Edgar Filing: EOG RESOURCES INC

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, 2013

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 28, 2013: $35,668 million.

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, 273,119,572 shares outstanding as of February 14, 2014.

Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2014 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2013, 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	8
	Competition	9
	Regulation	9
	Other Matters	14
	Executive Officers of the Registrant	15
ITEM 1A.	Risk Factors	17
ITEM 1B.	Unresolved Staff Comments	26
ITEM 2.	Properties	26
	Oil and Gas Exploration and Production - Properties and Reserves	26
ITEM 3.	Legal Proceedings	30
ITEM 4.	Mine Safety Disclosures	30

PART II

ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
ITEM 6.	Selected Financial Data	34
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	35
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
ITEM 8.	Financial Statements and Supplementary Data	55
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	56
ITEM 9A.	Controls and Procedures	56
ITEM 9B.	Other Information	56

PART III

ITEM 10.	Directors, Executive Officers and Corporate Governance	57
ITEM 11.	Executive Compensation	57
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	58
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	59
ITEM 14.	Principal Accounting Fees and Services	59

PART IV

ITEM 15.	Exhibits, Financial Statement Schedules	59

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 www.eogresources.com.

At December 31, 2013, EOG's total estimated net proved reserves were 2,119 million barrels of oil equivalent (MMBoe), of which 901 million barrels (MMBbl) were crude oil and condensate reserves, 377 MMBbl were natural gas liquids (NGLs) reserves and 5,045 billion cubic feet, or 841 MMBoe, were natural gas reserves (see Supplemental Information to Consolidated Financial Statements). At such date, approximately 94% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States, 4% in Trinidad, 1% in Canada and 1% in Other International. Crude oil equivalent volumes are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet (Mcf) of natural gas.

As of December 31, 2013, EOG employed approximately 2,800 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.

Exploration and Production

United States and Canada Operations

EOG's operations are focused in most of the productive basins in the United States and Canada, with a current focus on crude oil and, to a lesser extent, liquids-rich natural gas plays.

At December 31, 2013, on a crude oil equivalent basis, 44% of EOG's net proved reserves in the United States and Canada were crude oil and condensate, 19% were NGLs and 37% were natural gas. The majority 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 applicable technologies. EOG also maintains an active exploration program designed to extend fields and add new trends and resource plays to its already broad portfolio. The following is a summary of significant developments during 2013 and certain 2014 plans for EOG's United States and Canada operations.

United States. The Eagle Ford continues to prove itself as among the best resource plays in the world. With approximately 564,000 of the 632,000 total net acres that EOG controls within the prolific oil window, EOG completed 466 net wells in 2013 yielding a direct after-tax rate of return⁽¹⁾ in excess of 100%. In 2013, EOG continued to decrease well costs and believes it has the lowest completed well costs in the play, while continuing to have the most productive wells. The combination of self-sourced sand, dedicated frac crews and other services along with continual well optimization programs have made this play the centerpiece of EOG's portfolio.

EOG is the biggest oil producer in the Eagle Ford play with year-end, net volumes of approximately 142 thousand barrels per day (MBbld) of crude oil and condensate, an increase of 79% over year-end 2012. In addition to being an anchor shipper on the Enterprise Products Partners L.P. Eagle Ford crude oil pipeline, EOG began shipping its crude oil on the Kinder Morgan crude oil and condensate pipeline into the Houston market in December 2013. EOG's capacity on the Kinder Morgan crude oil and condensate pipeline provides further diversification and the security of firm transportation capacity for its Eagle Ford production. EOG's large contiguous acreage position allows for low transportation and operating costs which adds to the overall return for the play. In 2014, EOG plans to drill approximately 520 net wells and build infrastructure to accommodate production from its western Eagle Ford acreage.

The Rocky Mountain area continues to provide strong liquids growth. In 2013, EOG began infill drilling on its crude oil acreage in the Williston Basin Bakken core, drilling 39 net wells. EOG continued its development program in the Powder River Basin, drilling 20 net wells in the Turner Sand formation. Net average production for the entire Rocky Mountain area for 2013 was approximately 61 MBbld of crude oil and condensate and NGLs, an increase of 17% over the prior year. Natural gas production decreased 6% compared to 2012 with activity focused on liquids growth. EOG plans to increase activity in the Rocky Mountain area in 2014.

In 2013, EOG drilled and participated in 61 net wells in the Permian Basin to develop its liquids-rich Leonard and Wolfcamp plays. EOG is well positioned with approximately 73,000 net acres in the Leonard Shale, and 134,000 net acres in the Wolfcamp Shale, all within the Delaware Basin. Additionally, EOG has approximately 113,000 net acres in the Wolfcamp Shale within the Midland Basin. Net production in the Permian Basin for 2013 averaged 23 MBbld of crude oil and condensate and NGLs, an increase of 40% over 2012. Natural gas production increased 24% to 54 million cubic feet per day (MMcfd). After divestitures in 2013, EOG holds approximately 413,000 net acres throughout the Permian Basin. In 2014, EOG plans to continue the expansion and development of the Leonard and Wolfcamp plays by drilling approximately 65 net wells.

In the Upper Gulf Coast region, EOG drilled 21 net wells, and net production averaged 124 MMcfd of natural gas and 1.9 MBbld of crude oil and condensate and NGLs in 2013. The Haynesville and Bossier Shale plays located near the Texas-Louisiana border continue to be core natural gas assets. EOG controls approximately 143,000 net acres, all within the highly productive areas of these plays. Due to low natural gas prices, EOG plans to defer dry gas drilling until natural gas economics improve sufficiently to support the activity. However, in 2013, EOG successfully tested and confirmed high NGLs and condensate production in the Panola County region of EOG's Haynesville leasehold. Total net liquids volumes increased to 4 MBbld at year-end 2013. EOG holds approximately 593,000 net acres in the Upper Gulf Coast region and plans to increase activity during 2014.

In the Mid-Continent area, EOG continued to expand its activities in the Western Anadarko Basin. During 2013, EOG averaged net production of 8.0 MBbld of crude oil and condensate and NGLs and 33 MMcfd of natural gas. Crude oil volumes increased 6% in 2013 compared to 2012. In 2013, EOG continued its successful horizontal exploitation of the Pennsylvanian sandstones in the Anadarko Basin, drilling 36 net wells. EOG holds approximately 200,000 net acres throughout the trend, and plans to drill approximately 25 net crude oil wells in 2014.

During 2013, EOG continued development of its liquids-rich Barnett Shale Combo play in the Fort Worth Basin. EOG drilled 142 net Barnett Combo wells and continued to upgrade the quality of its acreage position and add potential drilling locations in the Barnett Combo core area. In 2013, net daily total production in the Barnett Shale averaged approximately 36 MBbld of crude oil and condensate and NGLs and approximately 305 MMcfd of natural gas. For 2014, EOG will continue to be active in this play with plans to drill approximately 105 net Barnett Shale Combo wells.

In the South Texas area, EOG drilled 30 net wells in 2013. Net production during 2013 averaged 6 MBbld of crude oil and condensate and NGLs and 86 MMcfd of natural gas. EOG's activity was focused in San Patricio, Nueces, Brooks, Kenedy and Kleberg Counties. In 2014, EOG will continue to exploit the liquids-rich Frio and Vicksburg sands on its approximately 320,000 net acre position in these counties and plans to drill approximately 24 net wells.

During 2013, EOG significantly slowed development of the Marcellus Shale, drilling a total of four net wells and completing one net well to hold its acreage position. Net production for 2013 averaged 36 MMcfd of natural gas. For 2014, Marcellus Shale development plans are minimal, focusing on infrastructure projects that will support additional Marcellus Shale development in the coming years. EOG currently holds approximately 195,000 net acres with Marcellus Shale potential, most of which is held as fee or by production.

At December 31, 2013, EOG held approximately 2.7 million net undeveloped acres in the United States.

During 2013, EOG continued the expansion of its gathering and processing activities in the Eagle Ford in South Texas, the Bakken and Three Forks plays in North Dakota, the Permian Basin in West Texas and New Mexico and the Barnett Shale in North Texas. At December 31, 2013, EOG-owned natural gas processing capacity in the Eagle Ford and Barnett Shale was 225 MMcfd and 180 MMcfd, respectively.

In support of its operations in the Williston Basin, EOG continued to increase the utilization of its crude oil loading facility near Stanley, North Dakota, to transport its crude oil production and, from time to time, crude oil purchased from third-party producers. EOG loaded 406 unit trains (each unit train typically consists of 100 cars and has a total aggregate capacity of approximately 70,000 barrels of crude oil) with crude oil for transport to St. James, Louisiana, Stroud, Oklahoma, and certain other destinations in the U.S.

Additionally, in support of EOG operations in the Eagle Ford, the Permian Basin and the Barnett Shale, EOG continued to use its crude oil loading facilities in Harwood and Barnhart, Texas, and established a new crude oil loading facility near Fort Worth, Texas. At these facilities, crude oil is loaded onto unit trains of approximately 70 cars each, with aggregate capacity of approximately 45,000 barrels per train, and shipped to St. James, Louisiana, or to other destinations on the U.S. Gulf Coast. During 2013, a total of 89 unit train shipments were made from these three facilities.

A total of 372 crude oil unit trains carrying EOG production were received at a crude oil unloading facility in St. James, Louisiana, during 2013. Owned by EOG and NuStar Energy L.P., this facility provides access to one of the key markets in the U.S., where sales are based upon the Light Louisiana Sweet (LLS) crude oil index. The St. James facility accommodates multiple trains at a single time and has a capacity of approximately 120 MBbld. EOG's share of that capacity is 100 MBbld.

During 2013, EOG utilized its Stroud, Oklahoma, crude oil unloading facility and pipeline to transport 50 unit trainloads of crude oil to the Cushing, Oklahoma, trading hub. These facilities have the capacity to unload approximately 90 MBbld of crude oil. EOG also delivered crude by rail to certain other third-party operated facilities in the U.S.

EOG believes that its crude-by-rail facilities and logistics processes provide a competitive advantage, giving EOG the flexibility to direct its crude oil shipments via rail car to the most favorable markets.

Since 2008, EOG has been operating its own sand mine and sand processing plant located in Hood County, Texas, to reduce costs and to help fulfill EOG's sand needs for its well completion operations in the Barnett Shale Combo play. EOG purchased a second Hood County sand processing plant in 2011, and utilizes that facility to process raw EOG-owned sand from Wisconsin, as needed, to support EOG's well completion activities in several key EOG plays.

In 2013, EOG increased the use of processed sand from its Chippewa Falls, Wisconsin, sand plant, which processes sand from multiple EOG-owned mines nearby.

During 2013, EOG shipped 141 sand unit trains of approximately 100 cars each, from various sources, to EOG's sand storage and distribution facility in Refugio, Texas, primarily for use in its Eagle Ford well completions. Also during 2013, EOG shipped the equivalent of 89 unit trains of processed sand for well completions in other plays.

EOG also continued utilization of its resin coating plant, located at the Refugio sand storage facility. After coating for added strength and sand control, the sand is shipped primarily to the Eagle Ford. EOG also ships its coated sand to other plays, including the North Dakota Bakken and the Permian Basin.

Canada. EOG conducts operations in Canada through its wholly-owned subsidiary, EOG Resources Canada Inc. (EOGRC), from its offices in Calgary, Alberta. During 2013, EOGRC continued its focus on horizontal crude oil exploitation, mainly through its development of the shallow Spearfish formation in southwest Manitoba. Of the 93 net wells EOGRC drilled or participated in during 2013, 91 were horizontal and 2 were vertical. In 2014, EOGRC will continue to develop its Manitoba acreage as well as drill test wells on existing acreage in Alberta to identify new targets. In 2013, net crude oil and condensate and NGLs production was 7.9 MBbld and net natural gas production was 76 MMcfd.

At December 31, 2013, EOGRC held approximately 483,000 net undeveloped acres in Canada.

In December 2012, EOGRC signed a purchase and sale agreement for the sale of its entire interest in the planned Kitimat LNG Terminal and the proposed Pacific Trail Pipelines, as well as approximately 28,500 undeveloped net acres in the Horn River Basin, to Chevron Canada Limited. The transaction closed in February 2013.

___________________________

⁽¹⁾ Direct After-Tax Rate of Return. The calculation of our direct after-tax rate of return with respect to our capital expenditures for our net wells drilled in the Eagle Ford in 2013 is based on the estimated proved reserves ("net" to our interest) associated with such wells, the estimated present value of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling such wells. As such, our after-tax rate of return with respect to our capital expenditures for our net wells drilled in the Eagle Ford in 2013 cannot be calculated from our audited financial statements for fiscal year 2013.

Operations Outside the United States and Canada

EOG has operations offshore Trinidad, in the U.K. North Sea and East Irish Sea, in the China Sichuan Basin and in 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 exploration and production license covering 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;

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; and

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

Several fields in the SECC Block, Modified U(a) Block, Modified U(b) Block, Block 4(a) and the EMZ Area have been developed and are producing natural gas and crude oil and condensate. Natural gas from EOG's Trinidad operations currently is sold under various contracts with the National Gas Company of Trinidad and Tobago (NGC). Crude oil and condensate from EOG's Trinidad operations currently is sold to the Petroleum Company of Trinidad and Tobago Limited. In 2013, EOG's average net production from Trinidad was 355 MMcfd of natural gas and 1.2 MBbld of crude oil and condensate.

During 2013, EOG completed its four-well program in the Modified U(a) Block, having drilled three development wells and one successful exploratory well. In addition, an existing well was successfully recompleted and began production in 2013. EOG expects to drill three net wells in the SECC and Modified U(b) Blocks during 2014.

In 2014, certain agreements with NGC require EOG's Trinidad operations to deliver approximately 490 MMcfd (360 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.

At December 31, 2013, 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 2013, production continued from the Valkyrie field in this block.

In 2006, EOGUK participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f in which EOG has a 25% non-operating working interest. A successful Columbus natural gas prospect appraisal well was drilled during the third quarter of 2007. In 2013, the U.K. Department of Energy and Climate Change (DECC) extended the previously granted license by two years. Costs associated with the Central North Sea Columbus natural gas project were written off in 2013.

In 2007, EOGUK was awarded a license for two blocks in the East Irish Sea – Blocks 110/7b and 110/12a. In 2009, EOGUK drilled a successful exploratory well in the East Irish Sea Block 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. The field development plans for the Conwy/Corfe project were approved by the DECC in March 2012. In 2013, after drilling an appraisal well, EOG determined that the Corfe field did not contain proved commercial reserves. The Conwy production platform and pipelines were installed during 2012 and 2013. In 2013, modifications to the nearby third-party owned Douglas platform began and a crude oil processing module was installed. The Douglas platform will be used to process Conwy production. During 2013, the three-well Conwy development drilling program was completed with first production from the Conwy field anticipated in late 2014.

In the third quarter of 2013, EOG drilled an unsuccessful exploratory well in the Central North Sea Block 21/12b, and in January 2014, EOG drilled an unsuccessful exploratory well in the East Irish Sea Block 110/7b.

In 2013, production averaged 1 MMcfd of natural gas, net, in the United Kingdom.

At December 31, 2013, EOG held approximately 54,000 net undeveloped acres in the United Kingdom.

China. In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuan Zhong Block exploration area in the Sichuan Basin, Sichuan Province, China. In October 2008, EOG obtained the rights to shallower zones on the acquired acreage. During the first half of 2013, EOG successfully recompleted a well and drilled and completed an additional well, both of which began production in the latter part of 2013. Additionally in 2013, EOG drilled one well that is expected to be completed and begin producing in 2014. EOG plans to drill six additional wells on its acreage in 2014.

In 2013, production averaged 7 MMcfd of natural gas, net, in China.

At December 31, 2013, EOG held approximately 131,000 net developed acres in China.

Argentina. In 2011, EOG signed two exploration contracts and one farm-in agreement covering approximately 95,000 net acres in the Neuquén Basin in Neuquén Province, Argentina. During 2013, EOG completed a well in the Aguada del Chivato Block that was drilled in 2012. Also, in late 2013, EOG participated in the drilling of a vertical well in the Cerro Avispa Block. In 2014, EOG plans to complete this vertical well, participate in the drilling of a well in the Cerro Avispa Block and a well in the Bajo del Toro Block. EOG continues to evaluate its drilling results and exploration program in Argentina.

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

In 2013, EOG's wellhead crude oil and condensate production was sold into local markets or transported either by pipeline, truck or EOG's crude-by-rail assets to downstream markets. In each case, the price received was based on market prices at that specific sales point or based on the price index applicable for that location. Major sales points included Cushing, Oklahoma, St. James, Louisiana, and other points along the U.S. Gulf Coast. In 2014, the pricing mechanism for such production is expected to remain the same.

In 2013, EOG processed certain of its natural gas production, either at EOG-owned facilities or at third-party facilities, extracting NGLs. NGLs were sold at prevailing market prices. In 2014, the pricing mechanism for such production is expected to remain the same.

In 2013, EOG's United States and Canada wellhead natural gas production was sold into local markets or transported by pipeline to downstream markets. Pricing, based on the spot market and long-term natural gas contracts, was at prevailing market prices. In 2014, the pricing mechanism for such production is expected to remain the same.

In 2013, 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 2014.

In 2013, all wellhead natural gas volumes from the U.K. were sold on the spot market. The 2014 marketing strategy for wellhead natural gas volumes from the U.K. is expected to remain the same. EOG is currently investigating possible marketing opportunities for its U.K. wellhead crude oil production, which is anticipated to begin in late 2014.

In 2013, all 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 2014.

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 2013, two purchasers each accounted for more than 10% of EOG's total wellhead crude oil and condensate, NGLs and natural gas revenues and gathering, processing and marketing revenues. Both purchasers are in the crude oil refining industry. 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, NGLs and natural gas. The table also presents crude oil equivalent volumes which are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 Mcf of natural gas for each of the years ended December 31, 2013, 2012 and 2011.

Year Ended December 31	2013		2012		2011

Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
United States:
Eagle Ford		122.3		72.3		30.2
Barnett		11.7		13.0		15.2
Other		78.1		64.0		56.6
United States		212.1		149.3		102.0
Canada		7.0		7.0		7.9
Trinidad		1.2		1.5		3.4
Other International ⁽²⁾		0.1		0.1		0.1
Total		220.4		157.9		113.4
Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
United States:
Eagle Ford		18.6		11.2		3.9
Barnett		24.2		25.8		22.6
Other		21.5		18.1		15.0
United States		64.3		55.1		41.5
Canada		0.9		0.8		0.9
Total		65.2		55.9		42.4
Natural Gas Volumes (MMcfd) ⁽¹⁾
United States:
Eagle Ford		115		65		21
Barnett		305		368		403
Other		488		601		689
United States		908		1,034		1,113
Canada		76		95		132
Trinidad		355		378		344
Other International ⁽²⁾		8		9		13
Total		1,347		1,516		1,602
Crude Oil Equivalent Volumes (MBoed) ⁽³⁾
United States:
Eagle Ford		160.2		94.4		37.7
Barnett		86.8		100.1		105.0
Other		180.9		182.1		186.4
United States		427.9		376.6		329.1
Canada		20.5		23.6		30.7
Trinidad		60.4		64.5		60.7
Other International ⁽²⁾		1.3		1.7		2.2
Total		510.1		466.4		422.7

Total MMBoe ⁽³⁾		186.2		170.7		154.3

Year Ended December 31	2013		2012		2011

Average Crude Oil and Condensate Prices ($/Bbl) ⁽⁴⁾
United States	$	103.81	$	98.38	$	92.92
Canada		87.05		86.08		91.92
Trinidad		90.30		92.26		90.62
Other International ⁽²⁾		89.11		89.57		100.11
Composite		103.20		97.77		92.79
Average Natural Gas Liquids Prices ($/Bbl) ⁽⁴⁾
United States	$	32.46	$	35.41	$	50.37
Canada		39.45		44.13		52.69
Composite		32.55		35.54		50.41
Average Natural Gas Prices ($/Mcf) ⁽⁴⁾
United States	$	3.32	$	2.51	$	3.92
Canada		3.08		2.49		3.71
Trinidad		3.68		3.72		3.53
Other International ⁽²⁾		6.45		5.71		5.62
Composite		3.42		2.83		3.83

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

(2) Other International includes EOG's United Kingdom, China and Argentina operations.

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

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

Competition

EOG competes with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses and leases, properties and reserves and access to the facilities, equipment, materials, services and employees and other contract personnel (including geologists, geophysicists, engineers and other specialists) required to explore for, develop, produce, market and transport crude oil and natural gas. In addition, 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 or in accessing necessary services, facilities, equipment, materials and personnel. 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. In addition, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations applicable to the oil and gas industry. Such rules and regulations, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas through restrictions on flaring, require surety bonds for various exploration and production operations and regulate the calculation and disbursement of royalty payments (for federal and state leases), production taxes and ad valorem taxes.

A portion of EOG's oil and gas leases in New Mexico, North Dakota, Utah, Wyoming and the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (BLM) and the Bureau of Indian Affairs (BIA) or, in the case of offshore leases, by 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 and, in the case of leases relating to tribal lands, certain tribal environmental and permitting requirements and employment rights regulations.

BLM, BIA 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). Under certain circumstances, the BLM, BIA, BOEM or BSEE (as applicable) 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 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 NGLs by EOG are made at unregulated market prices.

EOG owns certain gathering and/or processing facilities in the Permian Basin in West Texas and New Mexico, the Barnett Shale in North Texas, the Bakken and Three Forks plays in North Dakota, and the Eagle Ford in South Texas. State regulation of gathering and processing facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. EOG's gathering and processing 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 and processing 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.

EOG also owns crude oil loading facilities in North Dakota and Texas and crude oil unloading facilities in Oklahoma and Louisiana. Regulation of such facilities is conducted at the state and federal levels and generally includes various safety, environmental, permitting and packaging/labeling requirements. Additional regulation pertaining to these matters is considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, any such new regulations might have on its crude-by-rail operations, EOG could be required to incur additional capital expenditures and increased compliance costs depending on the nature and extent of such future 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. EOG is subject to 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. These laws and regulations affect EOG's operations and costs as a result of their effect on crude oil and natural gas exploration, development and production operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements.

In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. 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 previously owned or currently owns an interest, but was or is not the operator. Moreover, EOG is subject to the U.S. Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG) emissions and may in the future, as discussed further below, be subject to federal, state and local laws and regulations regarding hydraulic fracturing.

Compliance with environmental 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. However, given that such laws and regulations are subject to change, EOG is unable to predict the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations.

Climate Change - United States. 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 in October 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 - United States. Most onshore crude oil and natural gas wells drilled by EOG are completed and stimulated through the use of hydraulic fracturing. 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. However, there have been various proposals to regulate hydraulic fracturing at the federal level. 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 April 2012, the U.S. EPA issued regulations specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic compounds (VOC) emissions from natural gas wells that are hydraulically fractured through the use of "green completions" to capture natural gas that would otherwise escape into the air. The U.S. EPA also issued regulations that establish standards for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves and sweetening units at gas processing plants. In addition to these federal regulations, some state 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.

EOG is unable to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the United States, 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, 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. However, given that such laws and regulations are subject to change, EOG is unable to predict the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations.

As discussed above, local, provincial, 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. In addition, regulation of GHG emissions in Canada takes place at the provincial and municipal level. For example, the governments of Alberta and British Columbia each regulate GHG emissions and 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 withdrew from the Kyoto Protocol, effective December 2012.

In Canada, the regulation of hydraulic fracturing is primarily conducted at the provincial and local levels through permitting and other compliance requirements. Some provinces 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; 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 provincial and local requirements, restrictions and conditions could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. EOG is unable to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in Canada, 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.

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.

Other Regulation. EOG has sand mining and processing operations in Texas and Wisconsin, which support EOG's exploration and development operations. EOG's sand mining operations are subject to regulation by the federal Mine Safety and Health Administration (in respect of safety and health matters) and by state agencies (in respect of air permitting and other environmental matters). 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.

Other Matters

Energy Prices. EOG is a crude oil and natural gas producer and is impacted by changes in prices of crude oil and condensate, NGLs and natural gas. Crude oil and condensate and NGLs production comprised a larger portion of EOG's production mix in 2013 than in prior years and is expected to comprise an even larger portion in 2014. Average crude oil and condensate prices received by EOG for production in the United States and Canada increased 6% in 2013, 5% in 2012 and 24% in 2011, each as compared to the immediately preceding year. Average NGLs prices received by EOG for production in the United States and Canada decreased 8% in 2013 and 30% in 2012 and increased 21% in 2011, each as compared to the immediately preceding year. During the last three years, average United States and Canada wellhead natural gas prices have fluctuated, at times rather dramatically. These fluctuations resulted in a 31% increase in the average wellhead natural gas price received by EOG for production in the United States and Canada in 2013, a 36% decrease in 2012 and an 8% decrease in 2011, each as compared to the immediately preceding year. 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 prices of crude oil and condensate, NGLs and natural gas 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 2014 crude oil derivative contracts (exclusive of options) and based on EOG's tax position, EOG's price sensitivity in 2014 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $44 million for net income and $65 million for cash flows from operating activities. Including the impact of EOG's 2014 natural gas derivative contracts (exclusive of options) and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2014 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 $13 million for net income and $19 million for cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts at February 24, 2014, 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, 2013, 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 prices of crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. See Note 11 to Consolidated Financial Statements. In addition to financial transactions, from time to time 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 Financial Accounting Standards Board's 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, 2014, 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, 2013, 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, production and transportation of, crude oil and natural gas, including rig and well explosions, cratering, fires, loss of well control and leaks and spills, each of which could result in damage to life, property and/or the environment. EOG's onshore and offshore operations are also subject to usual customary perils, including hurricanes and other adverse weather conditions. Moreover, EOG's activities are subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance.

Insurance is maintained by EOG against some, but not all, of these risks in accordance with what EOG believes are customary industry practices and in amounts and at costs that EOG believes to be prudent and commercially practicable. Specifically, EOG maintains commercial general liability and excess liability coverage provided by third-party insurers for bodily injury or death claims resulting from an incident involving EOG's onshore or offshore operations (subject to policy terms and conditions). Moreover, in the event an incident with respect to EOG's onshore or offshore operations results in negative environmental effects, EOG maintains operators extra expense coverage provided by third-party insurers for obligations, expenses or claims that EOG may incur from such an incident, including obligations, expenses or claims in respect of seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions). In the event of a well control incident 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 with respect to its operations outside the United States.

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.

Executive Officers of the Registrant

The current executive officers of EOG and their names and ages (as of February 24, 2014) are as follows:

Name	Age	Position

William R. Thomas	61	Chairman of the Board and Chief Executive Officer

Gary L. Thomas	64	Chief Operating Officer

Lloyd W. Helms, Jr.	56	Executive Vice President, Exploration and Production

David W. Trice	43	Executive Vice President, Exploration and Production

Timothy K. Driggers	52	Vice President and Chief Financial Officer

Michael P. Donaldson	51	Vice President, General Counsel and Corporate Secretary

William R. Thomas was elected Chairman of the Board and Chief Executive Officer effective January 2014. 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 and Senior Executive Vice President, Exploitation in February 2011. He subsequently served as Senior Executive Vice President, Exploration from July 2011 to September 2011, as President from September 2011 to July 2013 and as President and Chief Executive Officer from July 2013 to December 2013. Mr. Thomas joined a predecessor of EOG in January 1979. Mr. Thomas is EOG's principal executive officer.

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.

Lloyd W. Helms, Jr. was elected Executive Vice President, Exploration and Production in August 2013. He was elected Vice President, Engineering and Acquisitions in September 2006, Vice President and General Manager of EOG's Calgary, Alberta, Canada office in March 2008, and served as Executive Vice President, Operations from February 2012 to August 2013. Mr. Helms joined a predecessor of EOG in February 1981.

David W. Trice was elected Executive Vice President, Exploration and Production in August 2013. He served as Vice President and General Manager of EOG's Fort Worth, Texas, office from May 2010 to August 2013. Prior to that, he served in various geological and management positions at EOG. Mr. Trice joined EOG in November 1999.

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, 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 a predecessor of EOG in August 1995.

Michael P. Donaldson was elected Vice President, General Counsel and Corporate Secretary in May 2012. He was elected Corporate Secretary in May 2008, and was appointed Deputy General Counsel and Corporate Secretary in July 2010. Mr. Donaldson joined EOG in September 2007.

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 flows 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," "our" and "EOG" refer to EOG Resources, Inc. and its subsidiaries.

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

Prices for crude oil and natural gas (including prices for natural gas liquids (NGLs) and condensate) fluctuate widely. Among the factors that can or could cause these price fluctuations are:

the level of consumer demand;

domestic and worldwide supplies of crude oil, NGLs and natural gas;

the price and quantity of imported and exported crude oil, NGLs and natural gas;

weather conditions and changes in weather patterns;

domestic and international drilling activity;

the availability, proximity and capacity of appropriate transportation facilities, gathering, processing and compression facilities and refining facilities;

worldwide economic and political conditions, including political instability or armed conflict in oil and gas producing regions;

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, regulation of derivatives transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

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 flows 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 flows we have available for our capital expenditures and other operating expenses, our ability to access the credit and capital markets and our results of operations.

In addition, if we expect or experience significant sustained decreases in crude oil and natural gas prices such that the expected future cash flows 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 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, health and safety laws and regulations relating to air emissions, hydraulic fracturing, access to and use of water, and disposal of produced water, drilling fluids and other wastes, laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas, and other laws and regulations, such as tax laws and regulations;

the availability and timely issuance of required federal, state, tribal and other permits and licenses, which may be affected by (among other things) government shutdowns or other suspensions of, or delays in, government services;

the availability of, costs associated with and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, rail cars, crude oil hauling trucks and qualified drivers and facilities and equipment to gather, process, compress, transport and market crude oil, natural gas and related commodities; and

the costs of, or shortages or delays in the availability of, drilling rigs, hydraulic fracturing services, pressure pumping equipment and supplies, tubular materials, water, sand, disposal facilities, qualified personnel and other necessary facilities, equipment, materials, 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 and supporting activities and 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 crude oil and natural gas operations and supporting activities and operations are subject to all of the risks associated with exploring and drilling for, and producing, gathering, processing, compressing 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, wastes or pollutants;

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

fires and explosions;

terrorism, vandalism and physical, electronic and cyber security breaches;

formations with abnormal or unexpected pressures;

leaks or spills in connection with, or associated with, the gathering, processing, compression and transportation of crude oil and natural gas; and

malfunctions of, or damage to, gathering, processing, compression and transportation facilities and equipment and other facilities and equipment utilized in support of our crude oil and natural gas operations.

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

injury or loss of life;

damage to, or destruction of, property, facilities, 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;

repairs necessary to resume operations; and

compliance with laws and regulations enacted as a result of such events.

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 operations 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 adequate gathering, processing, compression and transportation facilities and equipment are unavailable.

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 and equipment owned by third parties. These facilities may be temporarily unavailable to us due to market conditions, regulatory reasons, 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. In particular, in certain newer shale plays, the capacity of gathering, processing, compression and transportation facilities and equipment may not be sufficient to accommodate potential production from existing and new wells. In addition, lack of financing, construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new gathering, processing, compression and transportation facilities and equipment by third parties or us, and we may experience delays or increased costs in accessing the pipelines, gathering systems or rail systems necessary to transport our production to points of sale or delivery.

Any significant change in market or other conditions affecting gathering, processing, compression or transportation facilities and equipment or the availability of these facilities, including due to our failure or inability to obtain access to these facilities and equipment 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 flows 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 crude oil and natural gas operations and supporting activities are regulated extensively by federal, state, tribal 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, health, safety or other considerations. Moreover, we have incurred and will continue to incur costs in our efforts to comply with the requirements of environmental, health, safety and other regulations. Further, the regulatory environment could change in ways that we cannot predict and that might substantially increase our costs of compliance and, in turn, materially and adversely affect our business, results of operations and financial condition.

Specifically, as a current or past owner or lessee and operator of crude oil and natural gas properties, we are subject to various federal, state, tribal, 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 current or past 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. 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.

In addition, there have been various proposals to regulate hydraulic fracturing in the U.S. at the federal level. Currently, the regulation of hydraulic fracturing in the U.S. is primarily conducted at the state level (and, in Canada, at the provincial and local levels) 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 and in additional operating restrictions. Moreover, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations. Any such federal or state requirements, restrictions or 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 regulation and hydraulic fracturing regulation, see Climate Change - United States, Hydraulic Fracturing - 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.

Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and production may be eliminated as a result of future legislation.

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain U.S. federal income tax incentives currently available to crude oil and natural gas exploration and production companies. These changes include, but are not limited to, the elimination of current deductions for intangible drilling and development costs. It is unclear whether such changes or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The enactment of such changes or any other similar changes in U.S. federal income tax laws could materially and adversely affect our cash flows, results of operations and financial condition.

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

A portion of our crude oil and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions, the unavailability of gathering, processing, compression, transportation or refining facilities or equipment 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 or shut in, our cash flows and, in turn, our financial condition and results of operations could be materially and adversely affected.

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

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. 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 (such as title or environmental issues), 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. In addition, 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, production and transportation of crude oil and natural gas reserves. We intend to finance our capital expenditures primarily through our cash flows 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 flows. 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. In addition, weakness and/or volatility in domestic and global financial markets or economic conditions may increase the interest rates that lenders and commercial paper investors require us to pay and adversely affect our ability to finance our capital expenditures through equity or debt offerings or other borrowings. A reduction in our cash flows (for example, as a result of lower crude oil and natural gas prices or unanticipated well shut-ins) and the corresponding adverse effect on our financial condition and results of operations may also increase the interest rates that lenders and commercial paper investors require us to pay. In addition, a substantial increase in interest rates would decrease our net cash flows available for reinvestment. Any of these factors could have a material and adverse effect on our business, financial condition and results of operations.

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

We have various customers for the crude oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including several financial institutions and affiliates of financial institutions. Domestic and global economic conditions, including the financial condition of financial institutions generally, while weakened in recent years, have improved somewhat. However, there continues to be weakness and volatility in domestic and global financial markets, and there is the possibility that lenders may react by tightening credit. 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 gathering, processing, compression and 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 flows.

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 access to the facilities, equipment, materials, services and employees and other contract personnel (including geologists, geophysicists, engineers and other specialists) necessary to explore for, develop, produce, market and transport 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 accessing necessary services, facilities, equipment, materials 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 crude oil, NGLs 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. Also, the data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

To prepare estimates of our economically recoverable crude oil, NGLs 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, gathering, processing, compression and transportation costs, severance, ad valorem and other applicable production 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 or "write-downs" 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 flows 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, 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, processing, compression and transportation 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 price swaps, options, swaptions and collar and basis swap contracts) to hedge the impact of fluctuations in crude oil and natural gas prices on our results of operations and cash flows. 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 flows. In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which, among other matters, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (CFTC), adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivatives activities. Although a number of the rules necessary to implement the Dodd-Frank Act are yet to be adopted, the CFTC has issued several rules to implement the Dodd-Frank Act, including a rule establishing an "end-user" exception to mandatory clearing (End-User Exception), and a proposed rule imposing position limits (Position Limits Rule).

We qualify as a "non-financial entity" for purposes of the End-User Exception and, as such, we are eligible for, and expect to utilize, such exception. As a result, our hedging activities will not be subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. However, it remains uncertain whether margin requirements will be imposed on uncleared swaps. The Dodd-Frank Act, the rules which have been adopted and not vacated and the Position Limits Rule, to the extent that it is ultimately enacted, could significantly increase the cost of derivative contracts (including costs related to requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and related regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund our capital expenditures requirements. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.

Our business and prospects for future success depend to a significant extent upon the continued service and performance of our management team.

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

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, loss of or damage to equipment, property and other assets and interruption of operations as a result of expropriation, nationalization, 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.

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, 2013, approximately 3% of our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.

Our business could be adversely affected by security threats, including cybersecurity threats.

As a producer of crude oil and natural gas, we face various security threats, including cybersecurity threats to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing facilities, refineries, rail facilities and pipelines. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business, financial condition and results of operations. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruptions, or other disruptions to our operations.

Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position and results of operations.

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 (NGLs) 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, NGLs 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 by 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 and "Supplemental Information to Consolidated Financial Statements."

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

Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2013. 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		1,880,995		1,452,786		4,120,777		2,706,054		6,001,772		4,158,840
Canada		1,201,351		1,007,418		537,253		482,672		1,738,604		1,490,090
Trinidad		75,667		65,669		48,520		38,816		124,187		104,485
United Kingdom		8,797		2,570		71,054		53,886		79,851		56,456
China		130,548		130,548		-		-		130,548		130,548
Argentina		-		-		211,016		95,052		211,016		95,052
Total		3,297,358		2,658,991		4,988,620		3,376,480		8,285,978		6,035,471

Most of our undeveloped 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. Approximately 0.7 million net acres will expire in 2014, 0.5 million net acres will expire in 2015 and 0.3 million net acres will expire in 2016 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 16,261gross and 14,432 net producing crude oil and natural gas wells at December 31, 2013. Gross crude oil and natural gas wells include 1,514 wells with multiple completions.

	Crude Oil				Natural Gas				Total
	Gross		Net		Gross		Net		Gross		Net

United States		4,209		3,309		5,360		4,572		9,569		7,881
Canada		844		724		7,031		6,346		7,875		7,070
Trinidad		13		10		31		27		44		37
United Kingdom		-		-		1		-		1		-
China		-		-		26		26		26		26
Argentina		3		1		-		-		3		1
Total		5,069		4,044		12,449		10,971		17,518		15,015

Drilling and Acquisition Activities. During the years ended December 31, 2013, 2012 and 2011, EOG expended $7.0 billion, $7.1 billion and $6.6 billion, respectively, for exploratory and development drilling and acquisition of leases and producing properties, including asset retirement obligations of $134 million, $127 million and $133 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, 2013, 2012 and 2011:

	Gross Development Wells Completed								Gross Exploratory Wells Completed
	Crude Oil		Natural Gas		Dry Hole		Total		Crude Oil		Natural Gas		Dry Hole		Total

2013
United States		909		57		22		988		7		2		3		12
Canada		85		-		-		85		1		-		-		1
Trinidad		-		1		-		1		-		1		-		1
United Kingdom		3		-		-		3		-		-		1		1
China		-		-		-		-		-		1		-		1
Argentina		-		-		-		-		1		-		-		1
Total		997		58		22		1,077		9		4		4		17

2012
United States		844		135		8		987		8		7		1		16
Canada		83		3		-		86		3		-		-		3
China		-		-		-		-		-		-		1		1
Argentina		-		-		-		-		2		-		-		2
Total		927		138		8		1,073		13		7		2		22

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

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, 2013, 2012 and 2011:

	Net Development Wells Completed								Net Exploratory Wells Completed
	Crude Oil		Natural Gas		Dry Hole		Total		Crude Oil		Natural Gas		Dry Hole		Total

2013
United States		788		50		15		853		6		2		3		11
Canada		76		-		-		76		1		-		-		1
Trinidad		-		1		-		1		-		1		-		1
United Kingdom		3		-		-		3		-		-		1		1
China		-		-		-		-		-		1		-		1
Argentina		-		-		-		-		1		-		-		1
Total		867		51		15		933		8		4		4		16

2012
United States		705		100		7		812		7		6		1		14
Canada		80		3		-		83		3		-		-		3
China		-		-		-		-		-		-		1		1
Argentina		-		-		-		-		1		-		-		1
Total		785		103		7		895		11		6		2		19

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

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, 2013, 2012 and 2011:

	Wells in Progress at End of Period
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net

United States		320		280		324		267		359		282
Canada		13		8		-		-		-		-
Trinidad		-		-		1		1		-		-
United Kingdom		-		-		-		-		3		2
China		2		2		-		-		1		1
Argentina		1		1		-		-		-		-
Total		336		291		325		268		363		285

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, 2013, 2012 and 2011:

	Gross Acquired Wells						Net Acquired Wells
	Crude Oil		Natural Gas		Total		Crude Oil		Natural Gas		Total

2013
United States		68		27		95		50		21		71
Total		68		27		95		50		21		71

2012
United States		49		272		321		23		136		159
Total		49		272		321		23		136		159

2011
United States		8		-		8		4		-		4
Canada		-		5		5		-		5		5
Total		8		5		13		4		5		9

All of EOG's drilling activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors. EOG does not own drilling equipment. EOG's other property, plant and equipment primarily includes gathering, transportation and processing infrastructure assets, crude-by-rail 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 the 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.

PART II

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

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

	Price Range
	High		Low		Dividend Declared

2013
First Quarter	$	138.20	$	120.76	$	0.1875
Second Quarter		139.00		112.05		0.1875
Third Quarter		173.92		133.24		0.1875
Fourth Quarter		188.30		156.01		0.1875
2012
First Quarter	$	119.97	$	99.82	$	0.1700
Second Quarter		114.33		82.48		0.1700
Third Quarter		119.69		87.54		0.1700
Fourth Quarter		124.50		107.76		0.1700

On February 24, 2014, EOG's Board of Directors (Board) approved a two-for-one stock split in the form of a stock dividend, payable on March 31, 2014, to stockholders of record as of March 17, 2014. Also on February 24, 2014, the Board increased the quarterly cash dividend on the common stock by 33% from the current $0.09375 per share post-split ($0.1875 per share pre-split) to $0.125 per share post-split ($0.25 per share pre-split), effective beginning with the dividend to be paid on April 30, 2014, to stockholders of record as of April 16, 2014.

As of February 12, 2014, there were approximately 1,800 record holders and approximately 270,000 beneficial owners of EOG's common stock.

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

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

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

October 1, 2013 - October 31, 2013		23,519	$	176.30		-		6,386,200
November 1, 2013 - November 30, 2013		8,313	$	171.15		-		6,386,200
December 1, 2013 - December 31, 2013		15,641	$	161.89		-		6,386,200
Total		47,473	$	170.65

(1)

The 47,473 total shares for the quarter ended December 31, 2013, and the 427,409 shares for the full year 2013 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 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 2013, EOG did not repurchase any shares under the Board-authorized repurchase program.

Comparative Stock Performance

The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the 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 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, 2008 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, 2013)

*Cumulative total return assumes reinvestment of dividends.

	2008		2009		2010		2011		2012		2013

EOG	$	100.00	$	147.36	$	139.26	$	151.07	$	186.45	$	260.09
S&P 500	$	100.00	$	126.46	$	145.51	$	148.58	$	172.35	$	228.18
S&P O&G E&P	$	100.00	$	142.10	$	155.27	$	145.29	$	150.59	$	191.99

ITEM 6. Selected Financial Data

(In Thousands, Except Per Share Data)

Year Ended December 31	2013		2012		2011		2010		2009

Statement of Income Data:
Net Operating Revenues	$	14,487,118	$	11,682,636	$	10,126,115	$	6,099,896	$	4,786,959
Operating Income	$	3,675,211	$	1,479,797	$	2,113,309	$	523,319	$	970,841

Net Income	$	2,197,109	$	570,279	$	1,091,123	$	160,654	$	546,627
Net Income Per Share
Basic	$	8.13	$	2.13	$	4.15	$	0.64	$	2.20
Diluted	$	8.04	$	2.11	$	4.10	$	0.63	$	2.17
Dividends Per Common Share	$	0.75	$	0.68	$	0.64	$	0.62	$	0.58
Average Number of Common Shares
Basic		270,170		267,577		262,735		250,876		248,996
Diluted		273,114		270,762		266,268		254,500		251,884

At December 31	2013		2012		2011		2010		2009

Balance Sheet Data:
Total Property, Plant and Equipment, Net	$	26,148,836	$	23,337,681	$	21,288,824	$	18,680,900	$	16,139,225
Total Assets		30,574,238		27,336,578		24,838,797		21,624,233		18,118,667
Long-Term Debt and Current Portion of Long-Term Debt		5,913,221		6,312,181		5,009,166		5,223,341		2,797,000
Total Stockholders' Equity		15,418,459		13,284,764		12,640,904		10,231,632		9,998,042

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, China and Argentina. 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 2013 totaled $2,197 million as compared to $570 million for 2012. At December 31, 2013, EOG's total estimated net proved reserves were 2,119 million barrels of oil equivalent (MMBoe), an increase of 308 MMBoe from December 31, 2012. During 2013, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 257 million barrels (MMBbl), and net proved natural gas reserves increased by 305 billion cubic feet or 51 MMBoe.

Operations

Several important developments have occurred since January 1, 2013.

United States and Canada. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and liquids-rich natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and liquids-rich reservoirs. In 2013, EOG focused its efforts on developing its existing North American crude oil and liquids-rich acreage and testing methods to improve the recovery factor of the oil-in-place in these plays. Increasing drilling and completion efficiencies and improving the recovery factor of oil-in-place are expected to continue to be areas of emphasis in 2014. In addition, EOG continues to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 63% of total North American production during 2013 compared to 53% in 2012. This liquids growth primarily reflects increased production from the South Texas Eagle Ford, the North Dakota Bakken and the Permian Basin. In 2013, EOG's net Eagle Ford production averaged 140.9 thousand barrels per day (MBbld) of crude oil and condensate and NGLs as compared to 83.5 MBbld in 2012. Based on current trends, EOG expects its 2014 crude oil and condensate and NGLs production to continue to increase both in total and as a percentage of total company production as compared to 2013. EOG's major producing areas are in New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

EOG continues to deliver its crude oil to various markets in the United States, including sales points on the Gulf Coast where sales are based upon the Light Louisiana Sweet crude oil index. EOG's crude-by-rail facilities provide EOG the flexibility to direct its crude oil shipments via rail car to the most favorable markets, including the Gulf Coast, Cushing, Oklahoma, and other markets.

In December 2012, EOG Resources Canada Inc. (EOGRC) signed a purchase and sale agreement for the sale of its entire interest in the planned Kitimat liquefied natural gas export terminal, the proposed Pacific Trail Pipelines and approximately 28,500 undeveloped net acres in the Horn River Basin. The transaction closed in February 2013.

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, Block 4(a) and Modified U(b) Block and the EMZ Area, have been developed and are producing natural gas sold to the National Gas Company of Trinidad and Tobago and crude oil and condensate sold to the Petroleum Company of Trinidad and Tobago Limited. During 2013, EOG completed its four-well program in the Modified U(a) Block, drilling three development wells and one successful exploratory well. All four wells began production in 2013. In addition, an existing well was successfully recompleted and began production in 2013. EOG expects to drill three net wells in the SECC and Modified U(b) Blocks during 2014.

In the United Kingdom, EOG continues to make progress in the development of its 100% working interest East Irish Sea Conwy crude oil discovery. In 2013, after drilling an appraisal well, EOG determined that the adjoining Corfe field did not contain proved commercial reserves. In 2012, the U.K. Department of Energy and Climate Change approved the field development plans, and the Conwy production platform and pipelines were installed during 2012 and 2013. In 2013, modifications to the nearby third-party owned Douglas platform began and a crude oil processing module was installed. The Douglas platform will be used to process Conwy production. During 2013, the three-well Conwy development drilling program was completed with first production from the Conwy field anticipated in late 2014. In 2013, costs totaling $24.1 million associated with the Central North Sea Columbus natural gas project were written off. Also in 2013, EOG drilled an unsuccessful exploratory well in the Central North Sea Block 21/12b. In the first quarter of 2014, EOG drilled an unsuccessful exploratory well in the East Irish Sea Block 110/7b.

In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuan Zhong Block exploration area in the Sichuan Basin, Sichuan Province, China. In October 2008, EOG obtained the rights to shallower zones on the acquired acreage. During the first half of 2013, EOG successfully recompleted a well and drilled and completed an additional well, both of which began production in the latter part of 2013. Additionally in 2013, EOG drilled one well that is expected to be completed and begin producing in 2014. EOG plans to drill six additional wells on its acreage in 2014.

In 2011, EOG signed two exploration contracts and one farm-in agreement covering approximately 95,000 net acres in the Neuquén Basin in Neuquén Province, Argentina. During 2013, EOG completed a well in the Aguada del Chivato Block that was drilled in 2012. Also, in late 2013, EOG participated in the drilling of a vertical well in the Cerro Avispa Block. In 2014, EOG plans to complete this vertical well, participate in the drilling of a well in the Cerro Avispa Block and a well in the Bajo del Toro Block. EOG continues to evaluate its drilling results and exploration program in Argentina.

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

Capital Structure

One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 28% at December 31, 2013 and 32% at December 31, 2012. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On October 1, 2013, EOG repaid at maturity the $400 million principal amount of its 6.125% Senior Notes due 2013 (6.125% Senior Notes). At December 31, 2013, $350 million principal amount of Floating Rate Senior Notes due 2014 (Floating Rate Notes) and $150 million principal amount of 4.75% Subsidiary Debt due 2014 were classified as long-term debt based upon EOG's ability and intent to ultimately replace such amounts with other long-term debt. On February 3, 2014, EOG repaid upon maturity the Floating Rate Notes and settled the related interest rate swap.

During 2013, EOG funded $7.2 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid at maturity the 6.125% Senior Notes, paid $199 million in dividends to common stockholders and purchased $64 million of treasury stock in connection with stock compensation plans, primarily by utilizing cash provided from its operating activities, net proceeds of $761 million from the sale of certain North American assets, $56 million of excess tax benefits from stock compensation and proceeds of $39 million from stock options exercised and employee stock purchase plan activity.

Total anticipated 2014 capital expenditures are estimated to range from approximately $8.1 billion to $8.3 billion, excluding acquisitions. The majority of 2014 expenditures will be focused on United States crude oil and, to a lesser extent, liquids-rich natural gas drilling activity. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its $2.0 billion senior unsecured Revolving Credit Agreement and equity and debt offerings.

When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2013, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.

Net Operating Revenues

During 2013, net operating revenues increased $2,804 million, or 24%, to $14,487 million from $11,683 million in 2012. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $2,798 million, or 35%, to $10,756 million in 2013 from $7,958 million in 2012. Revenues from the sales of crude oil and condensate and NGLs in 2013 were approximately 84% of total wellhead revenues compared to 80% in 2012. During 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million compared to net gains of $394 million in 2012. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, NGLs and natural gas as well as gathering fees associated with gathering third-party natural gas, increased $547 million, or 18%, during 2013, to $3,644 million from $3,097 million in 2012. Gains on asset dispositions, net, totaled $198 million and $193 million in 2013 and 2012, respectively.

Wellhead volume and price statistics for the years ended December 31, 2013, 2012 and 2011 were as follows:

Year Ended December 31	2013		2012		2011

Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
United States		212.1		149.3		102.0
Canada		7.0		7.0		7.9
Trinidad		1.2		1.5		3.4
Other International ⁽²⁾		0.1		0.1		0.1
Total		220.4		157.9		113.4

Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
United States	$	103.81	$	98.38	$	92.92
Canada		87.05		86.08		91.92
Trinidad		90.30		92.26		90.62
Other International ⁽²⁾		89.11		89.57		100.11
Composite		103.20		97.77		92.79

Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
United States		64.3		55.1		41.5
Canada		0.9		0.8		0.9
Total		65.2		55.9		42.4

Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
United States	$	32.46	$	35.41	$	50.37
Canada		39.45		44.13		52.69
Composite		32.55		35.54		50.41

Natural Gas Volumes (MMcfd) ⁽¹⁾
United States		908		1,034		1,113
Canada		76		95		132
Trinidad		355		378		344
Other International ⁽²⁾		8		9		13
Total		1,347		1,516		1,602

Average Natural Gas Prices ($/Mcf) ⁽³⁾
United States	$	3.32	$	2.51	$	3.92
Canada		3.08		2.49		3.71
Trinidad		3.68		3.72		3.53
Other International ⁽²⁾		6.45		5.71		5.62
Composite		3.42		2.83		3.83

Crude Oil Equivalent Volumes (MBoed) ⁽⁴⁾
United States		427.9		376.6		329.1
Canada		20.5		23.6		30.7
Trinidad		60.4		64.5		60.7
Other International ⁽²⁾		1.3		1.7		2.2
Total		510.1		466.4		422.7

Total MMBoe ⁽⁴⁾		186.2		170.7		154.3

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

(2)	Other International includes EOG's United Kingdom, China and Argentina 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, NGLs and natural gas. Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs 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.

2013 compared to 2012. Wellhead crude oil and condensate revenues in 2013 increased $2,642 million, or 47%, to $8,301 million from $5,659 million in 2012, due to an increase of 63 MBbld, or 40%, in wellhead crude oil and condensate deliveries ($2,205 million) and a higher composite average wellhead crude oil and condensate price ($437 million). The increase in deliveries primarily reflects increased production in the Eagle Ford, the North Dakota Bakken and the Permian Basin. EOG's composite average wellhead crude oil and condensate price for 2013 increased 6% to $103.20 per barrel compared to $97.77 per barrel in 2012.

NGLs revenues in 2013 increased $47 million, or 6%, to $774 million from $727 million in 2012, due to an increase of 9 MBbld, or 17%, in NGLs deliveries ($118 million), partially offset by a lower composite average price ($71 million). The increase in deliveries primarily reflects increased volumes in the Eagle Ford. EOG's composite average NGLs price in 2013 decreased 8% to $32.55 per barrel compared to $35.54 per barrel in 2012.

Wellhead natural gas revenues in 2013 increased $109 million, or 7%, to $1,681 million from $1,572 million in 2012. The increase was due to a higher composite average wellhead natural gas price ($288 million), partially offset by decreased natural gas deliveries ($179 million). EOG's composite average wellhead natural gas price increased 21% to $3.42 per Mcf in 2013 compared to $2.83 per Mcf in 2012. Natural gas deliveries in 2013 decreased 169 MMcfd, or 11%, primarily due to decreased production in the United States (126 MMcfd), Trinidad (23 MMcfd) and Canada (19 MMcfd). The decrease in the United States was attributable to asset sales and reduced natural gas drilling activity. The decrease in Trinidad was primarily attributable to higher contractual deliveries in 2012.

During 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million, which included net cash received from settlements of commodity derivative contracts of $116 million. During 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $394 million, which included net cash received from settlements of commodity derivative contracts of $711 million.

Gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas. Purchases and sales 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 2013, gathering, processing and marketing revenues and marketing costs increased, compared to 2012, primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs in 2013 decreased $66 million, compared to 2012, due primarily to lower margins on crude oil marketing activities.

2012 compared to 2011. Wellhead crude oil and condensate revenues in 2012 increased $1,821 million, or 47%, to $5,659 million from $3,838 million in 2011, due to an increase of 45 MBbld, or 39%, in wellhead crude oil and condensate deliveries ($1,533 million) and a higher composite average wellhead crude oil and condensate price ($288 million). The increase in deliveries primarily reflects increased production in the Eagle Ford and the North Dakota Bakken. EOG's composite average wellhead crude oil and condensate price for 2012 increased 5% to $97.77 per barrel compared to $92.79 per barrel in 2011.

NGLs revenues in 2012 decreased $52 million, or 7%, to $727 million from $779 million in 2011, due to a lower composite average price ($304 million), partially offset by an increase of 14 MBbld, or 32%, in NGLs deliveries ($252 million). The increase in deliveries primarily reflects increased volumes in the Eagle Ford (7 MBbld), the Fort Worth Basin Barnett Shale area (3 MBbld) and the Permian Basin (2 MBbld). EOG's composite average NGLs price in 2012 decreased 30% to $35.54 per barrel compared to $50.41 per barrel in 2011.

Wellhead natural gas revenues in 2012 decreased $669 million, or 30%, to $1,572 million from $2,241 million in 2011. The decrease was due to a lower composite average wellhead natural gas price ($554 million) and decreased natural gas deliveries ($115 million). Natural gas deliveries in 2012 decreased 86 MMcfd, or 5%, to 1,516 MMcfd from 1,602 MMcfd in 2011. The decrease was primarily due to lower production in the United States (79 MMcfd) and Canada (37 MMcfd), partially offset by increased production in Trinidad (34 MMcfd). The decrease in the United States was primarily attributable to asset sales and reduced natural gas drilling activity. The decrease in Canada primarily reflects decreased production in Alberta and the Horn River Basin area. The increase in Trinidad was primarily attributable to an increase in contractual deliveries. EOG's composite average wellhead natural gas price decreased 26% to $2.83 per Mcf in 2012 from $3.83 per Mcf in 2011.

During 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $394 million, which included net cash received from settlements of commodity derivative contracts of $711 million. During 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $626 million, which included net cash received from settlements of commodity derivative contracts of $181 million.

During 2012, gathering, processing and marketing revenues and marketing costs increased, compared to 2011, primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs in 2012 totaled $61 million compared to $44 million in 2011.

Operating and Other Expenses

2013 compared to 2012. During 2013, operating expenses of $10,812 million were $609 million higher than the $10,203 million incurred during 2012. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2013 and 2012:

	2013		2012

Lease and Well	$	5.94	$	5.85
Transportation Costs		4.58		3.52
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties		18.79		17.71
Other Property, Plant and Equipment		0.55		0.85
General and Administrative (G&A)		1.87		1.94
Net Interest Expense		1.26		1.25
Total ⁽¹⁾	$	32.99	$	31.12

(1)

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

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2013 compared to 2012 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

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 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 $1,106 million in 2013 increased $106 million from $1,000 million in 2012 primarily due to higher operating and maintenance expenses in the United States ($48 million) and Canada ($13 million) and increased workover expenditures in the United States ($38 million).

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include transportation fees, costs associated with crude-by-rail operations, 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 and fuel costs.

Transportation costs of $853 million in 2013 increased $252 million from $601 million in 2012 primarily due to increased transportation costs related to production from the Eagle Ford ($136 million), the Rocky Mountain area ($84 million) and the Fort Worth Basin Barnett Shale area ($27 million).

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group 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, economic factors 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 generally calculated using the straight-line depreciation method over the useful lives of the assets. Other property, plant and equipment consists of gathering, transportation and processing infrastructure 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 2013 increased $431 million to $3,601 million from $3,170 million in 2012. DD&A expenses associated with oil and gas properties in 2013 were $473 million higher than in 2012 primarily due to increased production in the United States ($347 million) and higher unit rates in the United States ($133 million) and Trinidad ($44 million), partially offset by a decrease in production in Canada ($29 million) and Trinidad ($10 million) and lower unit rates in Canada ($12 million). DD&A unit rates in the United States increased due primarily to downward revisions of natural gas reserves at December 31, 2012, and a proportional increase in production from higher cost properties.

DD&A expenses associated with other property, plant and equipment were $42 million lower in 2013 than in 2012 primarily in the Fort Worth Basin Barnett Shale area ($32 million), the Eagle Ford ($7 million) and the Rocky Mountain area ($7 million).

G&A expenses of $348 million in 2013 were $17 million higher than 2012 due primarily to higher costs associated with supporting expanding operations.

Net interest expense of $235 million in 2013 was $22 million higher than 2012 due primarily to interest expense on the $1,250 million principal amount of 2.625% Senior Notes due 2023 issued in September 2012 ($23 million). This was partially offset by a reduction in interest expense on the 6.125% Senior Notes, which were repaid at maturity in October 2013 ($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 $10 million to $108 million in 2013 compared to $98 million in 2012. The increase primarily reflects increased activities in the Eagle Ford ($22 million), partially offset by decreased costs in Canada ($9 million).

Exploration costs of $161 million in 2013 decreased $25 million from $186 million in 2012 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; other property, plant and equipment; and other assets. 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 DD&A group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC). In certain instances, EOG utilizes accepted bids as the basis for determining fair value.

Impairments of $287 million in 2013 decreased $984 million from $1,271 million in 2012 primarily due to decreased impairments of proved and unproved properties in Canada ($881 million), decreased impairments of proved properties and other assets in the United States ($98 million) and decreased amortization of unproved property costs in the United States ($17 million). EOG recorded impairments of proved and unproved properties; other property, plant and equipment; and other assets of $172 million and $1,133 million in 2013 and 2012, respectively. The 2013 and 2012 amounts include impairments of $7 million and $1,022 million, respectively, related to certain North American assets as a result of declining commodity prices and using accepted bids for determining fair value.

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 2013 increased $129 million to $624 million (5.8% of wellhead revenues) from $495 million (6.2% of wellhead revenues) in 2012. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($122 million) primarily as a result of increased wellhead revenues and higher ad valorem/property taxes in the United States ($15 million), partially offset by decreased severance/production taxes in Canada ($9 million).

Other expense, net, was $3 million in 2013 compared to other income, net, of $14 million in 2012. The decrease of $17 million was primarily due to losses on warehouse stock sales and adjustments.

Income tax provision of $1,240 million in 2013 increased $530 million from $710 million in 2012 due primarily to higher pretax income. The net effective tax rate for 2013 decreased to 36% from 55% in 2012 due primarily to the absence of certain 2012 Canadian losses (26% statutory tax rate).

2012 compared to 2011. During 2012, operating expenses of $10,203 million were $2,190 million higher than the $8,013 million incurred in 2011. The following table presents the costs per Boe for the years ended December 31, 2012 and 2011:

	2012		2011

Lease and Well	$	5.85	$	6.11
Transportation Costs		3.52		2.79
DD&A -
Oil and Gas Properties		17.71		15.52
Other Property, Plant and Equipment		0.85		0.79
G&A		1.94		1.98
Net Interest Expense		1.25		1.36
Total ⁽¹⁾	$	31.12	$	28.55

(1)

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

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A and G&A for 2012 compared to 2011 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

Lease and well expenses of $1,000 million in 2012 increased $58 million from $942 million in 2011 primarily due to higher operating and maintenance expenses in the United States ($60 million) and Trinidad ($5 million) and increased lease and well administrative expenses in the United States ($15 million), partially offset by lower operating and maintenance expenses in Canada ($12 million) and decreased workover expenditures in Canada ($6 million) and the United States ($5 million).

Transportation costs of $601 million in 2012 increased $171 million from $430 million in 2011 primarily due to increased transportation costs related to production from the Eagle Ford ($101 million) and the Rocky Mountain area ($73 million).

DD&A expenses in 2012 increased $654 million to $3,170 million from $2,516 million in 2011. DD&A expenses associated with oil and gas properties in 2012 were $631 million higher than in 2011 primarily due to higher unit rates ($379 million), increased production in the United States ($296 million) and Trinidad ($7 million), partially offset by a decrease in production in Canada ($57 million). DD&A rates increased due primarily to a proportional increase in production from higher cost properties in the United States ($331 million), Trinidad ($33 million) and Canada ($20 million).

DD&A expenses associated with other property, plant and equipment were $23 million higher in 2012 than in 2011 primarily due to gathering and processing assets being placed in service in the Eagle Ford.

G&A expenses of $332 million in 2012 were $27 million higher than 2011 due primarily to higher employee-related costs ($22 million) and higher information systems costs ($5 million).

Gathering and processing costs increased $17 million to $98 million in 2012 compared to $81 million in 2011. The increase primarily reflects increased activities in the Eagle Ford ($21 million), partially offset by decreased costs in the Fort Worth Basin Barnett Shale area ($7 million).

Exploration costs of $186 million in 2012 increased $14 million from $172 million for the same prior year period primarily due to increased expenditures in the United States.

Impairments of $1,271 million in 2012 increased $240 million from $1,031 million in 2011 primarily due to increased impairments of proved and unproved properties in Canada ($534 million), partially offset by decreased impairments of proved properties and other assets in the United States ($232 million) and decreased amortization of unproved property costs ($50 million) in the United States. EOG recorded impairments of proved and unproved properties; other property, plant and equipment; and other assets of $1,133 million and $834 million in 2012 and 2011, respectively. The 2012 and 2011 amounts include impairments of $1,022 million and $745 million related to certain North American assets as a result of declining commodity prices and using accepted bids for determining fair value.

Taxes other than income in 2012 increased $84 million to $495 million (6.2% of wellhead revenues) from $411 million (6.0% of wellhead revenues) in 2011. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($70 million) primarily as a result of increased wellhead revenues and a newly enacted fee imposed by the State of Pennsylvania on certain wells drilled in the state in 2012 and prior years and higher ad valorem/property taxes in the United States ($30 million), partially offset by decreased severance/production taxes in Trinidad ($17 million).

Other income, net, was $14 million in 2012 compared to $7 million in 2011. The increase of $7 million was primarily due to higher interest income ($8 million) primarily as a result of interest on severance tax refunds, an increase in foreign currency transaction gains ($8 million) and higher equity income from ammonia plants in Trinidad ($3 million), partially offset by increased losses on warehouse stock ($5 million) and higher operating losses on EOG's investment in the PTP ($4 million).

Income tax provision of $710 million in 2012 decreased $109 million from $819 million in 2011 due primarily to lower pretax income. The net effective tax rate for 2012 increased to 55% from 43% in 2011. The effective tax rate for 2012 exceeded the United States statutory tax rate (35%) due primarily to foreign losses in Canada (26% statutory tax rate) and Canadian valuation allowances.

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2013, were funds generated from operations, proceeds from asset sales, net proceeds from the sale of common stock, net proceeds from issuances of long-term debt, excess tax benefits from stock-based compensation, proceeds from stock options exercised and employee stock purchase plan activity, net commercial paper borrowings and borrowings under other uncommitted credit facilities and revolving credit facilities. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; dividend payments to stockholders; repayments of debt; and purchases of treasury stock in connection with stock compensation plans.

2013 compared to 2012. Net cash provided by operating activities of $7,329 million in 2013 increased $2,092 million from $5,237 million in 2012 primarily reflecting an increase in wellhead revenues ($2,798 million), favorable changes in working capital and other assets and liabilities ($405 million) and a decrease in net cash paid for income taxes ($65 million), partially offset by an unfavorable change in the net cash received from the settlement of financial commodity derivative contracts ($595 million), an increase in cash operating expenses ($478 million) and an increase in net cash paid for interest expense ($39 million).

Net cash used in investing activities of $6,315 million in 2013 increased by $196 million from $6,119 million for the same period of 2012 due primarily to a decrease in proceeds from sales of assets ($549 million); and an increase in restricted cash ($66 million); partially offset by a decrease in additions to other property, plant and equipment ($256 million); favorable changes in working capital associated with investing activities ($125 million); and a decrease in additions to oil and gas properties ($38 million).

Net cash used in financing activities of $574 million during 2013 included the repayment of long-term debt ($400 million), cash dividend payments ($199 million) and treasury stock purchases in connection with stock compensation plans ($64 million). Cash provided by financing activities in 2013 included excess tax benefits from stock-based compensation ($56 million) and proceeds from stock options exercised and employee stock purchase plan activity ($39 million).

2012 compared to 2011. Net cash provided by operating activities of $5,237 million in 2012 increased $659 million from $4,578 million in 2011 primarily reflecting an increase in wellhead revenues ($1,100 million) and a favorable change in the net cash received from the settlement of financial commodity derivative contracts ($531 million), partially offset by unfavorable changes in working capital and other assets and liabilities ($422 million), an increase in cash operating expenses ($369 million) and an increase in net cash paid for income taxes ($100 million).

Net cash used in investing activities of $6,119 million in 2012 increased by $364 million from $5,755 million for the same period of 2011 due primarily to an increase in additions to oil and gas properties ($441 million) and a decrease in proceeds from sales of assets ($123 million), partially offset by favorable changes in working capital associated with investing activities ($163 million) and a decrease in additions to other property, plant and equipment ($37 million).

Net cash provided by financing activities of $1,140 million in 2012 included net proceeds from the issuance of the Notes ($1,234 million), proceeds from stock options exercised and employee stock purchase plan activity ($83 million) and excess tax benefits from stock-based compensation ($67 million). Cash used in financing activities during 2012 included cash dividend payments ($181 million) and treasury stock purchases in connection with stock compensation plans ($59 million).

Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2013, 2012 and 2011 (in millions):

	2013		2012		2011
Expenditure Category
Capital
Drilling and Facilities	$	6,044	$	6,184	$	5,878
Leasehold Acquisitions ⁽¹⁾		414		505		301
Property Acquisitions		120		1		4
Capitalized Interest		49		50		58
Subtotal		6,627		6,740		6,241
Exploration Costs		161		186		172
Dry Hole Costs		75		15		53
Exploration and Development Expenditures		6,863		6,941		6,466
Asset Retirement Costs		134		127		133
Total Exploration and Development Expenditures		6,997		7,068		6,599
Other Property, Plant and Equipment ⁽²⁾		364		686		656
Total Expenditures	$	7,361	$	7,754	$	7,255

(1)	In 2013 and 2012, leasehold acquisitions included $5 million and $20 million, respectively, related to non-cash property exchanges.

(2)	In 2012, other property, plant and equipment included non-cash additions of $66 million in connection with a capital lease transaction in the Eagle Ford.

Exploration and development expenditures of $6,863 million for 2013 were $78 million lower than the prior year due primarily to decreased drilling and facilities expenditures in the United States ($137 million), Canada ($128 million) and Argentina ($32 million); decreased leasehold acquisition expenditures in the United States ($60 million) and Canada ($31 million); and decreased exploration geological and geophysical expenditures in the United States ($27 million). These decreases were partially offset by increased property acquisitions in the United States ($119 million) and increased drilling and facilities expenditures in Trinidad ($85 million), the United Kingdom ($64 million) and China ($14 million). The 2013 exploration and development expenditures of $6,863 million included $5,952 million in development, $742 million in exploration, $120 million in property acquisitions and $49 million in capitalized interest. The 2012 exploration and development expenditures of $6,941 million included $5,989 million in development, $901 million in exploration and $50 million in capitalized interest. 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.

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.

Derivative Transactions

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, 2013, as a net liability of $119 million. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at February 24, 2014, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

Crude Oil Derivative Contracts
			Weighted
	Volume		Average Price
	(Bbld)		($/Bbl)
2014 ⁽¹⁾
January 2014 (closed)		156,000	$	96.30
February 2014		171,000		96.35
March 2014		181,000		96.55
April 1, 2014 through May 31, 2014		171,000		96.55
June 2014		161,000		96.33
July 1, 2014 through December 31, 2014		64,000		95.18

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month, six-month and nine-month periods. Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014. Options covering a notional volume of 10,000 Bbld are exercisable on or about May 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $100.00 per barrel for each month during the period June 1, 2014 through August 31, 2014. Options covering a notional volume of 118,000 Bbld are exercisable on or about June 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 118,000 Bbld at an average price of $96.64 per barrel for each month during the period July 1, 2014 through December 31, 2014. Options covering a notional volume of 69,000 Bbld are exercisable on or about December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 69,000 Bbld at an average price of $95.20 per barrel for each month during the period January 1, 2015 through June 30, 2015.

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at February 24, 2014, 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
			Weighted
	Volume		Average Price
	(MMBtud)		($/MMBtu)
2014 ⁽¹⁾
January 2014 (closed)		230,000	$	4.51
February 2014 (closed)		710,000		4.57
March 1, 2014 through December 31, 2014		330,000		4.55

2015 ⁽²⁾
January 1, 2015 through December 31, 2015		175,000	$	4.51

(1)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. All 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 480,000 MMBtud at an average price of $4.63 per MMBtu for each month during the period March 1, 2014 through December 31, 2014.

(2)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. All 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 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period January 1, 2015 through December 31, 2015.

Financing

EOG's debt-to-total capitalization ratio was 28% at December 31, 2013, compared to 32% at December 31, 2012. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

During 2013, the principal amount of total debt outstanding decreased $400 million to $5,890 million at December 31, 2013, from $6,290 million at December 31, 2012. The estimated fair value of EOG's debt at December 31, 2013 and 2012 was $6,222 million and $7,032 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable inputs regarding interest rates available to EOG at year-end. EOG's debt is primarily at fixed interest rates. While changes in interest rates affect the fair value of EOG's debt, such changes do not expose EOG to material fluctuations in earnings or cash flow.

During 2013, EOG funded its capital programs primarily by utilizing cash provided by operating activities, proceeds from asset sales and cash provided by borrowings from its commercial paper program. While EOG maintains a $2.0 billion commercial paper program, the maximum outstanding at any time during 2013 was $570 million, and the amount outstanding at year-end was zero. The average borrowings outstanding under the commercial paper program was $37 million during the year 2013. EOG considers this excess availability, which is backed by its $2.0 billion senior unsecured Revolving Credit Agreement (Credit Agreement) described in Note 2 to Consolidated Financial Statements, to be ample to meet its ongoing operating needs.

Contractual Obligations

The following table summarizes EOG's contractual obligations at December 31, 2013, (in thousands):

Contractual Obligations ⁽¹⁾	Total		2014			2015 - 2016		2017 - 2018	2019 & Beyond

Current and Long-Term Debt	$	5,890,000	$	500,000	$	900,000	$	950,000	$	3,540,000
Capital Lease		57,187		6,764		11,712		13,318		25,393
Non-Cancelable Operating Leases		433,223		119,948		87,372		68,337		157,566
Interest Payments on Long-Term Debt and Capital Lease		1,419,340		235,635		434,713		376,314		372,678
Transportation and Storage Service Commitments ⁽²⁾		4,897,090		1,254,428		1,470,654		1,153,769		1,018,239
Drilling Rig Commitments ⁽³⁾		311,361		187,115		115,241		9,005		-
Seismic Purchase Obligations		10,383		10,196		187		-		-
Fracturing Services Obligations		319,660		162,692		117,784		39,184		-
Other Purchase Obligations		62,932		42,635		17,589		2,283		425
Total Contractual Obligations	$	13,401,176	$	2,519,413	$	3,155,252	$	2,612,210	$	5,114,301

(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, 2013. 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).

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 2013, 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 2013 was the Canadian dollar. The fluctuation of the Canadian dollar in 2013 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 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, 2013, EOG recorded the fair value of the foreign currency swap of $40 million in Current Liabilities - Other 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 an increase of $2 million to 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, NGLs, natural gas, ammonia and methanol prices in the future. The market price of crude oil and condensate, NGLs and natural gas in 2014 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 2014 crude oil derivative contracts (exclusive of options) and based on EOG's tax position, EOG's price sensitivity in 2014 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $44 million for net income and $65 million for cash flows from operating activities. Including the impact of EOG's 2014 natural gas derivative contracts (exclusive of options) and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2014 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 $13 million for net income and $19 million for cash flows from operating activities. For information regarding EOG's crude oil and natural gas financial commodity derivative contracts at February 24, 2014, see "Derivative Transactions" above.

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. In particular, EOG will be focused on United States crude oil drilling activity in its Eagle Ford, Bakken and Three Forks and Permian Basin plays and, to a lesser extent, liquids-rich natural gas drilling. 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 2014 capital expenditures of $8.1 to $8.3 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 has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its Credit Agreement and equity and debt offerings.

Operations. EOG expects to increase overall production in 2014 byapprozimately 11.5% over 2013 levels. Total liquids production is expected to increase by 24%, comprised of an increase in crude oil and condensate and NGLs production of 27% and 12%, respectively. North American natural gas production is expected to decrease by 6% from 2013 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 application. 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 in accordance with United States Securities and Exchange Commission regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of crude oil and condensate, NGLs 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 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 and "Supplemental Information to Consolidated Financial Statements."

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, 2012 and 2011, EOG had exploratory drilling costs related to projects that had been deferred for more than one year (see Note 15 to Consolidated Financial Statements). These costs met 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 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.

When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future 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 Measurement Topic of the ASC. In certain instances, EOG utilizes accepted bids as the basis for determining fair value. Estimates of undiscounted future 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 $39.26 per barrel to $110.04 per barrel and Henry Hub natural gas spot prices have ranged from approximately $2.03 per MMBtu to $5.96 per MMBtu. EOG's proved reserves estimates, including the timing of future production, are also subject to significant assumptions and 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.

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. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. Significant assumptions used in estimating future taxable income include future oil and gas prices and changes in tax rates. Changes in such assumptions could materially affect the recognized amounts of valuation allowances.

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, expected volatility of the price of shares of EOG's peer companies 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, statements regarding future commodity prices 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," "should" 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, unknown or currently unforeseen 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, NGLs, 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 is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and optimize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;

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

·	the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining 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, and EOG's ability to retain mineral licenses and leases;

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

·	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, facilities, equipment, materials and services;

·	the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) 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 (by EOG or third parties) of production, gathering, processing, refining, 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 conditions and developments around the world (such as political instability and armed conflict), 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;

·	physical, electronic and cyber security breaches; and

·	the other factors described under ITEM 1A, Risk Factors, on pages 17 through 26 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.

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, 2013. EOG's disclosure controls and procedures are designed to provide reasonable assurance that information that is required to be disclosed in the reports EOG files or submits under the Exchange Act is accumulated and communicated to EOG's management, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the United States Securities and Exchange Commission. Based on that 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, 2013.

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, 2013. 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 (1992). 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, 2013. 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 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, 2013, that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

ITEM 9B. Other Information

None.

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 2014 Annual Meeting of Stockholders to be filed not later than April 30, 2014 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 for Directors, Officers and Employees (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 "About EOG" 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 2014 Annual Meeting of Stockholders to be filed not later than April 30, 2014. 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 Matter

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 2014 Annual Meeting of Stockholders to be filed not later than April 30, 2014.

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, performance stock, performance 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. At the 2013 Annual Meeting of Stockholders in May 2013, EOG's stockholders approved the Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Amended and Restated Plan). As more fully discussed in the Amended and Restated Plan document, the Amended and Restated Plan, among other things, authorizes an additional 15,500,000 shares of EOG common stock for grant under the plan and extends the expiration date of the plan to May 2023. Under the Amended and Restated 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.

The 1992 Stock Plan and the 1993 Nonemployee Directors Stock Option Plan have also been approved by EOG's stockholders. Upon the effective date of the 2008 Plan, no further grants were made under the 1992 Stock Plan or the 1993 Non-Employee Directors Stock Option Plan. 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. 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 (as subsequently amended), payment of up to 50% of base salary and 100% of annual cash bonus, director's fees, vestings of restricted stock units granted to non-employee directors (and dividends credited thereon) under the 2008 Plan and 401(k) refunds (as defined in the Deferral 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 270,000 shares of EOG common stock have been authorized by the Board and registered for issuance under the Deferral Plan. As of December 31, 2013, 138,680 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, 2013.

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		5,220,996	⁽¹⁾	$	108.93		17,069,007	⁽²⁾
Equity Compensation Plans Not Approved by EOG Stockholders		109,679	⁽³⁾	$	26.70		131,320	⁽⁴⁾
Total		5,330,675		$	108.86		17,200,327

(1)

Does not include 1,622,154 outstanding restricted stock units and 113,943 outstanding performance units, for which shares of EOG common stock will be issued, on a one-for-one basis, upon the vesting of such grants.

(2)

Consists of (i) 16,571,359 shares remaining available for issuance under the 2008 Plan and (ii) 497,648 shares remaining available for purchase under the ESPP. Pursuant to the fungible share design of the 2008 Plan, each share issued as a SAR or stock option under the 2008 Plan counts as 1.0 share against the aggregate plan share limit, and each share issued as a "full value award" (i.e., as restricted stock, restricted stock units, performance stock or performance units) counts as 2.45 shares against the aggregate plan share limit. Thus, from the 16,571,359 shares remaining available for issuance under the 2008 Plan, (i) the maximum number of shares we could issue as SAR and stock option awards is 16,571,359 (i.e., if all shares remaining available for issuance under the 2008 Plan are issued as SAR and stock options awards) and (ii) the maximum number of shares we could issue as full value awards is 6,763,820 (i.e., if all shares remaining available for issuance under the 2008 Plan are issued as full value awards).

(3)

Includes 104,759 shares of EOG common stock to be issued in accordance with the Deferral Plan and participant deferral elections (i.e., in respect of the 104,759 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2013). The weighted-average exercise price in column (b) does not take into account these shares.

(4)

Represents phantom shares that remain available for issuance under the Deferral Plan.

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

ITEM 14. Principal Accounting Fees and Services

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-8 for a listing of the exhibits.

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, 2013	F-5

Consolidated Balance Sheets - December 31, 2013 and 2012	F-6

Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2013	F-7

Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2013	F-8

Notes to Consolidated Financial Statements	F-9

Supplemental Information to Consolidated Financial Statements	F-35

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, 2013. 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 (1992). 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, 2013.

Deloitte & Touche LLP, independent registered public accounting firm, was engaged to audit the consolidated financial statements 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 all minutes of meetings of stockholders, the Board of Directors and committees of the Board of Directors. 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.

WILLIAM R. THOMAS		TIMOTHY K. DRIGGERS
Chairman of the Board and		Vice President and Chief
Chief Executive Officer		Financial Officer

Houston, Texas
February 24, 2014

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, 2013 and 2012, 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, 2013. We also have audited the Company's internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements, 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 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Houston, Texas

February 24, 2014

F-4

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In Thousands, Except Per Share Data)

Year Ended December 31	2013			2012			2011
Net Operating Revenues
Crude Oil and Condensate	$	8,300,647		$	5,659,437		$	3,838,284
Natural Gas Liquids		773,970			727,177			779,364
Natural Gas		1,681,029			1,571,762			2,240,540
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		(166,349	)		393,744			626,053
Gathering, Processing and Marketing		3,643,749			3,096,694			2,115,792
Gains on Asset Dispositions, Net		197,565			192,660			492,909
Other, Net		56,507			41,162			33,173
Total		14,487,118			11,682,636			10,126,115
Operating Expenses
Lease and Well		1,105,978			1,000,052			941,954
Transportation Costs		853,044			601,431			430,322
Gathering and Processing Costs		107,871			97,945			80,727
Exploration Costs		161,346			185,569			171,658
Dry Hole Costs		74,655			14,970			53,230
Impairments		286,941			1,270,735			1,031,037
Marketing Costs		3,648,840			3,035,494			2,072,137
Depreciation, Depletion and Amortization		3,600,976			3,169,703			2,516,381
General and Administrative		348,312			331,545			304,811
Taxes Other Than Income		623,944			495,395			410,549
Total		10,811,907			10,202,839			8,012,806
Operating Income		3,675,211			1,479,797			2,113,309
Other Income (Expense), Net		(2,865	)		14,495			6,853
Income Before Interest Expense and Income Taxes		3,672,346			1,494,292			2,120,162
Interest Expense
Incurred		284,599			263,254			268,104
Capitalized		(49,139	)		(49,702	)		(57,741	)
Net Interest Expense		235,460			213,552			210,363
Income Before Income Taxes		3,436,886			1,280,740			1,909,799
Income Tax Provision		1,239,777			710,461			818,676
Net Income	$	2,197,109		$	570,279		$	1,091,123

Net Income Per Share
Basic	$	8.13		$	2.13		$	4.15
Diluted	$	8.04		$	2.11		$	4.10
Dividends Declared per Common Share	$	0.75		$	0.68		$	0.64
Average Number of Common Shares
Basic		270,170			267,577			262,735
Diluted		273,114			270,762			266,268
Comprehensive Income
Net Income	$	2,197,109		$	570,279		$	1,091,123
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		(29,395	)		37,739			(32,597	)
Foreign Currency Swap Transaction		1,652			1,589			(1,571	)
Income Tax Related to Foreign Currency Swap Transaction		1			(404	)		404
Interest Rate Swap Transaction		2,737			(134	)		(5,223	)
Income Tax Related to Interest Rate Swap Transaction		(981	)		48			1,878
Other		1,925			(689	)		(1,216	)
Other Comprehensive Income (Loss)		(24,061	)		38,149			(38,325	)
Comprehensive Income	$	2,173,048		$	608,428		$	1,052,798

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	2013			2012

ASSETS
Current Assets
Cash and Cash Equivalents	$	1,318,209		$	876,435
Accounts Receivable, Net		1,658,853			1,656,618
Inventories		563,268			683,187
Assets from Price Risk Management Activities		8,260			166,135
Income Taxes Receivable		4,797			29,163
Deferred Income Taxes		244,606			-
Other		274,022			178,346
Total		4,072,015			3,589,884

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		42,821,803			38,126,298
Other Property, Plant and Equipment		2,967,085			2,740,619
Total Property, Plant and Equipment		45,788,888			40,866,917
Less: Accumulated Depreciation, Depletion and Amortization		(19,640,052	)		(17,529,236	)
Total Property, Plant and Equipment, Net		26,148,836			23,337,681
Other Assets		353,387			409,013
Total Assets	$	30,574,238		$	27,336,578

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,254,418		$	2,078,948
Accrued Taxes Payable		159,365			162,083
Dividends Payable		50,795			45,802
Liabilities from Price Risk Management Activities		127,542			7,617
Deferred Income Taxes		-			22,838
Current Portion of Long-Term Debt		6,579			406,579
Other		263,017			200,191
Total		2,861,716			2,924,058

Long-Term Debt		5,906,642			5,905,602
Other Liabilities		865,067			894,758
Deferred Income Taxes		5,522,354			4,327,396
Commitments and Contingencies (Note 7)

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 273,189,220 Shares and 271,958,495 Shares Issued at December 31, 2013 and 2012, respectively		202,732			202,720
Additional Paid in Capital		2,646,879			2,500,340
Accumulated Other Comprehensive Income		415,834			439,895
Retained Earnings		12,168,277			10,175,631
Common Stock Held in Treasury, 103,415 Shares and 326,264 Shares at December 31, 2013 and 2012, respectively		(15,263	)		(33,822	)
Total Stockholders' Equity		15,418,459			13,284,764
Total Liabilities and Stockholders' Equity	$	30,574,238		$	27,336,578

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)

	Common Stock		Additional Paid In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Common Stock Held In Treasury			Total Stockholders' Equity
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	)
Other Comprehensive Income (Loss)		-		-			(38,325	)		-			-			(38,325	)
Change in Treasury Stock - Stock Compensation Plans, Net		-		(18,622	)		-			-			(5,413	)		(24,035	)
Excess Tax Benefit 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
Net Income		-		-			-			570,279			-			570,279
Common Stock Issued Under Stock Plans		21		83,197			-			-			-			83,218
Common Stock Dividends Declared, $0.68 Per Share		-		-			-			(183,993	)		-			(183,993	)
Other Comprehensive Income		-		-			38,149			-			-			38,149
Change in Treasury Stock - Stock Compensation Plans, Net		-		(47,123	)		-			-			(11,465	)		(58,588	)
Excess Tax Benefit from Stock-Based Compensation		-		67,035			-			-			-			67,035
Restricted Stock and Restricted Stock Units, Net		6		(2,364	)		-			-			2,358			-
Stock-Based Compensation Expenses		-		127,504			-			-			-			127,504
Treasury Stock Issued as Compensation		-		39			-			-			217			256
Balance at December 31, 2012		202,720		2,500,340			439,895			10,175,631			(33,822	)		13,284,764
Net Income		-		-			-			2,197,109			-			2,197,109
Common Stock Issued Under Stock Plans		6		38,723			-			-			-			38,729
Common Stock Dividends Declared, $0.75 Per Share		-		-			-			(204,463	)		-			(204,463	)
Other Comprehensive Income		-		-			(24,061	)		-			-			(24,061	)
Change in Treasury Stock - Stock Compensation Plans, Net		-		(79,641	)		-			-			47,427			(32,214	)
Excess Tax Benefit from Stock-Based Compensation		-		55,831			-			-			-			55,831
Restricted Stock and Restricted Stock Units, Net		6		(2,974	)		-			-			(28,454	)		(31,422	)
Stock-Based Compensation Expenses		-		134,467			-			-			-			134,467
Treasury Stock Issued as Compensation		-		133			-			-			(414	)		(281	)
Balance at December 31, 2013	$	202,732	$	2,646,879		$	415,834		$	12,168,277		$	(15,263	)	$	15,418,459

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	2013			2012			2011

Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	2,197,109		$	570,279		$	1,091,123
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		3,600,976			3,169,703			2,516,381
Impairments		286,941			1,270,735			1,031,037
Stock-Based Compensation Expenses		134,055			127,778			128,345
Deferred Income Taxes		874,765			292,938			499,300
Gains on Asset Dispositions, Net		(197,565	)		(192,660	)		(492,909	)
Other, Net		11,072			672			15,139
Dry Hole Costs		74,655			14,970			53,230
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		166,349			(393,744	)		(626,053	)
Net Cash Received from Settlements of Commodity Derivative Contracts		116,361			711,479			180,701
Excess Tax Benefits from Stock-Based Compensation		(55,831	)		(67,035	)		-
Other, Net		18,205			14,411			26,454
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(23,613	)		(178,683	)		(339,780	)
Inventories		53,402			(156,762	)		(176,623	)
Accounts Payable		178,701			(17,150	)		351,087
Accrued Taxes Payable		75,142			78,094			92,589
Other Assets		(109,567	)		(118,520	)		(23,625	)
Other Liabilities		(20,382	)		36,114			14,986
Changes in Components of Working Capital Associated with Investing and Financing Activities		(51,361	)		74,158			237,028
Net Cash Provided by Operating Activities		7,329,414			5,236,777			4,578,410

Investing Cash Flows
Additions to Oil and Gas Properties		(6,697,091	)		(6,735,316	)		(6,294,397	)
Additions to Other Property, Plant and Equipment		(363,536	)		(619,800	)		(656,415	)
Proceeds from Sales of Assets		760,557			1,309,776			1,433,137
Changes in Restricted Cash		(65,814	)		-			-
Changes in Components of Working Capital Associated with Investing Activities		51,106			(73,923	)		(237,267	)
Net Cash Used in Investing Activities		(6,314,778	)		(6,119,263	)		(5,754,942	)

Financing Cash Flows
Common Stock Sold		-			-			1,388,265
Long-Term Debt Borrowings		-			1,234,138			-
Long-Term Debt Repayments		(400,000	)		-			(220,000	)
Dividends Paid		(199,178	)		(181,080	)		(167,169	)
Excess Tax Benefits from Stock-Based Compensation		55,831			67,035			-
Treasury Stock Purchased		(63,784	)		(58,592	)		(23,922	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		38,730			82,887			35,913
Debt Issuance Costs		-			(1,578	)		(4,787	)
Repayment of Capital Lease Obligation		(5,780	)		(2,824	)		-
Other, Net		255			(235	)		239
Net Cash (Used in) Provided by Financing Activities		(573,926	)		1,139,751			1,008,539

Effect of Exchange Rate Changes on Cash		1,064			3,444			(5,134	)

Increase (Decrease) in Cash and Cash Equivalents		441,774			260,709			(173,127	)
Cash and Cash Equivalents at Beginning of Year		876,435			615,726			788,853
Cash and Cash Equivalents at End of Year	$	1,318,209		$	876,435		$	615,726

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 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.

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.

F-9

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.

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 sales of crude oil and condensate, natural gas liquids (NGLs) and natural gas 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, NGLs 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 generally depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 45 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, 2013, 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 (Losses) 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. EOG is party to a foreign currency swap transaction and an interest rate swap transaction. 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. See Note 11.

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. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (see Note 5).

F-10

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 period. Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the period 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 February 2013, the FASB issued Accounting Standards Update (ASU) 2013-02 "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income" (ASU 2013-02). ASU 2013-02 amends ASU 2011-05 and requires that entities disclose additional information about amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. Significant amounts reclassified out of AOCI are required to be presented either on the face of the Consolidated Statements of Income and Comprehensive Income or in the notes to the financial statements. The requirements of ASU 2013-02 are effective for fiscal years and interim periods in those years beginning after December 15, 2012. The adoption of ASU 2013-02 did not have a material impact on EOG's financial statements. No significant amounts were reclassified out of AOCI during the years ended December 31, 2013, 2012 and 2011.

In July 2013, the FASB issued ASU 2013-11 "Presentation of an Unrecognized Tax Benefit when a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists" (ASU 2013-11). ASU 2013-11 includes specific guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The requirements of ASU 2013-11 are effective for fiscal years and interim periods in those years beginning after December 15, 2013. Early adoption is permitted. EOG does not expect a material impact on its financial statements from the adoption of ASU 2013-11.

F-11

2. Long-Term Debt

Long-Term Debt at December 31, 2013 and 2012 consisted of the following (in thousands):

	2013		2012

6.125% Senior Notes due 2013	$	-	$	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
2.625% Senior Notes due 2023		1,250,000		1,250,000
6.65% Senior Notes due 2028		140,000		140,000
4.75% Subsidiary Debt due 2014		150,000		150,000
Total Long-Term Debt		5,890,000		6,290,000
Capital Lease Obligation		57,187		62,968
Less: Current Portion of Long-Term Debt		6,579		406,579
Unamortized Debt Discount		33,966		40,787
Total Long-Term Debt, Net	$	5,906,642	$	5,905,602

At December 31, 2013, the aggregate annual maturities of long-term debt (excluding capital lease obligations) were $500 million in 2014, $500 million in 2015, $400 million in 2016, $600 million in 2017 and $350 million in 2018. On October 1, 2013, EOG repaid at maturity $400 million principal amount of its 6.125% Senior Notes due 2013, plus accrued and unpaid interest. All subsidiary debt is guaranteed by EOG. At December 31, 2013, $350 million principal amount of Floating Rate Senior Notes due 2014 (Floating Rate Notes) and $150 million principal amount of 4.75% Subsidiary Debt due 2014 (4.75% Subsidiary Debt) were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amounts with other long-term debt.

On February 3, 2014, EOG repaid upon maturity $350 million principal amount of its Floating Rate Notes. On the same date, EOG settled its interest rate swap agreement entered into contemporaneously with the issuance of the Floating Rate Notes.

During 2013 and 2012, EOG utilized commercial paper and short-term borrowings from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding borrowings from commercial paper or uncommitted credit facilities at December 31, 2013 and 2012, respectively. The average borrowings outstanding under the commercial paper program were $37 million and $236 million during the years ended December 31, 2013 and 2012, respectively. The average borrowings outstanding under the uncommitted credit facilities were zero and $41 million during the years ended December 31, 2013 and 2012, respectively. The weighted average interest rates for commercial paper borrowings were 0.30% and 0.45% for the years 2013 and 2012, respectively, and were 0.70% for uncommitted credit facility borrowings for the year 2012.

On September 10, 2012, EOG closed its sale of $1.25 billion aggregate principal amount of its 2.625% Senior Notes due 2023 (Notes). Interest on the Notes is payable semi-annually in arrears on March 15 and September 15 of each year, beginning March 15, 2013. Net proceeds from the Notes offering of approximately $1,234 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings and funding of capital expenditures. The Notes were issued through a public offering with an effective interest rate of 2.784%.

F-12

EOG currently has a $2.0 billion senior unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The Agreement 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 Agreement. At December 31, 2013, there were no borrowings or letters of credit outstanding under the Agreement. Advances under the Agreement accrue interest based, at EOG's option, on either the London InterBank Offered Rate (LIBOR) plus an applicable margin (Eurodollar rate), or the base rate (as defined in the Agreement) plus an applicable margin. At December 31, 2013, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.04% and 3.25%, respectively.

The Agreement 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, 2013, and during the year then ended, EOG believes that it was in compliance with this financial debt covenant.

EOG Resources Canada Inc. (EOGRC), a wholly-owned subsidiary of EOG, has outstanding the 4.75% Subsidiary Debt with 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).

Restricted Cash. In May 2013, the Canadian Alberta Energy Regulator (AER) made effective certain regulations affecting the Licensee Liability Rating program which requires well owners to post financial security for well abandonment obligations in amounts set forth by the AER. In order to comply with these requirements, EOGRC established a 160 million Canadian dollar letter of credit facility (maturing May 29, 2018) with Royal Bank of Canada (RBC) as the lender. The letter of credit facility requires EOGRC to deposit cash, in an amount equal to all outstanding letters of credit under such facility, in a cash collateral account at RBC. At December 31, 2013, the balance in this account was 70 million Canadian dollars (66 million United States dollars) and was included in Other Assets on the Consolidated Balance Sheets.

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, 2013, 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 (SARs), 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-based compensation plans and any other approved transactions or activities for which such shares of Common Stock may be required.

The Board increased the quarterly cash dividend on the Common Stock to $0.17 per share on February 16, 2012, and to $0.1875 on February 13, 2013. On February 24, 2014, EOG's Board approved a two-for-one stock split in the form of a stock dividend, payable on March 31, 2014, to stockholders of record as of March 17, 2014. Also on February 24, 2014, the Board increased the quarterly cash dividend on the common stock by 33% to $0.125 per share post-split ($0.25 per share pre-split), effective beginning with the dividend to be paid on April 30, 2014, to stockholders of record as of April 16, 2014.

F-13

The following summarizes Common Stock activity for each of the years ended December 31, 2011, 2012 and 2013 (in thousands):

	Common Shares
	Issued		Treasury			Outstanding

Balance at December 31, 2010		254,223		(146	)		254,077
Common Stock Issued Under Stock-Based 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 Stock-Based Compensation Plans		-		109			109
Common Stock Sold		13,570		-			13,570
Balance at December 31, 2011		269,323		(304	)		269,019
Common Stock Issued Under Stock-Based Compensation Plans		2,471		-			2,471
Treasury Stock Purchased ⁽¹⁾		-		(575	)		(575	)
Common Stock Issued Under Employee Stock Purchase Plan		164		-			164
Treasury Stock Issued Under Stock-Based Compensation Plans		-		553			553
Balance at December 31, 2012		271,958		(326	)		271,632
Common Stock Issued Under Stock-Based Compensation Plans		1,103		-			1,103
Treasury Stock Purchased ⁽¹⁾		-		(427	)		(427	)
Common Stock Issued Under Employee Stock Purchase Plan		128		-			128
Treasury Stock Issued Under Stock-Based Compensation Plans		-		650			650
Balance at December 31, 2013		273,189		(103	)		273,086

(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 SARs, 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. As of December 31, 2013, there were no shares of preferred stock outstanding.

4. Other Income, Net

Other income, net, for 2013 included net foreign currency transaction gains ($12 million), equity income from investments in ammonia plants in Trinidad ($11 million), interest income ($6 million) primarily related to sales and use tax refunds, and losses on sales and adjustments of warehouse stock ($23 million). Other income, net, for 2012 included equity income from investments in ammonia plants in Trinidad ($20 million), interest income ($9 million) primarily related to severance tax refunds, net foreign currency transaction gains ($7 million), losses on sales of warehouse stock ($10 million) and operating losses on EOG's investment in the proposed Pacific Trail Pipelines (PTP) in Canada ($9 million). Other income, net, for 2011 included equity income from investments in ammonia plants in Trinidad ($17 million), operating losses on EOG's investment in the PTP in Canada ($5 million) and losses on sales of warehouse stock ($5 million).

F-14

5. Income Taxes

The principal components of EOG's net deferred income tax liabilities at December 31, 2013 and 2012 were as follows (in thousands):

	2013			2012

Current Deferred Income Tax Assets (Liabilities)
Commodity Hedging Contracts	$	29,582		$	(57,754	)
Deferred Compensation Plans		42,296			35,715
Net Operating Loss		96,616			-
Alternative Minimum Tax Credit Carryforward		72,297			-
Timing Differences Associated with Different Year-ends in Foreign Jurisdictions		-			(2,762	)
Other		3,815			1,963
Total Net Current Deferred Income Tax Assets (Liabilities)	$	244,606		$	(22,838	)

Noncurrent Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Over (Under) Book Depreciation, Depletion and Amortization	$	(112,346	)	$	25,592
Foreign Net Operating Loss		369,257			164,829
Foreign Other		4,179			1,607
Foreign Valuation Allowances		(183,122	)		(134,792	)
Total Net Noncurrent Deferred Income Tax Assets	$	77,968		$	57,236

Noncurrent Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	6,287,541		$	5,300,115
Non-Producing Leasehold Costs		(50,581	)		(61,512	)
Seismic Costs Capitalized for Tax		(136,964	)		(125,026	)
Equity Awards		(122,665	)		(116,666	)
Capitalized Interest		101,006			102,677
Net Operating Loss		-			(308,154	)
Alternative Minimum Tax Credit Carryforward		(557,352	)		(476,505	)
Other		1,369			12,467
Total Net Noncurrent Deferred Income Tax Liabilities	$	5,522,354		$	4,327,396

Total Net Deferred Income Tax Liabilities	$	5,199,780		$	4,292,998

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

	2013		2012			2011

United States	$	3,268,727	$	1,988,105		$	2,156,147
Foreign		168,159		(707,365	)		(246,348	)
Total	$	3,436,886	$	1,280,740		$	1,909,799

F-15

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

	2013			2012			2011

Current:
Federal	$	207,777		$	242,674		$	94,244
State		22,856			22,573			1,083
Foreign		134,379			152,276			224,049
Total		365,012			417,523			319,376
Deferred:
Federal		915,994			454,173			608,181
State		26,305			632			40,321
Foreign		(67,534	)		(161,867	)		(149,202	)
Total		874,765			292,938			499,300
Income Tax Provision	$	1,239,777		$	710,461		$	818,676

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

	2013	2012	2011

Statutory Federal Income Tax Rate	35.00%	35.00%	35.00%
State Income Tax, Net of Federal Benefit	0.93	1.18	1.41
Income Tax Provision Related to Foreign Operations	(0.20)	1.38	0.88
Income Tax Provision Related to Trinidad Operations	0.43	(0.27)	3.37
Canadian Valuation Allowances	-	10.57	-
Canadian Natural Gas Impairments	-	6.90	1.85
Other	(0.09)	0.71	0.36
Effective Income Tax Rate	36.07%	55.47%	42.87%

The difference in the effective tax rate and the United States federal statutory rate of 35% is attributable principally to state and foreign income taxes. The effective tax rate of 36% in 2013 was lower than the prior year rate of 55% primarily due to the absence of certain 2012 Canadian impairments and valuation allowances (26% statutory rate).

Deferred tax assets are recorded for certain tax benefits, including tax net operating losses (NOLs) and tax credit carryforwards, provided that management assesses the utilization of such assets to be "more likely than not." Management assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to use the existing deferred tax assets. On the basis of this evaluation, as of December 31, 2013 and 2012, cumulative valuation allowances of $183 million and $158 million, respectively, have been recorded as EOG does not believe that certain foreign deferred tax assets are more likely than not to be realized. Once established, these valuation allowances are subsequently adjusted for current year taxable profits or losses and future taxable income estimates.

F-16

The balance of unrecognized tax benefits at December 31, 2013, was zero. The $33 million decrease from the prior year-end balance was the result of concluded income tax audits. However, there was no impact on the effective tax rate as the tax benefits were offset by a valuation allowance. When applicable, 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 on the Consolidated Statements of Income and Comprehensive Income or on 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 2010, 2009, 2012, 2002 and 2008, respectively.

EOG's foreign subsidiaries' undistributed earnings of approximately $2.7 billion at December 31, 2013, 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, although additional taxes resulting from a repatriation of foreign earnings could be significant.

In 2013, EOG utilized a United States federal tax NOL of $787 million. Remaining NOLs of $314 million are expected to be carried forward and applied against regular taxable income in future periods. To the extent not utilized, these NOL carryforwards will begin to expire in 2031. Additionally, as of December 31, 2013, EOG had state income tax NOLs of approximately $700 million, which, if unused, expire between 2015 and 2033. 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. Due to the current-year utilization of a portion of the available NOLs, a benefit of $15 million will be reflected in APIC. Future utilization of the remaining NOLs will result in an additional benefit of $16 million being reflected in APIC (related to 2011). In 2013, EOG paid alternative minimum tax (AMT) of $161 million. The AMT paid in 2013, along with AMT of $469 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 carryforwards and the AMT credit carryforwards to reduce federal income taxes 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, 2013, management does not believe that an ownership change has occurred which would limit either carryforward.

During 2013, EOG's United Kingdom subsidiary incurred a tax NOL of approximately $282 million which, along with prior years' NOLs of $267 million, will be carried forward indefinitely.

The American Taxpayer Relief Act of 2012 (ATRA) was enacted on January 2, 2013. Although ATRA principally affected individual taxpayers, the legislation included certain corporate tax incentives, notably the extension of bonus depreciation (additional depreciation expense of 50% for qualified domestic property additions), which had a favorable impact on EOG's tax position in 2013.

F-17

6. Employee Benefit Plans

Stock-Based Compensation

During 2013, EOG maintained various stock-based compensation plans as discussed below. EOG recognizes compensation expense on grants of stock options, SARs, restricted stock and restricted stock units, performance units and performance stock, 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 the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2013, 2012 and 2011 was as follows (in millions):

	2013		2012		2011

Lease and Well	$	35	$	35	$	33
Gathering and Processing Costs		1		1		1
Exploration Costs		27		27		26
General and Administrative		71		65		68
Total	$	134	$	128	$	128

The Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, SARs, restricted stock and restricted stock units, performance stock and performance units, and other stock-based awards up to an aggregate maximum of 28.4 million shares. At December 31, 2013, approximately 16.6 million shares of Common Stock remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

During 2013, 2012 and 2011, EOG issued shares in connection with stock option/SAR exercises, restricted stock and performance stock grants, restricted stock unit releases and ESPP purchases. EOG recognized, as an adjustment to APIC, federal income tax benefits of $56 million, $67 million and $25,000 for 2013, 2012 and 2011, respectively, related to the exercise of stock options/SARs and the release of restricted stock and restricted stock units.

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan. Participants in EOG's stock-based compensation 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.

F-18

The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option pricing model. The fair value of ESPP grants is estimated using the Black-Scholes-Merton model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $53 million, $49 million and $48 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2013, 2012 and 2011 were as follows:

	Stock Options/SARs									ESPP
	2013			2012			2011			2013			2012			2011

Weighted Average Fair Value of Grants	$	54.70		$	37.95		$	29.92		$	30.12		$	25.11		$	22.75
Expected Volatility		35.86	%		39.68	%		40.96	%		29.89	%		40.92	%		29.82	%
Risk-Free Interest Rate		0.78	%		0.45	%		0.58	%		0.11	%		0.11	%		0.14	%
Dividend Yield		0.40	%		0.60	%		0.70	%		0.60	%		0.60	%		0.70	%
Expected Life	5.5		yrs	5.6		yrs	5.6		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, 2013, 2012 and 2011 (stock options and SARs in thousands):

	2013					2012					2011
	Number of Stock Options/ SARs			Weighted Average Grant Price		Number of Stock Options/ SARs			Weighted Average Grant Price		Number of Stock Options/ SARs			Weighted Average Grant Price

Outstanding at January 1		6,219		$	85.81		8,374		$	70.01		8,445		$	64.49
Granted		1,134			167.40		1,240			111.97		1,509			85.29
Exercised ⁽¹⁾		(2,023	)		71.23		(3,246	)		54.80		(1,399	)		50.86
Forfeited		(104	)		101.56		(149	)		91.18		(181	)		87.74
Outstanding at December 31		5,226			108.86		6,219			85.81		8,374			70.01

Stock Options/SARs Exercisable at December 31		2,319			87.90		3,143			74.98		5,148			59.19

(1)

The total intrinsic value of stock options/SARs exercised during the years 2013, 2012 and 2011 was $151 million, $185 million and $78 million, respectively. The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs.

At December 31, 2013, there were 5.0 million stock options/SARs vested or expected to vest with a weighted average grant price of $108.03 per share, an intrinsic value of $300 million and a weighted average remaining contractual life of 4.5 years.

F-19

The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2013 (stock options and SARs in thousands):

Stock Options/SARs Outstanding								Stock Options/SARs Exercisable
Range of Grant Prices	Stock Options/ SARs		Weighted Average Remaining Life (Years)		Weighted Average Grant Price		Aggregate Intrinsic Value⁽¹⁾	Stock Options/ SARs		Weighted Average Remaining Life (Years)		Weighted Average Grant Price		Aggregate Intrinsic Value⁽¹⁾

$ 26.00 to $ 81.99		764		2	$	77.08			760		2	$	77.13
82.00 to 89.99		1,380		4		84.82			765		3		85.87
90.00 to 109.99		837		4		93.39			519		4		92.87
110.00 to 136.99		1,154		6		113.22			274		5		113.65
137.00 to 178.99		1,091		7		168.77			1		1		168.86
		5,226		5		108.86	$309,422		2,319		3		87.90	$185,362

(1)	Based upon the difference between the closing market price of the 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, 2013, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $103 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.7 years.

At December 31, 2013, approximately 498,000 shares of Common Stock remained available for issuance under the ESPP. The following table summarizes ESPP activities for the years ended December 31, 2013, 2012 and 2011 (in thousands, except number of participants):

	2013		2012		2011

Approximate Number of Participants		1,844		1,705		1,525
Shares Purchased		128		164		135
Aggregate Purchase Price	$	14,015	$	12,522	$	10,947

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 $72 million, $72 million and $80 million for the years ended December 31, 2013, 2012 and 2011, respectively.

F-20

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2013, 2012 and 2011 (shares and units in thousands):

	2013					2012					2011
	Number of Shares and Units			Weighted Average Grant Date Fair Value		Number of Shares and Units			Weighted Average Grant Date Fair Value		Number of Shares and Units			Weighted Average Grant Date Fair Value

Outstanding at January 1		3,818		$	91.06		4,240		$	82.93		4,009		$	79.13
Granted		647			152.07		767			112.17		932			90.87
Released ⁽¹⁾		(684	)		104.78		(1,059	)		72.70		(457	)		66.10
Forfeited		(102	)		97.10		(130	)		85.36		(244	)		82.45
Outstanding at December 31 ⁽²⁾		3,679			99.08		3,818			91.06		4,240			82.93

(1)

The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2013, 2012 and 2011 was $101 million, $120 million and $44 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, 2013 and 2012 was approximately $617 million and $461 million, respectively.

At December 31, 2013, unrecognized compensation expense related to restricted stock and restricted stock units totaled $154 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.4 years.

Performance Units and Performance Stock. EOG grants performance units and/or performance stock to its executive officers. As more fully discussed in the grant agreements, the performance metric applicable to these performance-based grants is EOG's total shareholder return over a three-year performance period relative to the total shareholder return of a designated group of peer companies. Upon the application of the performance multiple at the completion of the performance period, a minimum of zero and a maximum of 261,390 performance units/shares could be outstanding (based on the number of performance units/shares outstanding as of December 31, 2013). Subject to the termination provisions set forth in the grant agreements and the applicable performance multiple, the grants of performance shares/units will "cliff" vest five years from the date of grant. The fair value of the performance units and performance stock is estimated using a Monte Carlo simulation. Stock-based compensation expense related to performance unit and performance stock grants totaled $9 million and $7 million for the years ended December 31, 2013 and 2012, respectively.

Weighted average fair values and valuation assumptions used to value performance unit and performance stock grants during the years ended December 31, 2013 and 2012 are as follows:

	2013			2012

Weighted Average Fair Value of Grants	$	200.68		$	134.09
Expected Volatility		33.63	%		36.39	%
Risk-Free Interest Rate		0.79	%		0.39	%

Expected volatility is based on the term-matched historical volatility over the simulated term, which is calculated as the time between the grant date and the end of the performance period. The risk-free interest rate is based on a 3.26 year zero-coupon risk-free interest rate derived from the Treasury Constant Maturities yield curve on the grant date.

F-21

The following table sets forth performance unit and performance stock transactions for the years ended December 31, 2013 and 2012 (shares and units in thousands):

	2013				2012
	Number of Shares and Units		Weighted Average Grant Date Fair Value		Number of Shares and Units		Weighted
							Average
							Grant Date
							Fair Value

Outstanding at January 1		71	$	134.09		-	$	-
Granted		60		200.68		71		134.09
Released		-		-		-		-
Forfeited		-		-		-		-
Outstanding at December 31 ⁽¹⁾		131	$	164.36		71	$	134.09

(1)

The total intrinsic value of performance units and performance stock outstanding at December 31, 2013 and 2012 was $21.9 million and $8.6 million, respectively.

At December 31, 2013, unrecognized compensation expense related to performance units and performance stock totaled $6 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.4 years.

Pension Plans. EOG has a defined contribution pension plan in place for most of its employees in the United States. EOG's contributions to the pension plan 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 the plan were $37 million, $36 million and $27 million for 2013, 2012 and 2011, 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 $4 million, $3 million and $3 million for 2013, 2012 and 2011, respectively.

For the Canadian and Trinidadian defined benefit pension plans, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $13 million, $11 million and $1 million, respectively, at December 31, 2013, and $14 million, $10 million and $2 million, respectively, at December 31, 2012.

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-22

7. Commitments and Contingencies

Letters of Credit. At December 31, 2013, EOG had standby letters of credit and guarantees outstanding totaling approximately $711 million, of which $150 million represented a guarantee of subsidiary indebtedness (see Note 2) and $561 million primarily represented guarantees of payment or performance obligations on behalf of subsidiaries. At December 31, 2012, EOG had standby letters of credit and guarantees outstanding totaling approximately $636 million, of which $150 million represented a guarantee of subsidiary indebtedness (see Note 2) and $486 million primarily represented guarantees of payment or performance obligations on behalf of subsidiaries. As of February 24, 2014, there were no demands for payment under these guarantees.

Minimum Commitments. At December 31, 2013, 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, 2013, were as follows (in thousands):

	Total Minimum Commitments

2014	$	1,777,014
2015 - 2016		1,808,827
2017 - 2018		1,272,578
2019 and beyond		1,176,230
	$	6,034,649

Included in the table above are leases for buildings, facilities and equipment with varying expiration dates through 2042. Rental expenses associated with existing leases amounted to $191 million, $182 million and $149 million for 2013, 2012 and 2011, 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.

F-23

8. Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2013, 2012 and 2011 (in thousands, except per share data):

	2013		2012		2011

Numerator for Basic and Diluted Earnings per Share -
Net Income	$	2,197,109	$	570,279	$	1,091,123
Denominator for Basic Earnings per Share -
Weighted Average Shares		270,170		267,577		262,735
Potential Dilutive Common Shares -
Stock Options/SARs		1,159		1,456		1,707
Restricted Stock/Units and Performance Units/Stock		1,785		1,729		1,826
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares		273,114		270,762		266,268

Net Income Per Share
Basic	$	8.13	$	2.13	$	4.15
Diluted	$	8.04	$	2.11	$	4.10

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 0.3 million, 0.5 million and 0.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.

9. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the years ended December 31, 2013, 2012 and 2011 (in thousands):

	2013		2012		2011

Interest, Net of Capitalized Interest	$	235,854	$	196,944	$	186,718
Income Taxes, Net of Refunds Received	$	294,739	$	360,006	$	260,224

EOG's accrued capital expenditures at December 31, 2013, 2012 and 2011 were $731 million, $734 million and $663 million, respectively.

Non-cash investing activities for the year ended December 31, 2013, included non-cash additions of $5 million to EOG's oil and gas properties as a result of property exchanges.

Non-cash investing and financing activities for the year ended December 31, 2012, included non-cash additions of $66 million to EOG's other property, plant and equipment and related obligations in connection with a capital lease transaction and non-cash additions of $20 million to EOG's oil and gas properties as a result of property exchanges.

F-24

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, China and Argentina. 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, 2013, 2012 and 2011 (in thousands):


	United States			Canada			Trinidad		Other International ⁽¹⁾			Total

2013
Crude Oil and Condensate	$	8,035,358		$	221,999		$	40,379	$	2,911		$	8,300,647
Natural Gas Liquids		761,535			12,435			-		-			773,970
Natural Gas		1,100,808			85,446			477,103		17,672			1,681,029
Losses on Mark-to-Market Commodity Derivative Contracts		(166,349	)		-			-		-			(166,349	)
Gathering, Processing and Marketing		3,636,209			1,476			6,064		-			3,643,749
Gains on Asset Dispositions, Net		93,876			102,570			1,119		-			197,565
Other, Net		51,713			4,770			24		-			56,507
Net Operating Revenues ⁽²⁾		13,513,150			428,696			524,689		20,583			14,487,118

Depreciation, Depletion and Amortization		3,223,596			180,836			181,990		14,554			3,600,976
Operating Income (Loss)		3,543,841			(45,214	)		266,329		(89,745	)		3,675,211
Interest Income		2,803			2,076			336		370			5,585
Other Income (Expense)		(29,696	)		7,707			9,889		3,650			(8,450	)
Net Interest Expense		283,209			(4,204	)		-		(43,545	)		235,460
Income (Loss) Before Income Taxes		3,233,739			(31,227	)		276,554		(42,180	)		3,436,886
Income Tax Provision (Benefit)		1,161,328			598			118,270		(40,419	)		1,239,777
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		6,133,894			137,920			132,984		217,638			6,622,436
Total Property, Plant and Equipment, Net		24,456,383			602,333			476,174		613,946			26,148,836
Total Assets		27,668,713			880,765			986,796		1,037,964			30,574,238

F-25

	United									Other
	States			Canada			Trinidad			International ⁽¹⁾			Total

2012
Crude Oil and Condensate	$	5,383,612		$	221,556			50,708		$	3,561		$	5,659,437
Natural Gas Liquids		713,497			13,680			-			-			727,177
Natural Gas		951,463			86,361			514,322			19,616			1,571,762
Gains on Mark-to-Market Commodity Derivative Contracts		393,744			-			-			-			393,744
Gathering, Processing and Marketing		3,091,281			-			5,413			-			3,096,694
Gains on Asset Dispositions, Net		166,201			26,459			-			-			192,660
Other, Net		40,780			367			15			-			41,162
Net Operating Revenues ⁽³⁾		10,740,578			348,423			570,458			23,177			11,682,636

Depreciation, Depletion and Amortization		2,780,563			223,689			147,062			18,389			3,169,703
Operating Income (Loss)		2,233,911			(1,065,434	)		371,876			(60,556	)		1,479,797
Interest Income		8,343			123			125			180			8,771
Other Income (Expense)		(12,455	)		(8,689	)		20,482			6,386			5,724
Net Interest Expense		242,138			6,589			238			(35,413	)		213,552
Income (Loss) Before Income Taxes		1,987,661			(1,080,589	)		392,245			(18,577	)		1,280,740
Income Tax Provision (Benefit)		707,401			(134,745	)		140,468			(2,663	)		710,461
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		6,198,267			302,851			49,376			169,852			6,720,346
Total Property, Plant and Equipment, Net		21,560,998			877,996			535,405			363,282			23,337,681
Total Assets		24,523,072			1,202,031			1,012,727			598,748			27,336,578

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 ⁽³⁾		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

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

(2)	EOG had sales activity with two significant purchasers in 2013, one totaling $3.9 billion and the other totaling $2.0 billion of consolidated Net Operating Revenues in the United States segment.

(3)	EOG had sales activity with a single significant purchaser in the United States segment in 2012 that totaled $2.2 billion of consolidated Net Operating Revenues.

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

F-26

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 prices for crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. In addition to financial transactions, from time to time 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 2013, 2012 and 2011, 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. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact is reflected in Cash Flows from Operating Activities. During 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million, which included net cash received from settlements of commodity derivative contracts of $116 million. During 2012 and 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $394 million and $626 million, respectively, which included net cash received from settlements of commodity derivative contracts of $711 million and $181 million, respectively.

Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at December 31, 2013, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl)

Crude Oil Derivative Contracts
	Volume (Bbld)		Weighted Average Price ($/Bbl)
2014 ⁽¹⁾
January 2014		156,000	$	96.30
February 1, 2014 through March 31, 2014		171,000		96.35
April 1, 2014 through June 30, 2014		161,000		96.33
July 1, 2014 through December 31, 2014		64,000		95.18

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month and nine-month periods. Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014. Options covering a notional volume of 118,000 Bbld are exercisable on or about June 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 118,000 Bbld at an average price of $96.64 per barrel for each month during the period July 1, 2014 through December 31, 2014. Options covering a notional volume of 69,000 Bbld are exercisable on or about December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 69,000 Bbld at an average price of $95.20 per barrel for each month during the period January 1, 2015 through June 30, 2015.

F-27

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at December 31, 2013, 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)
2014 ⁽¹⁾
January 2014 (closed)		230,000		$	4.51
February 1, 2014 through December 31, 2014		205,000		$	4.52

(1)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. All 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 355,000 MMBtud at an average price of $4.63 per MMBtu for each month during the period February 1, 2014 through December 31, 2014.

Foreign Currency Exchange Rate Derivative. EOG is party to a foreign currency aggregate swap with multiple banks to eliminate any exchange rate impacts that may result from the 4.75% Subsidiary Debt issued by one of EOG's Canadian subsidiaries. The foreign currency swap agreement expires on March 15, 2014. EOG accounts for the foreign currency swap transaction using the hedge accounting method. Changes in the fair value of the foreign currency swap do not impact Net Income. The after-tax net impact from the foreign currency swap for the years ended December 31, 2013 and 2012 resulted in increases in Other Comprehensive Income (Loss) (OCI) of $2 million and $1 million, respectively, and for the year ended December 31, 2011 resulted in a decrease in OCI of $1 million.

Interest Rate Derivative. EOG is a party to an interest rate swap with a counterparty bank. The interest rate swap was entered into in order to mitigate EOG's exposure to volatility in interest rates related to the Floating Rate Notes. The interest rate swap has a notional amount of $350 million. EOG accounts for the interest rate swap transaction using the hedge accounting method. Changes in the fair value of the interest rate swap do not impact Net Income. The after-tax impact from the interest rate swap resulted in an increase in OCI of $2 million for the year ended December 31, 2013, and reductions in OCI of $0.1 million and $3 million for the years ended December 31, 2012 and 2011, respectively. On February 3, 2014, the interest rate swap was settled in conjunction with the maturity and repayment of the Floating Rate Notes.

F-28

The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2013 and 2012, 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	2013		2012

Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities ⁽¹⁾	$	8	$	166

Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities ⁽²⁾	$	127	$	8
Noncurrent portion	Other Liabilities ⁽³⁾	$	-	$	13

Foreign currency swap -
Current portion	Current Liabilities - Other	$	40	$	-
Noncurrent portion	Other Liabilities	$	-	$	55

Interest rate swap -
Current portion	Current Liabilities - Other	$	1	$	-
Noncurrent portion	Other Liabilities	$	-	$	4

(1)	The current portion of Assets from Price Risk Management Activities consists of gross assets of $18 million, partially offset by gross liabilities of $10 million, at December 31, 2013 and gross assets of $271 million, partially offset by gross liabilities of $105 million, at December 31, 2012.

(2)

The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $137 million, partially offset by gross assets of $10 million, at December 31, 2013 and gross liabilities of $113 million, partially offset by gross assets of $105 million, at December 31, 2012.

(3)	The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $13 million at December 31, 2012.

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, 2013, EOG's net accounts receivable balance related to United States, Canada, Argentina and United Kingdom hydrocarbon sales include three receivable balances, each of which accounted for more that 10% of the total balance. The receivables were due from two petroleum refinery companies and one multinational oil and gas company. The related amounts were collected during early 2014. At December 31, 2012, EOG's net accounts receivable balance related to United States, Canada and United Kingdom hydrocarbon sales include one receivable balance which constituted 26% of the total balance. The receivable was due from a United States petroleum marketing company. The related amount was collected during early 2013. In 2013 and 2012, 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.

F-29

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 that were in a net liability position at December 31, 2013 and 2012. EOG had no collateral posted and held no collateral at December 31, 2013, and had no collateral posted and held $6 million of collateral at December 31, 2012.

Substantially all of EOG's accounts receivable at December 31, 2013 and 2012 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, 2013, 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.

F-30

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, 2013 and 2012 (in millions):

	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
At December 31, 2013
Financial Assets:
Natural Gas Options/Swaptions	$	-	$	8	$	-	$	8

Financial Liabilities:
Crude Oil Swaps	$	-	$	17	$	-	$	17
Crude Oil Options/Swaptions		-		110		-		110
Foreign Currency Rate Swap		-		40		-		40
Interest Rate Swap		-		1		-		1

At December 31, 2012
Financial Assets:
Crude Oil Swaps	$	-	$	65	$	-	$	65
Crude Oil Options/Swaptions		-		36		-		36
Natural Gas Options/Swaptions		-		65		-		65

Financial Liabilities:
Crude Oil Options/Swaptions	$	-	$	8	$	-	$	8
Natural Gas Options/Swaptions		-		13		-		13
Foreign Currency Rate Swap		-		55		-		55
Interest Rate Swap		-		4		-		4

The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) and the interest rate swap contract (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. Commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable.

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.

F-31

During 2013, proved oil and gas properties and other assets with a carrying amount of $400 million were written down to their fair value of $228 million, resulting in pretax impairment charges of $172 million. Included in the $172 million pretax impairment charges are $58 million of impairments of proved oil and gas properties and other assets for which EOG utilized accepted offers from third-party purchasers as the basis for determining fair value. During 2012, proved and unproved oil and gas properties and other assets with a carrying amount of $1,524 million were written down to their fair value of $391 million, resulting in pretax impairment charges of $1,133 million. Included in the $1,133 million pretax impairment charges are $60 million of impairments of proved oil and gas properties and other property, plant and equipment for which EOG utilized accepted offers from third-party purchasers 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.

Fair Value of Debt. At December 31, 2013 and 2012, EOG had outstanding $5,890 million and $6,290 million, respectively, aggregate principal amount of debt, which had estimated fair values of approximately $6,222 million and $7,032 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at year-end.

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 depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. During 2013, 2012 and 2011, 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 $73 million, $171 million and $403 million in the United States during 2013, 2012 and 2011, respectively, and $76 million, $872 million and $428 million in Canada during 2013, 2012 and 2011, respectively. Additionally, EOG recorded pretax charges of $14 million in Trinidad during 2013 and $9 million and $3 million in Other International during 2013 and 2011, respectively. 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 described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted bids as the basis for determining fair value. Amortization and impairments of unproved oil and gas property costs, including amortization of capitalized interest, were $115 million, $228 million and $197 million during 2013, 2012 and 2011, respectively.

F-32

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, 2013 and 2012 (in thousands):

	2013			2012

Carrying Amount at Beginning of Period	$	665,944		$	587,084
Liabilities Incurred		103,284			107,378
Liabilities Settled ⁽¹⁾		(70,510	)		(77,384	)
Accretion		35,180			30,020
Revisions		38,552			15,287
Foreign Currency Translations		(10,552	)		3,559
Carrying Amount at End of Period	$	761,898		$	665,944

Current Portion	$	43,857		$	30,127
Noncurrent Portion	$	718,041		$	635,817

(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, 2013, 2012 and 2011 are presented below (in thousands):

	2013			2012			2011

Balance at January 1	$	49,116		$	61,111		$	99,801
Additions Pending the Determination of Proved Reserves		52,099			73,332			31,271
Reclassifications to Proved Properties		(54,505	)		(69,462	)		(29,227	)
Costs Charged to Expense ⁽¹⁾		(35,859	)		(17,115	)		(42,178	)
Foreign Currency Translations		(1,640	)		1,250			1,444
Balance at December 31	$	9,211		$	49,116		$	61,111

(1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

F-33

The following table provides an aging of capitalized exploratory well costs at December 31, 2013, 2012 and 2011 (in thousands, except well count):

	2013		2012			2011

Capitalized exploratory well costs that have been capitalized for a period less than one year	$	9,211	$	28,319		$	17,009
Capitalized exploratory well costs that have been capitalized for a period greater than one year		-		20,797	⁽¹⁾		44,102	⁽²⁾
Total	$	9,211	$	49,116		$	61,111
Number of exploratory wells that have been capitalized for a period greater than one year		-		1			4

(1)	Consists of costs related to an outside operated, offshore Central North Sea natural gas project in the United Kingdom (U.K.).

(2)	Consists of costs related to an outside operated, offshore Central North Sea project in the 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 ($6 million).

16. Divestitures

During 2013, EOG received proceeds of approximately $761 million primarily from the sales of its entire interest in the planned Kitimat liquefied natural gas export terminal (Kitimat LNG Terminal) and PTP, undeveloped acreage in the Horn River Basin in Canada and producing properties and acreage in the Permian Basin, the Mid-Continent area and the Upper Gulf Coast region. During 2012, EOG received proceeds of approximately $1.3 billion from the sales of producing properties and acreage primarily in the Rocky Mountain area, the Upper Gulf Coast region and Canada. 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 Kitimat LNG Terminal and PTP.

In December 2012, EOGRC signed a purchase and sale agreement for the sale of its entire interest in the Kitimat LNG Terminal and PTP, as well as undeveloped net acres in the Horn River Basin, to Chevron Canada Limited. The transaction closed in February 2013. Additionally in 2012, EOG signed purchase and sale agreements for the sale of certain properties in the United States. At December 31, 2012, the book value of these assets held for sale and the related liabilities were $310 million and $31 million, respectively.

F-34

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

Oil and Gas Producing Activities

The following disclosures are made in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2010-03 "Oil and Gas Reserve Estimates and Disclosures" and the United States Securities and Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting."

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 (NGLs) 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, NGLs 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 then-existing 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 (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a significant 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. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs are to be recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded. EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2013. Under EOG's current drilling and development plan, each PUD location will be drilled within five years from the date it was recorded. Estimates for PUDs 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.

F-35

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In making estimates of PUDs, 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 analysis techniques employed include, but are not limited to, well testing analysis, static bottom hole pressure analysis, flowing bottom hole pressure analysis, analysis of historical production trends, pressure transient analysis and rate transient analysis. Application of proprietary rate transient analysis techniques in low permeability rocks allow for quantification of estimates of contribution to production from both fractures and rock matrix.

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 completing horizontal wells with multi-stage fracture stimulation. In the early stages of development of a play, 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 activities provides the appropriate level of certainty as well as support for the economic producibility of the plays in which PUDs are reflected. EOG has found this approach to be effective based on successful application in analogous reservoirs in low permeability resource plays.

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices, production volumes and the length of wells, both vertical and horizontal. 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, 2013, 2012 and 2011 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 two of whom 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 28 years of experience in reserve evaluations and is a Registered Professional Engineer in the State of Texas.

F-36

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, NGLs and natural gas prices, production costs, transportation 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 comprising not less than 75% of EOG's estimates 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 Chief Operating Officer; the Executive Vice Presidents, Exploration and Production; and the Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2013, 2012 and 2011 covered producing areas containing 82%, 87% and 85%, 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 January 31, 2014, 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, 2013, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

F-37

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, 2013, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2013, as estimated by the Engineering and Acquisitions Department of EOG:

NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY

	United States			Canada			Trinidad			Other International ⁽¹⁾			Total

NET PROVED RESERVES

Crude Oil (MBbl) ⁽²⁾
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
Revisions of previous estimates		4,105			(2,493	)		71			5			1,688
Purchases in place		1,010			-			-			-			1,010
Extensions, discoveries and other additions		241,171			5,681			-			8,834			255,686
Sales in place		(15,921	)		(1,343	)		-			-			(17,264	)
Production		(54,632	)		(2,574	)		(550	)		(39	)		(57,795	)
Net proved reserves at December 31, 2012		671,029			17,863			3,028			8,898			700,818
Revisions of previous estimates		57,668			(5,866	)		(991	)		(142	)		50,669
Purchases in place		1,097			-			-			-			1,097
Extensions, discoveries and other additions		230,023			673			-			58			230,754
Sales in place		(2,337	)		-			-			-			(2,337	)
Production		(77,431	)		(2,550	)		(447	)		(33	)		(80,461	)
Net proved reserves at December 31, 2013		880,049			10,120			1,590			8,781			900,540

Natural Gas Liquids (MBbl) ⁽²⁾
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
Revisions of previous estimates		47,293			563			-			-			47,856
Purchases in place		612			-			-			-			612
Extensions, discoveries and other additions		71,396			178			-			-			71,574
Sales in place		(7,300	)		(77	)		-			-			(7,377	)
Production		(20,181	)		(309	)		-			-			(20,490	)
Net proved reserves at December 31, 2012		318,406			1,557			-			-			319,963
Revisions of previous estimates		12,157			(48	)		-			-			12,109
Purchases in place		1,202			-			-			-			1,202
Extensions, discoveries and other additions		69,187			10			-			-			69,197
Sales in place		(1,471	)		-			-			-			(1,471	)
Production		(23,479	)		(315	)		-			-			(23,794	)
Net proved reserves at December 31, 2013		376,002			1,204			-			-			377,206

F-38

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	United States			Canada			Trinidad			Other International ⁽¹⁾			Total

Natural Gas (Bcf) ⁽³⁾
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
Revisions of previous estimates		(1,736.0	)		(894.5	)		(24.1	)		1.6			(2,653.0	)
Purchases in place		14.8			-			-			-			14.8
Extensions, discoveries and other additions		477.8			-			-			0.3			478.1
Sales in place		(386.2	)		(8.5	)		-			-			(394.7	)
Production		(380.2	)		(34.6	)		(138.4	)		(3.4	)		(556.6	)
Net proved reserves at December 31, 2012		4,036.0			98.3			588.2			17.0			4,739.5
Revisions of previous estimates		264.0			31.4			(17.4	)		(0.7	)		277.3
Purchases in place		5.7			-			-			-			5.7
Extensions, discoveries and other additions		504.7			0.1			79.5			9.8			594.1
Sales in place		(69.4	)		-			-			-			(69.4	)
Production		(342.3	)		(27.7	)		(129.6	)		(2.8	)		(502.4	)
Net proved reserves at December 31, 2013		4,398.7			102.1			520.7			23.3			5,044.8

Oil Equivalents (MBoe) ⁽²⁾
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
Revisions of previous estimates		(237,936	)		(151,015	)		(3,953	)		283			(392,621	)
Purchases in place		4,098			-			-			-			4,098
Extensions, discoveries and other additions		392,196			5,860			-			8,876			406,932
Sales in place		(87,588	)		(2,832	)		-			-			(90,420	)
Production		(138,170	)		(8,657	)		(23,616	)		(611	)		(171,054	)
Net proved reserves at December 31, 2012		1,662,108			35,804			101,060			11,726			1,810,698
Revisions of previous estimates		113,823			(676	)		(3,892	)		(265	)		108,990
Purchases in place		3,241			-			-			-			3,241
Extensions, discoveries and other additions		383,324			693			13,245			1,703			398,965
Sales in place		(15,375	)		-			-			-			(15,375	)
Production		(157,955	)		(7,482	)		(22,049	)		(490	)		(187,976	)
Net proved reserves at December 31, 2013		1,989,166			28,339			88,364			12,674			2,118,543

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

(2)	Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.

(3)	Billion cubic feet.

F-39

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2013, EOG added 399 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Bakken, Permian Basin, and Barnett Combo shale plays. Approximately 75% of the 2013 reserve additions were crude oil and condensate and NGLs and over 96% were in the United States. Sales in place of 15 MMBoe were primarily related to the disposition of certain producing natural gas assets in South Texas, the Barnett Shale and the Permian Basin. Revisions of previous estimates of positive 109 MMBoe for 2013 included a positive revision of 61 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2013 reserves estimation as compared to the price used in the prior year estimate. The primary plays affected were the Barnett Shale, the Uinta and Green River basins in the Rocky Mountain area and the Haynesville Shale play. Revisions other than price resulted primarily from improved recovery in the Eagle Ford.

During 2012, EOG added 407 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Permian Basin, Bakken and Barnett Combo shale plays. Approximately 80% of the 2012 reserve additions were crude oil and condensate and NGLs and over 96% were in the United States. Sales in place of 90 MMBoe were primarily related to the disposition of certain producing natural gas assets on the Gulf Coast, outside-operated crude oil properties in the Rocky Mountain area and other producing basins in the United States. Revisions of previous estimates of negative 393 MMBoe for 2012 included a negative revision of 531 MMBoe primarily due to a decrease in the average natural gas price used in the December 31, 2012 reserves estimation as compared to the price used in the prior year estimate. The primary plays affected were the Horn River, Haynesville, Barnett Shale and Marcellus Shale. Revisions other than price resulted from revisions for certain crude oil and natural gas properties in the United States.

During 2011, EOG added 387 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 NGLs 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 area 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 revisions for certain crude oil and natural gas properties in the United States, Canada and Trinidad.

F-40

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	United States		Canada		Trinidad		Other International ⁽¹⁾		Total

NET PROVED DEVELOPED RESERVES

Crude Oil (MBbl)
December 31, 2010		161,907		11,283		3,852		98		177,140
December 31, 2011		213,872		8,128		2,657		98		224,755
December 31, 2012		281,167		6,853		2,377		253		290,650
December 31, 2013		382,517		6,871		1,505		163		391,056
Natural Gas Liquids (MBbl)
December 31, 2010		91,401		1,475		-		-		92,876
December 31, 2011		124,271		1,092		-		-		125,363
December 31, 2012		161,482		1,111		-		-		162,593
December 31, 2013		199,964		896		-		-		200,860
Natural Gas (Bcf)
December 31, 2010		3,519.7		401.6		519.2		17.3		4,457.8
December 31, 2011		3,235.0		295.8		606.3		18.5		4,155.6
December 31, 2012		2,387.5		98.3		476.7		17.0		2,979.5
December 31, 2013		2,597.3		102.1		494.6		19.4		3,213.4
Oil Equivalents (MBoe)
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
December 31, 2012		840,564		24,348		81,826		3,081		949,819
December 31, 2013		1,015,359		24,782		83,933		3,402		1,127,476


NET PROVED UNDEVELOPED RESERVES

Crude Oil (MBbl)
December 31, 2010		193,550		14,353		879		-		208,782
December 31, 2011		281,424		10,464		850		-		292,738
December 31, 2012		389,862		11,010		651		8,645		410,168
December 31, 2013		497,532		3,249		85		8,618		509,484
Natural Gas Liquids (MBbl)
December 31, 2010		59,033		-		-		-		59,033
December 31, 2011		102,315		110		-		-		102,425
December 31, 2012		156,924		446		-		-		157,370
December 31, 2013		176,038		308		-		-		176,346
Natural Gas (Bcf)
December 31, 2010		2,971.8		732.2		308.4		-		4,012.4
December 31, 2011		2,810.8		740.1		144.4		-		3,695.3
December 31, 2012		1,648.5		-		111.5		-		1,760.0
December 31, 2013		1,801.4		-		26.1		3.9		1,831.4
Oil Equivalents (MBoe)
December 31, 2010		747,878		136,383		52,287		-		936,548
December 31, 2011		852,207		133,924		24,919		-		1,011,050
December 31, 2012		821,544		11,456		19,234		8,645		860,879
December 31, 2013		973,807		3,557		4,431		9,272		991,067

(1)

Other International includes EOG's United Kingdom, China and Argentina operations.

F-41

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the twelve-month period ended December 31, 2013, total PUDs increased by 130 MMBoe to 991 MMBoe. EOG added approximately 28 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-36 of this Annual Report on Form 10-K), EOG added 263 MMBoe. The PUD additions were primarily in the Eagle Ford, Bakken and Permian Basin shale plays, and over 80% of the additions were crude oil and condensate and NGLs. During 2013, EOG drilled and transferred 160 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,874 million. Revisions of PUDs totaled negative 1 MMBoe. During 2013, EOG did not sell any PUD reserves.

For the twelve-month period ended December 31, 2012, total PUDs decreased by 150 MMBoe to 861 MMBoe. EOG added approximately 32 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, EOG added 268 MMBoe. The PUD additions were primarily in the Eagle Ford, Permian Basin, Bakken and Barnett Combo shale plays, and nearly 84% of the additions were crude oil and condensate and NGLs. During 2012, EOG drilled and transferred 138 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,764 million. Revisions of PUDs totaled negative 293 MMBoe, primarily due to removal of certain natural gas PUDs due to lower average natural gas prices. The primary plays affected were the Horn River, Haynesville, Barnett Shale and Marcellus Shale. During 2012, EOG sold 19 MMBoe of PUDs.

For the twelve-month period ended December 31, 2011, total 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, EOG added 199 MMBoe. The PUD additions were primarily in the Eagle Ford and Barnett Combo shale plays, and over 78% of the additions were crude oil and condensate and NGLs. 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.

F-42

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, 2013 and 2012:

	2013			2012

Proved properties	$	41,377,303		$	36,872,434
Unproved properties		1,444,500			1,253,864
Total		42,821,803			38,126,298
Accumulated depreciation, depletion and amortization		(18,880,611	)		(16,849,068	)
Net capitalized costs	$	23,941,192		$	21,277,230

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 Accounting Standards Codification (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-43

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, 2013, 2012 and 2011:

	United States		Canada			Trinidad		Other International ⁽¹⁾			Total

2013
Acquisition Costs of Properties
Unproved	$	411,556	$	2,565		$	-	$	-		$	414,121
Proved		120,220		(6	)		-		-			120,214
Subtotal		531,776		2,559			-		-			534,335
Exploration Costs		273,788		19,660			16,060		67,671			377,179
Development Costs ⁽²⁾		5,573,260		149,426			124,231		239,460			6,086,377
Total	$	6,378,824	$	171,645		$	140,291	$	307,131		$	6,997,891

2012
Acquisition Costs of Properties
Unproved	$	471,345	$	33,561		$	1,000	$	(603	)	$	505,303
Proved		739		-			-		-			739
Subtotal		472,084		33,561			1,000		(603	)		506,042
Exploration Costs		333,534		38,530			19,555		53,979			445,598
Development Costs ⁽³⁾		5,657,378		278,995			32,609		147,568			6,116,550
Total	$	6,462,996	$	351,086		$	53,164	$	200,944		$	7,068,190

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 ⁽⁴⁾		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

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

(2)	Includes Asset Retirement Costs of $84 million, $13 million and $37 million for the United States, Canada and Other International, respectively. Excludes other property, plant and equipment.

(3)	Includes Asset Retirement Costs of $80 million, $33 million, $2 million and $12 million for the United States, Canada, Trinidad and Other International, respectively. Excludes other property, plant and equipment.

(4)	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.

F-44

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Results of Operations for Oil and Gas Producing Activities ⁽¹⁾. The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2013, 2012 and 2011:


	United States		Canada			Trinidad		Other International ⁽²⁾			Total

2013
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	9,897,701	$	319,880		$	517,482	$	20,583		$	10,755,646
Other		51,713		4,770			24		-			56,507
Total		9,949,414		324,650			517,506		20,583			10,812,153
Exploration Costs		141,286		11,203			2,345		6,512			161,346
Dry Hole Costs		14,276		9,579			4,478		46,322			74,655
Transportation Costs		841,567		9,694			659		1,124			853,044
Production Costs		1,494,791		154,947			43,279		13,205			1,706,222
Impairments		178,718		84,934			14,274		9,015			286,941
Depreciation, Depletion and Amortization		3,122,858		179,520			181,637		13,995			3,498,010
Income (Loss) Before Income Taxes		4,155,918		(125,227	)		270,834		(69,590	)		4,231,935
Income Tax Provision (Benefit)		1,486,445		(32,295	)		103,313		(66,931	)		1,490,532
Results of Operations	$	2,669,473	$	(92,932	)	$	167,521	$	(2,659	)	$	2,741,403

2012
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	7,048,572	$	321,597		$	565,030	$	23,177		$	7,958,376
Other		40,780		367			15		-			41,162
Total		7,089,352		321,964			565,045		23,177			7,999,538
Exploration Costs		162,152		13,350			2,262		7,805			185,569
Dry Hole Costs		1,772		1,570			-		11,628			14,970
Transportation Costs		591,547		7,511			1,104		1,269			601,431
Production Costs		1,264,633		154,509			37,792		11,694			1,468,628
Impairments		294,172		976,563			-		-			1,270,735
Depreciation, Depletion and Amortization		2,637,500		222,366			146,690		17,958			3,024,514
Income (Loss) Before Income Taxes		2,137,576		(1,053,905	)		377,197		(27,177	)		1,433,691
Income Tax Provision (Benefit)		761,459		(136,105	)		119,442		(21,890	)		722,906
Results of Operations	$	1,376,117	$	(917,800	)	$	257,755	$	(5,287	)	$	710,785

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

(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, 2013.

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

F-45

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, 2013, 2012 and 2011:

	United States		Canada		Trinidad		Other International ⁽¹⁾		Composite

Year Ended December 31, 2013	$	5.78	$	19.98	$	1.36	$	26.77	$	5.88

Year Ended December 31, 2012	$	5.96	$	16.42	$	0.98	$	18.97	$	5.85

Year Ended December 31, 2011	$	6.19	$	14.26	$	0.78	$	13.82	$	6.03

(1) Other International primarily consists of EOG's United Kingdom, China and Argentina 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, NGLs 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 2013, 2012 and 2011. 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, NGLs 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-46

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, 2013, 2012 and 2011:

	United States			Canada			Trinidad			Other International ⁽¹⁾			Total

2013
Future cash inflows ⁽²⁾	$	119,644,713		$	1,199,251		$	2,082,195		$	1,073,340		$	123,999,499
Future production costs		(49,099,393	)		(540,188	)		(315,483	)		(211,424	)		(50,166,488	)
Future development costs		(17,753,860	)		(529,788	)		(112,050	)		(153,653	)		(18,549,351	)
Future income taxes		(15,763,089	)		-			(603,786	)		(49,512	)		(16,416,387	)
Future net cash flows		37,028,371			129,275			1,050,876			658,751			38,867,273
Discount to present value at 10% annual rate		(17,451,470	)		202,379			(174,236	)		(110,514	)		(17,533,841	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	19,576,901		$	331,654		$	876,640		$	548,237		$	21,333,432
2012
Future cash inflows ⁽³⁾	$	89,324,274		$	1,816,369		$	2,408,116		$	1,063,854		$	94,612,613
Future production costs		(35,892,997	)		(751,113	)		(342,113	)		(198,609	)		(37,184,832	)
Future development costs		(15,825,040	)		(813,061	)		(171,737	)		(221,893	)		(17,031,731	)
Future income taxes		(10,247,007	)		-			(691,109	)		(212,626	)		(11,150,742	)
Future net cash flows		27,359,230			252,195			1,203,157			430,726			29,245,308
Discount to present value at 10% annual rate		(12,177,896	)		146,954			(242,087	)		(56,807	)		(12,329,836	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	15,181,334		$	399,149		$	961,070		$	373,919		$	16,915,472
2011
Future cash inflows ⁽⁴⁾	$	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

(1)

Other International includes EOG's United Kingdom, China and Argentina operations.

(2)

Estimated crude oil prices used to calculate 2013 future cash inflows for the United States, Canada, Trinidad and Other International were $105.91, $91.47, $94.30 and $107.36, respectively. Estimated NGLs prices used to calculate 2013 future cash inflows for the United States and Canada were $29.42 and $40.88, respectively. Estimated natural gas prices used to calculate 2013 future cash inflows for the United States, Canada, Trinidad and Other International were $3.50, $2.95, $3.71 and $5.67, respectively.

(3)

Estimated crude oil prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $99.78, $84.77, $94.46 and $109.94, respectively. Estimated NGLs prices used to calculate 2012 future cash inflows for the United States and Canada were $36.95 and $47.80, respectively. Estimated natural gas prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $2.63, $2.22, $3.61, and $5.04, respectively.

(4)

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 NGLs 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.

F-47

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, 2013:

	United States			Canada			Trinidad			Other International			Total
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
Sales and transfers of oil and gas produced, net of production costs		(5,192,392	)		(159,577	)		(526,134	)		(10,214	)		(5,888,317	)
Net changes in prices and production costs		(393,585	)		(67,964	)		162,600			(2,283	)		(301,232	)
Extensions, discoveries, additions and improved recovery, net of related costs		5,517,945			79,529			-			484,648			6,082,122
Development costs incurred		2,042,300			23,600			23,500			5,200			2,094,600
Revisions of estimated development cost		1,987,330			383,215			(28,835	)		(234	)		2,341,476
Revisions of previous quantity estimates		(3,286,943	)		(396,408	)		(62,285	)		2,809			(3,742,827	)
Accretion of discount		1,832,377			63,635			178,298			2,907			2,077,217
Net change in income taxes		174,418			-			88,853			(138,206	)		125,065
Purchases of reserves in place		64,317			-			-			5,623			69,940
Sales of reserves in place		(869,534	)		(44,227	)		-			-			(913,761	)
Changes in timing and other		(1,070,553	)		(119,001	)		(59,134	)		(5,404	)		(1,254,092	)
December 31, 2012		15,181,334			399,149			961,070			373,919			16,915,472
Sales and transfers of oil and gas produced, net of production costs		(7,561,343	)		(155,239	)		(473,544	)		(6,254	)		(8,196,380	)
Net changes in prices and production costs		1,734,058			(438,982	)		(12,050	)		(25,173	)		1,257,853
Extensions, discoveries, additions and improved recovery, net of related costs		5,449,531			33,901			-			-			5,483,432
Development costs incurred		2,792,400			95,400			67,100			1,000			2,955,900
Revisions of estimated development cost		892,803			48,906			(3,539	)		52,226			990,396
Revisions of previous quantity estimates		1,887,062			(23,915	)		(60,419	)		(8,530	)		1,794,198
Accretion of discount		1,895,503			39,915			147,099			51,212			2,133,729
Net change in income taxes		(2,772,267	)		-			56,373			137,644			(2,578,250	)
Purchases of reserves in place		66,359			-			-			-			66,359
Sales of reserves in place		(140,652	)		-			-			-			(140,652	)
Changes in timing and other		152,113			332,519			194,550			(27,807	)		651,375
December 31, 2013	$	19,576,901		$	331,654		$	876,640		$	548,237		$	21,333,432

F-48

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Unaudited Quarterly Financial Information

(In Thousands, Except Per Share Data)

Quarter Ended	Mar 31		Jun 30		Sep 30		Dec 31

2013
Net Operating Revenues	$	3,356,514	$	3,840,185	$	3,541,396	$	3,749,023
Operating Income	$	833,074	$	1,092,044	$	769,769	$	980,324

Income Before Income Taxes	$	761,019	$	1,035,230	$	721,555	$	919,082
Income Tax Provision		266,294		375,538		259,057		338,888
Net Income	$	494,725	$	659,692	$	462,498	$	580,194
Net Income Per Share ⁽¹⁾
Basic	$	1.84	$	2.44	$	1.71	$	2.14
Diluted	$	1.82	$	2.42	$	1.69	$	2.12
Average Number of Common Shares
Basic		269,358		270,016		270,471		270,929
Diluted		272,263		272,739		273,576		273,983

2012
Net Operating Revenues	$	2,806,651	$	2,909,319	$	2,954,855	$	3,011,811
Operating Income (Loss)	$	559,772	$	692,339	$	605,747	$	(378,061	)

Income (Loss) Before Income Taxes	$	520,134	$	646,239	$	560,189	$	(445,822	)
Income Tax Provision		196,125		250,461		204,698		59,177
Net Income (Loss) ⁽²⁾	$	324,009	$	395,778	$	355,491	$	(504,999	)
Net Income (Loss) Per Share ⁽¹⁾
Basic	$	1.22	$	1.48	$	1.33	$	(1.88	)
Diluted	$	1.20	$	1.47	$	1.31	$	(1.88	)
Average Number of Common Shares
Basic		266,674		266,874		267,941		268,941
Diluted		270,242		269,985		270,982		268,941

(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.

(2)

Fourth quarter 2012 results include the impact of pretax impairments of $1,020 million, primarily related to proved and unproved natural gas properties in Canada and the United States as well as an additional income tax provision of $135 million related to valuation allowances recorded to reduce the value of Canadian deferred tax assets.

F-49

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). (SEC File No. 001-09743).

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) (SEC File No. 001-09743).

E-1

Exhibit Number		Description

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). (SEC File No. 001-09743).

3.2	-	Bylaws, as amended and restated effective as of May 3, 2013 (Exhibit 4.2 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).

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).

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). (SEC File No. 001-09743).

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). (SEC File No. 001-09743).

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). (SEC File No. 001-09743).

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) (SEC File No. 001-09743).

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) (SEC File No. 001-09743).

#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	-	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.

4.7	-	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).

E-2

Exhibit Number		Description

4.8(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).

4.8(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).

4.9(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).

4.9(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).

4.9(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).

4.10(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).

4.10(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).

4.10(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).

4.10(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).

4.11(a)	-	Officers' Certificate Establishing 2.625% Senior Notes due 2023, dated September 10, 2012 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed September 11, 2012).

4.11(b)	-	Form of Global Note with respect to the 2.625% Senior Notes due 2023 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed September 11, 2012).

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). (SEC File No. 001-09743).

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). (SEC File No. 001-09743).

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) +	-	Third Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as of September 26, 2012 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012).

E-3

Exhibit Number		Description

10.1(e)+	-	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). (SEC File No. 001-09743).

10.1(f)+	-	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(g)+	-	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). (SEC File No. 001-09743).

10.1(h)+	-	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(i)	-	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). (SEC File No. 001-09743).

10.1(j)+	-	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). (SEC File No. 001-09743).

10.1(k)+	-	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). (SEC File No. 001-09743).

10.1(l)	-	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). (SEC File No. 001-09743).

10.1(m)	-	Form of Nonemployee Director Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012).

10.1(n)+	-	Form of Performance Unit Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed October 1, 2012).

10.1(o)+	-	Form of Performance 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 October 1, 2012).

10.2(a)+	-	Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, effective as of May 2, 2013 (Exhibit 4.4 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).

E-4

Exhibit Number		Description

10.2(b)+	-	Form of Restricted Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 4.5 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).

10.2(c)+	-	Form of Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 4.6 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).

10.2(d)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 4.7 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).

10.2(e)+	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 4.8 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).

10.2(f)+	-	Form of Performance Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 4.9 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).

10.2(g)	-	Form of Non-Employee Director Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 4.10 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).

10.2(h)	-	Form of Non-Employee Director Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 4.11 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).

10.3(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). (SEC File No. 001-09743).

10.3(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)) (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2011) (originally filed as Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008). (SEC File No. 001-09743).

10.3(c)+	-	First Amendment to the EOG Resources, Inc. 409A Deferred Compensation Plan, effective as of January 1, 2013 (Exhibit 10.8 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013).

10.3(d)+	-	Amended and Restated 1996 Deferral Plan (Exhibit 4.4 to EOG's Registration Statement on Form S-8, SEC File No. 333-84014, filed March 8, 2002).

E-5

Exhibit Number		Description

10.3(e)+	-	First Amendment to Amended and Restated 1996 Deferral Plan, effective as of September 10, 2002 (Exhibit 10.9(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 2002) (SEC File No. 001-09743).

10.4(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).

10.4(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).

10.4(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).

10.4(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).

10.4(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).

10.4(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).

10.4(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).

10.5(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).

10.5(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).

10.6(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).

10.6(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).

10.7(a)+	-	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).

E-6

Exhibit Number		Description

10.7(b)+	-	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).

10.7(c)+	-	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(d)+	-	Third Amendment to Amended and Restated Change of Control Agreement between EOG and Mark G. Papa, effective as of September 4, 2013 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013).

10.8(a)+	-	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).

10.8(b)+	-	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).

10.8(c)+	-	Second Amendment to Change of Control Agreement between EOG and William R. Thomas, effective as of September 4, 2013 (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013).

10.9(a)+	-	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).

10.9(b)+	-	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).

10.9(c)+	-	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).

10.9(d)+	-	Third Amendment to Amended and Restated Change of Control Agreement between EOG and Gary L. Thomas, effective as of September 4, 2013 (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013).

10.10(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).

10.10(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).

E-7

Exhibit Number		Description

10.10(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).

10.11(a)+	-	Change of Control Agreement by and between EOG and Michael P. Donaldson, effective as of May 3, 2012 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012).

10.11(b)+	-	First Amendment to Change of Control Agreement between EOG and Michael P. Donaldson, effective as of September 4, 2013 (Exhibit 10.7 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013).

10.12(a)+	-	Change of Control Agreement by and between EOG and Lloyd W. Helms, effective as of June 27, 2013 (Exhibit 10.9 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013).

10.12(b)+	-	First Amendment to Change of Control Agreement between EOG and Lloyd W. Helms, Jr., effective as of September 4, 2013 (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013).

10.13+	-	Change of Control Agreement by and between EOG and David W. Trice, effective as of September 4, 2013 (Exhibit 10.5 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013).

10.14(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).

10.14(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).

10.15+	-	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).

10.16(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).

10.16(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).

10.17	-	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).

* 12	-	Computation of Ratio of Earnings to Fixed Charges.

* 21	-	Subsidiaries of EOG, as of December 31, 2013.

E-8

Exhibit Number		Description

* 23.1	-	Consent of DeGolyer and MacNaughton.

* 23.2	-	Opinion of DeGolyer and MacNaughton dated January 31, 2014.

* 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, 2013, (ii) the Consolidated Balance Sheets - December 31, 2013 and 2012, (iii) the Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2013, (iv) the Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2013 and (v) Notes to Consolidated Financial Statements.

+ Management contract, compensatory plan or arrangement

E-9

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, 2014	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, 2014.

	Signature	Title

	/s/ WILLIAM R. THOMAS	Chairman of the Board and Chief Executive Officer and
	(William R. Thomas)	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
	(Janet F. Clark)

	*	Director
	(Charles R. Crisp)

	*	Director
	(James C. Day)

	*	Director
	(Mark G. Papa)

	*	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)