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Article by DailyStocks_admin    (12-30-13 12:02 AM)

Description

EOG RESOURCES INC. Director DONALD F TEXTOR bought 6,000 shares on 12-20-2013 at $ 168.61

BUSINESS OVERVIEW

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.

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.

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.

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.

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.

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.

CEO BACKGROUND

At the Annual Meeting, seven directors are to be elected to hold office until the 2014 annual meeting of stockholders and until their respective successors are duly elected and qualified. All of the nominees, except for Mr. W. Thomas (EOG’s President), are our current directors. Pursuant to our Corporate Governance Guidelines, Mr. Alcorn, having attained the age of 80, will not stand for re-election as a director at the Annual Meeting; his current term will expire in conjunction with the Annual Meeting.

We believe that each of our director nominees possesses high standards of personal and professional ethics, character, integrity and values; an inquisitive and objective perspective; practical wisdom; mature judgment; diversity in professional experience, skills and background; a proven record of success in their respective fields; and valuable knowledge of our business and of the oil and gas industry. Moreover, each of our director nominees is willing to devote sufficient time to carrying out his duties and responsibilities effectively and is committed to serving EOG and our stockholders. Set forth below is a brief description of the specific experiences, qualifications and skills attributable to each of our director nominees that led the Board, as of the date of this proxy statement, to its conclusion that the nominee should serve as a director of EOG and, in the case of Messrs. Crisp, Day, Steward, Textor and Wisner, as a member of the Board’s Audit, Compensation and Nominating and Governance Committees. Director nominee ages set forth below are as of February 28, 2013.
A majority of the votes cast in person or by proxy by the holders of our Common Stock entitled to vote at the Annual Meeting is required to elect a nominee. Under our bylaws, (1) a “majority of the votes cast” means that the number of shares voted “FOR” a nominee’s election exceeds 50% of the number of votes cast with respect to that nominee’s election and (2) votes cast shall include votes to “withhold authority” (shown as “AGAINST” on the enclosed form of proxy) and exclude abstentions with respect to that nominee’s election. Therefore, abstentions and broker non-votes (which occur if a broker or other nominee does not have discretionary authority and has not received instructions with respect to a particular director nominee within ten days of the Annual Meeting) will not be counted in determining the number of votes cast with respect to that nominee’s election.

Pursuant to our Corporate Governance Guidelines, any nominee for director who fails to receive a majority vote of our stockholders at the Annual Meeting must promptly, following certification of the stockholder vote, tender his or her resignation to the Nominating and Governance Committee of the Board. The Nominating and Governance Committee (excluding the nominee who tendered the resignation) will evaluate the resignation and make a recommendation to the Board, who will then act on the tendered resignation and publicly disclose its decision and rationale within 90 days following certification of the stockholder vote.

Properly executed proxies will be voted at the Annual Meeting in accordance with the instructions specified on the proxy; if no such instructions are given, the persons named as agents and proxies in the enclosed form of proxy will vote such proxy “FOR” the election of the nominees named herein. Should any nominee become unavailable for election, discretionary authority is conferred to the persons named as agents and proxies in the enclosed form of proxy to vote for a substitute.

Pursuant to our bylaws, the Board has set the number of directors that shall constitute the Board at seven. Proxies cannot be voted for a greater number of persons than the number of nominees named on the enclosed form of proxy, and stockholders may not cumulate their votes in the election of directors.

THE BOARD OF DIRECTORS RECOMMENDS VOTING “FOR” EACH OF THE NOMINEES LISTED BELOW.

CHARLES R. CRISP, 65
Director since 2002

Mr. Crisp began his career in the oil and gas industry over 40 years ago with Conoco Inc. and has held senior management positions with numerous energy companies, including (i) Coral Energy, LLC, a subsidiary of Shell Oil Company, where he served as President and Chief Executive Officer from 1999 until his retirement in November 2000 and as President and Chief Operating Officer from 1998 to 1999; (ii) Houston Industries Incorporated, where he served as President of the power generation group from 1996 to 1998; and (iii) Tejas Gas Corporation, a major intrastate natural gas pipeline company, where he served as President, Chief Operating Officer and a director from 1988 to 1996.

Mr. Crisp has also accumulated over 10 years of experience as a director of publicly traded energy companies. Mr. Crisp is currently a director of three other public companies: (i) AGL Resources Inc. (since 2003), a natural gas distribution and marketing and energy services company, where he currently serves on the Compensation and Management Development Committee and Finance and Risk Management Committee; (ii) IntercontinentalExchange, Inc. (since 2002), an operator of regulated exchanges, trading platforms and clearing houses, where he currently serves on the Compensation and Audit Committees; and (iii) Targa Resources Corp. (since 2005), a provider of midstream natural gas and natural gas liquids services, where he currently serves on the Compensation Committee, Audit Committee and Conflicts Committee. Mr. Crisp also serves as director of ICE Futures U.S., Inc. and Climate Exchange Plc, each a subsidiary of IntercontinentalExchange, Inc.


JAMES C. DAY, 69
Director since 2008

Mr. Day has extensive leadership experience serving as a member of senior management in various roles at Noble Corporation, including as Chairman of the Board from 1992 until his retirement in May 2007, Chief Executive Officer from 1984 until October 2006 and President from 1984 to 1999 and again from 2003 until February 2006. Noble Corporation is a publicly traded company and one of the world’s largest offshore drilling companies.

Mr. Day is also a director of Tidewater Inc. (since 2007), a publicly traded provider of large offshore service vessels to the energy sector worldwide, where he serves on the Audit and Nominating and Corporate Governance Committees, and of ONEOK, Inc. (since 2004), the publicly traded general partner of ONEOK Partners, L.P., a provider of natural gas gathering, processing, storage and transportation services, where he serves as a member of the Audit Committee and Corporate Governance Committee. From 1993 to May 2006, Mr. Day served as a director of Global Industries, Ltd., a publicly traded provider of offshore marine construction services and Noble Energy, Inc., a worldwide independent energy company. He served as a member of various committees, including compensation, audit and nomination.

Mr. Day is past chairman of the International Association of Drilling Contractors and the National Ocean Industries Association, and is an honorary director of the American Petroleum Institute, Trustee of The Samuel Roberts Noble Foundation and President of the James C. and Teresa K. Day Foundation. Mr. Day has held numerous other leadership positions with various industry and civic associations throughout his career.

MARK G. PAPA, 66
Director since 1998

Mr. Papa has served as EOG’s Chairman of the Board and CEO for over 13 years, and has been with EOG and its predecessor companies for over 31 years. Prior to becoming EOG’s Chairman of the Board and CEO, Mr. Papa served in other leadership positions at EOG, including President, CEO and director, President and Chief Operating Officer and President-North America Operations. Mr. Papa joined Belco Petroleum Corporation, a predecessor of EOG, in 1981.

Mr. Papa also serves as a director of Oil States International, Inc. (since 2001), a publicly traded 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, L.P., a publicly traded pipeline and terminal company, where he served as Chairman of the Compensation Committee and as a member of the Audit and Conflicts Committees.

H. LEIGHTON STEWARD, 78
Director since 2004

Mr. Steward has extensive experience in the oil and gas exploration and production industry, having served in various senior management roles with The Louisiana Land and Exploration Company, a publicly traded oil and gas exploration and production company, including President, Chief Operating Officer and, from 1989 until its acquisition by Burlington Resources Inc. in 1997, Chairman of the Board and Chief Executive Officer. Mr. Steward subsequently served as Vice Chairman of Burlington Resources, a publicly traded oil and gas exploration, production and development company, until his retirement in 2000.

Mr. Steward is former Chairman of the U.S. Oil and Gas Association and the Natural Gas Supply Association, and is currently an honorary director of the American Petroleum Institute.

Mr. Steward is also currently an author-partner of Sugar Busters, LLC, a provider of seminars, books and products related to helping people follow a healthy and nutritious lifestyle, and Chairman of the non-profit corporations Plants Need CO2 and CO2 Is Green, providers of information related to carbon dioxide’s impact on the global climate and the plant and animal kingdoms.

DONALD F. TEXTOR, 66
Director since 2001

Mr. Textor is currently Portfolio Manager of the Dorset Energy Fund, an energy fund which invests primarily in the equity securities of companies in the energy industry. Mr. Textor was previously employed by Goldman, Sachs & Co., where he was a partner and managing director until his retirement in March 2001 and where he had 21 years of experience as the firm’s senior security analyst for domestic oil and gas exploration and production companies.

Mr. Textor is also currently a director of Trilogy Energy Corp., a petroleum and natural gas-focused Canadian energy corporation, where he serves as a member of the Compensation Committee.

As a result of serving in these roles and serving as a member and the Chairman of our Audit Committee since 2001, Mr. Textor has accumulated significant leadership and financial reporting experience as well as extensive knowledge of the oil and gas exploration and production industry.

WILLIAM R. THOMAS, 60
New Director Nominee

Mr. Thomas has been with EOG and its predecessor companies for over 34 years. Prior to becoming President in September 2011, Mr. Thomas served in other leadership positions at EOG, including Senior Executive Vice President, Exploitation and Senior Executive Vice President, Exploration.

Mr. Thomas has also previously served as the General Manager of EOG’s Fort Worth, Texas, Midland, Texas and Corpus Christi, Texas offices, where he was instrumental in EOG’s successful exploration, development and exploitation of various key resource plays. Mr. Thomas joined HNG Oil Company, a predecessor of EOG, in 1979.

FRANK G. WISNER, 74
Director since 1997

Mr. Wisner concluded his more than 35-year career with the U.S. State Department by serving as U.S. Ambassador to India from 1994 to 1997. Following his retirement as U.S. Ambassador to India, Mr. Wisner served as Vice Chairman, External Affairs of American International Group, Inc., a publicly traded international insurance and financial services company (“AIG”), from 1997 until his retirement in March 2009. Mr. Wisner has served as Foreign Affairs Advisor with Patton Boggs LLP, a Washington, D.C.-based law firm, since 2009.

In addition to his extensive international and governmental affairs experience, Mr. Wisner has accumulated diverse business experience. Since 2001, Mr. Wisner has served as a director of Ethan Allen Interiors Inc., a publicly traded residential furniture company, where he serves as the Chair of the Nominations Committee and as a member of the Compensation Committee. Mr. Wisner is also a director of Chartis Inc., a wholly owned subsidiary of AIG and a leading U.S. and international property and casualty and general insurer. In addition, he serves on the board of Chartis International, LLC.

MANAGEMENT DISCUSSION FROM LATEST 10K

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.

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.

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.

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.

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.

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 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.

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).

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.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

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.

United States and Canada. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate 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 to unconventional crude oil and liquids-rich reservoirs. In 2013, EOG is focused on developing its existing North American crude oil and liquids-rich acreage and testing methods to improve the recovery factor of the oil-in-place in these plays. In addition, EOG continues to evaluate certain potential crude oil and liquids-rich exploration and development prospects. For the first nine months of 2013, revenues from the sales of crude oil and condensate and natural gas liquids (NGLs) were approximately 84% of total wellhead revenues. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 55% of total company production for the first nine months of 2013 as compared to 45% for the comparable period in 2012. In North America, crude oil and condensate and NGLs production accounted for approximately 62% of total North American production during the first nine months of 2013 as compared to 52% for the comparable period in 2012. This liquids growth primarily reflects increased production from the South Texas Eagle Ford, the Permian Basin and the North Dakota Bakken. 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. In 2013, EOG's major producing areas in the United States and Canada are in New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

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

In December 2012, EOG's wholly-owned Canadian subsidiary signed a purchase and sale agreement for the sale of its entire interest in the planned Kitimat liquefied natural gas export terminal, the proposed Pacific Trail Pipelines and approximately 28,500 undeveloped net acres in the Horn River Basin. The transaction closed in February 2013.

International. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium Block, Modified U(a) Block, Block 4(a) and Modified U(b) Block, as well as in the Pelican Field and the EMZ Area, have been developed and are producing natural gas sold to the National Gas Company of Trinidad and Tobago and condensate sold to the Petroleum Company of Trinidad and Tobago. During the first nine months of 2013, EOG continued its four-well program in the Modified U(a) Block, drilling three development wells and one successful exploratory well. In the third quarter of 2013, three of the four wells began production. The fourth well will begin production in the fourth quarter of 2013. In addition, an existing well was recompleted and began production in the third quarter of 2013.

In the United Kingdom, EOG continues to make progress in field development for its East Irish Sea Conwy crude oil discovery. Modifications to the nearby third-party-owned Douglas platform, which will be used to process Conwy production, began in the first quarter of 2013. In the third quarter of 2013, a crude oil processing module was installed on the Douglas platform. In addition, drilling began on three development wells. First production from the Conwy field is anticipated in late 2014. In the second quarter of 2013, costs totaling $24.1 million associated with the Central North Sea Columbus natural gas project were written off. In the third quarter of 2013, EOG drilled an unsuccessful exploratory well in the Central North Sea Block 21/12b which was awarded to EOG in 2009.

In Argentina, EOG is focused on the Vaca Muerta oil shale formation in the Neuquén Basin in Neuquén Province. In 2012, a monitor well was drilled in the Aguada del Chivato Block and completed during the first half of 2013. Also, in 2013, the first well on the Cerro Avispa Block was drilled with completion expected in the fourth quarter of 2013. EOG continues to evaluate its drilling results and exploration program in Argentina.

During the first half of 2013, EOG successfully recompleted a well in the Sichuan Basin, Sichuan Province, The People's Republic of China. A second well was drilled in the third quarter of 2013 and will be completed in the fourth quarter of 2013. One additional well is planned in the fourth quarter of 2013, which is expected to begin producing in 2014.

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

Capital Structure . One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 30% and 32% at September 30, 2013 and December 31, 2012, respectively. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity. At September 30, 2013, $350 million principal amount of Floating Rate Senior Notes due 2014 and $150 million principal amount of 4.75% Subsidiary Debt due 2014 were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amounts with other long-term debt. On October 1, 2013, EOG repaid, at maturity, the $400 million principal amount of its 6.125% Senior Notes.

EOG's total anticipated 2013 capital expenditures are estimated to range from $7.0 billion to $7.2 billion, excluding acquisitions. The majority of 2013 expenditures have been and 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 slightly higher than cash flow from operating activities for 2013. EOG's business plan includes an objective of selling certain non-core assets in 2013 to cover any anticipated shortfall in cash flows. In the first nine months of 2013, EOG achieved this goal by receiving proceeds of approximately $587 million from sales of assets. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its $2.0 billion senior unsecured revolving credit facility and equity and debt offerings. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

Results of Operations

The following review of operations for the three and nine months ended September 30, 2013 and 2012 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Three Months Ended September 30, 2013 vs. Three Months Ended September 30, 2012

Net Operating Revenues. During the third quarter of 2013, net operating revenues increased $586 million, or 20%, to $3,541 million from $2,955 million for the same period of 2012. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, for the third quarter of 2013 increased $833 million, or 39%, to $2,942 million from $2,109 million for the same period of 2012. During the third quarter of 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $293 million compared to net gains of $5 million for the same period of 2012. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, NGLs and natural gas as well as fees associated with gathering third-party natural gas, for the third quarter of 2013 increased $109 million, or 14%, to $873 million from $764 million for the same period of 2012. Gains on asset dispositions, net, for the third quarter of 2013 and 2012 totaled $8 million and $67 million, respectively.

Wellhead crude oil and condensate revenues for the third quarter of 2013 increased $826 million, or 55%, to $2,338 million from $1,512 million for the same period of 2012, due to an increase of 66 MBbld, or 39%, in wellhead crude oil and condensate deliveries ($587 million) and a higher composite average wellhead crude oil and condensate price ($239 million). The increase in deliveries primarily reflects increased production in the South Texas Eagle Ford, the North Dakota Bakken and the Permian Basin. EOG's composite average wellhead crude oil and condensate price for the third quarter of 2013 increased 11% to $108.20 per barrel compared to $97.13 per barrel for the same period of 2012.

NGLs revenues for the third quarter of 2013 increased $38 million, or 22%, to $208 million from $170 million for the same period of 2012, due to an increase of 10 MBbld, or 17%, in NGLs deliveries ($28 million) and a higher composite average NGLs price ($10 million). The increase in deliveries primarily reflects increased volumes in the South Texas Eagle Ford and the Permian Basin. EOG's composite average NGLs price for the third quarter of 2013 increased 5% to $32.74 per barrel compared to $31.11 per barrel for the same period of 2012.

Wellhead natural gas revenues for the third quarter of 2013 decreased $31 million, or 7%, to $396 million from $427 million for the same period of 2012. The decrease was due to a decrease in natural gas deliveries ($50 million), partially offset by a higher composite average wellhead natural gas price ($19 million). EOG's composite average wellhead natural gas price for the third quarter of 2013 increased 5% to $3.23 per thousand cubic feet (Mcf) compared to $3.07 per Mcf for the same period of 2012. Natural gas deliveries for the third quarter of 2013 decreased 178 MMcfd, or 12%, primarily due to lower production in the United States (123 MMcfd), Trinidad (35 MMcfd) and Canada (18 MMcfd). The decrease in the United States was primarily attributable to asset sales and reduced natural gas drilling activity. The decrease in Trinidad was primarily attributable to higher contractual deliveries in 2012.

During the third quarter of 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $293 million compared to net gains of $5 million for the same period of 2012. During the third quarter of 2013, the net cash outflow related to settled crude oil and natural gas derivative contracts was $21 million compared to the net cash inflow of $249 million for the same period of 2012.

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. 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 the third quarter of 2013, gathering, processing and marketing revenues and marketing costs increased compared to the same period of 2012 primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs for the third quarter of 2013 decreased $13 million compared to the same period of 2012 due to lower margins on crude oil marketing activities.

Operating and Other Expenses. For the third quarter of 2013, operating expenses of $2,772 million were $423 million higher than the $2,349 million incurred during the third quarter of 2012.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net, for the three months ended September 30, 2013, compared to the same period of 2012 are set forth below.

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 $299 million for the third quarter of 2013 increased $46 million from $253 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($25 million) and Canada ($5 million) and increased workover expenditures in the United States ($15 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 $220 million for the third quarter of 2013 increased $56 million from $164 million for the same prior year period primarily due to increased transportation costs related to production from the South Texas Eagle Ford ($29 million), the Rocky Mountain area ($18 million) and the Fort Worth Basin Barnett Shale area ($9 million).

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells, reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from year to year. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses for the third quarter of 2013 increased $103 million to $929 million from $826 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2013 were $113 million higher than the same prior year period primarily as a result of increased production in the United States ($97 million) and higher unit rates in the United States ($25 million) and Trinidad ($9 million), partially offset by decreased production in Canada ($8 million) and Trinidad ($4 million). Unit rates in the United States increased due primarily to downward revisions of natural gas reserves at December 31, 2012, and an increase in production from higher-cost properties.

G&A expenses of $99 million for the third quarter of 2013 increased $6 million compared to the same prior year period primarily due to higher costs associated with supporting expanding operations.

Interest expense, net, of $59 million for the third quarter of 2013 increased $6 million compared to the same prior year period primarily due to interest charges related to $1.25 billion aggregate principal amount of the 2.625% Senior Notes due 2023 issued in September 2012.

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 $5 million to $31 million for the third quarter of 2013 compared to $26 million for the same prior year period. The increase primarily reflects increased activities in the South Texas Eagle Ford.

Exploration costs of $39 million for the third quarter of 2013 decreased $7 million from $46 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States.

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the asset. If the expected 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. For certain assets held for sale, EOG utilized accepted bids as the basis for determining fair value.

Impairments of $86 million for the third quarter of 2013 were $23 million higher than impairments for the same prior year period primarily due to increased impairments of other assets in the United States ($30 million) and increased amortization of unproved property costs in the United States ($3 million), partially offset by decreased impairments of proved properties in the United States ($10 million). EOG recorded impairments of proved properties and other assets of $55 million and $33 million for the third quarter of 2013 and 2012, respectively.

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 for the third quarter of 2013 increased $52 million to $172 million (5.9% of wellhead revenues) compared to $120 million (5.7% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($44 million) primarily as a result of increased wellhead revenues and increased ad valorem/property taxes in the United States ($8 million).

Income tax provision of $259 million for the third quarter of 2013 increased $54 million compared to the same period of 2012 due primarily to higher pretax income. The net effective tax rate for the third quarter of 2013 decreased to 36% from 37% for the same prior year period.

Nine Months Ended September 30, 2013 vs. Nine Months Ended September 30, 2012

Net Operating Revenues. During the first nine months of 2013, net operating revenues increased $2,067 million, or 24%, to $10,738 million from $8,671 million for the same period of 2012. Total wellhead revenues for the first nine months of 2013 increased $2,087 million, or 36%, to $7,958 million from $5,871 million for the same period of 2012. During the first nine months of 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $207 million compared to net gains of $327 million for the same period of 2012. Gathering, processing and marketing revenues for the first nine months of 2013 increased $562 million, or 26%, to $2,755 million from $2,193 million for the same period of 2012. Gains on asset dispositions, net, for the first nine months of 2013 and 2012 totaled $186 million and $248 million, respectively.

Wellhead crude oil and condensate revenues for the first nine months of 2013 increased $1,934 million, or 46%, to $6,133 million from $4,199 million for the same period of 2012, due to an increase of 56 MBbld, or 36%, in wellhead crude oil and condensate deliveries ($1,465 million) and a higher composite average wellhead crude oil and condensate price ($469 million). The increase in deliveries primarily reflects increased production in the South Texas Eagle Ford, the Permian Basin and the North Dakota Bakken. EOG's composite average wellhead crude oil and condensate price for the first nine months of 2013 increased 8% to $105.76 per barrel compared to $97.68 per barrel for the same period of 2012.

NGLs revenues for the first nine months of 2013 increased $37 million, or 7%, to $556 million from $519 million for the same period of 2012, due to an increase of 9 MBbld, or 17%, in NGLs deliveries ($106 million), partially offset by a lower composite average NGLs price ($69 million). The increase in deliveries primarily reflects increased volumes in the South Texas Eagle Ford and the Permian Basin. EOG's composite average NGLs price for the first nine months of 2013 decreased 11% to $31.64 per barrel compared to $35.58 per barrel for the same period of 2012.

Wellhead natural gas revenues for the first nine months of 2013 increased $117 million, or 10%, to $1,270 million from $1,153 million for the same period of 2012. The increase was due to a higher composite average wellhead natural gas price ($266 million), partially offset by decreased natural gas deliveries ($149 million). EOG's composite average wellhead natural gas price for the first nine months of 2013 increased 27% to $3.43 per Mcf compared to $2.71 per Mcf for the same period of 2012. Natural gas deliveries for the first nine months of 2013 decreased 196 MMcfd, or 13%, primarily due to decreased production in the United States (131 MMcfd), Trinidad (43 MMcfd) and Canada (20 MMcfd). The decrease in the United States was attributable to asset sales and reduced natural gas drilling activity. The decrease in Trinidad was primarily attributable to higher contractual deliveries in 2012.

During the first nine months of 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $207 million compared to net gains of $327 million for the same period of 2012. During the first nine months of 2013, the net cash inflow related to settled crude oil and natural gas derivative contracts was $115 million compared to the net cash inflow of $556 million for the same period of 2012.

During the first nine months of 2013, gathering, processing and marketing revenues and marketing costs increased, compared to the same period of 2012, primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs for the first nine months of 2013 decreased $30 million compared to the same period of 2012 due to lower margins on crude oil marketing activities.

Operating and Other Expenses. For the first nine months of 2013, operating expenses of $8,043 million were $1,230 million higher than the $6,813 million incurred during the same period of 2012.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net, for the nine months ended September 30, 2013, compared to the same period of 2012 are set forth below.

Lease and well expenses of $817 million for the first nine months of 2013 increased $51 million from $766 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($21 million) and Canada ($7 million), increased workover expenditures in the United States ($15 million) and increased lease and well administrative expenses ($8 million).

Transportation costs of $629 million for the first nine months of 2013 increased $197 million from $432 million for the same prior year period primarily due to increased transportation costs related to production from the South Texas Eagle Ford ($93 million), the Rocky Mountain area ($73 million) and the Fort Worth Basin Barnett Shale area ($30 million).

DD&A expenses for the first nine months of 2013 increased $303 million to $2,686 million from $2,383 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2013 were $332 million higher than the same prior year period primarily as a result of increased production in the United States ($229 million) and higher unit rates in the United States ($125 million) and Trinidad ($32 million), partially offset by decreased production in Canada ($25 million) and Trinidad ($12 million) and lower unit rates in Canada ($16 million). Unit rates in the United States increased due primarily to downward revisions of natural gas reserves at December 31, 2012, and an increase in production from higher-cost properties.

G&A expenses of $257 million for the first nine months of 2013 increased $12 million compared to the same prior year period primarily due to higher costs associated with supporting expanding operations.

Interest expense, net of $183 million for the first nine months of 2013 increased $29 million compared to the same prior year period primarily due to a higher average debt balance.

Gathering and processing costs for the first nine months of 2013 increased $9 million to $82 million compared to the same prior year period primarily due to increased activities in the South Texas Eagle Ford.

Exploration costs of $131 million for the first nine months of 2013 decreased $6 million from $137 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States ($9 million) and Canada ($2 million), partially offset by increased exploration administrative expenses in the United States ($5 million).

Impairments of $177 million for the first nine months of 2013 were $73 million lower than impairments for the same prior year period primarily due to decreased impairments of proved properties in the United States ($87 million) and decreased amortization of unproved property costs in the United States ($14 million) and Canada ($4 million), partially offset by increased impairments of proved properties in Canada ($12 million) and Argentina ($6 million) and increased impairments of other assets in the United States ($11 million). EOG recorded impairments of proved properties and other assets of $93 million and $148 million for the first nine months of 2013 and 2012, respectively.

Taxes other than income for the first nine months of 2013 increased $99 million to $459 million (5.8% of wellhead revenues) from $360 million (6.1% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($86 million) primarily as a result of increased wellhead revenues, higher ad valorem/property taxes in the United States ($15 million) and a decrease in credits available to EOG in 2013 for Texas high-cost gas severance tax rate reductions ($4 million), partially offset by decreased severance/production taxes in Trinidad ($3 million) and Canada ($2 million).

Other income, net, was $6 million for the first nine months of 2013 compared to $23 million for the same prior year period. The decrease of $17 million was primarily due to losses related to warehouse stock sales and adjustments ($12 million) and an increase in deferred compensation expense ($4 million).

Income tax provision of $901 million for the first nine months of 2013 increased $250 million compared to the same period of 2012 due primarily to higher pretax income. The net effective tax rate for the first nine months of 2013 decreased to 36% from 38% for the same prior year period.

CONF CALL

Doug Leggate - Bank of America Merrill Lynch
My apologies, I think there is going to be some folks mulling in and out. But I'm sure you're all aware of how exciting news that of EOG has been recently in terms of what's going on with their quarter growth, their cash flow, and their completion changes. So it gives me great pleasure to introduce Bill Thomas, President and CEO. Bill?

Bill Thomas - President & CEO
Yes. Good morning. And I just want to certainly thank Doug and Bank of America for the opportunity to present the EOG story. It's obviously a very strong story. And I know many of you are all very familiar with the company and know that when you think about EOG, you want to think about oil, and you want to think about oil growth, and you want to think about rapid oil growth. And that's what the company has delivered over the last three really six years. For the last three years, we've averaged about 43% a year-over-year growth in just crude oil and that really came about because EOG was clearly the first mover in converting from the horizontal gas shale to the horizontal oil shale, a revolution has been going on. And so because of that we were able to acquire we believe the best, the strongest horizontal oil assets in North America, in the E&P business. And so we've been leading the sector in oil growth and we feel like through 2017 at least may be beyond that that we will continue to lead the sector in oil growth as we go forward. And so we will talk about all that, a little bit more as we go through these slides.

We have a very diverse portfolio of key assets in the company. And when you look at just these key assets, we believe that we have 10 years of inventory, 10 years of very high rate of return inventory, and of course the hallmark asset is Eagle Ford. We have the strongest obviously the best position in Eagle Ford 569,000 acres and we've been growing production really rapidly and we will talk about that in a minute. That's obviously the best horizontal oil discovery and field in the world presently and we have the largest position in that.

In the Bakken/Three Forks, we made the discovery well, horizontal oil discovery well back in 2006 and we have a strong position there particularly in the Parshall core area of the field. We've had a technical renaissance. We've tremendously increased our productivity of the well just in this last year and we have a big inventory on that, and I will talk about that.

Really the third leg of our oil inventory is in the Permian. And we have three plays in the Permian, but we're particularly excited about the Delaware side of the Permian, and in the Leonard play that we have, some people call it Avalon play, we -- year-to-date results on that are actually or directly 100% rates of return on that and it's a nice crude oil play for us. We have 1600 locations in inventory in the Leonard.

In all of these plays, all three of these plays we're generating 100% direct rates of return right now and we have more than 10 years of inventory in each one of those. And as we go forward, obviously, we are generating a lot more cash with oil growth like it is in the company, we're going to be putting most of our money back into and accelerating the drilling on all three of these play as we go forward.

Each one of these plays and also the additional plays we have in the company, the company is very focused on increasing the recovery factor. And so we're using new frac technology, drilling wells on a downspacing program, connecting more rock to the well and adding reserve potential as we go along in each one of these plays while also decreasing the cost of the wells dramatically too. So the efficiencies on cost reduction and the remaining upside on the play, we feel like it could potentially be very large.

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