UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2012

or

 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  No 

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  No 

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  No 

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  No 

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.  

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  Accelerated filer  Non-accelerated filer  Smaller reporting company 

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

Yes  No 

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 29, 2012: 

$24,304,558,319.

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, 271,746,510 shares outstanding as of February 15, 2013.

Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2013 Annual Meeting of 

Stockholders, to be filed within 120 days after December 31, 2012, are incorporated by reference into Part III of this report.
(i)

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 13

 Executive Officers of the Registrant 15

ITEM 1A. Risk Factors 16

ITEM 1B. Unresolved Staff Comments 24

ITEM 2. Properties 24

 Oil and Gas Exploration and Production - Properties and Reserves 24

ITEM 3. Legal Proceedings 27

ITEM 4. Mine Safety Disclosures 27

PART II

ITEM 5. Market for Registrant's Common Equity, Related Stockholder Matters and

 Issuer Purchases of Equity Securities 28

ITEM 6. Selected Financial Data 31

ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 32

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk 52

ITEM 8. Financial Statements and Supplementary Data 52

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 52

ITEM 9A. Controls and Procedures 52

ITEM 9B. Other Information 53

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance 54

ITEM 11. Executive Compensation 54

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and 54

Related Stockholder Matters

ITEM 13. Certain Relationships and Related Transactions, and Director Independence 56

ITEM 14. Principal Accounting Fees and Services 56

PART IV

ITEM 15. Exhibits, Financial Statement Schedules 56

SIGNATURES
1

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, 2012, EOG's total estimated net proved reserves were 1,811 million barrels of oil 

equivalent (MMBoe), of which 701 million barrels (MMBbl) were crude oil and condensate reserves, 320 MMBbl 

were natural gas liquids (NGLs) reserves and 4,740 billion cubic feet, or 790 MMBoe, were natural gas reserves (see 

Supplemental Information to Consolidated Financial Statements). At such date, approximately 92% of EOG's net 

proved reserves, on a crude oil equivalent basis, were located in the United States, 6% in Trinidad and 2% in 

Canada. 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, 2012, EOG employed approximately 2,650 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.
2

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, 2012, 40% of EOG's net proved reserves in the United States and Canada (on a crude oil 

equivalent basis) were crude oil and condensate, 19% were NGLs and 41% were natural gas. Substantial portions of 

these reserves are in long-lived fields with well-established production characteristics. EOG believes that 

opportunities exist to increase production through continued development in and around many of these fields and 

through the utilization of the applicable technologies. 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 2012 and certain 2013 plans for EOG's United States and Canada operations.

United States. The Eagle Ford Shale, with well-defined crude oil, wet gas and dry gas trends, has proven to 

have the best crude oil economics of any of EOG's shale plays. EOG was one of the first companies to recognize the 

potential of the Eagle Ford Shale and captured what EOG believes to be the best crude oil acreage position within 

the play. With 569,000 of its 639,000 net acres within the crude oil window, EOG is the largest oil producer in the 

play with year-end volumes of 106 thousand barrels of oil equivalent per day (MBoed), net, of which 75% were

crude oil and condensate volumes. EOG's total Eagle Ford production for 2012 increased approximately 150% to 

94.4 MBoed from 37.7 MBoed in 2011.

EOG has a large contiguous acreage block that enhances the economics of the play through the efficient 

development of crude oil and natural gas gathering systems, as well as processing plants to extract NGLs. EOG is 

also an anchor shipper on the Enterprise Products Partners L.P. crude oil pipeline which began delivering crude oil 

from the Eagle Ford into the Texas Gulf Coast refining complex in July 2012. EOG has established a reputation of 

being a low-cost operator and, by utilizing its self-sourced sand along with dedicated frac crews and other services, is 

able to consistently deliver the lowest cost and highest productivity of any operator, further enhancing the economics 

of the play. EOG drilled 352 net wells in 2012 in this play and, in 2013, plans to drill approximately 400 net wells 

with a 26-rig program.

During 2012, EOG continued development of its liquids-rich Barnett Shale Combo play in the Fort Worth 

Basin. EOG drilled 190 net Barnett Combo wells and continued to upgrade the quality of its acreage position and 

add potential drilling locations in the liquids-rich Combo core area. In 2012, the average net daily total production 

in the Barnett Shale averaged approximately 38.8 thousand barrels per day (MBbld) of crude oil and condensate and 

NGLs and approximately 368 million cubic feet per day (MMcfd) of natural gas. For 2013, EOG will continue to be 

active in this play with plans to drill an additional 130 net Barnett Shale Combo wells. With a large acreage position 

of approximately 430,000 net acres in the Barnett Shale and a history of strong drilling results, EOG expects to 

continue to be an active driller in the Fort Worth Basin Barnett Shale for many years.

Also during 2012, EOG continued its strong liquids development in the Rocky Mountain area. In the 

Williston Basin, where production is approximately 85% crude oil, 62 net wells were drilled in 2012. EOG has 

continued its development of the Turner Sand formation in the Powder River Basin, where EOG has drilled 12 net 

wells, each producing liquids-rich natural gas. Net average production for the entire Rocky Mountain area for 2012 

was 51.8 MBbld of crude oil and condensate and NGLs, an increase of 11% over the prior year. Natural gas 

production decreased 7% compared to 2011 levels as EOG reduced its activity in the Uinta Basin, drilling 18 net 

wells during 2012, consistent with its strategy to de-emphasize natural gas drilling. EOG holds approximately 1.3 

million net acres in the Rocky Mountain area and expects to drill 51 net wells in 2013.

In 2012, EOG drilled and participated in 105 net wells in the Permian Basin to develop its liquids-rich 

Leonard-Avalon, Bone Spring and Wolfcamp plays. EOG is well positioned with approximately 73,000 net acres in 

the Leonard-Avalon Shale and Bone Spring, and 114,000 net acres in the Wolfcamp Shale, all within the Delaware 

Basin. Additionally, EOG has approximately 133,000 net acres in the Wolfcamp Shale within the Midland Basin. 

Net production for 2012 averaged 16.5 MBbld of crude oil and condensate and NGLs and 44 MMcfd of natural gas. 

After divestitures in 2012, EOG holds approximately 450,000 net acres throughout the Permian Basin. In 2013, 

EOG plans to continue the expansion and development of the Leonard-Avalon, Bone Spring and Wolfcamp plays by 

drilling 63 net wells.
3

In the South Texas area, EOG drilled 34 net wells in 2012. Net production during 2012 averaged 5.2

MBbld of crude oil and condensate and NGLs and 116 MMcfd of natural gas. EOG's activity was focused in San 

Patricio, Nueces, Brooks, Kenedy and Kleberg Counties, where EOG will continue to exploit the liquids-rich Frio 

and Vicksburg sands utilizing vertical and horizontal well applications. 

In December 2012, EOG entered into a joint venture with respect to the King Ranch (Ranch) in South 

Texas. EOG has assumed the operatorship and has acquired the right to explore on approximately 364,000 gross 

acres. EOG has also assumed a 50% working interest in the production on the Ranch as well as 50% of the plugging 

and abandonment cost liabilities and decommissioning cost liabilities for existing wells and certain facilities on the 

Ranch. Current net production from the Ranch is approximately 1.1 MBbld of crude oil and condensate, 1.5 MBbld 

of NGLs and 28 MMcfd of natural gas. The exploration potential of the Ranch includes the Frio Anomalina and 

Vicksburg trends. 

In the Upper Gulf Coast region, EOG drilled 19 net wells, and net production averaged 191 MMcfd of 

natural gas and 0.4 MBbld of crude oil and condensate and NGLs in 2012. The Haynesville and Bossier Shale plays 

located near the Texas-Louisiana border continue to be core natural gas assets. EOG controls 160,000 net acres, all 

within the highly productive areas of these plays. Due to low natural gas prices, EOG plans to defer drilling in the 

Haynesville until natural gas economics support the activity. EOG holds a total of approximately 485,000 net acres 

in the Upper Gulf Coast region and plans to drill 15 net wells targeting crude oil projects during 2013. 

In 2012, EOG continued to expand its activities in the Mid-Continent area with continued growth and 

extension of its Western Anadarko Basin core area. For the year, EOG averaged net production of 8.0 MBbld of 

crude oil and condensate and NGLs and 44 MMcfd of natural gas. Total liquids volumes increased 14% in 2012 

compared to 2011. In 2012, EOG continued its successful horizontal exploitation of the Cleveland and Marmaton 

sandstones, drilling 35 net wells. Since 2002, EOG has drilled over 270 net wells in these plays and holds 

approximately 125,000 net acres throughout the trend. In 2013, approximately 35 net wells are planned in order to 

further exploit these liquids-rich plays.

During the first half of 2012, EOG continued the development of its Pennsylvania Marcellus Shale asset, 

completing 19 net wells. EOG reduced its operations in the second half of 2012, dropping from 3 drilling rigs to 1 

drilling rig, with activities focused on its Bradford County, Pennsylvania, acreage. In 2012, net gas production 

averaged approximately 43 MMcfd, an increase of 24% from 2011. EOG plans to drill 4 net wells in Bradford 

County during 2013 for acreage retention. EOG holds approximately 170,000 net acres in the Pennsylvania 

Marcellus Shale play.

At December 31, 2012, EOG held approximately 3.0 million net undeveloped acres in the United States.

During 2012, EOG continued the expansion of its gathering and processing activities in the Barnett Shale in

North Texas, the Bakken and Three Forks plays in North Dakota and the Eagle Ford Shale in South Texas. EOGowned natural gas processing capacity at December 31, 2012, in the Barnett Shale and Eagle Ford Shale was 120 

MMcfd and 250 MMcfd, respectively.

In April 2012, a newly-constructed crude oil unloading facility in St. James, Louisiana, became operational. 

Owned by EOG and NuStar Energy L.P., this facility provides access to one of the key premium markets in the U.S., 

where sales are based upon the Light Louisiana Sweet (LLS) crude oil index. The St. James facility can 

accommodate multiple trains at a single time and has a capacity of approximately 120 MBbld. EOG's share of that 

capacity is 100 MBbld. 

Additionally, 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 crude oil 

purchased from third-party producers. EOG loaded 322 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 Stroud, 

Oklahoma, St. James, Louisiana, and certain other destinations in the U.S. 
4

In Stroud, Oklahoma, EOG owns a crude oil unloading facility and a pipeline to transport crude oil to the 

Cushing, Oklahoma, trading hub. These facilities have the capacity to unload approximately 90 MBbld of crude oil.

In the South Texas Eagle Ford, EOG continued to use its crude oil loading facility in Harwood, Texas. At 

this facility, 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 destinations on the U.S. Gulf Coast. During 2012, a total of 

98 rail shipments were made from the Harwood facility.

In support of its Permian Basin operations, EOG commenced shipments from its Barnhart, Texas, crude oil 

loading facility in mid-2012 and continues to increase shipments from that region to markets on the U.S. Gulf Coast. 

During 2012, EOG shipped 24 unit trains from this facility. Each unit train currently consists of approximately 70 

cars each, with aggregate capacity of approximately 45,000 barrels per train.

EOG believes that its crude-by-rail facilities provide a distinct competitive advantage, giving it the ability 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, helping to fulfill EOG's sand needs for its well completion operations in the Barnett Shale Combo play. 

At its second Hood County sand processing plant that was purchased in 2011, EOG continued to process 

raw EOG-owned sand from Wisconsin. After final processing at the Hood County facility, the sand is being utilized 

in completion operations in several key EOG plays. 

EOG also increased production of processed sand at its new state-of-the-art Chippewa Falls, Wisconsin, 

sand plant. The plant processes sand from multiple nearby EOG-owned sand mines. The first unit train of processed 

sand was dispatched from Chippewa Falls in January 2012. During 2012, EOG shipped 70 sand unit trains of 

approximately 100 cars each to a new EOG sand storage facility in Refugio, Texas.

EOG also installed and commissioned a resin coating plant at the Refugio sand storage facility where sand 

can also be coated for added strength. From Refugio, the sand is shipped primarily to the South Texas Eagle Ford 

Shale. EOG also ships its processed 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 2012, EOGRC continued its focus on horizontal 

crude oil growth, mainly through its development of the shallow Spearfish formation in southwest Manitoba. Other 

drilling activity was directed to acreage retention in its bigger target horizontal natural gas play in the Horn River 

Basin of British Columbia. EOG's entire acreage position in the Horn River Basin has now been converted from 

drilling licenses to production leases that will remain intact for a period of ten years from the conversion point. Of 

the 135 net wells EOGRC drilled or participated in during 2012, 124 were horizontal wells in oil plays, 7 were 

horizontal natural gas acreage retention wells and the remaining 4 were vertical wells. In 2013, EOGRC will 

continue to develop its Manitoba property and identify new targets in Alberta. In 2012, net crude oil and condensate 

and NGL production was 7.8 MBbld and net natural gas production was 95 MMcfd. 

At December 31, 2012, EOGRC held approximately 638,000 net undeveloped acres in Canada.

EOGRC owned a 30% interest in both the planned liquefied natural gas export terminal to be located near 

the Port of Kitimat, British Columbia (Kitimat LNG Terminal) and the proposed Pacific Trail Pipelines (PTP) which 

is intended to link Western Canada's natural gas producing regions to the Kitimat LNG Terminal. In December 

2012, EOGRC signed a purchase and sale agreement for the sale of its entire interest in the Kitimat LNG Terminal

and PTP, as well as approximately 28,500 undeveloped net acres in the Horn River Basin, to Chevron Canada 

Limited. The transaction closed in February 2013. 
5

 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 and Modified U(b) Block, as well as the Pelican 

Field, have been developed and are producing natural gas and crude oil and condensate. Production from both the 

Toucan Field in Block 4(a) and the adjacent EMZ Area began in February 2012 to supply natural gas under a contract 

with the National Gas Company of Trinidad and Tobago (NGC). 

During the fourth quarter of 2012, EOG began drilling an exploratory well in the Modified U(a) Block

which was successful. This well and three additional development wells to be drilled in 2013 will be completed 

during the first half of 2013.

Natural gas from EOG's Trinidad operations currently is sold to NGC or its subsidiary. In 2013, certain 

agreements with NGC require EOG's Trinidad operations to deliver approximately 470 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. Crude oil and condensate from EOG's Trinidad operations currently 

is sold to the Petroleum Company of Trinidad and Tobago Limited.

In 2012, EOG's average net production from Trinidad was 378 MMcfd of natural gas and 1.5 MBbld of 

crude oil and condensate. 

At December 31, 2012, 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 2012, production continued from the Valkyrie field in this block. 

EOGUK also owns a 30% non-operating working interest in a portion of Blocks 53/1 and 53/2. These 

blocks are also located in the Southern Gas Basin of the North Sea. 

In 2006, EOGUK participated in the drilling and successful testing of the Columbus prospect in the Central 

North Sea Block 23/16f. EOG has a 25% non-operating working interest in this block. A successful Columbus 

natural gas prospect appraisal well was drilled during the third quarter of 2007. The field operator submitted a 

revised field development plan to the U.K. Department of Energy and Climate Change (DECC) in the third quarter 

of 2012 with approval expected in the second quarter of 2013. The project participants are currently negotiating 

commercial agreements.
6

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 its 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. The production 

platform was installed during the second quarter of 2012 and the pipelines were installed in the fourth quarter of 

2012. EOG expects to begin processing facility installation during the first half of 2013. The Conwy development 

drilling program is expected to commence during the second quarter of 2013, with initial production expected in the 

fourth quarter of 2013. 

In 2009, EOGUK was awarded a license for Block 21/12b in the Central North Sea where it expects to drill 

an exploratory well to test a crude oil prospect in late 2013. EOGUK has 100% interest in this block.

In 2012, production averaged 2 MMcfd of natural gas, net, in the United Kingdom.

At December 31, 2012, EOG held approximately 95,000 net undeveloped acres in the United Kingdom. 

China. In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the 

Chuanzhong Block exploration area in the Sichuan Basin, Sichuan Province, China. In October 2008, EOG obtained 

the rights to shallower zones on the acreage acquired. 

In 2012, production averaged 8 MMcfd of natural gas, net, in China.

At December 31, 2012, 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 80,000 net acres in the Neuquén Basin in Neuquén Province, Argentina. During the first half of 2012, 

EOG participated in the drilling and completion of a vertical well in the Bajo del Toro Block. In the first half of 

2012, EOG drilled a well to monitor future well completions in the Aguada del Chivato Block and drilled and 

completed a horizontal well in this block. Both the horizontal and vertical wells that were completed are under 

evaluation. During the first quarter of 2013, EOG plans to complete the monitoring well in the Aguada del Chivato 

Block.

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 2012, 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 Clearbrook, Minnesota, Cushing, Oklahoma, St. James, Louisiana, and the U.S. Gulf Coast. In 2013, the 

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

In 2012, EOG processed certain of its natural gas production, either at EOG-owned plants or at third-party 

plants, extracting NGLs. NGLs were sold at prevailing market prices. In 2013, the pricing mechanism for such 

production is expected to remain the same.

In 2012, 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 2013, the pricing mechanism for such production is expected to remain the same.

In 2012, 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 2013. 
7

In 2012, all wellhead natural gas volumes from the United Kingdom were sold on the spot market. The 

2013 marketing strategy for wellhead natural gas volumes from the United Kingdom is expected to remain the same.

EOG is currently investigating possible marketing opportunities for its wellhead crude oil due to the anticipated start

of EOG's crude oil production in the United Kingdom in the fourth quarter of 2013.

In 2012, all of the wellhead natural gas volumes from China were sold under a contract with prices based on 

the purchaser's pipeline sales prices to various local market segments. The pricing mechanism for the contract in 

China is expected to remain the same in 2013.

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 2012, a single purchaser accounted for 19.8% of EOG's total wellhead crude oil and condensate, NGLs

and natural gas revenues and gathering, processing and marketing revenues. EOG does not believe that the loss of any 

single purchaser would have a material adverse effect on its financial condition or results of operations.
8

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, 2012, 2011 and 2010.

Year Ended December 31 2012 2011 2010

Crude Oil and Condensate Volumes (MBbld) (1)

United States:

Eagle Ford 72.3 30.2 4.1

Barnett 13.0 15.2 6.8

Other 64.0 56.6 52.3

United States 149.3 102.0 63.2

Canada 7.0 7.9 6.7

Trinidad 1.5 3.4 4.7

Other International (2) 0.1 0.1 0.1

Total 157.9 113.4 74.7

Natural Gas Liquids Volumes (MBbld) (1)

United States:

Eagle Ford 11.2 3.9 0.2

Barnett 25.8 22.6 16.3

Other 18.1 15.0 13.0

United States 55.1 41.5 29.5

Canada 0.8 0.9 0.9

Total 55.9 42.4 30.4

Natural Gas Volumes (MMcfd) (1)

United States:

Eagle Ford 65 21 4

Barnett 368 403 404

Other 601 689 725

United States 1,034 1,113 1,133

Canada 95 132 200

Trinidad 378 344 341

Other International (2) 9 13 14

Total 1,516 1,602 1,688

Crude Oil Equivalent Volumes (MBoed) (3)

United States:

Eagle Ford 94.4 37.7 5.0

Barnett 100.1 105.0 90.5

Other 182.1 186.4 186.0

United States 376.6 329.1 281.5

Canada 23.6 30.7 40.9

Trinidad 64.5 60.7 61.5

Other International (2) 1.7 2.2 2.5

Total 466.4 422.7 386.4

Total MMBoe (3) 170.7 154.3 141.1
9

Year Ended December 31 2012 2011 2010

Average Crude Oil and Condensate Prices ($/Bbl) (4)

United States $ 98.38 $ 92.92 $ 74.88

Canada 86.08 91.92 72.66

Trinidad 92.26 90.62 68.80

Other International (2) 89.57 100.11 73.11

Composite 97.77 92.79 74.29

Average Natural Gas Liquids Prices ($/Bbl) (4)

United States $ 35.41 $ 50.37 $ 41.68

Canada 44.13 52.69 43.40

Composite 35.54 50.41 41.73

Average Natural Gas Prices ($/Mcf) (4)

United States $ 2.51 $ 3.92 $ 4.30

Canada 2.49 3.71 3.91

Trinidad 3.72 3.53 2.65

Other International (2) 5.71 5.62 4.90

Composite 2.83 3.83 3.93

(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 

the equipment, materials, services and employees and other contract personnel (including geologists, geophysicists, 

engineers and other specialists) required to explore for, develop, produce and market crude oil and natural gas. 

Moreover, many of EOG's competitors have financial and other resources substantially greater than those EOG 

possesses and have established strategic long-term positions and strong governmental relationships in countries in 

which EOG may seek new or expanded entry. As a consequence, EOG may be at a competitive disadvantage in 

certain respects, such as in bidding for drilling rights. In addition, many of EOG's larger competitors may have a 

competitive advantage when responding to factors that affect demand for crude oil and natural gas, such as changing 

worldwide prices and levels of production and the cost and availability of alternative fuels. EOG also faces 

competition, to a lesser extent, from competing energy sources, such as alternative energy sources.

Regulation

United States Regulation of Crude Oil and Natural Gas Production. Crude oil and natural gas production 

operations are subject to various types of regulation, including regulation in the United States by federal and state 

agencies.

United States legislation affecting the oil and gas industry is under constant review for amendment or 

expansion. 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 drilling bonds and regulate the calculation and disbursement of royalty payments, 

production taxes and ad valorem taxes. 
10

A substantial portion of EOG's oil and gas leases in Utah, New Mexico, Wyoming and the Gulf of Mexico, as 

well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management 

(BLM) 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. Certain operations must be 

conducted pursuant to appropriate permits issued by the BLM or the BSEE.

BLM and BOEM leases contain relatively standardized terms requiring compliance with detailed regulations 

and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act (which are subject to 

change by the BOEM or BSEE). Under certain circumstances, the BLM, BOEM or the BSEE may require operations 

on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely 

affect EOG's interests.

The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the 

Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978. These statutes are administered by the Federal 

Energy Regulatory Commission (FERC). Effective January 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 Barnett Shale in North Texas, the Bakken and 

Three Forks plays in North Dakota, and the Eagle Ford Shale 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.

Proposals and proceedings that might affect the oil and gas industry are considered from time to time by 

Congress, the state legislatures, the FERC and federal and state regulatory commissions and courts. EOG cannot predict 

when or whether any such proposals or proceedings may become effective. It should also be noted that the oil and gas 

industry historically has been very heavily regulated; therefore, there is no assurance that the approach currently being 

followed by such legislative bodies and regulatory agencies and courts will continue indefinitely.

Canadian Regulation of Crude Oil and Natural Gas Production. The oil and gas industry in Canada is 

subject to extensive controls and regulations imposed by various levels of government. These regulatory authorities 

may impose regulations on or otherwise intervene in the oil and gas industry with respect to taxes and factors 

affecting prices, transportation rates, the exportation of the commodity and, possibly, expropriation or cancellation of 

contract rights. Such regulations may be changed from time to time in response to economic, political or other 

factors. The implementation of new regulations or the modification of existing regulations affecting the oil and gas 

industry could reduce demand for these commodities or increase EOG's costs and, therefore, may have a material 

adverse impact on EOG's operations and financial condition. 

It is not expected that any of these controls or regulations will affect EOG's operations in a manner 

materially different than they would affect other oil and gas companies of similar size; however, EOG is unable to 

predict what additional legislation or amendments may be enacted or how such additional legislation or amendments 

may affect EOG's operations and financial condition. 
11

In addition, each province has regulations that govern land tenure, royalties, production rates and other 

matters. The royalty system in Canada is a significant factor in the profitability of crude oil and natural gas 

production. Royalties payable on production from freehold lands are determined by negotiations between the 

mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and 

royalties. Royalties payable on lands that the government has an interest in are determined by government regulation 

and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable 

generally depends, in part, on prescribed reference prices, well productivity, geographical location, field discovery 

date and the type and quality of the petroleum product produced. From time to time, the federal and provincial 

governments of Canada have also established incentive programs such as royalty rate reductions, royalty holidays 

and tax credits for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These 

incentives generally have the effect of increasing EOG's revenues, earnings and cash flow.

Environmental Regulation - United States. EOG is subject to various federal, state and local laws and 

regulations covering the discharge of materials into the environment or otherwise relating to the protection of the 

environment. These laws and regulations affect EOG's operations and costs as a result of their effect on crude oil and 

natural gas exploration, development and production operations. Failure to comply with these laws and regulations may 

result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, 

the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and 

authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future 

operations or imposing additional compliance requirements. 

In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to 

the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under 

environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by 

prior owners or operators. EOG also could incur costs related to the clean-up of third-party sites to which it sent 

regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or 

other claims related to releases of regulated substances at such third-party sites. In addition, EOG could be responsible 

under environmental laws and regulations for oil and gas properties in which EOG previously owned or currently owns 

an interest, but was or is not the operator. Moreover, EOG is subject to the U.S. Environmental Protection Agency's 

(U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG) emissions and may in the future, as discussed 

further below, be subject to federal, state and local laws and regulations regarding hydraulic fracturing.

Compliance with environmental laws and regulations increases EOG's overall cost of business, but has not had, 

to date, a material adverse effect on EOG's operations, financial condition or results of operations. It is not anticipated, 

based on current laws and regulations, that EOG will be required in the near future to expend amounts (whether for 

environmental control facilities or otherwise) that are material in relation to its total exploration and development 

expenditure program in order to comply with such laws and regulations. However, given that such laws and 

regulations are subject to change, EOG is unable to predict the ultimate cost of compliance or the ultimate effect on 

EOG's operations, financial condition and results of operations.

Climate Change - United States. Local, state, national and international regulatory bodies have been 

increasingly focused on GHG emissions and climate change issues in recent years. In addition to the U.S. EPA's rule 

requiring annual reporting of GHG emissions, recent U.S. EPA rulemaking may result in the regulation of GHGs as 

pollutants under the federal Clean Air Act. EOG supports efforts to understand and address the contribution of human 

activities to global climate change through the application of sound scientific research and analysis. Moreover, EOG 

believes that its strategy to reduce GHG emissions throughout its operations is in the best interest of the environment and 

is a generally good business practice. 

EOG has developed a system that is utilized in calculating GHG emissions from its operating facilities. This 

emissions management system calculates emissions based on recognized regulatory methodologies, where applicable, 

and on commonly accepted engineering practices. EOG is now reporting GHG emissions for facilities covered under 

the U.S. EPA's Mandatory Reporting of Greenhouse Gases Rule published in October 2009. EOG is unable to predict 

the timing, scope and effect of any currently proposed or future laws, regulations or treaties regarding climate change 

and GHG emissions, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially 

and adversely affect EOG's operations, financial condition and results of operations.
12

Hydraulic Fracturing - United States. Most onshore crude oil and natural gas wells drilled by EOG are 

completed and stimulated through the use of hydraulic fracturing. Hydraulic fracturing technology, which has been used 

by the oil and gas industry for more than 60 years and is constantly being enhanced, enables EOG to produce crude oil 

and natural gas from formations that would otherwise not be recovered. Specifically, hydraulic fracturing is a process in 

which pressurized fluid is pumped into underground formations to create tiny fractures or spaces that allow crude oil and 

natural gas to flow from the reservoir into the well so that it can be brought to the surface. Hydraulic fracturing 

generally takes place thousands of feet underground, a considerable distance below any drinking water aquifers, and 

there are impermeable layers of rock between the area fractured and the water aquifers. The makeup of the fluid used in 

the hydraulic fracturing process is typically more than 99% water and sand, and less than 1% of highly diluted chemical 

additives; lists of the chemical additives most typically used in fracturing fluids are available to the public via internet 

websites and in other publications sponsored by industry trade associations and through state agencies in those states that

require the reporting of the components of fracturing fluids. While the majority of the sand remains underground to hold 

open the fractures, a significant percentage of the water and chemical additives flow back and are then either reused or 

safely disposed of at sites that are approved and permitted by the appropriate regulatory authorities. EOG regularly 

conducts audits of these disposal facilities to monitor compliance with all applicable regulations. 

Currently, the regulation of hydraulic fracturing is primarily conducted at the state and local level through 

permitting and other compliance requirements. However, there have been various proposals to regulate hydraulic 

fracturing at the federal level. Any new federal regulations that may be imposed on hydraulic fracturing could result in 

additional permitting and disclosure requirements (such as the reporting and public disclosure of the chemical additives 

used in the fracturing process) and in additional operating restrictions. In April 2012, the U.S. EPA issued regulations 

specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic 

compounds (VOC) emissions from natural gas wells that are hydraulically fractured through the use of "green 

completions" to capture natural gas that would otherwise escape into the air. The U.S. EPA also issued regulations that 

establish standards for VOC emissions from several types of equipment, including storage tanks, compressors, 

dehydrators, and valves and sweetening units at gas processing plants. In addition to these federal regulations, some 

state and local governments have imposed or have considered imposing various conditions and restrictions on drilling 

and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water 

wells; restrictions on access to, and usage of, water; disclosure of the chemical additives used in hydraulic fracturing 

operations; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Such 

federal, state and local permitting and disclosure requirements and operating restrictions and conditions could lead to 

operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the 

development of crude oil and natural gas from formations which would not be economically viable without the use of 

hydraulic fracturing.

EOG is unable to predict the timing, scope and effect of any currently proposed or future laws or regulations 

regarding hydraulic fracturing in the United States, but the direct and indirect costs of such laws and regulations (if 

enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.

Environmental Regulation - Canada. All phases of the oil and gas industry in Canada are subject to 

environmental regulation pursuant to a variety of Canadian federal, provincial and municipal laws and regulations. 

Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the 

generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in 

connection with spills, releases and emissions of various substances into the environment. These laws and 

regulations also require that facility sites and other properties associated with EOG's operations be operated, 

maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, EOG could 

be held responsible for oil and gas properties in which EOG owns an interest but is not the operator. 

These laws and regulations are subject to frequent change, and the clear trend is to place increasingly 

stringent limitations on activities that may affect the environment. Compliance with such laws and regulations 

increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, 

financial condition or results of operations. It is not anticipated, based on current laws and regulations, that EOG will be 

required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are 

material in relation to its total exploration and development expenditure program in order to comply with such laws and 

regulations. However, given that such laws and regulations are subject to change, EOG is unable to predict the ultimate 

cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations. 
13

As discussed above, local, provincial, national and international regulatory bodies have been increasingly 

focused on GHG emissions and climate change issues in recent years. The Canadian federal government has 

indicated an intention to work with the United States to regulate industrial emissions of GHG and air pollutants from 

a broad range of industrial sectors. In addition, regulation of GHG emissions in Canada takes place at the provincial 

and municipal level. For example, the governments of Alberta and British Columbia each regulate GHG emissions 

and the Government of Manitoba is currently considering the creation of a cap-and-trade system to reduce GHG 

emissions in Manitoba. Canada was an original signatory to the United Nations Framework Convention on Climate 

Change (also known as the Kyoto Protocol), but Canada withdrew from the Kyoto Protocol, effective December 

2012.

In Canada, the regulation of hydraulic fracturing is primarily conducted at the provincial and local levels 

through permitting and other compliance requirements. Some provinces and local governments have imposed or have 

considered imposing various conditions and restrictions on drilling and completion operations, including requirements 

regarding casing and cementing of wells; restrictions on access to and usage of water; disclosure of the chemical 

additives used in hydraulic fracturing operations; and restrictions on the type of chemical additives that may be used in 

hydraulic fracturing operations. Such provincial and local requirements, restrictions and conditions could lead to 

operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the 

development of crude oil and natural gas from formations which would not be economically viable without the use of 

hydraulic fracturing. EOG is unable to predict the timing, scope and effect of any currently proposed or future laws or 

regulations regarding hydraulic fracturing in Canada, but the direct and indirect costs of such laws and regulations (if 

enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.

Other International Regulation. EOG's exploration and production operations outside the United States and 

Canada are subject to various types of regulations imposed by the respective governments of the countries in which 

EOG's operations are conducted, and may affect EOG's operations and costs of compliance within that country. EOG 

currently has operations in Trinidad, the United Kingdom, China and Argentina. EOG is unable to predict the timing, 

scope and effect of any currently proposed or future laws, regulations or treaties, including those regarding climate 

change and hydraulic fracturing, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could 

materially and adversely affect EOG's operations, financial condition and results of operations. EOG will continue to 

review the risks to its business and operations associated with all environmental matters, including climate change and 

hydraulic fracturing. In addition, EOG will continue to monitor and assess any new policies, legislation, regulations and 

treaties in the areas where it operates to determine the impact on its operations and take appropriate actions, where 

necessary.

Other Regulation. EOG has sand mining and processing operations in Texas and Wisconsin, which support 

EOG's exploration and development operations. EOG's sand mining operations are subject to regulation by the federal 

Mine Safety and Health Administration (in respect of safety and health matters) and by state agencies (in respect of air 

permitting and other environmental matters). The information concerning mine safety violations and other regulatory 

matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 

of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this report.

Other Matters

Energy Prices. EOG is a crude oil and natural gas producer and is impacted by changes in prices for 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 2012 than in prior years and is expected to comprise an even larger portion in 2013. Average 

crude oil and condensate prices received by EOG for production in the United States and Canada increased by 5% in 

2012, 24% in 2011 and 37% in 2010, 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 36% decrease in the average wellhead natural gas price received by EOG for production in the 

United States and Canada in 2012, an 8% decrease in 2011 and an increase of 13% in 2010, 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 crude oil and condensate, NGLs and 

natural gas prices in the future. For additional discussion regarding changes in crude oil and natural gas prices and the 

risks that such changes may present to EOG, see ITEM 1A. Risk Factors.
14

Including the impact of EOG's 2013 crude oil derivative contracts (exclusive of options) and based on EOG's 

tax position, EOG's price sensitivity in 2013 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 $28 million for net income and 

$41 million for cash flows from operating activities. Including the impact of EOG's 2013 natural gas derivative 

contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2013 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 $18 million for net income and $27 million for cash 

flows from operating activities. For a summary of EOG's financial commodity derivative contracts at February 21, 

2013, 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, 2012, see Note 11 to Consolidated Financial Statements.

Risk Management. EOG engages in price risk management activities from time to time. These activities 

are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas. EOG 

utilizes financial commodity derivative instruments, primarily 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, 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 21, 2013, 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, 2012, see Note 11

to Consolidated Financial Statements.

All of EOG's crude oil and natural gas activities are subject to the risks normally incident to the exploration 

for, and development and production of, crude oil and natural gas, including blowouts, rig and well explosions, 

cratering, fires and loss of well control, each of which could result in damage to life, property and/or the 

environment. EOG's onshore and offshore operations are also subject to usual customary perils, including hurricanes 

and other adverse weather conditions. Moreover, EOG's activities are subject to governmental regulations as well as 

interruption or termination by governmental authorities based on environmental and other considerations. Losses 

and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by 

insurance.

Insurance is maintained by EOG against some, but not all, of these risks in accordance with what EOG believes 

are customary industry practices and in amounts and at costs that EOG believes to be prudent and commercially 

practicable. Specifically, EOG maintains commercial general liability and excess liability coverage provided by thirdparty insurers for bodily injury or death claims resulting from an incident involving EOG's onshore or offshore 

operations (subject to policy terms and conditions). Moreover, in the event an incident with respect to EOG's onshore or 

offshore operations results in negative environmental effects, EOG maintains operators extra expense coverage provided 

by third-party insurers for obligations, expenses or claims that EOG may incur from such an incident, including 

obligations, expenses or claims in respect of seepage and pollution, cleanup and containment, evacuation expenses and 

control of the well (subject to policy terms and conditions). In the specific event of a well blowout or out-of-control well 

resulting in negative environmental effects, such operators extra expense coverage would be EOG's primary coverage, 

with the commercial general liability and excess liability coverage referenced above also providing certain coverage to 

EOG. All of EOG's onshore and offshore drilling activities are conducted on a contractual basis with independent 

drilling contractors and other third-party service contractors. The indemnification and other risk allocation provisions 

included in such contracts are negotiated on a contract-by-contract basis and are each based on the particular 

circumstances of the services being provided and the anticipated operations. 

In addition to the above-described risks, EOG's operations outside the United States are subject to certain risks, 

including the risk of increases in taxes and governmental royalties, changes in laws and policies governing the

operations of foreign-based companies, expropriation of assets, unilateral or forced renegotiation or modification of 

existing contracts with governmental entities, currency restrictions and exchange rate fluctuations. Please refer to ITEM 

1A. Risk Factors for further discussion of the risks to which EOG is subject with respect to its operations outside the 

United States.
15

Texas Severance Tax Rate Reduction. Natural gas production from qualifying Texas natural gas wells spudded 

or completed after August 31, 1996 is entitled to a reduced severance tax rate for the first 120 consecutive months of 

production. However, the cumulative value of the tax reduction cannot exceed 50 percent of the drilling and completion 

costs incurred on a well-by-well basis. For a discussion of the impact on EOG, see ITEM 7. Management's Discussion 

and Analysis of Financial Condition and Results of Operations - Results of Operations - Operating and Other Expenses.

Executive Officers of the Registrant

The current executive officers of EOG and their names and ages (as of February 21, 2013) are as follows:

Name Age Position

Mark G. Papa 66 Chairman of the Board and Chief Executive Officer; Director

William R. Thomas 60 President

Gary L. Thomas 63 Chief Operating Officer

Timothy K. Driggers 51 Vice President and Chief Financial Officer

Michael P. Donaldson 50 Vice President, General Counsel and Corporate Secretary

Mark G. Papa was elected Chairman of the Board and Chief Executive Officer of EOG in August 1999, 

President and Chief Executive Officer and director in September 1998, President and Chief Operating Officer in 

September 1997 and President in December 1996, and was President-North America Operations from February 1994 

to December 1996. Mr. Papa joined Belco Petroleum Corporation, a predecessor of EOG, in 1981. Mr. Papa is also 

a director of Oil States International, Inc., an oilfield service company, where he serves on the Compensation and 

Nominating and Corporate Governance committees. From July 2003 to April 2005, Mr. Papa served as a director of 

the general partner of Magellan Midstream Partners LP, a pipeline and terminal company, where he served as 

Chairman of the Compensation Committee and as a member of the Audit and Conflicts Committees. Mr. Papa is 

EOG's principal executive officer.

William R. Thomas was elected President in September 2011. He was elected Senior Vice President and 

General Manager of EOG's Fort Worth, Texas, office in June 2004, Executive Vice President and General Manager 

of EOG's Fort Worth, Texas, office in February 2007, and Senior Executive Vice President, Exploitation in February 

2011, and served as Senior Executive Vice President, Exploration from July 2011 to September 2011. Mr. Thomas 

joined a predecessor of EOG in January 1979.

Gary L. Thomas was elected Chief Operating Officer in September 2011. He was elected Executive Vice 

President, North America Operations in May 1998, Executive Vice President, Operations in May 2002, and served 

as Senior Executive Vice President, Operations from February 2007 to September 2011. He also previously served 

as Senior Vice President and General Manager of EOG's Midland, Texas, office. Mr. Thomas joined a predecessor 

of EOG in July 1978.

Timothy K. Driggers was elected Vice President and Chief Financial Officer in July 2007. He was elected 

Vice President and Controller of EOG in October 1999 and was subsequently named Vice President, Accounting and 

Land Administration in October 2000 and Vice President and Chief Accounting Officer in August 2003. Mr. 

Driggers is EOG's principal financial officer. Mr. Driggers joined 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 as an Assistant General Counsel 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 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 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 and regulation of 

derivatives transactions and hedging activities) and taxation;

 the level and effect of trading in commodity futures markets, including trading by commodity price 

speculators and others; and

 the effect of worldwide energy conservation measures.

Our cash flows and results of operations depend to a great extent on the prevailing prices for crude oil and 

natural gas. Prolonged or substantial declines in crude oil and/or natural gas prices may materially and adversely 

affect our liquidity, the amount of cash flows we have available for our capital expenditures and other operating 

expenses, our ability to access the credit and capital markets and our results of operations. 

In addition, if we expect or experience significant sustained decreases in crude oil and natural gas prices 

such that the expected future cash flows from our crude oil and natural gas properties falls below the net book value 

of our properties, we may be required to write down the value of our crude oil and natural gas properties. Any such 

asset impairments could materially and adversely affect our results of operations and, in turn, the trading price of our 

common stock.

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

control. 

Drilling crude oil and natural gas wells, including development wells, involves numerous risks, including 

the risk that we may not encounter commercially productive crude oil and natural gas reserves (including "dry 

holes"). As a result, we may not recover all or any portion of our investment in new wells.

Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating 

wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled, the 

cost of such operations may increase and/or our results of operations and cash flows from such operations may be 

impacted, as a result of a variety of factors, including: 

 unexpected drilling conditions;

 title problems;

 pressure or irregularities in formations;
17

 equipment failures or accidents;

 adverse weather conditions, such as winter storms, flooding and hurricanes, and changes in weather 

patterns;

 compliance with, or changes in, environmental laws and regulations relating to air emissions, hydraulic 

fracturing and disposal of produced water, drilling fluids and other wastes, laws and regulations imposing 

conditions and restrictions on drilling and completion operations and other laws and regulations, such as tax 

laws and regulations; 

 the availability and timely issuance of required governmental permits and licenses; 

 the availability of, costs associated with and terms of contractual arrangements for properties, including 

mineral licenses and leases, pipelines, rail cars, crude oil hauling trucks and qualified drivers and related 

facilities and equipment to gather, process, compress, transport and market crude oil, natural gas and related 

commodities; and

 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 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 thirdparty operators in each case due to any of the above factors or other factors, may materially and adversely affect our 

business, financial condition and results of operations. For related discussion of the risks and potential losses and 

liabilities inherent in our crude oil and natural gas operations generally, see the immediately following risk factor.

Our crude oil and natural gas operations involve many risks and expose us to potential losses and liabilities, and 

insurance may not fully protect us against these risks and potential losses and liabilities. 

Our onshore and offshore operations are subject to all of the risks associated with exploring and drilling for, 

and producing, gathering, processing and transporting, crude oil and natural gas, including the risks of:

 well blowouts and cratering; 

 loss of well control; 

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

 pipe failures and casing collapses;

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

 releases of chemicals or other hazardous substances; 

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

disasters; 

 fires and explosions;

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

 formations with abnormal pressures; and

 malfunctions of gathering, processing and other equipment.

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

 injury or loss of life; 

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

 pollution or other environmental damage; 

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

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

 repairs necessary to resume operations. 
18

We maintain insurance against many, but not all, such losses and liabilities in accordance with what we 

believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially 

practicable. The occurrence of any of these events and any losses or liabilities incurred as a result of such events, if 

uninsured or in excess of our insurance coverage, would reduce the funds available to us for our onshore and 

offshore exploration, exploitation, development and production activities and could, in turn, have a material adverse 

effect on our business, financial condition and results of operations.

Our ability to sell and deliver our crude oil and natural gas production could be materially and adversely affected if 

adequate gathering, processing, compression and transportation facilities 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 owned by third parties. These facilities may be temporarily unavailable to us due to 

market conditions, mechanical reasons or other factors or conditions, and may not be available to us in the future on 

terms we consider acceptable, if at all. In particular, in certain newer shale plays, the capacity of gathering, 

processing, compression and transportation facilities 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 

other constraints could limit or delay the construction of new gathering, processing, compression and transportation 

facilities 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 or the availability 

of these facilities, including due to our failure or inability to obtain access to these facilities on terms acceptable to us

or at all, could materially and adversely affect our business and, in turn, our financial condition and results of 

operations.

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

their current levels.

The rate of production from crude oil and natural gas properties generally declines as reserves are 

produced. Except to the extent that we conduct successful exploration, exploitation and development activities, 

acquire additional properties containing reserves or, through engineering studies, identify additional behind-pipe 

zones or secondary recovery reserves, our reserves will decline as they are produced. Maintaining our production of 

crude oil and natural gas at, or increasing our production from, current levels, is, therefore, highly dependent upon 

our level of success in acquiring or finding additional reserves, which could in turn impact our future cash flows and 

results of operations.

We incur certain costs to comply with government regulations, particularly regulations relating to environmental 

protection and safety, and could incur even greater costs in the future.

Our exploration, production and marketing operations are regulated extensively by federal, state and local 

governments and regulatory agencies, both domestically and in the foreign countries in which we do business, and 

are subject to interruption or termination by governmental and regulatory authorities based on environmental or other 

considerations. Moreover, we have incurred and will continue to incur costs in our efforts to comply with the 

requirements of environmental, safety and other regulations. Further, the regulatory environment in the oil and gas 

industry could change in ways that we cannot predict and that might substantially increase our costs of compliance 

and, in turn, materially and adversely affect our business, results of operations and financial condition.

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, 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.
19

Local, state, national and international regulatory bodies have been increasingly focused on GHG emissions 

and climate change issues in recent years. EOG is unable to predict the timing, scope and effect of any currently 

proposed or future laws, regulations or treaties regarding climate change and GHG emissions, but the direct and 

indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's 

operations, financial condition and results of operations. 

In addition, there have been various proposals to regulate hydraulic fracturing in the U.S. at the federal 

level. Currently, the regulation of hydraulic fracturing in the U.S. is primarily conducted at the state level (and, in 

Canada, at the provincial and local levels) through permitting and other compliance requirements. Any new federal 

regulations that may be imposed on hydraulic fracturing could result in additional permitting and disclosure 

requirements and in additional operating restrictions. Moreover, some state and local governments have imposed or 

have considered imposing various conditions and restrictions on drilling and completion operations. Any such 

federal or state requirements, restrictions or conditions could lead to operational delays and increased operating and 

compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas 

from formations which would not be economically viable without the use of hydraulic fracturing. Accordingly, our 

production of crude oil and natural gas could be materially and adversely affected. For additional discussion 

regarding climate change regulation and hydraulic fracturing regulation, see Climate Change - United States, 

Hydraulic Fracturing - United States and Environmental Regulation - Canada under ITEM 1. Business - Regulation.

We will continue to monitor and assess any proposed or new policies, legislation, regulations and treaties in 

the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. 

We are unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, 

but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely 

affect our business, results of operations and financial condition. For related discussion, see the risk factor below 

regarding the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act with respect to 

regulation of derivatives transactions and entities (such as EOG) that participate in such transactions.

Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration 

and production may be eliminated as a result of future legislation.

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, 

including the elimination of certain U.S. federal income tax incentives currently available to crude oil and natural gas 

exploration and production companies. These changes include, but are not limited to, the elimination of current 

deductions for intangible drilling and development costs. It is unclear whether such changes or similar changes will 

be enacted and, if enacted, how soon any such changes could become effective. The enactment of such changes or 

any other similar changes in U.S. federal income tax laws could materially and adversely affect our cash flows, 

results of operations and financial condition.

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

adverse effect on us. 

A portion of our crude oil and natural gas production may be interrupted, or shut in, from time to time for 

various reasons, including, but not limited to, as a result of accidents, weather conditions, loss of gathering, processing, 

compression or transportation facility access or field labor issues, or intentionally as a result of market conditions such 

as crude oil or natural gas prices that we deem uneconomic. If a substantial amount of our production is interrupted, our 

cash 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.
20

If we acquire crude oil and natural gas properties, our failure to fully identify existing and potential problems, to 

accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our 

operations could materially and adversely affect our business, financial condition and results of operations.

From time to time, we seek to acquire crude oil and natural gas properties. Although we perform reviews of 

properties to be acquired in a manner that we believe is duly diligent and consistent with industry practices, reviews 

of records and properties may not necessarily reveal existing or potential problems, nor may they permit us to 

become sufficiently familiar with the properties in order to assess fully their deficiencies and potential. Even when 

problems with a property are identified, we often may assume environmental and other risks and liabilities in 

connection with acquired properties pursuant to the acquisition agreements. In addition, there are numerous 

uncertainties inherent in estimating quantities of crude oil and natural gas reserves (as discussed further below), 

actual future production rates and associated costs with respect to acquired properties. Actual reserves, production 

rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a 

material and adverse effect on our business and results of operations, particularly during the periods in which the 

operations of the acquired properties are being integrated into our ongoing operations or if we are unable to 

effectively integrate the acquired properties into our ongoing operations.

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

at all. 

We make, and will continue to make, substantial capital expenditures for the acquisition, exploration, 

development and production 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) 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, have 

weakened in recent years and remain relatively weak. In addition, there continues to be weakness and volatility in 

domestic and global financial markets relating to the credit crisis in recent years, and corresponding reaction by lenders 

to risk. These conditions and factors may adversely affect the ability of our customers and other contractual 

counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, 

as well as their ability to access the credit and capital markets for such purposes. 

Moreover, our customers and other contractual counterparties may be unable to satisfy their contractual 

obligations to us for reasons unrelated to these conditions and factors, such as the unavailability of required facilities or 

equipment due to mechanical failure or market conditions. Furthermore, if a customer is unable to satisfy its contractual 

obligation to purchase crude oil, natural gas or related commodities from us, we may be unable to sell such production to

another customer on terms we consider acceptable, if at all, due to the geographic location of such production, the 

availability, proximity or capacity of gathering, processing, compression and transportation facilities or market or 

other factors and conditions.
21

The inability of our customers and other contractual counterparties to pay amounts owed to us and to otherwise 

satisfy their contractual obligations to us may materially and adversely affect our business, financial condition, results of 

operations and cash flows.

Competition in the oil and gas exploration and production industry is intense, and many of our competitors have 

greater resources than we have. 

We compete with major integrated oil and gas companies, government-affiliated oil and gas companies and 

other independent oil and gas companies for the acquisition of licenses and leases, properties and reserves and the 

equipment, materials, services and employees and other contract personnel (including geologists, geophysicists, 

engineers and other specialists) required to explore for, develop, produce and market crude oil and natural gas. In 

addition, many of our competitors have financial and other resources substantially greater than those we possess and 

have established strategic long-term positions and strong governmental relationships in countries in which we may 

seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in certain respects, such as 

in bidding for drilling rights or in acquiring necessary services, equipment, 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, severance and excise taxes, capital 

expenditures and workover and remedial costs, many of which factors are or may be beyond our control. Our actual 

reserves and future net cash flows from such reserves most likely will vary from our estimates. Any significant 

variance, including any significant revisions 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, relatively 

lower prices for natural gas production. 
22

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, 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 many 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 (EndUser Exception), and a 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 will be 

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 Position Limits Rule was vacated and 

remanded to the CFTC for further proceedings by order of the U.S. District Court for the District of Columbia in 

September 2012. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that a 

position limit rule is ultimately effected, such position limit rule, 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.
23

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, 2012, approximately 3% of 

our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the 

U.S. dollar.

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

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other 

actions taken in response to these acts, could cause instability in the global financial and energy markets. The U.S. 

government has at times issued public warnings that indicate that energy assets might be specific targets of terrorist 

organizations. Any such actions and the threat of such actions could materially and adversely affect us in 

unpredictable ways, including the disruption of energy supplies and markets, increased volatility in crude oil and 

natural gas prices or the possibility that the infrastructure on which we rely could be a direct target or an indirect 

casualty of an act of terrorism, and, in turn, could materially and adversely affect our business, financial condition 

and results of operations.
24

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 EOG's crude oil and natural gas properties declines as reserves are 

produced. Except to the extent EOG acquires additional properties containing proved reserves, conducts successful 

exploration, exploitation and development activities or, through engineering studies, identifies additional behind-pipe 

zones or secondary recovery reserves, the proved reserves of EOG will decline as reserves are produced. The volumes 

to be generated from future activities of EOG are therefore highly dependent upon the level of success in finding or 

acquiring additional reserves. For related discussion, see ITEM 1A. Risk Factors. EOG's estimates of reserves filed 

with other federal agencies agree with the information set forth in "Supplemental Information to Consolidated Financial 

Statements."

Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2012. 

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 1,638,610 1,258,069 4,390,043 2,970,523 6,028,653 4,228,592

Canada 1,201,874 1,001,646 691,321 637,754 1,893,195 1,639,400

Trinidad 75,667 65,669 48,520 38,816 124,187 104,485

United Kingdom 8,797 2,570 118,333 94,731 127,130 97,301

China 130,548 130,548 - - 130,548 130,548

Argentina - - 183,916 79,452 183,916 79,452

Total 3,055,496 2,458,502 5,432,133 3,821,276 8,487,629 6,279,778

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 0.8 

million net acres will expire in 2013, 0.7 million net acres will expire in 2014 and 0.5 million net acres will expire in 

2015 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. 
25

Producing Well Summary. EOG operated 15,963 gross and 14,134 net producing crude oil and natural gas 

wells at December 31, 2012. Gross crude oil and natural gas wells include 1,460 wells with multiple completions.

Crude Oil Natural Gas Total

Gross Net Gross Net Gross Net

United States 3,490 2,702 5,977 5,012 9,467 7,714

Canada 759 643 7,043 6,351 7,802 6,994

Trinidad 13 10 29 25 42 35

United Kingdom - - 1 - 1 -

China - - 25 25 25 25

Argentina 2 1 - - 2 1

Total 4,264 3,356 13,075 11,413 17,339 14,769

Drilling and Acquisition Activities. During the years ended December 31, 2012, 2011 and 2010, EOG 

expended $7.1 billion, $6.6 billion and $5.5 billion, respectively, for exploratory and development drilling and 

acquisition of leases and producing properties, including asset retirement obligations of $127 million, $133 million 

and $72 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, 2012, 2011 and 2010:

Gross Development Wells Completed Gross Exploratory Wells Completed

Crude 

Oil

Natural 

Gas

Dry 

Hole Total

Crude

Oil

Natural 

Gas

Dry 

Hole Total

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

2010

United States 589 448 32 1,069 19 8 10 37

Canada 128 25 - 153 1 - - 1

Trinidad - - - - - 1 - 1

United Kingdom - - - - - - 3 3

China - - - - - 2 - 2

Total 717 473 32 1,222 20 11 13 44
26

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, 2012, 2011 and 2010:

Net Development Wells Completed Net Exploratory Wells Completed

Crude 

Oil

Natural 

Gas

Dry 

Hole Total

Crude 

Oil

Natural 

Gas

Dry 

Hole Total

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

2010

United States 459 374 29 862 16 7 10 33

Canada 128 25 - 153 1 - - 1

Trinidad - - - - - 1 - 1

United Kingdom - - - - - - 3 3

China - - - - - 2 - 2

Total 587 399 29 1,015 17 10 13 40

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, 2012, 2011 and 2010:

Wells in Progress at End of Period

2012 2011 2010

Gross Net Gross Net Gross Net

United States 324 267 359 282 243 205

Canada - - - - 1 1

Trinidad 1 1 - - - -

United Kingdom - - 3 2 3 2

China - - 1 1 4 4

Total 325 268 363 285 251 212
27

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, 2012, 2011 and 2010:

Gross Acquired Wells Net Acquired Wells

Crude 

Oil

Natural 

Gas Total

Crude 

Oil

Natural 

Gas Total

2012

United States 49 272 321 23 136 159

Canada - - - - - -

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

2010

Canada 1 - 1 1 - 1

Total 1 - 1 1 - 1

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.

As previously reported by EOG Resources, Inc. (EOG) in its Form 10-Q for the quarterly period ended June 

30, 2012, in the second quarter of 2012, EOG engaged in negotiations with the North Dakota Department of Health 

(NDDH) regarding a proposed consent agreement to resolve potential air emissions violations at certain of EOG's 

wells in the North Dakota Bakken shale play. Upon its discovery of the potential air emissions violations, EOG 

promptly reported to the NDDH and implemented additional preventative controls and equipment to reduce 

emissions. In consideration of EOG's self-reporting and prompt implementation of such additional controls and 

equipment, the consent agreement will provide for reduced fines. EOG expects to finalize and enter into the consent 

agreement with the NDDH in the first quarter of 2013.

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.
28

PART II

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

Securities

EOG's common stock is traded on the New York Stock Exchange (NYSE) under the ticker symbol "EOG." 

The following table sets forth, for the periods indicated, the high and low sales price per share for EOG's common 

stock, as reported by the NYSE, and the amount of the cash dividend declared per share. The quarterly cash 

dividend on EOG's common stock has historically been declared in the quarter immediately preceding the quarter of 

payment and paid on January 31, April 30, July 31 and October 31 of each year (or, if such day is not a business day, 

the immediately preceding business day).

Price Range

High Low Dividend Declared

2012

First Quarter $ 119.97 $ 99.82 $ 0.17

Second Quarter 114.33 82.48 0.17

Third Quarter 119.69 87.54 0.17

Fourth Quarter 124.50 107.76 0.17

2011

First Quarter $ 121.44 $ 90.84 $ 0.16

Second Quarter 119.82 96.62 0.16

Third Quarter 107.88 69.55 0.16

Fourth Quarter 106.20 66.81 0.16

On February 13, 2013, EOG's Board of Directors (Board) increased the quarterly cash dividend on the 

common stock from the current $0.17 per share to $0.1875 per share, effective beginning with the dividend to be 

paid on April 30, 2013, to stockholders of record as of April 16, 2013. 

As of February 13, 2013, there were approximately 1,850 record holders and approximately 281,000

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.
29

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, 2012 - October 31, 2012 10,868 $113.96 - 6,386,200

November 1, 2012 - November 30, 2012 41,076 $119.72 - 6,386,200

December 1, 2012 - December 31, 2012 59,945 $120.17 - 6,386,200

Total 111,889 $119.40

(1) The 111,889 total shares for the quarter ended December 31, 2012, and the 574,890 shares for the full year 2012 consist solely 

of shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the 

exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock or restricted 

stock unit grants or (ii) in payment of the exercise price of employee stock options. These shares do not count against the 10 

million aggregate share repurchase authorization of EOG's Board discussed below.

(2) In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During 2012, 

EOG did not repurchase any shares under the Board-authorized repurchase program.
30

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, 2007 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, 2012)

*Cumulative total return assumes reinvestment of dividends.

2007 2008 2009 2010 2011 2012

EOG $ 100.00 $ 74.99 $ 110.50 $ 104.43 $ 113.29 $ 139.82

S&P 500 $ 100.00 $ 61.51 $ 75.94 $ 85.65 $ 85.65 $ 97.13

S&P O&G E&P $ 100.00 $ 69.02 $ 103.46 $ 115.21 $ 101.81 $ 105.68
31

ITEM 6. Selected Financial Data

(In Thousands, Except Per Share Data)

Year Ended December 31 2012 2011 2010 2009 2008

Statement of Income Data:

Net Operating Revenues $ 11,682,636 $ 10,126,115 $ 6,099,896 $ 4,786,959 $ 7,127,143

Operating Income $ 1,479,797 $ 2,113,309 $ 523,319 $ 970,841 $ 3,767,185

Net Income $ 570,279 $ 1,091,123 $ 160,654 $ 546,627 $ 2,436,919

Preferred Stock Dividends - - - - 443

Net Income Available to Common Stockholders $ 570,279 $ 1,091,123 $ 160,654 $ 546,627 $ 2,436,476

Net Income Per Share Available to Common 

Stockholders

Basic $ 2.13 $ 4.15 $ 0.64 $ 2.20 $ 9.88

Diluted $ 2.11 $ 4.10 $ 0.63 $ 2.17 $ 9.72

Dividends Per Common Share $ 0.68 $ 0.64 $ 0.62 $ 0.58 $ 0.51

Average Number of Common Shares

Basic 267,577 262,735 250,876 248,996 246,662

Diluted 270,762 266,268 254,500 251,884 250,542

At December 31 2012 2011 2010 2009 2008

Balance Sheet Data:

Total Property, Plant and Equipment, Net $ 23,337,681 $ 21,288,824 $ 18,680,900 $ 16,139,225 $ 13,657,302

Total Assets 27,336,578 24,838,797 21,624,233 18,118,667 15,951,226

Long-Term Debt and Current Portion of LongTerm Debt 6,312,181 5,009,166 5,223,341 2,797,000 1,897,000

Total Stockholders' Equity 13,284,764 12,640,904 10,231,632 9,998,042 9,014,497
32

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 2012 totaled $570 million as compared to $1,091 million for 2011. At December 31, 2012, 

EOG's total estimated net proved reserves were 1,811 million barrels of oil equivalent (MMBoe), a decrease of 243 

MMBoe from December 31, 2011. During 2012, net proved crude oil and condensate and natural gas liquids 

(NGLs) reserves increased by 276 million barrels (MMBbl), and net proved natural gas reserves decreased by 3,111 

billion cubic feet or 519 MMBoe.

Operations

Several important developments have occurred since January 1, 2012. 

United States and Canada. EOG's efforts to identify plays with large reserve potential has proven a 

successful supplement to its base development and exploitation program in the United States and Canada. EOG 

continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute 

substantially to EOG's crude oil and liquids-rich natural gas production. EOG has placed an emphasis on applying 

its horizontal drilling and completion expertise gained from its natural gas resource plays to unconventional crude oil 

and liquids-rich reservoirs. In 2012, EOG focused its efforts on developing its existing North American crude oil 

and liquids-rich acreage. In addition, EOG continues to evaluate certain potential crude oil and, to a lesser extent, 

liquids-rich natural gas exploration and development prospects. During 2012, crude oil and condensate and NGLs

production accounted for approximately 46% of total company production as compared to 37% during 2011. In 

North America, crude oil and condensate and NGLs production accounted for approximately 53% of total North 

American production during 2012 as compared to 42% in 2011. This liquids growth primarily reflects increased 

production from the Eagle Ford Shale near San Antonio, Texas, the North Dakota Bakken and the Permian Basin. In 

2012, EOG's net Eagle Ford Shale production averaged 83.5 thousand barrels per day (MBbld) of crude oil and 

condensate and NGLs as compared to 34.1 MBbld in 2011. Based on current trends, EOG expects its 2013 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 2012. EOG's major producing areas are in Louisiana, New Mexico, North Dakota, 

Texas, Utah, Wyoming and western Canada. 

EOG delivers its crude oil to various markets in the United States, including sales points on the Gulf Coast

where sales are based upon the Light Louisiana Sweet (LLS) crude oil index. As part of its diversification strategy 

for its crude-by-rail shipments, in April 2012, EOG completed the construction of a crude oil unloading facility in St. 

James, Louisiana, where sales are based upon the LLS crude oil index. This facility, which received the first unit 

train of EOG crude oil in April 2012, has a capacity of approximately 120 MBbld, of which 100 MBbld belongs to 

EOG. To support its Permian Basin operations, EOG commissioned a crude oil loading facility in Barnhart, Texas,

in 2012. EOG believes that its crude-by-rail facilities provide a distinct competitive advantage giving it the ability to 

direct its crude oil shipments via rail car to the most favorable markets, including both the Gulf Coast and Cushing, 

Oklahoma, markets. Additionally, in July 2012, EOG began shipping a portion of its Eagle Ford Shale crude oil 

production to Gulf Coast sales points on the newly completed Enterprise Products Partners L.P. crude oil pipeline. 
33

During 2012, EOG increased production of processed sand at its state-of-the-art Chippewa Falls, 

Wisconsin, sand plant. The plant processes sand from multiple nearby EOG-owned sand mines. The first unit train 

of processed sand was dispatched from Chippewa Falls in January 2012. During 2012, EOG shipped 70 sand unit 

trains of approximately 100 cars each to a new EOG sand storage facility in Refugio, Texas, where sand can also be 

coated for added strength. From Refugio, the sand is shipped primarily to the South Texas Eagle Ford Shale. EOG 

also ships its processed sand to other plays, including the North Dakota Bakken and the Permian Basin.

EOG Resources Canada Inc. (EOGRC) owned a 30% interest in both the planned liquefied natural gas 

export terminal to be located near the Port of Kitimat, British Columbia (Kitimat LNG Terminal) and the proposed 

Pacific Trail Pipelines (PTP) which is intended to link Western Canada's natural gas producing regions to the 

Kitimat LNG Terminal. In December 2012, EOGRC signed a purchase and sale agreement for the sale of its entire 

interest in the Kitimat LNG Terminal and PTP, as well as approximately 28,500 undeveloped net acres in the Horn 

River Basin, to Chevron Canada Limited. The transaction closed in February 2013. 

International. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. Several 

fields in the South East Coast Consortium Block, Modified U(a) Block and Modified U(b) Block, as well as the 

Pelican Field, have been developed and are producing natural gas and crude oil and condensate. In February 2012, 

production from both the Toucan Field in Block 4(a) and the adjacent EMZ Area began supplying natural gas under 

a contract with the Natural Gas Company of Trinidad and Tobago. 

During the fourth quarter of 2012, EOG began drilling an exploratory well in the Modified U(a) Block

which was successful. This well and three additional wells to be drilled in 2013 will be completed in the first half of 

2013.

In 2006, EOG Resources United Kingdom Limited (EOGUK) participated in the drilling and successful 

testing of the Columbus prospect in the Central North Sea Block 23/16f. EOG has a 25% non-operating working 

interest in this block. A successful Columbus natural gas prospect appraisal well was drilled during the third quarter 

of 2007. The field operator submitted a revised field development plan to the U.K. Department of Energy and 

Climate Change (DECC) during the third quarter of 2012 and anticipates receiving approval of this plan in the 

second quarter of 2013. The project participants are currently negotiating commercial agreements. 

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 its 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. Field 

development plans for the Conwy and Corfe fields were approved by the DECC in March 2012. The production 

platform and pipelines were installed in 2012, and EOG expects to begin processing facility installation during the 

first half of 2013. The Conwy development drilling program is expected to commence during the second quarter of 

2013, with initial production expected in the fourth quarter of 2013. 

In 2009, EOGUK was awarded a license for Block 21/12b in the Central North Sea where it expects to drill 

an exploratory well to test a crude oil prospect in late 2013. EOGUK has 100% interest in this block.

In 2011, EOG signed two exploration contracts and one farm-in agreement covering approximately 80,000 

net acres in the Neuquén Basin in Neuquén Province, Argentina. During the first half of 2012, EOG participated in 

the drilling and completion of a vertical well in the Bajo del Toro Block. In the first half of 2012, EOG drilled a 

well to monitor future well completions in the Aguada del Chivato Block and drilled and completed a horizontal well 

in this block. Both the horizontal and vertical wells that were completed are under evaluation. During the first 

quarter of 2013, EOG plans to complete the monitoring well in the Aguada del Chivato Block.

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.
34

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 32% and 28% at December 31, 2012 and 2011, respectively. As used in this calculation, total capitalization 

represents the sum of total current and long-term debt and total stockholders' equity. 

On September 10, 2012, EOG closed its sale of $1,250 million aggregate principal amount of 2.625% 

Senior Notes due 2023 (Notes). Interest on the Notes is payable semi-annually in arrears on March 15 and 

September 15 of each year, beginning March 15, 2013. Net proceeds from the Notes offering of approximately 

$1,234 million were used for general corporate purposes, including the repayment of outstanding commercial paper 

borrowings and funding of capital expenditures.

During 2012, EOG funded $7.5 billion in exploration and development and other property, plant and 

equipment expenditures (excluding asset retirement obligations), paid $181 million in dividends to common 

stockholders and purchased $59 million of treasury stock in connection with stock compensation plans, primarily by 

utilizing cash provided from its operating activities, net proceeds of $1,234 million from the issuance of the Notes,

proceeds of $1,310 million from the sale of certain North American assets and proceeds of $83 million from stock 

options exercised and employee stock purchase plan activity.

Total anticipated 2013 capital expenditures are estimated to range from approximately $7.0 billion to $7.2 

billion, excluding acquisitions. The majority of 2013 expenditures will be focused on United States crude oil and, to 

a lesser extent, liquids-rich natural gas drilling activity. EOG expects capital expenditures to be greater than cash 

flow from operating activities for 2013. EOG's business plan includes selling certain non-core assets in 2013, 

realizing proceeds of approximately $550 million, to cover the anticipated shortfall. 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 (2011 Facility) and equity and debt offerings. 

When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer 

EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of 

the strongest prospect inventories in EOG's history. 
35

Results of Operations 

The following review of operations for each of the three years in the period ended December 31, 2012, should 

be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1. 

Net Operating Revenues

During 2012, net operating revenues increased $1,557 million, or 15%, to $11,683 million from $10,126

million in 2011. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil 

and condensate, NGLs and natural gas, in 2012 increased $1,100 million, or 16%, to $7,958 million from $6,858

million in 2011. During 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative 

contracts of $394 million compared to net gains of $626 million in 2011. 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 $981 million, or 46%, during 2012, to 

$3,097 million from $2,116 million in 2011. Gains on asset dispositions, net, totaled $193 million and $493 million in 

2012 and 2011, respectively. 
36

Wellhead volume and price statistics for the years ended December 31, 2012, 2011 and 2010 were as follows:

Year Ended December 31 2012 2011 2010

Crude Oil and Condensate Volumes (MBbld) (1)

United States 149.3 102.0 63.2

Canada 7.0 7.9 6.7

Trinidad 1.5 3.4 4.7

Other International (2) 0.1 0.1 0.1

Total 157.9 113.4 74.7

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

United States $ 98.38 $ 92.92 $ 74.88

Canada 86.08 91.92 72.66

Trinidad 92.26 90.62 68.80

Other International (2) 89.57 100.11 73.11

Composite 97.77 92.79 74.29

Natural Gas Liquids Volumes (MBbld) (1)

United States 55.1 41.5 29.5

Canada 0.8 0.9 0.9

Total 55.9 42.4 30.4

Average Natural Gas Liquids Prices ($/Bbl) (3)

United States $ 35.41 $ 50.37 $ 41.68

Canada 44.13 52.69 43.40

Composite 35.54 50.41 41.73

Natural Gas Volumes (MMcfd) (1)

United States 1,034 1,113 1,133

Canada 95 132 200

Trinidad 378 344 341

Other International (2) 9 13 14

Total 1,516 1,602 1,688

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

United States $ 2.51 $ 3.92 $ 4.30

Canada 2.49 3.71 3.91

Trinidad 3.72 3.53 2.65

Other International (2) 5.71 5.62 4.90

Composite 2.83 3.83 3.93

Crude Oil Equivalent Volumes (MBoed) (4)

United States 376.6 329.1 281.5

Canada 23.6 30.7 40.9

Trinidad 64.5 60.7 61.5

Other International (2) 1.7 2.2 2.5

Total 466.4 422.7 386.4

Total MMBoe (4) 170.7 154.3 141.1

(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.
37

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 Shale and 

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 Shale (7 

MBbld), the Fort Worth Basin Barnett Shale (3 MBbld) and the Permian Basin (2 MBbld). EOG's composite 

average NGLs price in 2012 decreased 30% to $35.54 per barrel compared to $50.41 per barrel in 2011. 

Wellhead natural gas revenues in 2012 decreased $669 million, or 30%, to $1,572 million from $2,241

million in 2011. The decrease was due to a lower composite average wellhead natural gas price ($554 million) and 

decreased natural gas deliveries ($115 million). Natural gas deliveries in 2012 decreased 86 MMcfd, or 5%, to 

1,516 MMcfd from 1,602 MMcfd in 2011. The decrease was primarily due to lower production in the United States 

(79 MMcfd) and Canada (37 MMcfd), partially offset by increased production in Trinidad (34 MMcfd). The 

decrease in the United States was primarily attributable to asset sales and reduced natural gas drilling activity. The 

decrease in Canada primarily reflects decreased production in Alberta and the Horn River Basin area. The increase 

in Trinidad was primarily attributable to an increase in contractual deliveries. EOG's composite average wellhead 

natural gas price decreased 26% to $2.83 per Mcf in 2012 from $3.83 per Mcf in 2011.

During 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts 

of $394 million, which included net realized gains 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 realized gains of 

$181 million. 

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, 

NGLs and natural gas as well as fees associated with gathering third-party natural gas. For the years ended 

December 31, 2012, 2011 and 2010, 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 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.

2011 compared to 2010. Wellhead crude oil and condensate revenues in 2011 increased $1,839 million, or 

92%, to $3,838 million from $1,999 million in 2010, due to an increase of 39 MBbld, or 52%, in wellhead crude oil 

and condensate deliveries ($1,074 million) and a higher composite average wellhead crude oil and condensate price 

($765 million). The increase in deliveries primarily reflects increased production in Texas (35 MBbld) and 

Colorado (3 MBbld). Production increases in Texas were the result of increased production from the Eagle Ford 

Shale (26 MBbld) and Fort Worth Basin Barnett Combo (8 MBbld) plays. EOG's composite average wellhead crude 

oil and condensate price for 2011 increased 25% to $92.79 per barrel compared to $74.29 per barrel in 2010.
38

NGLs revenues in 2011 increased $317 million, or 69%, to $779 million from $462 million in 2010, due to 

an increase of 12 MBbld, or 39%, in NGLs deliveries ($183 million) and a higher composite average price ($134 

million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale (6 

MBbld), the Eagle Ford Shale (4 MBbld) and the Rocky Mountain area (3 MBbld). EOG's composite average 

NGLs price in 2011 increased 21% to $50.41 per barrel compared to $41.73 per barrel in 2010. 

Wellhead natural gas revenues in 2011 decreased $179 million, or 7%, to $2,241 million from $2,420 

million in 2010. The decrease was due to reduced natural gas deliveries ($123 million) and a lower composite 

average wellhead natural gas price ($56 million). EOG's composite average wellhead natural gas price decreased 

3% to $3.83 per Mcf in 2011 from $3.93 per Mcf in 2010.

Natural gas deliveries in 2011 decreased 86 MMcfd, or 5%, to 1,602 MMcfd from 1,688 MMcfd in 2010. 

The decrease was primarily due to lower production in Canada (68 MMcfd) and the United States (20 MMcfd). The 

decrease in Canada primarily reflects sales of certain shallow natural gas assets in 2010, partially offset by increased 

production from the Horn River Basin area. The decrease in the United States was primarily attributable to 

decreased production in the Rocky Mountain area (36 MMcfd), Louisiana (17 MMcfd), Mississippi (11 MMcfd), 

New Mexico (8 MMcfd) and Kansas (5 MMcfd), partially offset by increased production in Texas (38 MMcfd) and 

Pennsylvania (23 MMcfd). 

During 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts 

of $626 million, which included net realized gains of $181 million. During 2010, EOG recognized net gains on the 

mark-to-market of financial commodity derivative contracts of $62 million, which included net realized gains of $7 

million. 

During 2011, gathering, processing and marketing revenues and marketing costs increased primarily as a 

result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs 

in 2011 increased $19 million to $44 million from $25 million in 2010, primarily as a result of increased crude oil 

marketing activities.

Operating and Other Expenses

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 barrel of oil equivalent (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

Depreciation, Depletion and Amortization (DD&A) -

Oil and Gas Properties 17.71 15.52

Other Property, Plant and Equipment 0.85 0.79

General and Administrative (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.
39

Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG 

from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the 

following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease 

and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, 

salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. 

Workovers are operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and 

increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to 

increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs 

within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time. 

In general, operating and maintenance costs for wells producing crude oil are higher than operating and maintenance 

costs for wells producing natural gas. 

Lease and well expenses of $1,000 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 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 $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 Shale ($101 million) and the Rocky 

Mountain area ($73 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 field calculations. There are several 

factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or 

acquisition of new wells, disposition of existing wells, reserve revisions (upward or downward) primarily related to 

well performance, 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, crudeby-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 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 Shale.

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).
40

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 $17 million to $98 million in 2012 compared to $81 million in 

2011. The increase primarily reflects increased activities in the Eagle Ford Shale ($21 million), partially offset by 

decreased costs in the Fort Worth Basin Barnett Shale area ($7 million).

Exploration costs of $186 million in 2012 increased $14 million from $172 million for the same prior year 

period primarily due to increased expenditures in the United States.

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved 

oil and gas properties and other assets. Unproved properties with individually significant acquisition costs are 

amortized over the lease term and analyzed on a property-by-property basis for any impairment in value. Unproved 

properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs 

estimated to be nonproductive is amortized over the remaining lease term. When circumstances indicate that a 

proved property may be impaired, EOG compares expected undiscounted future cash flows at a producing field level 

to the unamortized capitalized cost of the asset. If the future undiscounted cash flows are lower than the unamortized 

capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated by using the Income 

Approach as described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's 

Accounting Standards Codification (ASC). For certain assets held for sale, EOG utilizes accepted bids as the basis 

for determining fair value.

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 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 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. 
41

2011 compared to 2010. During 2011, operating expenses of $8,013 million were $2,436 million higher 

than the $5,577 million incurred in 2010. The following table presents the costs per Boe for the years ended 

December 31, 2011 and 2010:

2011 2010

Lease and Well $ 6.11 $ 4.96

Transportation Costs 2.79 2.74

DD&AOil and Gas Properties (1) 15.52 13.19

Other Property, Plant and Equipment 0.79 0.79

G&A 1.98 1.99

Net Interest Expense 1.36 0.92

Total (2) $ 28.55 $ 24.59

(1) The 2010 amount excludes the reductions in the estimated fair value of the contingent consideration liability 

of $24 million, or $0.17 per Boe, related to the acquisition of certain unproved acreage.

(2) Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing 

costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, 

DD&A, G&A and net interest expense for 2011 compared to 2010 are set forth below.

Lease and well expenses of $942 million in 2011 increased $244 million from $698 million in 2010 

primarily due to higher operating and maintenance expenses in the United States ($188 million), increased lease and 

well administrative expenses in the United States ($33 million), increased workover expenditures in the United 

States ($11 million) and Canada ($4 million) and unfavorable changes in the Canadian exchange rate ($6 million),

partially offset by lower operating and maintenance costs in Canada ($4 million).

Transportation costs of $430 million in 2011 increased $45 million from $385 million in 2010 primarily 

due to increased transportation costs in the Eagle Ford Shale ($30 million), the Upper Gulf Coast region ($16 

million) and the Fort Worth Basin Barnett Shale area ($9 million), partially offset by decreased transportation costs 

in Canada ($4 million), the Rocky Mountain area ($2 million) and the South Texas area ($2 million). The net 

increase in transportation costs primarily reflects increased volumes transported to downstream markets. 

DD&A expenses in 2011 increased $574 million to $2,516 million from $1,942 million in 2010. DD&A 

expenses associated with oil and gas properties in 2011 were $563 million higher than in 2010 primarily due to 

higher unit rates ($375 million), increased production in the United States ($249 million), a reduction during 2010 in 

the fair value of the contingent consideration liability ($24 million) and unfavorable changes in the Canadian 

exchange rate ($11 million), partially offset by a decrease in production in Canada ($77 million). DD&A rates 

increased due primarily to a proportional increase in production from higher cost properties in the United States 

($306 million), Trinidad ($37 million) and Canada ($9 million).

DD&A expenses associated with other property, plant and equipment were $11 million higher in 2011 than 

in 2010 primarily due to gathering and processing assets being placed in service in the Eagle Ford Shale ($5 million) 

and the Rocky Mountain area ($3 million).

G&A expenses of $305 million in 2011 were $25 million higher than 2010 due primarily to higher 

employee-related costs.

Net interest expense of $210 million in 2011 increased $80 million from $130 million in 2010 primarily due to 

a higher average debt balance ($56 million), lower capitalized interest ($18 million) and the write-off of fees associated 

with revolving credit facilities cancelled in 2011 in connection with the establishment of the 2011 Facility ($6 million).
42

Gathering and processing costs increased $14 million to $81 million in 2011 compared to $67 million in 

2010. The increase primarily reflects increased activities in the Fort Worth Basin Barnett Shale area ($10 million), 

the Eagle Ford Shale ($5 million) and Canada ($5 million), partially offset by decreased activities in the Upper Gulf 

Coast region ($5 million) and the Rocky Mountain area ($4 million).

Exploration costs of $172 million in 2011 decreased $15 million from $187 million for the same prior year 

period primarily due to decreased geological and geophysical expenditures in the United States.

Impairments of $1,031 million in 2011 increased $288 million from $743 million in 2010 primarily due to 

increased impairments of proved properties and other property, plant and equipment in the United States. EOG 

recorded impairments of proved properties and other property, plant and equipment of $834 million and $526 

million in 2011 and 2010, respectively. The 2011 amount includes impairments of $745 million related to certain

North American natural gas assets as a result of declining commodity prices and accepted bids.

Taxes other than income in 2011 increased $94 million to $411 million (6.0% of wellhead revenues) from 

$317 million (6.5% of wellhead revenues) in 2010. The increase in taxes other than income was primarily due to 

increased severance/production taxes primarily as a result of increased wellhead revenues in the United States ($101

million) and a decrease in credits available to EOG in 2011 for Texas high cost gas severance tax rate reductions as a 

result of fewer wells qualifying for such credit ($8 million), partially offset by lower ad valorem/property taxes in the 

United States ($9 million) and Canada ($4 million) and decreased severance/production taxes in Trinidad ($4 

million).

Other income, net was $7 million in 2011 compared to $14 million in 2010. The decrease of $7 million was

primarily due to operating losses on EOG's investment in the PTP ($5 million) and an increase in foreign currency 

transaction losses ($5 million), partially offset by higher equity income from ammonia plants in Trinidad ($3 

million).

Income tax provision of $819 million in 2011 increased $572 million from $247 million in 2010 due 

primarily to greater pretax income. The net effective tax rate for 2011 decreased to 43% from 61% in 2010. The 

effective tax rate for 2011 exceeded the United States statutory tax rate (35%) due mostly to foreign earnings in 

Trinidad (55% statutory tax rate) combined with losses in Canada (27% statutory tax rate). 

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2012, were net 

funds generated from operations, net proceeds from issuances of long-term debt, proceeds from asset sales, net 

proceeds from the sale of Common Stock, proceeds from stock options exercised and employee stock purchase plan 

activity, net commercial paper borrowings and borrowings under other uncommitted credit facilities and revolving 

credit facilities. The primary uses of cash were exploration and development expenditures; other property, plant and 

equipment expenditures; dividend payments; and repayments of debt.

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 flow 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). 
43

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).

2011 compared to 2010. Net cash provided by operating activities of $4,578 million in 2011 increased 

$1,869 million from $2,709 million in 2010 primarily reflecting an increase in wellhead revenues ($1,977 million), 

favorable changes in the net cash flow from the settlement of financial commodity derivative contracts ($174 

million) and favorable changes in working capital and other assets and liabilities ($137 million), partially offset by 

an increase in cash operating expenses ($383 million), an increase in cash paid for interest expense ($40 million) and

an increase in cash paid for income taxes ($27 million).

Net cash used in investing activities of $5,755 million in 2011 increased by $852 million from $4,903

million for the same period of 2010 due primarily to an increase in additions to oil and gas properties ($1,084 

million), unfavorable changes in working capital associated with investing activities ($446 million) and an increase 

in additions to other property, plant and equipment ($286 million), partially offset by an increase in proceeds from 

sales of assets ($761 million) and the acquisition of Galveston LNG Inc. in 2010 ($210 million). 

Net cash provided by financing activities of $1,009 million in 2011 included net proceeds from the sale of 

Common Stock ($1,388 million) and proceeds from stock options exercised and employee stock purchase plan 

activity ($36 million). Cash used in financing activities during 2011 included the repayment of long-term debt ($220 

million), cash dividend payments ($167 million), treasury stock purchases in connection with stock compensation 

plans ($24 million) and debt issuance costs associated with the establishment of the 2011 Facility ($5 million).

Total Expenditures 

The table below sets out components of total expenditures for the years ended December 31, 2012, 2011 and 

2010 (in millions):

2012 2011 2010

Expenditure Category

Capital

Drilling and Facilities $ 6,184 $ 5,878 $ 4,634

Leasehold Acquisitions (1) 505 301 399

Property Acquisitions 1 4 18

Capitalized Interest 50 58 76

Subtotal 6,740 6,241 5,127

Exploration Costs 186 172 187

Dry Hole Costs 15 53 72

Exploration and Development Expenditures 6,941 6,466 5,386

Asset Retirement Costs 127 133 72

Total Exploration and Development 

Expenditures 7,068 6,599 5,458

Other Property, Plant and Equipment (2)686 656 581

Total Expenditures $ 7,754 $ 7,255 $ 6,039

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

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

transaction in the Eagle Ford Shale. 
44

Exploration and development expenditures of $6,941 million for 2012 were $475 million higher than the 

prior year due primarily to increased drilling and facilities expenditures in the United States ($263 million), the 

United Kingdom ($65 million), Argentina ($41 million) and Canada ($18 million); increased leasehold acquisition 

expenditures in the United States ($176 million) and Canada ($27 million); and increased exploration costs in the 

United States ($14 million). These increases were partially offset by decreased drilling and facilities expenditures in 

Trinidad ($84 million), decreased dry hole costs in the United States ($29 million) and decreased capitalized interest 

in the United States ($8 million). The 2012 exploration and development expenditures of $6,941 million included 

$5,989 million in development, $901 million in exploration and $50 million in capitalized interest. The 2011

exploration and development expenditures of $6,466 million included $5,797 million in development, $607 million 

in exploration, $58 million in capitalized interest and $4 million in property acquisitions. In 2011, other property, 

plant and equipment expenditures included $231 million for sand mine and sand processing assets. The 2010

exploration and development expenditures of $5,386 million included $4,366 million in development, $926 million 

in exploration, $76 million in capitalized interest and $18 million in property acquisitions. In 2010, other property, 

plant and equipment expenditures included $210 million for the acquisition of Galveston LNG Inc. 

The level of exploration and development expenditures, including acquisitions, will vary in future periods 

depending on energy market conditions and other related economic factors. EOG has significant flexibility with 

respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as 

circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to 

its operations, such commitments are not expected to be material when considered in relation to the total financial 

capacity of EOG.

Derivative Transactions

During 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts 

of $394 million, which included net realized gains 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 realized gains of 

$181 million. See Note 11 to Consolidated Financial Statements.

Commodity Derivative Contracts. The total fair value of EOG's crude oil and natural gas derivative

contracts is reflected on the Consolidated Balance Sheets at December 31, 2012, as a net asset of $145 million. 

Presented below is a comprehensive summary of EOG's crude oil derivative contracts at February 21, 2013, with 

notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl). 

Crude Oil Derivative Contracts

Weighted

Volume (1) Average Price

(Bbld) ($/Bbl)

2013

January 2013 (closed) 101,000 $ 99.29

February 1, 2013 through April 30, 2013 109,000 99.17

May 1, 2013 through June 30, 2013 101,000 99.29

July 1, 2013 through December 31, 2013 93,000 98.44

(1) EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain 

current derivative contracts for additional three-month or six-month periods. Options covering a notional 

volume of 8,000 Bbld are exercisable on April 30, 2013. If the counterparties exercise all such options, the 

notional volume of EOG's existing crude oil derivative contracts will increase by 8,000 Bbld at an average price 

of $97.66 per barrel for the period May 1, 2013 through July 31, 2013. Options covering a notional volume of 

62,000 Bbld are exercisable on June 28, 2013. If the counterparties exercise all such options, the notional 

volume of EOG's existing crude oil derivative contracts will increase by 62,000 Bbld at an average price of 

$100.24 per barrel for the period July 1, 2013 through December 31, 2013. Options covering a notional 

volume of 54,000 Bbld are exercisable on December 31, 2013. If the counterparties exercise all such options, 

the notional volume of EOG's existing crude oil derivative contracts will increase by 54,000 Bbld at an average 

price of $98.91 per barrel for the period January 1, 2014 through June 30, 2014.
45

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at February 21, 

2013, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices 

expressed in dollars per MMBtu ($/MMBtu). 

Natural Gas Derivative Contracts

Volume 

(MMBtud)

Weighted 

Average Price 

($/MMBtu)

2013 (1)

January 1, 2013 through February 28, 2013 (closed) 150,000 $4.79

March 1, 2013 through December 31, 2013 150,000 4.79

2014 (2)

(1) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into 

derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each 

monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural 

gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for the 

period from March 1, 2013 through December 31, 2013.

(2) In July 2012, EOG settled its natural gas financial price swap contracts for the period January 1, 2014 through 

December 31, 2014 and received proceeds of $36.6 million. In connection with these contracts, the 

counterparties retain an option of entering into derivative contracts at future dates. Such options are exercisable 

monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, 

the notional volume of EOG’s existing natural gas derivative contracts will increase by 150,000 MMBtud at an 

average price of $4.79 per MMBtu for each month of 2014.

Financing

EOG's debt-to-total capitalization ratio was 32% at December 31, 2012, compared to 28% at December 31, 

2011. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total 

stockholders' equity.

During 2012, the principal amount of total debt outstanding increased $1,250 million to $6,290 million at 

December 31, 2012, from $5,040 million at December 31, 2011. The estimated fair value of EOG's debt at 

December 31, 2012 and 2011 was $7,032 million and $5,657 million, respectively. The estimated fair value of debt 

was based upon quoted market prices and, where such prices were not available, other observable inputs regarding

interest rates available to EOG at year-end. EOG's debt is primarily at fixed interest rates. While changes in interest 

rates affect the fair value of EOG's debt, such changes do not expose EOG to material fluctuations in earnings or 

cash flow. During 2012, EOG entered into a capital lease transaction for the use of newly constructed crude oil 

storage tanks in the Eagle Ford Shale. At December 31, 2012, the capital lease liability totaled $63 million. See 

Note 2 to Consolidated Financial Statements. 

During 2012, EOG utilized cash provided by operating activities, proceeds from the issuance of the Notes 

as further described below, proceeds from asset sales and cash provided by borrowings from its commercial paper 

program to fund its capital programs. While EOG maintains a $2.0 billion commercial paper program, the maximum 

outstanding at any time during 2012 was $959 million, and the amount outstanding at year-end was zero. The 

maximum amount outstanding under uncommitted credit facilities during 2012 was $6 million with zero outstanding 

at year-end. The average borrowings outstanding under the commercial paper program and the uncommitted credit 

facilities were $236 million and $41 thousand, respectively, during the year 2012. EOG considers this excess 

availability, which is backed by its $2.0 billion senior unsecured Revolving Credit Agreement described in Note 2 to 

Consolidated Financial Statements, to be ample to meet its ongoing operating needs.

On September 10, 2012, EOG closed its sale of $1.25 billion aggregate principal amount of the Notes. 

Interest on the Notes is payable semi-annually in arrears on March 15 and September 15 of each year, beginning 

March 15, 2013. Net proceeds from the Notes offering of approximately $1,234 million were used for general 

corporate purposes, including repayment of outstanding commercial paper borrowings and funding of capital 

expenditures. 
46

Contractual Obligations

The following table summarizes EOG's contractual obligations at December 31, 2012, (in thousands):

2018 &

Contractual Obligations (1) Total 2013 2014 - 2015 2016 - 2017 Beyond

Current and Long-Term Debt $ 6,290,000 $ 400,000 $ 1,000,000 $ 1,000,000 $ 3,890,000

Capital Lease 62,968 6,579 11,325 12,908 32,156

Non-Cancelable Operating Leases 523,311 152,021 97,804 78,232 195,254

Interest Payments on Long-Term 

Debt and Capital Lease 1,690,093 269,996 460,030 416,957 543,110

Transportation and Storage Service 

Commitments (2) 5,129,835 1,582,227 1,267,751 1,111,416 1,168,441

Drilling Rig Commitments (3) 263,301 167,408 86,472 3,421 6,000

Seismic Purchase Obligations 15,572 15,397 175 - -

Fracturing Services Obligations 275,319 220,531 51,164 3,624 -

Other Purchase Obligations 104,520 76,550 18,537 9,204 229

Total Contractual Obligations $ 14,354,919 $ 2,890,709 $ 2,993,258 $ 2,635,762 $ 5,835,190

(1) This table does not include the liability for unrecognized tax benefits, EOG's pension or postretirement benefit obligations or 

liability for dismantlement, abandonment and asset retirement obligations (see Notes 5, 6 and 14, respectively, to Consolidated 

Financial Statements). 

(2) Amounts shown are based on current transportation and storage rates and the foreign currency exchange rates used to convert 

Canadian dollars and British pounds into United States dollars at December 31, 2012. Management does not believe that any 

future changes in these rates before the expiration dates of these commitments will have a material adverse effect on the financial 

condition or results of operations of EOG.

(3) Amounts shown represent minimum future expenditures for drilling rig services. EOG's expenditures for drilling rig services 

will exceed such minimum amounts to the extent EOG utilizes the drilling rigs subject to a particular contractual commitment 

for a period greater than the period set forth in the governing contract or if EOG utilizes drilling rigs in addition to the drilling 

rigs subject to the particular contractual commitment (for example, pursuant to the exercise of an option to utilize additional 

drilling rigs provided for in the governing contract).

Off-Balance Sheet Arrangements

EOG does not participate in financial transactions that generate relationships with unconsolidated entities or 

financial partnerships. Such entities or partnerships, often referred to as variable interest entities (VIE) or special 

purpose entities (SPE), are generally established for the purpose of facilitating off-balance sheet arrangements or 

other limited purposes. EOG was not involved in any unconsolidated VIE or SPE financial transactions or any other 

"off-balance sheet arrangement" (as defined in Item 303(a)(4)(ii) of Regulation S-K) during any of the periods 

covered by this report, and currently has no intention of participating in any such transaction or arrangement in the 

foreseeable future. 

Foreign Currency Exchange Rate Risk

During 2012, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign 

countries, including Canada, Trinidad, the United Kingdom, China and Argentina. The foreign currency most 

significant to EOG's operations during 2012 was the Canadian dollar. The fluctuation of the Canadian dollar in 2012

impacted both the revenues and expenses of EOG's Canadian subsidiaries. However, since Canadian commodity 

prices are largely correlated to United States prices, the changes in the Canadian currency exchange rate have less of 

an impact on the Canadian revenues than the Canadian expenses. EOG continues to monitor the foreign currency 

exchange rates of countries in which it is currently conducting business and may implement measures to protect 

against foreign currency exchange rate risk.
47

Effective March 9, 2004, EOG entered into a foreign currency swap transaction with multiple banks to 

eliminate exchange rate impacts that may result from the notes offered by one of its Canadian subsidiaries on the 

same date (see Note 2 to Consolidated Financial Statements). EOG accounts for the foreign currency swap 

transaction using the hedge accounting method, pursuant to the provisions of the Derivatives and Hedging Topic of 

the ASC. Under those provisions, as of December 31, 2012, EOG recorded the fair value of the foreign currency 

swap of $55 million in Other Liabilities on the Consolidated Balance Sheets. Changes in the fair value of the foreign 

currency swap resulted in no net impact to Net Income on the Consolidated Statements of Income and 

Comprehensive Income. The after-tax net impact from the foreign currency swap transaction resulted in an increase

of $1 million to Accumulated Other Comprehensive Income in the Stockholders' Equity section of the Consolidated 

Balance Sheets.

Outlook

Pricing. Crude oil and natural gas prices have been volatile, and this volatility is expected to continue. As a 

result of the many uncertainties associated with the world political environment, the availabilities of other worldwide 

energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, EOG 

is unable to predict what changes may occur in crude oil and condensate, NGLs, natural gas, ammonia and methanol 

prices in the future. The market price of crude oil and condensate, NGLs and natural gas in 2013 will impact the amount 

of cash generated from operating activities, which will in turn impact EOG's financial position. See ITEM 1A. Risk 

Factors.

Including the impact of EOG's 2013 crude oil derivative contracts (exclusive of options) and based on EOG's 

tax position, EOG's price sensitivity in 2013 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 $28 million for net income and

$41 million for cash flows from operating activities. Including the impact of EOG's 2013 natural gas derivative 

contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2013 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 $18 million for net income and $27 million for cash 

flows from operating activities. For information regarding EOG's crude oil and natural gas financial commodity 

derivative contracts at February 21, 2013, see "Derivative Transactions" above.

Capital. EOG plans to continue to focus a substantial portion of its exploration and development expenditures 

in its major producing areas in the United States. In particular, EOG will be focused on United States crude oil drilling 

activity in its Eagle Ford, Bakken and Three Forks plays and, to a lesser extent, liquids-rich natural gas drilling. 

United States natural gas drilling activity will be limited to that necessary to hold acreage, primarily in the Marcellus. 

In order to diversify its overall asset portfolio, EOG expects to conduct exploratory activity in other areas outside of the 

United States and Canada and will continue to evaluate the potential for involvement in additional exploitation-type 

opportunities. 

The total anticipated 2013 capital expenditures of $7.0 to $7.2 billion, excluding acquisitions, is structured 

to maintain the flexibility necessary under EOG's strategy of funding its exploration, development, exploitation and 

acquisition activities primarily from available internally generated cash flow and the sale of certain non-core assets. 

EOG expects capital expenditures to be greater than cash flow from operating activities for 2013. EOG's business 

plan includes selling certain non-core assets in 2013, realizing proceeds of approximately $550 million, to cover the 

anticipated shortfall. However, EOG has significant flexibility with respect to financing alternatives, including 

borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, 

borrowings under its revolving credit facility and equity and debt offerings.

Operations. EOG expects to increase overall production in 2013 by 4% over 2012 levels. Total liquids

production is expected to increase by 23%, comprised of an increase in crude oil and condensate and NGLs

production of 28% and 10%, respectively. North American natural gas production is expected to decrease by 15% 

from 2012 levels.
48

Summary of Critical Accounting Policies

EOG prepares its financial statements and the accompanying notes in conformity with accounting principles 

generally accepted in the United States of America, which require management to make estimates and assumptions 

about future events that affect the reported amounts in the financial statements and the accompanying notes. EOG 

identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of EOG's 

financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their 

application. Critical accounting policies cover accounting matters that are inherently uncertain because the future 

resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of 

each of the critical accounting policies. Following is a discussion of EOG's most critical accounting policies:

Proved Oil and Gas Reserves 

EOG's engineers estimate proved oil and gas reserves in accordance with United States Securities and 

Exchange Commission regulations, which directly impact financial accounting estimates, including depreciation, 

depletion and amortization. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and 

natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future 

years from known reservoirs under economic and operating conditions existing at the time the estimates were made. 

The process of estimating quantities of proved oil and gas reserves is complex, requiring significant subjective 

decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data 

for a given reservoir may also change substantially over time as a result of numerous factors including, but not 

limited to, additional development activity, evolving production history and continual reassessment of the viability of 

production under varying economic conditions. Consequently, material revisions (upward or downward) to existing 

reserve estimates may occur from time to time. For related discussion, see ITEM 1A. Risk Factors and "Supplemental 

Information to Consolidated Financial Statements."

Oil and Gas Exploration Costs

EOG accounts for its crude oil and natural gas exploration and production activities under the successful 

efforts method of accounting. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are 

charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of 

whether EOG has discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is 

complete if it is determined that there is economic producibility supported by either actual production, a conclusive

formation test or by certain technical data if the discovery is located offshore. If proved commercial reserves are not 

discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved 

commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs 

may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and 

sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. 

As of December 31, 2012 and 2011, EOG had exploratory drilling costs related to projects that have been deferred 

for more than one year (see Note 15 to Consolidated Financial Statements). These costs meet the accounting 

requirements outlined above for continued capitalization. Costs to develop proved reserves, including the costs of 

all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. 

Depreciation, Depletion and Amortization for Oil and Gas Properties

The quantities of estimated proved oil and gas reserves are a significant component of EOG's calculation of 

depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future 

expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase 

or decrease, respectively. 

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the 

unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold 

acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved 

undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful 

exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, 

restoration and abandonment costs, net of salvage values, are taken into account. 
49

Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas 

Topic of the ASC. The basis for grouping is a reasonable aggregation of properties with a common geological structural 

feature or stratigraphic condition, such as a reservoir or field. 

Amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or 

downwards) and additions, property acquisitions and/or property dispositions and impairments. 

Depreciation and amortization of other property, plant and equipment is calculated on a straight-line basis 

over the estimated useful life of the asset.

Impairments

Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with individually 

significant acquisition costs are amortized over the lease term and analyzed on a property-by-property basis for any 

impairment in value. Unproved properties with acquisition costs that are not individually significant are aggregated, 

and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. If the 

unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and 

gas properties. Lease rentals are expensed as incurred.

When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected 

undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the 

future undiscounted cash flows, based on EOG's estimate of future crude oil and natural gas prices, operating costs, 

anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, 

the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described 

in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted bids as the basis for 

determining fair value. Estimates of future undiscounted cash flows require significant judgment. Crude oil and 

natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the 

future. During the past five years, West Texas Intermediate crude oil spot prices have fluctuated from approximately 

$34.00 per barrel to $145.00 per barrel and Henry Hub natural gas spot prices have ranged from approximately 

$1.82 per MMBtu to $13.31 per MMBtu. EOG's proved reserves estimates, including the timing of future 

production, are also subject to significant judgment, and are frequently revised (upwards and downwards) as more 

information becomes available. In the future, if actual crude oil and/or natural gas prices and/or actual production 

diverge negatively from EOG's current estimates, impairment charges may be necessary.

Income Taxes

Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax 

assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between 

financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the 

realizability of deferred tax assets and recognizes valuation allowances as appropriate. Significant assumptions used 

in estimating future taxable income include future oil and gas prices and changes in tax rates. Changes in such 

assumptions could materially affect the recognized amounts of valuation allowances. 

Stock-Based Compensation

In accounting for stock-based compensation, judgments and estimates are made regarding, among other 

things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs 

required by those valuation methodologies. Assumptions regarding expected volatility of EOG's Common Stock, the 

level of risk-free interest rates, expected dividend yields on EOG's Common Stock, the expected term of the awards, 

expected volatility of the price of shares of EOG's peer companies and other valuation inputs are subject to change. 

Any such changes could result in different valuations and thus impact the amount of stock-based compensation 

expense recognized on the Consolidated Statements of Income and Comprehensive Income.
50

Information Regarding Forward-Looking Statements

This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A 

of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 

All statements, other than statements of historical facts, including, among others, statements and projections 

regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, 

levels of production and costs, statements regarding future commodity prices and statements regarding the plans and 

objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words 

such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," 

"should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its 

forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results 

and returns or EOG's ability to replace or increase reserves, increase production, generate income or cash flows or 

pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. 

Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on 

reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these 

expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking 

statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be 

outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the 

expectations reflected in EOG's forward-looking statements include, among others: 

 the timing and extent of changes in prices for, and demand for, crude oil and condensate, NGLs, natural gas 

and related commodities; 

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

 the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing 

horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing;

 the extent to which EOG is successful in its efforts to economically develop its acreage in, and to produce 

reserves and achieve anticipated production levels from, its existing and future crude oil and natural gas 

exploration and development projects, given the risks and uncertainties and capital expenditure 

requirements inherent in drilling, completing and operating crude oil and natural gas wells and the potential 

for interruptions of development and production, whether involuntary or intentional as a result of market or 

other conditions; 

 the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related 

commodity production;

 the availability, proximity and capacity of, and costs associated with, gathering, processing, compression 

and transportation facilities; 

 the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses 

and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral 

licenses and leases;

 the impact of, and changes in, government policies, laws and regulations, including tax laws and 

regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic 

fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on 

drilling and completion operations and laws and regulations with respect to derivatives and hedging 

activities; 

 EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully 

identify existing and potential problems with respect to such properties and accurately estimate reserves, 

production and costs with respect to such properties;

 the extent to which EOG's third-party-operated crude oil and natural gas properties are operated

successfully and economically;

 competition in the oil and gas exploration and production industry for employees and other personnel, 

equipment, materials and services and, related thereto, the availability and cost of employees and other 

personnel, equipment, materials and services;

 the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and 

may therefore be imprecise;

 weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling 

and in the installation and operation of production, gathering, processing, compression and transportation 

facilities;
51

 the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, 

related thereto, to access the credit and capital markets to obtain financing needed to satisfy their 

obligations to EOG;

 EOG's ability to access the commercial paper market and other credit and capital markets to obtain 

financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure 

requirements;

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

 the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and 

domestic financial market conditions and global and domestic general economic conditions;

 political conditions and developments around the world (such as political instability and armed conflict), 

including in the areas in which EOG operates;

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

 the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its 

insurance coverage;

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

 physical, electronic and cyber security breaches; and

 the other factors described under ITEM 1A, Risk Factors, on pages 16 through 23 of this Annual Report on 

Form 10-K and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q 

or Current Reports on Form 8-K. 

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking 

statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence 

or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of 

EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG 

undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking 

statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or 

otherwise. 
52

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

The information required by this Item is incorporated by reference from Item 7 of this report, specifically 

the information set forth under the captions "Derivative Transactions," "Financing," "Foreign Currency Exchange 

Rate Risk" and "Outlook" in "Management's Discussion and Analysis of Financial Condition and Results of 

Operations - Capital Resources and Liquidity." 

ITEM 8. Financial Statements and Supplementary Data

The information required by this Item is included in this report as set forth in the "Index to Financial 

Statements" on page F-1 and is incorporated by reference herein.

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

None.

ITEM 9A. Controls and Procedures

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal 

executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and 

procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as 

amended (Exchange Act)) as of December 31, 2012. EOG's disclosure controls and procedures are designed to 

provide reasonable assurance that information that is required to be disclosed in the reports EOG files or submits 

under the Exchange Act is accumulated and communicated to EOG's management, as appropriate, to allow timely 

decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods 

specified in the rules and forms of the Securities and Exchange Commission. Based on that evaluation, EOG's 

principal executive officer and principal financial officer have concluded that EOG's disclosure controls and 

procedures were effective as of December 31, 2012. 

Management's Annual Report on Internal Control over Financial Reporting. EOG's management is 

responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 

13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Even an effective system of internal control over 

financial reporting, no matter how well designed, has inherent limitations, including the possibility of human error, 

circumvention of controls or overriding of controls and, therefore, can provide only reasonable assurance with 

respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial 

reporting in future periods can change as conditions change.

EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of 

December 31, 2012. In making this assessment, it used the criteria set forth by the Committee of Sponsoring 

Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on this 

assessment and such criteria, EOG's management believes that EOG's internal control over financial reporting was 

effective as of December 31, 2012. See also "Management's Responsibility for Financial Reporting" appearing on 

page F-2 of this report, which is incorporated herein by reference.

The report of EOG's independent registered public accounting firm relating to the consolidated financial 

statements and effectiveness of internal control over financial reporting is set forth beginning on page F-3 of this 

report.

There were no changes in EOG's internal control over financial reporting that occurred during the quarter 

ended December 31, 2012, that have materially affected, or are reasonably likely to materially affect, EOG's internal 

control over financial reporting.
53

ITEM 9B. Other Information

On February 21, 2013, the Compensation Committee of the Board of Directors (Committee) of EOG made 

determinations regarding cash bonuses for 2012 for EOG's "named executive officers" (i.e., the current executive 

officers of EOG for whom disclosure was required in EOG's definitive proxy statement for its 2012 annual meeting 

of stockholders).

The Committee assessed EOG's 2012 performance relative to EOG's operational, financial and strategic 

goals for 2012 as previously established and weighted by the Committee. The 2012 performance goals were 

comprised of goals relating to: (i) EOG's after-tax rate of return with respect to its capital expenditure program

(weighting: 25%); (ii) EOG's results relative to its peer group companies with respect to year-over-year non-GAAP 

earnings per share, EBITDAX per share and cash flow growth (weighting: 15%); (iii) EOG's achievement of 

specified production and unit cost targets (weighting: 10%); (iv) EOG's performance relative to its peer group 

companies with respect to stock price performance and forward-year cash flow multiple (weighting: 10%); and (v) 

EOG's achievement of various strategic goals for 2012, such as the sale of an aggregate $1.1 billion of non-core 

assets and achievement of a year-end net debt-to-total capitalization ratio of less than 30% (weighting: 40%). The 

Committee also assessed each named executive officer's individual performance relative to the accomplishment of 

the weighted 2012 performance goals. 

The result of the Committee's assessment was an above-target "performance factor" for each named 

executive officer, which was applied to the individual bonus targets for each of the named executive officers 

previously established by the Committee. Accordingly, the Committee determined that above-target cash bonuses 

will be paid for 2012 to each of the named executive officers, pursuant to the EOG Resources, Inc. Amended and 

Restated Executive Officer Annual Bonus Plan, on or about March 15, 2013 in connection with the payment of 

annual bonuses to EOG's other employees.

The bonus target for each named executive officer utilized by the Committee in its determination of the 

2012 cash bonuses are as follows: Mark G. Papa - 150% of salary; William R. Thomas and Gary L. Thomas - 100%

of salary; and Timothy K. Driggers - 80% of salary.
54

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance 

The information required by this Item is incorporated by reference from (i) EOG's Definitive Proxy Statement 

with respect to its 2013 Annual Meeting of Stockholders to be filed not later than April 30, 2013 and (ii) Item 1 of this 

report, specifically the information therein set forth under the caption "Executive Officers of the Registrant."

Pursuant to Rule 303A.10 of the New York Stock Exchange and Item 406 of Regulation S-K promulgated 

under the Securities Exchange Act of 1934, as amended, EOG has adopted a Code of Business Conduct and Ethics for 

Directors, Officers and Employees (Code of Conduct) that applies to all EOG directors, officers and employees, 

including EOG's principal executive officer, principal financial officer and principal accounting officer. EOG has also 

adopted a Code of Ethics for Senior Financial Officers (Code of Ethics) that, along with EOG's Code of Conduct, 

applies to EOG's principal executive officer, principal financial officer, principal accounting officer and controllers.

You can access the Code of Conduct and Code of Ethics on the Corporate Governance page under “Investors”

on EOG's website at www.eogresources.com, and any EOG stockholder who so requests may obtain a printed copy of 

the Code of Conduct and Code of Ethics by submitting a written request to EOG's Corporate Secretary.

EOG intends to disclose any amendments to the Code of Conduct or Code of Ethics, and any waivers with 

respect to the Code of Conduct or Code of Ethics granted to EOG's principal executive officer, principal financial 

officer, principal accounting officer, any of our controllers or any of our other employees performing similar functions, 

on its website at www.eogresources.com within four business days of the amendment or waiver. In such case, the 

disclosure regarding the amendment or waiver will remain available on EOG's website for at least 12 months after the 

initial disclosure. There have been no waivers granted with respect to EOG's Code of Conduct or Code of Ethics.

ITEM 11. Executive Compensation

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement

with respect to its 2013 Annual Meeting of Stockholders to be filed not later than April 30, 2013. The Compensation 

Committee Report and related information incorporated by reference herein shall not be deemed "soliciting material" 

or to be "filed" with the United States Securities and Exchange Commission, nor shall such information be 

incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange 

Act of 1934, as amended, except to the extent that EOG specifically incorporates such information by reference into 

such a filing.

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

The information required by this Item with respect to security ownership of certain beneficial owners and 

management is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2013 Annual 

Meeting of Stockholders to be filed not later than April 30, 2013.

Equity Compensation Plan Information

Stock Plans Approved by EOG Stockholders. EOG's stockholders approved the EOG Resources, Inc. 2008 

Omnibus Equity Compensation Plan (2008 Plan) at the 2008 Annual Meeting of Stockholders in May 2008. At the 

2010 Annual Meeting of Stockholders in April 2010 (2010 Annual Meeting), an amendment to the 2008 Plan was 

approved, pursuant to which the number of shares of common stock available for future grants of stock options, 

stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units, performance stock, 

performance units and other stock-based awards under the 2008 Plan was increased by an additional 6.9 million 

shares, to an aggregate maximum of 12.9 million shares plus shares underlying forfeited or cancelled grants under 

the prior stock plans referenced below. Under the 2008 Plan, grants may be made to employees and non-employee 

members of EOG's Board of Directors (Board). 

At the 2010 Annual Meeting, an amendment to the Employee Stock Purchase Plan (ESPP) was approved to 

increase the shares available for grant by 1.0 million shares. The ESPP was originally approved by EOG's 

stockholders in 2001, and would have expired on July 1, 2011. The amendment also extended the term of the ESPP 

to December 31, 2019, unless terminated earlier by its terms or by EOG. 
55

The 1992 Stock Plan and the 1993 Nonemployee Directors Stock Option Plan have also been approved by 

EOG's stockholders. Upon the effective date of the 2008 Plan, no further grants were made under the 1992 Stock 

Plan or the 1993 Non-Employee Directors Stock Option Plan. Plans that have not been approved by EOG's 

stockholders are described below. 

Stock Plans Not Approved by EOG Stockholders. The Board approved the 1994 Stock Plan, which 

provides equity compensation to employees who are not officers within the meaning of Rule 16a-1 of the Securities 

Exchange Act of 1934, as amended. Upon the effective date of the 2008 Plan, no further grants were made under the 

1994 Stock Plan.

In December 2008, the Board approved the amendment and continuation of the 1996 Deferral Plan as the 

"EOG Resources, Inc. 409A Deferred Compensation Plan" (Deferral Plan). Under the Deferral Plan, payment of up 

to 50% of base salary and 100% of annual cash bonus, director's fees, vestings of restricted stock units granted to 

non-employee directors and 401(k) refunds resulting from excess deferrals in the EOG Resources, Inc. Savings and 

Retirement Plan may be deferred into a phantom stock account. In the phantom stock account, deferrals are treated

as if shares of EOG common stock were purchased at the closing stock price on the date of deferral. Dividends are 

credited quarterly and treated as if reinvested in EOG common stock. Payment of the phantom stock account is 

made in actual shares of EOG common stock in accordance with the Deferral Plan and the individual's deferral 

election. A total of 270,000 shares have been authorized by the Board and registered for issuance under the Deferral 

Plan. As of December 31, 2012, 129,939 phantom shares had been issued.

The following table sets forth data for EOG's equity compensation plans aggregated by the various plans 

approved by EOG's stockholders and those plans not approved by EOG's stockholders, in each case as of December 

31, 2012.

(a)

Number of Securities to be

Issued Upon Exercise of

Outstanding Options, 

Warrants and Rights

(b)

Weighted-Average

Exercise Price of

Outstanding Options,

Warrants and Rights

(c)

Number of Securities

Remaining Available

for Future Issuance Under

Equity Compensation 

Plans (Excluding Securities 

Plan Category Reflected in Column (a))

Equity Compensation 

Plans Approved by EOG 

Stockholders 9,962,326 $54.25 3,987,425 (1) (2)

Equity Compensation 

Plans Not Approved by 

EOG Stockholders 239,728 $27.98 140,061 (3) 

Total 10,202,054 $53.63 4,127,486 

(1) Of these securities, 625,062 shares remain available for purchase under the ESPP.

(2) Of these securities, 549,264 could be issued as restricted stock, restricted stock units, performance stock or performance 

units under the 2008 Plan.

(3) Represents shares that remain available for issuance under the Deferral Plan (as described above). 
56

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

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement 

with respect to its 2013 Annual Meeting of Stockholders to be filed not later than April 30, 2013.

ITEM 14. Principal Accounting Fees and Services

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement 

with respect to its 2013 Annual Meeting of Stockholders to be filed not later than April 30, 2013.

PART IV

ITEM 15. Exhibits, Financial Statement Schedules

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

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

(a)(3), (b) Exhibits

See pages E-1 through E-8 for a listing of the exhibits.
F-1

EOG RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS

Page

Consolidated Financial Statements:

Management's Responsibility for Financial Reporting F-2 

Report of Independent Registered Public Accounting Firm F-3 

Consolidated Statements of Income and Comprehensive Income for Each of the Three Years

in the Period Ended December 31, 2012 F-5 

Consolidated Balance Sheets - December 31, 2012 and 2011 F-6 

Consolidated Statements of Stockholders' Equity for Each of the Three Years in the

Period Ended December 31, 2012 F-7 

Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended

December 31, 2012 F-8 

Notes to Consolidated Financial Statements F-9 

Supplemental Information to Consolidated Financial Statements F-32
F-2

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING

The following consolidated financial statements of EOG Resources, Inc., together with its subsidiaries 

(collectively, EOG), were prepared by management, which is responsible for the integrity, objectivity and fair 

presentation of such financial statements. The statements have been prepared in conformity with generally accepted 

accounting principles in the United States of America and, accordingly, include some amounts that are based on the best 

estimates and judgments of management.

EOG's management is also responsible for establishing and maintaining adequate internal control over financial 

reporting. The system of internal control of EOG is designed to provide reasonable assurance regarding the reliability of 

financial reporting and the preparation of financial statements for external purposes in accordance with generally 

accepted accounting principles in the United States of America. This system consists of 1) entity level controls, 

including written policies and guidelines relating to the ethical conduct of business affairs, 2) general computer controls 

and 3) process controls over initiating, authorizing, recording, processing and reporting transactions. Even an effective 

internal control system, no matter how well designed, has inherent limitations, including the possibility of human error, 

circumvention of controls or overriding of controls and, therefore, can provide only reasonable assurance with respect to 

reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial reporting in 

future periods can change as conditions change.

The adequacy of EOG's financial controls and the accounting principles employed by EOG in its financial 

reporting are under the general oversight of the Audit Committee of the Board of Directors. No member of this 

committee is an officer or employee of EOG. Moreover, EOG's independent registered public accounting firm and 

internal auditors have full, free, separate and direct access to the Audit Committee and meet with the committee 

periodically to discuss accounting, auditing and financial reporting matters.

EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of 

December 31, 2012. In making this assessment, EOG used the criteria set forth by the Committee of Sponsoring 

Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. These criteria cover 

the control environment, risk assessment process, control activities, information and communication systems, and

monitoring activities. Based on this assessment and those criteria, management believes that EOG maintained effective 

internal control over financial reporting as of December 31, 2012. 

Deloitte & Touche LLP, independent registered public accounting firm, was engaged to audit the consolidated 

financial statements of EOG, audit EOG's internal control over financial reporting and issue a report thereon. In the 

conduct of the audits, Deloitte & Touche LLP was given unrestricted access to all financial records and related data, 

including all minutes of meetings of stockholders, the Board of Directors and committees of the Board. Management 

believes that all representations made to Deloitte & Touche LLP during the audits were valid and appropriate. Their 

audits were made in accordance with the standards of the Public Company Accounting Oversight Board (United States). 

Their report begins on page F-3. 

MARK G. PAPA TIMOTHY K. DRIGGERS

Chairman of the Board and Vice President and Chief

Chief Executive Officer Financial Officer

Houston, Texas

February 21, 2013
F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

EOG Resources, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. and subsidiaries (the 

"Company") as of December 31, 2012 and 2011, and the related consolidated statements of income and 

comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended 

December 31, 2012. We also have audited the Company's internal control over financial reporting as of December 

31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of 

Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these 

financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the 

effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual 

Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial 

statements and an opinion on the Company's internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board 

(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about 

whether the financial statements are free of material misstatement and whether effective internal control over 

financial reporting was maintained in all material respects. Our audits of the financial statements included examining, 

on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting 

principles used and significant estimates made by management, and evaluating the overall financial statement 

presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal 

control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the 

design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing 

such other procedures as we considered necessary in the circumstances. We believe that our audits provide a 

reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the 

company's principal executive and principal financial officers, or persons performing similar functions, and effected 

by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the 

reliability of financial reporting and the preparation of financial statements for external purposes in accordance with 

generally accepted accounting principles. A company's internal control over financial reporting includes those 

policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly 

reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that 

transactions are recorded as necessary to permit preparation of financial statements in accordance with generally 

accepted accounting principles and that receipts and expenditures of the company are being made only in accordance 

with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding 

prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could 

have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion 

or improper management override of controls, material misstatements due to error or fraud may not be prevented or 

detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over 

financial reporting to future periods are subject to the risk that the controls may become inadequate because of 

changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
F-4

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the 

financial position of EOG Resources, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of 

their operations and their cash flows for each of the three years in the period ended December 31, 2012, in 

conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the 

Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 

2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of 

Sponsoring Organizations of the Treadway Commission.

/S/ DELOITTE & TOUCHE LLP

Houston, Texas

February 21, 2013
F-5

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In Thousands, Except Per Share Data)

Year Ended December 31 2012 2011 2010

Net Operating Revenues

Crude Oil and Condensate $ 5,659,437 $ 3,838,284 $ 1,998,771

Natural Gas Liquids 727,177 779,364 462,345

Natural Gas 1,571,762 2,240,540 2,420,099

Gains on Mark-to-Market Commodity Derivative Contracts 393,744 626,053 61,912

Gathering, Processing and Marketing 3,096,694 2,115,792 909,680

Gains on Asset Dispositions, Net 192,660 492,909 223,538

Other, Net 41,162 33,173 23,551

Total 11,682,636 10,126,115 6,099,896

Operating Expenses

Lease and Well 1,000,052 941,954 698,430

Transportation Costs 601,431 430,322 385,189

Gathering and Processing Costs 97,945 80,727 66,758

Exploration Costs 185,569 171,658 187,381

Dry Hole Costs 14,970 53,230 72,486

Impairments 1,270,735 1,031,037 742,647

Marketing Costs 3,035,494 2,072,137 884,212

Depreciation, Depletion and Amortization 3,169,703 2,516,381 1,941,926

General and Administrative 331,545 304,811 280,474

Taxes Other Than Income 495,395 410,549 317,074

Total 10,202,839 8,012,806 5,576,577

Operating Income 1,479,797 2,113,309 523,319

Other Income, Net 14,495 6,853 14,243

Income Before Interest Expense and Income Taxes 1,494,292 2,120,162 537,562

Interest Expense

Incurred 263,254 268,104 205,886

Capitalized (49,702) (57,741) (76,300)

Net Interest Expense 213,552 210,363 129,586

Income Before Income Taxes 1,280,740 1,909,799 407,976

Income Tax Provision 710,461 818,676 247,322

Net Income $ 570,279 $ 1,091,123 $ 160,654

Net Income Per Share 

Basic $ 2.13 $ 4.15 $ 0.64

Diluted $ 2.11 $ 4.10 $ 0.63

Dividends Declared per Common Share $ 0.68 $ 0.64 $ 0.62

Average Number of Common Shares

Basic 267,577 262,735 250,876

Diluted 270,762 266,268 254,500

Comprehensive Income

Net Income $ 570,279 $ 1,091,123 $ 160,654

Other Comprehensive Income (Loss)

Foreign Currency Translation Adjustments 37,739 (32,597) 96,179

Foreign Currency Swap Transaction 1,589 (1,571) 4,447

Income Tax Related to Foreign Currency Swap Transaction (404) 404 (1,203)

Interest Rate Swap Transaction (134) (5,223) 1,843

Income Tax Related to Interest Rate Swap Transaction 48 1,878 (664)

Other (689) (1,216) (251)

Other Comprehensive Income (Loss) 38,149 (38,325) 100,351

Comprehensive Income $ 608,428 $ 1,052,798 $ 261,005

The accompanying notes are an integral part of these consolidated financial statements.
F-6

EOG RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Data)

At December 31 2012 2011

ASSETS

Current Assets

Cash and Cash Equivalents $ 876,435 $ 615,726

Accounts Receivable, Net 1,656,618 1,451,227

Inventories 683,187 590,594

Assets from Price Risk Management Activities 166,135 450,730

Income Taxes Receivable 29,163 26,609

Other 178,346 119,052

Total 3,589,884 3,253,938

Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method) 38,126,298 33,664,435

Other Property, Plant and Equipment 2,740,619 2,149,989

Total Property, Plant and Equipment 40,866,917 35,814,424

Less: Accumulated Depreciation, Depletion and Amortization (17,529,236) (14,525,600)

Total Property, Plant and Equipment, Net 23,337,681 21,288,824

Other Assets 409,013 296,035

Total Assets $ 27,336,578 $ 24,838,797

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

Accounts Payable $ 2,078,948 $ 2,033,615

Accrued Taxes Payable 162,083 147,105

Dividends Payable 45,802 42,578

Liabilities from Price Risk Management Activities 7,617 -

Deferred Income Taxes 22,838 135,989

Current Portion of Long-Term Debt 406,579 -

Other 200,191 163,032

Total 2,924,058 2,522,319

Long-Term Debt 5,905,602 5,009,166

Other Liabilities 894,758 799,189

Deferred Income Taxes 4,327,396 3,867,219

Commitments and Contingencies (Note 7)

Stockholders' Equity

Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 

271,958,495 Shares and 269,323,084 Shares Issued at December 31, 

2012 and 2011, respectively 202,720 202,693

Additional Paid in Capital 2,500,340 2,272,052

Accumulated Other Comprehensive Income 439,895 401,746

Retained Earnings 10,175,631 9,789,345

Common Stock Held in Treasury, 326,264 Shares and 303,633 Shares at 

December 31, 2012 and 2011, respectively (33,822) (24,932)

Total Stockholders' Equity 13,284,764 12,640,904

Total Liabilities and Stockholders' Equity $ 27,336,578 $ 24,838,797

The accompanying notes are an integral part of these consolidated financial statements.
F-7

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In Thousands, Except Per Share Data)

Accumulated Common

Additional Other Stock Total

Common Paid In Comprehensive Retained Held In Stockholders'

Stock Capital Income (Loss) Earnings Treasury Equity

Balance at December 31, 2009 $202,526 $ 596,702 $339,720 $ 8,866,747 $ (7,653) $ 9,998,042

Net Income - - - 160,654 - 160,654

Common Stock Issued Under Stock Plans 10 34,552 - - - 34,562

Common Stock Dividends Declared, $0.62 Per Share - - - (157,222) - (157,222)

Other Comprehensive Income - - 100,351 - - 100,351

Change in Treasury Stock - Stock Compensation Plans, Net - (7,257) - - (4,039) (11,296)

Excess Tax Expense from Stock-Based Compensation - (837) - - - (837)

Restricted Stock and Restricted Stock Units, Net 6 (505) - - 499 -

Stock-Based Compensation Expenses - 107,314 - - - 107,314

Treasury Stock Issued as Compensation - 23 - - 41 64

Balance at December 31, 2010 202,542 729,992 440,071 8,870,179 (11,152) 10,231,632

Net Income - - - 1,091,123 - 1,091,123

Common Stock Issued Under Stock Plans 10 35,903 - - - 35,913

Common Stock Dividends Declared, $0.64 Per Share - - - (171,957) - (171,957)

Other Comprehensive Income (Loss) - - (38,325) - - (38,325)

Change in Treasury Stock - Stock Compensation Plans, Net - (18,622) - - (5,413) (24,035)

Excess Tax Benefit from Stock-Based Compensation - 25 - - - 25

Restricted Stock and Restricted Stock Units, Net 5 8,410 - - (8,415) -

Stock-Based Compensation Expenses - 128,205 - - - 128,205

Common Stock Sold 136 1,388,129 - - - 1,388,265

Treasury Stock Issued as Compensation - 10 - - 48 58

Balance at December 31, 2011 202,693 2,272,052 401,746 9,789,345 (24,932) 12,640,904

Net Income - - - 570,279 - 570,279

Common Stock Issued Under Stock Plans 21 83,197 - - - 83,218

Common Stock Dividends Declared, $0.68 Per Share - - - (183,993) - (183,993)

Other Comprehensive Income - - 38,149 - - 38,149

Change in Treasury Stock - Stock Compensation Plans, Net - (47,123) - - (11,465) (58,588)

Excess Tax Benefit from Stock-Based Compensation - 67,035 - - - 67,035

Restricted Stock and Restricted Stock Units, Net 6 (2,364) - - 2,358 -

Stock-Based Compensation Expenses - 127,504 - - - 127,504

Treasury Stock Issued as Compensation - 39 - - 217 256

Balance at December 31, 2012 $202,720 $2,500,340 $439,895 $10,175,631 $(33,822) $13,284,764

The accompanying notes are an integral part of these consolidated financial statements.
F-8

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

Year Ended December 31 2012 2011 2010

Cash Flows from Operating Activities

Reconciliation of Net Income to Net Cash Provided by Operating Activities:

Net Income $ 570,279 $ 1,091,123 $ 160,654

Items Not Requiring (Providing) Cash

Depreciation, Depletion and Amortization 3,169,703 2,516,381 1,941,926

Impairments 1,270,735 1,031,037 742,647

Stock-Based Compensation Expenses 127,778 128,345 107,378

Deferred Income Taxes 292,938 499,300 76,245

Gains on Asset Dispositions, Net (192,660) (492,909) (223,538)

Other, Net 672 15,139 (468)

Dry Hole Costs 14,970 53,230 72,486

Mark-to-Market Commodity Derivative Contracts

Total Gains (393,744) (626,053) (61,912)

Realized Gains 711,479 180,701 7,033

Excess Tax Benefits from Stock-Based Compensation (67,035) - -

Other, Net 14,411 26,454 17,273

Changes in Components of Working Capital and Other Assets and 

Liabilities 

Accounts Receivable (178,683) (339,780) (339,126)

Inventories (156,762) (176,623) (171,791)

Accounts Payable (17,150) 351,087 654,688

Accrued Taxes Payable 78,094 92,589 (53,098)

Other Assets (118,520) (23,625) (32,169)

Other Liabilities 36,114 14,986 19,342

Changes in Components of Working Capital Associated with Investing and 

Financing Activities 74,158 237,028 (208,968)

Net Cash Provided by Operating Activities 5,236,777 4,578,410 2,708,602

Investing Cash Flows

Additions to Oil and Gas Properties (6,735,316) (6,294,397) (5,210,612)

Additions to Other Property, Plant and Equipment (619,800) (656,415) (370,770)

Acquisition of Galveston LNG Inc. - - (210,000)

Proceeds from Sales of Assets 1,309,776 1,433,137 672,593

Changes in Components of Working Capital Associated with Investing 

Activities (73,923) (237,267) 208,933

Other, Net - - 7,082

Net Cash Used in Investing Activities (6,119,263) (5,754,942) (4,902,774)

Financing Cash Flows

Common Stock Sold - 1,388,265 -

Long-Term Debt Borrowings 1,234,138 - 2,478,659

Long-Term Debt Repayments - (220,000) (37,000)

Dividends Paid (181,080) (167,169) (153,240)

Excess Tax Benefits from Stock-Based Compensation 67,035 - -

Treasury Stock Purchased (58,592) (23,922) (11,295)

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 82,887 35,913 34,560

Debt Issuance Costs (1,578) (4,787) (8,300)

Repayment of Capital Lease Obligation (2,824) - -

Other, Net (235) 239 35

Net Cash Provided by Financing Activities 1,139,751 1,008,539 2,303,419

Effect of Exchange Rate Changes on Cash 3,444 (5,134) (6,145)

Increase (Decrease) in Cash and Cash Equivalents 260,709 (173,127) 103,102

Cash and Cash Equivalents at Beginning of Year 615,726 788,853 685,751

Cash and Cash Equivalents at End of Year $ 876,435 $ 615,726 $ 788,853

The accompanying notes are an integral part of these consolidated financial statements.
F-9

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Principles of Consolidation. The consolidated financial statements of EOG Resources, Inc. (EOG) include 

the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able 

to exercise significant influence, are accounted for using the equity method. All intercompany accounts and 

transactions have been eliminated. 

The preparation of financial statements in conformity with accounting principles generally accepted in the 

United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the 

reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial 

statements and the reported amounts of revenues and expenses during the reporting period. Actual results could 

differ from those estimates.

Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, commodity 

derivative contracts, accounts receivable, accounts payable and current and long-term debt, along with associated 

foreign currency and interest rate swaps. The carrying values of cash and cash equivalents, commodity derivative 

contracts, accounts receivable, foreign currency and interest rate swaps and accounts payable approximate fair value (see 

Notes 2 and 11).

Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with 

original maturities of three months or less. 

Oil and Gas Operations. EOG accounts for its crude oil and natural gas exploration and production activities 

under the successful efforts method of accounting.

Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with individually 

significant acquisition costs are amortized over the lease term and analyzed on a property-by-property basis for any 

impairment in value. Unproved properties with acquisition costs that are not individually significant are aggregated, 

and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. If the 

unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and 

gas properties. Lease rentals are expensed as incurred.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as 

incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has

discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are 

expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered 

when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve 

quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves 

and the economic and operating viability of the project is being made (see Note 15). Costs to develop proved 

reserves, including the costs of all development wells and related equipment used in the production of crude oil and 

natural gas, are capitalized. 

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the 

unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold 

acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved 

undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful 

exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, 

restoration and abandonment costs, net of salvage values, are taken into account. 
F-10

Oil and gas properties are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the 

Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a 

reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a 

reservoir or field. 

Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions 

(upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments. 

When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected 

undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the 

future undiscounted cash flows, based on EOG's estimate of future crude oil and natural gas prices, operating costs, 

anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, 

the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described 

in the Fair Value Measurement Topic of the ASC. If applicable, EOG utilizes accepted bids as the basis for 

determining fair value.

Inventories, consisting primarily of tubular goods, materials for completion operations and well equipment held 

for use in the exploration for, and development and production of, crude oil and natural gas reserves, are carried at cost 

with adjustments made, as appropriate, to recognize any reductions in value.

Arrangements for sales of crude oil and condensate, natural gas liquids (NGLs) and natural gas are evidenced 

by signed contracts with determinable market prices, and revenues are recorded when production is delivered. A 

significant majority of the purchasers of these products have investment grade credit ratings and material credit losses 

have been rare. Revenues are recorded on the entitlement method based on EOG's percentage ownership of current 

production. Each working interest owner in a well generally has the right to a specific percentage of production, 

although actual production sold on that owner's behalf may differ from that owner's ownership percentage. Under 

entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when 

overproduction occurs. Gathering, processing and marketing revenues represent sales of third-party crude oil and 

condensate, NGLs and natural gas, as well as gathering fees associated with gathering third-party natural gas. 

Other Property, Plant and Equipment. Other property, plant and equipment consists of gathering and 

processing assets, compressors, buildings and leasehold improvements, crude-by-rail assets, sand mine and sand 

processing assets, computer hardware and software, vehicles, and furniture and fixtures. Other property, plant and 

equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property, plant and 

equipment, which range from 3 years to 40 years.

Capitalized Interest Costs. Interest costs have been capitalized as a part of the historical cost of unproved 

oil and gas properties. The amount capitalized is an allocation of the interest cost incurred during the reporting 

period. Capitalized interest is computed only during the exploration and development phases and ceases once 

production begins. The interest rate used for capitalization purposes is based on the interest rates on EOG's 

outstanding borrowings. 

Accounting for Risk Management Activities. Derivative instruments are recorded on the balance sheet as either 

an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings 

unless specific hedge accounting criteria are met. During the three-year period ended December 31, 2012, EOG elected 

not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in 

the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The 

gains or losses are recorded as Gains on Mark-to-Market Commodity Derivative Contracts on the Consolidated 

Statements of Income and Comprehensive Income. The related cash flow impact is reflected as cash flows from 

operating activities. EOG is party to a foreign currency swap transaction and an interest rate swap transaction. EOG 

employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and 

liabilities are with the same counterparty and subject to a master netting arrangement. See Note 11. 
F-11

Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, 

deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to 

differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG 

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

Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's 

consolidated subsidiaries except for certain of its Canadian subsidiaries, for which the functional currency is the 

Canadian dollar, and its United Kingdom subsidiary, for which the functional currency is the British pound. For 

subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts 

are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing 

during the year. Translation adjustments are included in Accumulated Other Comprehensive Income on the 

Consolidated Balance Sheets. Any gains or losses on transactions or monetary assets or liabilities in currencies other 

than the functional currency are included in net income in the current period.

Net Income Per Share. Basic net income per share is computed on the basis of the weighted-average number 

of common shares outstanding during the period. Diluted net income per share is computed based upon the weightedaverage number of common shares outstanding during the period plus the assumed issuance of common shares for all 

potentially dilutive securities (see Note 8).

Stock-Based Compensation. EOG measures the cost of employee services received in exchange for an 

award of equity instruments based on the grant-date fair value of the award (see Note 6).

Recently Issued Accounting Standards. In May 2011, the FASB issued Accounting Standards Update 

(ASU) 2011-04, "Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement 

and Disclosure Requirements in U.S. GAAP and IFRSs". ASU 2011-04 amends the Fair Value Measurement Topic 

of the ASC to clarify the FASB's intent about the application of existing fair value measurement requirements and 

change certain principles or requirements for measuring fair value or disclosing information about fair value 

measurements. ASU 2011-04 became effective for interim and annual fiscal periods beginning after December 15, 

2011. The adoption of ASU 2011-04 did not have a material impact on EOG's financial statements.

In June 2011, the FASB issued ASU 2011-05 "Comprehensive Income (Topic 220): Presentation of 

Comprehensive Income." ASU 2011-05 is intended to increase the prominence of comprehensive income in the 

financial statements by requiring that an entity that reports items of comprehensive income do so in either one 

continuous or two consecutive financial statements. ASU 2011-05 also requires separate presentation on the face of 

the financial statements for items reclassified from other comprehensive income into net income. Subsequently, in 

December 2011, the FASB deferred the effective date of the provisions of ASU 2011-05 relating to the presentation 

of reclassification adjustments out of accumulated other comprehensive income. The provisions of ASU 2011-05 not 

deferred by the FASB became effective for interim and annual fiscal periods beginning after December 15, 2011. 

Retroactive application is required. The adoption of ASU 2011-05 did not have a material impact on EOG's 

financial statements. 

In February 2013, the FASB issued ASU 2013-02 "Reporting of Amounts Reclassified Out of Accumulated 

Other Comprehensive Income" (ASU 2013-02). ASU 2013-02 amends ASU 2011-05 and requires that entities 

disclose additional information about amounts reclassified out of Accumulated Other Comprehensive Income 

(AOCI) by component. Significant amounts reclassified out of AOCI are required to be presented either on the face 

of the Consolidated Statements of Income and Comprehensive Income or in the notes to the financial statements. 

The requirements of ASU 2013-02 are effective for fiscal years and interim periods in those years beginning after 

December 15, 2012. EOG does not expect the adoption of ASU 2013-02 to have a material impact on EOG's 

financial statements.
F-12

2. Long-Term Debt

Long-Term Debt at December 31, 2012 and 2011 consisted of the following (in thousands):

2012 2011

6.125% Senior Notes due 2013 $ 400,000 $ 400,000

Floating Rate Senior Notes due 2014 350,000 350,000

2.95% Senior Notes due 2015 500,000 500,000

2.500% Senior Notes due 2016 400,000 400,000

5.875% Senior Notes due 2017 600,000 600,000

6.875% Senior Notes due 2018 350,000 350,000

5.625% Senior Notes due 2019 900,000 900,000

4.40% Senior Notes due 2020 500,000 500,000

4.100% Senior Notes due 2021 750,000 750,000

2.625% Senior Notes due 2023 1,250,000 -

6.65% Senior Notes due 2028 140,000 140,000

4.75% Subsidiary Debt due 2014 150,000 150,000

Total Long-Term Debt 6,290,000 5,040,000

Capital Lease Obligation 62,968 -

Less: Current Portion of Long-Term Debt 406,579 -

Unamortized Debt Discount 40,787 30,834

Total Long-Term Debt, Net $ 5,905,602 $ 5,009,166

At December 31, 2012, the aggregate annual maturities of long-term debt were $400 million in 2013, $500

million in 2014, $500 million in 2015, $400 million in 2016 and $600 million in 2017. All subsidiary debt is 

guaranteed by EOG.

During 2012 and 2011, EOG utilized commercial paper and short-term borrowings from uncommitted 

credit facilities, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding 

borrowings from commercial paper or uncommitted credit facilities at December 31, 2012. The average borrowings 

outstanding under the commercial paper program and uncommitted credit facilities were $236 million and $41 

thousand, respectively, during the year ended December 31, 2012. The weighted average interest rates for 

commercial paper and uncommitted credit facility borrowings for 2012 was 0.45% and 0.70%, respectively. 

On September 10, 2012, EOG closed its sale of $1.25 billion aggregate principal amount of its 2.625% 

Senior Notes due 2023 (Notes). Interest on the Notes is payable semi-annually in arrears on March 15 and 

September 15 of each year, beginning March 15, 2013. Net proceeds from the Notes offering of approximately 

$1,234 million were used for general corporate purposes, including repayment of outstanding commercial paper 

borrowings and funding of capital expenditures. The Notes were issued through a public offering with an effective 

interest rate of 2.784%. 
F-13

On October 11, 2011, EOG entered into a $2.0 billion senior unsecured Revolving Credit Agreement (2011 

Facility) among EOG, JPMorgan Chase Bank, N.A., as Administrative Agent, the financial institutions as bank 

parties thereto (Banks) and the other parties thereto. The 2011 Facility replaced EOG's $1.0 billion senior unsecured 

Revolving Credit Agreement, dated as of June 28, 2005, which had a scheduled maturity date of June 28, 2012, and

EOG's $1.0 billion senior unsecured Revolving Credit Agreement, dated as of September 10, 2010, which had a 

scheduled maturity date of September 10, 2013. The 2011 Facility has a scheduled maturity date of October 11, 

2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, 

subject to, among certain other terms and conditions, the consent of the banks holding greater than 50% of the 

commitments then outstanding under the 2011 Facility. The 2011 Facility commits the Banks to provide advances 

up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request 

increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and 

conditions. Advances under the 2011 Facility accrue interest based, at EOG's option, on either the London 

InterBank Offered Rate (LIBOR) plus an applicable margin (Eurodollar rate), or the base rate (as defined in the 2011

Facility) plus an applicable margin. At December 31, 2012, there were no borrowings or letters of credit outstanding 

under the 2011 Facility. The Eurodollar rate and applicable base rate, had there been any amounts borrowed under 

the 2011 Facility, would have been 1.08% and 3.25%, respectively. 

The 2011 Facility contains representations, warranties, covenants and events of default that are customary 

for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the 

maintenance of a total debt-to-total capitalization ratio of no greater than 65%. At December 31, 2012, and during 

the year then ended, EOG believes that it was in compliance with this financial debt covenant.

EOG Resources Canada Inc., a wholly-owned subsidiary of EOG, has outstanding notes with an aggregate 

principal amount of $150 million, an interest rate of 4.75% and a maturity date of March 15, 2014. In conjunction 

with the offering, EOG entered into a foreign currency swap transaction with multiple banks for the equivalent 

amount of the notes and related interest, which has in effect converted this indebtedness into $201.3 million 

Canadian dollars with a 5.275% interest rate. EOG accounts for the foreign currency swap transaction using the 

hedge accounting method (see Note 11). 

Capital Lease. During the third quarter of 2012, EOG began leasing certain newly constructed crude oil 

storage tanks located in the Eagle Ford Shale. The lease has an initial term of 10 years and EOG has an option to 

extend the lease for an additional 5-year period. EOG determined that the lease qualified as a capital lease for 

accounting purposes. At December 31, 2012, the capital lease asset is included in Other Property, Plant and 

Equipment and the related liabilities are included in Long-Term Debt ($56 million) and Current Portion of LongTerm Debt ($7 million) on the Consolidated Balance Sheets. Total aggregate minimum lease payments are 

approximately $72 million at December 31, 2012.

3. Stockholders' Equity

Common Stock. On March 7, 2011, EOG completed the public offering and sale of 13,570,000 shares of 

EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share. 

Net proceeds from the sale of the Common Stock were approximately $1,388 million after deducting the 

underwriting discount and offering expenses. Proceeds from the sale were used for general corporate purposes, 

including funding capital expenditures. 
F-14

In September 2001, EOG's Board of Directors (Board) authorized the purchase of an aggregate maximum 

of 10 million shares of Common Stock that superseded all previous authorizations. At December 31, 2012, 

6,386,200 shares remained available for purchase under this authorization. EOG last purchased shares of its 

Common Stock under this authorization in March 2003. In addition, shares of Common Stock are from time to time 

withheld by, or returned to, EOG in satisfaction of tax withholding obligations arising upon the exercise of employee 

stock options or stock-settled stock appreciation rights, the vesting of restricted stock or restricted stock unit grants 

or in payment of the exercise price of employee stock options. Such shares withheld or returned do not count against 

the Board authorization discussed above. Shares purchased, withheld and returned are held in treasury for, among 

other purposes, fulfilling any obligations arising under EOG's stock plans and any other approved transactions or 

activities for which such shares of Common Stock may be required. 

The Board increased the quarterly cash dividend on the Common Stock to $0.16 per share on February 17, 

2011, $0.17 per share on February 16, 2012 and $0.1875 on February 13, 2013. 

The following summarizes Common Stock activity for each of the years ended December 31, 2010, 2011

and 2012 (in thousands):

Common Shares

Issued Treasury Outstanding

Balance at December 31, 2009 252,627 (118) 252,509

Common Stock Issued Under Equity Compensation Plans 1,482 - 1,482

Treasury Stock Purchased (1)- (115) (115)

Common Stock Issued Under Employee Stock Purchase Plan 114 - 114

Treasury Stock Issued Under Other Equity Compensation Plans - 87 87

Balance at December 31, 2010 254,223 (146) 254,077

Common Stock Issued Under Equity Compensation Plans 1,395 - 1,395

Treasury Stock Purchased (1)- (267) (267)

Common Stock Issued Under Employee Stock Purchase Plan 135 - 135

Treasury Stock Issued Under Other Equity Compensation Plans - 109 109

Common Stock Sold 13,570 - 13,570

Balance at December 31, 2011 269,323 (304) 269,019

Common Stock Issued Under Equity Compensation Plans 2,471 - 2,471

Treasury Stock Purchased (1)- (575) (575)

Common Stock Issued Under Employee Stock Purchase Plan 164 - 164

Treasury Stock Issued Under Other Equity Compensation Plans - 553 553

Balance at December 31, 2012 271,958 (326) 271,632

(1) Represents shares that were withheld by, or returned to, EOG in satisfaction of tax withholding obligations that arose upon the 

exercise of employee stock options or stock-settled stock appreciation rights, the vesting of restricted stock or restricted stock 

unit grants or in payment of the exercise price of employee stock options. 

Preferred Stock. EOG currently has one authorized series of preferred stock. In February 2000, EOG's 

Board, in connection with a rights agreement, authorized 1,500,000 shares of the Series E Junior Participating 

Preferred Stock (Series E preferred stock). In February 2005, EOG's Board increased the authorized shares of the 

Series E preferred stock to 3,000,000 in connection with the two-for-one stock split of the Common Stock effected in 

March 2005. The rights agreement and the related preferred share purchase rights expired on February 24, 2010. As 

of December 31, 2012, there were no shares of the Series E preferred stock outstanding. 
F-15

4. Other Income, Net

Other income, net for 2012 included equity income from investments in ammonia plants in Trinidad ($20 

million), interest income ($9 million) primarily related to severance tax refunds, net foreign currency transaction 

gains ($7 million), losses on sales of warehouse stock ($10 million) and operating losses on EOG's investment in 

Pacific Trail Pipelines (PTP) in Canada ($9 million). Other income, net for 2011 included equity income from 

investments in ammonia plants in Trinidad ($17 million), operating losses on EOG's investment in PTP in Canada 

($5 million) and losses on sales of warehouse stock ($5 million). 

5. Income Taxes 

The principal components of EOG's net deferred income tax liabilities at December 31, 2012 and 2011 were as 

follows (in thousands):

2012 2011

Noncurrent Deferred Income Tax Assets (Liabilities)

Foreign Oil and Gas Exploration and Development Costs Deducted for 

Tax Over Book Depreciation, Depletion and Amortization $ 25,592 $ (57,850)

Foreign Net Operating Loss 164,829 62,477

Foreign Other 1,607 314

Foreign Valuation Allowances (134,792) -

Total Net Noncurrent Deferred Income Tax Assets $ 57,236 $ 4,941

Current Deferred Income Tax (Assets) Liabilities

Commodity Hedging Contracts $ 57,754 $ 158,302

Deferred Compensation Plans (35,715) (28,346)

Timing Differences Associated with Different Year-ends in Foreign 

Jurisdictions 2,762 6,251

Other (1,963) (218)

Total Net Current Deferred Income Tax Liabilities $ 22,838 $ 135,989

Noncurrent Deferred Income Tax (Assets) Liabilities

Oil and Gas Exploration and Development Costs Deducted for Tax 

Over Book Depreciation, Depletion and Amortization $ 5,300,115 $ 5,485,436

Non-Producing Leasehold Costs (61,512) (66,926)

Seismic Costs Capitalized for Tax (125,026) (111,862)

Equity Awards (116,666) (120,852)

Capitalized Interest 102,677 106,265

Net Operating Loss (308,154) (1,152,386)

Alternative Minimum Tax Credit Carryforward (476,505) (298,350)

Other 12,467 25,894

Total Net Noncurrent Deferred Income Tax Liabilities $ 4,327,396 $ 3,867,219

Total Net Deferred Income Tax Liabilities $ 4,292,998 $ 3,998,267
F-16

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

2012 2011 2010

United States $ 1,988,105 $ 2,156,147 $ 646,495

Foreign (707,365) (246,348) (238,519)

Total $ 1,280,740 $ 1,909,799 $ 407,976

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

thousands):

2012 2011 2010

Current:

Federal $ 242,674 $ 94,244 $ 17,154

State 22,573 1,083 (1,642)

Foreign 152,276 224,049 155,565

Total 417,523 319,376 171,077

Deferred:

Federal 454,173 608,181 190,602

State 632 40,321 60,619

Foreign (161,867) (149,202) (174,976)

Total 292,938 499,300 76,245

Income Tax Provision $ 710,461 $ 818,676 $ 247,322

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

rate were as follows:

2012 2011 2010

Statutory Federal Income Tax Rate 35.00% 35.00% 35.00%

State Income Tax, Net of Federal Benefit 1.18 1.41 9.39 

Income Tax Provision Related to Foreign Operations 1.38 0.88 (0.03) 

Income Tax Provision Related to Trinidad Operations (0.27) 3.37 6.26 

Canadian Valuation Allowances 10.57 - - 

Canadian Natural Gas Impairments 6.90 1.85 9.49 

Other 0.71 0.36 0.51 

Effective Income Tax Rate 55.47% 42.87% 60.62%

The difference in the effective tax rate and the United States federal statutory rate of 35% is attributed 

principally to state and foreign income taxes. The impact of foreign taxes on EOG's worldwide tax rate was mostly 

due to Canadian impairments, which are tax-effected at a statutory rate of 26%, and Canadian valuation allowances. 

Deferred tax assets are recorded for certain tax benefits, including tax net operating losses (NOLs) and tax 

credit carryforwards, provided that management assesses the utilization of such assets to be "more likely than not." 

Management assesses the available positive and negative evidence to estimate if sufficient future taxable income will 

be generated to use the existing deferred tax assets. On the basis of this evaluation, as of December 31, 2012, 

valuation allowances of $135 million have been recorded as EOG no longer believes that certain Canadian deferred 

tax assets are more likely than not to be realized.
F-17

The balance of unrecognized tax benefits at December 31, 2012, was $33 million, all of which, if 

recognized, would affect the effective tax rate. EOG records interest and penalties related to unrecognized tax 

benefits to its income tax provision. Currently, there are no amounts of interest or penalties recognized in the 

Consolidated Statements of Income and Comprehensive Income or in the Consolidated Balance Sheets. EOG does 

not anticipate that the amount of the unrecognized tax benefits will significantly change during the next twelve 

months. EOG and its subsidiaries file income tax returns in the United States and various state, local and foreign 

jurisdictions. EOG is generally no longer subject to income tax examinations by tax authorities in the United States 

(federal), Canada, the United Kingdom, Trinidad and China for taxable years before 2009, 2008, 2011, 2005 and 

2008, respectively.

EOG's foreign subsidiaries' undistributed earnings of approximately $2.5 billion at December 31, 2012, are 

considered to be indefinitely invested outside the United States and, accordingly, no United States federal or state 

income taxes have been provided thereon. Upon distribution of those earnings, EOG may be subject to both foreign 

withholding taxes and United States income taxes, net of allowable foreign tax credits. The amount of such 

additional taxes would be dependent on several factors, including the size and timing of the distribution, the 

particular foreign jurisdiction from which the distribution is made, and the availability of foreign tax credits. As a 

result, the determination of the potential amount of unrecognized withholding and deferred income taxes is not 

practicable, although additional taxes resulting from a repatriation of foreign earnings could be significant.

In 2012, EOG utilized a regular tax net operating loss (NOL) of $939 million. Remaining NOLs of $932 

million ($444 million and $488 million from 2011 and 2010, respectively) are expected to be carried forward and 

applied against regular taxable income in future periods. To the extent not utilized, these NOL carryforwards will 

expire in 2030 and 2031, respectively. Additionally, as of December 31, 2012, EOG had state income tax NOLs of 

approximately $800 million, which, if unused, expire between 2015 and 2032. The Stock Compensation Topic of 

the ASC provides that when settlement of a stock award contributes to a NOL carryforward, neither the associated 

excess tax benefit nor the credit to additional paid in capital (APIC) should be recorded until the stock award 

deduction reduces income taxes payable. Due to the current year utilization of a portion of the available NOLs, a 

benefit of $11 million will be reflected in APIC. Future utilization of the remaining NOLs will result in an additional 

benefit of $29 million being reflected in APIC (including $23 million and $6 million related to 2011 and 2010, 

respectively). In 2012, EOG paid alternative minimum tax (AMT) of $187 million. The AMT paid in 2012, along 

with AMT of $289 million paid in prior years, will be carried forward indefinitely as a credit available to offset 

regular income taxes in future periods.

The ability of EOG to utilize both the regular tax NOL carryforwards and the AMT credit carryforwards to 

reduce federal income taxes may become subject to various limitations under the Internal Revenue Code. Such 

limitations may arise if certain ownership changes (as defined for income tax purposes) were to occur. As of 

December 31, 2012, management does not believe that an ownership change has occurred which would limit either 

carryforward.

During 2012, EOG's United Kingdom subsidiary incurred a tax NOL of approximately $159 million which, 

along with prior years' NOLs of $104 million, will be carried forward indefinitely. In July 2012, the United 

Kingdom enacted the Finance Act of 2012, which introduced certain tax law changes beneficial to EOG, related to 

the Small Field Allowance and decommissioning costs. These two changes did not have a material impact on EOG's 

2012 earnings or cash flow.

The American Taxpayer Relief Act of 2012 (ATRA) was enacted on January 2, 2013. Although ATRA 

principally affected individual taxpayers, the legislation included certain corporate tax incentives, notably the extension 

of bonus depreciation (additional depreciation expense of 50% for qualified domestic property additions), which is 

expected to have a favorable impact on EOG's tax position in 2013.

6. Employee Benefit Plans 

Stock-Based Compensation

During 2012, EOG maintained various stock-based compensation plans as discussed below. EOG 

recognizes compensation expense on grants of stock options, stock-settled stock appreciation rights (SARs), 

restricted stock and restricted stock units, performance stock and performance units, and grants made under its 

Employee Stock Purchase Plan (ESPP). Stock-based compensation expense is calculated based upon the grant date 

estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate. 

Compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the 

date the employee becomes eligible to retire without company approval. 
F-18

Stock-based compensation expense is included on the Consolidated Statements of Income and 

Comprehensive Income based upon job functions of the employees receiving the grants. Compensation expense 

related to EOG's stock-based compensation plans for the years ended December 31, 2012, 2011 and 2010 was as 

follows (in millions): 

2012 2011 2010

Lease and Well $ 35 $ 33 $ 27

Gathering and Processing Costs 1 1 1

Exploration Costs 27 26 24

General and Administrative 65 68 55

 Total $ 128 $ 128 $ 107

The EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of 

stock options, SARs, restricted stock and restricted stock units, performance stock and performance units, and other 

stock-based awards up to an aggregate maximum of 12.9 million shares plus shares of Common Stock underlying 

forfeited or cancelled grants under prior stock plans. At December 31, 2012, approximately 3.4 million shares of 

Common Stock remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 

Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

During 2012, 2011 and 2010, EOG issued shares in connection with stock option/SAR exercises, restricted 

stock grants, restricted stock unit releases and ESPP purchases. EOG recognized, as an adjustment to APIC, federal 

income tax (expense)/benefits of $67 million, $25,000 and $(1) million for 2012, 2011 and 2010, respectively, 

related to the exercise of stock options/SARs and the release of restricted stock and restricted stock units.

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan. 

Participants in EOG's stock plans (including the 2008 Plan) have been or may be granted options to purchase shares 

of Common Stock. In addition, participants in EOG's stock plans (including the 2008 Plan) have been or may be 

granted SARs, representing the right to receive shares of Common Stock based on the appreciation in the stock price 

from the date of grant on the number of SARs granted. Stock options and SARs are granted at a price not less than 

the market price of the Common Stock on the date of grant. Stock options and SARs granted vest on a graded 

vesting schedule up to four years from the date of grant based on the nature of the grants and as defined in individual 

grant agreements. Terms for stock options and SARs granted have not exceeded a maximum term of 10 years. 

EOG's ESPP allows eligible employees to semi-annually purchase, through payroll deductions, shares of Common 

Stock at 85 percent of the fair market value at specified dates. Contributions to the ESPP are limited to 10 percent of 

the employee's pay (subject to certain ESPP limits) during each of the two six-month offering periods each year. 

The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option 

pricing model. The fair value of all ESPP grants is estimated using the Black-Scholes-Merton model. Stock-based 

compensation expense related to stock option, SAR and ESPP grants totaled $49 million, $48 million and $41

million for the years ended December 31, 2012, 2011 and 2010, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants 

for the years ended December 31, 2012, 2011 and 2010 were as follows:

Stock Options/SARs ESPP

2012 2011 2010 2012 2011 2010

Weighted Average Fair Value 

of Grants $37.95 $29.92 $32.12 $25.11 $22.75 $25.45

Expected Volatility 39.68% 40.96% 39.70% 40.92% 29.82% 38.30%

Risk-Free Interest Rate 0.45% 0.58% 0.87% 0.11% 0.14% 0.18%

Dividend Yield 0.60% 0.70% 0.70% 0.60% 0.70% 0.70%

Expected Life 5.6 yrs 5.6 yrs 5.5 yrs 0.5 yrs 0.5 yrs 0.5 yrs
F-19

Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded 

options in EOG's Common Stock. The risk-free interest rate is based upon United States Treasury yields in effect at 

the time of grant. The expected life is based upon historical experience and contractual terms of stock option, SAR 

and ESPP grants.

The following table sets forth the stock option and SAR transactions for the years ended December 31, 2012, 

2011 and 2010 (stock options and SARs in thousands):

2012 2011 2010

Number Weighted Number Weighted Number Weighted

of Stock Average of Stock Average Of Stock Average

Options/ Grant Options/ Grant Options/ Grant

SARs Price SARs Price SARs Price

Outstanding at January 1 8,374 $ 70.01 8,445 $64.49 8,335 $57.08

Granted 1,240 111.97 1,509 85.29 1,450 93.07

Exercised (1) (3,246) 54.80 (1,399) 50.86 (1,144) 43.38

Forfeited (149) 91.18 (181) 87.74 (196) 84.22

Outstanding at December 31 6,219 85.81 8,374 70.01 8,445 64.49

Stock Options/SARs Exercisable at 

December 31 3,143 74.98 5,148 59.19 5,439 51.71

(1) The total intrinsic value of stock options/SARs exercised during the years 2012, 2011 and 2010 was $185 million, $78

million and $66 million, respectively. The intrinsic value is based upon the difference between the market price of the 

Common Stock on the date of exercise and the grant price of the stock options/SARs.

At December 31, 2012, there were 5,982,406 stock options/SARs vested or expected to vest with a 

weighted average grant price of $85.36 per share, an intrinsic value of $212 million and a weighted average 

remaining contractual life of 4.1 years.

The following table summarizes certain information for the stock options and SARs outstanding at 

December 31, 2012 (stock options and SARs in thousands):

Stock Options/SARs Outstanding Stock Options/SARs Exercisable

Weighted Weighted

Average Weighted Average Weighted

Range of Stock Remaining Average Aggregate Stock Remaining Average Aggregate

Grant Options/ Life Grant Intrinsic Options/ Life Grant Intrinsic

Prices SARs (Years) Price Value(1) SARs (Years) Price Value(1)

$ 18.00 to $ 69.99 846 1 $ 45.84 838 1 $45.62

70.00 to 81.99 1,168 3 78.44 932 3 77.64

82.00 to 88.99 1,767 5 85.14 790 4 87.14

89.00 to 109.99 1,157 4 93.37 508 4 92.76

110.00 to 136.99 1,281 6 113.03 75 4 121.24

6,219 4 85.81 $217,879 3,143 3 74.98 $144,335

(1) Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the 

grant price of in-the-money stock options and SARs.

At December 31, 2012, unrecognized compensation expense related to non-vested stock option and SAR 

grants totaled $91 million. This unrecognized expense will be amortized on a straight-line basis over a weighted 

average period of 2.8 years.
F-20

At December 31, 2012, approximately 625,000 shares of Common Stock remained available for issuance 

under the ESPP. The following table summarizes ESPP activities for the years ended December 31, 2012, 2011 and 

2010 (in thousands, except number of participants):

2012 2011 2010

Approximate Number of Participants 1,705 1,525 1,236

Shares Purchased 164 135 114

Aggregate Purchase Price $ 12,522 $ 10,947 $ 9,172

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock 

and/or restricted stock units without cost to them. The restricted stock and restricted stock units generally vest five 

years after the date of grant, except for certain bonus grants, and as defined in individual grant agreements. Upon 

vesting of restricted stock, shares of Common Stock are released to the employee. Upon vesting, restricted stock 

units are converted into shares of Common Stock and released to the employee. Stock-based compensation expense 

related to restricted stock and restricted stock units totaled $72 million, $80 million and $66 million for the years 

ended December 31, 2012, 2011 and 2010, respectively. 

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended 

December 31, 2012, 2011 and 2010 (shares and units in thousands):

2012 2011 2010

Weighted Weighted Weighted

Number of Average Number of Average Number of Average

Shares and Grant Date Shares and Grant Date Shares and Grant Date

Units Fair Value Units Fair Value Units Fair Value

Outstanding at January 1 4,240 $82.93 4,009 $79.13 3,636 $73.69

Granted 767 112.17 932 90.87 850 93.39

Released (1) (1,059) 72.70 (457) 66.10 (364) 58.00

Forfeited (130) 85.36 (244) 82.45 (113) 79.37

Outstanding at December 31 (2) 3,818 91.06 4,240 82.93 4,009 79.13

(1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2012, 

2011 and 2010 was $120 million, $44 million and $35 million, respectively. The intrinsic value is based upon the closing 

price of EOG's common stock on the date restricted stock and restricted stock units are released. 

(2) The aggregate intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2012 and 2011 was 

approximately $461 million and $418 million, respectively.

At December 31, 2012, unrecognized compensation expense related to restricted stock and restricted stock 

units totaled $136 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted 

average period of 2.5 years.

Performance Units and Performance Stock. In September 2012, as a new element of the long-term 

incentive component of EOG's executive officer compensation program, EOG granted an aggregate of 54,526 

performance units and 16,752 shares of performance stock to its executive officers (in each case under the terms of 

the 2008 Plan), which units and shares remained outstanding at December 31, 2012. As more fully discussed in the 

grant agreements, the performance metric applicable to these performance-based grants is EOG's total shareholder 

return over a three-year performance period relative to the total shareholder return of a designated group of peer 

companies. Upon the application of the performance multiple at the completion of the performance period, a 

minimum of zero and a maximum of 142,556 performance units/shares could be outstanding. Subject to the 

termination provisions set forth in the grant agreements and the applicable performance multiple, the grants of 

performance units/shares will "cliff" vest five years from the date of grant. 

The fair value of the performance units and performance stock is estimated using a Monte Carlo simulation. 

Stock-based compensation expense related to performance unit and performance stock grants totaled $7 million for 

the year ended December 31, 2012. Weighted average fair values and valuation assumptions used to value 

performance unit and performance stock grants as of December 31, 2012 were: Weighted Average Fair Value of 

Grants, $134.09; Expected Volatility, 36.39%; Risk-Free Interest Rate, 0.39%; and Dividend Yield, 0.60%.
F-21

Expected volatility is based on the term-matched historical volatility over the simulated term, which is 

calculated as the time between the grant date and the end of the performance period. The risk-free interest rate is 

based on a 3.26 year zero-coupon risk-free interest rate derived from the Treasury Constant Maturities yield curve on 

the grant date.

At December 31, 2012, unrecognized compensation expense related to performance units and performance

stock totaled $3 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted 

average period of 3.0 years.

Pension Plans. EOG has a defined contribution pension plan in place for most of its employees in the 

United States. EOG's contributions to the pension plan are based on various percentages of compensation and, in 

some instances, are based upon the amount of the employees' contributions. EOG's total costs recognized for the 

plan were $36 million, $27 million and $23 million for 2012, 2011 and 2010, respectively. 

In addition, EOG's Canadian subsidiary maintains both a non-contributory defined benefit pension plan and 

a non-contributory defined contribution pension plan, as well as a matched defined contribution savings plan. EOG's 

Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan. EOG's 

United Kingdom subsidiary maintains a pension plan which includes a non-contributory defined contribution pension 

plan and a matched defined contribution savings plan. With the exception of Canada's non-contributory defined 

benefit pension plan, which is closed to new employees, these pension plans are available to most employees of the 

Canadian, Trinidadian and United Kingdom subsidiaries. EOG's combined contributions to these plans were $3 

million for each of the years 2012, 2011 and 2010. 

For the Canadian and Trinidadian defined benefit pension plans, the benefit obligation, fair value of plan 

assets and prepaid/(accrued) benefit cost totaled $14 million, $10 million and $(2) million, respectively, at December 

31, 2012, and $11 million, $8 million and $(2) million, respectively, at December 31, 2011. 

Postretirement Health Care. EOG has postretirement medical and dental benefits in place for eligible United 

States and Trinidad employees and their eligible dependents, the costs of which are not material. 

7. Commitments and Contingencies

Letters of Credit. At December 31, 2012, EOG had standby letters of credit and guarantees outstanding 

totaling approximately $636 million, of which $150 million represented guarantees of subsidiary indebtedness (see 

Note 2) and $486 million primarily represented guarantees of payment or performance obligations on behalf of 

subsidiaries. At December 31, 2011, EOG had standby letters of credit and guarantees outstanding totaling 

approximately $585 million, of which $150 million represented guarantees of subsidiary indebtedness (see Note 2) 

and $435 million primarily represented guarantees of payment obligations on behalf of subsidiaries. As of February 

21, 2013, there were no demands for payment under these guarantees.

Minimum Commitments. At December 31, 2012, total minimum commitments from long-term noncancelable operating leases, drilling rig commitments, seismic purchase obligations, fracturing services obligations,

other purchase obligations and transportation and storage service commitments, based on current transportation and 

storage rates and the foreign currency exchange rates used to convert Canadian dollars and British pounds into 

United States dollars at December 31, 2012, were as follows (in thousands):

Total Minimum

Commitments

2013 $ 2,214,134

2014 - 2015 1,521,903

2016 - 2017 1,205,897

2018 and beyond 1,369,924

$ 6,311,858
F-22

Included in the table above are leases for buildings, facilities and equipment with varying expiration dates 

through 2042. Rental expenses associated with existing leases amounted to $182 million, $149 million and $95

million for 2012, 2011 and 2010, respectively.

Contingencies. There are currently various suits and claims pending against EOG that have arisen in the 

ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title 

disputes. While the ultimate outcome and impact on EOG cannot be predicted, management believes that the 

resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's 

consolidated financial position, results of operations or cash flow. EOG records reserves for contingencies when 

information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

8. Net Income Per Share 

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 

2012, 2011 and 2010 (in thousands, except per share data):

2012 2011 2010

Numerator for Basic and Diluted Earnings per Share -

Net Income $ 570,279 $ 1,091,123 $ 160,654

Denominator for Basic Earnings per Share -

Weighted Average Shares 267,577 262,735 250,876

Potential Dilutive Common Shares -

Stock Options/SARs 1,456 1,707 1,991

Restricted Stock/Units and Performance Units/Stock 1,729 1,826 1,633

Denominator for Diluted Earnings per Share -

Adjusted Diluted Weighted Average Shares 270,762 266,268 254,500

Net Income Per Share 

Basic $ 2.13 $ 4.15 $ 0.64

Diluted $ 2.11 $ 4.10 $ 0.63

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. Shares 

underlying the excluded stock options and SARs totaled 0.5 million, 0.4 million and 0.3 million for the years ended 

December 31, 2012, 2011 and 2010, respectively.

9. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the years ended December 31, 2012, 2011 and 

2010 (in thousands):

2012 2011 2010

Interest, Net of Capitalized Interest $ 196,944 $ 186,718 $ 146,731

Income Taxes, Net of Refunds Received $ 360,006 $ 260,224 $ 233,462

EOG's accrued capital expenditures at December 31, 2012, 2011 and 2010 were $734 million, $663 million 

and $709 million, respectively.

Non-cash investing and financing activities for the year ended December 31, 2012, included non-cash additions 

of $66 million to EOG's other property, plant and equipment and related obligations in connection with a capital lease 

transaction and non-cash additions of $20 million to EOG's oil and gas properties as a result of property exchanges.
F-23

10. Business Segment Information 

EOG's operations are all crude oil and natural gas exploration and production related. The Segment 

Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual 

financial statements. Operating segments are defined as components of an enterprise about which separate financial 

information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in 

deciding how to allocate resources and in assessing performance. EOG's chief operating decision making process is 

informal and involves the Chairman of the Board and Chief Executive Officer and other key officers. This group 

routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major 

producing areas in the United States, Canada, Trinidad, the United Kingdom, China and Argentina. For segment 

reporting purposes, the chief operating decision maker considers the major United States producing areas to be one 

operating segment. 

Financial information by reportable segment is presented below as of and for the years ended December 31, 

2012, 2011 and 2010 (in thousands):

United Other

States Canada Trinidad International (1) Total

2012

Crude Oil and Condensate $ 5,383,612 $ 221,556 $ 50,708 $ 3,561 $ 5,659,437

Natural Gas Liquids 713,497 13,680 - - 727,177

Natural Gas 951,463 86,361 514,322 19,616 1,571,762

Gains on Mark-to-Market Commodity 

Derivative Contracts 393,744 - - - 393,744

Gathering, Processing and Marketing 3,091,281 - 5,413 - 3,096,694

Gains on Asset Dispositions, Net 166,201 26,459 - - 192,660

Other, Net 40,780 367 15 - 41,162

Net Operating Revenues (2) 10,740,578 348,423 570,458 23,177 11,682,636

Depreciation, Depletion and Amortization 2,780,563 223,689 147,062 18,389 3,169,703

Operating Income (Loss) 2,233,911 (1,065,434) 371,876 (60,556) 1,479,797

Interest Income 8,343 123 125 180 8,771

Other Income (Expense) (12,455) (8,689) 20,482 6,386 5,724

Net Interest Expense 242,138 6,589 238 (35,413) 213,552

Income (Loss) Before Income Taxes 1,987,661 (1,080,589) 392,245 (18,577) 1,280,740

Income Tax Provision (Benefit) 707,401 (134,745) 140,468 (2,663) 710,461

Additions to Oil and Gas Properties, 

Excluding Dry Hole Costs 6,198,267 302,851 49,376 169,852 6,720,346

Total Property, Plant and Equipment, Net 21,560,998 877,996 535,405 363,282 23,337,681

Total Assets 24,523,072 1,202,031 1,012,727 598,748 27,336,578
F-24

United Other

States Canada Trinidad International (1) Total

2011

Crude Oil and Condensate $ 3,458,248 $ 264,895 $ 112,554 $ 2,587 $ 3,838,284

Natural Gas Liquids 762,730 16,634 - - 779,364

Natural Gas 1,593,964 178,324 442,589 25,663 2,240,540

Gains on Mark-to-Market Commodity 

Derivative Contracts 626,053 - - - 626,053

Gathering, Processing and Marketing 2,115,768 - 24 - 2,115,792

Gains on Asset Dispositions, Net 475,878 17,033 (2) - 492,909

Other, Net 32,329 258 586 - 33,173

Net Operating Revenues (3)9,064,970 477,144 555,751 28,250 10,126,115

Depreciation, Depletion and Amortization 2,131,706 260,084 107,141 17,450 2,516,381

Operating Income (Loss) 2,252,508 (459,520) 383,992 (63,671) 2,113,309

Interest Income 436 342 101 140 1,019

Other Income (Expense) (6,480) (2,375) 18,755 (4,066) 5,834

Net Interest Expense 214,360 23,085 - (27,082) 210,363

Income (Loss) Before Income Taxes 2,032,104 (484,638) 402,848 (40,515) 1,909,799

Income Tax Provision (Benefit) 732,362 (125,474) 204,698 7,090 818,676

Additions to Oil and Gas Properties, 

Excluding Dry Hole Costs 5,790,590 259,634 132,159 58,784 6,241,167

Total Property, Plant and Equipment, Net 18,711,774 1,760,066 627,794 189,190 21,288,824

Total Assets 21,313,158 2,131,949 1,085,664 308,026 24,838,797

2010

Crude Oil and Condensate $ 1,700,770 $ 178,349 $ 117,605 $ 2,047 $ 1,998,771

Natural Gas Liquids 448,647 13,698 - - 462,345

Natural Gas 1,778,823 285,369 330,247 25,660 2,420,099

Gains on Mark-to-Market Commodity 

Derivative Contracts 61,912 - - - 61,912

Gathering, Processing and Marketing 909,660 - 20 - 909,680

Gains on Asset Dispositions, Net 196,774 23,112 3,652 - 223,538

Other, Net 19,886 (31) 3,696 - 23,551

Net Operating Revenues (3)5,116,472 500,497 455,220 27,707 6,099,896

Depreciation, Depletion and Amortization 1,539,240 315,849 71,085 15,752 1,941,926

Operating Income (Loss) 787,422 (516,874) 312,128 (59,357) 523,319

Interest Income 152 387 120 164 823

Other Income (Expense) (3,905) 2,067 14,022 1,236 13,420

Net Interest Expense 112,226 34,350 448 (17,438) 129,586

Income (Loss) Before Income Taxes 671,443 (548,770) 325,822 (40,519) 407,976

Income Tax Provision (Benefit) 255,945 (146,495) 140,934 (3,062) 247,322

Additions to Oil and Gas Properties, 

Excluding Dry Hole Costs 4,491,897 446,626 134,198 65,405 5,138,126

Total Property, Plant and Equipment, Net 15,747,808 2,189,961 595,970 147,161 18,680,900

Total Assets 17,762,533 2,598,412 954,391 308,897 21,624,233

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

(2) EOG has sales activity with a single significant purchaser in the United States segment in 2012 that totaled $2.2 billion of 

consolidated Net Operating Revenues.

(3) EOG had no purchasers in 2011 or 2010 whose sales totaled 10 percent or more of consolidated Net Operating Revenues.
F-25

11. Risk Management Activities

Commodity Price Risks. EOG engages in price risk management activities from time to time. These 

activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas. 

EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis 

swap contracts, as a means to manage this price risk. In addition to financial transactions, from time to time EOG is 

a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and 

have varying pricing provisions. These physical commodity contracts qualify for the normal purchases and normal 

sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial 

impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects 

average realized hydrocarbon prices.

During 2012, 2011 and 2010, EOG elected not to designate any of its financial commodity derivative 

contracts as accounting hedges and, accordingly, accounted for these financial commodity derivative contracts using 

the mark-to-market accounting method. During 2012, EOG recognized net gains on the mark-to-market of financial 

commodity derivative contracts of $394 million, which included net realized gains 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 realized gains of $181 million. During 2010, EOG recognized net gains on the mark-to-market of 

financial commodity derivative contracts of $62 million, which included net realized gains of $7 million. 

Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's crude oil 

derivative contracts at December 31, 2012, with notional volumes expressed in barrels per day (Bbld) and prices 

expressed in dollars per barrel ($/Bbl) 

Crude Oil Derivative Contracts

Weighted

Volume (1) Average Price

(Bbld) ($/Bbl)

2013

January 1, 2013 through June 30, 2013 101,000 $ 99.29

July 1, 2013 through December 31, 2013 93,000 98.44

(1) EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current 

derivative contracts for an additional six-month period. Options covering a notional volume of 62,000 Bbld are 

exercisable on June 28, 2013. If the counterparties exercise all such options, the notional volume of EOG's 

existing crude oil derivative contracts will increase by 62,000 Bbld at an average price of $100.24 per barrel for 

the period July 1, 2013 through December 31, 2013. Options covering a notional volume of 54,000 Bbld are 

exercisable on December 31, 2013. If the counterparties exercise all such options, the notional volume of EOG's 

existing crude oil derivative contracts will increase by 54,000 Bbld at an average price of $98.91 per barrel for the 

period January 1, 2014 through June 30, 2014.
F-26

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at December 31, 

2012, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices 

expressed in dollars per MMBtu ($/MMBtu). 

Natural Gas Derivative Contracts

Volume 

(MMBtud)

Weighted 

Average Price 

($/MMBtu)

2013 (1)

January 2013 (closed) 150,000 $4.79

February 1, 2013 through December 31, 2013 150,000 4.79

2014 (2)

(1) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into 

derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each 

monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural 

gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for the 

period from February 1, 2013 through December 31, 2013.

(2) In July 2012, EOG settled its natural gas financial price swap contracts for the period January 1, 2014 through 

December 31, 2014 and received proceeds of $36.6 million. In connection with these contracts, the 

counterparties retain an option of entering into derivative contracts at future dates. Such options are exercisable 

monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the 

notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMbtud at an 

average price of $4.79 per MMBtu for each month of 2014.

Foreign Currency Exchange Rate Derivative. EOG is party to a foreign currency aggregate swap with 

multiple banks to eliminate any exchange rate impacts that may result from the $150 million principal amount of 

notes issued by one of EOG's Canadian subsidiaries. EOG accounts for the foreign currency swap transaction using 

the hedge accounting method. Changes in the fair value of the foreign currency swap do not impact Net Income. 

The after-tax net impact from the foreign currency swap for the years ended December 31, 2012, 2011 and 2010 

resulted in an increase in Other Comprehensive Income (OCI) of $1 million, a decrease in OCI of $1 million and an 

increase in OCI of $3 million, respectively.

Interest Rate Derivative. EOG is a party to an interest rate swap with a counterparty bank. The interest rate 

swap was entered into in order to mitigate EOG's exposure to volatility in interest rates related to EOG's $350 

million principal amount of Floating Rate Senior Notes due 2014 issued in November 2010. The interest rate swap 

has a notional amount of $350 million. EOG accounts for the interest rate swap using the hedge accounting method. 

Changes in the fair value of the interest rate swap do not impact Net Income. The after-tax impact from the interest 

rate swap resulted in reductions in OCI of $0.1 million and $3 million for the years ended December 31, 2012 and 

2011, respectively, and an increase in OCI of $1 million for the year ended December 31, 2010.
F-27

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding 

derivative financial instruments at December 31, 2012 and 2011, respectively. Certain amounts may be presented on 

a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to

a master netting arrangement (in millions): 

Fair Value at December 31,

Description Location on Balance Sheet 2012 2011

Asset Derivatives

Crude oil and natural gas 

derivative contracts -

Current portion Assets from Price Risk 

Management Activities $ 166 $ 451

Noncurrent portion Other Assets $ - $ 35

Liability Derivatives

Crude oil and natural gas 

derivative contracts -

Current portion Liabilities from Price Risk 

Management Activities $ 8 $ -

Noncurrent portion Other Liabilities $ 13 $ -

Foreign currency swap -

Noncurrent portion Other Liabilities $ 55 $ 52

Interest rate swap -

Noncurrent portion Other Liabilities $ 4 $ 3

Credit Risk. Notional contract amounts are used to express the magnitude of commodity price, foreign 

currency and interest rate swap agreements. The amounts potentially subject to credit risk, in the event of 

nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 12). EOG evaluates its 

exposure to significant counterparties on an ongoing basis, including those arising from physical and financial 

transactions. In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit 

risk. At December 31, 2012, EOG's net accounts receivable balance related to United States, Canada and United 

Kingdom hydrocarbon sales include one receivable balance which constituted 26% of the total balance. The 

receivable was due from a United States petroleum marketing company. The related amount was collected during 

early 2013. At December 31, 2011, no individual purchaser's net accounts receivable balance related to United 

States, Canada and United Kingdom hydrocarbon sales accounted for 10% or more of the total balance. In 2012 and 

2011, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and 

Tobago and all natural gas from EOG's China operations was sold to Petrochina Company Limited.

All of EOG's outstanding derivative instruments are covered by International Swap Dealers Association 

Master Agreements (ISDAs) with counterparties. The ISDAs may contain provisions that require EOG, if it is the 

party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level 

specified for EOG's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain 

circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its thencurrent ratings, the counterparty may require all outstanding derivatives under the ISDA to be settled immediately. 

See Note 12 for the aggregate fair value of all derivative instruments that were in a net liability position at December 

31, 2012 and 2011. EOG had no collateral posted at both December 31, 2012 and 2011. EOG held $6 million and 

$67 million of collateral at December 31, 2012 and 2011, respectively.
F-28

Substantially all of EOG's accounts receivable at December 31, 2012 and 2011 resulted from hydrocarbon 

sales and/or joint interest billings to third-party companies, including foreign state-owned entities in the oil and gas 

industry. This concentration of customers and joint interest owners may impact EOG's overall credit risk, either 

positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. 

In determining whether or not to require collateral or other credit enhancements from a customer or joint interest 

owner, EOG typically analyzes the entity's net worth, cash flows, earnings and credit ratings. Receivables are 

generally not collateralized. During the three-year period ended December 31, 2012, credit losses incurred on 

receivables by EOG have been immaterial.

12. Fair Value Measurements

Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the 

Consolidated Balance Sheets. An established fair value hierarchy prioritizes the relative reliability of inputs used in 

fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted 

market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at 

the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included 

within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. EOG gives

consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets 

and liabilities at fair value. 

The following table provides fair value measurement information within the fair value hierarchy for certain 

of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2012 and 2011 (in 

millions): 

Fair Value Measurements Using:

Quoted Significant

Prices in Other Significant

Active Observable Unobservable

Markets Inputs Inputs

(Level 1) (Level 2) (Level 3) Total

At December 31, 2012

Financial Assets:

Crude Oil Swaps $ - $ 65 $ - $ 65

Crude Oil Options/Swaptions - 36 - 36

Natural Gas Options/Swaptions - 65 - 65

Financial Liabilities:

Crude Oil Options/Swaptions $ - $ 8 $ - $ 8

Natural Gas Options/Swaptions - 13 - 13

Foreign Currency Rate Swap - 55 - 55

Interest Rate Swap - 4 - 4

At December 31, 2011

Financial Assets:

Crude Oil Swaps $ - $ 29 $ - $ 29

Crude Oil Options/Swaptions - 4 - 4

Natural Gas Swaps - 81 - 81

Natural Gas Options/Swaptions - 372 - 372

Financial Liabilities:

Foreign Currency Rate Swap $ - $ 52 $ - $ 52

Interest Rate Swap - 3 - 3
F-29

The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) and 

the interest rate swap contract (see Note 11) was based upon forward commodity price and interest rate curves based 

on quoted market prices. The estimated fair value of the foreign currency rate swap was based upon forward 

currency rates. Swaps were valued using market prices and discount rates from an independent third-party provider 

of financial market data. The Black 76 Model is utilized in valuing options.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow 

techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. 

Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve 

lives. A reconciliation of EOG's asset retirement obligations is presented in Note 14.

During 2012, proved and unproved oil and gas properties and other assets with a carrying amount of $1,524 

million were written down to their fair value of $391 million, resulting in pretax impairment charges of $1,133

million. Included in the $1,133 million pretax impairment charges are $60 million of impairments of proved oil and 

gas properties and other property, plant and equipment for which EOG utilized accepted offers from third-party 

purchasers as the basis for determining fair value. During 2011, proved oil and gas properties with a carrying 

amount of $1,450 million were written down to their fair value of $616 million, resulting in pretax impairment 

charges of $834 million. In connection with $278 million of impairments of certain natural gas assets in the United 

States during 2011, EOG utilized accepted bids as the basis for determining fair value. Significant Level 3 

assumptions associated with the calculation of discounted cash flows used in the impairment analysis include EOG's 

estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated 

production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. 

Fair Value of Debt. At December 31, 2012 and 2011, EOG had outstanding $6,290 million and $5,040 

million, respectively, aggregate principal amount of debt, which had estimated fair values of approximately $7,032

million and $5,657 million, respectively. The estimated fair value of debt was based upon quoted market prices and, 

where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at 

year-end. 

13. Accounting for Certain Long-Lived Assets

EOG reviews its proved oil and gas properties for impairment purposes by comparing the expected 

undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. During 

2012, 2011 and 2010, such reviews indicated that unamortized capitalized costs of certain properties were higher 

than their expected undiscounted future cash flows due primarily to lower commodity prices, downward reserve 

revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields. Several 

impairments over this period were recognized in connection with the signing of purchase and sale agreements. As a 

result, EOG recorded pretax charges of $171 million, $403 million and $107 million in the United States during 

2012, 2011 and 2010, respectively, and $872 million, $428 million and $418 million in Canada during 2012, 2011

and 2010, respectively. Additionally, EOG recorded pretax charges of $3 million in Other International during 2011 

and $1 million in Trinidad during 2010. The pretax charges are included in Impairments on the Consolidated 

Statements of Income and Comprehensive Income. The carrying values for assets determined to be impaired were 

adjusted to estimated fair value using the Income Approach described in the Fair Value Measurement Topic of the 

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

impairments of unproved oil and gas property costs, including amortization of capitalized interest, were $228

million, $197 million and $217 million for 2012, 2011 and 2010, respectively. 
F-30

14. Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of 

short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the 

years ended December 31, 2012 and 2011 (in thousands):

2012 2011

Carrying Amount at Beginning of Period $ 587,084 $ 498,288

Liabilities Incurred 107,378 68,703

Liabilities Settled (1) (77,384) (66,129)

Accretion 30,020 27,907

Revisions 15,287 58,786

Foreign Currency Translations 3,559 (471)

Carrying Amount at End of Period $ 665,944 $ 587,084

Current Portion $ 30,127 $ 29,527

Noncurrent Portion $ 635,817 $ 557,557

(1) Includes settlements related to asset sales.

The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities -

Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

15. Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2012, 2011 and 

2010 are presented below (in thousands):

2012 2011 2010

Balance at January 1 $ 61,111 $ 99,801 $ 118,459

Additions Pending the Determination of Proved Reserves 73,332 31,271 94,090

Reclassifications to Proved Properties (69,462) (29,227) (93,333)

Costs Charged to Expense (1) (17,115) (42,178) (20,267)

Foreign Currency Translations 1,250 1,444 852

Balance at December 31 $ 49,116 $ 61,111 $ 99,801

(1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments.
F-31

The following table provides an aging of capitalized exploratory well costs at December 31, 2012, 2011 and 

2010 (in thousands, except well count):

2012 2011 2010

Capitalized exploratory well costs that have been 

capitalized for a period less than one year $ 28,319 $ 17,009 $ 43,408

Capitalized exploratory well costs that have been 

capitalized for a period greater than one year 20,797 (1) 44,102 (2)56,393 (3)

Total $ 49,116 $ 61,111 $ 99,801

Number of exploratory wells that have been capitalized 

for a period greater than one year 1 4 4

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

In the Central North Sea Columbus project, a revised field development plan was submitted to the U.K. Department of Energy 

and Climate Change during the third quarter of 2012. The project participants are currently negotiating commercial agreements.

(2) Consists of costs related to an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($20 million), 

an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($9 million), and a 

shale project in British Columbia, Canada (B.C.) ($6 million). 

(3) Consists of costs related to an outside operated, offshore Central North Sea project in the U.K. ($21 million), an East Irish Sea 

project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($20 million), and a shale project in 

B.C. ($6 million). 

16. Acquisitions and Divestitures

During 2012, EOG received proceeds of approximately $1.3 billion from the sales of producing properties 

and acreage primarily in the Rocky Mountain area, the Upper Gulf Coast region and Canada. During 2011, EOG 

received proceeds of approximately $1.4 billion from sales of producing properties and acreage and certain 

midstream assets, primarily in the Rocky Mountain area and Texas, and the sale of a portion of EOG's interest in the 

planned Kitimat liquefied natural gas export terminal (Kitimat LNG Terminal) and the proposed Pacific Trail 

Pipelines (PTP). During 2010, EOG received proceeds of approximately $673 million from the sale of producing 

properties and acreage, primarily Canadian shallow natural gas assets and properties in the Rocky Mountain area, 

Texas, and Pennsylvania.

EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), owned a 30% interest 

in both the Kitimat LNG Terminal to be located near the Port of Kitimat, British Columbia and PTP which is 

intended to link Western Canada's natural gas producing regions to the Kitimat LNG Terminal. In December 2012, 

EOGRC signed a purchase and sale agreement for the sale of its entire interest in the Kitimat LNG Terminal and 

PTP, as well as approximately 28,500 undeveloped net acres in the Horn River Basin, to Chevron Canada Limited. 

The transaction closed in February 2013. Additionally in 2012, EOG signed purchase and sale agreements for the 

sale of certain properties in the United States. At December 31, 2012, the book value of these assets held for sale 

and the related liabilities were $310 million and $31 million, respectively. 

In the fourth quarter of 2010, EOG completed the sales of certain of its Canadian shallow natural gas assets 

in three separate transactions. Proceeds from the sales were approximately $344 million. In 2010, EOG recorded a 

pretax impairment of $280 million to adjust the shallow natural gas assets sold to estimated fair value less estimated 

cost to sell. 
F-32

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

Oil and Gas Producing Activities

The following disclosures are made in accordance with Financial Accounting Standards Board Accounting 

Standards Update No. 2010-03 "Oil and Gas Reserve Estimates and Disclosures" and the United States Securities and 

Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting."

Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of 

"proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids (NGLs) and natural gas reserves 

is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and 

economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of 

numerous factors, including, but not limited to, additional development activity, evolving production history and 

continual reassessment of the viability of production under varying economic conditions. Consequently, material 

revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort 

is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of 

the subjective decisions required and variances in available data for various reservoirs make these estimates generally 

less precise than other estimates presented in connection with financial statement disclosures. See ITEM 1A. Risk 

Factors.

Proved reserves represent estimated quantities of crude oil, NGLs and natural gas that geoscience and 

engineering data can estimate, with reasonable certainty, to be economically producible from a given day forward from 

known reservoirs under then-existing economic conditions, operating methods and government regulation before the 

time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably 

certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved developed reserves are proved reserves expected to be recovered under operating methods being 

utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required 

equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on 

undrilled acreage, or from existing wells where a significant expenditure is required. Reserves on undrilled acreage 

are limited to those directly offsetting development spacing areas that are reasonably certain of production when 

drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic 

producibility at greater distances. PUDs can be recorded in respect of a particular undrilled location only if the

location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the 

date that the PUDs are to be recorded, unless specific factors (such as those described in interpretative guidance 

issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs 

associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if 

the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond 

five years from the date that the PUDs were recorded. Estimates for PUDs are not attributed to any acreage for 

which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques 

have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence 

using reliable technology establishing reasonable certainty.
F-33

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In making estimates of PUDs, EOG's technical staff, including engineers and geoscientists, perform detailed 

technical analysis of each potential drilling location within its entire inventory of prospects. In making a 

determination as to which of these locations would penetrate undrilled portions of the formation that can be judged, 

with reasonable certainty, to be continuous and contain economically producible crude oil and natural gas, studies 

are conducted using numerous data elements and analysis techniques. EOG technical staff estimates the 

hydrocarbons in place, by mapping the entirety of the play in question using seismic techniques, typically employing 

two-dimensional and three-dimensional data. This analysis is integrated with other static data, including, but not 

limited to, core analysis, mechanical properties of the formation, thermal maturity indicators, and well logs of 

existing penetrations. Highly specialized equipment is utilized to prepare rock samples in assessing microstructures 

which contribute to porosity and permeability.

Analysis of dynamic data is then incorporated to arrive at the estimated fractional recovery of hydrocarbons 

in place. Data analysis techniques employed include, but are not limited to, well testing analysis, static bottom hole 

pressure analysis, flowing bottom hole pressure analysis, analysis of historical production trends, pressure transient 

analysis and rate transient analysis. Application of proprietary rate transient analysis techniques in low permeability 

rocks allow for quantification of estimates of contribution to production from both fractures and rock matrices.

The impact of optimal completion techniques is a key factor in determining if prospective locations are 

reasonably certain of being economically producible. EOG's technical staff estimates recovery improvement that 

might be achieved when completing horizontal wells with multi-stage fracture stimulation. In the early stages of 

development of a play, EOG determines the optimal length of the horizontal lateral and multi-stage fracture 

stimulation using the aforementioned analysis techniques along with pilot drilling programs and gathering of 

microseismic data.

The process of analyzing static and dynamic data, well completion optimization and the results of early 

development activities provides the appropriate level of certainty as well as support for the economic producibilty of 

the plays in which PUDs are reflected. EOG has found this approach to be effective based on successful application 

in analogous reservoirs in low permeability resource plays.

EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 

2012. Under EOG's current drilling and development plan, each PUD location will be drilled within five years from 

the date it was recorded.

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices, 

production volumes and the length of wells, both vertical and horizontal. Canadian reserves, as presented on a net basis, 

assume prices and legislated future royalty rates and EOG's estimate of future production volumes. Similarly, certain of

EOG's Trinidad reserves are held under production sharing contracts where EOG's interest varies with prices and 

production volumes. Trinidad reserves, as presented on a net basis, assume prices in existence at the time the estimates 

were made and EOG's estimate of future production volumes. Future fluctuations in prices, production rates or changes 

in political or regulatory environments could cause EOG's share of future production from Canadian and Trinidadian 

reserves to be materially different from that presented.

Estimates of proved reserves at December 31, 2012, 2011 and 2010 were based on studies performed by the 

engineering staff of EOG. The Engineering and Acquisitions Department is directly responsible for EOG's reserve 

evaluation process and consists of seven professionals, all of whom hold, at a minimum, bachelor's degrees in 

engineering, and two of whom are Registered Professional Engineers. The Manager, Engineering and Acquisitions is 

the manager of this department and is the primary technical person responsible for this process. The Manager, 

Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 27 years of experience 

in reserve evaluations and is a Registered Professional Engineer in the State of Texas.
F-34

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions 

Department in compliance with EOG's internal controls for such process. Reserve information as well as models used to 

estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, 

including crude oil, NGLs and natural gas prices, production costs, future capital expenditures and EOG's net ownership 

percentages are obtained from other departments within EOG. EOG's Internal Audit Department conducts testing with 

respect to such non-technical inputs. Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent 

petroleum consultants, to perform independent reserves evaluation of select EOG properties comprising not less than 

75% of EOG's estimates of proved reserves. EOG's Board of Directors requires that D&M's and EOG's reserve 

quantities for the properties evaluated by D&M vary by no more than 5% in the aggregate. Once completed, EOG's 

year-end reserves are presented to senior management, including the Chairman of the Board and Chief Executive 

Officer, the President, the Chief Operating Officer, and the Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2012, 2011 and 2010 covered producing areas containing 

87%, 85% and 77%, respectively, of proved reserves of EOG on a net-equivalent-barrel-of-oil basis. D&M's opinions 

indicate that the estimates of proved reserves prepared by EOG's Engineering and Acquisitions Department for the 

properties reviewed by D&M, when compared in total on a net-equivalent-barrel-of-oil basis, do not differ materially 

from the estimates prepared by D&M. Such estimates by D&M in the aggregate varied by not more than 5% from those 

prepared by the Engineering and Acquisitions Department of EOG. All reports by D&M were developed utilizing 

geological and engineering data provided by EOG. The report of D&M dated January 29, 2013, which contains 

further discussion of the reserve estimates and evaluations prepared by D&M, as well as the qualifications of D&M's 

technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 23.2 to 

this Annual Report on Form 10-K and incorporated herein by reference.

No major discovery or other favorable or adverse event subsequent to December 31, 2012, is believed to have 

caused a material change in the estimates of proved or proved developed reserves as of that date.
F-35

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the 

four years in the period ended December 31, 2012, and the changes in the net proved reserves for each of the three years 

in the period ended December 31, 2012, as estimated by the Engineering and Acquisitions Department of EOG:

NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY

United Other

States Canada Trinidad International (1) Total

NET PROVED RESERVES

Crude Oil (MBbl) (2)

Net proved reserves at December 31, 2009 188,452 25,586 5,443 58 219,539

Revisions of previous estimates (8,313) (104) (754) 20 (9,151)

Purchases in place 13 - - - 13

Extensions, discoveries and other additions 199,479 3,198 1,751 48 204,476

Sales in place (1,082) (589) - - (1,671)

Production (23,092) (2,455) (1,709) (28) (27,284)

Net proved reserves at December 31, 2010 355,457 25,636 4,731 98 385,922

Revisions of previous estimates (21,188) (4,611) 18 25 (25,756)

Purchases in place 9 - - - 9

Extensions, discoveries and other additions 202,552 449 - - 203,001

Sales in place (4,301) - - - (4,301)

Production (37,233) (2,882) (1,242) (25) (41,382)

Net proved reserves at December 31, 2011 495,296 18,592 3,507 98 517,493

Revisions of previous estimates 4,105 (2,493) 71 5 1,688

Purchases in place 1,010 - - - 1,010

Extensions, discoveries and other additions 241,171 5,681 - 8,834 255,686

Sales in place (15,921) (1,343) - - (17,264)

Production (54,632) (2,574) (550) (39) (57,795)

Net proved reserves at December 31, 2012 671,029 17,863 3,028 8,898 700,818

Natural Gas Liquids (MBbl) (2)

Net proved reserves at December 31, 2009 91,489 1,972 - - 93,461

Revisions of previous estimates 27,490 (196) - - 27,294

Purchases in place - - - - -

Extensions, discoveries and other additions 42,221 21 - - 42,242

Sales in place (2) (6) - - (8)

Production (10,764) (316) - - (11,080)

Net proved reserves at December 31, 2010 150,434 1,475 - - 151,909

Revisions of previous estimates 35,999 43 - - 36,042

Purchases in place 17 - - - 17

Extensions, discoveries and other additions 65,288 - - - 65,288

Sales in place (10,008) - - - (10,008)

Production (15,144) (316) - - (15,460)

Net proved reserves at December 31, 2011 226,586 1,202 - - 227,788

Revisions of previous estimates 47,293 563 - - 47,856

Purchases in place 612 - - - 612

Extensions, discoveries and other additions 71,396 178 - - 71,574

Sales in place (7,300) (77) - - (7,377)

Production (20,181) (309) - - (20,490)

Net proved reserves at December 31, 2012 318,406 1,557 - - 319,963
F-36

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

United Other

States Canada Trinidad International (1) Total

Natural Gas (Bcf) (3)

Net proved reserves at December 31, 2009 6,350.1 1,549.5 985.8 12.7 8,898.1

Revisions of previous estimates (222.7) (29.9) (88.6) 1.9 (339.3)

Purchases in place - - - - -

Extensions, discoveries and other additions 821.3 3.4 63.0 7.9 895.6

Sales in place (34.6) (316.2) - - (350.8)

Production (422.6) (73.0) (132.6) (5.2) (633.4)

Net proved reserves at December 31, 2010 6,491.5 1,133.8 827.6 17.3 8,470.2

Revisions of previous estimates (344.0) (49.8) (24.2) 1.3 (416.7)

Purchases in place 3.0 - - - 3.0

Extensions, discoveries and other additions 634.6 - 74.7 4.5 713.8

Sales in place (323.6) - - - (323.6)

Production (415.7) (48.1) (127.4) (4.6) (595.8)

Net proved reserves at December 31, 2011 6,045.8 1,035.9 750.7 18.5 7,850.9

Revisions of previous estimates (1,736.0) (894.5) (24.1) 1.6 (2,653.0)

Purchases in place 14.8 - - - 14.8

Extensions, discoveries and other additions 477.8 - - 0.3 478.1

Sales in place (386.2) (8.5) - - (394.7)

Production (380.2) (34.6) (138.4) (3.4) (556.6)

Net proved reserves at December 31, 2012 4,036.0 98.3 588.2 17.0 4,739.5

Oil Equivalents (MBoe) (2)

Net proved reserves at December 31, 2009 1,338,292 285,808 169,747 2,172 1,796,019

Revisions of previous estimates (17,945) (5,288) (15,513) 342 (38,404)

Purchases in place 14 - - - 14

Extensions, discoveries and other additions 378,582 3,789 12,250 1,363 395,984

Sales in place (6,860) (53,288) - - (60,148)

Production (104,277) (14,937) (23,815) (901) (143,930)

Net proved reserves at December 31, 2010 1,587,806 216,084 142,669 2,976 1,949,535

Revisions of previous estimates (42,526) (12,865) (4,011) 239 (59,163)

Purchases in place 521 - - - 521

Extensions, discoveries and other additions 373,602 448 12,455 750 387,255

Sales in place (68,247) - - - (68,247)

Production (121,648) (11,219) (22,484) (787) (156,138)

Net proved reserves at December 31, 2011 1,729,508 192,448 128,629 3,178 2,053,763

Revisions of previous estimates (237,936) (151,015) (3,953) 283 (392,621)

Purchases in place 4,098 - - - 4,098

Extensions, discoveries and other additions 392,196 5,860 - 8,876 406,932

Sales in place (87,588) (2,832) - - (90,420)

Production (138,170) (8,657) (23,616) (611) (171,054)

Net proved reserves at December 31, 2012 1,662,108 35,804 101,060 11,726 1,810,698

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

(2) Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and 

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

feet of natural gas.

(3) Billion cubic feet.
F-37

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2012, EOG added 407 million barrels of oil equivalent (MMBoe) of proved reserves from drilling 

activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Permian Basin, Bakken and 

Barnett Combo shale plays. Approximately 80% of the 2012 reserve additions were crude oil and condensate and 

NGLs and over 96% were in the United States. Sales in place of 90 MMBoe were primarily related to the 

disposition of certain producing natural gas assets on the Gulf Coast, outside-operated crude oil properties in the 

Rocky Mountain area and other producing basins in the United States. Revisions of previous estimates of negative 

393 MMBoe for 2012 included a negative revision of 531 MMBoe primarily due to a decrease in the average natural 

gas price used in the December 31, 2012 reserves estimation as compared to the price used in the prior year estimate. 

The primary plays affected were the Horn River, Haynesville, Barnett Shale and Marcellus Shale. Revisions other 

than price resulted from revisions for certain crude oil and natural gas properties in the United States.

During 2011, EOG added 387 million barrels of oil equivalent (MMBoe) of proved reserves from drilling 

activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Barnett Combo and Bakken 

shale plays. Approximately 69% of the 2011 reserve additions were crude oil and condensate and NGLs and over 

96% were in the United States. Sales in place of 68 MMBoe were primarily related to the disposition of certain 

producing natural gas assets in East Texas, the Rocky Mountain area and other producing basins in the United States. 

Revisions of previous estimates of negative 59 MMBoe for 2011 included a negative revision of 16 MMBoe 

primarily due to a decrease in the average natural gas price used in the December 31, 2011 reserves estimation as 

compared to the price used in the prior year estimate. Revisions other than price resulted from negative revisions for 

certain crude oil and natural gas properties in the United States, Canada and Trinidad.

During 2010, EOG added 396 MMBoe of proved reserves from drilling activities and technical evaluation 

of major proved areas, primarily in the Eagle Ford, Bakken, Barnett Combo and Haynesville shale plays. 

Approximately 62% of the 2010 reserve additions were crude oil and condensate and NGLs and over 95% were in 

the United States. Sales in place of 60 MMBoe were primarily related to the Canadian shallow natural gas assets and 

certain producing natural gas assets in East Texas. Revisions of previous estimates of negative 38 MMBoe for 2010 

included a positive revision of 28 MMBoe primarily due to an increase in the average natural gas price used in the 

December 31, 2010 reserves estimation as compared to the price used in the prior year estimate. Revisions other 

than price resulted from negative revisions for certain natural gas properties in the United States, Canada and 

Trinidad and the removal of proved undeveloped natural gas drilling locations from the five-year drilling plan to 

focus on crude oil and liquids-rich drilling as part of EOG's overall strategy.
F-38

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

United Other

States Canada Trinidad International (1) Total

NET PROVED DEVELOPED RESERVES

Liquids (MBbl)

December 31, 2009 189,322 10,831 3,966 58 204,177

December 31, 2010 253,308 12,758 3,853 98 270,017

December 31, 2011 338,144 9,220 2,657 97 350,118

December 31, 2012 442,648 7,963 2,378 253 453,242

Natural Gas (Bcf)

December 31, 2009 3,330.1 681.0 609.4 12.7 4,633.2

December 31, 2010 3,519.7 401.6 519.2 17.3 4,457.8

December 31, 2011 3,234.9 295.8 606.3 18.6 4,155.6

December 31, 2012 2,387.5 98.3 476.7 17.0 2,979.5

Oil Equivalents (MBoe)

December 31, 2009 744,339 124,323 105,540 2,172 976,374

December 31, 2010 839,928 79,701 90,382 2,976 1,012,987

December 31, 2011 877,301 58,524 103,710 3,178 1,042,713

December 31, 2012 840,564 24,348 81,826 3,081 949,819

NET PROVED UNDEVELOPED RESERVES

Liquids (MBbl)

December 31, 2009 90,619 16,727 1,477 - 108,823

December 31, 2010 252,583 14,352 879 - 267,814

December 31, 2011 383,739 10,574 850 - 395,163

December 31, 2012 546,786 11,456 651 8,645 567,538

Natural Gas (Bcf)

December 31, 2009 3,020.0 868.5 376.4 - 4,264.9

December 31, 2010 2,971.7 732.2 308.5 - 4,012.4

December 31, 2011 2,810.8 740.1 144.4 - 3,695.3

December 31, 2012 1,648.5 - 111.5 - 1,760.0

Oil Equivalents (MBoe)

December 31, 2009 593,953 161,486 64,207 - 819,646

December 31, 2010 747,878 136,383 52,287 - 936,548

December 31, 2011 852,207 133,924 24,919 - 1,011,050

December 31, 2012 821,544 11,456 19,234 8,645 860,879

(1) Other International includes EOG's United Kingdom, China and Argentina operations.
F-39

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the twelve-month period ended December 31, 2012, total PUDs decreased by 150 MMBoe to 861 

MMBoe. EOG added approximately 32 MMBoe of PUDs through drilling activities where the wells were drilled 

but significant expenditures remained for completion. Based on the technology employed by EOG to identify and 

record PUDs (see discussion of technology employed on page F-33 of this Annual Report on Form 10-K), EOG 

added 268 MMBoe. The PUD additions were primarily in the Eagle Ford, Permian Basin, Bakken and Barnett 

Combo shale plays, and nearly 84% of the additions were crude oil and condensate and NGLs. During 2012, EOG 

drilled and transferred 138 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,764 million. 

Revisions of PUDs totaled negative 293 MMBoe, primarily due to removal of certain natural gas PUDs due to lower 

average natural gas prices. The primary plays affected were the Horn River, Haynesville, Barnett Shale and 

Marcellus Shale. During 2012, EOG sold 19 MMBoe of PUDs. 

For the twelve-month period ended December 31, 2011, total PUDs increased by 75 MMBoe to 1,011 

MMBoe. EOG added approximately 36 MMBoe of PUDs through drilling activities where the wells were drilled 

but significant expenditures remained for completion. Based on the technology employed by EOG to identify and 

record PUDs, EOG added 199 MMBoe. The PUD additions were primarily in the Eagle Ford and Barnett Combo 

shale plays, and over 78% of the additions were crude oil and condensate and NGLs. During 2011, EOG drilled and 

transferred 144 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,619 million. Revisions 

of PUDs totaled negative 7 MMBoe, primarily due to removal of certain natural gas PUDs from the five-year drilling 

plan. During 2011, EOG sold 9 MMBoe of PUDs. 

For the twelve-month period ended December 31, 2010, total PUDs increased by 117 MMBoe to 937 

MMBoe. EOG added approximately 37 MMBoe of PUDs through drilling activities where the wells were drilled 

but significant expenditures remained for completion. Based on the technology employed by EOG to identify and 

record PUDs, EOG added 218 MMBoe. The PUD additions were primarily in the Eagle Ford, Bakken, Barnett 

Combo and Haynesville shale plays, and nearly 73% of the additions were crude oil and condensate and NGLs. 

During 2010, EOG drilled and transferred 118 MMBoe of PUDs to proved developed reserves at a total capital cost 

of $1,280 million. Revisions of PUDs totaled negative 12 MMBoe, primarily due to removal of certain natural gas 

PUDs from the five-year drilling plan. During 2010, EOG sold 8 MMBoe of PUDs. 

As of December 31, 2012, EOG did not have any reserves that have remained undeveloped for five or more 

years.
F-40

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized 

costs relating to EOG's crude oil and natural gas producing activities at December 31, 2012 and 2011:

2012 2011

Proved properties $ 36,872,434 $ 32,353,380

Unproved properties 1,253,864 1,311,055

Total 38,126,298 33,664,435

Accumulated depreciation, depletion and 

amortization (16,849,068) (13,981,143)

Net capitalized costs $ 21,277,230 $ 19,683,292

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

exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive 

Industries - Oil and Gas Topic of the ASC.

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

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

Development costs include additions to production facilities and equipment and additions to development 

wells, including those in progress.
F-41

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended 

December 31, 2012, 2011 and 2010:

United Other

States Canada Trinidad International (1) Total

2012

Acquisition Costs of Properties

Unproved $ 471,345 $ 33,561 $ 1,000 $ (603) $ 505,303

Proved 739 - - - 739

Subtotal 472,084 33,561 1,000 (603) 506,042

Exploration Costs 333,534 38,530 19,555 53,979 445,598

Development Costs (2) 5,657,378 278,995 32,609 147,568 6,116,550

Total $ 6,462,996 $ 351,086 $ 53,164 $ 200,944 $ 7,068,190

2011

Acquisition Costs of Properties

Unproved $ 295,160 $ 6,216 $ - $ (604) $ 300,772

Proved 4,219 28 - - 4,247

Subtotal 299,379 6,244 - (604) 305,019

Exploration Costs 311,369 31,472 2,549 18,164 363,554

Development Costs (3)5,410,378 302,564 138,905 78,744 5,930,591

Total $ 6,021,126 $ 340,280 $ 141,454 $ 96,304 $ 6,599,164

2010

Acquisition Costs of Properties

Unproved $ 403,509 $ 13,956 $ - $ (107) $ 417,358

Proved - - - - -

Subtotal 403,509 13,956 - (107) 417,358

Exploration Costs 454,379 38,604 23,386 86,784 603,153

Development Costs (4)3,892,403 417,176 114,986 13,429 4,437,994

Total $ 4,750,291 $ 469,736 $ 138,372 $ 100,106 $ 5,458,505

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

(2) Includes Asset Retirement Costs of $80 million, $33 million, $2 million and $12 million for the United States, Canada, Trinidad 

and Other International, respectively. Excludes other property, plant and equipment.

(3) Includes Asset Retirement Costs of $52 million, $70 million, $7 million and $4 million for the United States, Canada, Trinidad 

and Other International, respectively. Excludes other property, plant and equipment.

(4) Includes Asset Retirement Costs of $71 million, $2 million, $(3) million and $2 million for the United States, Canada, Trinidad 

and Other International, respectively. Excludes other property, plant and equipment.
F-42

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Results of Operations for Oil and Gas Producing Activities (1). The following table sets forth results of operations 

for oil and gas producing activities for the years ended December 31, 2012, 2011 and 2010:

United Other

States Canada Trinidad International (2) Total

2012

Crude Oil and Condensate, Natural Gas 

Liquids and Natural Gas Revenues $ 7,048,572 $ 321,597 $ 565,030 $ 23,177 $ 7,958,376

Other 40,780 367 15 - 41,162

Total 7,089,352 321,964 565,045 23,177 7,999,538

Exploration Costs 162,152 13,350 2,262 7,805 185,569

Dry Hole Costs 1,772 1,570 - 11,628 14,970

Transportation Costs 591,547 7,511 1,104 1,269 601,431

Production Costs 1,264,633 154,509 37,792 11,694 1,468,628

Impairments 294,172 976,563 - - 1,270,735

Depreciation, Depletion and Amortization 2,637,500 222,366 146,690 17,958 3,024,514

Income (Loss) Before Income Taxes 2,137,576 (1,053,905) 377,197 (27,177) 1,433,691

Income Tax Provision (Benefit) 761,459 (136,105) 119,442 (21,890) 722,906

Results of Operations $ 1,376,117 $ (917,800) $ 257,755 $ (5,287) $ 710,785

2011

Crude Oil and Condensate, Natural Gas 

Liquids and Natural Gas Revenues $ 5,814,942 $ 459,853 $ 555,143 $ 28,250 $ 6,858,188

Other 32,329 258 586 - 33,173

Total 5,847,271 460,111 555,729 28,250 6,891,361

Exploration Costs 148,199 10,479 2,520 10,460 171,658

Dry Hole Costs 30,521 432 - 22,277 53,230

Transportation Costs 421,060 5,969 1,620 1,673 430,322

Production Costs 1,096,955 174,973 49,318 10,964 1,332,210

Impairments 575,976 452,103 - 2,958 1,031,037

Depreciation, Depletion and Amortization 2,011,080 258,772 106,802 17,160 2,393,814

Income (Loss) Before Income Taxes 1,563,480 (442,617) 395,469 (37,242) 1,479,090

Income Tax Provision (Benefit) 569,153 (121,044) 202,815 (13,056) 637,868

Results of Operations $ 994,327 $ (321,573) $ 192,654 $ (24,186) $ 841,222

2010

Crude Oil and Condensate, Natural Gas 

Liquids and Natural Gas Revenues $ 3,928,240 $ 477,416 $ 447,852 $ 27,707 $ 4,881,215

Other 19,886 (31) 3,696 - 23,551

Total 3,948,126 477,385 451,548 27,707 4,904,766

Exploration Costs 156,252 17,597 2,277 11,255 187,381

Dry Hole Costs 30,927 14,875 5,000 21,684 72,486

Transportation Costs 372,466 9,892 1,348 1,483 385,189

Production Costs 763,769 174,667 51,125 8,504 998,065

Impairments 271,466 451,703 1,465 418 725,052

Depreciation, Depletion and Amortization 1,430,408 314,663 70,553 15,399 1,831,023

Income (Loss) Before Income Taxes 922,838 (506,012) 319,780 (31,036) 705,570

Income Tax Provision (Benefit) 375,855 (151,315) 140,413 (14,245) 350,708

Results of Operations $ 546,983 $ (354,697) $ 179,367 $ (16,791) $ 354,862

(1) Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and 

related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2012. 

(2) Other International primarily consists of EOG's United Kingdom, China and Argentina operations. 
F-43

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad 

valorem taxes, for the years ended December 31, 2012, 2011 and 2010:

United Other

States Canada Trinidad International (1) Composite

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

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

Year Ended December 31, 2010 $ 5.00 $ 10.28 $ 0.65 $ 9.34 $ 4.85

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

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

following information has been developed utilizing procedures prescribed by the Extractive Industries - Oil and Gas Topic of 

the ASC and based on crude oil, NGLs and natural gas reserves and production volumes estimated by the Engineering and 

Acquisitions Department of EOG. The estimates were based on a 12-month average for commodity prices for the years 

2012, 2011 and 2010. The following information may be useful for certain comparison purposes, but should not be solely 

relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be 

considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of 

Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in 

existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGLs and 

natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than 

those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such 

decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves, 

and varying price and cost assumptions considered more representative of a range of possible economic conditions that may 

be anticipated.
F-44

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth the standardized measure of discounted future net cash flows from projected production of 

EOG's oil and gas reserves for the years ended December 31, 2012, 2011 and 2010:

United Other

States Canada Trinidad International (1) Total

2012

Future cash inflows (2) $ 89,324,274 $ 1,816,369 $ 2,408,116 $ 1,063,854 $ 94,612,613

Future production costs (35,892,997) (751,113) (342,113) (198,609) (37,184,832)

Future development costs (15,825,040) (813,061) (171,737) (221,893) (17,031,731)

Future income taxes (10,247,007) - (691,109) (212,626) (11,150,742)

Future net cash flows 27,359,230 252,195 1,203,157 430,726 29,245,308

Discount to present value at 10% annual rate (12,177,896) 146,954 (242,087) (56,807) (12,329,836)

Standardized measure of discounted future net 

cash flows relating to proved oil and gas 

reserves $ 15,181,334 $ 399,149 $ 961,070 $ 373,919 $ 16,915,472

2011

Future cash inflows (3)$ 84,518,638 $ 5,056,501 $ 2,851,545 $ 103,853 $ 92,530,537

Future production costs (33,294,343) (2,315,110) (388,199) (62,938) (36,060,590)

Future development costs (13,811,449) (1,566,917) (149,884) (331) (15,528,581)

Future income taxes (10,539,182) (81,590) (794,856) (2,457) (11,418,085)

Future net cash flows 26,873,664 1,092,884 1,518,606 38,127 29,523,281

Discount to present value at 10% annual rate (12,498,010) (456,537) (334,399) (9,054) (13,298,000)

Standardized measure of discounted future net 

cash flows relating to proved oil and gas 

reserves $ 14,375,654 $ 636,347 $ 1,184,207 $ 29,073 $ 16,225,281

2010

Future cash inflows (4)$ 62,063,123 $ 6,040,422 $ 2,760,819 $ 91,805 $ 70,956,169

Future production costs (22,616,039) (2,711,415) (384,147) (48,953) (25,760,554)

Future development costs (9,596,005) (1,716,734) (198,072) (334) (11,511,145)

Future income taxes (8,503,301) (129,816) (850,699) (3,598) (9,487,414)

Future net cash flows 21,347,778 1,482,457 1,327,901 38,920 24,197,056

Discount to present value at 10% annual rate (10,718,854) (736,222) (339,035) (11,121) (11,805,232)

Standardized measure of discounted future net 

cash flows relating to proved oil and gas 

reserves $ 10,628,924 $ 746,235 $ 988,866 $ 27,799 $ 12,391,824

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

(2) Estimated crude oil prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $99.78, 

$84.77, $94.46 and $109.94, respectively. Estimated NGLs prices used to calculate 2012 future cash inflows for the United States and Canada were 

$36.95 and $47.80, respectively. Estimated natural gas prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and 

Other International were $2.63, $2.22, $3.61 and $5.04, respectively. 

(3) Estimated crude oil prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $97.75, 

$90.70, $92.50 and $102.86, respectively. Estimated NGLs prices used to calculate 2011 future cash inflows for the United States and Canada were 

$51.77 and $46.97, respectively. Estimated natural gas prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and 

Other International were $4.03, $3.28, $3.37, and $5.07, respectively. 

(4) Estimated crude oil prices used to calculate 2010 future cash inflows for the United States, Canada, Trinidad and Other International were $76.38, 

$72.59, $69.56 and $73.88, respectively. Estimated NGLs prices used to calculate 2010 future cash inflows for the United States and Canada were 

$43.85 and $26.56, respectively. Estimated natural gas prices used to calculate 2010 future cash inflows for the United States, Canada, Trinidad and 

Other International were $4.36, $3.67, $2.94 and $5.02, respectively. 
F-45

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the 

changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the 

period ended December 31, 2012:

United Other

States Canada Trinidad International Total

December 31, 2009 $ 5,822,916 $ 1,037,244 $ 665,563 $ 15,295 $ 7,541,018

Sales and transfers of oil and gas 

produced, net of production 

costs (2,792,005) (292,857) (395,379) (17,720) (3,497,961)

Net changes in prices and 

production costs 2,468,907 (559) 721,796 7,259 3,197,403

Extensions, discoveries, additions 

and improved recovery, net of 

related costs 4,319,659 75,162 183,453 - 4,578,274

Development costs incurred 864,700 175,100 67,300 - 1,107,100

Revisions of estimated 

development cost (257,360) 260,290 (767) 9 2,172

Revisions of previous quantity

estimates (164,748) (38,382) (175,002) 4,006 (374,126)

Accretion of discount 755,001 102,022 101,549 1,778 960,350

Net change in income taxes (1,171,384) 101,966 (258,354) 2,469 (1,325,303)

Purchases of reserves in place 265 - - - 265

Sales of reserves in place (54,057) (290,592) - - (344,649)

Changes in timing and other 837,030 (383,159) 78,707 14,703 547,281

December 31, 2010 10,628,924 746,235 988,866 27,799 12,391,824

Sales and transfers of oil and gas 

produced, net of production 

costs (4,296,926) (278,910) (504,205) (15,614) (5,095,655)

Net changes in prices and 

production costs 716,682 (57,545) 331,196 3,328 993,661

Extensions, discoveries, additions 

and improved recovery, net of 

related costs 6,223,552 22,591 102,548 - 6,348,691

Development costs incurred 1,422,500 48,200 74,800 - 1,545,500

Revisions of estimated 

development cost (210,919) 64,001 (14,074) 2 (160,990)

Revisions of previous quantity

estimates (482,496) (70,718) (56,884) 801 (609,297)

Accretion of discount 1,352,740 62,725 159,715 2,782 1,577,962

Net change in income taxes (1,049,641) (118,988) 9,511 13 (1,159,105)

Purchases of reserves in place 5,241 - - - 5,241

Sales of reserves in place (658,468) - - - (658,468)

Changes in timing and other 724,465 218,756 92,734 9,962 1,045,917

December 31, 2011 14,375,654 636,347 1,184,207 29,073 16,225,281

Sales and transfers of oil and gas 

produced, net of production 

costs (5,192,392) (159,577) (526,134) (10,214) (5,888,317)

Net changes in prices and 

production costs (393,585) (67,964) 162,600 (2,283) (301,232)

Extensions, discoveries, additions 

and improved recovery, net of 

related costs 5,517,945 79,529 - 484,648 6,082,122

Development costs incurred 2,042,300 23,600 23,500 5,200 2,094,600

Revisions of estimated 

development cost 1,987,330 383,215 (28,835) (234) 2,341,476

Revisions of previous quantity

estimates (3,286,943) (396,408) (62,285) 2,809 (3,742,827)

Accretion of discount 1,832,377 63,635 178,298 2,907 2,077,217

Net change in income taxes 174,418 - 88,853 (138,206) 125,065

Purchases of reserves in place 64,317 - - 5,623 69,940

Sales of reserves in place (869,534) (44,227) - - (913,761)

Changes in timing and other (1,070,553) (119,001) (59,134) (5,404) (1,254,092)

December 31, 2012 $ 15,181,334 $ 399,149 $ 961,070 $ 373,919 $ 16,915,472
F-46

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

Unaudited Quarterly Financial Information

(In Thousands, Except Per Share Data)

Quarter Ended Mar 31 Jun 30 Sep 30 Dec 31

2012

Net Operating Revenues $ 2,806,651 $ 2,909,319 $ 2,954,855 $ 3,011,811

Operating Income (Loss) $ 559,772 $ 692,339 $ 605,747 $ (378,061)

Income (Loss) Before Income Taxes $ 520,134 $ 646,239 $ 560,189 $ (445,822)

Income Tax Provision 196,125 250,461 204,698 59,177

Net Income (Loss) (1) $ 324,009 $ 395,778 $ 355,491 $ (504,999)

Net Income (Loss) Per Share (2)

Basic $ 1.22 $ 1.48 $ 1.33 $ (1.88)

Diluted $ 1.20 $ 1.47 $ 1.31 $ (1.88)

Average Number of Common Shares

Basic 266,674 266,874 267,941 268,941

Diluted 270,242 269,985 270,982 268,941

2011

Net Operating Revenues $ 1,897,106 $ 2,570,250 $ 2,885,744 $ 2,773,015

Operating Income $ 272,451 $ 588,253 $ 950,030 $ 302,575

Income Before Income Taxes $ 225,722 $ 543,224 $ 899,221 $ 241,632

Income Tax Provision 91,749 247,650 358,343 120,934

Net Income $ 133,973 $ 295,574 $ 540,878 $ 120,698

Net Income Per Share (1)

Basic $ 0.52 $ 1.11 $ 2.03 $ 0.45

Diluted $ 0.52 $ 1.10 $ 2.01 $ 0.45

Average Number of Common Shares

Basic 255,200 265,830 266,053 266,277

Diluted 258,819 269,332 269,292 269,524

(1) Fourth quarter 2012 results include the impact of pretax impairments of $1,020 million, primarily related to proved and unproved 

natural gas properties in Canada and the United States as well as an additional income tax provision of $135 million related to 

valuation allowances recorded to reduce the value of Canadian deferred tax assets.

(2) The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly 

computation is based on the weighted average of common shares outstanding.
E-1

EXHIBITS

Exhibits not incorporated herein by reference to a prior filing are designated by (i) an asterisk (*) and are filed herewith; 

or (ii) a pound sign (#) and are not filed herewith, and, pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, the registrant hereby 

agrees to furnish a copy of such exhibit to the United States Securities and Exchange Commission (SEC) upon request. 

Exhibit

Number Description

3.1(a) - Restated Certificate of Incorporation, dated September 3, 1987 (Exhibit 3.1(a) to EOG's Annual Report on 

Form 10-K for the year ended December 31, 2008).

3.1(b) - Certificate of Amendment of Restated Certificate of Incorporation, dated May 5, 1993 (Exhibit 4.1(b) to 

EOG's Registration Statement on Form S-8, SEC File No. 33-52201, filed February 8, 1994).

3.1(c) - Certificate of Amendment of Restated Certificate of Incorporation, dated June 14, 1994 (Exhibit 4.1(c) to 

EOG's Registration Statement on Form S-8, SEC File No. 33-58103, filed March 15, 1995).

3.1(d) - Certificate of Amendment of Restated Certificate of Incorporation, dated June 11, 1996 (Exhibit 3(d) to

EOG's Registration Statement on Form S-3, SEC File No. 333-09919, filed August 9, 1996).

3.1(e) - Certificate of Amendment of Restated Certificate of Incorporation, dated May 7, 1997 (Exhibit 3(e) to 

EOG's Registration Statement on Form S-3, SEC File No. 333-44785, filed January 23, 1998).

3.1(f) - Certificate of Ownership and Merger Merging EOG Resources, Inc. into Enron Oil & Gas Company, dated 

August 26, 1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for the year ended December 31,

1999) (SEC File No. 001-09743).

3.1(g) - Certificate of Designations of Series E Junior Participating Preferred Stock, dated February 14, 2000 

(Exhibit 2 to EOG's Registration Statement on Form 8-A, SEC File No. 001-09743, filed February 18, 

2000).

3.1(h) - Certificate of Elimination of the Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, dated 

September 13, 2000 (Exhibit 3.1(j) to EOG's Registration Statement on Form S-3, SEC File No. 333-46858, 

filed September 28, 2000).

3.1(i) - Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series C, dated 

September 13, 2000 (Exhibit 3.1(k) to EOG's Registration Statement on Form S-3, SEC File No. 333-

46858, filed September 28, 2000).

3.1(j) - Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series D, dated 

February 24, 2005 (Exhibit 3.1(k) to EOG's Annual Report on Form 10-K for the year ended December 31, 

2004) (SEC File No. 001-09743).

3.1(k) - Amended Certificate of Designations of Series E Junior Participating Preferred Stock, dated March 7, 2005 

(Exhibit 3.1(m) to EOG's Annual Report on Form 10-K for the year ended December 31, 2007) (SEC File 

No. 001-09743).

3.1(l) - Certificate of Amendment of Restated Certificate of Incorporation, dated May 3, 2005 (Exhibit 3.1(l) to 

EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005) (SEC File No. 001-09743).

3.1(m) - Certificate of Elimination of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated 

March 6, 2008 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed March 6, 2008).

3.2 - Bylaws, as amended and restated effective as of February 26, 2009 (Exhibit 3.2(a) to EOG's Current Report 

on Form 8-K, filed March 4, 2009).
E-2

Exhibit

Number Description

4.1 - Specimen of Certificate evidencing EOG's Common Stock (Exhibit 3.3 to EOG's Annual Report on Form 

10-K for the year ended December 31, 1999) (SEC File No. 001-09743).

4.2 - Indenture, dated as of September 1, 1991, between Enron Oil & Gas Company (predecessor to EOG) and 

The Bank of New York Mellon Trust Company, N.A. (as successor in interest to JPMorgan Chase Bank, 

N.A. (formerly, Texas Commerce Bank National Association)), as Trustee (Exhibit 4(a) to EOG's 

Registration Statement on Form S-3, SEC File No. 33-42640, filed September 6, 1991).

4.3(a) - Officers' Certificate Establishing 6.125% Senior Notes due 2013 and 6.875% Senior Notes due 2018, 

dated September 30, 2008 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed September 30, 

2008). 

4.3(b) - Form of Global Note with respect to the 6.125% Senior Notes due 2013 of EOG (Exhibit 4.3 to EOG's 

Current Report on Form 8-K, filed September 30, 2008). 

4.3(c) - Form of Global Note with respect to the 6.875% Senior Notes due 2018 of EOG (Exhibit 4.4 to EOG's 

Current Report on Form 8-K, filed September 30, 2008). 

4.4(a) - Officers' Certificate Establishing 5.875% Senior Notes due 2017 of EOG, dated September 10, 2007 

(Exhibit 4.2 to EOG's Current Report on Form 8-K, filed September 10, 2007) (SEC File No. 001-09743).

4.4(b) - Form of Global Note with respect to the 5.875% Senior Notes due 2017 of EOG (Exhibit 4.3 to EOG's 

Current Report on Form 8-K, filed September 10, 2007) (SEC File No. 001-09743).

#4.5(a) - Certificate, dated April 3, 1998, of the Senior Vice President and Chief Financial Officer of Enron Oil & 

Gas Company (predecessor to EOG) establishing the terms of the 6.65% Notes due April 1, 2028.

#4.5(b) - Global Note with respect to the 6.65% Notes due April 1, 2028 of Enron Oil & Gas Company (predecessor 

to EOG).

#4.6 - Indenture, dated as of March 1, 2004, between EOG Resources Canada Inc., as Issuer, and The Bank of 

New York Trust Company, N.A., as Trustee, with respect to the 4.75% Senior Notes due 2014 of EOG 

Resources Canada Inc.

4.7 - Indenture, dated as of May 18, 2009, between EOG and Wells Fargo Bank, NA, as Trustee (Exhibit 4.9 to 

EOG's Registration Statement on Form S-3, SEC File No. 333-159301, filed May 18, 2009).

4.8(a) - Officers' Certificate Establishing 5.625% Senior Notes due 2019 of EOG, dated May 21, 2009 (Exhibit 4.2 

to EOG's Current Report on Form 8-K, filed May 21, 2009).

4.8(b) - Form of Global Note with respect to the 5.625% Senior Notes due 2019 of EOG (Exhibit 4.3 to EOG's 

Current Report on Form 8-K, filed May 21, 2009).

4.9(a) - Officers' Certificate Establishing 2.95% Senior Notes due 2015 and 4.40% Senior Notes due 2020, dated 

May 20, 2010 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed May 26, 2010).
E-3

Exhibit

Number Description

4.9(b) - Form of Global Note with respect to the 2.95% Senior Notes due 2015 of EOG (Exhibit 4.3 to EOG's 

Current Report on Form 8-K, filed May 26, 2010).

4.9(c) - Form of Global Note with respect to the 4.40% Senior Notes due 2020 of EOG (Exhibit 4.4 to EOG's 

Current Report on Form 8-K, filed May 26, 2010).

4.10(a) - Officers' Certificate Establishing 2.500% Senior Notes due 2016, 4.100% Senior Notes due 2021 and 

Floating Rate Senior Notes due 2014, dated November 23, 2010 (Exhibit 4.2 to EOG's Current Report on 

Form 8-K, filed November 24, 2010).

4.10(b) - Form of Global Note with respect to the 2.500% Senior Notes due 2016 of EOG (Exhibit 4.3 to EOG's 

Current Report on Form 8-K, filed November 24, 2010).

4.10(c) - Form of Global Note with respect to the 4.100% Senior Notes due 2021 of EOG (Exhibit 4.4 to EOG's 

Current Report on Form 8-K, filed November 24, 2010).

4.10(d) - Form of Global Note with respect to the Floating Rate Senior Notes due 2014 of EOG (Exhibit 4.5 to 

EOG's Current Report on Form 8-K, filed November 24, 2010).

4.11(a) - Officers’ Certificate Establishing 2.625% Senior Notes due 2023, dated September 10, 2012 (Exhibit 4.2 

to EOG's Current Report on Form 8-K, filed September 11, 2012).

4.11(b) - Form of Global Note with respect to the 2.625% Senior Notes due 2023 of EOG (Exhibit 4.3 to EOG's 

Current Report on Form 8-K, filed September 11, 2012).

10.1(a)+ - EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, effective as of May 8, 2008 (Exhibit 

10.1 to EOG's Current Report on Form 8-K, filed May 14, 2008). 

10.1(b)+ - First Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as 

of September 4, 2008 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended 

September 30, 2008).

10.1(c)+ - Second Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as 

of January 1, 2010 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 

31, 2010).

10.1(d) + - Third Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as of 

September 26, 2012 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended 

September 30, 2012).

10.1(e)+ - Form of Stock Option Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan 

(effective for grants made prior to February 23, 2011) (Exhibit 10.2 to EOG's Current Report on Form 8-

K, filed May 14, 2008). 

10.1(f)+ - Form of Stock Option Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan 

(effective for grants made on or after February 23, 2011) (Exhibit 10.3 to EOG's Quarterly Report on Form 

10-Q for the quarter ended March 31, 2011).

10.1(g)+ - Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus 

Equity Compensation Plan (effective for grants made prior to February 23, 2011) (Exhibit 10.3 to EOG's 

Current Report on Form 8-K, filed May 14, 2008). 

10.1(h)+ - Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity 

Compensation Plan (effective for grants made on or after February 23, 2011) (Exhibit 10.4 to EOG's 

Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).
E-4

Exhibit

Number Description

10.1(i) - Form of Nonemployee Director Stock-Settled Stock Appreciation Right Agreement for EOG Resources, 

Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed 

May 14, 2008). 

10.1(j)+ - Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity 

Compensation Plan (Exhibit 10.5 to EOG's Current Report on Form 8-K, filed May 14, 2008). 

10.1(k)+ - Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity 

Compensation Plan (Exhibit 10.6 to EOG's Current Report on Form 8-K, filed May 14, 2008). 

10.1(l) - Form of Nonemployee Director Restricted Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus 

Equity Compensation Plan (Exhibit 10.7 to EOG's Current Report on Form 8-K, filed May 14, 2008). 

10.1(m) - Form of Nonemployee Director Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2008 

Omnibus Equity Compensation Plan (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter 

ended June 30, 2012).

10.1(n)+ - Form of Performance Unit Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation 

Plan (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed October 1, 2012).

10.1(o)+ - Form of Performance Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity 

Compensation Plan (Exhibit 10.5 to EOG's Current Report on Form 8-K, filed October 1, 2012).

10.2(a)+ - EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred 

Compensation Plan - Plan Document, effective as of December 16, 2008 (Exhibit 10.2(a) to EOG's Annual 

Report on Form 10-K for the year ended December 31, 2008).

10.2(b)+ - EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred 

Compensation Plan - Adoption Agreement, originally dated as of December 16, 2008 (and as amended 

through February 24, 2012 (including an amendment to Item 7 thereof, effective January 1, 2012, with 

respect to the deferral of restricted stock units)) (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for 

the year ended December 31, 2011) (originally filed as Exhibit 10.2(b) to EOG's Annual Report on Form 

10-K for the year ended December 31, 2008).

10.2(c)+ - Amended and Restated 1996 Deferral Plan (Exhibit 4.4 to EOG’s Registration Statement on Form S-8, 

SEC File No. 333-84014, filed March 8, 2002).

10.2(d)+ - First Amendment to Amended and Restated 1996 Deferral Plan, effective as of September 10, 2002 

(Exhibit 10.9(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 2002) (SEC 

File No. 001-09743).

10.3(a)+ - Amended and Restated Enron Oil & Gas Company 1994 Stock Plan (Exhibit 4.3 to EOG's Registration 

Statement on Form S-8, SEC File No. 33-58103, filed March 15, 1995). 

10.3(b)+ - Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of 

December 12, 1995 (Exhibit 4.3(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 

1995) (SEC File No. 001-09743).

10.3(c)+ - Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of 

December 10, 1996 (Exhibit 4.3(a) to EOG's Registration Statement on Form S-8, SEC File No. 333-20841, 

filed January 31, 1997).

10.3(d)+ - Third Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as 

of December 9, 1997 (Exhibit 4.3(d) to EOG's Annual Report on Form 10-K for the year ended 

December 31, 1997) (SEC File No. 001-09743).
E-5

Exhibit

Number Description

10.3(e)+ - Fourth Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective 

as of May 5, 1998 (Exhibit 4.3(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 

1998) (SEC File No. 001-09743).

10.3(f)+ - Fifth Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as 

of December 8, 1998 (Exhibit 4.3(f) to EOG's Annual Report on Form 10-K for the year ended 

December 31, 1998) (SEC File No. 001-09743).

10.3(g)+ - Sixth Amendment to Amended and Restated EOG Resources, Inc. 1994 Stock Plan, dated effective as of 

May 8, 2001 (Exhibit 10.1(g) to EOG's Annual Report on Form 10-K for the year ended December 31, 

2001) (SEC File No. 001-09743).

10.3(h)+ - Seventh Amendment to Amended and Restated EOG Resources, Inc. 1994 Stock Plan, dated effective as of 

December 30, 2005 (Exhibit 10.1(h) to EOG's Annual Report on Form 10-K for the year ended December 

31, 2005) (SEC File No. 001-09743).

10.4(a) - EOG Resources, Inc. 1993 Nonemployee Directors Stock Option Plan, as amended and restated effective 

May 7, 2002 (Exhibit A to EOG's Proxy Statement, filed March 28, 2002, with respect to EOG's 2002 

Annual Meeting of Stockholders) (SEC File No. 001-09743).

10.4(b) - First Amendment to EOG Resources, Inc. 1993 Nonemployee Directors Stock Option Plan, dated effective 

as of December 30, 2005 (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended 

December 31, 2005) (SEC File No. 001-09743).

10.5(a)+ - EOG Resources, Inc. 1992 Stock Plan, as amended and restated effective May 4, 2004 (Exhibit B to EOG's 

Proxy Statement, filed March 29, 2004, with respect to EOG's 2004 Annual Meeting of Stockholders) (SEC 

File No. 001-09743).

10.5(b)+ - First Amendment to EOG Resources, Inc. 1992 Stock Plan, dated effective as of December 30, 2005 

(Exhibit 10.3(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2005) (SEC File 

No. 001-09743).

10.6(a)+ - Executive Employment Agreement between EOG and Mark G. Papa, effective as of June 15, 2005 (Exhibit 

99.1 to EOG's Current Report on Form 8-K filed, June 21, 2005) (SEC File No. 001-09743).

10.6(b)+ - First Amendment to Executive Employment Agreement between EOG and Mark G. Papa, effective as of 

March 16, 2009 (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed March 18, 2009).

10.6(c) + - Agreement, dated as of February 21, 2012, by and between EOG and Mark G. Papa (Exhibit 10.1 to EOG's 

Current Report on Form 8-K, filed February 27, 2012).

10.6(d)+ - Amended and Restated Change of Control Agreement between EOG and Mark G. Papa, effective as of June 

15, 2005 (Exhibit 99.6 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-

09743).

10.6(e)+ - First Amendment to Amended and Restated Change of Control Agreement between EOG and Mark G. 

Papa, effective as of April 30, 2009 (Exhibit 10.1(b) to EOG's Quarterly Report on Form 10-Q for the 

quarter ended March 31, 2009).

10.6(f)+ - Second Amendment to Amended and Restated Change of Control Agreement between EOG and Mark G. 

Papa, effective as of September 13, 2011 (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed 

September 13, 2011).

10.7(a)+ - Executive Employment Agreement between EOG and William R. Thomas, effective as of February 1, 2011 

(Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).
E-6

Exhibit

Number Description

10.7(b)+ - Agreement, dated as of February 21, 2012, by and between EOG and William R. Thomas (Exhibit 10.2 to 

EOG's Current Report on Form 8-K, filed February 27, 2012).

10.7(c)+ - Change of Control Agreement between EOG and William R. Thomas, effective as of January 12, 2011 

(Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).

10.7(d)+ - First Amendment to Change of Control Agreement between EOG and William R. Thomas, effective as of 

September 13, 2011 (Exhibit 10.2 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.8(a)+ - Executive Employment Agreement between EOG and Gary L. Thomas, effective as of June 15, 2005 

(Exhibit 99.4 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).

10.8(b)+ - First Amendment to Executive Employment Agreement between EOG and Gary L. Thomas, effective as of 

March 16, 2009 (Exhibit 10.3 to EOG's Current Report on Form 8-K, filed March 18, 2009).

10.8(c)+ - Agreement, dated as of February 21, 2012, by and between EOG and Gary L. Thomas (Exhibit 10.3 to 

EOG's Current Report on Form 8-K, filed February 27, 2012).

10.8(d)+ - Amended and Restated Change of Control Agreement between EOG and Gary L. Thomas, effective as of 

June 15, 2005 (Exhibit 99.9 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-

09743).

10.8(e)+ - First Amendment to Amended and Restated Change of Control Agreement between EOG and Gary L. 

Thomas, effective as of April 30, 2009 (Exhibit 10.3(b) to EOG's Quarterly Report on Form 10-Q for the 

quarter ended March 31, 2009).

10.8(f)+ - Second Amendment to Amended and Restated Change of Control Agreement between EOG and Gary L. 

Thomas, effective as of September 13, 2011 (Exhibit 10.3 to EOG's Current Report on Form 8-K, filed 

September 13, 2011).

10.9(a)+ - Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as 

of June 15, 2005 (Exhibit 99.11 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 

001-09743).

10.9(b)+ - First Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. 

Driggers, effective as of April 30, 2009 (Exhibit 10.5 to EOG's Quarterly Report on Form 10-Q for the 

quarter ended March 31, 2009).

10.9(c)+ - Second Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy 

K. Driggers, effective as of September 13, 2011 (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed 

September 13, 2011).

10.10(a)+ - Executive Employment Agreement between EOG and Frederick J. Plaeger, II, effective as of April 23, 2007 

(Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007) (SEC File 

No. 001-09743).

10.10(b)+ - First Amendment to Executive Employment Agreement between EOG and Frederick J. Plaeger, II, effective 

as of April 30, 2009 (Exhibit 10.4(a) to EOG's Quarterly Report on Form 10-Q for the quarter ended March 

31, 2009).

10.10(c) + - Agreement, dated as of February 21, 2012, by and between EOG and Frederick J. Plaeger, II (Exhibit 10.4 

to EOG's Current Report on Form 8-K, filed February 27, 2012).
E-7

Exhibit

Number Description

10.10(d)+ - Change of Control Agreement between EOG and Frederick J. Plaeger, II, effective as of April 23, 2007 

(Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007) (SEC File 

No. 001-09743).

10.10(e)+ - First Amendment to Change of Control Agreement between EOG and Frederick J. Plaeger, II, effective as of 

April 30, 2009 (Exhibit 10.4(b) to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 

2009).

10.10(f)+ - Second Amendment to Change of Control Agreement between EOG and Frederick J. Plaeger, II, effective 

as of September 13, 2011 (Exhibit 10.5 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.10(g)+ - Agreement, dated as of May 3, 2012, by and between EOG and Frederick J. Plaeger, II (Exhibit 10.2 to 

EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012).

10.11+ - Change of Control Agreement by and between EOG and Michael P. Donaldson, effective as of May 3, 2012 

(Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012).

10.12(a)+ - EOG Resources, Inc. Change of Control Severance Plan, as amended and restated effective as of June 15, 

2005 (Exhibit 99.12 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).

10.12(b)+ - First Amendment to the EOG Resources, Inc. Change of Control Severance Plan, effective as of April 

30, 2009 (Exhibit 10.6 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).

10.13+ - EOG Resources, Inc. Amended and Restated Executive Officer Annual Bonus Plan (Exhibit 10.4 to EOG's 

Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).

10.14(a)+ - EOG Resources, Inc. Employee Stock Purchase Plan (Exhibit 4.4 to EOG’s Registration Statement on Form 

S-8, SEC File No. 333-62256, filed June 4, 2001).

10.14(b)+ - Amendment to EOG Resources, Inc. Employee Stock Purchase Plan, dated effective as of January 1, 2010 

(Exhibit 4.3(b) to EOG’s Registration Statement on Form S-8, SEC File No. 333-166518, filed May 4, 

2010).

10.15 - Revolving Credit Agreement, dated as of October 11, 2011, among EOG, JPMorgan Chase Bank, N.A., as 

Administrative Agent, the financial institutions as bank parties thereto, and the other parties thereto (Exhibit 

10.1 to EOG's Current Report on Form 8-K, filed October 12, 2011).

* 12 - Computation of Ratio of Earnings to Fixed Charges and to Combined Fixed Charges and Preferred Stock 

Dividends. 

* 21 - Subsidiaries of EOG, as of December 31, 2012.

* 23.1 - Consent of DeGolyer and MacNaughton.

* 23.2 - Opinion of DeGolyer and MacNaughton dated January 29, 2013.

* 23.3 - Consent of Deloitte & Touche LLP.

* 24 - Powers of Attorney. 
E-8

Exhibit

Number Description

* 31.1 - Section 302 Certification of Annual Report of Principal Executive Officer.

* 31.2 - Section 302 Certification of Annual Report of Principal Financial Officer.

* 32.1 - Section 906 Certification of Annual Report of Principal Executive Officer.

* 32.2 - Section 906 Certification of Annual Report of Principal Financial Officer.

* 95 - Mine Safety Disclosure Exhibit.

* **101.INS - XBRL Instance Document.

* **101.SCH - XBRL Schema Document.

* **101.CAL - XBRL Calculation Linkbase Document.

* **101.LAB - XBRL Label Linkbase Document.

* **101.PRE - XBRL Presentation Linkbase Document.

* **101.DEF - XBRL Definition Linkbase Document.

*Exhibits filed herewith

**Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting 

Language): (i) the Consolidated Statements of Income and Comprehensive Income for Each of the Three Years in the Period 

Ended December 31, 2012, (ii) the Consolidated Balance Sheets - December 31, 2012 and 2011, (iii) the Consolidated 

Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2012, (iv) the Consolidated 

Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2012 and (v) Notes to Consolidated 

Financial Statements. 

+ Management contract, compensatory plan or arrangement
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant 

has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

EOG RESOURCES, INC.

(Registrant)

Date: February 21, 2013 By: /s/ TIMOTHY K. DRIGGERS

Timothy K. Driggers

Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized 

Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by 

the following persons on behalf of the registrant and in the capacities with EOG Resources, Inc. indicated and on the 21st day of 

February, 2013.

Signature Title

/s/ MARK G. PAPA Chairman of the Board and Chief Executive Officer and

(Mark G. Papa) Director (Principal Executive Officer)

/s/ TIMOTHY K. DRIGGERS Vice President and Chief Financial Officer

(Timothy K. Driggers) (Principal Financial Officer)

/s/ ANN D. JANSSEN Vice President, Accounting

(Ann D. Janssen) (Principal Accounting Officer)

* Director

(George A. Alcorn)

* Director

(Charles R. Crisp)

* Director

(James C. Day)

* Director

(H. Leighton Steward)

* Director

(Donald F. Textor)

* Director

(Frank G. Wisner)

*By: /s/ MICHAEL P. DONALDSON

(Michael P. Donaldson)

(Attorney-in-fact for persons indicated)