10-K 1 eogform10-k.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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

For the fiscal year ended December 31, 2013

or

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

Commission file number: 1-9743

EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)

Delaware
 
47-0684736
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
1111 Bagby, Sky Lobby 2, Houston, Texas   77002
(Address of principal executive offices)     (Zip Code)

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

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

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

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

None.

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o  No x

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o  No x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter.  Common Stock aggregate market value held by non-affiliates as of June 28, 2013: $35,668 million.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.  Class: Common Stock, par value $0.01 per share, 273,119,572 shares outstanding as of February 14, 2014.

Documents incorporated by reference.  Portions of the Definitive Proxy Statement for the registrant's 2014 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2013, are incorporated by reference into Part III of this report.



TABLE OF CONTENTS

 
 
Page
PART I
 
 
 
 
ITEM 1.
Business
1
 
General
1
 
Business Segments
1
 
Exploration and Production
2
 
Marketing
6
 
Wellhead Volumes and Prices
8
 
Competition
9
 
Regulation
9
 
Other Matters
14
 
Executive Officers of the Registrant
15
ITEM 1A.
Risk Factors
17
ITEM 1B.
Unresolved Staff Comments
26
ITEM 2.
Properties
26
 
Oil and Gas Exploration and Production - Properties and Reserves
26
ITEM 3.
Legal Proceedings
30
ITEM 4.
Mine Safety Disclosures
30
 
 
 
PART II
 
 
 
 
ITEM 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
31
ITEM 6.
Selected Financial Data
34
ITEM 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
35
ITEM 7A.
Quantitative and Qualitative Disclosures About Market Risk
55
ITEM 8.
Financial Statements and Supplementary Data
55
ITEM 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
56
ITEM 9A.
Controls and Procedures
56
ITEM 9B.
Other Information
56
 
 
 
PART III
 
 
 
 
ITEM 10.
Directors, Executive Officers and Corporate Governance
57
ITEM 11.
Executive Compensation
57
ITEM 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
58
ITEM 13.
Certain Relationships and Related Transactions, and Director Independence
59
ITEM 14.
Principal Accounting Fees and Services
59
 
 
 
PART IV
 
 
 
 
ITEM 15.
Exhibits, Financial Statement Schedules
59
 
 
 
SIGNATURES
 
 
 
(i)

PART I

ITEM 1.  Business

General

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

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

As of December 31, 2013, EOG employed approximately 2,800 persons, including foreign national employees.

EOG's business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries.  This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis.  EOG is focused on cost-effective utilization of advanced technology associated with three-dimensional seismic and microseismic data, the development of reservoir simulation models, the use of improved drill bits, mud motors and mud additives for horizontal drilling, formation evaluation, and horizontal completion methods.  These advanced technologies are used, as appropriate, throughout EOG to reduce the risks associated with all aspects of oil and gas exploration, development and exploitation.  EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves.  Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

With respect to information on EOG's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by EOG's working interest in the wells or acreage.

Business Segments

EOG's operations are all crude oil and natural gas exploration and production related.  For financial information about our reportable segments (including financial information by segment geographic area), see Note 10 to Consolidated Financial Statements.  For information regarding the risks associated with EOG's foreign operations, see ITEM 1A. Risk Factors.

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, on a crude oil equivalent basis, 44% of EOG's net proved reserves in the United States and Canada were crude oil and condensate, 19% were NGLs and 37% were natural gas.  The majority of these reserves are in long-lived fields with well-established production characteristics.  EOG believes that opportunities exist to increase production through continued development in and around many of these fields and through the utilization of applicable technologies.  EOG also maintains an active exploration program designed to extend fields and add new trends and resource plays to its already broad portfolio.  The following is a summary of significant developments during 2013 and certain 2014 plans for EOG's United States and Canada operations.

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

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

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

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

2


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

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

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

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

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

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

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

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

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

3


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

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

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

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

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

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

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

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

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

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

___________________________
(1) Direct After-Tax Rate of Return.  The calculation of our direct after-tax rate of return with respect to our capital expenditures for our net wells drilled in the Eagle Ford in 2013 is based on the estimated proved reserves ("net" to our interest) associated with such wells, the estimated present value of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling such wells. As such, our after-tax rate of return with respect to our capital expenditures for our net wells drilled in the Eagle Ford in 2013 cannot be calculated from our audited financial statements for fiscal year 2013.
4

Operations Outside the United States and Canada

EOG has operations offshore Trinidad, in the U.K. North Sea and East Irish Sea, in the China Sichuan Basin and in the Neuquén Basin of Argentina, and is evaluating additional exploration, development and exploitation opportunities in these and other select international areas.

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

· holds an 80% working interest in the exploration and production license covering the South East Coast Consortium (SECC) Block offshore Trinidad, except in the Deep Ibis area in which EOG's working interest decreased as a result of a third-party farm-out agreement;
· holds an 80% working interest in the exploration and production license covering the Pelican Field and its related facilities;
· holds a 50% working interest in the exploration and production license covering the EMZ Area offshore Trinidad;
· holds a 100% working interest in a production sharing contract with the Government of Trinidad and Tobago for each of the Modified U(a) Block, Modified U(b) Block and Block 4(a);
· owns a 12% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Caribbean Nitrogen Company Limited; and
· owns a 10% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Nitrogen (2000) Unlimited.

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

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

In 2014, certain agreements with NGC require EOG's Trinidad operations to deliver approximately 490 MMcfd (360 MMcfd, net) of natural gas, under current economic conditions.  EOG intends to fulfill these natural gas delivery obligations by using production from existing proved reserves.

At December 31, 2013, EOG held approximately 39,000 net undeveloped acres in Trinidad.

United Kingdom.   EOG's subsidiary, EOG Resources United Kingdom Limited (EOGUK), owns a 25% non-operating working interest in a portion of Block 49/16a, located in the Southern Gas Basin of the North Sea.  During 2013, production continued from the Valkyrie field in this block.

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

5


In 2007, EOGUK was awarded a license for two blocks in the East Irish Sea – Blocks 110/7b and 110/12a.  In 2009, EOGUK drilled a successful exploratory well in the East Irish Sea Block 110/12a.  Well 110/12-6, in which EOGUK has a 100% working interest, was an oil discovery and was designated the Conwy field.  In 2010, EOGUK added an adjoining field in its East Irish Sea block, designated Corfe, to its overall development plans.  The field development plans for the Conwy/Corfe project were approved by the DECC in March 2012.  In 2013, after drilling an appraisal well, EOG determined that the Corfe field did not contain proved commercial reserves.  The Conwy production platform and pipelines were installed during 2012 and 2013.  In 2013, modifications to the nearby third-party owned Douglas platform began and a crude oil processing module was installed.  The Douglas platform will be used to process Conwy production.  During 2013, the three-well Conwy development drilling program was completed with first production from the Conwy field anticipated in late 2014.

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

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

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

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

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

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

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

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

Marketing

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

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

6


In 2013, EOG's United States and Canada wellhead natural gas production was sold into local markets or transported by pipeline to downstream markets. Pricing, based on the spot market and long-term natural gas contracts, was at prevailing market prices. In 2014, the pricing mechanism for such production is expected to remain the same.
 
In 2013, a large majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices.  The remaining volumes were sold under a contract at prices partially dependent on United States Henry Hub market prices.  The pricing mechanisms for these contracts in Trinidad are expected to remain the same in 2014.

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

In 2013, all wellhead natural gas volumes from China were sold under a contract with prices based on the purchaser's pipeline sales prices to various local market segments.  The pricing mechanism for the contract in China is expected to remain the same in 2014.

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

During 2013, two purchasers each accounted for more than 10% of EOG's total wellhead crude oil and condensate, NGLs and natural gas revenues and gathering, processing and marketing revenues.  Both purchasers are in the crude oil refining industry.  EOG does not believe that the loss of any single purchaser would have a material adverse effect on its financial condition or results of operations.

7

Wellhead Volumes and Prices

The following table sets forth certain information regarding EOG's wellhead volumes of, and average prices for, crude oil and condensate, NGLs and natural gas. The table also presents crude oil equivalent volumes which are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 Mcf of natural gas for each of the years ended December 31, 2013, 2012 and 2011.

Year Ended December 31
 
2013
   
2012
   
2011
 
 
 
   
   
 
Crude Oil and Condensate Volumes (MBbld) (1)
 
   
   
 
United States:
 
   
   
 
Eagle Ford
   
122.3
     
72.3
     
30.2
 
Barnett
   
11.7
     
13.0
     
15.2
 
Other
   
78.1
     
64.0
     
56.6
 
United States
   
212.1
     
149.3
     
102.0
 
Canada
   
7.0
     
7.0
     
7.9
 
Trinidad
   
1.2
     
1.5
     
3.4
 
Other International (2)
   
0.1
     
0.1
     
0.1
 
Total
   
220.4
     
157.9
     
113.4
 
Natural Gas Liquids Volumes (MBbld) (1)
                       
United States:
                       
Eagle Ford
   
18.6
     
11.2
     
3.9
 
Barnett
   
24.2
     
25.8
     
22.6
 
Other
   
21.5
     
18.1
     
15.0
 
United States
   
64.3
     
55.1
     
41.5
 
Canada
   
0.9
     
0.8
     
0.9
 
Total
   
65.2
     
55.9
     
42.4
 
Natural Gas Volumes (MMcfd) (1)
                       
United States:
                       
Eagle Ford
   
115
     
65
     
21
 
Barnett
   
305
     
368
     
403
 
Other
   
488
     
601
     
689
 
United States
   
908
     
1,034
     
1,113
 
Canada
   
76
     
95
     
132
 
Trinidad
   
355
     
378
     
344
 
Other International (2)
   
8
     
9
     
13
 
Total
   
1,347
     
1,516
     
1,602
 
Crude Oil Equivalent Volumes (MBoed) (3)
                       
United States:
                       
Eagle Ford
   
160.2
     
94.4
     
37.7
 
Barnett
   
86.8
     
100.1
     
105.0
 
Other
   
180.9
     
182.1
     
186.4
 
United States
   
427.9
     
376.6
     
329.1
 
Canada
   
20.5
     
23.6
     
30.7
 
Trinidad
   
60.4
     
64.5
     
60.7
 
Other International (2)
   
1.3
     
1.7
     
2.2
 
Total
   
510.1
     
466.4
     
422.7
 
 
                       
Total MMBoe (3)
   
186.2
     
170.7
     
154.3
 

8


Year Ended December 31
 
2013
   
2012
   
2011
 
 
 
   
   
 
Average Crude Oil and Condensate Prices ($/Bbl) (4)
 
   
   
 
United States
 
$
103.81
   
$
98.38
   
$
92.92
 
Canada
   
87.05
     
86.08
     
91.92
 
Trinidad
   
90.30
     
92.26
     
90.62
 
Other International (2)
   
89.11
     
89.57
     
100.11
 
Composite
   
103.20
     
97.77
     
92.79
 
Average Natural Gas Liquids Prices ($/Bbl) (4)
                       
United States
 
$
32.46
   
$
35.41
   
$
50.37
 
Canada
   
39.45
     
44.13
     
52.69
 
Composite
   
32.55
     
35.54
     
50.41
 
Average Natural Gas Prices ($/Mcf) (4)
                       
United States
 
$
3.32
   
$
2.51
   
$
3.92
 
Canada
   
3.08
     
2.49
     
3.71
 
Trinidad
   
3.68
     
3.72
     
3.53
 
Other International (2)
   
6.45
     
5.71
     
5.62
 
Composite
   
3.42
     
2.83
     
3.83
 

(1) Thousand barrels per day or million cubic feet per day, as applicable.
(2)    Other International includes EOG's United Kingdom, China and Argentina operations.
(3) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas.  MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.
(4) Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 11 to Consolidated Financial Statements).

Competition

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

Regulation

United States Regulation of Crude Oil and Natural Gas Production.  Crude oil and natural gas production operations are subject to various types of regulation, including regulation in the United States by federal and state agencies.

United States legislation affecting the oil and gas industry is under constant review for amendment or expansion.  In addition, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations applicable to the oil and gas industry.  Such rules and regulations, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas through restrictions on flaring, require surety bonds for various exploration and production operations and regulate the calculation and disbursement of royalty payments (for federal and state leases), production taxes and ad valorem taxes.

9


A portion of EOG's oil and gas leases in New Mexico, North Dakota, Utah, Wyoming and the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (BLM) and the Bureau of Indian Affairs (BIA) or, in the case of offshore leases, by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), all federal agencies.  Operations conducted by EOG on federal oil and gas leases must comply with numerous additional statutory and regulatory restrictions and, in the case of leases relating to tribal lands, certain tribal environmental and permitting requirements and employment rights regulations.

BLM, BIA and BOEM leases contain relatively standardized terms requiring compliance with detailed regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act (which are subject to change by the BOEM or BSEE).  Under certain circumstances, the BLM, BIA, BOEM or BSEE (as applicable) may require operations on federal leases to be suspended or terminated.  Any such suspension or termination could materially and adversely affect EOG's interests.

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

EOG owns certain gathering and/or processing facilities in the Permian Basin in West Texas and New Mexico, the Barnett Shale in North Texas, the Bakken and Three Forks plays in North Dakota, and the Eagle Ford in South Texas.  State regulation of gathering and processing facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation.  EOG's gathering and processing operations could be materially and adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.

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

EOG also owns crude oil loading facilities in North Dakota and Texas and crude oil unloading facilities in Oklahoma and Louisiana.  Regulation of such facilities is conducted at the state and federal levels and generally includes various safety, environmental, permitting and packaging/labeling requirements.  Additional regulation pertaining to these matters is considered and/or adopted from time to time.  Although EOG cannot predict what effect, if any, any such new regulations might have on its crude-by-rail operations, EOG could be required to incur additional capital expenditures and increased compliance costs depending on the nature and extent of such future regulatory changes.

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

10


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

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

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

Environmental Regulation - United States.  EOG is subject to various federal, state and local laws and regulations covering the discharge of materials into the environment or otherwise relating to the protection of the environment.  These laws and regulations affect EOG's operations and costs as a result of their effect on crude oil and natural gas exploration, development and production operations.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements.

In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control.  Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators.  EOG also could incur costs related to the clean-up of third-party sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such third-party sites.  In addition, EOG could be responsible under environmental laws and regulations for oil and gas properties in which EOG previously owned or currently owns an interest, but was or is not the operator.  Moreover, EOG is subject to the U.S. Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG) emissions and may in the future, as discussed further below, be subject to federal, state and local laws and regulations regarding hydraulic fracturing.

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

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.  In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions, recent U.S. EPA rulemaking may result in the regulation of GHGs as pollutants under the federal Clean Air Act.  EOG supports efforts to understand and address the contribution of human activities to global climate change through the application of sound scientific research and analysis.  Moreover, EOG believes that its strategy to reduce GHG emissions throughout its operations is in the best interest of the environment and is a generally good business practice.

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

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

Currently, the regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements.  However, there have been various proposals to regulate hydraulic fracturing at the federal level.  Any new federal regulations that may be imposed on hydraulic fracturing could result in additional permitting and disclosure requirements (such as the reporting and public disclosure of the chemical additives used in the fracturing process) and in additional operating restrictions.  In April 2012, the U.S. EPA issued regulations specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic compounds (VOC) emissions from natural gas wells that are hydraulically fractured through the use of "green completions" to capture natural gas that would otherwise escape into the air.  The U.S. EPA also issued regulations that establish standards for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves and sweetening units at gas processing plants.  In addition to these federal regulations, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; disclosure of the chemical additives used in hydraulic fracturing operations; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations.  Such federal, state and local permitting and disclosure requirements and operating restrictions and conditions could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing.

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

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 imposed by the respective governments of the countries in which EOG's operations are conducted, and may affect EOG's operations and costs of compliance within that country.  EOG currently has operations in Trinidad, the United Kingdom, China and Argentina.  EOG is unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, including those regarding climate change and hydraulic fracturing, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.  EOG will continue to review the risks to its business and operations associated with all environmental matters, including climate change and hydraulic fracturing.  In addition, EOG will continue to monitor and assess any new policies, legislation, regulations and treaties in the areas where it operates to determine the impact on its operations and take appropriate actions, where necessary.

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 NGLs production comprised a larger portion of EOG's production mix in 2013 than in prior years and is expected to comprise an even larger portion in 2014.  Average crude oil and condensate prices received by EOG for production in the United States and Canada increased 6% in 2013, 5% in 2012 and 24% in 2011, each as compared to the immediately preceding year.  Average NGLs prices received by EOG for production in the United States and Canada decreased 8% in 2013 and 30% in 2012 and increased 21% in 2011, each as compared to the immediately preceding year.  During the last three years, average United States and Canada wellhead natural gas prices have fluctuated, at times rather dramatically.  These fluctuations resulted in a 31% increase in the average wellhead natural gas price received by EOG for production in the United States and Canada in 2013, a 36% decrease in 2012 and an 8% decrease in 2011, each as compared to the immediately preceding year.  Due to the many uncertainties associated with the world political environment, the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in prices of crude oil and condensate, NGLs and natural gas in the future.  For additional discussion regarding changes in crude oil and natural gas prices and the risks that such changes may present to EOG, see ITEM 1A. Risk Factors.

Including the impact of EOG's 2014 crude oil derivative contracts (exclusive of options) and based on EOG's tax position, EOG's price sensitivity in 2014 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $44 million for net income and $65 million for cash flows from operating activities.  Including the impact of EOG's 2014 natural gas derivative contracts (exclusive of options) and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2014 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf increase or decrease in wellhead natural gas price is approximately $13 million for net income and $19 million for cash flows from operating activities.  For a summary of EOG's financial commodity derivative contracts at February 24, 2014, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Derivative Transactions.  For a summary of EOG's financial commodity derivative contracts at December 31, 2013, see Note 11 to Consolidated Financial Statements.

Risk Management.  EOG engages in price risk management activities from time to time.  These activities are intended to manage EOG's exposure to fluctuations in prices of crude oil and natural gas.  EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk.  See Note 11 to Consolidated Financial Statements.  In addition to financial transactions, from time to time EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions.  Under the provisions of the Derivatives and Hedging Topic of the Financial Accounting Standards Board's Accounting Standards Codification, these physical commodity contracts qualify for the normal purchases and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting.  The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.  For a summary of EOG's financial commodity derivative contracts at February 24, 2014, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Derivative Transactions.  For a summary of EOG's financial commodity derivative contracts at December 31, 2013, see Note 11 to Consolidated Financial Statements.

14


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

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

In addition to the above-described risks, EOG's operations outside the United States are subject to certain risks, including the risk of increases in taxes and governmental royalties, changes in laws and policies governing the operations of foreign-based companies, expropriation of assets, unilateral or forced renegotiation or modification of existing contracts with governmental entities, currency restrictions and exchange rate fluctuations.  Please refer to ITEM 1A. Risk Factors for further discussion of the risks to which EOG is subject with respect to its operations outside the United States.

Texas Severance Tax Rate Reduction.  Natural gas production from qualifying Texas natural gas wells spudded or completed after August 31, 1996 is entitled to a reduced severance tax rate for the first 120 consecutive months of production.  However, the cumulative value of the tax reduction cannot exceed 50 percent of the drilling and completion costs incurred on a well-by-well basis.

Executive Officers of the Registrant

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

Name
Age
Position
 
 
 
William R. Thomas
61
Chairman of the Board and Chief Executive Officer
 
 
 
Gary L. Thomas
64
Chief Operating Officer
 
 
 
Lloyd W. Helms, Jr.
56
Executive Vice President, Exploration and Production
 
 
 
David W. Trice
43
Executive Vice President, Exploration and Production
 
 
 
Timothy K. Driggers
52
Vice President and Chief Financial Officer
 
 
 
Michael P. Donaldson
51
Vice President, General Counsel and Corporate Secretary

15

William R. Thomas was elected Chairman of the Board and Chief Executive Officer effective January 2014.  He was elected Senior Vice President and General Manager of EOG's Fort Worth, Texas, office in June 2004, Executive Vice President and General Manager of EOG's Fort Worth, Texas, office in February 2007 and Senior Executive Vice President, Exploitation in February 2011.  He subsequently served as Senior Executive Vice President, Exploration from July 2011 to September 2011, as President from September 2011 to July 2013 and as President and Chief Executive Officer from July 2013 to December 2013.  Mr. Thomas joined a predecessor of EOG in January 1979.  Mr. Thomas is EOG's principal executive officer.

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

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

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

Timothy K. Driggers was elected Vice President and Chief Financial Officer in July 2007.  He was elected Vice President and Controller of EOG in October 1999, was subsequently named Vice President, Accounting and Land Administration in October 2000 and Vice President and Chief Accounting Officer in August 2003.  Mr. Driggers is EOG's principal financial officer.  Mr. Driggers joined a predecessor of EOG in August 1995.

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

16


ITEM 1A.  Risk Factors


Our business and operations are subject to many risks.  The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial.  If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations or cash flows could be materially and adversely affected and the trading price of our common stock could decline.  The following risk factors should be read in conjunction with the other information contained herein, including the consolidated financial statements and the related notes.  Unless the context requires otherwise, "we," "us," "our" and "EOG" refer to EOG Resources, Inc. and its subsidiaries.

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

Prices for crude oil and natural gas (including prices for natural gas liquids (NGLs) and condensate) fluctuate widely.  Among the factors that can or could cause these price fluctuations are:
 
· the level of consumer demand;
· domestic and worldwide supplies of crude oil, NGLs and natural gas;
· the price and quantity of imported and exported crude oil, NGLs and natural gas;
· weather conditions and changes in weather patterns;
· domestic and international drilling activity;
· the availability, proximity and capacity of appropriate transportation facilities, gathering, processing and compression facilities and refining facilities;
· worldwide economic and political conditions, including political instability or armed conflict in oil and gas producing regions;
· the price and availability of, and demand for, competing energy sources, including alternative energy sources;
· the nature and extent of governmental regulation, including environmental regulation, regulation of derivatives transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
· the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others; and
· the effect of worldwide energy conservation measures.
 
Our cash flows and results of operations depend to a great extent on the prevailing prices for crude oil and natural gas.  Prolonged or substantial declines in crude oil and/or natural gas prices may materially and adversely affect our liquidity, the amount of cash flows we have available for our capital expenditures and other operating expenses, our ability to access the credit and capital markets and our results of operations.

In addition, if we expect or experience significant sustained decreases in crude oil and natural gas prices such that the expected future cash flows from our crude oil and natural gas properties falls below the net book value of our properties, we may be required to write down the value of our crude oil and natural gas properties.  Any such asset impairments could materially and adversely affect our results of operations and, in turn, the trading price of our common stock.

Drilling crude oil and natural gas wells is a high-risk activity and subjects us to a variety of risks that we cannot control.

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

17


Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled, the cost of such operations may increase and/or our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:
 
· unexpected drilling conditions;
· title problems;
· pressure or irregularities in formations;
· equipment failures or accidents;
· adverse weather conditions, such as winter storms, flooding and hurricanes, and changes in weather patterns;
· compliance with, or changes in, environmental, health and safety laws and regulations relating to air emissions, hydraulic fracturing, access to and use of water, and disposal of produced water, drilling fluids and other wastes, laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas, and other laws and regulations, such as tax laws and regulations;
· the availability and timely issuance of required federal, state, tribal and other permits and licenses, which may be affected by (among other things) government shutdowns or other suspensions of, or delays in, government services;
· the availability of, costs associated with and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, rail cars, crude oil hauling trucks and qualified drivers and facilities and equipment to gather, process, compress, transport and market crude oil, natural gas and related commodities; and
· the costs of, or shortages or delays in the availability of, drilling rigs, hydraulic fracturing services, pressure pumping equipment and supplies, tubular materials, water, sand, disposal facilities, qualified personnel and other necessary facilities, equipment, materials, supplies and services.
 
Our failure to recover our investment in wells, increases in the costs of our drilling operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third-party operators in each case due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations.  For related discussion of the risks and potential losses and liabilities inherent in our crude oil and natural gas operations generally, see the immediately following risk factor.

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

Our crude oil and natural gas operations and supporting activities and operations are subject to all of the risks associated with exploring and drilling for, and producing, gathering, processing, compressing and transporting, crude oil and natural gas, including the risks of:
 
· well blowouts and cratering;
· loss of well control;
· crude oil spills, natural gas leaks and pipeline ruptures;
· pipe failures and casing collapses;
· uncontrollable flows of crude oil, natural gas, formation water or drilling fluids;
· releases of chemicals, wastes or pollutants;
· adverse weather conditions, such as winter storms, flooding and hurricanes, and other natural disasters;
· fires and explosions;
· terrorism, vandalism and physical, electronic and cyber security breaches;
· formations with abnormal or unexpected pressures;
· leaks or spills in connection with, or associated with, the gathering, processing, compression and transportation of crude oil and natural gas; and
18

· malfunctions of, or damage to, gathering, processing, compression and transportation facilities and equipment and other facilities and equipment utilized in support of our crude oil and natural gas operations.
 
If any of these events occur, we could incur losses, liabilities and other additional costs as a result of:
 
· injury or loss of life;
· damage to, or destruction of, property, facilities, equipment and crude oil and natural gas reservoirs;
· pollution or other environmental damage;
· regulatory investigations and penalties as well as clean-up and remediation responsibilities and costs;
· suspension or interruption of our operations, including due to injunction;
· repairs necessary to resume operations; and
· compliance with laws and regulations enacted as a result of such events.


We maintain insurance against many, but not all, such losses and liabilities in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable.  The occurrence of any of these events and any losses or liabilities incurred as a result of such events, if uninsured or in excess of our insurance coverage, would reduce the funds available to us for our onshore and offshore operations and could, in turn, have a material adverse effect on our business, financial condition and results of operations.

Our ability to sell and deliver our crude oil and natural gas production could be materially and adversely affected if adequate gathering, processing, compression and transportation facilities and equipment are unavailable.

The sale of our crude oil and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities and equipment owned by third parties.  These facilities may be temporarily unavailable to us due to market conditions, regulatory reasons, mechanical reasons or other factors or conditions, and may not be available to us in the future on terms we consider acceptable, if at all.  In particular, in certain newer shale plays, the capacity of gathering, processing, compression and transportation facilities and equipment may not be sufficient to accommodate potential production from existing and new wells.  In addition, lack of financing, construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new gathering, processing, compression and transportation facilities and equipment by third parties or us, and we may experience delays or increased costs in accessing the pipelines, gathering systems or rail systems necessary to transport our production to points of sale or delivery.

Any significant change in market or other conditions affecting gathering, processing, compression or transportation facilities and equipment or the availability of these facilities, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.

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

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

19


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

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

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

Local, state, national and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years.  EOG is unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.

In addition, there have been various proposals to regulate hydraulic fracturing in the U.S. at the federal level.  Currently, the regulation of hydraulic fracturing in the U.S. is primarily conducted at the state level (and, in Canada, at the provincial and local levels) through permitting and other compliance requirements.  Any new federal regulations that may be imposed on hydraulic fracturing could result in additional permitting and disclosure requirements and in additional operating restrictions.  Moreover, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations.  Any such federal or state requirements, restrictions or conditions could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing.  Accordingly, our production of crude oil and natural gas could be materially and adversely affected.  For additional discussion regarding climate change regulation and hydraulic fracturing regulation, see Climate Change - United States, Hydraulic Fracturing - United States and Environmental Regulation - Canada under ITEM 1. Business - Regulation.

We will continue to monitor and assess any proposed or new policies, legislation, regulations and treaties in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. We are unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations and financial condition.  For related discussion, see the risk factor below regarding the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act with respect to regulation of derivatives transactions and entities (such as EOG) that participate in such transactions.

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

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

A portion of our crude oil and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions, the unavailability of gathering, processing, compression, transportation or refining facilities or equipment or field labor issues, or intentionally as a result of market conditions such as crude oil or natural gas prices that we deem uneconomic.  If a substantial amount of our production is interrupted or shut in, our cash flows and, in turn, our financial condition and results of operations could be materially and adversely affected.

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

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners.  As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties.  Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects.  In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil or natural gas prices.  These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, lower production and materially and adversely affect our financial condition and results of operations.

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

From time to time, we seek to acquire crude oil and natural gas properties.  Although we perform reviews of properties to be acquired in a manner that we believe is duly diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems (such as title or environmental issues), nor may they permit us to become sufficiently familiar with the properties in order to assess fully their deficiencies and potential.  Even when problems with a property are identified, we often may assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements.  In addition, there are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves (as discussed further below), actual future production rates and associated costs with respect to acquired properties.  Actual reserves, production rates and costs may vary substantially from those assumed in our estimates.  In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.

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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 assets and borrowings under other uncommitted credit facilities and, to a lesser extent and if and as necessary, bank borrowings, borrowings under our revolving credit facility and public and private equity and debt offerings.

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

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

We have various customers for the crude oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including several financial institutions and affiliates of financial institutions.  Domestic and global economic conditions, including the financial condition of financial institutions generally, while weakened in recent years, have improved somewhat.  However, there continues to be weakness and volatility in domestic and global financial markets, and there is the possibility that lenders may react by tightening credit.  These conditions and factors may adversely affect the ability of our customers and other contractual counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, as well as their ability to access the credit and capital markets for such purposes.

Moreover, our customers and other contractual counterparties may be unable to satisfy their contractual obligations to us for reasons unrelated to these conditions and factors, such as the unavailability of required facilities or equipment due to mechanical failure or market conditions.  Furthermore, if a customer is unable to satisfy its contractual obligation to purchase crude oil, natural gas or related commodities from us, we may be unable to sell such production to another customer on terms we consider acceptable, if at all, due to the geographic location of such production, the availability, proximity or capacity of gathering, processing, compression and transportation facilities or market or other factors and conditions.

The inability of our customers and other contractual counterparties to pay amounts owed to us and to otherwise satisfy their contractual obligations to us may materially and adversely affect our business, financial condition, results of operations and cash flows.

22


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

We compete with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses and leases, properties and reserves and access to the facilities, equipment, materials, services and employees and other contract personnel (including geologists, geophysicists, engineers and other specialists) necessary to explore for, develop, produce, market and transport crude oil and natural gas.  In addition, many of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions and strong governmental relationships in countries in which we may seek new or expanded entry.  As a consequence, we may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights or in accessing necessary services, facilities, equipment, materials and personnel.  In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels.  We also face competition, to a lesser extent, from competing energy sources, such as alternative energy sources.

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

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

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

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

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

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In addition, our exploration, exploitation and development activities and equipment can be adversely affected by extreme weather conditions, such as winter storms, flooding and hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment.  Such extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs, the installation and operation of gathering, processing, compression and transportation facilities and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression and transportation services.  Such extreme weather conditions and changes in weather patterns may materially and adversely affect our business and, in turn, our financial condition and results of operations.

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

We use derivative instruments (primarily financial price swaps, options, swaptions and collar and basis swap contracts) to hedge the impact of fluctuations in crude oil and natural gas prices on our results of operations and cash flows.  To the extent that we engage in hedging activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of increases in crude oil and natural gas prices above the prices established by our hedging contracts.  In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.

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

As discussed in the risk factor immediately above, we use derivative instruments to hedge the impact of fluctuations in crude oil and natural gas prices on our results of operations and cash flows.  In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which, among other matters, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (CFTC), adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act.  The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivatives activities.  Although a number of the rules necessary to implement the Dodd-Frank Act are yet to be adopted, the CFTC has issued several rules to implement the Dodd-Frank Act, including a rule establishing an "end-user" exception to mandatory clearing (End-User Exception), and a proposed rule imposing position limits (Position Limits Rule).

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

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

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

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

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

· increases in taxes and governmental royalties;
· changes in laws and policies governing operations of foreign-based companies;
· loss of revenue, loss of or damage to equipment, property and other assets and interruption of operations as a result of expropriation, nationalization, acts of terrorism, war, civil unrest and other political risks;
· unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities;
· difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations; and
· currency restrictions and exchange rate fluctuations.
 
Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation.  The realization of any of these factors could materially and adversely affect our business, financial condition and results of operations.

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

The reporting currency for our financial statements is the U.S. dollar.  However, certain of our subsidiaries are located in countries other than the U.S. and have functional currencies other than the U.S. dollar.  The assets, liabilities, revenues and expenses of certain of these foreign subsidiaries are denominated in currencies other than the U.S. dollar.  To prepare our consolidated financial statements, we must translate those assets, liabilities, revenues and expenses into U.S. dollars at then-applicable exchange rates.  Consequently, increases and decreases in the value of the U.S. dollar versus other currencies will affect the amount of these items in our consolidated financial statements, even if the amount has not changed in the original currency.  These translations could result in changes to our results of operations from period to period.  For the fiscal year ended December 31, 2013, approximately 3% of our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.

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

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

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

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

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

ITEM 1B.  Unresolved Staff Comments

Not applicable.

ITEM 2.  Properties

Oil and Gas Exploration and Production - Properties and Reserves

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

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in "Supplemental Information to Consolidated Financial Statements" represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas that cannot be measured in an exact manner.  The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment.  As a result, estimates by different engineers normally vary.  In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate (upward or downward).  Accordingly, reserve estimates are often different from the quantities ultimately recovered.  The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.  For related discussion, see ITEM 1A. Risk Factors and "Supplemental Information to Consolidated Financial Statements."

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

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Acreage.  The following table summarizes EOG's developed and undeveloped acreage at December 31, 2013. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.

 
 
Developed
   
Undeveloped
   
Total
 
 
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
 
 
   
   
   
   
   
 
United States
   
1,880,995
     
1,452,786
     
4,120,777
     
2,706,054
     
6,001,772
     
4,158,840
 
Canada
   
1,201,351
     
1,007,418
     
537,253
     
482,672
     
1,738,604
     
1,490,090
 
Trinidad
   
75,667
     
65,669
     
48,520
     
38,816
     
124,187
     
104,485
 
United Kingdom
   
8,797
     
2,570
     
71,054
     
53,886
     
79,851
     
56,456
 
China
   
130,548
     
130,548
     
-
     
-
     
130,548
     
130,548
 
Argentina
   
-
     
-
     
211,016
     
95,052
     
211,016
     
95,052
 
Total
   
3,297,358
     
2,658,991
     
4,988,620
     
3,376,480
     
8,285,978
     
6,035,471
 


Most of our undeveloped oil and gas leases, particularly in the United States, are subject to lease expiration if initial wells are not drilled within a specified period, generally between three and five years.  Approximately 0.7 million net acres will expire in 2014, 0.5 million net acres will expire in 2015 and 0.3 million net acres will expire in 2016 if production is not established or we take no other action to extend the terms of the leases or concessions.  In the ordinary course of business, based on our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future.

Producing Well Summary.  EOG operated 16,261gross and 14,432 net producing crude oil and natural gas wells at December 31, 2013.  Gross crude oil and natural gas wells include 1,514 wells with multiple completions.

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


27


Drilling and Acquisition Activities.  During the years ended December 31, 2013, 2012 and 2011, EOG expended $7.0 billion, $7.1 billion and $6.6 billion, respectively, for exploratory and development drilling and acquisition of leases and producing properties, including asset retirement obligations of $134 million, $127 million and $133 million, respectively.  The following tables set forth the results of the gross crude oil and natural gas wells drilled and completed for the years ended December 31, 2013, 2012 and 2011:

 
 
Gross Development Wells Completed
   
Gross Exploratory Wells Completed
 
 
 
Crude Oil
   
Natural Gas
   
Dry Hole
   
Total
   
Crude Oil
   
Natural Gas
   
Dry Hole
   
Total
 
 
 
   
   
   
   
   
   
   
 
2013
 
   
   
   
   
   
   
   
 
United States
   
909
     
57
     
22
     
988
     
7
     
2
     
3
     
12
 
Canada
   
85
     
-
     
-
     
85
     
1
     
-
     
-
     
1
 
Trinidad
   
-
     
1
     
-
     
1
     
-
     
1
     
-
     
1
 
United Kingdom
   
3
     
-
     
-
     
3
     
-
     
-
     
1
     
1
 
China
   
-
     
-
     
-
     
-
     
-
     
1
     
-
     
1
 
Argentina
   
-
     
-
     
-
     
-
     
1
     
-
     
-
     
1
 
Total
   
997
     
58
     
22
     
1,077
     
9
     
4
     
4
     
17
 
 
                                                               
2012
                                                               
United States
   
844
     
135
     
8
     
987
     
8
     
7
     
1
     
16
 
Canada
   
83
     
3
     
-
     
86
     
3
     
-
     
-
     
3
 
China
   
-
     
-
     
-
     
-
     
-
     
-
     
1
     
1
 
Argentina
   
-
     
-
     
-
     
-
     
2
     
-
     
-
     
2
 
Total
   
927
     
138
     
8
     
1,073
     
13
     
7
     
2
     
22
 
 
                                                               
2011
                                                               
United States
   
851
     
203
     
24
     
1,078
     
11
     
4
     
2
     
17
 
Canada
   
105
     
9
     
-
     
114
     
2
     
-
     
-
     
2
 
Trinidad
   
-
     
7
     
-
     
7
     
-
     
-
     
-
     
-
 
China
   
-
     
-
     
-
     
-
     
-
     
1
     
2
     
3
 
Total
   
956
     
219
     
24
     
1,199
     
13
     
5
     
4
     
22
 


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, 2012 and 2011:

 
 
Net Development Wells Completed
   
Net Exploratory Wells Completed
 
 
 
Crude Oil
   
Natural Gas
   
Dry Hole
   
Total
   
Crude Oil
   
Natural Gas
   
Dry Hole
   
Total
 
 
 
   
   
   
   
   
   
   
 
2013
 
   
   
   
   
   
   
   
 
United States
   
788
     
50
     
15
     
853
     
6
     
2
     
3
     
11
 
Canada
   
76
     
-
     
-
     
76
     
1
     
-
     
-
     
1
 
Trinidad
   
-
     
1
     
-
     
1
     
-
     
1
     
-
     
1
 
United Kingdom
   
3
     
-
     
-
     
3
     
-
     
-
     
1
     
1
 
China
   
-
     
-
     
-
     
-
     
-
     
1
     
-
     
1
 
Argentina
   
-
     
-
     
-
     
-
     
1
     
-
     
-
     
1
 
Total
   
867
     
51
     
15
     
933
     
8
     
4
     
4
     
16
 
 
                                                               
2012
                                                               
United States
   
705
     
100
     
7
     
812
     
7
     
6
     
1
     
14
 
Canada
   
80
     
3
     
-
     
83
     
3
     
-
     
-
     
3
 
China
   
-
     
-
     
-
     
-
     
-
     
-
     
1
     
1
 
Argentina
   
-
     
-
     
-
     
-
     
1
     
-
     
-
     
1
 
Total
   
785
     
103
     
7
     
895
     
11
     
6
     
2
     
19
 
 
                                                               
2011
                                                               
United States
   
687
     
138
     
18
     
843
     
9
     
3
     
2
     
14
 
Canada
   
95
     
4
     
-
     
99
     
2
     
-
     
-
     
2
 
Trinidad
   
-
     
7
     
-
     
7
     
-
     
-
     
-
     
-
 
China
   
-
     
-
     
-
     
-
     
-
     
1
     
2
     
3
 
Total
   
782
     
149
     
18
     
949
     
11
     
4
     
4
     
19
 


EOG participated in the drilling of wells that were in progress at the end of the period as set out in the table below for the years ended December 31, 2013, 2012 and 2011:

 
 
Wells in Progress at End of Period
 
 
 
2013
   
2012
   
2011
 
 
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
 
 
   
   
   
   
   
 
United States
   
320
     
280
     
324
     
267
     
359
     
282
 
Canada
   
13
     
8
     
-
     
-
     
-
     
-
 
Trinidad
   
-
     
-
     
1
     
1
     
-
     
-
 
United Kingdom
   
-
     
-
     
-
     
-
     
3
     
2
 
China
   
2
     
2
     
-
     
-
     
1
     
1
 
Argentina
   
1
     
1
     
-
     
-
     
-
     
-
 
Total
   
336
     
291
     
325
     
268
     
363
     
285
 


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, 2012 and 2011:

 
 
Gross Acquired Wells
   
Net Acquired Wells
 
 
 
Crude Oil
   
Natural Gas
   
Total
   
Crude Oil
   
Natural Gas
   
Total
 
 
 
   
   
   
   
   
 
2013
 
   
   
   
   
   
 
United States
   
68
     
27
     
95
     
50
     
21
     
71
 
Total
   
68
     
27
     
95
     
50
     
21
     
71
 
 
                                               
2012
                                               
United States
   
49
     
272
     
321
     
23
     
136
     
159
 
Total
   
49
     
272
     
321
     
23
     
136
     
159
 
 
                                               
2011
                                               
United States
   
8
     
-
     
8
     
4
     
-
     
4
 
Canada
   
-
     
5
     
5
     
-
     
5
     
5
 
Total
   
8
     
5
     
13
     
4
     
5
     
9
 
 
All of EOG's drilling activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors.  EOG does not own drilling equipment.  EOG's other property, plant and equipment primarily includes gathering, transportation and processing infrastructure assets, crude-by-rail assets, along with sand mine and sand processing assets which support EOG's exploration and production activities.

ITEM 3.  Legal Proceedings

The information required by this Item is set forth under the "Contingencies" caption in Note 7 of the Notes to Consolidated Financial Statements and is incorporated by reference herein.
 
ITEM 4.  Mine Safety Disclosures

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

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


On February 24, 2014, EOG's Board of Directors (Board) approved a two-for-one stock split in the form of a stock dividend, payable on March 31, 2014, to stockholders of record as of March 17, 2014.  Also on February 24, 2014, the Board increased the quarterly cash dividend on the common stock by 33% from the current $0.09375 per share post-split ($0.1875 per share pre-split) to $0.125 per share post-split ($0.25 per share pre-split), effective beginning with the dividend to be paid on April 30, 2014, to stockholders of record as of April 16, 2014.
 
As of February 12, 2014, there were approximately 1,800 record holders and approximately 270,000 beneficial owners of EOG's common stock.

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


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
                 

(1)
The 47,473 total shares for the quarter ended December 31, 2013, and the 427,409 shares for the full year 2013 consist solely of shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of stock-settled stock appreciation rights or the vesting of restricted stock or restricted stock unit grants or (ii) in payment of the exercise price of employee stock options.  These shares do not count against the 10 million aggregate share repurchase authorization of EOG's Board discussed below.
(2)
In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock.  During 2013, EOG did not repurchase any shares under the Board-authorized repurchase program.

32

Comparative Stock Performance

The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the United States Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that EOG specifically requests that such information be treated as "soliciting material" or specifically incorporates such information by reference into such a filing.

The performance graph shown below compares the cumulative five-year total return to stockholders on EOG's common stock as compared to the cumulative five-year total returns on the Standard and Poor's 500 Index (S&P 500) and the Standard and Poor's 500 Oil & Gas Exploration & Production Index (S&P O&G E&P).  The comparison was prepared based upon the following assumptions:

1. $100 was invested on December 31, 2008 in each of the following:  common stock of EOG, the S&P 500 and the S&P O&G E&P.
2.    Dividends are reinvested.

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


*Cumulative total return assumes reinvestment of dividends.

   
2008
   
2009
   
2010
   
2011
   
2012
   
2013
 
   
   
   
   
   
   
 
EOG
   
$
100.00
   
$
147.36
   
$
139.26
   
$
151.07
   
$
186.45
   
$
260.09
 
S&P 500
   
$
100.00
   
$
126.46
   
$
145.51
   
$
148.58
   
$
172.35
   
$
228.18
 
S&P O&G E&P
   
$
100.00
   
$
142.10
   
$
155.27
   
$
145.29
   
$
150.59
   
$
191.99
 

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
 



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
 


34


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

Overview

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

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

Operations

Several important developments have occurred since January 1, 2013.

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

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

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


35


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

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

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

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

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

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

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

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

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

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

37

Results of Operations

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

Net Operating Revenues

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

38

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

Year Ended December 31
 
2013
   
2012
   
2011
 
 
 
   
   
 
Crude Oil and Condensate Volumes (MBbld) (1)
 
   
   
 
United States
   
212.1
     
149.3
     
102.0
 
Canada
   
7.0
     
7.0
     
7.9
 
Trinidad
   
1.2
     
1.5
     
3.4
 
Other International (2)
   
0.1
     
0.1
     
0.1
 
Total
   
220.4
     
157.9
     
113.4
 
 
                       
Average Crude Oil and Condensate Prices ($/Bbl) (3)
                       
United States
 
$
103.81
   
$
98.38
   
$
92.92
 
Canada
   
87.05
     
86.08
     
91.92
 
Trinidad
   
90.30
     
92.26
     
90.62
 
Other International (2)
   
89.11
     
89.57
     
100.11
 
Composite
   
103.20
     
97.77
     
92.79
 
 
                       
Natural Gas Liquids Volumes (MBbld) (1)
                       
United States
   
64.3
     
55.1
     
41.5
 
Canada
   
0.9
     
0.8
     
0.9
 
Total
   
65.2
     
55.9
     
42.4
 
 
                       
Average Natural Gas Liquids Prices ($/Bbl) (3)
                       
United States
 
$
32.46
   
$
35.41
   
$
50.37
 
Canada
   
39.45
     
44.13
     
52.69
 
Composite
   
32.55
     
35.54
     
50.41
 
 
                       
Natural Gas Volumes (MMcfd) (1)
                       
United States
   
908
     
1,034
     
1,113
 
Canada
   
76
     
95
     
132
 
Trinidad
   
355
     
378
     
344
 
Other International (2)
   
8
     
9
     
13
 
Total
   
1,347
     
1,516
     
1,602
 
 
                       
Average Natural Gas Prices ($/Mcf) (3)
                       
United States
 
$
3.32
   
$
2.51
   
$
3.92
 
Canada
   
3.08
     
2.49
     
3.71
 
Trinidad
   
3.68
     
3.72
     
3.53
 
Other International (2)
   
6.45
     
5.71
     
5.62
 
Composite
   
3.42
     
2.83
     
3.83
 
 
                       
Crude Oil Equivalent Volumes (MBoed) (4)
                       
United States
   
427.9
     
376.6
     
329.1
 
Canada
   
20.5
     
23.6
     
30.7
 
Trinidad
   
60.4
     
64.5
     
60.7
 
Other International (2)
   
1.3
     
1.7
     
2.2
 
Total
   
510.1
     
466.4
     
422.7
 
 
                       
Total MMBoe (4)
   
186.2
     
170.7
     
154.3
 

(1)    Thousand barrels per day or million cubic feet per day, as applicable.
(2) Other International includes EOG's United Kingdom, China and Argentina operations.
(3) Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 11 to Consolidated Financial Statements).
(4) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas.  Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.  MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

39

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

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

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

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

Gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas.  Purchases and sales of third-party crude oil and natural gas are utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities.  Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs.

During 2013, gathering, processing and marketing revenues and marketing costs increased, compared to 2012, primarily as a result of increased crude oil marketing activities.  Gathering, processing and marketing revenues less marketing costs in 2013 decreased $66 million, compared to 2012, due primarily to lower margins on crude oil marketing activities.

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

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

40


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

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

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

Operating and Other Expenses

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

 
 
2013
   
2012
 
 
 
   
 
Lease and Well
 
$
5.94
   
$
5.85
 
Transportation Costs
   
4.58
     
3.52
 
Depreciation, Depletion and Amortization (DD&A) -
               
Oil and Gas Properties
   
18.79
     
17.71
 
Other Property, Plant and Equipment
   
0.55
     
0.85
 
General and Administrative (G&A)
   
1.87
     
1.94
 
Net Interest Expense
   
1.26
     
1.25
 
Total (1)
 
$
32.99
   
$
31.12
 
 
(1) Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

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

Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property.  Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses.  Operating and maintenance costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power.  Workovers are operations to restore or maintain production from existing wells.

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

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

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

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

DD&A expenses in 2013 increased $431 million to $3,601 million from $3,170 million in 2012.  DD&A expenses associated with oil and gas properties in 2013 were $473 million higher than in 2012 primarily due to increased production in the United States ($347 million) and higher unit rates in the United States ($133 million) and Trinidad ($44 million), partially offset by a decrease in production in Canada ($29 million) and Trinidad ($10 million) and lower unit rates in Canada ($12 million).  DD&A unit rates in the United States increased due primarily to downward revisions of natural gas reserves at December 31, 2012, and a proportional increase in production from higher cost properties.

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

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

Net interest expense of $235 million in 2013 was $22 million higher than 2012 due primarily to interest expense on the $1,250 million principal amount of 2.625% Senior Notes due 2023 issued in September 2012 ($23 million).  This was partially offset by a reduction in interest expense on the 6.125% Senior Notes, which were repaid at maturity in October 2013 ($6 million).

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 ($9 million).

Exploration costs of $161 million in 2013 decreased $25 million from $186 million in 2012 primarily due to decreased geological and geophysical expenditures in the United States.

Impairments include amortization of unproved oil and gas property costs; as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets.  Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term.  When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the asset.  If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC).  In certain instances, EOG utilizes accepted bids as the basis for determining fair value.

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

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

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

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

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

43


2012 compared to 2011.  During 2012, operating expenses of $10,203 million were $2,190 million higher than the $8,013 million incurred in 2011.  The following table presents the costs per Boe for the years ended December 31, 2012 and 2011:
 
   
2012
   
2011
 
   
   
 
Lease and Well
   
$
5.85
   
$
6.11
 
Transportation Costs
     
3.52
     
2.79
 
DD&A -
                 
Oil and Gas Properties
     
17.71
     
15.52
 
Other Property, Plant and Equipment
     
0.85
     
0.79
 
G&A
1.94
1.98
Net Interest Expense
     
1.25
     
1.36
 
Total (1)
   
$
31.12
   
$
28.55
 

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

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

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

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

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

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

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

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

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

44


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

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

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

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

Capital Resources and Liquidity

Cash Flow

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

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

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

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

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

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

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

Total Expenditures

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

 
 
2013
   
2012
   
2011
 
Expenditure Category
 
   
   
 
Capital
 
   
   
 
Drilling and Facilities
 
$
6,044
   
$
6,184
   
$
5,878
 
Leasehold Acquisitions (1)
   
414
     
505
     
301
 
Property Acquisitions
   
120
     
1
     
4
 
Capitalized Interest
   
49
     
50
     
58
 
Subtotal
   
6,627
     
6,740
     
6,241
 
Exploration Costs
   
161
     
186
     
172</