10-K 1 eogform10-k.htm EOG FORM 10-K

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

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

For the fiscal year ended December 31, 2012

or

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

Commission file number: 1-9743

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

Delaware
 
47-0684736
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2, Houston, Texas   77002
(Address of principal executive offices)    (Zip Code)
 
Registrant's telephone number, including area code:  713-651-7000

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

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

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

None.

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

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

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

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

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

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

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

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

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
 
(i)

 

PART I

ITEM 1.  Business

General

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

At December 31, 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.

1



Exploration and Production

  United States and Canada Operations

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

At December 31, 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.
2



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.  EOG-owned 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.

3



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.

4



  Operations Outside the United States and Canada

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

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

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

Several fields in the SECC Block, Modified U(a) Block 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.

5



In 2007, EOGUK was awarded a license for two blocks in the East Irish Sea – Blocks 110/7b and 110/12a.  In 2009, EOGUK drilled a successful exploratory well in 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.

6



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.

7



Wellhead Volumes and Prices

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

8




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.


9



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.

10



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.

11



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.

12



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.

13



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 third-party insurers for bodily injury or death claims resulting from an incident involving EOG's onshore or offshore operations (subject to policy terms and conditions).  Moreover, in the event an incident with respect to EOG's onshore or offshore operations results in negative environmental effects, EOG maintains operators extra expense coverage provided by third-party insurers for obligations, expenses or claims that EOG may incur from such an incident, including obligations, expenses or claims in respect of seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions).  In the specific event of a well blowout or out-of-control well resulting in negative environmental effects, such operators extra expense coverage would be EOG's primary coverage, with the commercial general liability and excess liability coverage referenced above also providing certain coverage to EOG.  All of EOG's onshore and offshore drilling activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors.  The indemnification and other risk allocation provisions included in such contracts are negotiated on a contract-by-contract basis and are each based on the particular circumstances of the services being provided and the anticipated operations.
In addition to the above-described risks, EOG's operations outside the United States are subject to certain risks, including the risk of increases in taxes and governmental royalties, changes in laws and policies governing the operations of foreign-based companies, expropriation of assets, unilateral or forced renegotiation or modification of existing contracts with governmental entities, currency restrictions and exchange rate fluctuations.  Please refer to ITEM 1A. Risk Factors for further discussion of the risks to which EOG is subject with respect to its operations outside the United States.

14



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.

15



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;
16



·
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 third-party operators in each case due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations.  For related discussion of the risks and potential losses and liabilities inherent in our crude oil and natural gas operations generally, see the immediately following risk factor.

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

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

·
well blowouts and cratering;
·
loss of well control;
·
crude oil spills, natural gas leaks and pipeline ruptures;
·
pipe failures and casing collapses;
·
        uncontrollable flows of crude oil, natural gas, formation water or drilling fluids;
·
releases of chemicals or other hazardous substances;
·
        adverse weather conditions, such as winter storms, flooding and hurricanes, and other natural disasters;
·
fires and explosions;
·
        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.

17



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.

18



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.
19



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.

20



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.

21



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 (End-User 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.

22



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.

23



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.

24



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


25



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


26



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.


27



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.

28



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.

29



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

30



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 Long-Term 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
 

31



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.

32



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.

33



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.

34



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.

35



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.

36



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.

37



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.

38



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, crude-by-rail assets, sand mine and sand processing assets, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

DD&A expenses in 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).

39



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.

40



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&A-
 
 
 
 
 
Oil 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).

41



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).

42



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.

43



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
 
Volume (1)
(Bbld)
 
Weighted
Average Price
($/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.
44



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.

45



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.

46



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.

47



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.

48



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.

49



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;
50

·
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.


51



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.

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.

52



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.

53



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
Reflected in Column (a))
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Plan Category
 
 
 
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).
 
 

54



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.


55



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-1




MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING


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

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

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

EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 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-2



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Stockholders of
EOG Resources, Inc.
Houston, Texas

We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. and subsidiaries (the "Company") as of December 31, 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-3



In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EOG Resources, Inc. and subsidiaries as of December 31, 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-4



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-5



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-6



EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In Thousands, Except Per Share Data)


 
 
 
Accumulated
 
Common
 
 
 
Additional
Other
 
Stock
Total
 
Common
Paid In
Comprehensive
Retained