UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
(Mark One)
xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

2015
or

oTRANSITION 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 xý  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 xý

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 xý  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 xý  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 xý    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 xý

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: $35,66830, 2015: $47,957 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, 273,119,572549,883,390 shares outstanding as of February 14, 2014.18, 2016.

Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 20142016 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2013,2015, 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
Marketing6
5
Wellhead Volumes and Prices8
6
Competition9
7
Regulation9
7
Other Matters14
10
Executive Officers of the Registrant15
12
ITEM 1A.Risk Factors17
13
ITEM 1B.Unresolved Staff Comments26
22
ITEM 2.Properties26
22
Oil and Gas Exploration and Production - Properties and Reserves26
22
ITEM 3.Legal Proceedings30
25
ITEM 4.Mine Safety Disclosures30
25
PART II
ITEM 5.Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities31
26
ITEM 6.Selected Financial Data34
28
ITEM 7.Management's Discussion and Analysis of Financial Condition and Results of Operations35
29
ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk55
45
ITEM 8.Financial Statements and Supplementary Data55
45
ITEM 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure56
45
ITEM 9A.Controls and Procedures56
45
ITEM 9B.Other Information56
46
PART III
ITEM 10.Directors, Executive Officers and Corporate Governance57
46
ITEM 11.Executive Compensation57
46
ITEM 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters58
46
ITEM 13.Certain Relationships and Related Transactions, and Director Independence59
48
ITEM 14.Principal Accounting Fees and Services59
48
PART IV
ITEM 15.Exhibits, Financial Statement Schedules59
48
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)Canada 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. Information on our website is not incorporated by reference into, and does not constitute a part of, this report.

At December 31, 2013,2015, EOG's total estimated net proved reserves were 2,1192,118 million barrels of oil equivalent (MMBoe), of which 9011,098 million barrels (MMBbl) were crude oil and condensate reserves, 377383 MMBbl were natural gas liquids (NGLs) reserves and 5,0453,825  billion cubic feet, or 841637 MMBoe, were natural gas reserves (see Supplemental Information to Consolidated Financial Statements).  At such date, approximately 94%97% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States 4%and 3% in Trinidad, 1% in Canada and 1% in Other International.Trinidad.  Crude oil equivalent volumes are determined using thea 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, 2013,2015, EOG employed approximately 2,8002,760 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.basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet.  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 additivescompletion technologies for horizontal drilling and formation evaluation, and horizontal completion methods.evaluation.  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 1011 to Consolidated Financial Statements. For information regarding the risks associated with EOG's foreign operations, see ITEM 1A.1A, Risk Factors.

1


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, 2013,2015, on a crude oil equivalent basis, 44%53% of EOG's net proved reserves in the United States and Canada were crude oil and condensate, 19% were NGLs and 37%28% 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 20132015 and certain 20142016 plans for EOG's United States and Canada operations.

United States.The Eagle Ford continues to prove itself as among the best resource playsa world-class oil field having produced in the world.excess of 1.5 billion barrels of crude oil and condensate. With approximately 564,000549,000 of the 632,000its 608,000 total net acres that EOG controls withinin the prolific oil window, EOG continues to be the largest crude oil producer in the Eagle Ford with cumulative gross production in excess of 285 MMBbl of oil. EOG completed 466329 net wells in 2013 yielding a direct after-tax rate2015 and net production averaged approximately 209 thousand barrels per day (MBbld) of return(1) in excesscrude oil and condensate and NGLs, an increase 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.3% over 2014. The combination of self-sourced sand, dedicated frac crews and other services along with continualcontinuous well optimization programs have made this play the centerpiece of EOG's portfolio. In 2016, EOG expects to complete approximately 150 net wells, continue to improve well productivity and reduce drilling and completion costs as well as operating expenses.

In the Permian Basin, EOG is the biggest oil producercompleted 74 net wells primarily in the Eagle FordLeonard, Wolfcamp, and Second Bone Spring Sand plays during 2015, and evaluated multiple development concepts across these liquids-rich plays. In the Delaware Basin Wolfcamp Shale play, with year-end,where it has approximately 168,000 net volumes of approximately 142 thousand barrels per day (MBbld) ofacres, EOG tested 500-foot well spacing in both the crude oil and condensate, an increasecombo portions of 79% over year-end 2012.  In additionthis play with positive results. The success of the 2015 Delaware Basin Wolfcamp program was due to being an anchor shipper onrefined targeting, high-density stimulations and cost reductions, which will make 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.play a focal point of 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 the2016 Permian Basin to develop its liquids-rich Leonard and Wolfcamp plays.  EOG is well positioned withprogram. In the Second Bone Spring Sand play, where it holds approximately 73,000111,000 net acres, inEOG tested multiple target zones and well spacing as close as 550 feet. With over 1,000 estimated remaining net drilling locations, this high-return oil play is another integral part of EOG's Permian Basin portfolio. In the Leonard Shale and 134,000play, EOG has approximately 93,000 net acres in the Wolfcamp Shale, all within the Delaware Basin.and continued development at 300- to 500- foot well spacing. Additionally, EOG has approximately 113,00071,000 net acres in the Wolfcamp Shale within the Midland Basin. Net production in the Permian Basin for 20132015 averaged 23approximately 43 MBbld of crude oil and condensate and NGLs, an increase of 40%30% over 2012.  Natural2014. Net natural gas production increased 24%27% to 54approximately 108 million cubic feet per day (MMcfd). After divestitures in 2013, EOG holds approximately 413,000415,000 net acres throughout the Permian Basin. In 2014,2016, activity will be focused primarily in the Delaware Basin Wolfcamp, Second Bone Spring Sand and Leonard plays by completing approximately 75 net wells.

During 2015, the Rocky Mountain area experienced reduced activity levels due to lower commodity prices but yielded consistent results. In 2015, EOG continued infill drilling on its crude oil acreage in the Williston Basin Bakken core, completing 25 net wells. The 2015 development program also included completing 10 net Codell formation wells in the DJ Basin and 13 net wells in the Turner, Parkman and Niobrara formations in the Powder River Basin. Infrastructure improvements allowed for a substantial reduction in lease operating expenses and a much higher natural gas recovery. Improved efficiencies, lower service company costs both for drilling and completions and lower lease operating expenses resulted in more profitable wells in this challenging price environment. Net production for the entire Rocky Mountain area for 2015 averaged approximately 65 MBbld of crude oil and condensate and NGLs. In 2016, EOG plans to continuecomplete approximately 35 net wells, primarily in the expansionPowder River and development ofWilliston Basins. EOG holds approximately 985,000 net acres in the Leonard and Wolfcamp plays by drilling approximately 65 net wells.

2
Rocky Mountain area.

In the Upper Gulf Coast region, EOG drilled 21completed six net wells during 2015 and net production averaged 124approximately 54 MMcfd of natural gas and 1.9approximately 4 MBbld of crude oil and condensate and NGLs in 2013.  The Haynesville and Bossier Shale plays located near the Texas-Louisiana borderNGLs. In 2016, EOG will 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 netShale, while working to maintain base production and continue its liquids volumes increased to 4 MBbld at year-end 2013.exploration program. EOG holds approximately 593,000529,000 net acres in the Upper Gulf Coast region and plans to increase activity during 2014.complete approximately five net wells in 2016.

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 36completing five net wells.wells in 2015. During 2015, EOG's net production averaged approximately 6 MBbld of crude oil and condensate and NGLs and approximately 29 MMcfd of natural gas. EOG holds approximately 200,000250,000 net acres throughout the trend,Mid-Continent area and plansexpects to drill approximately 25 net crude oil wellscontinue its exploration program in 2014.2016.


2


During 2013,2015, EOG continuedperformed limited development of its liquids-rich Barnett Shale Combo play in the Fort Worth Basin.  EOG drilled 142Basin, completing six 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.wells. In 2013,2015, net daily total production in the Barnett Shale averaged approximately 3627 MBbld of crude oil and condensate and NGLs and approximately 305272 MMcfd of natural gas. For 2014,2016, EOG will continue to be activefocus on maintaining base production. EOG currently holds approximately 351,000 net acres in this play with plans to drill approximately 105 netthe Barnett Shale Combo wells.Shale.

In the South Texas area, EOG drilled 30total net wells in 2013.  Net production during 20132015 averaged approximately 6 MBbld of crude oil and condensate and NGLs and 86approximately 66 MMcfd of natural gas. EOG'sEOG completed seven net wells with activity was focused in San Patricio, Nueces, Brooks, KenedyKleberg and Kleberg Counties.Jim Wells counties. In 2014,2016, EOG will continueexpects to exploitcomplete approximately five net wells in the liquids-rich Frio and Vicksburg sandstrends, where it holds approximately 272,000 net acres. Exploration efforts will continue in this region, primarily focusing on its approximately 320,000 net acre position in these counties and plans to drill approximately 24 net wells.liquids-rich hydrocarbons.

During 2013, EOG significantly slowed development ofNet production in the Marcellus Shale drilling a total of four net wells and completing one net well to hold its acreage position.  Net production for 20132015 averaged 36approximately 24 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 195,000200,000 net acres with Marcellus and Utica Shale potential, mostpotential.

EOG has agreements with certain crude oil refining companies to deliver an average of which is held as fee or by58 MBbld and 9 MBbld of crude oil in 2016 and 2017, respectively, to certain refineries. EOG intends to fulfill these crude oil delivery obligations with its Eagle Ford production.

At December 31, 2013,2015, EOG held approximately 2.72.0 million net undeveloped acres in the United States.

During 2013,2015, 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 and the Permian Basin in West Texas and New Mexico and the Barnett Shale in North Texas.Mexico. At December 31, 2013,2015, EOG-owned natural gas processing capacity in the Eagle Ford and Barnett Shale was 225totaled 305 MMcfd and 180 MMcfd, respectively.

In support of its operations in the Williston Basin,Also during 2015, EOG continued to increase the utilization ofuse its crude oil loading facility near Stanley, North Dakota, to transport its Williston Basin crude oil production and, from time to time, crude oil purchased from third-party producers.production. During 2015, EOG loaded 40681 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 and Stroud, Oklahoma, and certain other destinations in the U.S.

Additionally, in support ofOklahoma. 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 aggregatehas net unloading capacity of approximately 45,000 barrels per train,100 MBbld and shipped to90 MBbld at St. James Louisiana, or to other destinations on the U.S. Gulf Coast.and Stroud, respectively. During 2013,2015, a total of 89 unit train shipments were made from these three facilities.

3

A total of 37218 crude oil unit trains carrying EOG production were received at athe crude oil unloading facility in St. James, Louisiana, during 2013. Owned by EOG and NuStar Energy L.P., this facilitywhich 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,In addition, EOG utilized its Stroud, Oklahoma, crude oil unloading facility and pipeline to transport 5063 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 marketing and related logistics processes, including 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. EOG expects to utilize its crude-by-rail network when it is advantageous.

Since 2008, EOG has been operatingoperates its own sand mine and sand processing plant locatedplants 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.Texas. Additionally, EOG purchasedowns a second Hood County sand processing plant, in 2011, and utilizes that facility to processwhich processes raw EOG-owned sand from Wisconsin, and sand sourced from the north Texas area, as needed, to support EOG's well completion activities in several key EOG plays.needed.

In 2013,2015, EOG increased the use of processedcontinued to process sand from its Chippewa Falls, Wisconsin, sand plant which  processeson an as-needed basis.

EOG placed in service an additional sand from multiple EOG-owned mines nearby.  unloading facility in Loving, New Mexico, during the first quarter of 2015 to support well completions in the Delaware Basin.

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 2013,2015, EOG shipped the equivalent of 89173 sand unit trains of processed sand forfrom various sources, to support 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.other plays.

43


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,Canada 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 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 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 licenses covering the Sercan Area (formerly known as the EMZ Area) offshore Trinidad;
·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);
·holds a 100% working interest in a production sharing contract with the Government ofowns a 12% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Caribbean Nitrogen Company Limited; 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 EMZSercan 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 Limited and its subsidiary (NGC). Crude oil and condensate from EOG's Trinidad operations currently is sold to the Petroleum Company of Trinidad and Tobago Limited.Limited (Petrotrin).  In 2013,2015, EOG's average net production from Trinidad was 355averaged approximately 349 MMcfd of natural gas and 1.2approximately 0.9 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 the2015, finishing its SECC Block and Modified U(b) Blocks duringBlock drilling program which was initiated in 2014.

In 2014, certain agreements with NGC require2016, it is anticipated that EOG's Trinidad operations to deliverwill supply approximately 490430 MMcfd (360(290 MMcfd, net) of natural gas under current economic conditions.  EOG intends to fulfill thesefrom its existing proved reserves. All of the natural gas delivery obligations by using productionproduced from existing proved reserves.EOG's Trinidad operations in 2016 is expected to be supplied to NGC under various contracts with NGC. All crude oil and condensate produced from EOG's Trinidad operations in 2016 is expected to be supplied to Petrotrin under various contracts with Petrotrin. In 2016, EOG expects to complete one net well and install infrastructure in the Sercan Area.

At December 31, 2013,2015, EOG held approximately 39,00040,000 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 2013,2015, a limited amount of production continued from the Valkyrie field in this block.

In 2006, EOGUK participated in Production ceased at the drilling and successful testingend 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 2013,2015, and decommissioning is planned for the U.K. Departmentfourth quarter 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.

5
2016.

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,The well, 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 forDuring 2012 and 2013, 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, modificationsinstalled. Modifications to the nearby third-party owned Douglas platform, began and a crude oil processing module was installed.  The Douglas platformwhich will be used to process Conwy production.  Duringproduction, began in 2013 the three-well Conwy development drilling program was completed with firstand continued throughout 2014 and 2015. First production from the Conwy field is anticipated in late 2014.March 2016.

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 2013,2015, production averaged 1less than 0.1 MMcfd of natural gas, net, in the United Kingdom.

At December 31, 2013,2015, EOG held approximately 54,0007,000 net undeveloped acres in the United Kingdom.


4


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,In 2015, EOG successfully recompleted a well and drilled four wells and completed an additional well, boththree wells, one of which began productionwas drilled in 2014, in the latter part of 2013.  AdditionallySichuan Basin, Sichuan Province, China. The successful completions extended the Shaximiao development in 2013, EOG drilled one well that is expected to be completedthe Chuan Zhong Block and begin producingprovides additional opportunities in 2014.  EOG plans to drill six additional wells on its acreage in 2014.the future.

In 2013,2015, production averaged 7approximately 14 MMcfd of natural gas, net, in China.

AtCanada. During 2014, EOG sold all of its assets in Manitoba and the majority of its assets in Alberta in two separate transactions that closed on or about December 31, 2013,1, 2014. EOG helddivested 1.3 million gross acres (1.1 million net), 97 percent of which were in Alberta. Of the approximate 5,800 net producing wells sold, 5,155 were natural gas. In 2015, net production averaged approximately 131,000 net developed acres in China.15 MMcfd of natural gas and less than 0.1 MBbld of NGLs.

Argentina. In 2011, EOG signed two exploration contracts and one farm-in agreement covering approximately 95,000 net acresEOG's activity in Argentina is focused on the Vaca Muerta oil shale formation 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 evaluateProvince. Management is currently evaluating options for its drilling results and exploration program in Argentina.investment.

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 2013,2015, 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 U.S. sales pointsareas included the Midwest, the Permian Basin, Cushing, Oklahoma, St. James, Louisiana, and other points along the U.S. Gulf Coast. In 2014,2016, the pricing mechanism for such production is expected to remain the same.

In 2013,2015, 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 2014,2016, the pricing mechanism for such production is expected to remain the same.

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In 2013,2015, EOG's United States and Canada wellhead natural gas production was sold into local markets or transported by pipeline to downstream markets. Pricing was based on the spot market and long-term natural gas contracts, was at prevailing market prices.the ultimate sales point. In 2014,2016, the pricing mechanism for such production is expected to remain the same.
 
In 2013,2015, 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 2014.2016.

In 2013,2015, all wellhead natural gas volumes from the U.K. were sold on the spot market. TheIn December 2014, marketing strategy for wellhead natural gas volumes from the U.K. is expectedEOG put in place arrangements to remain the same. EOG is currently investigating possible marketing opportunities formarket and sell its U.K. wellhead crude oil production from the Conwy field, which is anticipated to begin in late 2014.March 2016. The crude oil sales will be based on a Dated Brent price or other market prices, as applicable.

In 2013,2015, all wellhead natural gas volumes from China were sold under a contract withat regulated prices based on the purchaser's pipeline sales pricesvolumes to various local market segments. The pricing mechanism for the contractproduction in China is expected to remain the same in 2014.2016.

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 2013,2015, two purchasers each accounted for more than 10% of EOG's total wellhead crude oil and condensate, NGLsNGL 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.


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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 thea 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, 20122015, 2014 and 2011.2013.
Year Ended December 312015 2014 2013
      
Crude Oil and Condensate Volumes (MBbld) (1)
     
United States:     
Eagle Ford181.7
 178.0
 122.3
Other101.6
 104.0
 89.8
United States283.3
 282.0
 212.1
Trinidad0.9
 1.0
 1.2
Other International (2)
0.2
 5.9
 7.1
Total284.4
 288.9
 220.4
Natural Gas Liquids Volumes (MBbld) (1)
 
  
  
United States: 
  
  
Eagle Ford27.2
 24.7
 18.6
Other49.7
 55.0
 45.7
United States76.9
 79.7
 64.3
Other International (2)
0.1
 0.6
 0.9
Total77.0
 80.3
 65.2
Natural Gas Volumes (MMcfd) (1)
 
  
  
United States: 
  
  
Eagle Ford179
 164
 115
Other707
 756
 793
United States886
 920
 908
Trinidad349
 363
 355
Other International (2)
30
 70
 84
Total1,265
 1,353
 1,347
Crude Oil Equivalent Volumes (MBoed) (3)
 
  
  
United States: 
  
  
Eagle Ford238.8
 230.0
 160.2
Other269.1
 285.0
 267.7
United States507.9
 515.0
 427.9
Trinidad59.1
 61.5
 60.4
Other International (2)
5.2
 18.2
 21.8
Total572.2
 594.7
 510.1
      
Total MMBoe (3)
208.9
 217.1
 186.2

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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 312015 2014 2013
      
Average Crude Oil and Condensate Prices ($/Bbl) (4)
     
United States$47.55
 $92.73
 $103.81
Trinidad39.51
 84.63
 90.30
Other International (2)
57.32
 86.75
 87.08
Composite47.53
 92.58
 103.20
Average Natural Gas Liquids Prices ($/Bbl) (4)
     
United States$14.50
 $31.84
 $32.46
Other International (2)
4.61
 40.73
 39.45
Composite14.49
 31.91
 32.55
Average Natural Gas Prices ($/Mcf) (4)
     
United States$1.97
 $3.93
 $3.32
Trinidad2.89
 3.65
 3.68
Other International (2)
5.05
 4.40
 3.39
Composite2.30
 3.88
 3.42
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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.
(2)Other International includes EOG's United Kingdom, China, Canada 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 1112 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.


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7


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) andand/or the Bureau of Indian Affairs (BIA) or, in the case of offshore leases (which, for EOG, are de minimis), 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. In addition, the U.S. Department of the Interior (via various of its agencies, including the BLM, the BIA and the Office of Natural Resources Revenue) has certain authority over our calculation and payment of royalties, bonuses, fines, penalties, assessments and other revenues related to our federal and tribal oil and gas leases.

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, as amended (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, aremay be subject toin the future possibility ofto 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 takenondiscrimination requirements with respect to the provision of gathering and processing services, 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 industryEOG could be required to incur additional capital expenditures and increased compliance and operating costs depending on the nature and extent of such future legislative and regulatory changes.

EOG also owns crude oil rail loading facilities in North Dakota and Texas, and crude oil rail unloading facilities in Oklahoma and Louisiana.Louisiana and crude oil truck unloading facilities in certain of its U.S. plays. 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 and the transportation of its crude oil production by truck, EOG could be required to incur additional capital expenditures and increased compliance and operating 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, state and statelocal regulatory commissions, agencies, councils 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 commissions, agencies, councils and courts will continue indefinitely.remain unchanged.


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8

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. ItIn addition, 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.

11

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.issues. 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 GHGsGHG emissions as pollutants under the federal Clean Air Act. EOG supportsAlso, in December 2015, the U.S. participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts to understand and address the contribution of human activitieswith respect to global climate change throughtemperatures and GHG emissions. If ratified, the application of sound scientific research and analysis.  Moreover, Paris Agreement will take effect in 2020.

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 reportingreports 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 investigations, laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, 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 otherwise 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

9


The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements. However,In March 2015, the BLM issued new regulations applicable to hydraulic fracturing activities on federal and Indian lands, including requirements for chemical disclosure, wellbore integrity and handling of flowback and produced water. In addition, there have been various other 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 reportingadditional operating and public disclosure of the chemical additives used in the fracturing process)compliance costs 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, the U.S. EPA recently proposed regulations that would require operators to reduce methane and VOC emissions from crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations.

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.

12
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, including environmental 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.those countries. EOG currently has operations in Trinidad, the United Kingdom, China, Canada 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.

13

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 NGLsNGL production comprised a larger portion of EOG's production mix in 20132015 than in prior years and is expected to comprise an even larger portion in 2014.years. Average crude oil and condensate prices received by EOG for production in the United States decreased 49% in 2015, decreased 11% in 2014 and Canada increased 6% in 2013, 5% in 2012 and 24% in 2011, each as compared to the immediately preceding year. Average NGLsNGL prices received by EOG for production in the United States decreased 54% in 2015, 2% in 2014 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% increase50% decrease in the average wellhead natural gas price received by EOG for production in the United States in 2015, an 18% increase in 2014 and Canadaa 32% increase in 2013, a 36% decrease in 2012 and an 8% decrease in 2011, each as compared to the immediately preceding year. In addition, as of February 12, 2016, the average 2016 U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $34.97 per barrel and $2.23 per million British thermal units, respectively, representing declines of 28% and 17%, respectively, from the average NYMEX prices in 2015. Due to the many uncertainties associated with the world political environment (for example, the actions of other crude oil exporting nations, including the

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Organization of Petroleum Exporting Countries), the global supply of and demand for crude oil and 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.1A, Risk Factors.

Including the impact of EOG's 2014 crude oil derivative contracts (exclusive of options) and basedBased on EOG's tax position, EOG's price sensitivity in 20142016 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLsNGL price, is approximately $44$65 million for net income and $65$81 million for cash flows from operating activities. Including the impact of EOG's 20142016 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 20142016 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$15 million for net income and $19$18 million for cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts at February 24, 2014,25, 2016, see ITEM 7.7, 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 1112 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, 2014,25, 2016, see ITEM 7.7, 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.

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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 customarycertain 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 toinvolving 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.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.


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Executive Officers of the Registrant

The current executive officers of EOG and their names and ages (as of February 24, 2014)25, 2016) are as follows:

Name
Age
Position
NameAgePosition
William R. Thomas6163Chairman of the Board and Chief Executive Officer
Gary L. Thomas6466President and Chief Operating Officer
Lloyd W. Helms, Jr.5658Executive Vice President, Exploration and Production
David W. Trice4345Executive Vice President, Exploration and Production
Timothy K. Driggers5254Vice President and Chief Financial Officer
Michael P. Donaldson5153Vice President, General Counsel and Corporate Secretary

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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 2011.2011 and President in March 2015. 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.


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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.

ACrude oil, natural gas and NGL prices are volatile, and the substantial orand extended decline in crude oil and/or natural gascommodity prices couldhas had, and may continue to have, a material and adverse effect on us.us and the trading price of our common stock.

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;
·domestic and international drilling activity;
the actions of other crude oil exporting nations, including the Organization of Petroleum Exporting Countries;
·the availability, proximity and capacity of appropriate transportation facilities, gathering, processing and compression facilities and refining facilities;
weather conditions and changes in weather patterns;
·worldwide economic and political conditions, including political instability or armed conflict in oil and gas producing regions;
the availability, proximity and capacity of appropriate transportation facilities, gathering, processing and compression facilities and refining facilities;
·the price and availability of, and demand for, competing energy sources, including alternative energy sources;
worldwide economic and political conditions, including political instability or armed conflict in oil and gas producing regions;
·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 price and availability of, and demand for, competing energy sources, including alternative energy sources;
·the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others; and
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 effect of worldwide energy conservation measures.
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.

Beginning in the fourth quarter of 2014 and continuing through 2015 and into 2016, crude oil prices have substantially declined. In addition, natural gas and NGL prices began to decline substantially in the second quarter of 2014, and such declines continued during 2015 and into 2016. The above-described factors and the volatility of commodity prices make it difficult to predict future crude oil, natural gas and NGL prices. As a result, we cannot predict how long these lower prices will continue, and there can be no assurance that the prices for crude oil, natural gas and/or NGLs will not decline further.

Our cash flows and results of operations depend to a great extent on prevailing commodity prices. Accordingly, the prevailingrecent substantial and extended decline in commodity prices for crude oil and natural gas.  Prolonged or substantial declines in crude oil and/or natural gas prices maycan 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.

Lower commodity prices can also reduce the amount of crude oil, natural gas and NGLs that we can produce economically. Substantial declines in the prices of these commodities can also render uneconomic a significant portion of our exploration, development and exploitation projects, resulting in our having to make significant downward adjustments to our estimated proved reserves. As a result, prolonged or substantial declines in commodity prices can materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance our capital expenditures and, in turn, the trading price of our common stock.

In addition, if we expect or experience significant sustainedprolonged decreases in crude oil and natural gascommodity prices such thatmay cause the expected future cash flows from our crude oil and natural gas properties fallsto fall below thetheir respective net book value of our properties, we may be requiredvalues, which will require us to write down the value of our crude oil and natural gas properties. Any suchSuch asset impairments could materially and adversely affect our results of operations and financial position.

In fact, the substantial declines in turn,crude oil, natural gas and NGL prices that began in 2014 and which have continued into 2016 have materially and adversely affected the amount of cash flows we have available for our capital expenditures and other operating expenses, our results of operations during fiscal year 2015 and the trading price of our common stock.

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As a result of the decreased cash flow available for capital expenditures, we have delayed our drilling and completion plans with respect to certain of our properties. These delays may result in impacts to our production volumes as well as cause us to potentially shut-in certain wells and incur associated lease payment obligations. Such commodity price declines also resulted in an impairment charge (i.e., "write-down") of $6.3 billion in 2015 with respect to our proved oil and gas properties and related assets. Such declines in commodity prices also resulted in our making a downward adjustment of 574 million barrels of oil equivalent to our estimated net proved reserves at December 31, 2015.

In addition, our 2016 financial condition, cash flows and results of operations will be adversely affected if commodity prices remain at current levels or decline further. If commodity prices remain at current levels for an extended period of time or continue to decline, we may be limited in our ability to maintain our current level of dividends on our common stock. Further, if commodity prices remain at current levels or decline further, we may be required to incur additional impairment charges and/or make significant additional downward adjustments to our proved reserve estimates. As a result, our financial condition and results of operations will be further adversely affected.

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.

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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.


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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;
·well blowouts and cratering;
loss of well control;
·loss of well control;
crude oil spills, natural gas leaks and pipeline ruptures;
·crude oil spills, natural gas leaks and pipeline ruptures;
pipe failures and casing collapses;
·pipe failures and casing collapses;
uncontrollable flows of crude oil, natural gas, formation water or drilling fluids;
·uncontrollable flows of crude oil, natural gas, formation water or drilling fluids;
releases of chemicals, wastes or pollutants;
·releases of chemicals, wastes or pollutants;
adverse weather conditions, such as winter storms, flooding and hurricanes, and other natural disasters;
·adverse weather conditions, such as winter storms, flooding and hurricanes, and other natural disasters;
fires and explosions;
·fires and explosions;
terrorism, vandalism and physical, electronic and cyber security breaches;
·terrorism, vandalism and physical, electronic and cyber security breaches;
formations with abnormal or unexpected pressures;
·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
·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.
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·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;
·injury or loss of life;
damage to, or destruction of, property, facilities, equipment and crude oil and natural gas reservoirs;
·damage to, or destruction of, property, facilities, equipment and crude oil and natural gas reservoirs;
pollution or other environmental damage;
·pollution or other environmental damage;
regulatory investigations and penalties as well as clean-up and remediation responsibilities and costs;
·regulatory investigations and penalties as well as clean-up and remediation responsibilities and costs;
suspension or interruption of our operations, including due to injunction;
·suspension or interruption of our operations, including due to injunction;
repairs necessary to resume operations; and
·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.


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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 couldreserves. To the extent we are unsuccessful in turn impactacquiring or finding additional reserves, our future cash flows and results of operations.

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operations and, in turn, the trading price of our common stock could be materially and adversely affected.

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. For example, the U.S. EPA recently proposed regulations that would require operators to reduce methane emissions and emissions of volatile organic compounds from crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In December 2015, the U.S. participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. If ratified, the Paris Agreement will take effect in 2020. It is possible that the Paris Agreement and subsequent domestic and international regulations will have adverse effects on the market for crude oil, natural gas and other fossil fuel products as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, crude oil, natural gas and other fossil fuel products. EOG is unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, laws, regulations and treaties (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.

The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements. In March 2015, however, the U.S. Bureau of Land Management issued new regulations applicable to hydraulic fracturing activities on federal and Indian lands, including requirements for chemical disclosure, wellbore integrity, and handling of flow back and produced water. In addition, there have been various other 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, additional operating and incompliance costs and 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 and Hydraulic Fracturing - United States and Environmental Regulation - Canada under ITEM 1.1, Business - Regulation.


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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.

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Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and production may cease to be eliminatedavailable in the future or may be otherwise modified as a result of future legislation.

Legislation has beenmay be proposed in the future that would,could, if enacted into law, make significant changes to U.S. tax laws, includinglaws. Such changes may include, but not be limited to, 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 limitedcompanies, such as with respect to the elimination of current deductions for intangible drilling costs deduction and development costs.  It is unclearbonus tax depreciation. We can give no assurance whether such changes or similar or other tax law changes will be enactedproposed and, if enacted, how soon any such changes couldwould become effective. The enactment of such changes or any other similarsuch 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 otherthird-party 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.


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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 non-core 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. The lower commodity price environment could also delay or impair our ability to consummate certain planned non-core asset sales and divestitures. 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, weaknessWeakness and/or volatility in domestic and global financial markets or economic conditions and a depressed commodity price environment 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 continued 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.

Our ability to obtain financings and the terms of any financings are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. Factors that may impact our credit ratings include our debt levels; planned asset purchases or sales; near-term and long-term production growth opportunities; liquidity; asset quality; cost structure; product mix; and commodity pricing levels (including, but not limited to, the estimates and assumptions of credit rating agencies with respect to future commodity prices). In February 2016, Standard & Poor’s Ratings Services (an independent credit rating agency), as a result of its lowered assumptions with respect to future commodity prices, lowered its credit ratings of several investment grade-rated U.S. oil and gas exploration and production companies, including its rating of our long-term debt. We expect Moody’s Investors Service, Inc. (also an independent credit rating agency) will take similar action in the near future with respect to its ratings of our debt and its ratings of the debt of other U.S. oil and gas exploration and production companies. Such ratings downgrades could increase our borrowing costs and may adversely impact our ability to access financings. In addition, we cannot provide any assurance that our credit ratings will remain in effect for any given period of time or that our credit ratings will be raised in the future, nor can we provide any assurance that any of our credit ratings will not be further lowered.

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 a depressed commodity price environment, 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.


2218


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, NGLsNGL 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, NGLsNGL 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 2.2, Properties - Oil and Gas Exploration and Production - Properties and Reserves.Reserves and Supplemental Information to Consolidated Financial Statements.

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.

23
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.


19


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 andswap, option, swaption, 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. Our forecasted natural gas production for 2016 is currently approximately 4% hedged at approximately $2.49 per million British thermal units, and none of our forecasted crude oil production for 2016 is currently hedged. As a result, a significant portion of our forecasted production for 2016 remains unhedged and subject to fluctuating market prices. If we are ultimately unable to hedge additional production volumes for 2016 and beyond, we will be impacted by further commodity price declines, which may result in lower net cash provided by operating activities. 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 federalFederal 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), the Securities and Exchange Commission (SEC) and certain federal agencies that regulate the banking and insurance sectors (the Prudential Regulators) 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 numbersome of the rules necessary to implement the Dodd-Frank Act are yet to be adopted, the CFTC, hasthe SEC and the Prudential Regulators have issued severalnumerous rules, to implement the Dodd-Frank Act, including a rule establishing an "end-user" exception to mandatory clearing (End-User Exception), a rule regarding margin for uncleared swaps (Margin Rule) 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. We also qualify as a "non-financial entity" for purposes of the Margin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe our hedging activities would constitute bona fide hedging under the Position Limits Rule and would not be subject to limitation under such rule if it is enacted. However, it remains uncertain whether margin requirements willmany of our hedge counterparties and many other market participants may not be imposed on uncleared swaps.  eligible for the End-User Exception, may be subject to mandatory clearing or the Margin Rule for swaps with some or all of their other swap counterparties, and/or may be subject to the Position Limits Rule. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations related to derivatives (collectively, Foreign Regulations) which may apply to our transactions with counterparties subject to such Foreign Regulations.

The Dodd-Frank Act, the rules which have been adopted and not vacatedthereunder and the Position Limits Rule, to the extent that it is ultimately enacted,Foreign Regulations 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 is reduced as a result of the Dodd-Frank Act, and related regulations or the Foreign 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 expendituresexpenditure requirements. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.

24
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.


20


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%2015, less than 1% 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.

25

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.


21


ITEM 1B.  Unresolved Staff Comments

Not applicable.

ITEM 2.  Properties

Oil and Gas Exploration and Production - Properties and Reserves

Reserve Information. For estimates and discussions 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.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.1A, Risk Factors. EOG's estimates of reserves filed with other federal agencies agreeare consistent with the information set forth in "Supplemental Information to Consolidated Financial Statements."

26

Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2013.2015. 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 

 Developed Undeveloped Total
 Gross Net Gross Net Gross Net
            
United States2,168,651
 1,700,323
 2,895,940
 2,006,080
 5,064,591
 3,706,403
Trinidad75,667
 65,669
 50,338
 39,725
 126,005
 105,394
United Kingdom8,797
 2,570
 13,443
 6,713
 22,240
 9,283
China130,548
 130,548
 —
 —
 130,548
 130,548
Canada54,219
 46,021
 200,618
 161,334
 254,837
 207,355
Argentina—
 —
 183,916
 79,451
 183,916
 79,451
Total2,437,882
 1,945,131
 3,344,255
 2,293,303
 5,782,137
 4,238,434

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 0.70.4 million net acres will expire in 2014, 0.5 million net acres will expire in 2015 and2016, 0.3 million net acres will expire in 20162017 and 0.1 million net acres will expire in 2018 if production is not established or we take no other action to extend the terms of the leases or obtain 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.


22


Producing Well Summary. EOG operated 16,261gross10,074 gross and 14,4328,751 net producing crude oil and natural gas wells at December 31, 2013.2015. Gross crude oil and natural gas wells include 1,514200 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 


The following table represents wells in which EOG owns a working interest, including non-EOG operated wells.
27
 Crude Oil Natural Gas Total
 Gross Net Gross Net Gross Net
            
United States4,842
 3,846
 6,024
 5,261
 10,866
 9,107
Trinidad13
 10
 34
 29
 47
 39
China—
 —
 31
 31
 31
 31
Canada10
 1
 24
 23
 34
 24
Argentina3
 1
 —
 —
 3
 1
Total4,868
 3,858
 6,113
 5,344
 10,981
 9,202

Drilling and Acquisition Activities.  During the years ended December 31, 2013, 20122015, 2014 and 2011,2013, EOG expended $7.0$4.9 billion, $7.1$7.9 billion and $6.6$7.0 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement obligations of $134$53 million, $127$196 million and $133$134 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, 20122015, 2014 and 2011:2013:
 Gross Development Wells Completed Gross Exploratory Wells Completed
 Crude Oil Natural Gas Dry Hole Total Crude Oil Natural Gas Dry Hole Total
2015               
United States494
 16
 9
 519
 2
 —
 —
 2
Trinidad—
 3
 —
 3
 —
 1
 —
 1
China—
 —
 —
 —
 —
 3
 2
 5
Total494
 19
 9
 522
 2
 4
 2
 8
2014 
  
  
  
  
  
  
  
United States901
 47
 8
 956
 12
 —
 5
 17
Trinidad—
 1
 —
 1
 —
 —
 —
 —
United Kingdom—
 —
 —
 —
 —
 —
 1
 1
China—
 —
 —
 —
 —
 2
 —
 2
Canada42
 —
 —
 42
 —
 —
 —
 —
Argentina—
 —
 —
 —
 —
 —
 3
 3
Total943
 48
 8
 999
 12
 2
 9
 23
2013            

  
United States909
 57
 22
 988
 7
 2
 3
 12
Trinidad—
 1
 —
 1
 —
 1
 —
 1
United Kingdom3
 —
 —
 3
 —
 —
 1
 1
China—
 —
 —
 —
 —
 1
 —
 1
Canada85
 —
 —
 85
 1
 —
 —
 1
Argentina—
 —
 —
 —
 1
 —
 —
 1
Total997
 58
 22
 1,077
 9
 4
 4
 17

 
 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 

23


28
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, 20122015, 2014 and 2011:2013:

 
 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 

 Net Development Wells Completed Net Exploratory Wells Completed
 Crude Oil Natural Gas Dry Hole Total Crude Oil Natural Gas Dry Hole Total
2015               
United States457
 14
 8
 479
 2
 —
 —
 2
Trinidad—
 2
 —
 2
 —
 1
 —
 1
China—
 —
 —
 —
 —
 3
 2
 5
Total457
 16
 8
 481
 2
 4
 2
 8
2014 
  
  
  
  
  
  
  
United States807
 39
 7
 853
 11
 —
 5
 16
Trinidad—
 1
 —
 1
 —
 —
 —
 —
United Kingdom—
 —
 —
 —
 —
 —
 1
 1
China—
 —
 —
 —
 —
 2
 —
 2
Canada35
 —
 —
 35
 —
 —
 —
 —
Argentina—
 —
 —
 —
 —
 —
 1
 1
Total842
 40
 7
 889
 11
 2
 7
 20
2013 
  
  
  
  
  
  
  
United States788
 50
 15
 853
 6
 2
 3
 11
Trinidad—
 1
 —
 1
 —
 1
 —
 1
United Kingdom3
 —
 —
 3
 —
 —
 1
 1
China—
 —
 —
 —
 —
 1
 —
 1
Canada76
 —
 —
 76
 1
 —
 —
 1
Argentina—
 —
 —
 —
 1
 —
 —
 1
Total867
 51
 15
 933
 8
 4
 4
 16

EOG participated in the drilling of wells that were in progressthe process of being drilled or completed at the end of the period as set out in the table below for the years ended December 31, 2013, 20122015, 2014 and 2011:2013:
 Wells in Progress at End of Period
 2015 2014 2013
 Gross Net Gross Net Gross Net
            
United States516
 429
 388
 327
 320
 280
Trinidad—
 —
 1
 1
 —
 —
China—
 —
 2
 2
 2
 2
Canada—
 —
 —
 —
 13
 8
Argentina—
 —
 —
 —
 1
 1
Total516
 429
 391
 330
 336
 291

24

 
 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 


29
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, 20122015, 2014 and 2011:2013:

 
 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 
 Gross Acquired Wells Net Acquired Wells
 
Crude
Oil
 Natural Gas Total 
Crude
Oil
 Natural Gas Total
2015           
United States24
 —
 24
 23
 —
 23
Total24
 —
 24
 23
 —
 23
2014 
  
  
  
  
  
United States91
 10
 101
 41
 9
 50
Total91
 10
 101
 41
 9
 50
2013 
  
  
  
  
  
United States68
 27
 95
 50
 21
 71
Total68
 27
 95
 50
 21
 71
 
All of EOG's drilling and completion 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 withand sand mine and sand processing assets which support EOG's exploration and production activities. EOG does not own drilling rigs, hydraulic fracturing equipment or rail cars.


ITEM 3.  Legal Proceedings

The information required by this Item is set forth under the "Contingencies" caption in Note 78 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.

25

30

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
2015     
First Quarter$97.88
 $82.72
 $0.1675
Second Quarter101.36
 86.15
 0.1675
Third Quarter87.85
 68.15
 0.1675
Fourth Quarter89.52
 69.30
 0.1675
2014 
  
  
First Quarter$99.75
 $80.63
 $0.1250
Second Quarter118.89
 96.01
 0.1250
Third Quarter118.81
 97.45
 0.1675
Fourth Quarter103.04
 81.07
 0.1675

 
 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, 2014,3, 2016, there were approximately 1,8002,100 record holders and approximately 270,000339,000 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.


31
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         

 
 
 
 
 
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, 2015 - October 31, 2015 24,430
 $83.69
 — 6,386,200
November 1, 2015 - November 30, 2015 15,850
 $85.14
 — 6,386,200
December 1, 2015 - December 31, 2015 25,847
 $75.06
 — 6,386,200
Total 66,127
 $80.66
    
(1)The 47,47366,127 total shares for the quarter ended December 31, 2013,2015, and the 427,409580,815 total shares for the full year 20132015, consist solely of shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock or restricted stock unit grants or (ii) in payment of the exercise price of employee stock options.  These shares do not count against the 10 million aggregate share repurchase authorization of EOG's Board discussed below.
(2)In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock.  During 2013,2015, EOG did not repurchase any shares under the Board-authorized repurchase program.


3226


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, 20082010 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.
2.Dividends are reinvested.

Comparison of Five-Year Cumulative Total Returns*Returns
EOG, S&P 500 and S&P O&G E&P
(Performance Results Through December 31, 2013)2015)


*Cumulative total return assumes reinvestment of dividends.
 2010 2011 2012 2013 2014 2015
EOG$100.00
 $108.48
 $133.89
 $186.77
 $206.01
 $159.60
S&P 500$100.00
 $102.11
 $118.45
 $156.82
 $178.28
 $180.78
S&P O&G E&P$100.00
 $93.57
 $96.99
 $123.65
 $110.55
 $72.80

27

  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 


33
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 

The following selected consolidated financial information should be read in conjunction with ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and ITEM 8, Financial Statements and Supplementary Data.


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 

Year Ended December 31 2015 2014 2013 2012 2011
           
Statement of Income Data:          
Net Operating Revenues $8,757,428
 $18,035,340
 $14,487,118
 $11,682,636
 $10,126,115
Operating Income (Loss) $(6,686,079) $5,241,823
 $3,675,211
 $1,479,797
 $2,113,309
Net Income (Loss) $(4,524,515) $2,915,487
 $2,197,109
 $570,279
 $1,091,123
Net Income (Loss) Per Share      
  
  
Basic $(8.29) $5.36
 $4.07
 $1.07
 $2.08
Diluted $(8.29) $5.32
 $4.02
 $1.05
 $2.05
Dividends Per Common Share $0.670
 $0.585
 $0.375
 $0.340
 $0.320
Average Number of Common Shares      
  
  
Basic 545,697
 543,443
 540,341
 535,155
 525,470
Diluted 545,697
 548,539
 546,227
 541,524
 532,536

34
At December 31 2015 2014 2013 2012 2011
           
Balance Sheet Data:          
Total Property, Plant and Equipment, Net $24,210,721
 $29,172,644
 $26,148,836
 $23,337,681
 $21,288,824
Total Assets 26,975,244
 34,762,687
 30,574,238
 27,336,578
 24,838,797
Total Debt 6,660,264
 5,909,933
 5,913,221
 6,312,181
 5,009,166
Total Stockholders' Equity 12,943,035
 17,712,582
 15,418,459
 13,284,764
 12,640,904

28


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.China.  EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries.  This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet.  EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves.  Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

Net income for 2013 totaled $2,197EOG realized a net loss of $4,525 million during 2015 as compared to $570net income of $2,915 million for 2012.2014. During 2015, impairments of proved oil and gas properties and other assets totaling $6,326 million, $4,141 million net of tax, were recognized primarily due to the decline in commodity prices. At December 31, 2013,2015, EOG's total estimated net proved reserves were 2,1192,118 million barrels of oil equivalent (MMBoe), an increasea decrease of 308379 MMBoe from December 31, 2012.2014.  During 2013,2015, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increaseddecreased by 257126 million barrels (MMBbl), and net proved natural gas reserves increaseddecreased by 3051,517 billion cubic feet or 51253 MMBoe.

Operations

Several important developments have occurred since January 1, 2013.2015.

United States and Canada.States. 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,During 2015, EOG focused its efforts on developing its existing North American crude oilincreasing drilling and liquids-rich acreage andcompletion efficiencies, testing methods to improve the recovery factor of the oil-in-place and reducing operating costs through efficiency improvements and service cost reductions. These efficiency gains along with realized lower service costs resulted in these plays.  Increasinglower drilling and completion efficienciescosts and improving the recovery factor of oil-in-place are expected to continue to be areas of emphasis in 2014.  In addition,decreased operating expenses. 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 NGLsNGL production accounted for approximately 63%71% of total North AmericanUnited States production during 2013 compared to 53%2015, consistent with 2014. During 2015, drilling occurred primarily in 2012.  This liquids growth primarily reflects increased production from the South Texas Eagle Ford, theDelaware Basin and North Dakota Bakken plays, where EOG has built an inventory of uncompleted wells. In addition, EOG continues to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins or tactical acquisitions and the Permian Basin.  In 2013, EOG's net Eagle Ford production averaged 140.9 thousand barrels per day (MBbld) ofto evaluate certain potential crude oil and condensateliquids-rich natural gas exploration and NGLs as compareddevelopment prospects. In 2015, EOG completed four transactions to 83.5 MBbld in 2012.  Based on current trends, EOG expects its 2014acquire certain proved crude oil properties and condensate and NGLs production to continue to increase bothrelated assets in total and as a percentagethe Delaware Basin. The aggregate purchase price of total company production as compared to 2013.the transactions totaled approximately $400 million. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas, Utah Wyoming and western Canada.Wyoming.

EOG continuesDuring 2015, due to deliver its crudethe decline in commodity prices, proved oil to various marketsand gas properties and related assets 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 flexibilitywere written down to direct its crude oil shipments via rail cartheir fair value resulting in pretax impairment charges of $6,130 million, $3,945 million net of tax. Impairments were related 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 liquefiedlegacy natural gas export terminal, the proposed Pacific Trail Pipelinesassets and approximately 28,500 undeveloped net acres in the Horn River Basin.  The transaction closed in February 2013.


35
marginal liquids plays.

International. Trinidad.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 Sercan Area (formerly known as the EMZ Area,area) have been developed and are producing natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary and crude oil and condensate which is 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 the2015, finishing its SECC Block and Modified U(b) Blocks duringBlock drilling program that was initiated in 2014. In 2016, EOG expects to complete one net well and install infrastructure in the Sercan Area.

Other International. As previously reported, during the fourth quarter of 2014, EOG completed the divestiture of substantially all its assets in Canada (see Note 17 to the Consolidated Financial Statements). At the time of the sales, production from the divested assets totaled approximately 7,050 barrels of crude oil per day, 580 barrels of NGLs per day and 43.5 million cubic feet of natural gas per day. Information related to EOG's remaining Canadian operations is presented in the "Other International" segment.


29


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, modificationsModifications to the nearby third-party owned Douglas platform, began and a crude oil processing module was installed.  The Douglas platformwhich will be used to process Conwy production.  Duringproduction, began in 2013 the three-well Conwy development drilling program was completed with firstand continued throughout 2014 and 2015. First production from the Conwy field is anticipated in late 2014.  In 2013, costs totaling $24.1March 2016. During 2015, EOG recognized a pretax impairment charge of $186 million associated withfor the Central North Sea Columbus natural gasConwy project were written off.  Also in 2013, EOG drilled an unsuccessful exploratory well in the Central North Sea Block 21/12b.  In the first quarteras a result of 2014, EOG drilled an unsuccessful exploratory well in the East Irish Sea Block 110/7b.crude oil price declines.

In July 2008,2015, EOG acquired rights from ConocoPhillipsdrilled four wells and completed three wells, one of which was drilled in a Petroleum Contract covering the Chuan Zhong Block exploration area2014, in the Sichuan Basin, Sichuan Province, China. In October 2008, EOG obtainedThe successful completions extended the rights to shallower zonesShaximiao development in the Chuan Zhong Block and provides additional opportunities in the future.

EOG's activity in Argentina is focused 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 acresVaca Muerta oil shale formation 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 evaluateProvince. Management is currently evaluating options for its drilling results and exploration program in Argentina.investment.

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.

36
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%34% at December 31, 20132015 and 32%25% at December 31, 2012.2014.  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 At December 31, 2015, $400 million aggregate principal amount of its 2.500% Senior Notes due 2016 (the 2016 Notes) and $260 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 2014commercial paper borrowings were classifiedreclassified as long-term debt based upon EOG's abilityintent and intentability to ultimately replace such amountsamount with other long-term debt.

On January 14, 2016, EOG closed its sale of $750 million aggregate principal amount of its 4.15% Senior Notes due 2026 and $250 million aggregate principal amount of its 5.10% Senior Notes due 2036 (collectively, the New Notes). Interest on the New Notes is payable semi-annually in arrears on January 15 and July 15 of each year, beginning July 15, 2016. Proceeds from the issuance of the New Notes totaled approximately $991 million and were used to repay the $400 million aggregate principal amount of the 2016 Notes when such notes came due on February 3, 2014,1, 2016 and for general corporate purposes, including the repayment of outstanding commercial paper borrowings and funding of future capital expenditures.

On July 21, 2015, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (2015 Agreement) with domestic and foreign lenders (Banks). The 2015 Agreement replaced EOG's $2.0 billion senior unsecured revolving credit agreement which was canceled by EOG upon the closing of the 2015 Agreement. The 2015 Agreement has a scheduled maturity date of July 21, 2020, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to certain terms and conditions. The 2015 Agreement commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions.

On June 1, 2015, EOG repaid upon maturity the Floating Rate$500 million aggregate principal amount of its 2.95% Senior Notes due 2015.

On March 17, 2015, EOG closed its sale of $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 and settled$500 million aggregate principal amount of its 3.90% Senior Notes due 2035 (together, the related interest rate swap.Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2015. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes.

During 2013,2015, EOG funded $7.2$5.2 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid at maturity the 6.125% Senior Notes,$500 million aggregate principal amount of long-term debt, paid $199$367 million in dividends to common stockholders and purchased $64$49 million of treasury stock in connection with stock compensation plans, primarily by utilizing net cash provided from its operating activities, net proceeds from the sale of $761the Notes, commercial paper borrowings, net proceeds of $193 million from the sale of certain North American assets $56and $26 million of excess tax benefits from stock compensation and proceeds of $39 million from stock options exercised and employee stock purchase plan activity.compensation.

Total anticipated 20142016 capital expenditures are estimated to range from approximately $8.1$2.4 billion to $8.3$2.6 billion, excluding acquisitions. The majority of 20142016 expenditures will be focused on United States crude oil and, to a lesser extent, liquids-rich natural gas drilling activity.activities. 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 Creditthe 2015 Agreement and equity and debt offerings.

30


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.

37
Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2013,2015, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.

Net Operating Revenues

During 2013,2015, net operating revenues increased $2,804decreased $9,278 million, or 24%51%, to $14,487$8,757 million from $11,683$18,035 million in 2012.2014. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $2,798decreased $6,188 million, or 35%49%, to $10,756$6,404 million in 20132015 from $7,958$12,592 million in 2012.2014. Revenues from the sales of crude oil and condensate and NGLs in 20132015 were approximately 84%83% of total wellhead revenues compared to 80%85% in 2012.2014. During 2013,2015, EOG recognized net lossesgains on the mark-to-market of financial commodity derivative contracts of $166$62 million compared to net gains of $394$834 million in 2012.2014. 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 $547decreased $1,793 million or 18%, during 2013,2015, to $3,644$2,253 million from $3,097$4,046 million in 2012.  Gains2014. Net losses on asset dispositions net, totaled $198 million and $193$9 million in 2013 and 2012, respectively.2015 compared to net gains on asset dispositions of $508 million in 2014.


3831


Wellhead volume and price statistics for the years ended December 31, 2013, 20122015, 2014 and 20112013 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.
Year Ended December 31 2015 2014 2013
       
Crude Oil and Condensate Volumes (MBbld) (1)
      
United States 283.3
 282.0
 212.1
Trinidad 0.9
 1.0
 1.2
Other International (2)
 0.2
 5.9
 7.1
Total 284.4
 288.9
 220.4
Average Crude Oil and Condensate Prices ($/Bbl) (3)
    
  
United States $47.55
 $92.73
 $103.81
Trinidad 39.51
 84.63
 90.30
Other International (2)
 57.32
 86.75
 87.08
Composite 47.53
 92.58
 103.20
Natural Gas Liquids Volumes (MBbld) (1)
      
United States 76.9
 79.7
 64.3
Other International (2)
 0.1
 0.6
 0.9
Total 77.0
 80.3
 65.2
Average Natural Gas Liquids Prices ($/Bbl) (3)
    
  
United States $14.50
 $31.84
 $32.46
Other International (2)
 4.61
 40.73
 39.45
Composite 14.49
 31.91
 32.55
Natural Gas Volumes (MMcfd) (1)
      
United States 886
 920
 908
Trinidad 349
 363
 355
Other International (2)
 30
 70
 84
Total 1,265
 1,353
 1,347
Average Natural Gas Prices ($/Mcf) (3)
    
  
United States $1.97
 $3.93
 $3.32
Trinidad 2.89
 3.65
 3.68
Other International (2)
 5.05
 4.40
 3.39
Composite 2.30
 3.88
 3.42
Crude Oil Equivalent Volumes (MBoed) (4)
      
United States 507.9
 515.0
 427.9
Trinidad 59.1
 61.5
 60.4
Other International (2)
 5.2
 18.2
 21.8
Total 572.2
 594.7
 510.1
       
Total MMBoe (4)
 208.9
 217.1
 186.2
(1)Thousand barrels per day or million cubic feet per day, as applicable.
(2)Other International includes EOG's United Kingdom, China, Canada and Argentina operations.
(3)Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 1112 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 equivalentsequivalent volumes are determined using thea 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.

32

39

20132015 compared to 2012.2014. Wellhead crude oil and condensate revenues in 2013 increased $2,6422015 decreased $4,807 million, or 47%49%, to $8,301$4,935 million from $5,659$9,742 million in 2012,2014, due to an increasea lower composite average wellhead crude oil and condensate price ($4,677 million) and a decrease of 635 MBbld, or 40%2%, in wellhead crude oil and condensate deliveries ($2,205 million) and a higher composite average wellhead crude oil and condensate price ($437131 million). The increasedecrease in deliveries primarily reflects decreased production in the North Dakota Bakken, the Fort Worth Barnett Shale area and Other International, partially offset by increased production in the Permian Basin and Eagle Ford,Ford. The decrease in Other International is due to the North Dakota Bakken andsale of the Permian Basin.Canadian assets. EOG's composite average wellhead crude oil and condensate price for 2013 increased 6%2015 decreased 49% to $103.20$47.53 per barrel compared to $97.77$92.58 per barrel in 2012.2014.

NGLsNGL revenues in 2013 increased $472015 decreased $526 million, or 6%56%, to $774$408 million from $727$934 million in 2012,2014, due to an increase of 9 MBbld, or 17%, in NGLs deliveries ($118 million), partially offset by a lower composite average price ($71490 million) and a decrease of 3 MBbld, or 4%, in NGL deliveries ($36 million). The increase in deliveries primarily reflects increased volumes in the Eagle Ford.  EOG's composite average NGLsNGL price in 20132015 decreased 8%55% to $32.55$14.49 per barrel compared to $35.54$31.91 per barrel in 2012.2014.

Wellhead natural gas revenues in 2013 increased $1092015 decreased $855 million, or 7%45%, to $1,681$1,061 million from $1,572$1,916 million in 2012.  The increase was2014, primarily due to a higherlower composite average wellhead natural gas price ($288730 million), partially offset by decreased and a decrease in wellhead natural gas deliveries ($179125 million). EOG's composite average wellhead natural gas price increased 21%decreased 41% to $3.42$2.30 per Mcf in 20132015 compared to $2.83$3.88 per Mcf in 2012.2014. Natural gas deliveries in 20132015 decreased 1697% to 1,265 MMcfd or 11%, primarilyas compared to 1,353 MMcfd in 2014. The decrease in production was due to decreased production in Other International (40 MMcfd), the United States (126 MMcfd), Trinidad (23(34 MMcfd) and Canada (19Trinidad (14 MMcfd). The decrease inIn the United States, decreased production was attributabledue primarily to asset saleslower production in the Upper Gulf Coast, Fort Worth Barnett Shale and reduced naturalSouth Texas areas, partially offset by increased production of associated gas drilling activity.in the Eagle Ford and Permian Basin. The decreasedecline in Trinidad wasOther International primarily attributable to higher contractual deliveries in 2012.reflects the sale of the Canadian assets.

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 2012,2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $394$62 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $730 million. During 2014, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $711$834 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $34 million.

Gathering, processing and marketing revenues were primarily related toare revenues generated from sales of third-party crude oil, NGLs, and natural gas.gas as well as gathering fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. 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.costs as well as costs associated with EOG-owned sand sold to third parties.

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 $662015 declined $53 million compared to 2012,2014, primarily due primarily to lower margins on crude oil and natural gas marketing activities.activities and losses on sand sales.

20122014 compared to 2011.2013.  Wellhead crude oil and condensate revenues in 20122014 increased $1,821$1,441 million, or 47%17%, to $5,659$9,742 million from $3,838$8,301 million in 2011,2013, due to an increase of 4568.5 MBbld, or 39%31%, in wellhead crude oil and condensate deliveries ($1,5332,558 million) and, partially offset by a higherlower composite average wellhead crude oil and condensate price ($2881,117 million).  The increase in deliveries primarily reflects increased production in the Eagle Ford, and the North Dakota Bakken.Bakken and the Permian Basin.  EOG's composite average wellhead crude oil and condensate price for 2012 increased 5%2014 decreased 10% to $97.77$92.58 per barrel compared to $92.79$103.20 per barrel in 2011.2013.

NGLsNGL revenues in 2012 decreased $522014 increased $160 million, or 7%21%, to $727$934 million from $779$774 million in 2011,2013, due to an increase of 15 MBbld, or 23%, in NGL deliveries ($179 million), partially offset by a lower composite average price ($304 million), partially offset by an increase of 14 MBbld, or 32%, in NGLs deliveries ($25219 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).Basin.  EOG's composite average NGLsNGL price in 20122014 decreased 30%2% to $35.54$31.91 per barrel compared to $50.41$32.55 per barrel in 2011.

40
2013.

Wellhead natural gas revenues in 2012 decreased $6692014 increased $235 million, or 30%14%, to $1,572$1,916 million from $2,241$1,681 million in 2011.  The decrease was2013, primarily due to a lowerhigher 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.price.  EOG's composite average wellhead natural gas price decreased 26%increased 13% to $2.83$3.88 per Mcf in 2012 from $3.832014 compared to $3.42 per Mcf in 2011.2013.  Natural gas deliveries in 2014 increased less than 1% to 1,353 MMcfd as compared to 1,347 MMcfd in 2013. Increased production in the United States (12 MMcfd) and Trinidad (8 MMcfd) was offset by lower production in Canada (15 MMcfd). In the United States, increased production of associated natural gas in the Eagle Ford and Permian Basin areas was partially offset by lower production in the Upper Gulf Coast and Fort Worth Basin Barnett Shale areas.


33


During 2012,2014, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $394$834 million, which included net cash received from settlements of commoditycrude oil and natural gas financial derivative contracts of $711$34 million. During 2011,2013, EOG recognized net gainslosses on the mark-to-market of financial commodity derivative contracts of $626$166 million, which included net cash received from settlements of commoditycrude oil and natural gas financial derivative contracts of $181$116 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 $612014 declined $75 million compared to $44 million in 2011.2013, primarily due to lower margins on crude oil marketing activities.

Operating and Other Expenses

20132015 compared to 20122014.  During 2013,2015, operating expenses of $10,812$15,444 million were $609$2,650 million higher than the $10,203$12,794 million incurred during 2012.2014.Operating expenses for 2015 included impairments of proved properties, other property, plant and equipment and other assets of $6,326 million primarily due to commodity price declines. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 20132015 and 2012:2014:

 
 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 
 2015 2014
    
Lease and Well$5.66
 $6.53
Transportation Costs4.07
 4.48
Depreciation, Depletion and Amortization (DD&A) -   
Oil and Gas Properties15.27
 17.90
Other Property, Plant and Equipment0.59
 0.53
General and Administrative (G&A)1.75
 1.85
Net Interest Expense1.14
 0.93
Total (1)
$28.48
 $32.22
(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 20132015 compared to 20122014 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.

41
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$1,182 million in 2013 increased $1062015 decreased $234 million from $1,000$1,416 million in 20122014 primarily due to higherlower operating and maintenance expensescosts in the United States ($48125 million), lower lease and Canadawell expenses in Other International ($1399 million) primarily due to the sale of the Canadian assets and increasedlower workover expenditures in the United States ($3821 million), partially offset by increased lease and well administrative expenses in the United States ($12 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.


34


Transportation costs of $853$849 million in 2013 increased $2522015 decreased $123 million from $601$972 million in 20122014 primarily due to decreased transportation costs in the Rocky Mountain area ($81 million) and the Eagle Ford ($48 million) primarily due to an increase in the use of pipelines to transport crude oil production, partially offset by increased transportation costs related to higher production from the Eagle FordPermian Basin ($136 million), the Rocky Mountain area ($84 million) and the Fort Worth Basin Barnett Shale area ($2719 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 and 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 yearperiod to year.period.  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 $4312015 decreased $683 million to $3,601$3,314 million from $3,170$3,997 million in 2012.2014.  DD&A expenses associated with oil and gas properties in 20132015 were $473$691 million higherlower than in 20122014 primarily due to increased production in the United States ($347 million) and higherlower unit rates in the United States ($133513 million) and Trinidad ($4428 million), partially offset by a decrease in production in Canadathe United States ($29 million) and Trinidad ($1044 million) and lower unit ratesDD&A expense in CanadaOther International ($12104 million).  DD&A unit primarily due to the sale of the Canadian assets.  Unit rates in the United States decreased primarily due to impairments of proved oil and gas properties (see Note 14 to the Consolidated Financial Statements), upward reserve revisions and reserves added at lower costs as a result of 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).efficiencies.

G&A expenses of $348$367 million in 20132015 were $17$35 million higherlower than 20122014 primarily due primarily to higher costs associated with supporting expanding operations.lower employee-related expenses.

Net interest expense of $235$237 million in 20132015 was $22$36 million higher than 20122014 primarily due primarily to interest expenseincurred on the $1,250 million principal amount of 2.625% Senior Notes due 2023 issued in September 2012March 2015 ($2328 million), as well as a decrease in capitalized interest ($15 million). This was partially offset by athe reduction of interest on debt repaid in interest expense on the 6.125% Senior Notes, which were repaid at maturity in October 2013June 2015 and during 2014 ($6 million).

42
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 ($911 million).

Exploration costs of $161$149 million in 20132015 decreased $25$35 million from $186$184 million in 20122014 primarily due to decreased geological and geophysical expenditures in the United States.States ($19 million) and lower exploration administrative expenses in Other International ($10 million) primarily due to the sale of the Canadian assets.

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$6,614 million in 2013 decreased $9842015 increased $5,870 million from $1,271$744 million in 20122014 primarily due to decreased impairments of proved and unproved properties in Canada ($881 million), decreasedincreased impairments of proved properties and other assets in the United States ($985,959 million), primarily due to commodity price declines; and decreasedincreased amortization of unproved property costs in the United States ($17112 million), which was caused by higher amortization rates being applied to undeveloped leasehold costs in response to the significant decrease in commodity prices and an increase in EOG's estimates of undeveloped properties not expected to be developed before lease expiration; partially offset by decreased impairments of proved properties in the United Kingdom ($156 million) and Argentina ($43 million). Proved property and other asset impairments in the United States were primarily related to legacy natural gas assets and marginal liquids plays. EOG recorded impairments of proved and unproved properties; other property, plant and equipment; and other assets of $172$6,326 million and $1,133$575 million in 20132015 and 2012,2014, 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 $1292015 decreased $336 million to $624$422 million (5.8%(6.6% of wellhead revenues) from $495$758 million (6.2%(6.0% of wellhead revenues) in 2012.2014. The increasedecrease in taxes other than income was primarily due to increaseddecreases in severance/production taxes in the United States ($122307 million), primarily as a result of increaseddecreased wellhead revenues and higherlower ad valorem/property taxes ($17 million), both in the United States ($15 million), partially offset by decreased severance/production taxes in Canada ($9 million).States.


35


Other expense,income, net, was $3$2 million in 20132015 compared to other income,expense, net, of $14$45 million in 2012.2014. The decreaseincrease of $17$47 million was primarily due to a decrease in net foreign currency transaction losses on warehouse stock sales and adjustments.decreased deferred compensation expense.

IncomeEOG recognized an income tax provisionbenefit of $1,240$2,397 million in 2013 increased $530 million from $7102015 compared to an income tax expense of $2,080 million in 20122014 primarily due primarily to higher pretax income.impairments recognized in the United States in 2015. The net effective tax rate for 20132015 decreased to 36%35% from 55%42% in 2012the prior year primarily due primarily to the absenceeffects of certain 2012 Canadian losses (26% statutoryrecording valuation allowances in the United Kingdom and deferred tax rate).

43
in the United States related to undistributed foreign earnings in 2014.

20122014 compared to 20112013.  During 2012,2014, operating expenses of $10,203$12,794 million were $2,190$1,982 million higher than the $8,013$10,812 million incurred in 2011.  during 2013.The following table presents the costs per Boe for the years ended December 31, 20122014 and 2011:2013:
  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&A1.941.98
Net Interest Expense   1.25   1.36 
Total (1)
  $31.12  $28.55 

 2014 2013
    
Lease and Well$6.53
 $5.94
Transportation Costs4.48
 4.58
DD&A -   
Oil and Gas Properties17.90
 18.79
Other Property, Plant and Equipment0.53
 0.55
G&A1.85
 1.87
Net Interest Expense0.93
 1.26
Total (1)
$32.22
 $32.99
(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 and net interest expense for 20122014 compared to 20112013 are set forth below.  See "Net Operating Revenues" above for a discussion of production volumes.

Lease and well expenses of $1,000$1,416 million in 20122014 increased $58$310 million from $942$1,106 million in 20112013 primarily due to higher operating and maintenance expenses in the United Statescosts ($60209 million) and Trinidad, increased workover expenditures ($569 million) and increased lease and well administrative expenses ($32 million), all 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).States.

Transportation costs of $601$972 million in 20122014 increased $171$119 million from $430$853 million in 20112013 primarily due to increased transportation costs related to production from the Eagle Ford ($10199 million) and the Rocky Mountain area ($7315 million).

DD&A expenses in 20122014 increased $654$396 million to $3,170$3,997 million from $2,516$3,601 million in 2011.2013.  DD&A expenses associated with oil and gas properties in 20122014 were $631$384 million higher than in 20112013 primarily due to higher unit rates ($379 million), increased production in the United States ($296 million) and Trinidad ($7630 million), partially offset by lower unit rates in the United States ($191 million) and Canada ($37 million) and a decrease in production in Canada ($5731 million).  DD&AUnit 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 2011decreased primarily due to gatheringupward reserve revisions and processing assets being placed in service in the Eagle Ford.reserves added at lower costs as a result of increased efficiencies.

G&A expenses of $332$402 million in 20122014 were $27$54 million higher than 20112013 primarily due primarily to higher employee-related costs ($22 million)associated with supporting expanding operations.

Net interest expense of $201 million in 2014 was $34 million lower than 2013 primarily due to repayment of the $400 million aggregate principal amount of the 6.125% Senior Notes due 2013, the Subsidiary Debt and higher information systems coststhe Floating Rate Notes ($531 million), as well as an increase in capitalized interest across the company ($8 million). This was partially offset by interest expense on the Notes issued in March 2014 ($10 million).

Gathering and processing costs increased $17$38 million to $98$146 million in 20122014 compared to $81$108 million in 2011.  The increase2013 primarily reflectsdue to increased activities in the Eagle Ford ($21 million), partially offset by decreased costs in the Fort Worth Basin Barnett Shale area ($7 million).Ford.

Exploration costs of $186$184 million in 20122014 increased $14$23 million from $172$161 million for the same prior year periodin 2013 primarily due to increased geological and geophysical expenditures in the United States.

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44

Impairments of $1,271$744 million in 20122014 increased $240$457 million from $1,031$287 million in 20112013 primarily due to increased impairments of proved and unproved properties in Canadathe United Kingdom ($534351 million), the United States ($145 million) and Argentina ($39 million); and increased amortization of unproved property costs in the United States ($54 million); partially offset by decreased impairments of proved properties in Canada ($67 million) and Trinidad ($14 million); and lower impairments of other assets in the United States ($23246 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$575 million and $834$172 million in 20122014 and 2011,2013, respectively. The 20122014 and 20112013 amounts include impairments of $1,022$503 million and $745$7 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 in 20122014 increased $84$134 million to $495 million (6.2% of wellhead revenues) from $411$758 million (6.0% of wellhead revenues) from $624 million (5.8% of wellhead revenues) in 2011.2013.  The increase in taxes other than income was primarily due to increasedincreases in severance/production taxes in the United States ($70112 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 ($34 million) in the United States, ($30 million), partially offset by decreased severance/production taxesan increase in Trinidadcredits available to EOG in 2014 for Texas high-cost gas severance tax rate reductions ($1711 million).

Other income,expense, net, was $14$45 million in 20122014 compared to $7$3 million in 2011.2013. The increase of $7$42 million was primarily due to higher interest income ($8 million) primarily as a result of interest on severance tax refunds, an increase innet 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).losses.

Income tax provision of $710$2,080 million in 2012 decreased $1092014 increased $840 million from $819$1,240 million in 20112013 due primarily to lowerhigher pretax income.  The net effective tax rate for 20122014 increased to 55%42% from 43%36% in 2011.the prior year. The net effective tax rate for 20122014 exceeded the United States statutory tax rate (35%) due primarily to valuation allowances in the United Kingdom and deferred tax in the United States related to EOG's undistributed foreign lossesearnings. EOG no longer asserts that foreign earnings will remain permanently reinvested abroad and therefore recorded deferred tax of $250 million on the accumulated balance of such earnings in Canada (26% statutory tax rate) and Canadian valuation allowances.the fourth quarter of 2014.

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2013,2015, 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, proceeds from asset sales, 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; repayments of debt; dividend payments to stockholders; repayments of debt; and purchases of treasury stock in connection with stock compensation plans.

20132015 compared to 2012.2014.  Net cash provided by operating activities of $3,595 million in 2015 decreased $5,054 million from $8,649 million in 2014 primarily reflecting a decrease in wellhead revenues ($6,188 million), unfavorable changes in working capital and other assets and liabilities ($591 million) and an increase in net cash paid for interest expense ($25 million), partially offset by a decrease in cash operating expenses ($741 million), a favorable change in the net cash received from the settlement of financial commodity derivative contracts ($696 million) and a decrease in net cash paid for income taxes ($302 million).

Net cash used in investing activities of $5,320 million in 2015 decreased by $2,194 million from $7,514 million in 2014 primarily due to a decrease in additions to oil and gas properties ($2,795 million); and a decrease in additions to other property, plant and equipment ($439 million); partially offset by unfavorable changes in working capital associated with investing activities ($603 million); a decrease in proceeds from sales of assets ($377 million) and the release of restricted cash in 2014 ($60 million).

Net cash provided by financing activities of $371 million in 2015 included net proceeds from the issuance of the Notes ($990 million), net commercial paper borrowings ($260 million), excess tax benefits from stock-based compensation ($26 million) and proceeds from stock options exercised and employee stock purchase plan activity ($23 million). Cash used in financing activities in 2015 included repayments of long-term debt ($500 million), cash dividend payments ($367 million) and purchases of treasury stock in connection with stock compensation plans ($49 million). 


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2014 compared to 2013.  Net cash provided by operating activities of $8,649 million in 2014 increased $1,320 million from $7,329 million in 2013 increased $2,092 million from $5,237 million in 2012 primarily reflecting an increase in wellhead revenues ($2,7981,837 million), favorable changes in working capital and other assets and liabilities ($405391 million) and a decrease in net cash paid for income taxesinterest expense ($6538 million), partially offset by an increase in cash operating expenses ($662 million), an unfavorable change in the net cash received from the settlement of financial commodity derivative contracts ($595 million), an increase in cash operating expenses ($47882 million) and an increase in net cash paid for interest expenseincome taxes ($3948 million).

Net cash used in investing activities of $7,514 million in 2014 increased by $1,199 million from $6,315 million in 2013 increased by $196 million from $6,119 million for the same period of 2012primarily due primarily to an increase in additions to oil and gas properties ($823 million); an increase in additions to other property, plant and equipment ($364 million); and a decrease in proceeds from sales of assets ($549 million); and an increase in restricted cash ($66191 million); partially offset by a decrease in additions to other property, plantthe release of restricted cash ($126 million) 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 ($3852 million).

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Net cash used in financing activities of $574$328 million during 20132014 included the repaymentrepayments of long-term debt ($400500 million), cash dividend payments ($199280 million) and, purchases of treasury stock purchases in connection with stock compensation plans ($64127 million) and the settlement of a foreign currency swap ($32 million).  Cash provided by financing activities in 20132014 included net proceeds from the issuances of long-term debt ($496 million), excess tax benefits from stock-based compensation ($5699 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 ($5922 million).

Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2013, 20122015, 2014 and 20112013 (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 

 2015 2014 2013
Expenditure Category     
Capital     
Exploration and Development Drilling$3,289
 $5,543
 $5,070
Facilities765
 1,367
 974
Leasehold Acquisitions (1)
134
 370
 414
Property Acquisitions481
 139
 120
Capitalized Interest42
 57
 49
Subtotal4,711
 7,476
 6,627
Exploration Costs149
 184
 161
Dry Hole Costs15
 49
 75
Exploration and Development Expenditures4,875
 7,709
 6,863
Asset Retirement Costs53
 196
 134
Total Exploration and Development Expenditures4,928
 7,905
 6,997
Other Property, Plant and Equipment288
 727
 364
Total Expenditures$5,216
 $8,632
 $7,361
(1)In 2013 and 2012, leaseholdLeasehold acquisitions included $5 million in both 2014 and $20 million, respectively,2013 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.

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Exploration and development expenditures of $6,863$4,875 million for 20132015 were $78$2,834 million lower than the prior year primarily due primarily to decreased drillingexploration and facilitiesdevelopment drilling expenditures in the United States ($137 million), Canada ($1282,189 million) and ArgentinaOther International ($3274 million); decreased facilities expenditures ($553 million), decreased leasehold acquisition expenditures in the United Statesacquisitions ($60232 million) and Canada ($31 million); and, decreased exploration geological and geophysical expenditures ($19 million), and decreased capitalized interest ($11 million), all in the United States ($27 million).States.  These decreases were partially offset by increased property acquisitions ($342 million) in the United States ($119 million)States.  The 2015 exploration and increaseddevelopment expenditures of $4,875 million included $4,007 million in development drilling and facilities, $481 million in property acquisitions, $345 million in exploration and $42 million in capitalized interest. The 2014 exploration and development expenditures of $7,709 million included $6,804 million in Trinidad ($85 million), the United Kingdom ($64 million)development drilling and China ($14 million).facilities, $709 million in exploration, $139 million in property acquisitions and $57 million in capitalized interest. The 2013 exploration and development expenditures of $6,863 million included $5,952 million in development drilling and facilities, $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.


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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

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.  See Note 11 to Consolidated Financial Statements.

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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.

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Presented below is a comprehensive summary of EOG's natural gas derivative contracts at February 24, 2014,25, 2016, 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 $4.51 per MMBtu for each month during the period January 1, 2015 through December 31, 2015.
Natural Gas Derivative Contracts
   Weighted
 Volume Average Price
 (MMBtud) ($/MMBtu)
2016   
March 1, 2016 through August 31, 201660,000
 $2.49

Financing

EOG's debt-to-total capitalization ratio was 28%34% at December 31, 2013,2015, compared to 32%25% at December 31, 2012.2014.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

During 2013, theAt December 31, 2015 and 2014, respectively, EOG had outstanding $6,390 million and $5,890 million aggregate 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.  Thesenior notes which had estimated fair valuevalues of EOG's debt at December 31, 2013 and 2012 was $6,222$6,524 million and $7,032$6,242 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,senior notes, such changes do not expose EOG to material fluctuations in earnings or cash flow.

During 2013,2015, EOG funded its capital programsprogram primarily by utilizing cash provided by operating activities, proceeds from asset sales andthe issuance of the Notes, cash provided by borrowings from its commercial paper program.program and proceeds from asset sales.  While EOG maintains a $2.0 billion commercial paper program, the maximum outstanding at any time during 20132015 was $570$641 million, and the amount outstanding at year-end was zero.$260 million.  There were no amounts outstanding under uncommitted credit facilities during 2015. The average borrowings outstanding under the commercial paper program was $37and the uncommitted credit facilities were $81 million and zero, respectively, during the year 2013.2015.  EOG considers this excess availability, which is backed by its $2.0 billion senior unsecured Revolving Credit2015 Agreement (Credit Agreement) described in Note 2 to Consolidated Financial Statements, to be amplesufficient to meet its ongoing operating needs.


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Contractual Obligations

The following table summarizes EOG's contractual obligations at December 31, 2013,2015, (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 

Contractual Obligations (1)
 Total 2016 2017 - 2018 2019 - 2020 2021 & Beyond
           
Current and Long-Term Debt $6,390,000
 $400,000
 $950,000
 $1,900,000
 $3,140,000
Capital Lease 45,064
 6,579
 13,318
 14,172
 10,995
Non-Cancelable Operating Leases 421,189
 104,459
 113,953
 74,842
 127,935
Interest Payments on Long-Term Debt and Capital Lease 1,545,348
 258,575
 471,314
 294,335
 521,124
Transportation and Storage Service Commitments (2)
 4,070,003
 936,118
 1,482,446
 882,849
 768,590
Drilling Rig Commitments (3)
 144,540
 85,933
 57,107
 —
 1,500
Seismic Purchase Obligations 2,216
 2,216
 —
 —
 —
Fracturing Services Obligations 201,501
 105,957
 88,287
 5,412
 1,845
Other Purchase Obligations 91,309
 40,967
 33,834
 15,417
 1,091
Total Contractual Obligations $12,911,170
 $1,940,804
 $3,210,259
 $3,187,027
 $4,573,080
(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, 7 and 14,15, 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, 2013.2015.  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 2013,2015, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Canada, Trinidad, the United Kingdom, China, Canada and Argentina.  The foreign currency most significant to EOG's operations during 20132015 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.British pound.  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.


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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, worldwide supplies of, and demand for, crude oil and condensate, NGL and natural gas, 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 20142016 will impact the amount of cash generated from operating activities, which will in turn impact EOG's financial position. As of February 12, 2016, the average 2016 U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $34.97 per barrel and $2.23 per MMBtu, respectively, representing declines of 28% and 17%, respectively, from the average NYMEX prices in 2015. See ITEM 1A.1A, Risk Factors.

Including the impact of EOG's 2014 crude oil derivative contracts (exclusive of options) and basedBased on EOG's tax position, EOG's price sensitivity in 20142016 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLsNGL price, is approximately $44$65 million for net income and $65$81 million for cash flows from operating activities.  Including the impact of EOG's 20142016 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 20142016 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$15 million for net income and $19$18 million for cash flows from operating activities.  For information regarding EOG's crude oil and natural gas financial commodity derivative contracts at February 24, 2014,25, 2016, 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, Delaware Basin and Bakken and Three Forks and Permian Basin plays and, to a lesser extent, liquids-rich natural gas drilling.  In order to diversifywhere it generates its overall asset portfolio,highest rates-of-return. To further enhance the economics of these plays, 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.improve well performance and lower drilling and completion costs through efficiency gains and lower service costs.

The total anticipated 20142016 capital expenditures of $8.1approximately $2.4 billion to $8.3$2.6 billion, excluding acquisitions, is structured to maintain the flexibility necessary under EOG's strategy of capital discipline by funding its exploration, developmentand exploitation and acquisition activities primarily from available internally generated cash flowflows, net proceeds from the New Notes and the sale of certain non-core assets.cash on hand. 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 Credit2015 Agreement and equity and debt offerings.

Operations. In 2016, both total production and total crude oil production are expected to decline slightly from 2015 levels. In 2016, EOG expects to increase overall production in 2014 byapprozimately 11.5% over 2013 levels.  Total liquids production is expectedcontinue to increase by 24%, comprised of an increase in crude oilfocus on reducing operating costs through efficiency improvements and condensate and NGLs production of 27% and 12%, respectively.  North American natural gas production is expected to decrease by 6% from 2013 levels.lower service costs.



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41


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.amortization and impairments of proved properties and related assets.  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.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.

52
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.

AmortizationDepreciation, depletion and 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.

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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 ended December 31, 2015, West Texas Intermediate crude oil spot prices have fluctuated from approximately $39.26$34.55 per barrel to $110.04$113.39 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $2.03$1.63 per MMBtu to $5.96$8.15 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.

53
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.


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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, reduce or otherwise control operating and capital costs, 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,the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
·the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
·the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and optimizethe extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize 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 and condensate, natural gas liquids, 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'sthe 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;
54competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, 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;

44


political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;
·the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
the use of competing energy sources and the development of alternative energy sources;
·competition in the oil and gas exploration and production industry for employees and other personnel, facilities, equipment, materials and services;
the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
·the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;
acts of war and terrorism and responses to these acts;
·the accuracy of reserve estimates, which by their nature involve the exercise of professional judgmentphysical, electronic and cyber security breaches; 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 26the other factors described under ITEM 1A, Risk Factors, on pages 13 through 21 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 duration and 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.


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ITEM 9.  Changes in andDisagreements 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, 2013.2015. 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, 2013.2015.

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, 2013.2015. 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)(2013). 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, 2013.2015. See also "Management's Responsibility for Financial Reporting" appearing on page F-2 of this report, which is incorporated herein by reference.


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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, 2013,2015, that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.


ITEM 9B.  Other Information

None.

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PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

The information required by this Item is incorporated by reference from (i) EOG's Definitive Proxy Statement with respect to its 20142016 Annual Meeting of Stockholders to be filed not later than April 30, 201429, 2016 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 20142016 Annual Meeting of Stockholders to be filed not later than April 30, 2014.29, 2016. 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.

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

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 20142016 Annual Meeting of Stockholders to be filed not later than April 30, 2014.29, 2016.

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 to stockholders of record as of March 17, 2014, and paid on March 31, 2014) and corresponding adjustments to EOG's equity compensation plans. All share amounts set forth below have been restated to reflect the two-for-one stock split and such adjustments.


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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 6.913.8 million shares, to an aggregate maximum of 12.925.8 million shares plus shares underlying forfeited or cancelledcanceled grants under the prior stock plans referenced below.in the 2008 Plan document.  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 15,500,00031.0 million 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).Board.

At the 2010 Annual Meeting, an amendment to the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP) was approved to increase the shares available for grant by 1.02.0 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 havehas 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-EmployeeNonemployee 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 270,000540,000 shares of EOG common stock have been authorized by the Board and registered for issuance under the Deferral Plan.  As of December 31, 2013, 138,6802015, 269,508 phantom shares had been issued.

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   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, 2013.2015.
 
 
 
 
 
 
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   

 
 
 
 
 
 
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 10,743,819
(1) 
$67.98
 25,247,925
(2) 
Equity Compensation Plans Not Approved by EOG Stockholders 241,789
(3) 
N/A
 270,492
(4) 
Total 10,985,608
 $67.98
 25,518,417
 
(1)Does not include 1,622,1541,626,436 outstanding restricted stock units and 113,943371,496 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) 16,571,35924,679,703 shares remaining available for issuance under the 2008 Plan and (ii) 497,648568,222 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 16,571,35924,679,703 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 16,571,35924,679,703 (i.e., if all shares remaining available for issuance under the 2008 Plan are issued as SAR and stock optionsoption awards) and (ii) the maximum number of shares we could issue as full value awards is 6,763,82010,073,348 (i.e., if all shares remaining available for issuance under the 2008 Plan are issued as full value awards).
(3)Includes 104,759Consists of shares of EOG common stock to be issued in accordance with the Deferral Plan and participant deferral elections (i.e., in respect of the 104,759241,789 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2013)2015).  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

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 20142016 Annual Meeting of Stockholders to be filed not later than April 30, 2014.29, 2016.

ITEM 14.  Principal Accounting Fees and Services

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 20142016 Annual Meeting of Stockholders to be filed not later than April 30, 2014.29, 2016.


PART IVStock-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.


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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, reduce or otherwise control operating and capital costs, 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, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize 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 and condensate, natural gas liquids, 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 the acquisition of licenses, leases and properties, 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;

44


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 15.  1A, Risk Factors, on pages 13 through 21 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 duration and 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.

Exhibits, Financial Statement SchedulesITEM 7A.  Quantitative and Qualitative Disclosures About Market Risk

(a)(1)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 (a)(2) "Outlook" in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity."

ITEM 8.  Financial Statements and Financial Statement ScheduleSupplementary Data

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

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

None.

ITEM 9A.  Controls and Procedures

(a)(3), (b)Disclosure Controls and Procedures. ExhibitsEOG'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, 2015. 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, 2015.

See pages E-1 through E-8 for a listing of the exhibits.
59
EOG RESOURCES, INC.
INDEX TO FINANCIAL STATEMENTS

Page
Consolidated Financial Statements:
Management's Responsibility for Financial ReportingF-2
Management's Annual Report of Independent Registered Public Accounting FirmF-3
Consolidated Statements of Income and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2013F-5
Consolidated Balance Sheets - December 31, 2013 and 2012F-6
Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2013F-7
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2013F-8
Notes to Consolidated Financial StatementsF-9
Supplemental Information to Consolidated Financial StatementsF-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.

Internal Control over Financial Reporting. EOG's management is also responsible for establishing and maintaining adequate internal control over financial reporting.  Thereporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Even an effective system of internal control of EOG is designed to provide reasonable assurance regarding the reliability ofover 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, 2013.2015. In making this assessment, EOGit used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (1992)(2013). These criteria cover the control environment, risk assessment process, control activities, information and communication systems, and monitoring activities.  Based on this assessment and thosesuch criteria, EOG's 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 andVice 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")effective as of December 31, 2013 and 2012, and2015. See also "Management's Responsibility for Financial Reporting" appearing on page F-2 of this report, which is incorporated herein by reference.


45


The report of EOG's independent registered public accounting firm relating to 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 includedis set forth on page F-3 of this report.

There were no changes 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'sEOG's internal control over financial reporting based on our audits.

We conducted our audits in accordance withthat occurred during the standards of the Public Company Accounting Oversight Board (United States). Those standards requirequarter ended December 31, 2015, that we plan and perform the audithave materially affected, or are reasonably likely to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effectivematerially affect, EOG's internal control over financial reporting was maintained in all material respects. Our auditsreporting.


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 2016 Annual Meeting of Stockholders to be filed not later than April 29, 2016 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 statements included examining, onofficer and principal accounting officer. EOG has also adopted a test basis, evidence supportingCode 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 amountsCode of Conduct 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 auditCode 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 basedEthics on the assessed risk. Our audits also included performing such other procedures as we considered necessary inCorporate 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 circumstances. We believe that our audits provideCode of Conduct and Code of Ethics by submitting a reasonable basis for our opinions.written request to EOG's Corporate Secretary.

A company's internal control over financial reporting is a process designed by,EOG intends to disclose any amendments to the Code of Conduct or underCode of Ethics, and any waivers with respect to the supervisionCode of the company'sConduct or Code of Ethics granted to EOG's principal executive andofficer, principal financial officers,officer, principal accounting officer, any of our controllers or personsany of our other employees performing similar functions, and effected byon its website at www.eogresources.com within four business days of the company's board of directors, management, and other personnel to provide reasonable assuranceamendment or waiver. In such case, the disclosure regarding the reliabilityamendment 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 financial reporting and the preparationConduct or Code 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.Ethics.

ITEM 11.  Executive Compensation

BecauseThe information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2016 Annual Meeting of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements dueStockholders to error or fraud maybe filed not later than April 29, 2016. The Compensation Committee Report and related information incorporated by reference herein shall not be preventeddeemed "soliciting material" 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 compliancebe "filed" 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 Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of America. Also, in our opinion,1933, as amended, or Securities Exchange Act of 1934, as amended, except to 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) issuedextent that EOG specifically incorporates such information by the Committee of Sponsoring Organizations of the Treadway Commission.reference into such a filing.

/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 partITEM 12.  Security Ownership 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 domesticCertain Beneficial Owners 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 accountsManagement and transactions have been eliminated.Related Stockholder Matters

The preparationinformation required by this Item with respect to security ownership of financial statements in conformitycertain beneficial owners and management is incorporated by reference from EOG's Definitive Proxy Statement with accounting principles generally accepted in the United Statesrespect to its 2016 Annual Meeting of America (U.S. GAAP) requires managementStockholders 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.be filed not later than April 29, 2016.

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

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

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

Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term.  If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties.  Lease rentals are expensed as incurred.

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

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

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

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.

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.  If applicable, EOG utilizes accepted bids as the basis for determining fair value.

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

Arrangements for 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 of Directors (Board) approved a two-for-one stock split in the form of a stock dividend payable on March 31, 2014,(payable to stockholders of record as of March 17, 2014.  Also2014, and paid on February 24, 2014,March 31, 2014) and corresponding adjustments to EOG's equity compensation plans. All share amounts set forth below have been restated to reflect the two-for-one stock split and such adjustments.


46


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 13.8 million shares, to an aggregate maximum of 25.8 million shares plus shares underlying forfeited or canceled grants under the prior stock plans referenced in the 2008 Plan document.  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 31.0 million 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.

At the 2010 Annual Meeting, an amendment to the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP) was approved to increase the shares available for grant by 2.0 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 1993 Nonemployee Directors Stock Option Plan has also been approved by EOG's stockholders.  Upon the effective date of the 2008 Plan, no further grants were made under the 1993 Nonemployee Directors Stock Option Plan.  Plans that have not been approved by EOG's stockholders are described below.

Stock Plans Not Approved by EOG Stockholders.  In December 2008, the Board increasedapproved the quarterlyamendment 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 dividendbonus, 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 by 33% to $0.125 per share post-split ($0.25 per share pre-split), effective beginningin accordance with the dividend to be paid on April 30, 2014, to stockholdersDeferral Plan and the individual's deferral election.  A total of record as540,000 shares of April 16, 2014.

F-13
The following summarizes Common Stock activityEOG common stock have been authorized by the Board and registered for each ofissuance under 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.Deferral Plan.  As of December 31, 2013, there were no2015, 269,508 phantom shares of preferred stock outstanding.had been issued.

4.  Other Income, Net

47


Other income, net,The following table sets forth data for 2013 included net foreign currency transaction gains ($12 million),EOG's equity income from investmentscompensation plans aggregated by the various plans approved by EOG's stockholders and those plans not approved by EOG's stockholders, 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 Rate35.00%
 
35.00%
 
35.00%
State Income Tax, Net of Federal Benefit0.93   
 
1.18    
 
1.41    
Income Tax Provision Related to Foreign Operations(0.20)  
 
1.38    
 
0.88    
Income Tax Provision  Related to Trinidad Operations0.43   
 
(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 Rate36.07%
 
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,each case as of December 31, 20132015.
 
 
 
 
 
 
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 10,743,819
(1) 
$67.98
 25,247,925
(2) 
Equity Compensation Plans Not Approved by EOG Stockholders 241,789
(3) 
N/A
 270,492
(4) 
Total 10,985,608
 $67.98
 25,518,417
 
(1)Does not include 1,626,436 outstanding restricted stock units and 371,496 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) 24,679,703 shares remaining available for issuance under the 2008 Plan and (ii) 568,222 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 24,679,703 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 24,679,703 (i.e., if all shares remaining available for issuance under the 2008 Plan are issued as SAR and stock option awards) and (ii) the maximum number of shares we could issue as full value awards is 10,073,348 (i.e., if all shares remaining available for issuance under the 2008 Plan are issued as full value awards).
(3)Consists of shares of EOG common stock to be issued in accordance with the Deferral Plan and participant deferral elections (i.e., in respect of the 241,789 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2015).
(4)Represents phantom shares that remain available for issuance under the Deferral Plan.

ITEM 13.  Certain Relationships and 2012, cumulative valuation allowances of $183 millionRelated Transactions, 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.Director Independence

The abilityinformation required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2016 Annual Meeting of EOGStockholders 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 doesbe filed not believe that an ownership change has occurred which would limit either carryforward.later than April 29, 2016.

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.ITEM 14.  Principal Accounting Fees and Services

The American Taxpayer Relief Actinformation required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2016 Annual Meeting 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.Stockholders to be filed not later than April 29, 2016.

F-17
6.  Employee Benefit Plans

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.


43


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, reduce or otherwise control operating and capital costs, 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, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize 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 and condensate, natural gas liquids, 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 the acquisition of licenses, leases and properties, 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;

44


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 13 through 21 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 duration and 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 andDisagreements 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, 2015. 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, 2015.

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, 2015. 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 (2013). 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, 2015. See also "Management's Responsibility for Financial Reporting" appearing on page F-2 of this report, which is incorporated herein by reference.


45


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 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, 2015, 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 2016 Annual Meeting of Stockholders to be filed not later than April 29, 2016 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 2016 Annual Meeting of Stockholders to be filed not later than April 29, 2016. The Compensation Committee Report and related information incorporated by reference herein shall not be deemed "soliciting material" or to be "filed" with the United States Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that EOG specifically incorporates such information by reference into such a filing.

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

The information required by this Item with respect to security ownership of certain beneficial owners and management is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2016 Annual Meeting of Stockholders to be filed not later than April 29, 2016.

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 to stockholders of record as of March 17, 2014, and paid on March 31, 2014) and corresponding adjustments to EOG's equity compensation plans. All share amounts set forth below have been restated to reflect the two-for-one stock split and such adjustments.


46


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 13.8 million shares, to an aggregate maximum of 25.8 million shares plus shares underlying forfeited or canceled grants under the prior stock plans referenced in the 2008 Plan document.  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 31.0 million 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.

At the 2010 Annual Meeting, an amendment to the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP) was approved to increase the shares available for grant by 2.0 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 1993 Nonemployee Directors Stock Option Plan has also been approved by EOG's stockholders.  Upon the effective date of the 2008 Plan, no further grants were made under the 1993 Nonemployee Directors Stock Option Plan.  Plans that have not been approved by EOG's stockholders are described below.

Stock Plans Not Approved by EOG Stockholders.  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 540,000 shares of EOG common stock have been authorized by the Board and registered for issuance under the Deferral Plan.  As of December 31, 2015, 269,508 phantom shares had been issued.


47


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, 2015.
 
 
 
 
 
 
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 10,743,819
(1) 
$67.98
 25,247,925
(2) 
Equity Compensation Plans Not Approved by EOG Stockholders 241,789
(3) 
N/A
 270,492
(4) 
Total 10,985,608
 $67.98
 25,518,417
 
(1)Does not include 1,626,436 outstanding restricted stock units and 371,496 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) 24,679,703 shares remaining available for issuance under the 2008 Plan and (ii) 568,222 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 24,679,703 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 24,679,703 (i.e., if all shares remaining available for issuance under the 2008 Plan are issued as SAR and stock option awards) and (ii) the maximum number of shares we could issue as full value awards is 10,073,348 (i.e., if all shares remaining available for issuance under the 2008 Plan are issued as full value awards).
(3)Consists of shares of EOG common stock to be issued in accordance with the Deferral Plan and participant deferral elections (i.e., in respect of the 241,789 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2015).
(4)Represents phantom shares that remain available for issuance under the Deferral Plan.

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

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2016 Annual Meeting of Stockholders to be filed not later than April 29, 2016.

ITEM 14.  Principal Accounting Fees and Services

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2016 Annual Meeting of Stockholders to be filed not later than April 29, 2016.


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-6 for a listing of the exhibits.


48


EOG RESOURCES, INC.
INDEX TO FINANCIAL STATEMENTS

Page
Consolidated Financial Statements:
Management's Responsibility for Financial ReportingF-2
Report of Independent Registered Public Accounting FirmF-3
Consolidated Statements of Income and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2015F-4
Consolidated Balance Sheets - December 31, 2015 and 2014F-5
Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2015F-6
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2015F-7
Notes to Consolidated Financial StatementsF-8 
Supplemental Information to Consolidated Financial StatementsF-29

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 as well as designing and implementing programs and controls to prevent and detect fraud.  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, 2015.  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 (2013).  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, 2015.

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 appears on page F-3.

WILLIAM R. THOMASTIMOTHY K. DRIGGERS
Chairman of the Board andVice President and Chief
Chief Executive OfficerFinancial Officer
Houston, Texas
February 25, 2016

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, 2015 and 2014, 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, 2015. We also have audited the Company's internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) 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.
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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2016

F-3


EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In Thousands, Except Per Share Data)


Year Ended December 312015 2014 2013
Net Operating Revenues     
Crude Oil and Condensate$4,934,562
 $9,742,480
 $8,300,647
Natural Gas Liquids407,658
 934,051
 773,970
Natural Gas1,061,038
 1,916,386
 1,681,029
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts61,924
 834,273
 (166,349)
Gathering, Processing and Marketing2,253,135
 4,046,316
 3,643,749
Gains (Losses) on Asset Dispositions, Net(8,798) 507,590
 197,565
Other, Net47,909
 54,244
 56,507
Total8,757,428
 18,035,340
 14,487,118
Operating Expenses 
  
  
Lease and Well1,182,282
 1,416,413
 1,105,978
Transportation Costs849,319
 972,176
 853,044
Gathering and Processing Costs146,156
 145,800
 107,871
Exploration Costs149,494
 184,388
 161,346
Dry Hole Costs14,746
 48,490
 74,655
Impairments6,613,546
 743,575
 286,941
Marketing Costs2,385,982
 4,126,060
 3,648,840
Depreciation, Depletion and Amortization3,313,644
 3,997,041
 3,600,976
General and Administrative366,594
 402,010
 348,312
Taxes Other Than Income421,744
 757,564
 623,944
Total15,443,507
 12,793,517
 10,811,907
Operating Income (Loss)(6,686,079) 5,241,823
 3,675,211
Other Income (Expense), Net1,916
 (45,050) (2,865)
Income (Loss) Before Interest Expense and Income Taxes(6,684,163) 5,196,773
 3,672,346
Interest Expense 
  
  
Incurred279,234
 258,628
 284,599
Capitalized(41,841) (57,170) (49,139)
Net Interest Expense237,393
 201,458
 235,460
Income (Loss) Before Income Taxes(6,921,556) 4,995,315
 3,436,886
Income Tax Provision (Benefit)(2,397,041) 2,079,828
 1,239,777
Net Income (Loss)$(4,524,515) $2,915,487
 $2,197,109
Net Income (Loss) Per Share 
  
  
Basic$(8.29) $5.36
 $4.07
Diluted$(8.29) $5.32
 $4.02
Dividends Declared per Common Share$0.670
 $0.585
 $0.375
Average Number of Common Shares 
  
  
Basic545,697
 543,443
 540,341
Diluted545,697
 548,539
 546,227
Comprehensive Income (Loss) 
  
  
Net Income (Loss)$(4,524,515) $2,915,487
 $2,197,109
Other Comprehensive Income (Loss) 
  
  
Foreign Currency Translation Adjustments(11,517) (437,728) (29,395)
Other, Net of Tax1,235
 (1,162) 5,334
Other Comprehensive Loss(10,282) (438,890) (24,061)
Comprehensive Income (Loss)$(4,534,797) $2,476,597
 $2,173,048


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

F-4


EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
At December 312015 2014
ASSETS
Current Assets   
Cash and Cash Equivalents$718,506
 $2,087,213
Accounts Receivable, Net930,610
 1,779,311
Inventories598,935
 706,597
Assets from Price Risk Management Activities—
 465,128
Income Taxes Receivable40,704
 71,621
Deferred Income Taxes147,812
 19,618
Other155,677
 286,533
Total2,592,244
 5,416,021
Property, Plant and Equipment 
  
Oil and Gas Properties (Successful Efforts Method)50,613,241
 46,503,532
Other Property, Plant and Equipment3,986,610
 3,750,958
Total Property, Plant and Equipment54,599,851
 50,254,490
Less: Accumulated Depreciation, Depletion and Amortization(30,389,130) (21,081,846)
Total Property, Plant and Equipment, Net24,210,721
 29,172,644
Other Assets172,279
 174,022
Total Assets$26,975,244
 $34,762,687
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities 
  
Accounts Payable$1,471,953
 $2,860,548
Accrued Taxes Payable93,618
 140,098
Dividends Payable91,546
 91,594
Deferred Income Taxes—
 110,743
Current Portion of Long-Term Debt6,579
 6,579
Other155,591
 174,746
Total1,819,287
 3,384,308
Long-Term Debt6,653,685
 5,903,354
Other Liabilities971,335
 939,497
Deferred Income Taxes4,587,902
 6,822,946
Commitments and Contingencies (Note 8)

 

Stockholders' Equity 
  
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 550,150,823 Shares and 549,028,374 Shares Issued at December 31, 2015 and 2014, respectively205,502
 205,492
Additional Paid in Capital2,923,461
 2,837,150
Accumulated Other Comprehensive Loss(33,338) (23,056)
Retained Earnings9,870,816
 14,763,098
Common Stock Held in Treasury, 292,179 Shares and 733,517 Shares at December 31, 2015 and 2014, respectively(23,406) (70,102)
Total Stockholders' Equity12,943,035
 17,712,582
Total Liabilities and Stockholders' Equity$26,975,244
 $34,762,687

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

F-5


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, 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 Plans6
 38,723
 —
 —
 —
 38,729
Common Stock Dividends Declared, $0.38 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, Net6
 (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, 2013202,732
 2,646,879
 415,834
 12,168,277
 (15,263) 15,418,459
Net Income—
 —
 —
 2,915,487
 —
 2,915,487
Common Stock Issued Under Stock Plans8
 22,252
 —
 —
 —
 22,260
Common Stock Dividends Declared, $0.59 Per Share—
 —
 —
 (320,666) —
 (320,666)
Other Comprehensive Loss—
 —
 (438,890) —
 —
 (438,890)
Change in Treasury Stock - Stock Compensation Plans, Net—
 (30,470) —
 —
 (96,962) (127,432)
Excess Tax Benefit from Stock-Based Compensation—
 99,459
 —
 —
 —
 99,459
Restricted Stock and Restricted Stock Units, Net18
 (43,109) —
 —
 43,091
 —
Stock-Based Compensation Expenses—
 144,842
 —
 —
 —
 144,842
Common Stock Issued - Stock Split2,734
 (2,734) —
 —
 —
 —
Treasury Stock Issued as Compensation—
 31
 —
 —
 (968) (937)
Balance at December 31, 2014205,492
 2,837,150
 (23,056) 14,763,098
 (70,102) 17,712,582
Net Income—
 —
 —
 (4,524,515) —
 (4,524,515)
Common Stock Issued Under Stock Plans5
 15,366
 —
 —
 —
 15,371
Common Stock Dividends Declared, $0.67 Per Share—
 —
 —
 (367,767) —
 (367,767)
Other Comprehensive Loss—
 —
 (10,282) —
 —
 (10,282)
Change in Treasury Stock - Stock Compensation Plans, Net—
 (41,342) —
 —
 (129) (41,471)
Excess Tax Benefit from Stock-Based Compensation—
 26,058
 —
 —
 —
 26,058
Restricted Stock and Restricted Stock Units, Net5
 (44,339) —
 —
 44,334
 —
Stock-Based Compensation Expenses—
 130,577
 —
 —
 —
 130,577
Treasury Stock Issued as Compensation—
 (9) —
 —
 2,491
 2,482
Balance at December 31, 2015$205,502
 $2,923,461
 $(33,338) $9,870,816
 $(23,406) $12,943,035

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

F-6


EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
Year Ended December 312015 2014 2013
Cash Flows from Operating Activities     
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:     
Net Income (Loss)$(4,524,515) $2,915,487
 $2,197,109
Items Not Requiring (Providing) Cash 
  
  
Depreciation, Depletion and Amortization3,313,644
 3,997,041
 3,600,976
Impairments6,613,546
 743,575
 286,941
Stock-Based Compensation Expenses130,577
 145,086
 134,055
Deferred Income Taxes(2,482,307) 1,704,946
 874,765
(Gains) Losses on Asset Dispositions, Net8,798
 (507,590) (197,565)
Other, Net11,896
 48,138
 11,072
Dry Hole Costs14,746
 48,490
 74,655
Mark-to-Market Commodity Derivative Contracts 
  
  
Total (Gains) Losses(61,924) (834,273) 166,349
Net Cash Received from Settlements of Commodity Derivative Contracts730,114
 34,007
 116,361
Excess Tax Benefits from Stock-Based Compensation(26,058) (99,459) (55,831)
Other, Net12,532
 13,009
 18,205
Changes in Components of Working Capital and Other Assets and Liabilities 
  
  
Accounts Receivable641,412
 84,982
 (23,613)
Inventories58,450
 (161,958) 53,402
Accounts Payable(1,409,197) 543,630
 178,701
Accrued Taxes Payable11,798
 16,486
 75,142
Other Assets118,143
 (14,448) (109,567)
Other Liabilities(66,257) 75,420
 (20,382)
Changes in Components of Working Capital Associated with Investing and Financing Activities499,767
 (103,414) (51,361)
Net Cash Provided by Operating Activities3,595,165
 8,649,155
 7,329,414
Investing Cash Flows 
  
  
Additions to Oil and Gas Properties(4,725,150) (7,519,667) (6,697,091)
Additions to Other Property, Plant and Equipment(288,013) (727,138) (363,536)
Proceeds from Sales of Assets192,807
 569,332
 760,557
Changes in Restricted Cash—
 60,385
 (65,814)
Changes in Components of Working Capital Associated with Investing Activities(499,900) 103,523
 51,106
Net Cash Used in Investing Activities(5,320,256) (7,513,565) (6,314,778)
Financing Cash Flows 
  
  
Net Commercial Paper Borrowings259,718
 —
 —
Long-Term Debt Borrowings990,225
 496,220
 —
Long-Term Debt Repayments(500,000) (500,000) (400,000)
Settlement of Foreign Currency Swap—
 (31,573) —
Dividends Paid(367,005) (279,695) (199,178)
Excess Tax Benefits from Stock-Based Compensation26,058
 99,459
 55,831
Treasury Stock Purchased(48,791) (127,424) (63,784)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan22,690
 22,249
 38,730
Debt Issuance Costs(5,951) (895) —
Repayment of Capital Lease Obligation(6,156) (5,966) (5,780)
Other, Net133
 (109) 255
Net Cash Provided by (Used in) Financing Activities370,921
 (327,734) (573,926)
Effect of Exchange Rate Changes on Cash(14,537) (38,852) 1,064
Increase (Decrease) in Cash and Cash Equivalents(1,368,707) 769,004
 441,774
Cash and Cash Equivalents at Beginning of Year2,087,213
 1,318,209
 876,435
Cash and Cash Equivalents at End of Year$718,506
 $2,087,213
 $1,318,209
The accompanying notes are an integral part of these consolidated financial statements.

F-7


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.  The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Notes 2 and 12).

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

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

Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term.  If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties.  Lease rentals are expensed as incurred.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed 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 16).  Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

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

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

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


F-8


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.  If applicable, EOG utilizes accepted bids as the basis for determining fair value.

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

Arrangements for 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 these products are sold to purchasers who 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 and revenues from sales of EOG-owned sand.

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, 2015, 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 of settled contracts is reflected as cash flows from operating activities.  EOG was party to a foreign currency swap transaction and an interest rate swap transaction, both of which were accounted for using the hedge accounting method.  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 12.

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 6).

Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for 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 Loss 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. See Notes 4 and 17.

Net Income (Loss) Per Share. Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period.  Diluted net income (loss) 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 9).

F-9


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 7).

Recently Issued Accounting Standards. In November 2015, the FASB issued Accounting Standards Update (ASU) 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes " (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. ASU 2015-17 is effective for financial statements issued for interim and annual periods beginning after December 15, 2016, and early adoption is permitted. EOG does not intend to early-adopt ASU 2015-17 and does not expect the new standard to have a material impact on its consolidated financial statements and related disclosures.

In July 2015, the FASB issued ASU 2015-11, "Accounting for Inventory" (ASU 2015-11), which requires entities to measure most inventory at lower of cost or net realizable value. ASU 2015-11 defines net realizable value as "the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation." ASU 2015-11 is effective prospectively for interim and annual periods beginning after December 15, 2016. EOG is reviewing the requirements of the new standard and does not believe that the adoption of ASU 2015-11 will have a material impact on its consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03, "Interest - Computation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" (ASU 2015-03), which changes the presentation of debt issuance costs in financial statements. Under ASU 2015-03, an entity will present debt issuance costs in the balance sheet as a direct reduction from the related debt liability rather than as an asset. Amortization of such costs will be presented as a component of interest expense. ASU 2015-03 is effective for interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Because ASU 2015-03 does not address debt issuance costs related to line-of-credit arrangements, in August 2015, the FASB issued ASU 2015-15 "Interest - Computation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements" (ASU 2015-15). ASU 2015-15 provides that, in the absence of authoritative guidance in ASU 2015-03, the United States Securities and Exchange Commission would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset and subsequently amortizing the deferred debt issuance costs over the term of the line-of-credit arrangement. EOG does not expect the adoption of ASU 2015-03 and ASU 2015-15 to have a material impact on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The FASB originally intended ASU 2014-09 to be effective for interim and annual reporting periods beginning after December 15, 2016, and permits adoption through the use of either the full retrospective approach or a modified retrospective approach. In July 2015, the FASB issued an update which delays by one year the effective date of ASU 2014-09 and allows for early adoption as of the original effective date. EOG does not intend to early-adopt ASU 2014-09 and has not determined which transition method it will use. EOG continues to analyze ASU 2014-09 to determine what impact the new standard will have on its consolidated financial statements and related disclosures.



F-10


2.  Long-Term Debt

Long-Term Debt at December 31, 2015 and 2014 consisted of the following (in thousands):
 2015 2014
    
Commercial Paper$259,718
 $—
2.95% Senior Notes due 2015—
 500,000
2.500% Senior Notes due 2016400,000
 400,000
5.875% Senior Notes due 2017600,000
 600,000
6.875% Senior Notes due 2018350,000
 350,000
5.625% Senior Notes due 2019900,000
 900,000
4.40% Senior Notes due 2020500,000
 500,000
2.45% Senior Notes due 2020500,000
 500,000
4.100% Senior Notes due 2021750,000
 750,000
2.625% Senior Notes due 20231,250,000
 1,250,000
3.15% Senior Notes due 2025500,000
 —
6.65% Senior Notes due 2028140,000
 140,000
3.90% Senior Notes due 2035500,000
 —
Long-Term Debt6,649,718
 5,890,000
Capital Lease Obligation45,064
 51,221
Less: Current Portion of Long-Term Debt6,579
 6,579
Unamortized Debt Discount34,518
 31,288
Total Long-Term Debt$6,653,685
 $5,903,354

At December 31, 2015, the aggregate annual maturities of long-term debt (excluding capital lease obligations) were $400 million in 2016, $600 million in 2017, $350 million in 2018, $900 million in 2019 and $1 billion in 2020.  At December 31, 2015 and 2014, EOG had $260 million and zero, respectively, of outstanding short-term borrowings under the commercial paper program and no outstanding borrowings under uncommitted credit facilities.

During 2015 and 2014, EOG utilized commercial paper and short-term borrowings under uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes.  The average borrowings outstanding under the commercial paper program were $81 million and $12 million during the years ended December 31, 2015 and 2014, respectively.  The average borrowings outstanding under the uncommitted credit facilities were zero and $0.1 million during the years ended December 31, 2015 and 2014, respectively.  The weighted average interest rates for commercial paper borrowings were 0.51% and 0.25% for the years 2015 and 2014, respectively, and were 0.70% for uncommitted credit facility borrowings for the year 2014.

At December 31, 2015, the $400 million aggregate principal amount of its 2.500% Senior Notes due 2016 (2016 Notes) and $260 million aggregate principal amount of commercial paper borrowings were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amount with other long-term debt.

On January 14, 2016, EOG closed its sale of $750 million aggregate principal amount of its 4.15% Senior Notes due 2026 and $250 million aggregate principal amount of its 5.10% Senior Notes due 2036 (collectively, the New Notes). Interest on the New Notes is payable semi-annually in arrears on January 15 and July 15 of each year beginning on July 15, 2016. Net proceeds from the New Notes offering totaled approximately $991 million and were used to repay the 2016 Notes when they matured on February 1, 2016, and for general corporate purposes, including repayment of outstanding commercial paper borrowings and funding of future capital expenditures.


F-11


On July 21, 2015, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (2015 Agreement) with domestic and foreign lenders. The 2015 Agreement replaces EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of October 11, 2011, which had a scheduled maturity date of October 11, 2016 (2011 Agreement). There were no borrowings or letters of credit outstanding under the 2011 Agreement as of the closing of the 2015 Agreement and the termination of the 2011 Agreement. The 2015 Agreement has a scheduled maturity date of July 21, 2020, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. Advances under the 2015 Agreement will accrue interest based, at EOG's option, on either the London InterBank Offered Rate plus an applicable margin (Eurodollar rate) or the base rate (as defined in the 2015 Agreement) plus an applicable margin. Consistent with the terms of the 2011 Agreement, the 2015 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 debt-to-total capitalization ratio of no greater than 65%. At December 31, 2015, there were no borrowings or letters of credit outstanding under the 2015 Agreement. The Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2015 Agreement, would have been 1.33% and 3.50%, respectively.

On June 1, 2015, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.95% Senior Notes due 2015.

On March 17, 2015, EOG closed its sale of $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 and $500 million aggregate principal amount of its 3.90% Senior Notes due 2035 (together, the Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2015. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes.

3.  Stockholders' Equity

Common Stock.  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, 2015, 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.

On February 24, 2014, EOG's Board approved a two-for-one stock split in the form of a stock dividend, which was paid on March 31, 2014, to stockholders of record as of March 17, 2014. 

On August 5, 2014, the Board increased the quarterly cash dividend on the common stock by 34% to $0.1675 per share, effective beginning with the dividend paid on October 31, 2014, to stockholders of record as of October 17, 2014. On February 24, 2014, the Board increased the quarterly cash dividend on the common stock by 33% to $0.125 per share, effective beginning with the dividend paid on April 30, 2014, to stockholders of record as of April 16, 2014. The Board increased the quarterly cash dividend on the Common Stock to $0.0938 per share on February 13, 2013, effective beginning with the dividend paid on April 30, 2013, to stockholders of record as of April 16, 2013. 


F-12


The following summarizes Common Stock activity for each of the years ended December 31, 2013, 2014 and 2015 (in thousands):
 Common Shares
 Issued Treasury Outstanding
      
Balance at December 31, 2012543,916
 (652) 543,264
Common Stock Issued Under Stock-Based Compensation Plans2,206
 —
 2,206
Treasury Stock Purchased (1)
—
 (854) (854)
Common Stock Issued Under Employee Stock Purchase Plan256
 —
 256
Treasury Stock Issued Under Stock-Based Compensation Plans—
 1,300
 1,300
Balance at December 31, 2013546,378
 (206) 546,172
Common Stock Issued Under Stock-Based Compensation Plans2,448
 —
 2,448
Treasury Stock Purchased (1)
—
 (1,209) (1,209)
Common Stock Issued Under Employee Stock Purchase Plan202
 —
 202
Treasury Stock Issued Under Stock-Based Compensation Plans—
 682
 682
Balance at December 31, 2014549,028
 (733) 548,295
Common Stock Issued Under Stock-Based Compensation Plans1,019
 —
 1,019
Treasury Stock Purchased (1)
—
 (581) (581)
Common Stock Issued Under Employee Stock Purchase Plan104
 121
 225
Treasury Stock Issued Under Stock-Based Compensation Plans—
 901
 901
Balance at December 31, 2015550,151
 (292) 549,859
(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, 2015, there were no shares of preferred stock outstanding.


F-13


4.  Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) includes certain transactions that have generally been reported in the Consolidated Statements of Stockholders' Equity. The components of Accumulated Other Comprehensive Income (Loss) at December 31, 2015 and 2014 consisted of the following (in thousands):
 Foreign Currency Translation Adjustment Other Total
      
December 31, 2013$417,707
 $(1,873) $415,834
Other comprehensive loss before reclassifications(54,484) (918) (55,402)
Amounts reclassified out of other comprehensive income (loss)(383,244)
(1) 
246
(2) 
(382,998)
Tax effects—
 (490) (490)
Other comprehensive income (loss)(437,728) (1,162) (438,890)
December 31, 2014(20,021) (3,035) (23,056)
Other comprehensive loss before reclassifications(11,517) (129) (11,646)
Amounts reclassified out of other comprehensive income (loss)—

1,572
(3) 
1,572
Tax effects—
 (208) (208)
Other comprehensive income (loss)(11,517) 1,235
 (10,282)
December 31, 2015$(31,538) $(1,800) $(33,338)
(1)Reclassified to Net Income (Loss) - Gains (Losses) on Asset Dispositions, Net. See Note 17.
(2)Includes $107 thousand reclassified to Net Income (Loss) - Interest Expense in connection with the settlement of a foreign currency swap and an interest rate swap and $139 thousand reclassified to Net Income (Loss) - General and Administrative related to certain EOG pension plans (see Note 7).
(3)Reclassified to Net Income (Loss) - General and Administrative. Related to certain EOG pension plans. See Note 7.

No significant amount was reclassified out of Accumulated Other Comprehensive Income (Loss) during the year ended December 31, 2013.

5.  Other Income (Expense), Net

Other income, net, for 2015 included equity income from investments in ammonia plants in Trinidad ($9 million), a downward adjustment to deferred compensation expense ($6 million), interest income ($3 million) and net foreign currency transaction losses ($(17) million).  Other expense, net, for 2014 included net foreign currency transaction losses ($(34) million), losses on dispositions of warehouse stock ($15 million) and equity income from investments in ammonia plants in Trinidad ($8 million).  Other expense, net, for 2013 included losses on dispositions of warehouse stock ($23 million), net foreign currency transaction gains ($12 million), equity income from investments in ammonia plants in Trinidad ($11 million) and interest income ($6 million) primarily related to sales and use tax refunds. 



F-14


6.  Income Taxes

The principal components of EOG's net deferred income tax liabilities at December 31, 2015 and 2014 were as follows (in thousands):
 2015 2014
Current Deferred Income Tax Assets (Liabilities)   
Deferred Compensation Plans$38,559
 $—
Alternative Minimum Tax Credit Carryforward93,316
 —
Foreign Net Operating Loss47,786
 49,865
Foreign Valuation Allowance(35,536) (30,247)
Other3,687
 —
Total Net Current Deferred Income Tax Assets$147,812
 $19,618
Noncurrent Deferred Income Tax Assets (Liabilities) 
  
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization$(57,569) $(141,643)
Foreign Net Operating Loss443,010
 487,876
Foreign Valuation Allowances(380,104) (349,704)
Foreign Other1,506
 4,096
Total Net Noncurrent Deferred Income Tax Assets$6,843
 $625
Current Deferred Income Tax (Asset) Liabilities   
Commodity Hedging Contracts$—
 $166,109
Deferred Compensation Plans—
 (48,207)
Accrued Expenses and Liabilities—
 (5,643)
Other—
 (1,516)
Total Net Current Deferred Income Tax Liabilities$—
 $110,743
Noncurrent Deferred Income Tax (Assets) Liabilities 
  
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization$5,299,817
 $7,634,297
Non-Producing Leasehold Costs(53,026) (44,236)
Seismic Costs Capitalized for Tax(162,240) (158,157)
Equity Awards(140,663) (127,541)
Capitalized Interest98,242
 97,739
Alternative Minimum Tax Credit Carryforward(685,189) (793,126)
Undistributed Foreign Earnings258,403
 249,861
Other(27,442) (35,891)
Total Net Noncurrent Deferred Income Tax Liabilities$4,587,902
 $6,822,946
Total Net Deferred Income Tax Liabilities$4,433,247
 $6,913,446

The components of Income (Loss) Before Income Taxes for the years indicated below were as follows (in thousands):
 2015 2014 2013
      
United States$(6,840,119) $5,161,232
 $3,268,727
Foreign(81,437) (165,917) 168,159
Total$(6,921,556) $4,995,315
 $3,436,886


F-15


The principal components of EOG's Income Tax Provision (Benefit) for the years indicated below were as follows (in thousands):
 2015 2014 2013
Current:     
Federal$21,719
 $269,326
 $207,777
State9,404
 22,835
 22,856
Foreign54,143
 82,721
 134,379
Total85,266
 374,882
 365,012
Deferred: 
  
  
Federal(2,362,926) 1,608,706
 915,994
State(127,444) 29,056
 26,305
Foreign8,063
 67,184
 (67,534)
Total(2,482,307) 1,704,946
 874,765
Income Tax Provision (Benefit)$(2,397,041) $2,079,828
 $1,239,777

The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows:
 2015 2014 2013
      
Statutory Federal Income Tax Rate35.00 % 35.00 % 35.00 %
State Income Tax, Net of Federal Benefit1.11
 0.68
 0.93
Income Tax Provision Related to Foreign Operations(1.31) (0.12) 0.23
Canadian Divestiture—
 (3.46) —
Undistributed Foreign Earnings—
 4.94
 —
Foreign Valuation Allowances—
 6.47
 —
Foreign Oil and Gas Impairments—
 (1.90) —
Other(0.17) 0.03
 (0.09)
Effective Income Tax Rate34.63 % 41.64 % 36.07 %

The effective tax rate of 35% in 2015 was lower than the prior year rate of 42% primarily due to the effects of recording valuation allowances in the United Kingdom and deferred taxes in the United States on undistributed foreign earnings in 2014.

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, EOG has recorded valuation allowances for the portion of certain foreign and state deferred tax assets that management does not believe are more likely than not to be realized. 

The principal components of EOG's rollforward of valuation allowances for deferred tax assets were as follows (in thousands):
 2015 2014 2013
      
Beginning Balance$463,018
 $223,599
 $199,743
Increase (1)
146,602
 392,729
 43,422
Decrease (2)
(4,315) (1,424) (4,967)
Other (3)
(99,178) (151,886) (14,599)
Ending Balance$506,127
 $463,018
 $223,599
(1)Increase in valuation allowance related to the generation of tax net operating losses and other deferred tax assets.
(2)Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowance.
(3)Represents dispositions/revisions/foreign exchange rate variances and the effect of statutory income tax rate changes.

F-16


The balance of unrecognized tax benefits at December 31, 2015, was zero. 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 and are subject to tax audits in the United States and various state, local and foreign jurisdictions. EOG's earliest open tax years in its principal jurisdictions are as follows: United States federal (2011), Canada (2011), United Kingdom (2014), Trinidad (2002) and China (2008).

EOG's foreign subsidiaries' undistributed earnings of approximately $2 billion at December 31, 2015, are no longer considered to be permanently reinvested outside the United States and, accordingly, EOG has cumulatively recorded $258 million of United States federal and state deferred income taxes.  EOG changed its permanent reinvestment assertion in 2014.

In 2015, EOG utilized alternative minimum tax (AMT) credits of $4 million. Additional AMT credits of $779 million, resulting from AMT paid in prior years, will be carried forward indefinitely until they are used to offset regular income taxes in future periods. The ability of EOG to utilize these 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, 2015, management does not believe that an ownership change has occurred which would limit these carryforwards.

As of December 31, 2015, EOG had state income tax NOLs being carried forward of approximately $1.7 billion, which, if unused, expire between 2016 and 2034. During 2015, EOG's United Kingdom subsidiary incurred a tax NOL of approximately $153 million which, along with prior years' NOLs of $764 million, will be carried forward indefinitely. As described above, these NOLs have been evaluated for the likelihood of future utilization, and valuation allowances have been established for the portion of these deferred tax assets that do not meet the "more likely than not" threshold.

The Protecting Americans from Tax Hikes Act of 2015 (PATH) was enacted on December 18, 2015. PATH retroactively extended various temporary individual and business tax incentives for 2015 and in some instances extended certain incentives through 2019. Bonus tax depreciation, a favorable tax incentive for EOG, was extended from 2015 through 2019.

7.  Employee Benefit Plans

Stock-Based Compensation

During 2013,2015, 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 itsthe EOG Resources, Inc. 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, 20122015, 2014 and 20112013 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 
 2015 2014 2013
      
Lease and Well$44
 $41
 $35
Gathering and Processing Costs1
 1
 1
Exploration Costs26
 27
 27
General and Administrative60
 76
 71
Total$131
 $145
 $134

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.awards.  At December 31, 2013,2015, approximately 16.624.7 million common 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.


F-17


During 2013, 20122015, 2014 and 2011,2013, 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 $26 million, $99 million and $56 million $67 millionfor 2015, 2014 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 10seven 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$56 million, $49$62 million and $48$53 million for the years ended December 31, 2013, 20122015, 2014 and 2011,2013, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2013, 20122015, 2014 and 20112013 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
 Stock Options/SARs ESPP
 2015 2014 2013 2015 2014 2013
            
Weighted Average Fair Value of Grants$21.88
 $30.75
 $27.35
 $21.21
 $21.65
 $15.06
Expected Volatility38.03% 35.28% 35.86% 32.08% 25.03% 29.89%
Risk-Free Interest Rate0.83% 0.95% 0.78% 0.12% 0.08% 0.11%
Dividend Yield0.85% 0.61% 0.40% 0.73% 0.46% 0.60%
Expected Life5.3 years
 5.2 years
 5.5 years
 0.5 years
 0.5 years
 0.5 years

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


F-18


The following table sets forth the stock option and SAR transactions for the years ended December 31, 2013, 20122015, 2014 and 20112013 (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 

 2015 2014 2013
 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 110,493
 $64.96
 10,452
 $54.43
 12,438
 $42.91
Granted2,037
 69.99
 2,146
 101.55
 2,268
 83.70
Exercised (1)
(1,518) 47.64
 (1,718) 45.68
 (4,046) 35.62
Forfeited(268) 80.31
 (387) 68.95
 (208) 50.78
Outstanding at December 3110,744
 67.98
 10,493
 64.96
 10,452
 54.43
Stock Options/SARs Exercisable at December 315,993
 57.96
 5,287
 49.40
 4,638
 43.95
(1)The total intrinsic value of stock options/SARs exercised during the years 2015, 2014 and 2013 2012 and 2011 was $151$60 million, $185$95 million and $78$151 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, 2013,2015, there were 5.010.4 million stock options/SARs vested or expected to vest with a weighted average grant price of $108.03$67.52 per share, an intrinsic value of $300$52 million and a weighted average remaining contractual life of 4.54.1 years.

F-19
The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 20132015 (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

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)
                 
$22.00 to $  44.99 2,184
 2 $41.08
   2,182
 2 $41.08
   
45.00 to     56.99 2,672
 3 52.37
   2,229
 3 51.64
   
  57.00 to   69.99 2,019
 7 69.13
   51
 4 62.11
   
  70.00 to    84.99 1,832
 4 84.25
   936
 4 84.36
   
  85.00 to   116.99 2,037
 5 101.49
   595
 5 101.61
   
  10,744
 4 67.98
 $117,424
 5,993
 3 57.96
 $107,950
(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.SARs.

At December 31, 2013,2015, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $103$100 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.72.8 years.

At December 31, 2013,2015, approximately 498,000568,000 shares of Common Stock remained available for issuance under the ESPP.  The following table summarizes ESPP activities for the years ended December 31, 2013, 20122015, 2014 and 20112013 (in thousands, except number of participants):
 2015 2014 2013
      
Approximate Number of Participants1,963
 1,991
 1,844
Shares Purchased225
 202
 256
Aggregate Purchase Price$15,045
 $14,927
 $14,015

F-19
 
 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$69 million, $72$74 million and $80$72 million for the years ended December 31, 2015, 2014 and 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, 20122015, 2014 and 20112013 (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 

 2015 2014 2013
 
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 15,394
 $64.39
 7,358
 $49.54
 7,636
 $45.53
Granted1,044
 77.94
 1,132
 98.72
 1,294
 76.04
Released (1)
(1,331) 51.52
 (2,761) 105.24
 (1,368) 52.39
Forfeited(199) 74.56
 (335) 62.55
 (204) 48.55
Outstanding at December 31 (2)
4,908
 70.35
 5,394
 64.39
 7,358
 49.54
(1)The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2015, 2014 and 2013 2012 and 2011 was $101$109 million, $120$291 million and $44$101 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 aggregatetotal intrinsic value of restricted stock and restricted stock units outstanding at December 31, 20132015 and 20122014 was approximately $617$347 million and $461$497 million, respectively.


At December 31, 2013,2015, unrecognized compensation expense related to restricted stock and restricted stock units totaled $154$156 million.  Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.42.5 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 261,390810,000 performance units/shares could be outstanding (based on the number of performance units/shares outstanding as of December 31, 2013)2015).  Subject to the termination provisions set forth in the grant agreements and the applicable performance multiple, the grants of performance shares/unitsunits/shares 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 $5 million, $9 million and $7$9 million for the years ended December 31, 2015, 2014 and 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, 2015, 2014 and 2013 and 2012 arewere 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%
 2015 2014 2013
      
Weighted Average Fair Value of Grants$80.64
 $119.27
 $100.34
Expected Volatility29.35% 32.18% 33.63%
Risk-Free Interest Rate1.07% 1.18% 0.79%

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-21F-20


The following table sets forth performance unit and performance stock transactions for the years ended December 31, 2015, 2014 and 2013 (units and 2012 (shares and unitsshares 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 

 2015 2014 2013
 
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 1333
 $90.17
 261
 $82.18
 142
 $67.05
Granted72
 80.64
 72
 119.27
 119
 100.34
Outstanding at December 31 (1)
405
 88.48
 333
 90.17
 261
 82.18
(1)The total intrinsic value of performance units and performance stock outstanding at December 31, 20132015 and 20122014 was $21.9$29 million and $8.6$31 million, respectively.

At December 31, 2013,2015, 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 2.43.3 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 $36 million, $41 million and $37 million $36 millionfor 2015, 2014 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, theseThese pension plans are available to most employees of the Canadian, Trinidadian and United Kingdom subsidiaries.  EOG's combined contributions to these plans were $1 million, $5 million and $4 million $3 millionfor 2015, 2014 and $3 million for 2013, 2012 and 2011, respectively.

For the Canadian and Trinidadian defined benefit pension plans,plan, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $13$9 million, $11$7 million and $0.2 million, respectively, at December 31, 2015, and $14 million, $12 million and $1 million, respectively, at December 31, 2013, and $14 million, $10 million and $2 million, respectively, at December 31, 2012.2014. In connection with the divestiture of substantially all of its Canadian assets in the fourth quarter of 2014, EOG has elected to terminate the Canadian non-contributory defined benefit pension plan.

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

7.8.  Commitments and Contingencies

Letters of Credit.Credit and Guarantees. At December 31, 2013,2015 and 2014, respectively, EOG had standby letters of credit and guarantees outstanding totaling approximately $711$272 million of which $150 million represented a guarantee of subsidiary indebtedness (see Note 2) and $561$423 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 representedrepresenting guarantees of payment or performance obligations on behalf of subsidiaries.  As of February 24, 2014,25, 2016, there were no demands for payment under these guarantees.


F-21


Minimum Commitments.  At December 31, 2013,2015, 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, 2013,2015, 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 
 
Total Minimum
Commitments
  
2016$1,275,650
2017994,328
2018781,299
2019547,299
2020431,221
2021 and beyond900,961
 $4,930,758

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 $229 million, $237 million and $191 million $182 millionfor 2015, 2014 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
8.9.  Net Income (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the years ended December 31, 2013, 20122015, 2014 and 20112013 (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  $4.10 
 2015 2014 2013
Numerator for Basic and Diluted Earnings per Share -     
Net Income (Loss)$(4,524,515) $2,915,487
 $2,197,109
Denominator for Basic Earnings per Share - 
  
  
Weighted Average Shares545,697
 543,443
 540,341
Potential Dilutive Common Shares - 
  
  
Stock Options/SARs—
 2,526
 2,316
Restricted Stock/Units and Performance Units/Stock—
 2,570
 3,570
Denominator for Diluted Earnings per Share - 
  
  
Adjusted Diluted Weighted Average Shares545,697
 548,539
 546,227
Net Income (Loss) Per Share 
  
  
Basic$(8.29) $5.36
 $4.07
Diluted$(8.29) $5.32
 $4.02

The diluted earnings per share calculation excludes stock options, SARs, restricted stock and SARsunits and performance units and stock that were anti-dilutive.  Shares underlying the excluded stock options and SARs totaled 0.310.2 million, 0.50.7 million and 0.40.3 million for the years ended December 31, 2015, 2014 and 2013, 2012respectively. For the year ended December 31, 2015, 5.3 million shares of restricted stock and 2011, respectively.restricted stock units and performance units and performance stock were excluded.


9.
F-22


10.  Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the years ended December 31, 2013, 20122015, 2014 and 20112013 (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 
 2015 2014 2013
      
Interest, Net of Capitalized Interest$222,088
 $197,383
 $235,854
Income Taxes, Net of Refunds Received$41,108
 $342,741
 $294,739

EOG's accrued capital expenditures at December 31, 2015, 2014 and 2013 2012 and 2011 were $731$416 million, $734$972 million and $663$731 million, respectively.

Non-cash investing activities for each of the yearyears ended December 31, 2014 and 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
10.11.  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 makingdecision-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.Canada.  For segment reporting purposes, the chief operating decision maker considers the major United States producing areas to be one operating segment.

As previously reported, during the fourth quarter of 2014, EOG completed the sale of substantially all of its Canadian operations (see Note 17). As a result, information relating to EOG's remaining Canadian operations has been included in the Other International segment and prior year amounts have been reclassified to conform to current year presentation. Financial information by reportable segment is presented below as of and for the years ended December 31, 2013, 20122015, 2014 and 20112013 (in thousands):
 
United
States
 Trinidad 
Other
International (1)
 Total
2015       
Crude Oil and Condensate$4,917,731
 $13,122
 $3,709
 $4,934,562
Natural Gas Liquids407,570
 —
 88
 407,658
Natural Gas637,452
 368,639
 54,947
 1,061,038
Gains on Mark-to-Market Commodity Derivative Contracts61,924
 —
 —
 61,924
Gathering, Processing and Marketing2,254,477
 (1,342) —
 2,253,135
Gains (Losses) on Asset Dispositions, Net(12,176) 393
 2,985
 (8,798)
Other, Net47,464
 (3) 448
 47,909
Net Operating Revenues (2)
8,314,442
 380,809
 62,177
 8,757,428
Depreciation, Depletion and Amortization3,139,863
 154,853
 18,928
 3,313,644
Operating Income (Loss)(6,566,282) 175,658
 (295,455) (6,686,079)
Interest Income1,913
 389
 1,167
 3,469
Other Income (Expense)6,461
 8,780
 (16,794) (1,553)
Net Interest Expense274,606
 1,400
 (38,613) 237,393
Income (Loss) Before Income Taxes(6,832,514) 183,427
 (272,469) (6,921,556)
Income Tax Provision (Benefit)(2,463,213) 63,502
 2,670
 (2,397,041)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs4,495,730
 102,358
 112,316
 4,710,404
Total Property, Plant and Equipment, Net23,593,995
 350,766
 265,960
 24,210,721
Total Assets25,351,908
 886,826
 736,510
 26,975,244

          
 
 
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-25F-23
 
 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 


 
United
States
 Trinidad 
Other
International (1)
 Total
2014       
Crude Oil and Condensate$9,526,149
 $29,604
 $186,727
 $9,742,480
Natural Gas Liquids924,454
 —
 9,597
 934,051
Natural Gas1,321,175
 483,071
 112,140
 1,916,386
Gains on Mark-to-Market Commodity Derivative Contracts834,273
 —
 —
 834,273
Gathering, Processing and Marketing4,040,024
 6,064
 228
 4,046,316
Gains on Asset Dispositions, Net96,339
 —
 411,251
 507,590
Other, Net49,950
 37
 4,257
 54,244
Net Operating Revenues (3)
16,792,364
 518,776
 724,200
 18,035,340
Depreciation, Depletion and Amortization3,684,943
 188,592
 123,506
 3,997,041
Operating Income (Loss)5,074,911
 277,471
 (110,559) 5,241,823
Interest Income849
 253
 1,137
 2,239
Other Income (Expense)(14,953) 8,712
 (41,048) (47,289)
Net Interest Expense269,166
 —
 (67,708) 201,458
Income (Loss) Before Income Taxes4,791,641
 286,436
 (82,762) 4,995,315
Income Tax Provision1,837,185
 98,559
 144,084
 2,079,828
Additions to Oil and Gas Properties, Excluding Dry Hole Costs7,133,727
 76,138
 261,312
 7,471,177
Total Property, Plant and Equipment, Net28,391,741
 382,719
 398,184
 29,172,644
Total Assets32,871,398
 865,674
 1,025,615
 34,762,687
2013 
  
  
  
Crude Oil and Condensate$8,035,358
 $40,379
 $224,910
 $8,300,647
Natural Gas Liquids761,535
 —
 12,435
 773,970
Natural Gas1,100,808
 477,103
 103,118
 1,681,029
Losses on Mark-to-Market Commodity Derivative Contracts(166,349) —
 —
 (166,349)
Gathering, Processing and Marketing3,636,209
 6,064
 1,476
 3,643,749
Gains on Asset Dispositions, Net93,876
 1,119
 102,570
 197,565
Other, Net51,713
 24
 4,770
 56,507
Net Operating Revenues (4)
13,513,150
 524,689
 449,279
 14,487,118
Depreciation, Depletion and Amortization3,223,596
 181,990
 195,390
 3,600,976
Operating Income (Loss)3,543,841
 266,329
 (134,959) 3,675,211
Interest Income2,803
 336
 2,446
 5,585
Other Income (Expense)(29,696) 9,889
 11,357
 (8,450)
Net Interest Expense283,209
 —
 (47,749) 235,460
Income (Loss) Before Income Taxes3,233,739
 276,554
 (73,407) 3,436,886
Income Tax Provision (Benefit)1,161,328
 118,270
 (39,821) 1,239,777
Additions to Oil and Gas Properties, Excluding Dry Hole Costs6,133,894
 132,984
 355,558
 6,622,436
Total Property, Plant and Equipment, Net24,456,383
 476,174
 1,216,279
 26,148,836
Total Assets27,668,713
 986,796
 1,918,729
 30,574,238
(1)Other International primarily includesconsists of EOG's United Kingdom, China, Canada and Argentina operations.
(2)EOG had sales activity with two significant purchasers in 2015, one totaling $1.7 billion and the other totaling $1.4 billion of consolidated Net Operating Revenues in the United States segment.
(3)EOG had sales activity with two significant purchasers in 2014, one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment.
(4)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.



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11.12.  Risk Management Activities

CommodityPrice Risks. EOG engages in price risk management activities from time to time.  These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas.  EOG utilizes financial commodity derivative instruments, primarily price swap, 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, 20122015, 2014 and 2011,2013, 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 2015, 2014 and 2013, EOG recognized net lossesgains (losses) on the mark-to-market of financial commodity derivative contracts of $166$62 million, $834 million and $(166) million, respectively, 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.

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Presented below is a comprehensive summary of EOG's natural gas derivative contracts atof $730 million, $34 million and $116 million, respectively. At December 31, 2013, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).2015, EOG had no outstanding crude oil or natural gas commodity derivative contracts.

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.

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The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 20132015 and 2012,2014, 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, 
DescriptionLocation 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 portionCurrent Liabilities - Other $40  $- 
Noncurrent portionOther Liabilities $-  $55 
 
 
        
Interest rate swap -
 
        
Current portionCurrent Liabilities - Other $1  $- 
Noncurrent portionOther Liabilities $-  $4 

     Fair Value at December 31,
Description Location on Balance Sheet 2015 2014
Asset Derivatives      
Crude oil and natural gas derivative contracts -      
Current portion 
Assets from Price Risk Management Activities (1)
 $—
 $465
Liability Derivatives    
  
Crude oil and natural gas derivative contracts -    
  
Current portion 
Liabilities from Price Risk Management Activities (2)
 $—
 $—
(1)
The current portion of Assets from Price Risk Management Activities consists of gross assets of $18$477 million, partially offset by gross liabilities of $10$12 million, at December 31, 2013 and gross assets of $271 million, partially offset by gross liabilities of $105 million, at December 31, 2012.
2014.
(2)
The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $137$12 million,, partially offset by gross assets of $10$12 million, at December 31, 2013 and gross liabilities of $113 million, partially offset by gross assets of $105 million, at December 31, 2012.
2014.
(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.a financial derivative.  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)13).  EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions.  In some instances, EOG renegotiates payment terms and/or requires collateral, parent guarantees or letters of credit to minimize credit risk.  At December 31, 2013,2015, EOG's net accounts receivable balance related to United States, Canada Argentina and United Kingdom hydrocarbon sales includeincluded three receivable balances, each of which accounted for more thatthan 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 2014.2016.  At December 31, 2012,2014, EOG's net accounts receivable balance related to United States, Canada, Argentina and United Kingdom hydrocarbon sales include oneincluded two receivable balancebalances, each of which constituted 26%accounted for more than 10% of the total balance.  The receivable wasreceivables were due from a United Statestwo petroleum marketing company.refinery companies.  The related amount wasamounts were collected during early 2013.2015. In 20132015 and 2012,2014, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary, and all natural gas from EOG's China operations was sold to Petrochina Company Limited.


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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 1213 for the aggregate fair value of all derivative instruments that were in a net liability position at December 31, 2013 and 2012.2014.  EOG had no collateral posted and held no collateral at December 31, 2013,2015 and had no collateral posted and held $6$278 million of collateral at December 31, 2012.2014.

Substantially all of EOG's accounts receivable at December 31, 20132015 and 20122014 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, 2013,2015, credit losses incurred on receivables by EOG have been immaterial.

12.13.  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.

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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):2014. There were no such amounts outstanding at December 31, 2015. Amounts shown 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 
 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, 2014 
  
  
  
Financial Assets: 
  
  
  
Natural Gas Options/Swaptions$—
 $100
 $—
 $100
Crude Oil Swaps—
 121
 —
 121
Crude Oil Options/Swaptions—
 244
 —
 244
 
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 14.15.


F-31F-26


During 2013,2015, due to the decline in commodity prices, proved oil and gas properties, other property, plant and equipment and other assets with a carrying amount of $9,154 million were written down to their fair value of $2,828 million, resulting in pretax impairment charges of $6,326 million, $4,141 million net of tax.  Impairments included domestic legacy natural gas assets and marginal liquids plays and the Conwy crude oil project in the East Irish Sea. During 2014, proved oil and gas properties and other assets with a carrying amount of $400$968 million were written down to their fair value of $228$393 million, resulting in pretax impairment charges of $172$575 million. Included in the $172$575 million pretax impairment charges arewere $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 assumptionsinputs 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, 20132015 and 2012,2014, respectively, EOG had outstanding $5,890$6,390 million and $6,290$5,890 million respectively, aggregate principal amount of debt,senior notes, which had estimated fair values of approximately $6,222$6,524 million and $7,032$6,242 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.

13.14.  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, 20122015, 2014 and 2011,2013, such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows primarily due primarily to lower commodity prices and, to a lesser extent, 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$6,130 million, $171 million and $403$73 million in the United States during 2013, 20122015, 2014 and 2011,2013, respectively, and $76$196 million, $872$404 million and $428$85 million in CanadaOther International during 2013, 20122015, 2014 and 2011,2013, 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.2013.  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 $288 million, $168 million and $115 million $228 millionduring 2015, 2014 and $197 million during 2013, 2012 and 2011, respectively.
F-32

14.15.  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, 20132015 and 20122014 (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.
 2015 2014
    
Carrying Amount at Beginning of Period$752,718
 $761,898
Liabilities Incurred63,844
 123,849
Liabilities Settled (1)
(17,415) (247,422)
Accretion31,956
 41,489
Revisions(13,356) 82,885
Foreign Currency Translations(6,193) (9,981)
Carrying Amount at End of Period$811,554
 $752,718
    
Current Portion$7,651
 $11,814
Noncurrent Portion$803,903
 $740,904
(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.

F-27


15.16.  Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2013, 20122015, 2014 and 20112013 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 
 2015 2014 2013
      
Balance at January 1$17,253
 $9,211
 $49,116
Additions Pending the Determination of Proved Reserves24,640
 32,080
 52,099
Reclassifications to Proved Properties(26,659) (15,946) (54,505)
Costs Charged to Expense (1)
(6,279) (8,092) (35,859)
Foreign Currency Translations—
 —
 (1,640)
Balance at December 31$8,955
 $17,253
 $9,211
(1)Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

(1)Includes capitalizedAt December 31, 2015, 2014 and 2013, all exploratory well costs charged to either dry hole costs or impairments.had been capitalized for periods of less than one year.

F-33
The following table provides an aging of capitalized exploratory well costs at December 31, 2013, 201217.  Acquisitions 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 2013,2015, EOG completed acquisitions of approximately $481 million primarily to acquire proved crude oil properties and related assets in the Delaware Basin and gathering assets in the North Dakota Bakken.

During 2015, EOG received proceeds of approximately $761$193 million primarily from the sales of its entire interest in the planned Kitimat liquefied natural gas export terminal (Kitimat LNG Terminal)gathering and PTP, undeveloped acreage in the Horn River Basin in Canadaprocessing assets and producing properties and acreage in the Permian Basin, the Mid-Continent area and the Upper Gulf Coast region.other assets. During 2012,2014, EOG received proceeds of approximately $1.3 billion$569 million primarily from the salesdivestiture of producing propertiesall its assets in Manitoba and acreage primarilythe majority of its assets in Alberta (collectively, the Rocky Mountain area, the Upper Gulf Coast regionCanadian Sales) 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 Upper Gulf Coast region, the Rocky Mountain area and Texas,the Mid-Continent area. The Canadian Sales that closed on or about December 1, 2014, occurred in two separate transactions, an asset sale and the sale of a portionthe stock of certain of EOG's interestCanadian subsidiaries. As these two transactions represented a substantially complete liquidation of EOG's Canadian operations, approximately $383 million of cumulative translation adjustments previously recorded on the Consolidated Balance Sheets was reclassified to the Consolidated Statements of Income and Comprehensive Income. The Canadian Sales also resulted in the Kitimat LNG Terminal and PTP.release of approximately $150 million of restricted cash related to future abandonment liabilities.

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
F-28

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." During the fourth quarter of 2014, EOG completed the sale of substantially all of its Canadian operations. As a result, information relating to EOG's remaining Canadian operations has been included in the Other International segment and prior year amounts have been reclassified to conform to current year presentation.

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.1A, Risk Factors.

Proved reserves represent estimated quantities of crude oil, NGLs and natural gas, thatwhich, by analysis of geoscience and engineering data, can estimate,be estimated, with reasonable certainty, to be economically producible from a given daydate forward from known reservoirs under then-existing economic conditions, operating methods and government regulationregulations 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 significantrelatively major expenditure is required.required for recompletion. 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, 2013.2015.  Under EOG's current drilling and development plan,these plans, 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.  EOGEOG's 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. 

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EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


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, certainCertain 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, 20122015, 2014 and 20112013 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 seven11 professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and twofive of whom are Registered Professional Engineers.  The Manager,Vice President, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process.  The Manager,Vice President, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 2830 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)Engineer.

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, NGLsNGL 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 President and 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, 20122015, 2014 and 20112013 covered producing areas containing 82%86%, 87%76% and 85%82%, 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,February 1, 2016, 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, 2013,2015, is believed to have caused a material change in the estimates of net 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, 2013,2015, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2013,2015, 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-38F-30

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


NET PROVED RESERVE SUMMARY
 
United
States
 Trinidad 
Other
International (1)
 Total
NET PROVED RESERVES       
        
Crude Oil (MBbl) (2)
       
Net proved reserves at December 31, 2012671,029
 3,028
 26,761
 700,818
Revisions of previous estimates57,668
 (991) (6,008) 50,669
Purchases in place1,097
 —
 —
 1,097
Extensions, discoveries and other additions230,023
 —
 731
 230,754
Sales in place(2,337) —
 —
 (2,337)
Production(77,431) (447) (2,583) (80,461)
Net proved reserves at December 31, 2013880,049
 1,590
 18,901
 900,540
Revisions of previous estimates28,301
 99
 (378) 28,022
Purchases in place9,705
 —
 —
 9,705
Extensions, discoveries and other additions319,540
 —
 14
 319,554
Sales in place(4,967) —
 (7,656) (12,623)
Production(102,946) (350) (2,152) (105,448)
Net proved reserves at December 31, 20141,129,682
 1,339
 8,729
 1,139,750
Revisions of previous estimates(114,924) (1) —
 (114,925)
Purchases in place35,922
 —
 —
 35,922
Extensions, discoveries and other additions141,310
 63
 13
 141,386
Sales in place(730) —
 (10) (740)
Production(103,400) (332) (65) (103,797)
Net proved reserves at December 31, 20151,087,860
 1,069
 8,667
 1,097,596
        
Natural Gas Liquids (MBbl) (2)
 
  
  
  
Net proved reserves at December 31, 2012318,406
 —
 1,557
 319,963
Revisions of previous estimates12,157
 —
 (48) 12,109
Purchases in place1,202
 —
 —
 1,202
Extensions, discoveries and other additions69,187
 —
 10
 69,197
Sales in place(1,471) —
 —
 (1,471)
Production(23,479) —
 (315) (23,794)
Net proved reserves at December 31, 2013376,002
 —
 1,204
 377,206
Revisions of previous estimates27,450
 —
 (7) 27,443
Purchases in place1,812
 —
 —
 1,812
Extensions, discoveries and other additions91,683
 —
 —
 91,683
Sales in place(956) —
 (823) (1,779)
Production(29,061) —
 (236) (29,297)
Net proved reserves at December 31, 2014466,930
 —
 138
 467,068
Revisions of previous estimates(113,290) —
 68
 (113,222)
Purchases in place8,251
 —
 —
 8,251
Extensions, discoveries and other additions49,147
 —
 —
 49,147
Sales in place(84) —
 (187) (271)
Production(28,079) —
 (19) (28,098)
Net proved reserves at December 31, 2015382,875
 —
 —
 382,875

F-31
 
 
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 
EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
United
States
 Trinidad 
Other
International (1)
 Total
Natural Gas (Bcf) (3)
       
Net proved reserves at December 31, 20124,036.0
 588.2
 115.3
 4,739.5
Revisions of previous estimates264.0
 (17.4) 30.7
 277.3
Purchases in place5.7
 —
 —
 5.7
Extensions, discoveries and other additions504.7
 79.5
 9.9
 594.1
Sales in place(69.4) —
 —
 (69.4)
Production(342.3) (129.6) (30.5) (502.4)
Net proved reserves at December 31, 20134,398.7
 520.7
 125.4
 5,044.8
Revisions of previous estimates252.2
 12.9
 5.5
 270.6
Purchases in place17.1
 —
 —
 17.1
Extensions, discoveries and other additions638.3
 4.5
 4.7
 647.5
Sales in place(52.4) —
 (78.7) (131.1)
Production(348.4) (132.5) (25.4) (506.3)
Net proved reserves at December 31, 20144,905.5
 405.6
 31.5
 5,342.6
Revisions of previous estimates(1,453.1) 16.8
 5.6
 (1,430.7)
Purchases in place72.3
 —
 —
 72.3
Extensions, discoveries and other additions306.3
 21.7
 4.4
 332.4
Sales in place(3.9) —
 (11.1) (15.0)
Production(337.3) (127.5) (10.9) (475.7)
Net proved reserves at December 31, 20153,489.8
 316.6
 19.5
 3,825.9
        
Oil Equivalents (MBoe) (2)
 
  
  
  
Net proved reserves at December 31, 20121,662,108
 101,060
 47,530
 1,810,698
Revisions of previous estimates113,823
 (3,892) (941) 108,990
Purchases in place3,241
 —
 —
 3,241
Extensions, discoveries and other additions383,324
 13,245
 2,396
 398,965
Sales in place(15,375) —
 —
 (15,375)
Production(157,955) (22,049) (7,972) (187,976)
Net proved reserves at December 31, 20131,989,166
 88,364
 41,013
 2,118,543
Revisions of previous estimates97,782
 2,245
 541
 100,568
Purchases in place14,367
 —
 —
 14,367
Extensions, discoveries and other additions517,613
 758
 796
 519,167
Sales in place(14,661) —
 (21,602) (36,263)
Production(190,065) (22,430) (6,631) (219,126)
Net proved reserves at December 31, 20142,414,202
 68,937
 14,117
 2,497,256
Revisions of previous estimates(470,401) 2,802
 995
 (466,604)
Purchases in place56,215
 —
 —
 56,215
Extensions, discoveries and other additions241,513
 3,682
 736
 245,931
Sales in place(1,467) —
 (2,039) (3,506)
Production(187,701) (21,578) (1,896) (211,175)
Net proved reserves at December 31, 20152,052,361
 53,843
 11,913
 2,118,117
(1)Other International includes EOG's United Kingdom, China, Canada 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 thea 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-39F-32
EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


During 2015, EOG added 246 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Rocky Mountain area and the Eagle Ford.  Approximately 77% of the 2015 reserve additions were crude oil and condensate and NGLs, and 98% were in the United States.  Sales in place of 4 MMBoe were primarily related to the disposition of certain producing natural gas assets in Canada, the Permian Basin and the Upper Gulf Coast. Negative revisions of previous estimates of 467 MMBoe for 2015 included a negative revision of 574 MMBoe primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2015, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were the Uinta and Green River basins in the Rocky Mountain area, the Permian Basin and the Barnett Shale. Revisions other than price resulted primarily from improved recovery in the Eagle Ford.

During 2014, EOG added 519 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Permian Basin and the Rocky Mountain area.  Approximately 79% of the 2014 reserve additions were crude oil and condensate and NGLs, and nearly 100% were in the United States.  Sales in place of 36 MMBoe were primarily related to the disposition of certain producing natural gas assets in Canada, the Upper Gulf Coast and other producing basins in the United States. Positive revisions of previous estimates of 101 MMBoe for 2014 included a positive revision of 52 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2014 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 and improved recoveries and reduced operating costs in the Permian Basin.

During 2013, EOG added 399 million barrels of oil equivalent (MMBoe)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.  RevisionsPositive 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-40F-33

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 


 
United
States
 Trinidad 
Other
International (1)
 Total
NET PROVED DEVELOPED RESERVES       
Crude Oil (MBbl)       
December 31, 2012281,167
 2,377
 7,106
 290,650
December 31, 2013382,517
 1,505
 7,034
 391,056
December 31, 2014493,694
 1,339
 115
 495,148
December 31, 2015444,070
 1,069
 63
 445,202
Natural Gas Liquids (MBbl) 
  
  
  
December 31, 2012161,482
 —
 1,111
 162,593
December 31, 2013199,964
 —
 896
 200,860
December 31, 2014264,611
 —
 138
 264,749
December 31, 2015205,898
 —
 —
 205,898
Natural Gas (Bcf) 
  
  
  
December 31, 20122,387.5
 476.7
 115.3
 2,979.5
December 31, 20132,597.3
 494.6
 121.5
 3,213.4
December 31, 20143,102.8
 396.9
 28.6
 3,528.3
December 31, 20152,211.2
 297.6
 19.5
 2,528.3
Oil Equivalents (MBoe) 
  
  
  
December 31, 2012840,564
 81,826
 27,429
 949,819
December 31, 20131,015,359
 83,933
 28,184
 1,127,476
December 31, 20141,275,447
 67,484
 5,016
 1,347,947
December 31, 20151,018,491
 50,677
 3,309
 1,072,477
NET PROVED UNDEVELOPED RESERVES 
  
  
  
Crude Oil (MBbl) 
  
  
  
December 31, 2012389,862
 651
 19,655
 410,168
December 31, 2013497,532
 85
 11,867
 509,484
December 31, 2014635,988
 —
 8,614
 644,602
December 31, 2015643,790
 —
 8,604
 652,394
Natural Gas Liquids (MBbl) 
  
  
  
December 31, 2012156,924
 —
 446
 157,370
December 31, 2013176,038
 —
 308
 176,346
December 31, 2014202,319
 —
 —
 202,319
December 31, 2015176,977
 —
 —
 176,977
Natural Gas (Bcf) 
  
  
  
December 31, 20121,648.5
 111.5
 —
 1,760.0
December 31, 20131,801.4
 26.1
 3.9
 1,831.4
December 31, 20141,802.7
 8.7
 2.9
 1,814.3
December 31, 20151,278.6
 19.0
 —
 1,297.6
Oil Equivalents (MBoe) 
  
  
  
December 31, 2012821,544
 19,234
 20,101
 860,879
December 31, 2013973,807
 4,431
 12,829
 991,067
December 31, 20141,138,755
 1,453
 9,101
 1,149,309
December 31, 20151,033,870
 3,166
 8,604
 1,045,640
(1)Other International includes EOG's United Kingdom, China, Canada and Argentina operations.

F-41F-34

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total proved undeveloped reserves during 2015, 2014 and 2013 (in MBoe):
 2015 2014 2013
      
Balance at January 11,149,309
 991,067
 860,879
Extensions and Discoveries205,152
 403,713
 291,345
Revisions(241,973) (79,630) (855)
Acquisition of Reserves54,458
 4,239
 —
Sale of Reserves—
 (10,176) —
Conversion to Proved Developed Reserves(121,306) (159,904) (160,302)
Balance at December 311,045,640
 1,149,309
 991,067

For the twelve-month period ended December 31, 2015, total PUDs decreased by 104 MMBoe to 1,046 MMBoe.  EOG added approximately 52 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 pages F-30 and F-31 of this Annual Report on Form 10-K), EOG added 153 MMBoe.  The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 80% of the additions were crude oil and condensate and NGLs.  During 2015, EOG drilled and transferred 121 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,349 million.  Revisions of PUDs totaled negative 242 MMBoe, primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2015, reserves estimation as compared to the prices used in the prior year estimate.  During 2015, EOG did not sell any PUDs and acquired 54 MMBoe of PUDs.

For the twelve-month period ended December 31, 2014, total PUDs increased by 158 MMBoe to 1,149 MMBoe.  EOG added approximately 50 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 354 MMBoe.  The PUD additions were primarily in the Eagle Ford and Permian Basin, and 80% of the additions were crude oil and condensate and NGLs.  During 2014, EOG drilled and transferred 160 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,655 million.  Revisions of PUDs totaled negative 80 MMBoe, primarily due to removal of certain natural gas PUDs.  During 2014, EOG sold 10 MMBoe and acquired 4 MMBoe of PUDs.

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, 20132015 and 2012:2014:
 2015 2014
    
Proved properties$49,623,518
 $45,169,101
Unproved properties989,723
 1,334,431
Total50,613,241
 46,503,532
Accumulated depreciation, depletion and amortization(28,877,593) (20,212,748)
Net capitalized costs$21,735,648
 $26,290,784

 
 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 

F-35
EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


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, 20122015, 2014 and 2011:2013:

 
 
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 

 
United
States
 Trinidad 
Other
International (1)
 Total
2015       
Acquisition Costs of Properties       
Unproved$133,801
 $—
 $56
 $133,857
Proved480,617
 —
 —
 480,617
Subtotal614,418
 —
 56
 614,474
Exploration Costs206,814
 22,837
 23,041
 252,692
Development Costs (2)
3,847,813
 102,715
 110,589
 4,061,117
Total$4,669,045
 $125,552
 $133,686
 $4,928,283
2014 
  
  
  
Acquisition Costs of Properties 
  
  
  
Unproved$365,915
 $—
 $4,499
 $370,414
Proved138,772
 —
 329
 139,101
Subtotal504,687
 —
 4,828
 509,515
Exploration Costs332,703
 2,794
 60,476
 395,973
Development Costs (3)
6,638,192
 89,555
 271,534
 6,999,281
Total$7,475,582
 $92,349
 $336,838
 $7,904,769
2013 
  
  
  
Acquisition Costs of Properties 
  
  
  
Unproved$411,556
 $—
 $2,565
 $414,121
Proved120,220
 —
 (6) 120,214
Subtotal531,776
 —
 2,559
 534,335
Exploration Costs273,788
 16,060
 87,331
 377,179
Development Costs (4)
5,573,260
 124,231
 388,886
 6,086,377
Total$6,378,824
 $140,291
 $478,776
 $6,997,891
(1)Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations.
(2)Includes Asset Retirement Costs of $84$32 million, $13$15 million and $37$6 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)
(3)Includes Asset Retirement Costs of $52$149 million, $70 million, $7$14 million and $4$33 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

F-44
(4)Includes Asset Retirement Costs of $84 million and $50 million for the United States and Other International, respectively.  Excludes other property, plant and equipment.




F-36
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, 20122015, 2014 and 2011:2013:

          
 
 
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 

 
United
States
 Trinidad 
Other
International (2)
 Total
2015       
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues$5,962,753
 $381,761
 $58,744
 $6,403,258
Other47,464
 (3) 448
 47,909
Total6,010,217
 381,758
 59,192
 6,451,167
Exploration Costs139,753
 2,071
 7,670
 149,494
Dry Hole Costs956
 5,635
 8,155
 14,746
Transportation Costs838,428
 1,290
 9,601
 849,319
Production Costs1,486,189
 28,862
 66,080
 1,581,131
Impairments6,402,908
 —
 210,638
 6,613,546
Depreciation, Depletion and Amortization3,017,386
 154,588
 18,469
 3,190,443
Income (Loss) Before Income Taxes(5,875,403) 189,312
 (261,421) (5,947,512)
Income Tax Provision (Benefit)(2,128,183) 43,739
 (2,111) (2,086,555)
Results of Operations$(3,747,220) $145,573
 $(259,310) $(3,860,957)
2014 
  
  
  
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues$11,771,777
 $512,675
 $308,465
 $12,592,917
Other49,950
 37
 4,257
 54,244
Total11,821,727
 512,712
 312,722
 12,647,161
Exploration Costs162,434
 2,185
 19,769
 184,388
Dry Hole Costs25,408
 —
 23,082
 48,490
Transportation Costs957,522
 617
 14,037
 972,176
Production Costs1,940,074
 38,301
 171,652
 2,150,027
Impairments331,792
 —
 411,783
 743,575
Depreciation, Depletion and Amortization3,571,313
 188,250
 122,157
 3,881,720
Income (Loss) Before Income Taxes4,833,184
 283,359
 (449,758) 4,666,785
Income Tax Provision1,722,914
 74,588
 23,602
 1,821,104
Results of Operations$3,110,270
 $208,771
 $(473,360) $2,845,681
2013 
  
  
  
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues$9,897,701
 $517,482
 $340,463
 $10,755,646
Other51,713
 24
 4,770
 56,507
Total9,949,414
 517,506
 345,233
 10,812,153
Exploration Costs141,286
 2,345
 17,715
 161,346
Dry Hole Costs14,276
 4,478
 55,901
 74,655
Transportation Costs841,567
 659
 10,818
 853,044
Production Costs1,494,791
 43,279
 168,152
 1,706,222
Impairments178,718
 14,274
 93,949
 286,941
Depreciation, Depletion and Amortization3,122,858
 181,637
 193,515
 3,498,010
Income (Loss) Before Income Taxes4,155,918
 270,834
 (194,817) 4,231,935
Income Tax Provision (Benefit)1,486,445
 103,313
 (99,226) 1,490,532
Results of Operations$2,669,473
 $167,521
 $(95,591) $2,741,403
(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, 2013.2015.
(2)Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations.
F-45



F-37
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, 20122015, 2014 and 2011:2013:

 
 
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.
 
United
States
 Trinidad 
Other
International (1)
 Composite
        
Year Ended December 31, 2015$5.81
 $1.29
 $33.78
 $5.85
Year Ended December 31, 2014$6.44
 $1.34
 $24.60
 $6.46
Year Ended December 31, 2013$5.78
 $1.36
 $20.40
 $5.88
(1)Other International primarily consists of EOG's United Kingdom, China, Canada 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, NGLsNGL 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, 20122015, 2014 and 2011.2013.  The following information may be useful for certain comparisoncomparative 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, NGLsNGL 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 reserves 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
F-38

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, 20122015, 2014 and 2011:2013:

 
 
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 

 
United
States
 Trinidad 
Other
International (1)
 Total
2015       
Future cash inflows (2)
$67,242,928
 $954,779
 $522,941
 $68,720,648
Future production costs(31,707,743) (183,607) (169,505) (32,060,855)
Future development costs(15,579,923) (140,541) (65,347) (15,785,811)
Future income taxes(4,400,542) (215,659) —
 (4,616,201)
Future net cash flows15,554,720
 414,972
 288,089
 16,257,781
Discount to present value at 10% annual rate(6,589,253) (33,848) (13,284) (6,636,385)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves$8,965,467
 $381,124
 $274,805
 $9,621,396
2014 
  
  
  
Future cash inflows (3)
$144,355,692
 $1,615,280
 $979,249
 $146,950,221
Future production costs(51,112,604) (277,844) (242,845) (51,633,293)
Future development costs(20,270,439) (84,576) (139,750) (20,494,765)
Future income taxes(22,725,618) (460,096) —
 (23,185,714)
Future net cash flows50,247,031
 792,764
 596,654
 51,636,449
Discount to present value at 10% annual rate(23,542,990) (110,228) (59,813) (23,713,031)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves$26,704,041
 $682,536
 $536,841
 $27,923,418
2013 
  
  
  
Future cash inflows (4)
$119,644,713
 $2,082,195
 $2,272,591
 $123,999,499
Future production costs(49,099,393) (315,483) (751,612) (50,166,488)
Future development costs(17,753,860) (112,050) (683,441) (18,549,351)
Future income taxes(15,763,089) (603,786) (49,512) (16,416,387)
Future net cash flows37,028,371
 1,050,876
 788,026
 38,867,273
Discount to present value at 10% annual rate(17,451,470) (174,236) 91,865
 (17,533,841)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves$19,576,901
 $876,640
 $879,891
 $21,333,432
(1)
(1)Other International includes EOG's United Kingdom, China, Canada and Argentina operations.
(2)Estimated crude oil prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $49.58, $38.83 and $47.76, respectively. Estimated NGL price used to calculate 2015 future cash inflows for the United States was $15.17. Estimated natural gas prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $2.15, $2.88 and $5.60, respectively.
(3)Estimated crude oil prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $97.51, $80.60 and $94.09, respectively. Estimated NGL prices used to calculate 2014 future cash inflows for the United States and Other International were $34.29 and $27.03, respectively. Estimated natural gas prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $3.71, $3.71 and $5.14, respectively.
(4)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,$98.85, respectively. Estimated NGLsNGL prices used to calculate 2013 future cash inflows for the United States and CanadaOther International 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,$3.45, 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



F-39
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, 2013:2015:

 
 
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 
 
United
States
 Trinidad 
Other
International (1)
 Total
        
December 31, 2012$15,181,334
 $961,070
 $773,068
 $16,915,472
Sales and transfers of oil and gas produced, net of production costs(7,561,343) (473,544) (161,493) (8,196,380)
Net changes in prices and production costs1,734,058
 (12,050) (464,155) 1,257,853
Extensions, discoveries, additions and improved recovery, net of related costs5,449,531
 —
 33,901
 5,483,432
Development costs incurred2,792,400
 67,100
 96,400
 2,955,900
Revisions of estimated development cost892,803
 (3,539) 101,132
 990,396
Revisions of previous quantity estimates1,887,062
 (60,419) (32,445) 1,794,198
Accretion of discount1,895,503
 147,099
 91,127
 2,133,729
Net change in income taxes(2,772,267) 56,373
 137,644
 (2,578,250)
Purchases of reserves in place66,359
 —
 —
 66,359
Sales of reserves in place(140,652) —
 —
 (140,652)
Changes in timing and other152,113
 194,550
 304,712
 651,375
December 31, 201319,576,901
 876,640
 879,891
 21,333,432
Sales and transfers of oil and gas produced, net of production costs(8,874,180) (473,757) (122,777) (9,470,714)
Net changes in prices and production costs1,481,668
 (12,079) (206,412) 1,263,177
Extensions, discoveries, additions and improved recovery, net of related costs8,074,550
 3,113
 6,189
 8,083,852
Development costs incurred2,818,800
 12,800
 3,500
 2,835,100
Revisions of estimated development cost1,696,916
 9,981
 95,838
 1,802,735
Revisions of previous quantity estimates1,741,918
 35,001
 35,613
 1,812,532
Accretion of discount2,612,286
 133,019
 88,045
 2,833,350
Net change in income taxes(3,743,300) 91,438
 562
 (3,651,300)
Purchases of reserves in place317,785
 —
 —
 317,785
Sales of reserves in place(189,808) —
 (289,071) (478,879)
Changes in timing and other1,190,505
 6,380
 45,463
 1,242,348
December 31, 201426,704,041
 682,536
 536,841
 27,923,418
Sales and transfers of oil and gas produced, net of production costs(3,685,600) (351,606) 16,489
 (4,020,717)
Net changes in prices and production costs(29,993,699) (370,503) (305,148) (30,669,350)
Extensions, discoveries, additions and improved recovery, net of related costs1,028,410
 47,613
 19,875
 1,095,898
Development costs incurred2,135,800
 500
 1,400
 2,137,700
Revisions of estimated development cost4,087,093
 (34,647) 26,935
 4,079,381
Revisions of previous quantity estimates(4,084,572) 33,285
 (587) (4,051,874)
Accretion of discount3,699,330
 104,464
 53,685
 3,857,479
Net change in income taxes9,550,847
 177,576
 —
 9,728,423
Purchases of reserves in place123,542
 —
 —
 123,542
Sales of reserves in place(23,424) —
 (13,664) (37,088)
Changes in timing and other(576,301) 91,906
 (61,021) (545,416)
December 31, 2015$8,965,467
 $381,124
 $274,805
 $9,621,396
F-48
(1)Other International includes EOG's United Kingdom, China, Canada and Argentina operations.

F-40


EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)(Concluded)

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 

Quarter EndedMar 31 Jun 30 Sep 30 Dec 31
2015       
Net Operating Revenues$2,318,538
 $2,469,701
 $2,172,428
 $1,796,761
Operating Income (Loss)$(172,995) $39,626
 $(6,222,957) $(329,753)
Income (Loss) Before Income Taxes$(236,331) $(11,478) $(6,274,921) $(398,826)
Income Tax Benefit(66,583) (16,746) (2,199,182) (114,530)
Net Income (Loss)$(169,748) $5,268
 $(4,075,739) $(284,296)
Net Income (Loss) Per Share (1)
 
  
  
  
Basic$(0.31) $0.01
 $(7.47) $(0.52)
Diluted$(0.31) $0.01
 $(7.47) $(0.52)
Average Number of Common Shares 
  
  
  
Basic544,998
 545,504
 545,920
 546,432
Diluted544,998
 549,683
 545,920
 546,432
2014 
  
  
  
Net Operating Revenues$4,083,671
 $4,187,556
 $5,118,616
 $4,645,497
Operating Income$1,084,279
 $1,144,730
 $1,786,162
 $1,226,652
Income Before Income Taxes$1,030,789
 $1,100,813
 $1,715,120
 $1,148,593
Income Tax Provision369,861
 394,460
 611,502
 704,005
Net Income$660,928
 $706,353
 $1,103,618
 $444,588
Net Income Per Share (1)
 
  
  
  
Basic$1.22
 $1.30
 $2.03
 $0.82
Diluted$1.21
 $1.29
 $2.01
 $0.81
Average Number of Common Shares 
  
  
  
Basic542,278
 543,099
 543,984
 544,579
Diluted548,071
 548,676
 549,518
 549,153
(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


F-41


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, dated August 23, 1989, as amended and restated effective as of May 3, 2013September 22, 2015 (Exhibit 4.23.1 to EOG's Registration StatementEOG’s Current Report on Form S-8, SEC File No. 333-188352,8-K, filed May 3, 2013)September 28, 2015).
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 of EOG, 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).

E-1


Exhibit
Number
Description
  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, 2028.2028 of Enron Oil & Gas Company.
#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.
  4.74.6-Indenture, dated as of May 18, 2009, between EOG and Wells Fargo Bank, NA,National Association, 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)4.7(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) (SEC File No. 001-09743).
  4.8(b)4.7(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) (SEC File No. 001-09743).
  4.9(a)4.8(a)-Officers' Certificate Establishing 2.95% Senior Notes due 2015 and 4.40% Senior Notes due 2020 of EOG, dated May 20, 2010 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed May 26, 2010) (SEC File No. 001-09743).
  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)4.8(b)-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) (SEC File No. 001-09743).
  4.10(a)4.9(a)-Officers' Certificate Establishing 2.500% Senior Notes due 2016, 4.100% Senior Notes due 2021 and Floating Rate Senior Notes due 2014 of EOG, dated November 23, 2010 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed November 24, 2010) (SEC File No. 001-09743).
  4.10(b)4.9(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) (SEC File No. 001-09743).
  4.10(c)4.9(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) (SEC File No. 001-09743).
  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)4.10(a)-Officers' Certificate Establishing 2.625% Senior Notes due 2023 of EOG, dated September 10, 2012 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed September 11, 2012).
  4.11(b)4.10(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).
  4.11(a)-Officers' Certificate Establishing 2.45% Senior Notes due 2020 of EOG, dated March 21, 2014 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed March 25, 2014).
  4.11(b)-Form of Global Note with respect to the 2.45% Senior Notes due 2020 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed March 25, 2014).
  4.12(a)-Officers' Certificate Establishing 3.15% Senior Notes due 2025 and 3.90% Senior Notes due 2035 of EOG, dated March 17, 2015 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed March 19, 2015).
  4.12(b)-Form of Global Note with respect to the 3.15% Senior Notes due 2025 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed March 19, 2015).
  4.12(c)-Form of Global Note with respect to the 3.90% Senior Notes due 2035 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed March 19, 2015).
  4.13(a)-Officers' Certificate Establishing 4.15% Senior Notes due 2026 and 5.10% Senior Notes due 2036 of EOG, dated January 14, 2016 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed January 15, 2016).
  4.13(b)-Form of Global Note with respect to the 4.15% Senior Notes due 2026 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed January 15, 2016).

E-2


Exhibit Number
Description
4.13(c)-Form of Global Note with respect to the 5.10% Senior Notes due 2036 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed January 15, 2016).
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) (SEC File No. 001-09743).
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).

E-3


Exhibit Number
Description
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 Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 22, 2014) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014).
10.2(g)+-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)10.2(h)-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)10.2(i)-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)10.4(a)-EOG Resources, Inc. 1993 Nonemployee Directors Stock Option Plan, as amended and restated effective May 7, 2002 (Exhibit A to EOG's Proxy Statement, filed March 28, 2002, with respect to EOG's 2002 Annual Meeting of Stockholders) (SEC File No. 001-09743).
10.5(b)10.4(b)-First Amendment to EOG Resources, Inc. 1993 Nonemployee Directors Stock Option Plan, dated effective as of December 30, 2005 (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2005) (SEC File No. 001-09743).
10.6(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)10.5(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)10.5(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)10.5(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).

E-4


10.9(a)
Exhibit Number
Description
  10.6(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)  10.6(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) (SEC File No. 001-09743).
10.9(c)  10.6(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)  10.6(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)  10.7(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)  10.7(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) (SEC File No. 001-09743).
E-7

Exhibit
Number
Description
10.10(c)  10.7(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)  10.8(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)  10.8(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)  10.9(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)  10.9(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+  10.10+-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)  10.11(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)  10.11(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) (SEC File No. 001-09743).
10.15+  10.12+-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) (SEC File No. 001-09743).
10.16(a)  10.13(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)  10.13(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  10.14-Revolving Credit Agreement, dated as of October 11, 2011,July 21, 2015, 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)July 24, 2015).

E-5


Exhibit Number
Description
*     12-Computation of Ratio of Earnings to Fixed Charges.
*     21-Subsidiaries of EOG, as of December 31, 2013.
E-8

Exhibit
Number
Description
2015.
*     23.1-Consent of DeGolyer and MacNaughton.
*      23.2-Opinion of DeGolyer and MacNaughton dated January 31, 2014.February 1, 2016.
*      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, 2013,2015, (ii) the Consolidated Balance Sheets - December 31, 20132015 and 2012,2014, (iii) the Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2013,2015, (iv) the Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 20132015 and (v) the Notes to Consolidated Financial Statements.

+ Management contract, compensatory plan or arrangement

E-6


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, 201425, 2016By:
/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 24th25th day of February, 2014.2016.

Signature
Title
SignatureTitle
/s/ WILLIAM R. THOMASChairman of the Board and Chief Executive Officer and
(William R. Thomas)Director (Principal Executive Officer)
/s/ TIMOTHY K. DRIGGERSVice President and Chief Financial Officer
(Timothy K. Driggers)(Principal Financial Officer)
/s/ ANN D. JANSSENVice President, Accounting
(Ann D. Janssen)(Principal Accounting Officer)
*Director
(Janet F. Clark)
*Director
(Charles R. Crisp)
*Director
(James C. Day)
*Director
(Mark G. Papa)H. Leighton Steward)
*Director
(H. Leighton Steward)Donald F. Textor)
*Director
(Donald F. Textor)
*Director
(Frank G. Wisner)
*By:/s/ MICHAEL P. DONALDSON
(Michael P. Donaldson)
(Attorney-in-fact for persons indicated)



EOG RESOURCES, INC. AND SUBSIDIARIES
EXHIBITS TO FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015
INDEX OF EXHIBITS


Exhibit
Number
Description
*      12-Computation of Ratio of Earnings to Fixed Charges.
*      21-Subsidiaries of EOG, as of December 31, 2015.
*      23.1-Consent of DeGolyer and MacNaughton.
*      23.2-Opinion of DeGolyer and MacNaughton dated February 1, 2016.
*      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, 2015, (ii) the Consolidated Balance Sheets - December 31, 2015 and 2014, (iii) the Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2015, (iv) the Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2015 and (v) the Notes to Consolidated Financial Statements.