal	94,244,000	17,154,000	95,194,000
State	1,083,000	(1,642,000)	8,783,000
Foreign	224,049,000	155,565,000	47,015,000
Total	319,376,000	171,077,000	150,992,000
Deferred income tax provision [Abstract]
Federal	608,181,000	190,602,000	166,045,000
State	40,321,000	60,619,000	31,580,000
Foreign	(149,202,000)	(174,976,000)	(23,233,000)
Total	499,300,000	76,245,000	174,392,000
Income Tax Provision	818,676,000	247,322,000	325,384,000
Effective income tax rate [Abstract]
Statutory Federal Income Tax Rate (in hundredths)	35.00%	35.00%	35.00%
State Income Tax, Net of Federal Benefit (in hundredths)	1.41%	9.39%	3.00%
Income Tax Provision Related to Foreign Operations (in hundredths)	0.88%	(0.03%)	(1.40%)
Income Tax Provision Related to Trinidad Operations (in hundredths)	3.37%	6.26%	0.60%
Canadian Shallow Natural Gas Impairments (in hundredths)	1.85%	9.49%	0.00%
Other (in hundredths)	0.36%	0.51%	0.11%
Effective Income Tax Rate (in hundredths)	42.87%	60.62%	37.31%
Change in Canadian Federal and Provincial Statutory Tax Rates and Other Canadian Adjustments (in hundredths)	27.00%
Unrecognized tax benefits balance	33,000,000
Foreign subsidiaries' undistributed earnings	2,300,000,000
Regular tax net operating loss	1,800,000,000	1,400,000,000
Tax benefit reflected in APIC	23,000,000	17,000,000
Alternative minimum tax paid	104,000,000
AMT paid in years prior to current reporting period	194,000,000
Foreign tax net operating loss	71,000,000	30,000,000
Statutory Federal Income Tax Rate (in hundredths)	35.00%	35.00%	35.00%
State Income Tax Net Operating Losses	$ 700,000,000
Increase in the statutory income tax rate applying to oil and gas activities	50% to 62%
Increase in a statutory deduction	6% to 10%

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs

Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon job functions of the employees receiving the grants.  Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2011, 2010 and 2009 was as follows (in millions):

	2011		2010		2009
Lease and Well	$	33	$	27	$	23
Gathering and Processing Costs		1		1		-
Exploration Costs		26		24		21
General and Administrative		68		55		51
Total	$	128	$	107	$	95

Weighted Average Fair Values and Valuation Assumptions

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2011, 2010 and 2009 were as follows:

	Stock Options/SARs									ESPP
	2011			2010			2009			2011			2010			2009
Weighted Average Fair Value of Grants	$	29.92		$	32.12		$	30.13		$	22.75		$	25.45		$	25.78
Expected Volatility		40.96	%		39.70	%		41.90	%		29.82	%		38.30	%		78.89	%
Risk-Free Interest Rate		0.58	%		0.87	%		1.42	%		0.14	%		0.18	%		0.25	%
Dividend Yield		0.70	%		0.70	%		0.70	%		0.70	%		0.70	%		1.00	%
Expected Life	5.6 yrs			5.5 yrs			5.5 yrs			0.5 yrs			0.5 yrs			0.5 yrs

Schedule of Share Based Compensation Arrangement By Share Based Payment Award

The following table sets forth the stock option and SAR transactions for the years ended December 31, 2011, 2010 and 2009 (stock options and SARs in thousands):

	2011					2010					2009
	Number			Weighted		Number			Weighted		Number			Weighted
	of Stock			Average		of Stock			Average		Of Stock			Average
	Options/			Grant		Options/			Grant		Options/			Grant
	SARs			Price		SARs			Price		SARs			Price
Outstanding at January 1		8,445		$	64.49		8,335		$	57.08		7,802		$	52.56
Granted		1,509			85.29		1,450			93.07		1,270			80.95
Exercised (1)		(1,399	)		50.86		(1,144	)		43.38		(636	)		46.56
Forfeited		(181	)		87.74		(196	)		84.22		(101	)		74.07
Outstanding at December 31		8,374			70.01		8,445			64.49		8,335			57.08
Stock Options/SARs Exercisable at December 31		5,148			59.19		5,439			51.71		5,394			44.45

(1) The total intrinsic value of stock options/SARs exercised during the years 2011, 2010 and 2009 was $78.4 million, $66.0 million and $21.4 million, respectively.  The intrinsic value is based upon the difference between the market price of Common Stock on the date of exercise and the grant price of the stock options/SARs.

Stock Options and SARs Outstanding and Exercisable

The following table summarizes certain information for the stock options and SARs outstanding at December 31, 2011 (stock options and SARs in thousands):

		Stock Options/SARs Outstanding							Stock Options/SARs Exercisable
				Weighted							Weighted
				Average		Weighted					Average		Weighted
Range of		Stock		Remaining		Average		Aggregate	Stock		Remaining		Average		Aggregate
Grant		Options/		Life		Grant		Intrinsic	Options/		Life		Grant		Intrinsic
Prices		SARs		(Years)		Price		Value(1)	SARs		(Years)		Price		Value(1)
$	16.00 to $ 48.99		1,431		1	$	20.30			1,431		1	$	20.30
49.00 to  69.99			1,623		1		61.99			1,609		1		61.94
70.00 to  81.99			1,674		4		78.17			1,159		4		76.66
82.00 to  88.99			2,174		6		85.44			576		4		88.73
89.00 to 136.99			1,472		5		95.09			373		5		96.56
			8,374		4		70.01	$241,474		5,148		2		59.19	$203,646

(1) Based upon the difference between the closing market price of Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs.

ESPP Activity

The following table summarizes ESPP activities for the years ended December 31, 2011, 2010 and 2009 (in thousands, except number of participants):

	2011		2010		2009
Approximate Number of Participants		1,525		1,236		1,128
Shares Purchased		135		114		72
Aggregate Purchase Price	$	10,947	$	9,172	$	4,150

Restricted Stock and Restricted Stock Unit Transactions

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2011, 2010 and 2009 (shares and units in thousands):

	2011					2010					2009
				Weighted					Weighted					Weighted
	Number of			Average		Number of			Average		Number of			Average
	Shares and			Grant Date		Shares and			Grant Date		Shares and			Grant Date
	Units			Fair Value		Units			Fair Value		Units			Fair Value
Outstanding at January 1		4,009		$	79.13		3,636		$	73.69		3,048		$	70.24
Granted		932			90.87		850			93.39		1,197			63.13
Released (1)		(457	)		66.10		(364	)		58.00		(553	)		31.35
Forfeited		(244	)		82.45		(113	)		79.37		(56	)		78.18
Outstanding at December 31(2)		4,240			82.93		4,009			79.13		3,636			73.69

(1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2011, 2010 and 2009 was $44.4 million, $35.2 million and $36.9 million, respectively.  The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.

(2) The aggregate intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2011 and 2010 was approximately $417.7 million and $366.4 million, respectively.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Minimum commitments for unrecorded unconditional purchase obligations

At December 31, 2011, total minimum commitments from long-term non-cancelable operating leases, drilling rig commitments, seismic purchase obligations, fracturing services obligations, other purchase obligations and transportation and storage service commitments, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars and British pounds into United States dollars at December 31, 2011, are as follows (in thousands):

	Total Minimum
	Commitments
2012	$	1,185,759
2013 - 2014		1,013,735
2015 - 2016		925,514
2017 and beyond		1,435,506
	$	4,560,514

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Summary of Significant Accounting Policies [Text Block]

1.  Summary of Significant Accounting Policies

Principles of Consolidation.  The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries.  Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method.  All intercompany accounts and transactions have been eliminated.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Financial Instruments.  EOG's financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt, along with associated foreign currency and interest rate swaps.  The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable, foreign currency and interest rate swaps and accounts payable approximate fair value (see Notes 2 and 11).

Cash and Cash Equivalents.  EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.

Oil and Gas Operations.  EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.

Oil and gas lease acquisition costs are capitalized when incurred.  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.  If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred.  The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered proved commercial reserves.  If proved commercial reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 15).  Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method.  The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.  With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.  Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Oil and gas properties are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC).  The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.

When circumstances indicate that an asset 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, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated using the income approach described in the Fair Value Measurements and Disclosures Topic of the ASC.  If applicable, EOG utilizes accepted bids as the basis for determining fair value.

Inventories, consisting primarily of tubular goods, materials for completion operations and well equipment held for use in the exploration for, and development and production of, crude oil and natural gas reserves, are carried at cost with adjustments made, as appropriate, to recognize any reductions in value.

Arrangements for crude oil and condensate, natural gas liquids and natural gas sales are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered.  A significant majority of the purchasers of these products have investment grade credit ratings and material credit losses have been rare.  Revenues are recorded on the entitlement method based on EOG's percentage ownership of current production.  Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold on that owner's behalf may differ from that owner's ownership percentage.  Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs.  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.

Other Property, Plant and Equipment.  Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, crude-by-rail assets, sand mine and sand processing assets, computer hardware and software, vehicles, and furniture and fixtures.  Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 40 years.

Capitalized Interest Costs.  Interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties.  The amount capitalized is an allocation of the interest cost incurred during the reporting period.  Capitalized interest is computed only during the exploration and development phases and ceases once production begins.  The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings.

Accounting for Risk Management Activities.  Derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  During the three-year period ended December 31, 2011, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges, and accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change.  The gains or losses are recorded as Gains on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income.  The related cash flow impact is reflected as cash flows from operating activities.  See Note 11.  EOG is party to a foreign currency swap transaction and an interest rate swap transaction (see Note 2).  EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement.

Income Taxes.  Income taxes are accounted for using the asset and liability approach.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis (see Note 5).

Foreign Currency Translation.  The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for certain of its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary, for which the functional currency is the British pound.  For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year.  Translation adjustments are included in Accumulated Other Comprehensive Income on the Consolidated Balance Sheets.  Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period.

Net Income Per Share.  Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods.  Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the periods plus the assumed issuance of common shares for all potentially dilutive securities (see Note 8).

Stock-Based Compensation.  EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award.  (See Note 6.)

Recently Issued Accounting Standards.  In May 2011, the FASB issued Accounting Standards Update (ASU) 2011-04, "Fair Value Measurement (Topic 820):  Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs".  ASU 2011-04 amends the Fair Value Measurements and Disclosures Topic of the ASC to clarify the FASB's intent about the application of existing fair value measurement requirements and change certain principles or requirements for measuring fair value or disclosing information about fair value measurements.  ASU 2011-04 is effective for interim and annual fiscal periods beginning after December 15, 2011.  EOG does not expect that the adoption of ASU 2011-04 will have a material impact on its financial statements, but it may result in additional disclosures regarding fair value measurements.

In June 2011, the FASB issued ASU 2011-05 "Comprehensive Income (Topic 220): Presentation of Comprehensive Income."  ASU 2011-05 is intended to increase the prominence of comprehensive income in the financial statements by requiring that an entity that reports items of comprehensive income do so in either one continuous or two consecutive financial statements.  ASU 2011-05 also requires separate presentation on the face of the financial statements for items reclassified from other comprehensive income into net income.  Subsequently, in December 2011, the FASB deferred the effective date of the provisions of ASU 2011-05 relating to the presentation of reclassification adjustments out of accumulated other comprehensive income. The provisions of ASU 2011-05 not deferred by the FASB are effective for interim and annual fiscal periods beginning after December 15, 2011.  Retroactive application is required.  EOG does not expect that the adoption of ASU 2011-05 will have a material impact on its financial statements, but it may result in additional disclosures regarding components of comprehensive income.

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Net Income Per Share (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Computation of Net Income Per Share Available to Common Stockholders

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2011, 2010 and 2009 (in thousands, except per share data):

	2011		2010		2009
Numerator for Basic and Diluted Earnings per Share -
Net Income	$	1,091,123	$	160,654	$	546,627
Denominator for Basic Earnings per Share -
Weighted Average Shares		262,735		250,876		248,996
Potential Dilutive Common Shares -
Stock Options/SARs		1,707		1,991		1,691
Restricted Stock and Restricted Stock Units		1,826		1,633		1,197
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares		266,268		254,500		251,884
Net Income Per Share
Basic	$	4.15	$	0.64	$	2.20
Diluted	$	4.10	$	0.63	$	2.17

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Schedule II - Valuation and Qualiying Accounts (Tables)

12 Months Ended

Dec. 31, 2011

Schedule II - Valuation and Qualifying Accountins Tables [Abstract]

Valuation and Qualifying Accounts

Column A	Column B		Column C		Column D			Column E
			Additions
	Balance at		Charged to		Deductions			Balance at
	Beginning of		Costs and		From			End of
Description	Year		Expenses		Reserves			Year
2011
Allowance deducted from Accounts Receivable	$	13,642	$	778	$	11,711	(1)	$	2,709
2010
Allowance deducted from Accounts Receivable	$	13,228	$	885	$	471		$	13,642
2009
Allowance deducted from Accounts Receivable	$	13,131	$	145	$	48		$	13,228

(1)   Primarily reflects amounts related to bankruptcies which occurred in December 2001

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Asset Retirements Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Notes To Financial Statements [Abstract]
Carrying Amount at Beginning of Period	$ 498,288	$ 456,484
Liabilities Incurred	68,703	39,480
Liabilities Settled (1)	(66,129)	(30,763)
Accretion	27,907	25,456
Revisions	58,786	1,640
Foreign Currency Translations	(471)	5,991
Current Portion	29,527	32,005
Noncurrent Portion	557,557	466,283
Carrying Amount at End of Period	$ 587,084	$ 498,288

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Consolidated Statements of Income and Comprehensive Income (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net Operating Revenues
Crude Oil and Condensate	$ 3,838,284	$ 1,998,771	$ 1,089,711
Natural Gas Liquids	779,364	462,345	258,799
Natural Gas	2,240,540	2,420,099	2,050,963
Gains on Mark-to-Market Commodity Derivative Contracts	(626,053)	(61,912)	(431,757)
Gathering, Processing and Marketing	2,115,792	909,680	407,116
Gains on Asset Dispositions, Net	492,909	223,538	535,436
Other, Net	33,173	23,551	13,177
Total	10,126,115	6,099,896	4,786,959
Operating Expenses
Lease and Well	941,954	698,430	579,290
Transportation Costs	430,322	385,189	283,329
Gathering and Processing Costs	80,727	66,758	57,632
Exploration Costs	171,658	187,381	169,592
Dry Hole Costs	53,230	72,486	51,243
Impairments	1,031,037	742,647	305,832
Marketing Costs	2,072,137	884,212	397,375
Depreciation, Depletion and Amortization	2,516,381	1,941,926	1,549,188
General and Administrative	304,811	280,474	248,274
Taxes Other Than Income	410,549	317,074	174,363
Total	8,012,806	5,576,577	3,816,118
Operating Income	2,113,309	523,319	970,841
Other Income, Net	6,853	14,243	2,071
Income Before Interest Expense and Income Taxes	2,120,162	537,562	972,912
Interest Expense
Incurred	268,104	205,886	155,820
Capitalized	(57,741)	(76,300)	(54,919)
Interest Expense, Net	210,363	129,586	100,901
Income Before Income Taxes	1,909,799	407,976	872,011
Income Tax Provision	818,676	247,322	325,384
Net Income	1,091,123	160,654	546,627
Net Income Per Share Available to Common Stockholders
Basic	$ 4.15	$ 0.64	$ 2.20
Diluted	$ 4.10	$ 0.63	$ 2.17
Dividends Declared per Common Share	$ 0.64	$ 0.62	$ 0.58
Average Number of Common Shares
Basic	262,735	250,876	248,996
Diluted	266,268	254,500	251,884
Quarterly cash dividend	$ 0.64	$ 0.62	$ 0.58
Comprehensive Income
Net Income	1,091,123	160,654	546,627
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	(32,597)	96,179	308,286
Foreign Currency Swap Transaction	(1,571)	4,447	6,336
Income Tax Related to Foreign Currency Swap Transaction	404	(1,203)	(1,519)
Interest Rate Swap Transaction	(5,223)	1,843	0
Income Tax Related to Interest Rate Swap Transaction	1,878	(664)	0
Other	(1,216)	(251)	(1,170)
Comprehensive Income	$ 1,052,798	$ 261,005	$ 858,560

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Employee Benefit Plans (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Stock based compensation by job function [Line Items]
Compensation expense related to the company's stock-based compensation plans	$ 128,205,000	$ 107,314,000	$ 95,037,000
Maximum shares of stock-based awards approved	12,900,000
Common Shares Available for Grant	5,400,000
Federal income tax (expense) / benefit recognized from stock-based compensation	25,000	(1,000,000)	76,000,000
Vesting schedule for stock options and SARs granted	four years
Maximum term of stock options and SARs granted (in years)	10
Percentage of the fair market value at which employees may purchase company stock via the ESPP	85
Maximum Percentage Of Employee Pay Eligible For Contribution To Espp Percentage	10.00%
Term Of Espp Offering Period Description	two six-month offering periods
Stock-based compensation expense related to stock options, SAR and ESPP grants	48,000,000	41,000,000	38,000,000
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Aggregate Intrinsic Value For Outstanding Options and SARs	241,474
Aggregate Intrinsic Value For Exercisable Units	203,646
Unrecognized compensation expense related to non-vested stock option and SAR grants	87,900,000
Weighted average period over which unrecognized compensation expense will be recognized (in years)	2.8
Share Based Compensation Arrangement By Share Based Payment Award ESPP [Abstract]
Stock Options/SARs Exercisable at December 31 (in shares)	5,148,000	5,439,000	5,394,000
Available for Future Grant (in shares)	5,400,000
Intrinsic value of stock options/SARs exercised during the period	78,400,000	66,000,000	21,400,000
Stock options/SARs vested or expected to vest (in shares)	8,123,226
Weighted average grant price for stock options/SARs vested or expected to vest (per share)	$ 69.48
Intrinsic value of stock options/SARs vested or expected to vest	238,500,000
Weighted average remaining contractual life of stock options/SARs vested or expected to vest (in years)	3.6
Employee Service Share Based Compensation Unrecognized Compensation Costs On Nonvested Restricted Stock Awards	132,600,000
Stock Options And Sars [Member]
Weighted Average Fair Value And Valuation Assumptions Used To Value ESPP Stock Based Compensation [Abstract]
Weighted Average Fair Value of Grants	$ 29.92	$ 32.12	$ 30.13
Expected Volatility (in hundredths)	40.96%	39.70%	41.90%
Risk-Free Interest Rate (in hundredths)	0.58%	0.87%	1.42%
Dividend Yield (in hundredths)	0.70%	0.70%	0.70%
Expected Life (in years)	5.6	5.5	5.5
Stock option and SAR Rollforward [Abstract]
Outstanding at January 1	8,445,000	8,335,000	7,802,000
Granted	1,509,000	1,450,000	1,270,000
Exercised (1)	(1,399,000)	(1,144,000)	(636,000)
Forfeited	(181,000)	(196,000)	(101,000)
Outstanding at December 31	8,374,000	8,445,000	8,335,000
Share Based Compensation Arrangement By Share Based Payment Award ESPP [Abstract]
Outstanding at January 1 - Price per Share	$ 64.49	$ 57.08	$ 52.56
Granted - Price Per Share	$ 85.29	$ 93.07	$ 80.95
Exercised - Price Per Share	$ 50.86	$ 43.38	$ 46.56
Forfeited - Price per Share	$ 87.74	$ 84.22	$ 74.07
Outstanding at December 31 - Price per Share	$ 70.01	$ 64.49	$ 57.08
Stock Options/SARs Exercisable at December 31 (price per share)	$ 59.19	$ 51.71	$ 44.45
Espp [Member]
Stock based compensation by job function [Line Items]
Common Shares Available for Grant	790,000
Weighted Average Fair Value And Valuation Assumptions Used To Value ESPP Stock Based Compensation [Abstract]
Weighted Average Fair Value of Grants	$ 22.75	$ 25.45	$ 25.78
Expected Volatility (in hundredths)	29.82%	38.30%	78.89%
Risk-Free Interest Rate (in hundredths)	0.14%	0.18%	0.25%
Dividend Yield (in hundredths)	0.70%	0.70%	1.00%
Expected Life (in years)	0.5	0.5	0.5
Share Based Compensation Arrangement By Share Based Payment Award ESPP [Abstract]
Available for Future Grant (in shares)	790,000
Approximate Number Of Participants In Espp	1,525	1,236	1,128
Employee Stock Purchase Plan Espp Shares Contributed To Espp	135,000	114,000	72,000
Employee Stock Purchase Plan Espp Cash Contributions To Espp	10,947,000	9,172,000	4,150,000
Restricted Stock And Restricted Stock Units [Member]
Stock option and SAR Rollforward [Abstract]
Outstanding at January 1	4,009,000	3,636,000	3,048,000
Granted	932,000	850,000	1,197,000
Exercised (1)	(457,000)	(364,000)	(553,000)
Forfeited	(244,000)	(113,000)	(56,000)
Outstanding at December 31	4,240,000	4,009,000	3,636,000
Share Based Compensation Arrangement By Share Based Payment Award ESPP [Abstract]
Outstanding at January 1 - Price per Share	$ 79.13	$ 73.69	$ 70.24
Granted - Price Per Share	$ 90.87	$ 93.39	$ 63.13
Exercised - Price Per Share	$ 66.10	$ 58.00	$ 31.35
Forfeited - Price per Share	$ 82.45	$ 79.37	$ 78.18
Outstanding at December 31 - Price per Share	$ 82.93	$ 79.13	$ 73.69
Share Based Compensation Restricted Stock Arrangement By Share Based Payment Award Award Vesting Period	five years
Share Based Compensation Arrangement By Restricted Stock And Restricted Stock Units Compensation Cost	80,000,000	66,000,000	57,000,000
Employee Service Share Based Compensation Unrecognized Compensation Costs On Nonvested Restricted Stock Awards Weighted Average Period Of Recognition	2.4
Intrinsic value of restricted stock and restricted stock units released during the year	$ 44,400,000	$ 35,200,000	$ 36,900,000
Aggregate Intrinsic Value Of Restricted Stock And Restricted Stock Units	417,700,000	366,400,000
Grant Price Range 1 [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options And Sars Outstanding	1,431,000
Weighted Average Remaining Life For Outstanding Options and SARs	1
Weighted Average Grant Price For Outstanding Options and SARs	$ 20.30
Number Of Exercisable Options and SARs	1,431,000
Weighted Average Grant Price For Exercisable Options and SARs	$ 20.30
Weighted Average Remaining Life For Exercisable Options and SARs	1
Grant Price Range 2 [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options And Sars Outstanding	1,623,000
Weighted Average Remaining Life For Outstanding Options and SARs	1
Weighted Average Grant Price For Outstanding Options and SARs	$ 61.99
Number Of Exercisable Options and SARs	1,609,000
Weighted Average Grant Price For Exercisable Options and SARs	$ 61.94
Weighted Average Remaining Life For Exercisable Options and SARs	1
Grant Price Range 3 [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options And Sars Outstanding	1,674,000
Weighted Average Remaining Life For Outstanding Options and SARs	4
Weighted Average Grant Price For Outstanding Options and SARs	$ 78.17
Number Of Exercisable Options and SARs	1,159,000
Weighted Average Grant Price For Exercisable Options and SARs	$ 76.66
Weighted Average Remaining Life For Exercisable Options and SARs	4
Grant Price Range 4 [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options And Sars Outstanding	2,174,000
Weighted Average Remaining Life For Outstanding Options and SARs	6
Weighted Average Grant Price For Outstanding Options and SARs	$ 85.44
Number Of Exercisable Options and SARs	576,000
Weighted Average Grant Price For Exercisable Options and SARs	$ 88.73
Weighted Average Remaining Life For Exercisable Options and SARs	4
Grant Price Range 5 [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options And Sars Outstanding	1,472,000
Weighted Average Remaining Life For Outstanding Options and SARs	5
Weighted Average Grant Price For Outstanding Options and SARs	$ 95.09
Number Of Exercisable Options and SARs	373,000
Weighted Average Grant Price For Exercisable Options and SARs	$ 96.56
Weighted Average Remaining Life For Exercisable Options and SARs	5
Lease And Well [Member]
Stock based compensation by job function [Line Items]
Compensation expense related to the company's stock-based compensation plans	33,000,000	27,000,000	23,000,000
Gathering And Processing Costs [Member]
Stock based compensation by job function [Line Items]
Compensation expense related to the company's stock-based compensation plans	1,000,000	1,000,000	0
Exploration Costs [Member]
Stock based compensation by job function [Line Items]
Compensation expense related to the company's stock-based compensation plans	26,000,000	24,000,000	21,000,000
General And Administrative [Member]
Stock based compensation by job function [Line Items]
Compensation expense related to the company's stock-based compensation plans	68,000,000	55,000,000	51,000,000
Pension Plans Defined Benefit and Contribution [Member]
Defined Benefit and Defined Contribution Plan Disclosure [Line Items]
Total pension plan costs	27,100,000	23,400,000	21,800,000
Company contributions to foreign pension plans	2,500,000	2,800,000	2,600,000
Benefit obligation	11,300,000	10,300,000
Accrued benefit cost	(1,600,000)	(800,000)
Fair value of foreign pension plan assets	8,200,000	8,700,000
Defined Benefit Plan Disclosure [Line Items]
Fair value of foreign pension plan assets	$ 8,200,000	$ 8,700,000

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Consolidated Statements of Stockholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated Statements of Stockholders' Equity - Parenthetical [Abstract]
Common Stock Dividends Declared	$ 0.64	$ 0.62	$ 0.58

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Oil and Gas Exploration and Production Industries Disclosures, Average Sales Price (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
United States [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	6.19	5.00	4.43
Canada [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	14.26	10.28	8.41
Trinidad [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	0.78	0.65	0.74
Other International [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	13.82	9.34	10.52

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Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Derivative Contracts Table

Commodity Derivative Contracts.  Presented below is a comprehensive summary of EOG's crude oil derivative contracts at December 31, 2011, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl)

Crude Oil Derivative Contracts
			Weighted
	Volume		Average Price
	(Bbld)		($/Bbl)
2012 (1)
January 1, 2012 through June 30, 2012		34,000	$	104.95
July 1, 2012 through December 31, 2012		17,000		103.59

(1)   EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Such options are exercisable on June 29, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 17,000 Bbld at an average price of $106.31 per barrel for the period July 1, 2012 through December 31, 2012.

Presented below is a comprehensive summary of EOG's natural gas derivative contracts as of December 31, 2011, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Derivative Contracts
	Volume (MMBtud)		Weighted Average Price ($/MMBtu)
2012 (1)
January 2012 (closed)		525,000	$	5.44
February 1, 2012 through December 31, 2012		525,000		5.44
2013 (2)
January 1, 2013 through December 31, 2013		150,000	$	4.79
2014 (2)
January 1, 2014 through December 31, 2014		150,000	$	4.79

(1) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from February 1, 2012 through December 31, 2012.

(2) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2013 and 2014.

Schedule of Derivative Instruments In Statement Of Financial Position, Fair Value Table

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding derivative financial instruments at December 31, 2011 and 2010, respectively.  Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

		Fair Value at December 31,
Description	Location on Balance Sheet	2011		2010
Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities	$	451	$	51
Noncurrent portion	Other Assets	$	35	$	18
Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities	$	-	$	30
Foreign currency swap -
Noncurrent portion	Other Liabilities	$	53	$	55
Interest rate swap -
Noncurrent portion	Other Assets	$	-	$	2
Other Liabilities		$	3	$	-

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Exploratory Well Costs

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Suspended Well Costs [Text Block]

15.  Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2011, 2010 and 2009 are presented below (in thousands):

	2011			2010			2009
Balance at January 1	$	99,801		$	118,459		$	85,255
Additions Pending the Determination of Proved Reserves		31,271			94,090			75,362
Reclassifications to Proved Properties		(29,227	)		(93,333	)		(40,614	)
Charged to Dry Hole Costs		(42,178	)		(20,267	)		(11,223	)
Foreign Currency Translations		1,444			852			9,679
Balance at December 31	$	61,111		$	99,801		$	118,459

The following table provides an aging of capitalized exploratory well costs at December 31, 2011, 2010 and 2009 (in thousands, except well count):

	2011			2010			2009
Capitalized exploratory well costs that have been capitalized for a period less than one year	$	17,009		$	43,408		$	51,141
Capitalized exploratory well costs that have been capitalized for a period greater than one year		44,102	(1)		56,393	(2)		67,318	(3)
Total	$	61,111		$	99,801		$	118,459
Number of exploratory wells that have been capitalized for a period greater than one year		4			4			4

(1) Consists of costs related to an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($20 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($9 million), and a shale project in British Columbia, Canada (B.C.) ($6 million).  In the Central North Sea project, the operator and partners are currently negotiating processing and transportation terms with export infrastructure owners.  The operator submitted 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 during the first half of 2012.  In the East Irish Sea project, EOG submitted field development plans to the DECC during the first quarter of 2011 and expects regulatory approval during the first quarter of 2012. Installation of facilities, pipelines and drilling of development wells are planned for 2012 with initial production expected during the first quarter of 2013.  The evaluation of the Sichuan Basin project is expected to be completed by mid-2012.  In the B.C. shale project, EOG drilled four additional wells during the first half of 2011 and plans to drill seven wells in the first half of 2012 to retain land and further evaluate the project.  The related well completion activities are not expected to commence until 2013 or later.

(2) Consists of costs related to an outside operated, offshore Central North Sea project in the U.K. ($21 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($20 million), and a shale project in B.C. ($6 million).

(3) Consists of costs related to three shale projects in B.C. ($45 million) and an outside operated, offshore Central North Sea project in the U.K. ($22 million).

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Fair Value Assets And Liabilities Measured On Recurring Basis [Table]

The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2011 and 2010 (in millions):

	Fair Value Measurements Using:
	Quoted		Significant
	Prices in		Other		Significant
	Active		Observable		Unobservable
	Markets		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
At December 31, 2011
Financial Assets:
Crude Oil and Natural Gas Derivative Contracts	$	-	$	110	$	-	$	110
Crude Oil and Natural Gas Options/Swaptions		-		376		-		376
Financial Liabilities:
Foreign Currency Rate Swap	$	-	$	52	$	-	$	52
Interest Rate Swap		-		3		-		3
At December 31, 2010
Financial Assets:
Natural Gas Derivative Contracts	$	-	$	62	$	-	$	62
Natural Gas Options/Swaptions		-		6		-		6
Interest Rate Swap		-		2		-		2
Financial Liabilities:
Crude Oil and Natural Gas Derivative Contracts	$	-	$	29	$	-	$	29
Foreign Currency Rate Swap		-		55		-		55
Contingent Consideration		-		-		14		14

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Property Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Acquisitions and Divestitures

16.  Acquisitions and Divestitures

During 2011, EOG received proceeds of approximately $1.4 billion from sales of producing properties and acreage and certain midstream assets, primarily in the Rocky Mountain area and Texas, and the sale of a portion of EOG's interest in the planned Kitimat liquefied natural gas (LNG) Terminal and the proposed Pacific Trail Pipelines (PTP).  During 2010, EOG received proceeds of approximately $673 million from the sale of producing properties and acreage, primarily Canadian shallow natural gas assets and properties in the Rocky Mountain area, Texas, and Pennsylvania.

During the fourth quarter of 2010, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), paid $210 million to acquire Galveston LNG Inc., a Calgary-based corporation which owned 49% of the LNG export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia.  In addition, Galveston LNG Inc. also owned a 24.5% interest in the PTP originating at Summit Lake, British Columbia.  The pipeline is intended to link Western Canada's natural gas producing regions to the Kitimat LNG Terminal.  At the time EOG completed the acquisition, an affiliate of Apache Corporation (Apache) owned 51% of the Kitimat LNG Terminal and a 25.5% interest in PTP.  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 purchased an additional 24.5% interest in PTP for $25.2 million.  A portion of the purchase price ($15.3 million) was paid at closing with the remaining amount to be paid contingent on the decision to proceed with the construction of the Kitimat LNG Terminal.  Additionally, in March 2011, EOGRC and Apache, through a series of transactions, sold a portion of their interests in the Kitimat LNG Terminal and PTP to an affiliate of Encana Corporation (Encana).  Subsequent to these transactions, ownership interests in both the Kitimat LNG Terminal and PTP are:  Apache (operator) 40%, EOGRC 30% and Encana 30%.  All future costs of the project will be paid by each party in proportion to its respective ownership percentage.

In the fourth quarter of 2010, EOG completed the sales of certain of its Canadian shallow natural gas assets in three separate transactions.  Proceeds from the sales were approximately $344 million.  In 2010, 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.

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

In December 2009, EOG sold its crude oil and natural gas related assets located in California for consideration of $202 million.  EOG realized a pretax gain in 2009 of approximately $146 million on the sale.

In October 2009, EOG entered into an agreement to acquire unproved acreage located in Nacogdoches County, Texas, within the Haynesville and Bossier Shale formations (Haynesville Assets).  EOG acquired the unproved acreage at principal, supplemental and final closings held in October 2009, December 2009 and February 2010, respectively.  The acquisition agreement provides for an additional one-time supplemental cash payment to the sellers of the Haynesville Assets that is contingent on the satisfaction of certain conditions (within a five-year period beginning on the principal closing date) set forth in the acquisition agreement with respect to future natural gas prices.  The aggregate consideration recorded in 2009 and 2010 for the acquisition of the Haynesville Assets was $134 million and $18 million, respectively.

During the third quarter of 2009, EOG completed three transactions to acquire certain crude oil and natural gas properties and related assets located in Montague and Cooke Counties, Texas.  The aggregate purchase price of the transactions totaled $197 million, consisting of cash consideration of $107 million and 1,450,000 shares of EOG Common Stock valued at $89.6 million on the closing date of the applicable transaction.

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash Flows from Operating Activities
Net Income	$ 1,091,123	$ 160,654	$ 546,627
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	2,516,381	1,941,926	1,549,188
Impairments	1,031,037	742,647	305,832
Stock-Based Compensation Expenses	128,345	107,378	95,180
Deferred Income Taxes	499,300	76,245	174,392
Gains on Asset Dispositions, Net	(492,909)	(223,538)	(535,436)
Other, Net	15,139	(468)	6,761
Dry Hole Costs	53,230	72,486	51,243
Mark-to-Market Commodity Derivative Contracts
Total Gains	(626,053)	(61,912)	(431,757)
Realized Gains	180,701	7,033	1,277,584
Excess Tax Benefits from Stock-Based Compensation	0	0	(76,134)
Other, Net	26,454	17,273	18,862
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(339,780)	(339,126)	(47,818)
Inventories	(176,623)	(171,971)	(50,146)
Accounts Payable	351,087	654,688	(153,565)
Other Assets	(23,625)	(32,169)	(5,515)
Other Liabilities	14,986	19,342	(12,305)
Changes in Components of Working Capital Associated with Investing and Financing Activities	237,028	(208,968)	118,517
Net Cash Provided by Operating Activities	4,578,410	2,708,602	2,922,439
Investing Cash Flows
Additions to Oil and Gas Properties	(6,294,397)	(5,210,612)	(3,176,783)
Additions to Other Property, Plant and Equipment	(656,415)	(370,770)	(326,226)
Acquisition of Galveston LNG Inc.	0	(210,000)	0
Proceeds from Sales of Assets	1,433,137	672,593	212,000
Changes in Components of Working Capital Associated with Investing Activities	(237,267)	208,933	(118,221)
Other, Net	0	7,082	(5,321)
Net Cash Used in Investing Activities	(5,754,942)	(4,902,774)	(3,414,551)
Financing Cash Flows
Common Stock Sold	1,388,265	0	0
Long-Term Debt Borrowings	0	2,478,659	900,000
Long-Term Debt Repayments	(220,000)	(37,000)	0
Dividends Paid	(167,169)	(153,240)	(142,260)
Excess Tax Benefits from Stock-Based Compensation	0	0	76,134
Treasury Stock Purchased	(23,922)	(11,295)	(10,986)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	35,913	34,560	20,465
Debt Issuance Costs	(4,787)	(8,300)	(8,895)
Other, Net	239	35	(296)
Net Cash Provided by Financing Activities	1,008,539	2,303,419	834,162
Effect of Exchange Rate Changes on Cash	(5,134)	(6,145)	12,390
(Decrease) Increase in Cash and Cash Equivalents	(173,127)	103,102	354,440
Cash and Cash Equivalents at Beginning of Year	788,853	685,751	331,311
Cash and Cash Equivalents at End of Year	$ 615,726	$ 788,853	$ 685,751

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Current Assets
Cash and Cash Equivalents	$ 615,726	$ 788,853
Accounts Receivable, Net	1,451,227	1,113,279
Inventories	590,594	415,792
Assets from Price Risk Management Activities	450,730	48,153
Income Taxes Receivable	26,609	54,916
Deferred Income Taxes	0	9,260
Other	119,052	97,193
Total	3,253,938	2,527,446
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	33,664,435	29,263,809
Other Property, Plant and Equipment	2,149,989	1,733,073
Total Property, Plant and Equipment	35,814,424	30,996,882
Less: Accumulated Depreciation, Depletion and Amortization	(14,525,600)	(12,315,982)
Total Property, Plant and Equipment, Net	21,288,824	18,680,900
Other Assets	296,035	415,887
Total Assets	24,838,797	21,624,233
Current Liabilities
Accounts Payable	2,033,615	1,664,944
Accrued Taxes Payable	147,105	82,168
Dividends Payable	42,578	38,962
Liabilities from Price Risk Management Activities	0	28,339
Deferred Income Taxes	135,989	41,703
Current Portion of Long-Term Debt	0	220,000
Other	163,032	143,983
Total	2,522,319	2,220,099
Long-Term Debt	5,009,166	5,003,341
Other Liabilities	799,189	667,455
Deferred Income Taxes	3,867,219	3,501,706
Commitments and Contingencies (Note 7)
Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 269,323,084 Shares and 254,223,521 Shares Issued at December 31, 2011 and 2010, respectively	202,693	202,542
Additional Paid in Capital	2,272,052	729,992
Accumulated Other Comprehensive Income	401,746	440,071
Retained Earnings	9,789,345	8,870,179
Common Stock Held in Treasury, 303,633 Shares and 146,186 Shares at December 31, 2011 and 2010, respectively	(24,932)	(11,152)
Total Stockholders' Equity	12,640,904	10,231,632
Total Liabilities and Stockholders' Equity	$ 24,838,797	$ 21,624,233

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Segment Information

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Segment Information

10.  Business Segment Information

EOG's operations are all crude oil and natural gas exploration and production related. The Segment Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual financial statements.  Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance.  EOG's chief operating decision making process is informal and involves the Chairman of the Board and Chief Executive Officer and other key officers.  This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States, Canada, Trinidad, the United Kingdom and China.  For segment reporting purposes, the chief operating decision maker considers the major United States producing areas to be one operating segment.

Financial information by reportable segment is presented below as of and for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	United									Other
	States			Canada			Trinidad			International (1)			Total
2011
Crude Oil and Condensate	$	3,458,248		$	264,895		$	112,554		$	2,587		$	3,838,284
Natural Gas Liquids		762,730			16,634			-			-			779,364
Natural Gas		1,593,964			178,324			442,589			25,663			2,240,540
Gains on Mark-to-Market Commodity Derivative Contracts		626,053			-			-			-			626,053
Gathering, Processing and Marketing		2,115,768			-			24			-			2,115,792
Gains on Asset Dispositions, Net		475,878			17,033			(2	)		-			492,909
Other, Net		32,329			258			586			-			33,173
Net Operating Revenues (2)		9,064,970			477,144			555,751			28,250			10,126,115
Depreciation, Depletion and Amortization		2,131,706			260,084			107,141			17,450			2,516,381
Operating Income (Loss)		2,252,508			(459,520	)		383,992			(63,671	)		2,113,309
Interest Income		436			342			101			140			1,019
Other Income (Expense)		(6,480	)		(2,375	)		18,755			(4,066	)		5,834
Net Interest Expense		214,360			23,085			-			(27,082	)		210,363
Income (Loss) Before Income Taxes		2,032,104			(484,638	)		402,848			(40,515	)		1,909,799
Income Tax Provision (Benefit)		732,362			(125,474	)		204,698			7,090			818,676
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		5,790,590			259,634			132,159			58,784			6,241,167
Total Property, Plant and Equipment, Net		18,711,774			1,760,066			627,794			189,190			21,288,824
Total Assets		21,313,158			2,131,949			1,085,664			308,026			24,838,797

2010
Crude Oil and Condensate	$	1,700,770		$	178,349		$	117,605	$	2,047		$	1,998,771
Natural Gas Liquids		448,647			13,698			-		-			462,345
Natural Gas		1,778,823			285,369			330,247		25,660			2,420,099
Gains on Mark-to-Market Commodity Derivative Contracts		61,912			-			-		-			61,912
Gathering, Processing and Marketing		909,660			-			20		-			909,680
Gains on Asset Dispositions, Net		196,774			23,112			3,652		-			223,538
Other, Net		19,886			(31	)		3,696		-			23,551
Net Operating Revenues (2)		5,116,472			500,497			455,220		27,707			6,099,896
Depreciation, Depletion and Amortization		1,539,240			315,849			71,085		15,752			1,941,926
Operating Income (Loss)		787,422			(516,874	)		312,128		(59,357	)		523,319
Interest Income		152			387			120		164			823
Other Income (Expense)		(3,905	)		2,067			14,022		1,236			13,420
Net Interest Expense		112,226			34,350			448		(17,438	)		129,586
Income (Loss) Before Income Taxes		671,443			(548,770	)		325,822		(40,519	)		407,976
Income Tax Provision (Benefit)		255,945			(146,495	)		140,934		(3,062	)		247,322
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		4,491,897			446,626			134,198		65,405			5,138,126
Total Property, Plant and Equipment, Net		15,747,808			2,189,961			595,970		147,161			18,680,900
Total Assets		17,762,533			2,598,412			954,391		308,897			21,624,233
2009
Crude Oil and Condensate	$	945,224		$	86,140		$	57,089	$	1,258		$	1,089,711
Natural Gas Liquids		246,821			11,978			-		-			258,799
Natural Gas		1,540,042			315,792			172,560		22,569			2,050,963
Gains on Mark-to-Market Commodity Derivative Contracts		431,757			-			-		-			431,757
Gathering, Processing and Marketing		407,097			-			19		-			407,116
Gains on Asset Dispositions, Net		535,295			141			-		-			535,436
Other, Net		9,693			(16	)		3,500		-			13,177
Net Operating Revenues (2)		4,115,929			414,035			233,168		23,827			4,786,959
Depreciation, Depletion and Amortization		1,282,180			211,514			47,119		8,375			1,549,188
Operating Income (Loss)		896,937			(31,767	)		143,993		(38,322	)		970,841
Interest Income		137			612			146		205			1,100
Other Income (Expense)		(7,396	)		5,212			4,387		(1,232	)		971
Net Interest Expense		84,411			28,934			1,332		(13,776	)		100,901
Income (Loss) Before Income Taxes		805,267			(54,877	)		147,194		(25,573	)		872,011
Income Tax Provision (Benefit)		290,473			(27,073	)		57,363		4,621			325,384
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		2,770,482			268,604			31,219		55,235			3,125,540
Total Property, Plant and Equipment, Net		12,769,240			2,740,473			532,989		96,523			16,139,225
Total Assets		14,108,129			2,888,949			813,901		307,688			18,118,667

(1) Other International primarily includes EOG's United Kingdom and China operations.

(2) EOG had no purchasers in 2011, 2010 or 2009 whose sales totaled 10 percent or more of consolidated Net Operating Revenues.

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Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2011	Feb. 17, 2012	Jun. 30, 2011
Document And Entity Information [Abstract]
Entity Registrant Name	EOG RESOURCES INC
Entity Central Index Key	0000821189
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 28,070,598,553
Entity Common Stock, Shares Outstanding		269,085,607
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011

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Risk Management Activities

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Risk Management Activities

11.  Risk Management Activities

Commodity Price Risks.  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 price swap, collar, option and basis swap contracts, as a means to manage this price risk.  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.  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.

During 2011, 2010 and 2009, EOG elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounted for these financial commodity derivative contracts using the mark-to-market accounting method.  During 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $626 million, which included net realized gains of $181 million.  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 losses of $1,278 million.

At December 31, 2011, the fair value of EOG's financial commodity derivative contracts was reflected on the Consolidated Balance Sheets as Current Assets - Assets from Price Risk Management Activities ($451 million) and Other Assets ($35 million).  At December 31, 2010, the fair value of EOG's financial commodity derivative contracts was reflected on the Consolidated Balance Sheets as Current Assets - Assets From Price Risk Management Activities ($48 million), Other Assets ($20 million), Current Liabilities - Liabilities from Price Risk Management Activities ($28 million) and Other Liabilities ($1 million).

Commodity Derivative Contracts.  Presented below is a comprehensive summary of EOG's crude oil derivative contracts at December 31, 2011, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl)

Crude Oil Derivative Contracts
			Weighted
	Volume		Average Price
	(Bbld)		($/Bbl)
2012 (1)
January 1, 2012 through June 30, 2012		34,000	$	104.95
July 1, 2012 through December 31, 2012		17,000		103.59

(1)   EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Such options are exercisable on June 29, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 17,000 Bbld at an average price of $106.31 per barrel for the period July 1, 2012 through December 31, 2012.

Presented below is a comprehensive summary of EOG's natural gas derivative contracts as of December 31, 2011, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Derivative Contracts
	Volume (MMBtud)		Weighted Average Price ($/MMBtu)
2012 (1)
January 2012 (closed)		525,000	$	5.44
February 1, 2012 through December 31, 2012		525,000		5.44
2013 (2)
January 1, 2013 through December 31, 2013		150,000	$	4.79
2014 (2)
January 1, 2014 through December 31, 2014		150,000	$	4.79

(1) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from February 1, 2012 through December 31, 2012.

(2) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2013 and 2014.

Foreign Currency Exchange Rate Derivative.EOG is party to a foreign currency aggregate swap transaction with multiple banks to eliminate any exchange rate impacts that may result from the $150 million principal amount of notes issued by one of EOG's Canadian subsidiaries.  EOG accounts for the foreign currency swap transaction using the hedge accounting method.  The fair value of the foreign currency swap was $(52) million at December 31, 2011 and $(55) million at December 31, 2010.  The after-tax net impact from the foreign currency swap resulted in a decrease in Other Comprehensive Income (OCI) of $1 million for the year ended December 31, 2011 and an increase in OCI of $3 million and $5 million for the years ended December 31, 2010 and 2009, respectively.

Interest Rate Derivative.  EOG is a party to an interest rate swap transaction with a counterparty bank.  The interest rate swap transaction was entered into in order to mitigate EOG's exposure to volatility in interest rates related to EOG's Floating Rate Notes issued on November 23, 2010.  The interest rate swap has a notional amount of $350 million and a fair value of $(3) million and $2 million at December 31, 2011 and 2010, respectively.  EOG accounts for the interest rate swap transaction using the hedge accounting method.  The after-tax impact from the interest rate swap resulted in a decrease in OCI of $3 million for the year ended December 31, 2011 and an increase in OCI of $1 million for the year ended December 31, 2010.

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding derivative financial instruments at December 31, 2011 and 2010, respectively.  Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

		Fair Value at December 31,
Description	Location on Balance Sheet	2011		2010
Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities	$	451	$	51
Noncurrent portion	Other Assets	$	35	$	18
Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities	$	-	$	30
Foreign currency swap -
Noncurrent portion	Other Liabilities	$	52	$	55
Interest rate swap -
Noncurrent portion	Other Assets	$	-	$	2
Other Liabilities		$	3	$	-

Credit Risk.  Notional contract amounts are used to express the magnitude of commodity price, foreign currency and interest rate swap agreements.  The amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 12).  EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions.  In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk.  At December 31, 2011, no individual purchaser's net accounts receivable balance related to United States, Canada and United Kingdom hydrocarbon sales accounted for 10% or more of the total balance.  At December 31, 2010, a crude oil marketing company's net accounts receivable balance related to United States, Canada and United Kingdom hydrocarbon sales accounted for 13% of the total balance.  The related amounts were collected during early 2011.  In 2011 and 2010, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago and all natural gas from EOG's China operations was sold to Petrochina Company Limited.

All of EOG's outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties.  The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings.  In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDA to be settled immediately.  See Note 12 for the aggregate fair value of all derivative instruments with credit-risk related contingent features that are in a net liability position at December 31, 2011 and 2010.  EOG had no collateral posted at both December 31, 2011 and 2010.

At December 31, 2011 and 2010, EOG had an allowance for doubtful accounts of $3 million and $14 million, respectively.

Substantially all of EOG's accounts receivable at December 31, 2011 and 2010 resulted from hydrocarbon sales and/or joint interest billings to third-party companies, including foreign state-owned entities in the oil and gas industry.  This concentration of customers and joint interest owners may impact EOG's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.  In determining whether or not to require collateral or other credit enhancements from a customer or joint interest owner, EOG typically analyzes the entity's net worth, cash flows, earnings and credit ratings.  Receivables are generally not collateralized.  During the three-year period ended December 31, 2011, credit losses incurred on receivables by EOG have been immaterial.

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Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2011	Dec. 31, 2010
Common Stock
Common Stock, Par (in dollars per share)	$ 0.01	$ 0.01
Common Shares Issued	269,323,084	254,223,521
Shares Authorized	640,000,000	640,000,000
Treasury Stock
Common Stock Held in Treasury	303,633	146,186

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Income Taxes

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Income Taxes [Text Block]

5.  Income Taxes

The principal components of EOG's net deferred income tax liabilities at December 31, 2011 and 2010 were as follows (in thousands):

	2011			2010
Current Deferred Income Tax Assets (Liabilities)
Commodity Hedging Contracts	$	-		$	(7,141	)
Deferred Compensation Plans		-			13,216
Other		-			3,185
Total Net Current Deferred Income Tax Assets	$	-		$	9,260
Noncurrent Deferred Income Tax Assets (Liabilities)
United Kingdom Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	(57,850	)	$	(16,611	)
United Kingdom Net Operating Loss		62,477			17,329
United Kingdom Other		314			226
Total Net Noncurrent Deferred Income Tax Assets	$	4,941		$	944
Current Deferred Income Tax (Assets) Liabilities
Commodity Hedging Contracts	$	158,302		$	-
Deferred Compensation Plans		(28,346	)		-
Timing Differences Associated with Different Year-ends in Foreign Jurisdictions		6,251			41,027
Other		(218	)		676
Total Net Current Deferred Income Tax Liabilities	$	135,989		$	41,703
Noncurrent Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,485,435		$	4,373,110
Non-Producing Leasehold Costs		(66,926	)		(78,846	)
Seismic Costs Capitalized for Tax		(111,862	)		(92,901	)
Equity Awards		(120,852	)		(99,447	)
Capitalized Interest		106,265			94,957
Net Operating Loss		(1,152,386	)		(498,893	)
Alternative Minimum Tax Credit Carryforward		(298,350	)		(214,873	)
Other		25,894			18,599
Total Net Noncurrent Deferred Income Tax Liabilities	$	3,867,219		$	3,501,706
Total Net Deferred Income Tax Liabilities	$	3,998,267		$	3,533,205

The components of Income Before Income Taxes for the years indicated below were as follows (in thousands):

	2011			2010			2009
United States	$	2,156,147		$	646,495		$	784,248
Foreign		(246,348	)		(238,519	)		87,763
Total	$	1,909,799		$	407,976		$	872,011

The principal components of EOG's Income Tax Provision for the years indicated below were as follows (in thousands):

	2011			2010			2009
Current:
Federal	$	94,244		$	17,154		$	95,194
State		1,083			(1,642	)		8,783
Foreign		224,049			155,565			47,015
Total		319,376			171,077			150,992
Deferred:
Federal		608,181			190,602			166,045
State		40,321			60,619			31,580
Foreign		(149,202	)		(174,976	)		(23,233	)
Total		499,300			76,245			174,392
Income Tax Provision	$	818,676		$	247,322		$	325,384

The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows:

		2011	2010	2009
Statutory Federal Income Tax Rate		35.00%	35.00%	35.00%
State Income Tax, Net of Federal Benefit		1.41	9.39	3.00
Income Tax Provision Related to Foreign Operations		0.88	(0.03)	(1.40)
Income Tax Provision Related to Trinidad Operations		3.37	6.26	0.60
Canadian Shallow Natural Gas Impairments		1.85	9.49	-
Other		0.36	0.51	0.11
	Effective Income Tax Rate	42.87%	60.62%	37.31%

The difference in the effective tax rate and the United States federal statutory rate of 35% is attributed principally to state and foreign income taxes.  The decrease in the state tax expense is attributable largely to the redetermination of the deferred state tax liability, which was reduced to reflect lower statutory state tax rates in North Dakota.  Foreign taxes had a smaller effect on EOG's worldwide tax rate due to smaller Canadian impairments, which are tax-effected at a statutory rate of 27%, and to higher domestic earnings.

The balance of unrecognized tax benefits at December 31, 2011 was $33 million, all of which, if recognized, would affect the effective tax rate.  EOG records interest and penalties related to unrecognized tax benefits to its income tax provision.  Currently, there are no amounts of interest or penalties recognized in the Consolidated Statements of Income and Comprehensive Income or in the Consolidated Balance Sheets.  EOG does not anticipate that the amount of the unrecognized tax benefits will significantly change during the next twelve months.  EOG and its subsidiaries file income tax returns in the United States and various state, local and foreign jurisdictions.  EOG is generally no longer subject to income tax examinations by tax authorities in the United States (federal), Canada, the United Kingdom, Trinidad and China for taxable years before 2005, 2007, 2010, 2004 and 2008, respectively.

EOG's foreign subsidiaries' undistributed earnings of approximately $2.3 billion at December 31, 2011 are considered to be indefinitely invested outside the United States and, accordingly, no United States federal or state income taxes have been provided thereon.  Upon distribution of those earnings, EOG may be subject to both foreign withholding taxes and United States income taxes, net of allowable foreign tax credits.  The amount of such additional taxes would be dependent on several factors, including the size and timing of the distribution, the particular foreign jurisdiction from which the distribution is made, and the availability of foreign tax credits.  As a result, the determination of the potential amount of unrecognized withholding and deferred income taxes is not practicable, though additional taxes resulting from a repatriation of foreign earnings could be significant.

In 2011, EOG generated a regular tax net operating loss (NOL) of $1.8 billion.  This NOL, along with the 2010 NOL of $1.4 billion, is expected to be carried forward and applied against regular taxable income in future periods.  To the extent not utilized, these NOL carryforwards will expire in 2030 and 2031, respectively.  Additionally, as of December 31, 2011, EOG had state income tax NOLs of approximately $700 million, which, if unused, expire between 2015 and 2031.  The Stock Compensation Topic of the ASC provides that when settlement of a stock award contributes to a NOL carryforward, neither the associated excess tax benefit nor the credit to additional paid in capital (APIC) should be recorded until the stock award deduction reduces income taxes payable.  Upon utilization of the NOLs in future periods, a benefit of $40 million will be reflected in APIC (including $23 million and $17 million related to 2011 and 2010, respectively).  In 2011, EOG paid alternative minimum tax (AMT) of $104 million.  The AMT paid in 2011, along with AMT of $194 million paid in prior years, will be carried forward indefinitely as a credit available to offset regular income taxes in future periods.

The ability of EOG to utilize both the regular tax NOL carryfowards and the AMT credit carryforwards to reduce regular federal taxable income and federal income taxes, respectively, may become subject to various limitations under the Internal Revenue Code.  Such limitations may arise if certain ownership changes (as defined for income tax purposes) were to occur.  As of December 31, 2011, we do not believe that an ownership change has occurred which would limit either carryforward.

During 2011, EOG's United Kingdom subsidiary incurred a tax NOL of approximately $71 million which, along with the 2010 NOL of $30 million, will be carried forward indefinitely.  In July 2011, the United Kingdom increased the statutory income tax rate applying to oil and gas activities from 50% to 62%, effective March 2011.  In December 2011, the United Kingdom increased from 6% to 10% a statutory deduction referred to as "Uplift," which is an upward adjustment to certain unused NOLs.  The increase in the Uplift percentage is effective January 1, 2012. These two changes did not have a material impact on EOG's 2011 earnings or cash flow.

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Other Income, Net

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Other Income, Net [Text Block]

4.  Other Income, Net

Other income, net for 2011 included equity income from investments in ammonia plants in Trinidad ($17 million), operating losses on EOG's investment in Pacific Trail Pipelines (PTP) in Canada ($5 million) and losses on sales of warehouse stock ($5 million).  Other income, net for 2010 included equity income from investments in ammonia plants in Trinidad ($13 million), net foreign currency transaction gains ($4 million) and losses on sales of warehouse stock ($4 million).

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Oil and Gas Exploration and Production Industries Disclosures

12 Months Ended

Dec. 31, 2011

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands, Except Per Share Data Unless Otherwise Indicated)

(Unaudited)

Oil and Gas Producing Activities

In December 2008, the United States Securities and Exchange Commission (SEC) released a final rule, "Modernization of Oil and Gas Reporting," which amended the oil and gas reporting requirements effective January 1, 2010.  The key revisions include:

�   using a 12-month average price to determine reserves;

�   including nontraditional resources in reserves if they are intended to be upgraded to synthetic oil and gas;

�   the ability to use reliable technologies to determine and estimate reserves;

�   permitting the optional disclosure of probable and possible reserves;

�   reporting the independence and qualifications of the reserve preparer or auditor and filing a report as an exhibit when a third party is relied upon to prepare reserve estimates or conduct reserve audits; and

�   disclosing the development of any proved undeveloped reserves, including the total quantity of proved undeveloped reserves at year-end, material changes to proved undeveloped reserves during the year, investments and progress toward the development of proved undeveloped reserves and an explanation of the reasons why material concentrations of proved undeveloped reserves have remained undeveloped for five years or more after disclosure as proved undeveloped reserves

In January 2010, the Financial Accounting Standards Board (FASB) issued FASB Accounting Standards Update (ASU) No. 2010-03, "Oil and Gas Reserve Estimations and Disclosures" (ASU 2010-03).  ASU 2010-03 aligns the current oil and gas reserve estimation and disclosure requirements of the Extractive Industries - Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule, "Modernization of Oil and Gas Reporting."  ASU No. 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009.

Oil and Gas Reserves.  Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir.  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.  Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.  Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.  See ITEM 1A. Risk Factors.

Proved reserves represent estimated quantities of crude oil, natural gas liquids and natural gas that geoscience and engineering data can estimate, with reasonable certainty, to be economically producible from a given day forward from known reservoirs under economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.  Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

In making estimates of proved undeveloped reserves, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its entire inventory of prospects.  In making a determination as to which of these locations would penetrate undrilled portions of the formation that can be judged, with reasonable certainty, to be continuous and contain economically producible crude oil and natural gas, studies are conducted using numerous data elements and analysis techniques.  EOG technical staff estimates the hydrocarbons in place, by mapping the entirety of the play in question using seismic techniques, typically employing two-dimensional and three-dimensional data.  This analysis is integrated with other static data including, but not limited to, core analysis, mechanical properties of the formation, thermal maturity indicators, and well logs of existing penetrations.  Highly specialized equipment is utilized to prepare rock samples in assessing microstructures which contribute to porosity and permeability.

Analysis of dynamic data is then incorporated to arrive at the estimated fractional recovery of hydrocarbons in place.  Data and analysis techniques employed include, but are not limited to, well testing, static bottom hole pressure, flowing bottom hole pressure, historical production trends using extant completion techniques (typically from vertical wells), pressure transient analysis and rate transient analysis.  Application of proprietary rate transient analysis techniques allow for quantification of estimates of contribution to production from both fractures and rock matrices.

The impact of optimal completion techniques is a key factor in determining if prospective locations are reasonably certain of being economically producible.  EOG's technical staff estimates recovery improvement that might be achieved when employing horizontal wells with multi-stage fracture stimulation.  In the early stages of development, EOG determines the optimal length of the horizontal lateral and multi-stage fracture stimulation using the aforementioned analysis techniques along with pilot drilling programs.

The process of analyzing static and dynamic data, well completion optimization and the results of early development provides the appropriate level of certainty as well as support for the economic producibilty of the plays in which proved undeveloped reserves are reflected.  EOG has found that this approach has been proven effective based on successful application in analogous reservoirs in resource plays.

EOG has formulated development plans for all locations related to its proved undeveloped reserves. 

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices, production volumes and the length, both vertical and horizontal, of wells.  Canadian reserves, as presented on a net basis, assume prices and legislated future royalty rates and EOG's estimate of future production volumes.  Similarly, certain of EOG's Trinidad reserves are held under production sharing contracts where EOG's interest varies with prices and production volumes.  Trinidad reserves, as presented on a net basis, assume prices in existence at the time the estimates were made and EOG's estimate of future production volumes.  Future fluctuations in prices, production rates or changes in political or regulatory environments could cause EOG's share of future production from Canadian and Trinidadian reserves to be materially different from that presented.

Estimates of proved reserves at December 31, 2011, 2010 and 2009 were based on studies performed by the engineering staff of EOG.  The Engineering and Acquisitions Department is directly responsible for EOG's reserve evaluation process and consists of seven professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and three are Registered Professional Engineers.  The Manager, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process.  The Manager, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 26 years of experience in reserve evaluations and is a Registered Professional Engineer in the State of Texas.

EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions Department in compliance with EOG's internal controls for such process.  Reserve information as well as models used to estimate such reserves are stored on secured databases.  Non-technical inputs used in reserve estimation models, including crude oil, natural gas liquids and natural gas prices, production costs, future capital expenditures and EOG's net ownership percentages are obtained from other departments within EOG.  EOG's Internal Audit Department conducts testing with respect to such non-technical inputs.  Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent petroleum consultants, to perform independent reserves evaluation of select EOG properties of not less than 75% of proved reserves.  EOG's Board of Directors requires that D&M's and EOG's reserve quantities for the properties evaluated by D&M vary by no more than 5% in the aggregate.  Once completed, EOG's year-end reserves are presented to senior management, including the Chairman of the Board and Chief Executive Officer; the President; the Chief Operating Officer; and the Vice President and Chief Financial Officer for approval.

Opinions by D&M for the years ended December 31, 2011, 2010 and 2009 covered producing areas containing 85%, 77% and 81%, respectively, of proved reserves of EOG on a net-equivalent-barrel-of-oil basis.  D&M's opinions indicate that the estimates of proved reserves prepared by EOG's Engineering and Acquisitions Department for the properties reviewed by D&M, when compared in total on a net-equivalent-barrel-of-oil basis, do not differ materially from the estimates prepared by D&M.  Such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the Engineering and Acquisitions Department of EOG.  All reports by D&M were developed utilizing geological and engineering data provided by EOG.  The report of D&M dated February 1, 2012, which contains further discussion of the reserve estimates and evaluations prepared by D&M, as well as the qualifications of D&M's technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 23.2 to this Annual Report on Form 10-K and incorporated herein by reference.

No major discovery or other favorable or adverse event subsequent to December 31, 2011 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2011, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2011, as estimated by the Engineering and Acquisitions Department of EOG:

NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY

		United			Other
		States	Canada	Trinidad	International (1)	Total
NET PROVED RESERVES
Crude Oil (MBbl) (2)
Net proved reserves at December 31, 2008		133,362	7,498	8,326	65	149,251
	Revisions of previous estimates	4,402	(183)	(1,760)	17	2,476
	Purchases in place	15,666	-	-	-	15,666
	Extensions, discoveries and other additions	58,258	19,783	-	-	78,041
	Sales in place	(5,742)	(20)	-	-	(5,762)
	Production	(17,494)	(1,492)	(1,123)	(24)	(20,133)
Net proved reserves at December 31, 2009		188,452	25,586	5,443	58	219,539
	Revisions of previous estimates	(8,313)	(104)	(754)	20	(9,151)
	Purchases in place	13	-	-	-	13
	Extensions, discoveries and other additions	199,479	3,198	1,751	48	204,476
	Sales in place	(1,082)	(589)	-	-	(1,671)
	Production	(23,092)	(2,455)	(1,709)	(28)	(27,284)
Net proved reserves at December 31, 2010		355,457	25,636	4,731	98	385,922
	Revisions of previous estimates	(21,188)	(4,611)	18	25	(25,756)
	Purchases in place	9	-	-	-	9
	Extensions, discoveries and other additions	202,552	449	-	-	203,001
	Sales in place	(4,301)	-	-	-	(4,301)
	Production	(37,233)	(2,882)	(1,242)	(25)	(41,382)
Net proved reserves at December 31, 2011		495,296	18,592	3,507	98	517,493
Natural Gas Liquids (MBbl) (2)
Net proved reserves at December 31, 2008		72,484	3,297	-	-	75,781
	Revisions of previous estimates	6,109	(926)	-	-	5,183
	Purchases in place	5,801	-	-	-	5,801
	Extensions, discoveries and other additions	18,546	24	-	-	18,570
	Sales in place	(3,231)	(30)	-	-	(3,261)
	Production	(8,220)	(393)	-	-	(8,613)
Net proved reserves at December 31, 2009		91,489	1,972	-	-	93,461
	Revisions of previous estimates	27,490	(196)	-	-	27,294
	Purchases in place	-	-	-	-	-
	Extensions, discoveries and other additions	42,221	21	-	-	42,242
	Sales in place	(2)	(6)	-	-	(8)
	Production	(10,764)	(316)	-	-	(11,080)
Net proved reserves at December 31, 2010		150,434	1,475	-	-	151,909
	Revisions of previous estimates	35,999	43	-	-	36,042
	Purchases in place	17	-	-	-	17
	Extensions, discoveries and other additions	65,288	-	-	-	65,288
	Sales in place	(10,008)	-	-	-	(10,008)
	Production	(15,144)	(316)	-	-	(15,460)
Net proved reserves at December 31, 2011		226,586	1,202	-	-	227,788

		United			Other
		States	Canada	Trinidad	International (1)	Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 2008		4,889.0	1,237.2	1,198.1	14.9	7,339.2
	Revisions of previous estimates	(378.0)	(447.2)	(104.9)	3.0	(927.1)
	Purchases in place	450.8	-	-	-	450.8
	Extensions, discoveries and other additions	1,925.0	846.5	-	-	2,771.5
	Sales in place	(114.4)	(5.1)	-	-	(119.5)
	Production	(422.3)	(81.9)	(107.4)	(5.2)	(616.8)
Net proved reserves at December 31, 2009		6,350.1	1,549.5	985.8	12.7	8,898.1
	Revisions of previous estimates	(222.7)	(29.9)	(88.6)	1.9	(339.3)
	Purchases in place	-	-	-	-	-
	Extensions, discoveries and other additions	821.3	3.4	63.0	7.9	895.6
	Sales in place	(34.6)	(316.2)	-	-	(350.8)
	Production	(422.6)	(73.0)	(132.6)	(5.2)	(633.4)
Net proved reserves at December 31, 2010		6,491.5	1,133.8	827.6	17.3	8,470.2
	Revisions of previous estimates	(344.0)	(49.8)	(24.2)	1.3	(416.7)
	Purchases in place	3.0	-	-	-	3.0
	Extensions, discoveries and other additions	634.6	-	74.7	4.5	713.8
	Sales in place	(323.6)	-	-	-	(323.6)
	Production	(415.7)	(48.1)	(127.4)	(4.6)	(595.8)
Net proved reserves at December 31, 2011		6,045.8	1,035.9	750.7	18.5	7,850.9
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2008		1,020,671	217,002	208,013	2,548	1,448,234
	Revisions of previous estimates	(52,487)	(75,638)	(19,250)	515	(146,860)
	Purchases in place	96,605	-	-	-	96,605
	Extensions, discoveries and other additions	397,642	160,882	-	-	558,524
	Sales in place	(28,032)	(898)	-	-	(28,930)
	Production	(96,107)	(15,540)	(19,016)	(891)	(131,554)
Net proved reserves at December 31, 2009		1,338,292	285,808	169,747	2,172	1,796,019
	Revisions of previous estimates	(17,945)	(5,288)	(15,513)	342	(38,404)
	Purchases in place	14	-	-	-	14
	Extensions, discoveries and other additions	378,582	3,789	12,250	1,363	395,984
	Sales in place	(6,860)	(53,288)	-	-	(60,148)
	Production	(104,277)	(14,937)	(23,815)	(901)	(143,930)
Net proved reserves at December 31, 2010		1,587,806	216,084	142,669	2,976	1,949,535
	Revisions of previous estimates	(42,526)	(12,865)	(4,011)	239	(59,163)
	Purchases in place	521	-	-	-	521
	Extensions, discoveries and other additions	373,602	448	12,455	750	387,255
	Sales in place	(68,247)	-	-	-	(68,247)
	Production	(121,648)	(11,219)	(22,484)	(787)	(156,138)
Net proved reserves at December 31, 2011		1,729,508	192,448	128,629	3,178	2,053,763

(1) Other International includes EOG's United Kingdom and China operations.

(2) Thousand barrels or thousand 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.

(3) Billion cubic feet.

During 2011, EOG added 387 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Barnett Combo and Bakken shale plays.  Approximately 69% of the 2011 reserve additions were crude oil and condensate and natural gas liquids and over 96% were in the United States.  Sales in place of 68 MMBoe were primarily related to the disposition of certain producing natural gas assets in East Texas, the Rocky Mountain region and other producing basins in the United States.  Revisions of previous estimates of negative 59 MMBoe for 2011 included a negative revision of 16 MMBoe primarily due to a decrease in the average natural gas price used in the December 31, 2011 reserves estimation as compared to the price used in the prior year estimate.  Revisions other than price resulted from negative performance revisions for certain crude oil and natural gas properties in the United States, Canada and Trinidad.

During 2010, EOG added 396 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Bakken, Barnett Combo and Haynesville shale plays.  Approximately 62% of the 2010 reserve additions were crude oil and condensate and natural gas liquids and over 95% were in the United States.  Sales in place of 60 MMBoe were primarily related to the Canadian shallow natural gas assets and certain producing natural gas assets in East Texas.  Revisions of previous estimates of negative 38 MMBoe for 2010 included a positive revision of 28 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2010 reserves estimation as compared to the price used in the prior year estimate.  Revisions other than price resulted from negative performance revisions for certain natural gas properties in the United States, Canada and Trinidad and the removal of proved undeveloped natural gas drilling locations from the five-year drilling plan to focus on crude oil and liquids-rich drilling as part of EOG's overall strategy.

During 2009, EOG added 558 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Haynesville, Horn River, Barnett, Bakken and Marcellus shale plays.  Approximately 82% of the 2009 reserve additions were natural gas.  EOG's revisions of previous estimates for 2009 of negative 147 MMBoe included negative revisions of approximately 131 MMBoe, which were primarily due to the decrease in the average natural gas price used in the December 31, 2009 reserves estimation as compared to the price used in the prior year estimate.  Purchases in place include the reserves acquired in the Rocky Mountain property exchange and the acquisition of certain Barnett Shale Combo Assets in Montague and Cooke Counties, Texas.  Sales in place primarily include reserves from the properties relinquished in the Rocky Mountain property exchange and from the California asset sale.  See Note 16 to Consolidated Financial Statements.

		United			Other
		States	Canada	Trinidad	International (1)	Total
NET PROVED DEVELOPED RESERVES
Liquids (MBbl) (2)
	December 31, 2008	159,607	10,416	6,756	65	176,844
	December 31, 2009	189,322	10,831	3,966	58	204,177
	December 31, 2010	253,308	12,758	3,853	98	270,017
	December 31, 2011	338,144	9,220	2,657	97	350,118
Natural Gas (Bcf) (3)
	December 31, 2008	3,544.7	1,103.7	889.0	14.9	5,552.3
	December 31, 2009	3,330.1	681.0	609.4	12.7	4,633.2
	December 31, 2010	3,519.7	401.6	519.2	17.3	4,457.8
	December 31, 2011	3,234.9	295.8	606.3	18.6	4,155.6
Oil Equivalents (MBoe) (2)
	December 31, 2008	750,389	194,360	154,939	2,548	1,102,236
	December 31, 2009	744,339	124,323	105,540	2,172	976,374
	December 31, 2010	839,928	79,701	90,382	2,976	1,012,987
	December 31, 2011	877,301	58,524	103,710	3,178	1,042,713
NET PROVED UNDEVELOPED RESERVES
Liquids (MBbl) (2)
	December 31, 2008	46,239	379	1,570	-	48,188
	December 31, 2009	90,619	16,727	1,477	-	108,823
	December 31, 2010	252,583	14,352	879	-	267,814
	December 31, 2011	383,739	10,574	850	-	395,163
Natural Gas (Bcf) (3)
	December 31, 2008	1,344.3	133.6	309.0	-	1,786.9
	December 31, 2009	3,020.0	868.5	376.4	-	4,264.9
	December 31, 2010	2,971.7	732.2	308.5	-	4,012.4
	December 31, 2011	2,810.8	740.1	144.4	-	3,695.3
Oil Equivalents (MBoe) (2)
	December 31, 2008	270,282	22,642	53,074	-	345,998
	December 31, 2009	593,953	161,486	64,207	-	819,646
	December 31, 2010	747,878	136,383	52,287	-	936,548
	December 31, 2011	852,207	133,924	24,919	-	1,011,050

(1) Other International includes EOG's United Kingdom and China operations.

(2) Thousand barrels or thousand 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.

(3) Billion cubic feet.

For the twelve-month period ended December 31, 2011, total proved undeveloped reserves (PUDs) increased by 75 MMBoe to 1,011 MMBoe.  EOG added approximately 36 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on page F-34 of this Annual Report on Form 10-K), EOG added 199 MMBoe.  The proved undeveloped reserve additions were primarily in the Eagle Ford and Barnett Combo shale plays, and over 78% of the additions were crude oil and condensate and natural gas liquids.  During 2011, EOG drilled and transferred 144 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,619 million.  Revisions of PUDs totaled negative 7 MMBoe, primarily due to removal of certain natural gas PUDs from the five-year drilling plan.  During 2011, EOG sold 9 MMBoe of PUDs.

For the twelve-month period ended December 31, 2010, total PUDs increased by 117 MMBoe to 937 MMBoe.  EOG added approximately 37 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on page F-34 of this Annual Report on Form 10-K), EOG added 218 MMBoe.  The proved undeveloped reserve additions were primarily in the Eagle Ford, Bakken, Barnett Combo and Haynesville shale plays, and nearly 73% of the additions were crude oil and condensate and natural gas liquids.  During 2010, EOG drilled and transferred 118 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,280 million.  Revisions of PUDs totaled negative 12 MMBoe, primarily due to removal of certain natural gas PUDs from the five-year drilling plan.  During 2010, EOG sold 8 MMBoe of PUDs.

For the twelve-month period ended December 31, 2009, total PUDs increased by 474 MMBoe to 820 MMBoe.  Based on the definition of PUDs and its applicability to large resource plays (see discussion of technology employed on page F-34 of this Annual Report on Form 10-K), EOG added 445 MMBoe of PUDs, primarily in the Haynesville, Horn River, Barnett Combo and Marcellus shale plays.  Purchases in place included 70 MMBoe of PUDs from the Rocky Mountain property exchange and the acquisition of Barnett Combo assets (see Note 16 to Consolidated Financial Statements).  During 2009, EOG drilled and transferred approximately 29 MMBoe of PUDs to proved developed reserves at a total capital cost of $280 million.  Revisions of PUDs totaled negative 9 MMBoe.

As of December 31, 2011, EOG did not have a material amount of reserves that have remained undeveloped for five years or more.

Capitalized Costs Relating to Oil and Gas Producing Activities.  The following table sets forth the capitalized costs relating to EOG's crude oil and natural gas producing activities at December 31, 2011 and 2010:

	2011			2010
Proved properties	$	32,353,380		$	27,693,700
Unproved properties		1,311,055			1,570,109
Total		33,664,435			29,263,809
Accumulated depreciation, depletion and amortization		(13,981,143	)		(11,859,870	)
Net capitalized costs	$	19,683,292		$	17,403,939

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities.  The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive Industries - Oil and Gas Topic of the ASC.

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property.

Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses.

Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2011, 2010 and 2009:

	United							Other
	States		Canada			Trinidad		International (1)			Total
2011
Acquisition Costs of Properties
Unproved	$	295,160	$	6,216		$	-	$	(604	)	$	300,772
Proved		4,219		28			-		-			4,247
Subtotal		299,379		6,244			-		(604	)		305,019
Exploration Costs		311,369		31,472			2,549		18,164			363,554
Development Costs (2)		5,410,378		302,564			138,905		78,744			5,930,591
Total	$	6,021,126	$	340,280		$	141,454	$	96,304		$	6,599,164
2010
Acquisition Costs of Properties
Unproved	$	403,509	$	13,956		$	-	$	(107	)	$	417,358
Proved		-		-			-		-			-
Subtotal		403,509		13,956			-		(107	)		417,358
Exploration Costs		454,379		38,604			23,386		86,784			603,153
Development Costs (3)		3,892,403		417,176			114,986		13,429			4,437,994
Total	$	4,750,291	$	469,736		$	138,372	$	100,106		$	5,458,505
2009
Acquisition Costs of Properties
Unproved	$	648,331	$	17,806		$	800	$	(311	)	$	666,626
Proved (4)		464,362		(33	)		-		-			464,329
Subtotal		1,112,693		17,773			800		(311	)		1,130,955
Exploration Costs		473,489		51,164			14,263		71,872			610,788
Development Costs (5)		1,898,859		237,613			27,369		1,914			2,165,755
Total	$	3,485,041	$	306,550		$	42,432	$	73,475		$	3,907,498

(1) Other International primarily consists of EOG's United Kingdom and China operations.

(2) Includes Asset Retirement Costs of $52 million, $70 million, $7 million and $4 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

(3) Includes Asset Retirement Costs of $71 million, $2 million, $(3) million and $2 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

(4) Includes non-cash acquisition costs of $353 million related to a property exchange transaction in the Rocky Mountain area.

(5) Includes Asset Retirement Costs of $60 million, $18 million, $6 million and zero for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

Results of Operations for Oil and Gas Producing Activities (1).  The following tables set forth results of operations for oil and gas producing activities for the years ended December 31, 2011, 2010 and 2009:

	United							Other
	States		Canada			Trinidad		International (2)			Total
2011
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	5,814,942	$	459,853		$	555,143	$	28,250		$	6,858,188
Other		32,329		258			586		-			33,173
Total		5,847,271		460,111			555,729		28,250			6,891,361
Exploration Costs		148,199		10,479			2,520		10,460			171,658
Dry Hole Costs		30,521		432			-		22,277			53,230
Transportation Costs		421,060		5,969			1,620		1,673			430,322
Production Costs		1,096,955		174,973			49,318		10,964			1,332,210
Impairments		575,976		452,103			-		2,958			1,031,037
Depreciation, Depletion and Amortization		2,011,080		258,772			106,802		17,160			2,393,814
Income (Loss) Before Income Taxes		1,563,480		(442,617	)		395,469		(37,242	)		1,479,090
Income Tax Provision (Benefit)		569,153		(121,044	)		202,815		(13,056	)		637,868
Results of Operations	$	994,327	$	(321,573	)	$	192,654	$	(24,186	)	$	841,222
2010
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	3,928,240	$	477,416		$	447,852	$	27,707		$	4,881,215
Other		19,886		(31	)		3,696		-			23,551
Total		3,948,126		477,385			451,548		27,707			4,904,766
Exploration Costs		156,252		17,597			2,277		11,255			187,381
Dry Hole Costs		30,927		14,875			5,000		21,684			72,486
Transportation Costs		372,466		9,892			1,348		1,483			385,189
Production Costs		763,769		174,667			51,125		8,504			998,065
Impairments		271,466		451,703			1,465		418			725,052
Depreciation, Depletion and Amortization		1,430,408		314,663			70,553		15,399			1,831,023
Income (Loss) Before Income Taxes		922,838		(506,012	)		319,780		(31,036	)		705,570
Income Tax Provision (Benefit)		375,855		(151,315	)		140,413		(14,245	)		350,708
Results of Operations	$	546,983	$	(354,697	)	$	179,367	$	(16,791	)	$	354,862
2009
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	2,732,088	$	413,910		$	229,649	$	23,826		$	3,399,473
Other		9,692		(15	)		3,500		-			13,177
Total		2,741,780		413,895			233,149		23,826			3,412,650
Exploration Costs		137,696		18,675			5,107		8,114			169,592
Dry Hole Costs		39,570		1,461			-		10,212			51,243
Transportation Costs		270,940		9,317			1,141		1,931			283,329
Production Costs		556,236		145,292			27,616		9,452			738,596
Impairments		272,195		32,996			-		641			305,832
Depreciation, Depletion and Amortization		1,188,243		210,509			46,608		7,966			1,453,326
Income (Loss) Before Income Taxes		276,900		(4,355	)		152,677		(14,490	)		410,732
Income Tax Provision (Benefit)		106,537		(1,276	)		58,681		(6,067	)		157,875
Results of Operations	$	170,363	$	(3,079	)	$	93,996	$	(8,423	)	$	252,857

(1) Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2011.

(2) Other International primarily consists of EOG's United Kingdom and China operations.

The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2011, 2010 and 2009:

	United						Other
	States		Canada		Trinidad		International (1)		Composite
Year Ended December 31, 2011	$	6.19	$	14.26	$	0.78	$	13.82	$	6.03
Year Ended December 31, 2010	$	5.00	$	10.28	$	0.65	$	9.34	$	4.85
Year Ended December 31, 2009	$	4.43	$	8.41	$	0.74	$	10.52	$	4.40

(1)      Other International primarily consists of EOG's United Kingdom and China operations.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves.  The following information has been developed utilizing procedures prescribed by the Extractive Industries - Oil and Gas Topic of the ASC and based on crude oil, natural gas liquids and natural gas reserves and production volumes estimated by the Engineering and Acquisitions Department of EOG.  The estimates were based on a 12-month average for commodity prices for the years 2011, 2010 and 2009.  The following information  may be useful for certain comparison purposes, but should not be solely relied upon in evaluating EOG or its performance.  Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections.  It is expected that material revisions to some estimates of crude oil, natural gas liquids and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions.  Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2011, 2010 and 2009:

	United									Other
	States			Canada			Trinidad			International (1)			Total
2011
Future cash inflows (2)	$	84,518,638		$	5,056,501		$	2,851,545		$	103,853		$	92,530,537
Future production costs		(33,294,343	)		(2,315,110	)		(388,199	)		(62,938	)		(36,060,590	)
Future development costs		(13,811,449	)		(1,566,917	)		(149,884	)		(331	)		(15,528,581	)
Future income taxes		(10,539,182	)		(81,590	)		(794,856	)		(2,457	)		(11,418,085	)
Future net cash flows		26,873,664			1,092,884			1,518,606			38,127			29,523,281
Discount to present value at 10% annual rate		(12,498,010	)		(456,537	)		(334,399	)		(9,054	)		(13,298,000	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	14,375,654		$	636,347		$	1,184,207		$	29,073		$	16,225,281
2010
Future cash inflows (3)	$	62,063,123		$	6,040,422		$	2,760,819		$	91,805		$	70,956,169
Future production costs		(22,616,039	)		(2,711,415	)		(384,147	)		(48,953	)		(25,760,554	)
Future development costs		(9,596,005	)		(1,716,734	)		(198,072	)		(334	)		(11,511,145	)
Future income taxes		(8,503,301	)		(129,816	)		(850,699	)		(3,598	)		(9,487,414	)
Future net cash flows		21,347,778			1,482,457			1,327,901			38,920			24,197,056
Discount to present value at 10% annual rate		(10,718,854	)		(736,222	)		(339,035	)		(11,121	)		(11,805,232	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	10,628,924		$	746,235		$	988,866		$	27,799		$	12,391,824
2009
Future cash inflows (4)	$	34,506,336		$	6,887,530		$	2,133,778		$	52,738		$	43,580,382
Future production costs		(11,977,152	)		(2,537,001	)		(398,318	)		(27,791	)		(14,940,262	)
Future development costs		(5,696,619	)		(2,255,088	)		(264,104	)		(346	)		(8,216,157	)
Future income taxes		(5,307,041	)		(249,986	)		(525,873	)		(4,276	)		(6,087,176	)
Future net cash flows		11,525,524			1,845,455			945,483			20,325			14,336,787
Discount to present value at 10% annual rate		(5,702,608	)		(808,211	)		(279,920	)		(5,030	)		(6,795,769	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	5,822,916		$	1,037,244		$	665,563		$	15,295		$	7,541,018

(1) Other International includes EOG's United Kingdom and China operations.

(2) Estimated crude oil prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $97.75, $90.70, $92.50 and $102.86, respectively.  Estimated natural gas liquids prices used to calculate 2011 future cash inflows for the United States and Canada were $51.77  and $46.97, respectively.  Estimated natural gas prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $4.03, $3.28, $3.37, and $5.07, respectively.

(3) Estimated crude oil prices used to calculate 2010 future cash inflows for the United States, Canada, Trinidad and Other International were $76.38, $72.59, $69.56 and $73.88, respectively.  Estimated natural gas liquids prices used to calculate 2010 future cash inflows for the United States and Canada were $43.85 and $26.56, respectively.  Estimated natural gas prices used to calculate 2010 future cash inflows for the United States, Canada, Trinidad and Other International were $4.36, $3.67, $2.94 and $5.02, respectively.

(4) Estimated crude oil prices used to calculate 2009 future cash inflows for the United States, Canada, Trinidad and Other International were $53.64, $56.85, $51.35 and $52.87, respectively.  Estimated natural gas liquids prices used to calculate 2009 future cash inflows for the United States and Canada were $28.75 and $19.31, respectively.  Estimated natural gas prices used to calculate 2009 future cash inflows for the United States, Canada, Trinidad and Other International were $3.43, $3.50, $1.88 and $3.92, respectively.

Changes in Standardized Measure of Discounted Future Net Cash Flows.  The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2011:

	United									Other
	States			Canada			Trinidad			International			Total
December 31, 2008	$	6,307,712		$	1,751,152		$	601,053		$	19,984		$	8,679,901
Sales and transfers of oil and gas produced, net of production costs		(1,904,912	)		(259,301	)		(200,892	)		(12,443	)		(2,377,548	)
Net changes in prices and production costs		(1,482,778	)		(902,629	)		338,053			(13,868	)		(2,061,222	)
Extensions, discoveries, additions and improved recovery, net of related costs		1,702,471			259,305			-			-			1,961,776
Development costs incurred		344,500			14,200			-			-			358,700
Revisions of estimated
development cost		595,875			68,883			(3,380	)		4,555			665,933
Revisions of previous quantity estimates		(422,294	)		(425,018	)		(124,222	)		1,016			(970,518	)
Accretion of discount		829,631			199,330			84,521			3,232			1,116,714
Net change in income taxes		261,513			259,169			(105,766	)		9,847			424,763
Purchases of reserves in place		209,130			-			-			-			209,130
Sales of reserves in place		(264,482	)		(13,912	)		-			-			(278,394	)
Changes in timing and other		(353,450	)		86,065			76,196			2,972			(188,217	)
December 31, 2009		5,822,916			1,037,244			665,563			15,295			7,541,018
Sales and transfers of oil and gas produced, net of production costs		(2,792,005	)		(292,857	)		(395,379	)		(17,720	)		(3,497,961	)
Net changes in prices and production costs		2,468,907			(559	)		721,796			7,259			3,197,403
Extensions, discoveries, additions and improved recovery, net of related costs		4,319,659			75,162			183,453			-			4,578,274
Development costs incurred		864,700			175,100			67,300			-			1,107,100
Revisions of estimated development cost		(257,360	)		260,290			(767	)		9			2,172
Revisions of previous quantity estimates		(164,748	)		(38,382	)		(175,002	)		4,006			(374,126	)
Accretion of discount		755,001			102,022			101,549			1,778			960,350
Net change in income taxes		(1,171,384	)		101,966			(258,354	)		2,469			(1,325,303	)
Purchases of reserves in place		265			-			-			-			265
Sales of reserves in place		(54,057	)		(290,592	)		-			-			(344,649	)
Changes in timing and other		837,030			(383,159	)		78,707			14,703			547,281
December 31, 2010		10,628,924			746,235			988,866			27,799			12,391,824
Sales and transfers of oil and gas produced, net of production costs		(4,296,926	)		(278,910	)		(504,205	)		(15,614	)		(5,095,655	)
Net changes in prices and production costs		716,682			(57,545	)		331,196			3,328			993,661
Extensions, discoveries, additions and improved recovery, net of related costs		6,223,552			22,591			102,548			-			6,348,691
Development costs incurred		1,422,500			48,200			74,800			-			1,545,500
Revisions of estimated development cost		(210,919	)		64,001			(14,074	)		2			(160,990	)
Revisions of previous quantity estimates		(482,496	)		(70,718	)		(56,884	)		801			(609,297	)
Accretion of discount		1,352,740			62,725			159,715			2,782			1,577,962
Net change in income taxes		(1,049,641	)		(118,988	)		9,511			13			(1,159,105	)
Purchases of reserves in place		5,241			-			-			-			5,241
Sales of reserves in place		(658,468	)		-			-			-			(658,468	)
Changes in timing and other		724,465			218,756			92,734			9,962			1,045,917
December 31, 2011	$	14,375,654		$	636,347		$	1,184,207		$	29,073		$	16,225,281

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Fair Value Measurements [Text Block]

12.  Fair Value Measurements

Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets.  An established fair value hierarchy prioritizes the relative reliability of inputs used in fair value measurements.  The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date.  Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy.  EOG gives consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value.

The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2011 and 2010 (in millions):

	Fair Value Measurements Using:
	Quoted		Significant
	Prices in		Other		Significant
	Active		Observable		Unobservable
	Markets		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
At December 31, 2011
Financial Assets:
Crude Oil and Natural Gas Derivative Contracts	$	-	$	110	$	-	$	110
Crude Oil and Natural Gas Options/Swaptions		-		376		-		376
Financial Liabilities:
Foreign Currency Rate Swap	$	-	$	52	$	-	$	52
Interest Rate Swap		-		3		-		3
At December 31, 2010
Financial Assets:
Natural Gas Derivative Contracts	$	-	$	62	$	-	$	62
Natural Gas Options/Swaptions		-		6		-		6
Interest Rate Swap		-		2		-		2
Financial Liabilities:
Crude Oil and Natural Gas Derivative Contracts	$	-	$	29	$	-	$	29
Foreign Currency Rate Swap		-		55		-		55
Contingent Consideration		-		-		14		14

The estimated fair value of crude oil and natural gas derivative contracts and interest rate swap contracts (see Note 11) was based upon forward commodity price and interest rate curves based on quoted market prices.  The estimated fair value of the foreign currency rate swap was based upon forward currency rates.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment.  Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives.  A reconciliation of EOG's asset retirement obligations is presented in Note 14.

During 2011, proved oil and gas properties with a carrying amount of $1,450 million were written down to their fair value of $616 million, resulting in pretax impairment charges of $834 million.  In connection with a $278 million impairment of certain natural gas assets in the U.S. during 2011, EOG utilized accepted bids as the basis for determining fair value.  During 2010, proved oil and gas properties and other property, plant and equipment with a carrying amount of $1,013 million were written down to their fair value of $487 million, resulting in pretax impairment charges of $418 million in Canada, $107 million in the United States and $1 million in Trinidad.  In connection with the $280 million impairment of shallow natural gas assets sold in Canada during the fourth quarter of 2010, EOG utilized accepted bids adjusted for estimates of customary closing adjustments less selling costs as the basis for determining fair value.  Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.  In connection with certain impairments of proved oil and gas properties and other property, plant and equipment, EOG utilized an accepted offer from a third-party buyer.

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Net Income Per Share

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Net Income Per Share [Text Block]

8.  Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2011, 2010 and 2009 (in thousands, except per share data):

	2011		2010		2009
Numerator for Basic and Diluted Earnings per Share -
Net Income	$	1,091,123	$	160,654	$	546,627
Denominator for Basic Earnings per Share -
Weighted Average Shares		262,735		250,876		248,996
Potential Dilutive Common Shares -
Stock Options/SARs		1,707		1,991		1,691
Restricted Stock and Restricted Stock Units		1,826		1,633		1,197
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares		266,268		254,500		251,884
Net Income Per Share
Basic	$	4.15	$	0.64	$	2.20
Diluted	$	4.10	$	0.63	$	2.17

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive.  The excluded stock options and SARs totaled 0.4 million, 0.3 million and 2.5 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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Oil and Gas Exploration and Production Industries Disclosures, Discounted Future Net Cash Flows (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 84,518,638	$ 62,063,123	$ 34,506,336
Future production costs	(33,294,343)	(22,616,039)	(11,977,152)
Future development costs	(13,811,449)	(9,596,005)	(5,696,619)
Future income taxes	(10,539,182)	(8,503,301)	(5,307,041)
Future net cash flows	26,873,664	21,347,778	11,525,524
Discount to present value at 10% annual rate	(12,498,010)	(10,718,854)	(5,702,608)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	14,375,654	10,628,924	5,822,916
Per unit price used to calculate future cash inflows - Crude Oil	97.75	76.38	53.64
Per unit price used to calculate future cash inflows - Natural Gas Liquids	51.77	43.85	28.75
Per unit price used to calculate future cash inflows - Natural Gas	4.03	4.36	3.43
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period	10,628,924	5,822,916	6,307,712
Sales and transfers of oil and gas produced net of production costs	(4,296,926)	(2,792,005)	(1,904,912)
Net changes in prices and production costs	716,682	2,468,907	(1,482,778)
Extensions, discoveries, additions and improved recovery, net of related costs	6,223,552	4,319,659	1,702,471
Development costs incurred	1,422,500	864,700	344,500
Revisions of estimated development costs	(210,919)	(257,360)	595,875
Revisions of previous quantity estimates	(482,496)	(164,748)	(422,294)
Accretion of discount	1,352,740	755,001	829,631
Net change in income taxes	(1,049,641)	(1,171,384)	261,513
Purchases of reserves in place	5,241	265	209,130
Sales of reserves in place	(658,468)	(54,057)	(264,482)
Changes in timing and other	724,465	837,030	(353,450)
Balance at End of Period	14,375,654	10,628,924	5,822,916
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	5,056,501	6,040,422	6,887,530
Future production costs	(2,315,110)	(2,711,415)	(2,537,001)
Future development costs	(1,566,917)	(1,716,734)	(2,255,088)
Future income taxes	(81,590)	(129,816)	(249,986)
Future net cash flows	1,092,884	1,482,457	1,845,455
Discount to present value at 10% annual rate	(456,537)	(736,222)	(808,211)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	636,347	746,235	1,037,244
Per unit price used to calculate future cash inflows - Crude Oil	90.70	72.59	56.85
Per unit price used to calculate future cash inflows - Natural Gas Liquids	46.97	26.56	19.31
Per unit price used to calculate future cash inflows - Natural Gas	3.28	3.67	3.50
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period	746,235	1,037,244	1,751,152
Sales and transfers of oil and gas produced net of production costs	(278,910)	(292,857)	(259,301)
Net changes in prices and production costs	(57,545)	(559)	(902,629)
Extensions, discoveries, additions and improved recovery, net of related costs	22,591	75,162	259,305
Development costs incurred	48,200	175,100	14,200
Revisions of estimated development costs	64,001	260,290	68,883
Revisions of previous quantity estimates	(70,718)	(38,382)	(425,018)
Accretion of discount	62,725	102,022	199,330
Net change in income taxes	(118,988)	101,966	259,169
Purchases of reserves in place	0	0	0
Sales of reserves in place	0	(290,592)	(13,912)
Changes in timing and other	218,756	(383,159)	86,065
Balance at End of Period	636,347	746,235	1,037,244
Trinidad [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	2,851,545	2,760,819	2,133,778
Future production costs	(388,199)	(384,147)	(398,318)
Future development costs	(149,884)	(198,072)	(264,104)
Future income taxes	(794,856)	(850,699)	(525,873)
Future net cash flows	1,518,606	1,327,901	945,483
Discount to present value at 10% annual rate	(334,399)	(339,035)	(279,920)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	1,184,207	988,866	665,563
Per unit price used to calculate future cash inflows - Crude Oil	92.50	69.56	51.35
Per unit price used to calculate future cash inflows - Natural Gas	3.37	2.94	1.88
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period	988,866	665,563	601,053
Sales and transfers of oil and gas produced net of production costs	(504,205)	(395,379)	(200,892)
Net changes in prices and production costs	331,196	721,796	338,053
Extensions, discoveries, additions and improved recovery, net of related costs	102,548	183,453	0
Development costs incurred	74,800	67,300	0
Revisions of estimated development costs	(14,074)	(767)	(3,380)
Revisions of previous quantity estimates	(56,884)	(175,002)	(124,222)
Accretion of discount	159,715	101,549	84,521
Net change in income taxes	9,511	(258,354)	(105,766)
Purchases of reserves in place	0	0	0
Sales of reserves in place	0	0	0
Changes in timing and other	92,734	78,707	76,196
Balance at End of Period	1,184,207	988,866	665,563
Other International [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	103,853	91,805	52,738
Future production costs	(62,938)	(48,953)	(27,791)
Future development costs	(331)	(334)	(346)
Future income taxes	(2,457)	(3,598)	(4,276)
Future net cash flows	38,127	38,920	20,325
Discount to present value at 10% annual rate	(9,054)	(11,121)	(5,030)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	29,073	27,799	15,295
Per unit price used to calculate future cash inflows - Crude Oil	102.86	73.88	52.87
Per unit price used to calculate future cash inflows - Natural Gas	5.07	5.02	3.92
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period	27,799	15,295	19,984
Sales and transfers of oil and gas produced net of production costs	(15,614)	(17,720)	(12,443)
Net changes in prices and production costs	3,328	7,259	(13,868)
Extensions, discoveries, additions and improved recovery, net of related costs	0	0	0
Development costs incurred	0	0	0
Revisions of estimated development costs	2	9	4,555
Revisions of previous quantity estimates	801	4,006	1,016
Accretion of discount	2,782	1,778	3,232
Net change in income taxes	13	2,469	9,847
Purchases of reserves in place	0	0	0
Sales of reserves in place	0	0	0
Changes in timing and other	9,962	14,703	2,972
Balance at End of Period	$ 29,073	$ 27,799	$ 15,295

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Pension Plans and Postretirement Benefits and Stock-Based Compensation [Text Block]

6.  Employee Benefit Plans

Stock-Based Compensation

During 2011, EOG maintained various stock-based compensation plans as discussed below.  EOG recognizes compensation expense on grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock and restricted stock units and grants made under its Employee Stock Purchase Plan (ESPP).  Stock-based compensation expense is calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate.  Compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval.

Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon job functions of the employees receiving the grants.  Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2011, 2010 and 2009 was as follows (in millions):

	2011		2010		2009
Lease and Well	$	33	$	27	$	23
Gathering and Processing Costs		1		1		-
Exploration Costs		26		24		21
General and Administrative		68		55		51
Total	$	128	$	107	$	95

The EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, SARs, restricted stock, restricted stock units and other stock-based awards up to an aggregate maximum of 12.9 million shares plus shares underlying forfeited or cancelled grants under prior stock plans.  At December 31, 2011, approximately 5.4 million shares of Common Stock remained available for grant under the 2008 Plan.  Effective with the adoption of the 2008 Plan, EOG's policy is to issue shares related to the 2008 Plan from either previously authorized unissued shares or treasury shares, to the extent treasury shares are available.

During 2011, 2010 and 2009, EOG issued shares in connection with stock option/SAR exercises, restricted stock grants, restricted stock unit releases and ESPP purchases.  EOG recognized, as an adjustment to APIC, federal income tax (expense)/benefits of $25,000, $(1) million and $76 million for 2011, 2010 and 2009, respectively, related to the exercise of stock options/SARs and the release of restricted stock and restricted stock units.

Stock Options and Stock Appreciation Rights and Employee Stock Purchase Plan.  Participants in EOG's stock plans (including the 2008 Plan) have been or may be granted options to purchase shares of Common Stock.  In addition, participants in EOG's stock plans (including the 2008 Plan) have been or may be granted SARs, representing the right to receive shares of Common Stock based on the appreciation in the stock price from the date of grant on the number of SARs granted.  Stock options and SARs are granted at a price not less than the market price of the Common Stock on the date of grant.  Stock options and SARs granted vest on a graded vesting schedule up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements.  Terms for stock options and SARs granted have not exceeded a maximum term of 10 years.  EOG's ESPP allows eligible employees to semi-annually purchase, through payroll deductions, shares of Common Stock at 85 percent of the fair market value at specified dates.  Contributions to the ESPP are limited to 10 percent of the employee's pay (subject to certain ESPP limits) during each of the two six-month offering periods each year.

The fair value of all ESPP grants is estimated using the Black-Scholes-Merton model.  The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option pricing model.  Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $48 million, $41 million and $38 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2011, 2010 and 2009 were as follows:

	Stock Options/SARs									ESPP
	2011			2010			2009			2011			2010			2009
Weighted Average Fair Value of Grants	$	29.92		$	32.12		$	30.13		$	22.75		$	25.45		$	25.78
Expected Volatility		40.96	%		39.70	%		41.90	%		29.82	%		38.30	%		78.89	%
Risk-Free Interest Rate		0.58	%		0.87	%		1.42	%		0.14	%		0.18	%		0.25	%
Dividend Yield		0.70	%		0.70	%		0.70	%		0.70	%		0.70	%		1.00	%
Expected Life	5.6 yrs			5.5 yrs			5.5 yrs			0.5 yrs			0.5 yrs			0.5 yrs

Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's Common Stock.  The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant.  The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants.

The following table sets forth the stock option and SAR transactions for the years ended December 31, 2011, 2010 and 2009 (stock options and SARs in thousands):

	2011					2010					2009
	Number			Weighted		Number			Weighted		Number			Weighted
	of Stock			Average		of Stock			Average		Of Stock			Average
	Options/			Grant		Options/			Grant		Options/			Grant
	SARs			Price		SARs			Price		SARs			Price
Outstanding at January 1		8,445		$	64.49		8,335		$	57.08		7,802		$	52.56
Granted		1,509			85.29		1,450			93.07		1,270			80.95
Exercised (1)		(1,399	)		50.86		(1,144	)		43.38		(636	)		46.56
Forfeited		(181	)		87.74		(196	)		84.22		(101	)		74.07
Outstanding at December 31		8,374			70.01		8,445			64.49		8,335			57.08
Stock Options/SARs Exercisable at December 31		5,148			59.19		5,439			51.71		5,394			44.45

(1) The total intrinsic value of stock options/SARs exercised during the years 2011, 2010 and 2009 was $78.4 million, $66.0 million and $21.4 million, respectively.  The intrinsic value is based upon the difference between the market price of Common Stock on the date of exercise and the grant price of the stock options/SARs.

At December 31, 2011, there were 8,123,226 stock options/SARs vested or expected to vest with a weighted average grant price of $69.48 per share, an intrinsic value of $238.5 million and a weighted average remaining contractual life of 3.6 years.

The following table summarizes certain information for the stock options and SARs outstanding at December 31, 2011 (stock options and SARs in thousands):

		Stock Options/SARs Outstanding							Stock Options/SARs Exercisable
				Weighted							Weighted
				Average		Weighted					Average		Weighted
Range of		Stock		Remaining		Average		Aggregate	Stock		Remaining		Average		Aggregate
Grant		Options/		Life		Grant		Intrinsic	Options/		Life		Grant		Intrinsic
Prices		SARs		(Years)		Price		Value(1)	SARs		(Years)		Price		Value(1)
$	16.00 to $ 48.99		1,431		1	$	20.30			1,431		1	$	20.30
49.00 to  69.99			1,623		1		61.99			1,609		1		61.94
70.00 to  81.99			1,674		4		78.17			1,159		4		76.66
82.00 to  88.99			2,174		6		85.44			576		4		88.73
89.00 to 136.99			1,472		5		95.09			373		5		96.56
			8,374		4		70.01	$241,474		5,148		2		59.19	$203,646

(1) Based upon the difference between the closing market price of Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs.

At December 31, 2011, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $87.9 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.8 years.

At December 31, 2011, approximately 790,000 shares of Common Stock remained available for issuance under the ESPP.  The following table summarizes ESPP activities for the years ended December 31, 2011, 2010 and 2009 (in thousands, except number of participants):

	2011		2010		2009
Approximate Number of Participants		1,525		1,236		1,128
Shares Purchased		135		114		72
Aggregate Purchase Price	$	10,947	$	9,172	$	4,150

Restricted Stock and Restricted Stock Units.  Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them.  The restricted stock and restricted stock units generally vest five years after the date of grant, except for certain bonus grants, and as defined in individual grant agreements.  Upon vesting of restricted stock, shares of Common Stock are released to the employee.  Upon vesting, restricted stock units are converted into shares of Common Stock and released to the employee.  Stock-based compensation expense related to restricted stock and restricted stock units totaled $80 million, $66 million and $57 million for the years ended December 31, 2011, 2010 and 2009, respectively.

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2011, 2010 and 2009 (shares and units in thousands):

	2011					2010					2009
				Weighted					Weighted					Weighted
	Number of			Average		Number of			Average		Number of			Average
	Shares and			Grant Date		Shares and			Grant Date		Shares and			Grant Date
	Units			Fair Value		Units			Fair Value		Units			Fair Value
Outstanding at January 1		4,009		$	79.13		3,636		$	73.69		3,048		$	70.24
Granted		932			90.87		850			93.39		1,197			63.13
Released (1)		(457	)		66.10		(364	)		58.00		(553	)		31.35
Forfeited		(244	)		82.45		(113	)		79.37		(56	)		78.18
Outstanding at December 31(2)		4,240			82.93		4,009			79.13		3,636			73.69

(1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2011, 2010 and 2009 was $44.4 million, $35.2 million and $36.9 million, respectively.  The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.

(2) The aggregate intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2011 and 2010 was approximately $417.7 million and $366.4 million, respectively.

At December 31, 2011, unrecognized compensation expense related to restricted stock and restricted stock units totaled $132.6 million.  Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.4 years.

Pension Plans.  EOG has a non-contributory defined contribution pension plan and a matched defined contribution savings plan in place for most of its employees in the United States (such plans were merged into a single plan, effective as of January 1, 2012).  EOG's contributions to these pension plans are based on various percentages of compensation and, in some instances, are based upon the amount of the employees' contributions.  EOG's total costs recognized for these plans were $27.1 million, $23.4 million and $21.8 million for 2011, 2010 and 2009, respectively.

In addition, EOG's Canadian subsidiary maintains both a non-contributory defined benefit pension plan and a non-contributory defined contribution pension plan, as well as a matched defined contribution savings plan.  EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan.  EOG's United Kingdom subsidiary maintains a pension plan which includes a non-contributory defined contribution pension plan and a matched defined contribution savings plan.  With the exception of Canada's non-contributory defined benefit pension plan, which is closed to new employees, these pension plans are available to most employees of the Canadian, Trinidadian and United Kingdom subsidiaries.  EOG's combined contributions to these plans were $2.5 million, $2.8 million and $2.6 million for 2011, 2010 and 2009, respectively.

For the Canadian and Trinidadian defined benefit pension plans, the benefit obligation, fair value of plan assets and prepaid/(accrued) benefit cost totaled $11.3 million, $8.2 million and $(1.6) million, respectively, at December 31, 2011 and $10.3 million, $8.7 million and $(0.8) million, respectively, at December 31, 2010.

Postretirement Health Care.  EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents, the costs of which are not material.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Commitments and Contingencies [Text Block]

7.  Commitments and Contingencies

Letters of Credit.  At December 31, 2011, EOG had standby letters of credit and guarantees outstanding totaling approximately $585 million, of which $150 million represents guarantees of subsidiary indebtedness (see Note 2) and $435 million primarily represents guarantees of payment obligations on behalf of subsidiaries.  At December 31, 2010, EOG had standby letters of credit and guarantees outstanding totaling approximately $657 million, of which $370 million represents guarantees of subsidiary indebtedness (see Note 2) and $287 million primarily represents guarantees of payment obligations on behalf of subsidiaries.  As of February 24, 2012, there were no demands for payment under these guarantees.

Minimum Commitments.  At December 31, 2011, total minimum commitments from long-term non-cancelable operating leases, drilling rig commitments, seismic purchase obligations, fracturing services obligations, other purchase obligations and transportation and storage service commitments, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars and British pounds into United States dollars at December 31, 2011, are as follows (in thousands):

	Total Minimum
	Commitments
2012	$	1,185,759
2013 - 2014		1,013,735
2015 - 2016		925,514
2017 and beyond		1,435,506
	$	4,560,514

Included in the table above are leases for buildings, facilities and equipment with varying expiration dates through 2026.  Rental expenses associated with existing leases amounted to $149 million, $95 million and $77 million for 2011, 2010 and 2009, respectively.

Contingencies.  There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes.  While the ultimate outcome and impact on EOG cannot be predicted, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow.  EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Supplemental Cash Flow Information [Text Block]

9.  Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	2011		2010		2009
Interest, Net of Capitalized Interest	$	186,718	$	146,731	$	100,939
Income Taxes, Net of Refunds Received	$	260,224	$	233,462	$	51,684

EOG's accrued capital expenditures at December 31, 2011, 2010 and 2009 were $663 million, $709 million and $334 million, respectively.

Non-cash investing and financing activities for the year ended December 31, 2009 included the following (see Note 16):

�   the issuance of 1,450,000 shares of Common Stock valued at $90 million at the transaction closing date in connection with EOG's purchase of certain proved developed and undeveloped reserves and unproved acreage; and

�   non-cash additions to EOG's oil and gas properties in the amount of $353 million in connection with EOG's asset exchange agreement in respect of certain natural gas-related properties.

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Selected Financial Information by Reportable Segment

Financial information by reportable segment is presented below as of and for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	United									Other
	States			Canada			Trinidad			International (1)			Total
2011
Crude Oil and Condensate	$	3,458,248		$	264,895		$	112,554		$	2,587		$	3,838,284
Natural Gas Liquids		762,730			16,634			-			-			779,364
Natural Gas		1,593,964			178,324			442,589			25,663			2,240,540
Gains on Mark-to-Market Commodity Derivative Contracts		626,053			-			-			-			626,053
Gathering, Processing and Marketing		2,115,768			-			24			-			2,115,792
Gains on Asset Dispositions, Net		475,878			17,033			(2	)		-			492,909
Other, Net		32,329			258			586			-			33,173
Net Operating Revenues (2)		9,064,970			477,144			555,751			28,250			10,126,115
Depreciation, Depletion and Amortization		2,131,706			260,084			107,141			17,450			2,516,381
Operating Income (Loss)		2,252,508			(459,520	)		383,992			(63,671	)		2,113,309
Interest Income		436			342			101			140			1,019
Other Income (Expense)		(6,480	)		(2,375	)		18,755			(4,066	)		5,834
Net Interest Expense		214,360			23,085			-			(27,082	)		210,363
Income (Loss) Before Income Taxes		2,032,104			(484,638	)		402,848			(40,515	)		1,909,799
Income Tax Provision (Benefit)		732,362			(125,474	)		204,698			7,090			818,676
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		5,790,590			259,634			132,159			58,784			6,241,167
Total Property, Plant and Equipment, Net		18,711,774			1,760,066			627,794			189,190			21,288,824
Total Assets		21,313,158			2,131,949			1,085,664			308,026			24,838,797

2010
Crude Oil and Condensate	$	1,700,770		$	178,349		$	117,605	$	2,047		$	1,998,771
Natural Gas Liquids		448,647			13,698			-		-			462,345
Natural Gas		1,778,823			285,369			330,247		25,660			2,420,099
Gains on Mark-to-Market Commodity Derivative Contracts		61,912			-			-		-			61,912
Gathering, Processing and Marketing		909,660			-			20		-			909,680
Gains on Asset Dispositions, Net		196,774			23,112			3,652		-			223,538
Other, Net		19,886			(31	)		3,696		-			23,551
Net Operating Revenues (2)		5,116,472			500,497			455,220		27,707			6,099,896
Depreciation, Depletion and Amortization		1,539,240			315,849			71,085		15,752			1,941,926
Operating Income (Loss)		787,422			(516,874	)		312,128		(59,357	)		523,319
Interest Income		152			387			120		164			823
Other Income (Expense)		(3,905	)		2,067			14,022		1,236			13,420
Net Interest Expense		112,226			34,350			448		(17,438	)		129,586
Income (Loss) Before Income Taxes		671,443			(548,770	)		325,822		(40,519	)		407,976
Income Tax Provision (Benefit)		255,945			(146,495	)		140,934		(3,062	)		247,322
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		4,491,897			446,626			134,198		65,405			5,138,126
Total Property, Plant and Equipment, Net		15,747,808			2,189,961			595,970		147,161			18,680,900
Total Assets		17,762,533			2,598,412			954,391		308,897			21,624,233
2009
Crude Oil and Condensate	$	945,224		$	86,140		$	57,089	$	1,258		$	1,089,711
Natural Gas Liquids		246,821			11,978			-		-			258,799
Natural Gas		1,540,042			315,792			172,560		22,569			2,050,963
Gains on Mark-to-Market Commodity Derivative Contracts		431,757			-			-		-			431,757
Gathering, Processing and Marketing		407,097			-			19		-			407,116
Gains on Asset Dispositions, Net		535,295			141			-		-			535,436
Other, Net		9,693			(16	)		3,500		-			13,177
Net Operating Revenues (2)		4,115,929			414,035			233,168		23,827			4,786,959
Depreciation, Depletion and Amortization		1,282,180			211,514			47,119		8,375			1,549,188
Operating Income (Loss)		896,937			(31,767	)		143,993		(38,322	)		970,841
Interest Income		137			612			146		205			1,100
Other Income (Expense)		(7,396	)		5,212			4,387		(1,232	)		971
Net Interest Expense		84,411			28,934			1,332		(13,776	)		100,901
Income (Loss) Before Income Taxes		805,267			(54,877	)		147,194		(25,573	)		872,011
Income Tax Provision (Benefit)		290,473			(27,073	)		57,363		4,621			325,384
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		2,770,482			268,604			31,219		55,235			3,125,540
Total Property, Plant and Equipment, Net		12,769,240			2,740,473			532,989		96,523			16,139,225
Total Assets		14,108,129			2,888,949			813,901		307,688			18,118,667

(1) Other International primarily includes EOG's United Kingdom and China operations.

(2) EOG had no purchasers in 2011, 2010 or 2009 whose sales totaled 10 percent or more of consolidated Net Operating Revenues.

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Financial Assets:
Financial Assets: Crude Oil and Natural Gas Derivative Contracts		$ 62
Financial Assets: Crude Oil and Natural Gas Options/Swaptions		6
Financial Liabilities:
Proved oil and gas properties and other property, plant and equipment written down to fair value during the period - carrying amount	1,450	1,013
Proved Oil and Gas Properties and Other Property, Plant and Equipment Written Down During the Period - Fair value at End of Period	616	487
Impairment Charge for Proved Oil and Gas Properties (Pretax) in Canada		418
Impairment Charge for Proved Oil and Gas Properties (Pretax) in the United States	278	107
Impairment Charge for Proved Oil and Gas Properties (Pretax) in Trinidad		1
Impairment Charge for Shallow Natural Gas Assets Sold in Canada		280
Impairment Charge for Proved Oil and Gas Properties and Other Property, Plant and Equipment (Pretax) in the United States	834
Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Financial Assets: Crude Oil and Natural Gas Derivative Contracts	0	0
Financial Assets: Crude Oil and Natural Gas Options/Swaptions	0	0
Financial Assets: Interest Rate Swaps		0
Financial Liabilities:
Financial Liabilities: Foreign Currency Rate Swap	0	0
Financial Liabilities: Contingent Consideration (see Note 17)	0	0
Financial Liabilities: Crude Oil and Natural Gas Derivative Contracts		0
Financial Liabilities: Interest Rate Swap	0
Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Financial Assets: Crude Oil and Natural Gas Derivative Contracts	110
Financial Assets: Crude Oil and Natural Gas Options/Swaptions	376
Financial Assets: Interest Rate Swaps		2
Financial Liabilities:
Financial Liabilities: Foreign Currency Rate Swap	52	55
Financial Liabilities: Contingent Consideration (see Note 17)		0
Financial Liabilities: Crude Oil and Natural Gas Derivative Contracts		29
Financial Liabilities: Interest Rate Swap	3
Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Financial Assets: Crude Oil and Natural Gas Derivative Contracts	0	0
Financial Assets: Crude Oil and Natural Gas Options/Swaptions	0	0
Financial Assets: Interest Rate Swaps		0
Financial Liabilities:
Financial Liabilities: Foreign Currency Rate Swap	0	0
Financial Liabilities: Contingent Consideration (see Note 17)		14
Financial Liabilities: Crude Oil and Natural Gas Derivative Contracts		0
Financial Liabilities: Interest Rate Swap	$ 0

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Asset Retirement Obligations [Text Block]

14.  Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2011 and 2010 (in thousands):

	2011			2010
Carrying Amount at Beginning of Period	$	498,288		$	456,484
Liabilities Incurred		68,703			39,480
Liabilities Settled (1)		(66,129	)		(30,763	)
Accretion		27,907			25,456
Revisions		58,786			1,640
Foreign Currency Translations		(471	)		5,991
Carrying Amount at End of Period	$	587,084		$	498,288
Current Portion	$	29,527		$	32,005
Noncurrent Portion	$	557,557		$	466,283

(1)      Includes settlements related to asset sales.

The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Principles of Consolidation

Principles of Consolidation.  The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries.  Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method.  All intercompany accounts and transactions have been eliminated.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Financial Instruments

Financial Instruments.  EOG's financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt, along with associated foreign currency and interest rate swaps.  The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable, foreign currency and interest rate swaps and accounts payable approximate fair value (see Notes 2 and 11).

Cash and Cash Equivalents

Cash and Cash Equivalents.  EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.

Oil and Gas Operations

Oil and Gas Operations.  EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.

Oil and gas lease acquisition costs are capitalized when incurred.  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.  If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred.  The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered proved commercial reserves.  If proved commercial reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 15).  Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method.  The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.  With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.  Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Oil and gas properties are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC).  The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.

When circumstances indicate that an asset 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, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated using the income approach described in the Fair Value Measurements and Disclosures Topic of the ASC.  If applicable, EOG utilizes accepted bids as the basis for determining fair value.

Inventories, consisting primarily of tubular goods, materials for completion operations and well equipment held for use in the exploration for, and development and production of, crude oil and natural gas reserves, are carried at cost with adjustments made, as appropriate, to recognize any reductions in value.

Arrangements for crude oil and condensate, natural gas liquids and natural gas sales are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered.  A significant majority of the purchasers of these products have investment grade credit ratings and material credit losses have been rare.  Revenues are recorded on the entitlement method based on EOG's percentage ownership of current production.  Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold on that owner's behalf may differ from that owner's ownership percentage.  Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs.  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.

Other Property, Plant and Equipment

Other Property, Plant and Equipment.  Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, crude-by-rail assets, sand mine and sand processing assets, computer hardware and software, vehicles, and furniture and fixtures.  Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 40 years.

Capitalized Interest Costs

Capitalized Interest Costs.  Interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties.  The amount capitalized is an allocation of the interest cost incurred during the reporting period.  Capitalized interest is computed only during the exploration and development phases and ceases once production begins.  The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings.

Accounting for Price Risk Management Activities

Accounting for Risk Management Activities.  Derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  During the three-year period ended December 31, 2011, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges, and accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change.  The gains or losses are recorded as Gains on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income.  The related cash flow impact is reflected as cash flows from operating activities.  See Note 11.  EOG is party to a foreign currency swap transaction and an interest rate swap transaction (see Note 2).  EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement.

Income Taxes

Income Taxes.  Income taxes are accounted for using the asset and liability approach.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis (see Note 5).

Foreign Currency Translation

Foreign Currency Translation.  The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for certain of its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary, for which the functional currency is the British pound.  For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year.  Translation adjustments are included in Accumulated Other Comprehensive Income on the Consolidated Balance Sheets.  Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period.

Net Income Per Share

Net Income Per Share.  Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods.  Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the periods plus the assumed issuance of common shares for all potentially dilutive securities (see Note 8).

Stock-Based Compensation

Stock-Based Compensation.  EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (see Note 6).

Recently Issued Accounting Standards and Developments

Recently Issued Accounting Standards.  In May 2011, the FASB issued Accounting Standards Update (ASU) 2011-04, "Fair Value Measurement (Topic 820):  Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs".  ASU 2011-04 amends the Fair Value Measurements and Disclosures Topic of the ASC to clarify the FASB's intent about the application of existing fair value measurement requirements and change certain principles or requirements for measuring fair value or disclosing information about fair value measurements.  ASU 2011-04 is effective for interim and annual fiscal periods beginning after December 15, 2011.  EOG does not expect that the adoption of ASU 2011-04 will have a material impact on its financial statements, but it may result in additional disclosures regarding fair value measurements.

In June 2011, the FASB issued ASU 2011-05 "Comprehensive Income (Topic 220): Presentation of Comprehensive Income."  ASU 2011-05 is intended to increase the prominence of comprehensive income in the financial statements by requiring that an entity that reports items of comprehensive income do so in either one continuous or two consecutive financial statements.  ASU 2011-05 also requires separate presentation on the face of the financial statements for items reclassified from other comprehensive income into net income.  Subsequently, in December 2011, the FASB deferred the effective date of the provisions of ASU 2011-05 relating to the presentation of reclassification adjustments out of accumulated other comprehensive income. The provisions of ASU 2011-05 not deferred by the FASB are effective for interim and annual fiscal periods beginning after December 15, 2011.  Retroactive application is required.  EOG does not expect that the adoption of ASU 2011-05 will have a material impact on its financial statements, but it may result in additional disclosures regarding components of comprehensive income.

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate	$ 3,838,284	$ 1,998,771	$ 1,089,711
Natural Gas Liquids	779,364	462,345	258,799
Natural Gas	2,240,540	2,420,099	2,050,963
Gains on Mark-to-Market Commodity Derivative Contracts	(626,053)	(61,912)	(431,757)
Gathering, Processing and Marketing	2,115,792	909,680	407,116
Gains on Asset Dispositions, Net	492,909	223,538	535,436
Other, Net	33,173	23,551	13,177
Net Operating Revenues (2)	10,126,115	6,099,896	4,786,959
Depreciation, Depletion and Amortization	2,516,381	1,941,926	1,549,188
Operating Income (Loss)	2,113,309	523,319	970,841
Interest Income	1,019	823	1,100
Other Income (Expense)	5,834	13,420	971
Net Interest Expense	210,363	129,586	100,901
Income (Loss) Before Income Taxes	1,909,799	407,976	872,011
Income Tax Provision (Benefit)	818,676	247,322	325,384
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,241,167	5,138,126	3,125,540
Total Property, Plant and Equipment, Net	21,288,824	18,680,900	16,139,225
Total Assets	24,838,797	21,624,233	18,118,667
United States [Member]
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate	3,458,248	1,700,770	945,224
Natural Gas Liquids	762,730	448,647	246,821
Natural Gas	1,593,964	1,778,823	1,540,042
Gains on Mark-to-Market Commodity Derivative Contracts	626,053	61,912	431,757
Gathering, Processing and Marketing	2,115,768	909,660	407,097
Gains on Asset Dispositions, Net	475,878	196,774	535,295
Other, Net	32,329	19,886	9,693
Net Operating Revenues (2)	9,064,970	5,116,472	4,115,929
Depreciation, Depletion and Amortization	2,131,706	1,539,240	1,282,180
Operating Income (Loss)	2,252,508	787,422	896,937
Interest Income	436	152	137
Other Income (Expense)	(6,480)	(3,905)	(7,396)
Net Interest Expense	214,360	112,226	84,411
Income (Loss) Before Income Taxes	2,032,104	671,443	805,267
Income Tax Provision (Benefit)	732,362	255,945	290,473
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	5,790,590	4,491,897	2,770,482
Total Property, Plant and Equipment, Net	18,711,774	15,747,808	12,769,240
Total Assets	21,313,158	17,762,533	14,108,129
Canada [Member]
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate	264,895	178,349	86,140
Natural Gas Liquids	16,634	13,698	11,978
Natural Gas	178,324	285,369	315,792
Gains on Mark-to-Market Commodity Derivative Contracts	0	0	0
Gathering, Processing and Marketing	0	0	0
Gains on Asset Dispositions, Net	17,033	23,112	141
Other, Net	258	(31)	(16)
Net Operating Revenues (2)	477,144	500,497	414,035
Depreciation, Depletion and Amortization	260,084	315,849	211,514
Operating Income (Loss)	(459,520)	(516,874)	(31,767)
Interest Income	342	387	612
Other Income (Expense)	(2,375)	2,067	5,212
Net Interest Expense	23,085	34,350	28,934
Income (Loss) Before Income Taxes	(484,638)	(548,770)	(54,877)
Income Tax Provision (Benefit)	(125,474)	(146,495)	(27,073)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	259,634	446,626	268,604
Total Property, Plant and Equipment, Net	1,760,066	2,189,961	2,740,473
Total Assets	2,131,949	2,598,412	2,888,949
Trinidad [Member]
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate	112,554	117,605	57,089
Natural Gas Liquids	0	0	0
Natural Gas	442,589	330,247	172,560
Gains on Mark-to-Market Commodity Derivative Contracts	0	0	0
Gathering, Processing and Marketing	24	20	19
Gains on Asset Dispositions, Net	(2)	3,652	0
Other, Net	586	3,696	3,500
Net Operating Revenues (2)	555,751	455,220	233,168
Depreciation, Depletion and Amortization	107,141	71,085	47,119
Operating Income (Loss)	383,992	312,128	143,993
Interest Income	101	120	146
Other Income (Expense)	18,755	14,022	4,387
Net Interest Expense	0	448	1,332
Income (Loss) Before Income Taxes	402,848	325,822	147,194
Income Tax Provision (Benefit)	204,698	140,934	57,363
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	132,159	134,198	31,219
Total Property, Plant and Equipment, Net	627,794	595,970	532,989
Total Assets	1,085,664	954,391	813,901
Other International [Member]
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate	2,587	2,047	1,258
Natural Gas Liquids	0	0	0
Natural Gas	25,663	25,660	22,569
Gains on Mark-to-Market Commodity Derivative Contracts	0	0	0
Gathering, Processing and Marketing	0	0	0
Gains on Asset Dispositions, Net	0	0	0
Other, Net	0	0	0
Net Operating Revenues (2)	28,250	27,707	23,827
Depreciation, Depletion and Amortization	17,450	15,752	8,375
Operating Income (Loss)	(63,671)	(59,357)	(38,322)
Interest Income	140	164	205
Other Income (Expense)	(4,066)	1,236	(1,232)
Net Interest Expense	(27,082)	(17,438)	(13,776)
Income (Loss) Before Income Taxes	(40,515)	(40,519)	(25,573)
Income Tax Provision (Benefit)	7,090	(3,062)	4,621
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	58,784	65,405	55,235
Total Property, Plant and Equipment, Net	189,190	147,161	96,523
Total Assets	$ 308,026	$ 308,897	$ 307,688

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Long-Term Debt (Details)			12 Months Ended					12 Months Ended			12 Months Ended		12 Months Ended		12 Months Ended								12 Months Ended		12 Months Ended									12 Months Ended
	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2011 Uncommitted Credit Facility [Member] USD ($)	Dec. 31, 2011 Commercial Paper [Member] USD ($)	Dec. 31, 2011 Revolving Credit Agreement 2005 [Member] USD ($)	Dec. 31, 2011 Revolving Credit Agreement 2010 [Member] USD ($)	Dec. 31, 2010 Subsidiary Revolving Credit Facility 2010 [Member] USD ($)	Dec. 31, 2011 Revolving Credit Agreement 2011 [Member] USD ($)	Dec. 31, 2011 Senior Notes Due 2013 [Member] USD ($)	Dec. 31, 2010 Senior Notes Due 2013 [Member] USD ($)	Dec. 31, 2010 Floating Rate Senior Notes Due 2014 [Member] USD ($)	Dec. 31, 2011 Floating Rate Senior Notes Due 2014 [Member] USD ($)	Dec. 31, 2010 Senior Notes Due 2015 [Member] USD ($)	Dec. 31, 2011 Senior Notes Due 2015 [Member] USD ($)	Dec. 31, 2010 Senior Notes Due 2016 [Member] USD ($)	Dec. 31, 2011 Senior Notes Due 2016 [Member] USD ($)	Dec. 31, 2011 Senior Notes Due 2017 [Member] USD ($)	Dec. 31, 2010 Senior Notes Due 2017 [Member] USD ($)	Dec. 31, 2011 Senior Notes Due 2018 [Member] USD ($)	Dec. 31, 2010 Senior Notes Due 2018 [Member] USD ($)	Dec. 31, 2011 Senior Notes Due 2019 [Member] USD ($)	Dec. 31, 2010 Senior Notes Due 2019 [Member] USD ($)	Dec. 31, 2010 Senior Notes Due 2020 [Member] USD ($)	Dec. 31, 2011 Senior Notes Due 2020 [Member] USD ($)	Dec. 31, 2010 Senior Notes Due 2021 [Member] USD ($)	Dec. 31, 2011 Senior Notes Due 2021 [Member] USD ($)	Dec. 31, 2011 Senior Notes Due 2028 [Member] USD ($)	Dec. 31, 2010 Senior Notes Due 2028 [Member] USD ($)	Dec. 31, 2011 Subsidiary Debt Due 2011 [Member] USD ($)	Dec. 31, 2010 Subsidiary Debt Due 2011 [Member] USD ($)	Dec. 31, 2011 Subsidiary Debt Due 2014 [Member] USD ($)	Dec. 31, 2010 Subsidiary Debt Due 2014 [Member] USD ($)	Dec. 31, 2010 Subsidiary Debt Due 2014 [Member] CAD	Dec. 31, 2010 Senior Notes 2.95% Due 2015 And Senior Notes 4.40% Due 2020 [Member] USD ($)	Dec. 31, 2010 Fixed Rate Notes And Floating Rate Notes [Member] USD ($)
Debt Instrument Table [Line Items]
Total Long-Term Debt	$ 5,040,000,000	$ 5,260,000,000							$ 400,000,000	$ 400,000,000	$ 350,000,000	$ 350,000,000	$ 500,000,000	$ 500,000,000	$ 400,000,000	$ 400,000,000	$ 600,000,000	$ 600,000,000	$ 350,000,000	$ 350,000,000	$ 900,000,000	$ 900,000,000	$ 500,000,000	$ 500,000,000	$ 750,000,000	$ 750,000,000	$ 140,000,000	$ 140,000,000	$ 0	$ 220,000,000	$ 150,000,000	$ 150,000,000
Current Portion of Long-Term Debt	0	220,000,000
Unamortized Debt Discount	30,834,000	36,659,000
Total Long-Term Debt, Net	5,009,166,000	5,003,341,000
Interest Rate (in hundredths)									61.25%				2.95%		2.50%		58.75%		68.75%		56.25%		4.40%		4.10%		6.65%		7.00%			4.75%	4.75%
Effective Interest Rate (in hundredths)													3.148%		2.698%								4.565%		4.276%
Variable Rate Basis											LIBOR
Basis Spread (in hundredths)											0.75%
Subsidiary Debt Due 2014 (Canadian)																																	201,300,000
Interest Rate - Canadian Subsidiary Note																																5.275%	5.275%
Interest Rate Swap Agreement (Fixed Rate) (in hundredths)											1.87%
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Date											November 23, 2010		May 20, 2010		November 23, 2010								May 20, 2010		November 23, 2010
Debt Instrument Issuance Face Value											350,000,000		500,000,000		400,000,000								500,000,000		750,000,000							150,000,000
Debt Instrument Frequency of Periodic Payment											quarterly		semi-annually		semiannually								semi-annually		semiannually
Net Proceeds From Issuance of Senior Notes																																		990,000,000	1,487,000,000
Long-Term Debt by Maturity [Abstract]
Aggregate annual maturity of long-term debt in 2012	0
Aggregate annual maturity of long-term debt in 2013	400,000,000
Aggregate annual maturity of long-term debt in 2014	500,000,000
Aggregate annual maturity of long-term debt in 2015	500,000,000
Aggregate annual maturity of long-term debt in 2016	400,000,000
Line of Credit Facility [Line Items]
Weighted average interest rate				0.34%
Average Borrowings Outstanding			0	3,000,000
Line of Credit Facility, Expiration Date					June 28, 2012	September 10, 2013		October 11, 2016
Maximum borrowing capacity					1,000,000,000	1,000,000,000	75,000,000	2,000,000,000
Outstanding balance					0	0	37,000,000
Eurodollar rate at period end (in hundredths)								1.17%
Weighted average Eurodollar rate for the outstanding amount during the year (in hundredths)							2.74%
Base rate at period end (in hundredths)								3.25%
Maximum total debt-to-total capitalization ratio allowed under financial covenant (in hundredths)	65.00%
Advances up to an aggregate principal amount								2,000,000,000
Increases in the aggregate commitments to an amount not to exceed								3,000,000,000
Fair Value of Debt	$ 5,657,000,000	$ 5,602,000,000

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Consolidated Statements of Stockholders' Equity (USD $) In Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income [Member]	Retained Earnings [Member]	Common Stock Held in Treasury [Member]
Balance at Dec. 31, 2008	$ 9,014,497	$ 202,498	$ 323,805	$ 27,787	$ 8,466,143	$ (5,736)
Net Income	546,627	0	0	0	546,627	0
Common Stock Issued Under Stock Plans	18,644	3	18,641	0	0	0
Common Stock Dividends Declared Per Share	(146,023)	0	0	0	(146,023)	0
Foreign Currency Translation Adjustments	308,286	0	0	308,286	0	0
Foreign Currency Swap Transaction, Net of Tax	4,817	0	0	4,817	0	0
Defined Benefit Pension and Post Retirement Plans, Net of Tax	(1,170)	0	0	(1,170)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(9,163)	0	(4,240)	0	0	(4,923)
Excess Tax Expense from Stock-Based Compensation	76,134	0	76,134	0	0	0
Restricted Stock and Restricted Stock Units, Net	0	10	(2,483)	0	0	2,473
Stock-Based Compensation Expenses	95,037	0	95,037	0	0	0
Shares Issued for Property Acquisition	89,581	15	89,566	0	0	0
Treasury Stock Issued as Compensation	775	0	242	0	0	533
Balance at Dec. 31, 2009	9,998,042	202,526	596,702	339,720	8,866,747	(7,653)
Net Income	160,654	0	0	0	160,654	0
Common Stock Issued Under Stock Plans	34,562	10	34,552	0	0	0
Common Stock Dividends Declared Per Share	(157,222)	0	0	0	(157,222)	0
Foreign Currency Translation Adjustments	96,179	0	0	96,179	0	0
Foreign Currency Swap Transaction, Net of Tax	3,244	0	0	3,244	0	0
Defined Benefit Pension and Post Retirement Plans, Net of Tax	(251)	0	0	(251)	0	0
Interest Rate Swap, Net of Tax	1,179	0	0	1,179	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(11,296)	0	(7,257)	0	0	(4,039)
Excess Tax Expense from Stock-Based Compensation	(837)	0	(837)	0	0	0
Restricted Stock and Restricted Stock Units, Net	0	6	(505)	0	0	499
Stock-Based Compensation Expenses	107,314	0	107,314	0	0	0
Treasury Stock Issued as Compensation	64	0	23	0	0	41
Balance at Dec. 31, 2010	10,231,632	202,542	729,992	440,071	8,870,179	(11,152)
Net Income	1,091,123	0	0	0	1,091,123	0
Common Stock Issued Under Stock Plans	35,913	10	35,903	0	0	0
Common Stock Dividends Declared Per Share	(171,957)	0	0	0	(171,957)	0
Foreign Currency Translation Adjustments	(32,597)	0	0	(32,597)	0	0
Foreign Currency Swap Transaction, Net of Tax	(1,167)	0	0	(1,167)	0	0
Defined Benefit Pension and Post Retirement Plans, Net of Tax	(1,216)	0	0	(1,216)	0	0
Interest Rate Swap, Net of Tax	(3,345)	0	0	(3,345)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(24,035)	0	(18,622)	0	0	(5,413)
Excess Tax Expense from Stock-Based Compensation	25	0	25	0	0	0
Restricted Stock and Restricted Stock Units, Net	0	5	8,410	0	0	(8,415)
Stock-Based Compensation Expenses	128,205	0	128,205	0	0	0
Common Stock Sold	1,388,265	136	1,388,129	0	0	0
Treasury Stock Issued as Compensation	58	0	10	0	0	48
Balance at Dec. 31, 2011	$ 12,640,904	$ 202,693	$ 2,272,052	$ 401,746	$ 9,789,345	$ (24,932)

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Stockholder's Equity

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Stockholder's Equity [Text Block]

3.  Stockholders' Equity

Common Stock.  On March 7, 2011, EOG completed the public offering and sale of 13,570,000 shares of EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share.  Net proceeds from the sale of the Common Stock were approximately $1,388 million after deducting the underwriting discount and offering expenses.  Proceeds from the sale were used for general corporate purposes, including funding capital expenditures.

In September 2001, EOG's Board of Directors (Board) authorized the purchase of an aggregate maximum of 10 million shares of Common Stock that superseded all previous authorizations.  At December 31, 2011, 6,386,200 shares remained available for purchase under this authorization.  EOG last purchased shares of its Common Stock under this authorization in March 2003.  In addition, shares of Common Stock are from time to time withheld by, or returned to, EOG in satisfaction of tax withholding obligations arising upon the exercise of employee stock options or stock-settled stock appreciation rights, the vesting of restricted stock or restricted stock unit grants or in payment of the exercise price of employee stock options.  Such shares withheld or returned do not count against the Board authorization discussed above.  Shares purchased, withheld and returned are held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock plans and any other approved transactions or activities for which such shares of Common Stock shall be required.

The Board increased the quarterly cash dividend on the Common Stock to $0.155 per share on February 9, 2010, $0.16 per share on February 17, 2011 and to $0.17 per share on February 16, 2012.

The following summarizes Common Stock activity for each of the years ended December 31, 2009, 2010 and 2011 (in thousands):

		Common Shares
		Issued	Treasury	Outstanding
Balance at December 31, 2008		249,759	(127)	249,632
	Common Stock Issued Under Equity Compensation Plans	1,347	-	1,347
	Treasury Stock Purchased (1)	-	(168)	(168)
	Common Stock Issued Under Employee Stock Purchase Plan	71	-	71
	Treasury Stock Issued Under Other Equity Compensation Plans	-	177	177
	Common Stock Issued for Property Acquisition	1,450	-	1,450
Balance at December 31, 2009		252,627	(118)	252,509
	Common Stock Issued Under Equity Compensation Plans	1,482	-	1,482
	Treasury Stock Purchased (1)	-	(115)	(115)
	Common Stock Issued Under Employee Stock Purchase Plan	114	-	114
	Treasury Stock Issued Under Other Equity Compensation Plans	-	87	87
Balance at December 31, 2010		254,223	(146)	254,077
	Common Stock Issued Under Equity Compensation Plans	1,395	-	1,395
	Treasury Stock Purchased (1)	-	(267)	(267)
	Common Stock Issued Under Employee Stock Purchase Plan	135	-	135
	Treasury Stock Issued Under Other Equity Compensation Plans	-	109	109
	Common Stock Sold	13,570	-	13,570
Balance at December 31, 2011		269,323	(304)	269,019

(1) Represents shares that were withheld by, or returned to, EOG in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights, the vesting of restricted stock or restricted stock unit grants or in payment of the exercise price of employee stock options.

Preferred Stock.  EOG currently has one authorized series of preferred stock.  In February 2000, EOG's Board, in connection with a rights agreement, authorized 1,500,000 shares of the Series E Junior Participating Preferred Stock (Series E).  In February 2005, EOG's Board increased the authorized shares of the Series E to 3,000,000 in connection with the two-for-one stock split of the Common Stock effected in March 2005.  As of December 31, 2011, there were no shares of the Series E outstanding.  The rights agreement and the related preferred share purchase rights expired on February 24, 2010.

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Oil and Gas Exploration and Production Industries Disclosures, Results Of Operations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Dry Hole Costs	$ 53,230	$ 72,486	$ 51,243
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	5,814,942	3,928,240	2,732,088
Other	32,329	19,886	9,692
Total	5,847,271	3,948,126	2,741,780
Exploration Costs	148,199	156,252	137,696
Dry Hole Costs	30,521	30,927	39,570
Transportation Costs	421,060	372,466	270,940
Production Costs	1,096,955	763,769	556,236
Impairments	575,976	271,466	272,195
Depreciation, Depletion and Amortization	2,011,080	1,430,408	1,188,243
Income (Loss) Before Income Taxes	1,563,480	922,838	276,900
Income Tax Provision (Benefit)	569,153	375,855	106,537
Results of Operations	994,327	546,983	170,363
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	459,853	477,416	413,910
Other	258	(31)	(15)
Total	460,111	477,385	413,895
Exploration Costs	10,479	17,597	18,675
Dry Hole Costs	432	14,875	1,461
Transportation Costs	5,969	9,892	9,317
Production Costs	174,973	174,667	145,292
Impairments	452,103	451,703	32,996
Depreciation, Depletion and Amortization	258,772	314,663	210,509
Income (Loss) Before Income Taxes	(442,617)	(506,012)	(4,355)
Income Tax Provision (Benefit)	(121,044)	(151,315)	(1,276)
Results of Operations	(321,573)	(354,697)	(3,079)
Trinidad [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	555,143	447,852	229,649
Other	586	3,696	3,500
Total	555,729	451,548	233,149
Exploration Costs	2,520	2,277	5,107
Dry Hole Costs	0	5,000	0
Transportation Costs	1,620	1,348	1,141
Production Costs	49,318	51,125	27,616
Impairments	0	1,465	0
Depreciation, Depletion and Amortization	106,802	70,553	46,608
Income (Loss) Before Income Taxes	395,469	319,780	152,677
Income Tax Provision (Benefit)	202,815	140,413	58,681
Results of Operations	192,654	179,367	93,996
Other International [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	28,250	27,707	23,826
Other	0	0	0
Total	28,250	27,707	23,826
Exploration Costs	10,460	11,255	8,114
Dry Hole Costs	22,277	21,684	10,212
Transportation Costs	1,673	1,483	1,931
Production Costs	10,964	8,504	9,452
Impairments	2,958	418	641
Depreciation, Depletion and Amortization	17,160	15,399	7,966
Income (Loss) Before Income Taxes	(37,242)	(31,036)	(14,490)
Income Tax Provision (Benefit)	(13,056)	(14,245)	(6,067)
Results of Operations	$ (24,186)	$ (16,791)	$ (8,423)

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Long-Term Debt

Long-Term Debt at December 31, 2011 and 2010 consisted of the following (in thousands):

		2011		2010
6.125% Senior Notes due 2013		$	400,000	$	400,000
Floating Rate Senior Notes due 2014			350,000		350,000
2.95% Senior Notes due 2015			500,000		500,000
2.500% Senior Notes due 2016			400,000		400,000
5.875% Senior Notes due 2017			600,000		600,000
6.875% Senior Notes due 2018			350,000		350,000
5.625% Senior Notes due 2019			900,000		900,000
4.40% Senior Notes due 2020			500,000		500,000
4.100% Senior Notes due 2021			750,000		750,000
6.65% Senior Notes due 2028			140,000		140,000
7.00% Subsidiary Debt due 2011			-		220,000
4.75% Subsidiary Debt due 2014			150,000		150,000
Total Long-Term Debt			5,040,000		5,260,000
Less:	Current Portion of Long-Term Debt		-		220,000
	Unamortized Debt Discount		30,834		36,659
Total Long-Term Debt, Net		$	5,009,166	$	5,003,341

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Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Net Changes In Suspended Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2011, 2010 and 2009 are presented below (in thousands):

	2011			2010			2009
Balance at January 1	$	99,801		$	118,459		$	85,255
Additions Pending the Determination of Proved Reserves		31,271			94,090			75,362
Reclassifications to Proved Properties		(29,227	)		(93,333	)		(40,614	)
Charged to Dry Hole Costs		(42,178	)		(20,267	)		(11,223	)
Foreign Currency Translations		1,444			852			9,679
Balance at December 31	$	61,111		$	99,801		$	118,459

Aging of Suspended Well Costs

The following table provides an aging of capitalized exploratory well costs at December 31, 2011, 2010 and 2009 (in thousands, except well count):

	2011			2010			2009
Capitalized exploratory well costs that have been capitalized for a period less than one year	$	17,009		$	43,408		$	51,141
Capitalized exploratory well costs that have been capitalized for a period greater than one year		44,102	(1)		56,393	(2)		67,318	(3)
Total	$	61,111		$	99,801		$	118,459
Number of exploratory wells that have been capitalized for a period greater than one year		4			4			4

(1) Consists of costs related to an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($20 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($9 million), and a shale project in British Columbia, Canada (B.C.) ($6 million).  In the Central North Sea project, the operator and partners are currently negotiating processing and transportation terms with export infrastructure owners.  The operator submitted 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 during the first half of 2012.  In the East Irish Sea project, EOG submitted field development plans to the DECC during the first quarter of 2011 and expects regulatory approval during the first quarter of 2012. Installation of facilities, pipelines and drilling of development wells are planned for 2012 with initial production expected during the first quarter of 2013.  The evaluation of the Sichuan Basin project is expected to be completed by mid-2012.  In the B.C. shale project, EOG drilled four additional wells during the first half of 2011 and plans to drill seven wells in the first half of 2012 to retain land and further evaluate the project.  The related well completion activities are not expected to commence until 2013 or later.

(2) Consists of costs related to an outside operated, offshore Central North Sea project in the U.K. ($21 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($20 million), and a shale project in B.C. ($6 million).

(3) Consists of costs related to three shale projects in B.C. ($45 million) and an outside operated, offshore Central North Sea project in the U.K. ($22 million).

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Accounting For Certain Long-Lived Assets

12 Months Ended

Dec. 31, 2011

Notes To Financial Statements [Abstract]

Accounting For Certain Long-Lived Assets [Text Block]

13.  Accounting for Certain Long-Lived Assets

EOG reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset.  During 2011, 2010 and 2009, such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to lower commodity prices, downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields.  Several impairments over this period were recognized in connection with the signing of purchase and sale agreements.  As a result, EOG recorded pretax charges of $403 million, $107 million and $90 million in the United States during 2011, 2010 and 2009, respectively, and $428 million, $418 million and $4 million in Canada during 2011, 2010 and 2009, respectively.  Additionally, EOG recorded pretax charges of $3 million in Other International during 2011 and $1 million in Trinidad during 2010.  The pretax charges are included in Impairments on the Consolidated Statements of Income and Comprehensive Income.  The carrying values for assets determined to be impaired were adjusted to estimated fair value using the income approach.  If applicable, EOG utilizes accepted bids as the basis for determining fair value.  Amortization of unproved oil and gas property costs, including amortization of capitalized interest, was $197 million, $217 million and $212 million for 2011, 2010 and 2009, respectively.