ITEM 1. Business
General
	EOG Resources, Inc. (EOG), a Delaware corporation organized in 1985, together with its subsidiaries, explores for, develops, produces and markets natural gas and crude oil primarily in major producing basins in the United States of America (United States), Canada, offshore Trinidad, the United Kingdom North Sea 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 all amendments to those reports are made available, free of charge, through its website, as soon as reasonably practicable after such reports have been filed with the Securities and Exchange Commission (SEC). EOG's website address is http://www.eogresources.com.
	At December 31, 2006, EOG's total estimated net proved reserves were 6,802 billion cubic feet equivalent (Bcfe), of which 6,095 billion cubic feet (Bcf) were natural gas reserves and 118 million barrels (MMBbl), or 707 Bcfe, were crude oil, condensate and natural gas liquids reserves (see "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 60% of EOG's reserves (on a natural gas equivalent basis) were located in the United States, 20% in Canada and 20% in Trinidad. As of December 31, 2006, EOG employed approximately 1,570 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. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis. EOG focuses its drilling activity toward natural gas deliverability in addition to natural gas reserve replacement and to a lesser extent crude oil exploration and exploitation. EOG focuses on the cost-effective utilization of advances in technology associated with the gathering, processing and interpretation of three-dimensional (3-D) seismic data, the development of reservoir simulation models, the use of new and/or improved drill bits, mud motors and mud additives, and formation logging techniques and reservoir fracturing 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. EOG also makes select tactical acquisitions that result in additional economies of scale or land positions with significant additional prospects. 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 natural gas and crude oil exploration and production related.
Exploration and Production
United States and Canada Operations
	EOG's operations are focused on most of the productive basins in the United States and Canada.
	At December 31, 2006, 88% of EOG's net proved United States and Canada reserves (on a natural gas equivalent basis) were natural gas and 12% were crude oil, condensate and natural gas liquids. 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 application of new processes and technologies. EOG also maintains an active exploration program designed to extend fields and add new trends to its broad portfolio. The following is a summary of significant developments during 2006 and certain 2007 plans for EOG's United States and Canada operations.
	United States. During 2006, EOG substantially increased drilling activity, acreage position, reserve potential and production in the Fort Worth Basin Barnett Shale play (Fort Worth Barnett). The net average production from the Fort Worth Barnett for 2006 was 145 million cubic feet per day (MMcfd) of natural gas and 300 barrels per day (Bbld)
	of crude oil, condensate and natural gas liquids. EOG drilled 205 net Fort Worth Barnett wells during 2006 and grew production to over 200 MMcfd, net by year-end 2006. During the year, EOG leased more than 100,000 additional net acres and increased EOG's total leasehold to greater than 600,000 net acres. EOG will substantially increase drilling activity in the Forth Worth Barnett during 2007 with plans to drill approximately 380 gross wells and exit the year with over 300 MMcfd net production. EOG continues to generate new opportunities in the Fort Worth Barnett which EOG expects will add significant future reserve and production potential.
	The Upper Gulf Coast continued to be a growth area for EOG where 2006 net production averaged 117 MMcfd of natural gas and 3.5 thousand barrels per day (MBbld) of crude oil, condensate and natural gas liquids. EOG drilled 60 net wells with 30 net wells in the Cotton Valley and Travis Peak development programs at the Sligo, Minden, Carthage and Appleby Fields. North Louisiana development activity included five net wells at Driscoll Mountain in the expanded Cotton Valley and 10 horizontal producers in Spider Field. EOG continues its growth in Mississippi where 13 successful net wells were drilled in 2006 in the Hosston play in South Williamsburg. EOG is currently one of the largest natural gas producers in Mississippi. EOG will continue its growth in East Texas, Louisiana and Mississippi with tests of several high potential impact new projects in 2007.
	In the Permian Basin, EOG drilled 30 net horizontal gas wells in 2006 in the New Mexico Wolfcamp play. EOG has over 40,000 net acres in the play and plans to drill approximately 33 net wells in 2007. EOG has identified approximately 100 drilling locations in this play. Significant drilling and completion improvements have resulted in cost reductions, as well as quick spud-to-sales cycle times for these wells. This activity was complemented by a number of successful wells in the Permo-Penn Carbonate, Bone Spring Carbonate and Horizontal Bone Spring. EOG drilled 61 net wells in 2006, and net production averaged 87 MMcfd of natural gas and 7.1 MBbld of crude oil, condensate and natural gas liquids. Several additional horizontal plays, which could set up multiple drilling locations, will be tested in 2007 on over 20,000 acres controlled by EOG.
	EOG increased drilling activity within its core areas of the Rocky Mountain area, drilling 179 net wells during 2006, including 84 net wells in the Uinta Basin, Utah, 40 net wells in the LaBarge Platform, Wyoming, 34 net wells in the Moxa Arch area, Wyoming, and seven net wells in the Williston Basin. The net average daily production for 2006 from the Rocky Mountain area was 165 MMcfd of natural gas and 8.6 MBbld of crude oil, condensate and natural gas liquids. EOG expects to continue increasing drilling activity in these core areas during 2007, while maintaining an active exploration and delineation program in other areas in Utah, Wyoming and North Dakota.
	In the Mid-Continent area, EOG drilled 117 net wells in its core areas in 2006, most notably the Hugoton-Deep play in the Oklahoma Panhandle and the Cleveland Horizontal play in the Texas Panhandle. The net average production for 2006 was 74 MMcfd of natural gas and 2.4 MBbld of crude oil and condensate. In the Hugoton-Deep play, EOG shifted its prospecting into Southwest Kansas and was successful in finding several new Morrow plays. Net production from this area increased from 25 MMcfd in the beginning of 2006 to over 50 MMcfd by year-end. Nine years remain on the 900,000 acre, 10-year joint venture with Anadarko Petroleum Company. In the Cleveland Horizontal play, EOG drilled 28 net wells in 2006, bringing its total to 125 net wells drilled since 2003. EOG plans to continue exploiting these two core growth areas in 2007, while pursuing other exploration prospects throughout the Mid-Continent area.
	EOG had another successful year in South Texas, drilling 84 net wells in 2006. South Texas onshore net production averaged 185 MMcfd of natural gas and 6.3 MBbld of crude oil, condensate and natural gas liquids during 2006. The activity was focused in Webb, Zapata, San Patricio, Duval, and Starr counties, where EOG drilled successful wells in the Lobo, Roleta, Reklaw, Frio, and Wilcox trends. EOG's application of horizontal drilling and completion technology in the Wilcox trend has resulted in new opportunities for this mature play. EOG added significant lease positions and 3-D seismic in 2006 to sustain a long-term drilling program.
	During 2006, EOG participated in two discoveries in the Gulf of Mexico. In the High Island area, one well is producing and another well is expected to be on sales during the first quarter of 2007. A development well is currently being drilled in High Island Block 130 and is expected to be completed by March 2007. Net production from these three wells is expected to be 10 MMcfd by mid-2007. Drilling and completion operations for a deepwater project are underway, and first production is projected for early 2008. At least two additional exploratory projects are planned for the Gulf of Mexico in 2007.
	In 2006, EOG drilled 68 net wells in the Appalachian Basin. Net production averaged 19 MMcfd of natural gas and 60 Bbld of crude oil and condensate. EOG is planning a similar drilling program in 2007. The majority of the wells will be drilled in the shallow Devonian and 10 net wells are planned for the Marcellus Shale. The Marcellus wells will be drilled in Pennsylvania to evaluate EOG's acreage in the joint venture with Seneca Resources Corporation.
	At December 31, 2006, EOG held approximately 3,184,000 net undeveloped acres in the United States.
	Canada. In Canada, EOG conducts operations through its subsidiary, EOG Resources Canada Inc. (EOGRC), from offices in Calgary, Alberta. During 2006, EOGRC continued its successful shallow gas strategy in Western Canada, drilling a total of 1,330 net wells. The 2006 shallow natural gas drilling program included 128 net Horseshoe Canyon coalbed methane wells. EOGRC participated in two exploratory wells in the Northwest Territories in 2006, resulting in a new pool discovery and a confirmation of an existing discovery made in 2004. EOGRC's net production during 2006 averaged 226 MMcfd of natural gas and 3.3 MBbld of crude oil, condensate and natural gas liquids. Key producing areas are the Southeast Alberta/Southwest Saskatchewan shallow natural gas trends including the Drumheller, Twining and Halkirk areas, the Pembina/Highvale area of Central Alberta, the Grand Prairie/Wapiti area of Northwest Alberta and the Waskada area in Southwest Manitoba. EOGRC plans to drill approximately 1,000 net wells in these areas during 2007.
	At December 31, 2006, EOGRC held approximately 1,568,000 net undeveloped acres in Canada.
Operations Outside the United States and Canada
	EOG has operations offshore Trinidad and in the United Kingdom North Sea, and is evaluating additional exploration, development and exploitation opportunities in Trinidad, the United Kingdom and other international areas.
	Trinidad. In November 1992, EOG, through its subsidiary, EOG Resources Trinidad Limited (EOGRT), acquired an exploration and production license in the South East Coast Consortium (SECC) Block offshore Trinidad. EOG currently has an 80% working interest in the Block, except the Deep Ibis prospect in which EOG's working interest decreased as a result of a farm-out agreement with BP Trinidad Tobago LLC (BP). The SECC Deep Ibis well spudded in April 2006, was drilled to a depth of approximately 19,000 feet and was abandoned and classified as a dry hole in the third quarter of 2006. BP paid the entire cost for drilling the exploratory well. The Kiskadee, Ibis and Parula fields have been developed and are being produced. In 2006, EOG continued the development of the Oilbird field and expects initial production in the second quarter of 2007. Effective September 1, 2006, the Oilbird Field Unitization Agreement was executed as the Oilbird field straddles the SECC Block and the U(b) Block. The license covering the SECC Block will expire in December 2029.
	In July 1996, EOG, through its subsidiary, EOG Resources Trinidad-U(a) Block Limited, signed a production sharing contract with the Government of Trinidad and Tobago for the Modified U(a) Block. EOG holds a 100% working interest in this block. The Osprey field was discovered in 1998 and commenced production in 2002.
	Surplus processing and transportation capacity at the Pelican field facilities (owned and operated by a subsidiary of the other participants in the SECC Block) is being used to process and transport EOG's natural gas production from the SECC Block and all of its crude oil and condensate production from both the SECC and Modified U(a) Blocks. Crude oil and condensate from EOG's Trinidad operations are being sold to the Petroleum Company of Trinidad and Tobago.
	In April 2002, EOG, through its subsidiary, EOG Resources Trinidad-LRL Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for the Lower Reverse "L" (LRL) Block which is adjacent to the SECC Block. EOG holds a 100% working interest in the LRL Block. In the fourth quarter of 2003, EOG drilled the first exploratory well, LRL #1, on this block. The well was determined to be non-commercial. In November 2004, EOG drilled the LRL #2 well which encountered approximately 130 feet of net pay. EOG is currently evaluating development options for the LRL #2 discovery. In December 2004, the LRL #3 exploratory well was drilled and determined to be a dry hole.
	In October 2002, EOG, through its subsidiary, EOG Resources Trinidad U(b) Block Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for the Modified U(b) Block which is also adjacent to the SECC Block. EOG holds a 55% working interest in and operates the Modified U(b) Block. Primera Oil & Gas Ltd., a Trinidadian company, holds the remaining 45% working interest. In September 2004, EOG drilled the first exploratory well on this block, and the well was determined to be non-commercial. Effective September 1, 2006, the Oilbird Field Unitization Agreement was executed as the Oilbird field straddles the SECC Block and the U(b) Block.
	In July 2005, EOG, through its subsidiary, EOG Resources Trinidad Block 4(a) Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for Block 4(a). EOG, as the operator, holds a 90% working interest in Block 4(a). Primera Block 4(a) Limited, a Trinidadian company, holds the remaining 10% working interest. In the first quarter of 2006, two successful wells were drilled on Block 4(a). EOG's subsidiary has obtained approval to develop the discovery and has executed a term sheet with the National Gas Company of Trinidad and Tobago (NGC) for the sale of the gas.
	Natural gas from EOG's Trinidad operations is being sold to the NGC under the following arrangements:
Under a take-or-pay contract expiring in December 2018, natural gas is delivered to NGC for resale to Trinidad local markets. During 2006, EOG delivered net average production of 150 MMcfd of natural gas under this agreement. Prices are partially dependent on Caribbean ammonia index prices and methanol prices.
Under a take-or-pay contract expiring in 2017, EOG delivers to NGC approximately 60 MMcfd, gross, of natural gas which is resold to an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Caribbean Nitrogen Company Limited (CNCL). During 2006, 24 MMcfd, net to EOG, of natural gas was delivered under this contract to NGC. The plant commenced production in June 2002. EOGRT owns a 12% equity interest in CNCL. At December 31, 2006, EOGRT's investment in CNCL was $19 million. At December 31, 2006, CNCL had a long-term debt balance of $142 million, which is non-recourse to CNCL's shareholders. As part of the financing for CNCL, the shareholders have entered into a post-completion deficiency loan agreement with CNCL to fund the costs of operations, payment of principal and interest to the principal creditor and other cash deficiencies of CNCL up to $30 million, approximately $4 million of which is net to EOGRT's interest. The shareholders' agreement governing CNCL requires the consent of the holders of 90% or more of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOGRT is able to exercise significant influence over the operating and financial policies of CNCL and therefore, EOG accounts for the investment using the equity method. During 2006, EOG recognized equity income of $8 million and received cash dividends of $7 million from CNCL.
Under a fifteen-year take-or-pay contract expiring in 2019, EOG delivers to NGC approximately 60 MMcfd, gross, of natural gas which is resold to an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Nitrogen (2000) Unlimited (N2000). During 2006, 25 MMcfd, net to EOG, of natural gas was delivered under this contract to NGC. The plant commenced production in August 2004. EOG's subsidiary, EOG Resources NITRO2000 Ltd. (EOGNitro2000), owns a 10% equity interest in N2000. At December 31, 2006, EOGNitro2000's investment in N2000 was $17 million. At December 31, 2006, N2000 had a long-term debt balance of $166 million, which is non-recourse to N2000's shareholders. As part of the loan agreement for the N2000 financing, affiliates of the shareholders have entered into a post-completion deficiency loan agreement with N2000 to fund the costs of operations, payment of principal and interest to the principal creditor and other cash deficiencies of N2000 up to $30 million, approximately $3 million of which is to be provided by the immediate parent company of EOGNitro2000. The shareholders' agreement governing N2000 requires the consent of the holders of 100% of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOGNitro2000 is able to exercise significant influence over the operating and financial policies of N2000 and therefore, EOG accounts for the investment using the equity method. During 2006, EOG recognized equity income of $10 million and received cash dividends of $9 million from N2000.
Under a fifteen-year natural gas contract signed in January 2004, EOG is currently supplying approximately 100 MMcfd, gross, of natural gas to NGC, which is then being resold by NGC to a methanol plant located in Point Lisas, Trinidad. EOG has no investment in the methanol plant which became operational in September 2005. Under this natural gas contract, EOG expects to ultimately supply approximately 100 MMcfd, gross, (73 MMcfd, net to EOG, based on current pricing and operating assumptions) for the first four years of the contract term, beginning in 2005, and approximately 130 MMcfd, gross, (90 MMcfd, net to EOG, based on current pricing and operating assumptions) for the remaining term of the eleven-year contract. During 2006, 49 MMcfd, net to EOG, of natural gas was delivered under this contract to NGC.
In February 2005, EOGRT executed a twenty-year take-or-pay contract with NGC LNG (Train 4) Limited, a subsidiary of NGC, for the supply of 30 MMcfd, gross, (13 MMcfd, net to EOG, based on current pricing and operating assumptions) of natural gas for use in the Atlantic LNG Train 4 (ALNG) plant in Point Fortin, Trinidad. EOG has no investment in the ALNG plant. The plant commenced its start-up phase and began taking gas during December 2005. The plant remained in the start-up phase through December 2006. During 2006, 17 MMcfd, net to EOG, of natural gas was delivered under this contract to NGC. The ALNG plant has not yet reached commercial status.
	In 2006, EOG's average net production from Trinidad was 264 MMcfd of natural gas and 4.8 MBbld of crude oil and condensate.
	At December 31, 2006, EOG held approximately 209,000 net undeveloped acres in Trinidad.
	United Kingdom. In 2002, EOG's subsidiary, EOG Resources United Kingdom Limited (EOGUK), acquired a 25% non-operating working interest in a portion of Block 49/16, located in the Southern Gas Basin of the North Sea. In August 2004, production commenced in the Valkyrie field in the Southern Gas Basin.
	In 2003, EOGUK acquired 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. Since November 2003, three successful exploratory wells have been drilled in the Arthur field, with production commencing in January 2005.
	During the fourth quarter of 2006, EOG participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f. The Columbus well was a farm-in opportunity and its future appraisal and development is currently being evaluated.
	In 2006, EOG delivered net average production of 30 MMcfd of natural gas in the United Kingdom.
	At December 31, 2006, EOG held approximately 352,000 net undeveloped acres in the United Kingdom.
Other International. EOG continues to evaluate other select natural gas and crude oil opportunities outside the United States and Canada primarily by pursuing exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified.
Marketing
	Wellhead Marketing. EOG's United States and Canada wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts at market-responsive prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. In 2006, a large majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The remaining volumes were sold under a contract at prices partially dependent on the United States Henry Hub market prices. The pricing mechanisms for these contracts in Trinidad will remain the same in 2007. In 2006, a large majority of the wellhead natural gas volumes from the United Kingdom were sold on the spot market. The remaining volumes were sold by means of forward contracts. The marketing strategy for the wellhead natural gas volumes in the United Kingdom is expected to remain the same in 2007.
	Substantially all of EOG's wellhead crude oil and condensate is sold under various terms and arrangements at market-responsive prices.
	During 2006, sales to a major integrated oil and gas company with investment grade credit ratings accounted for 11% of EOG's oil and gas revenues. No other individual purchaser accounted for 10% or more of EOG's oil and gas revenues for the same period. EOG does not believe that the loss of any single purchaser will have a material adverse effect on its financial condition or results of operations.
Wellhead Volumes and Prices
	The following table sets forth certain information regarding EOG's wellhead volumes of and average prices for natural gas per thousand cubic feet (Mcf), crude oil and condensate per barrel (Bbl) and natural gas liquids per Bbl. The table also presents natural gas equivalent volumes on a thousand cubic feet equivalent basis (Mcfe - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil, condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 2006.
(1)	Million cubic feet per day or thousand barrels per day, as applicable.
(2)	Million cubic feet equivalent per day, includes natural gas, crude oil, condensate and natural gas liquids.
(3)	Dollars per thousand cubic feet or per barrel, as applicable.
(4)	Includes $0.23 per Mcf as a result of a revenue adjustment related to an amended Trinidad take-or-pay contract.
Competition
	EOG competes for reserve acquisitions and exploration/exploitation leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent EOG's exploration budget is lower than that of certain of its competitors, EOG may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms and quality of service, including pipeline connection times and distribution efficiencies. In addition, EOG faces competition from other worldwide energy supplies, such as liquefied natural gas imported into the United States from other countries. Please refer to ITEM 1A.
ITEM 1A. Risk Factors
	Our business faces many risks. The risks described below may not be the only risks we face. Additional risks that we do not yet know of, or that we currently think are immaterial, may also impair our business operations or financial results. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline. The following risk factors should be read in conjunction with the other information contained in this report, including the consolidated financial statements and the related notes.
A substantial or extended decline in natural gas or crude oil prices would have a material adverse effect on us.
	Prices for natural gas and crude oil fluctuate widely. Since we are primarily a natural gas company, we are more significantly affected by changes in natural gas prices than changes in the prices for crude oil, condensate or natural gas liquids. Among the factors that can cause these price fluctuations are:
the level of consumer demand;
weather conditions;
domestic drilling activity;
the price and availability of alternative fuels, including liquefied natural gas;
the proximity to, and capacity of, transportation facilities;
worldwide economic and political conditions;
the effect of worldwide energy conservation measures; and
the nature and extent of governmental regulation and taxation.
	Our cash flow and earnings depend to a great extent on the prevailing prices for natural gas and crude oil. Prolonged or substantial declines in these commodity prices may adversely affect our liquidity, the amount of cash flow we have available for capital expenditures and our ability to maintain our credit quality and access to the credit and capital markets.
Our ability to sell our crude oil and natural gas production could be materially harmed if we fail to obtain adequate services such as transportation and processing.
	The sale of our crude oil and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities or our failure to obtain these services on acceptable terms could materially harm our business. We deliver crude oil and natural gas through gathering systems and pipelines that we do not own. These facilities may be temporarily unavailable due to market conditions or mechanical reasons, or may not be available to us in the future.
Weather and climate may have a significant impact on our revenues and productivity.
	Demand for natural gas and oil is, to a significant degree, dependent on weather and climate, which impacts the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by severe weather, such as hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our underlying assumptions could cause the quantities of our reserves to be misstated.
	Estimating quantities of proved crude oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions or changes of conditions could cause the quantities of our reserves to be overstated or understated.
	To prepare estimates of economically recoverable crude oil and natural gas reserves and future net cash flows, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs. Actual results most likely will vary from our estimates. Any significant variance could reduce our estimated quantities and present value of reserves.
If we fail to acquire or find sufficient additional reserves, our reserves and production will decline from their current levels.
	The rate of production from crude oil and natural gas properties generally declines as reserves are depleted. Except to the extent that we conduct successful exploration and development activities, acquire additional properties containing proved reserves, or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. Future crude oil and natural gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.
Drilling crude oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.
	Drilling crude oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive crude oil and natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
unexpected drilling conditions;
title problems;
pressure or irregularities in formations;
equipment failures or accidents;
adverse weather conditions;
compliance with environmental and other governmental requirements, which may increase our costs 	or restrict our activities;
costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment;
lack of infrastructure; and
lack of trained drilling personnel.
We incur certain costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future.
	Our exploration, production and marketing operations are regulated extensively at the federal, state and local levels, as well as by other governments/authorities in countries in which we do business. We have and will continue to incur costs in our efforts to comply with the requirements of environmental and other regulations. Further, the crude oil and natural gas industry regulatory environment could change in ways that might substantially increase these costs.
	As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, local and foreign regulations relating to discharge of materials into, and protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, and require suspension or cessation of operations in affected areas. Changes in or additions to regulations regarding the protection of the environment could hurt our business.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
	The exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, injure or kill people, and damage property and the environment. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts that we believe to be prudent. Losses and liabilities arising from such events could reduce our revenues and increase our costs to the extent not covered by insurance.
	The occurrence of any of these events and any costs incurred as a result of such events and the liabilities related thereto, would reduce the funds available for exploration, drilling and production and could have a material adverse effect on our financial position or results of operations.
Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.
	From time to time, we use derivative instruments (primarily collars and price swaps) to hedge the impact of market fluctuations of natural gas and crude oil prices on net income and cash flow. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges. In addition, we are subject to risks associated with differences in prices at different locations, particularly where
	transportation constraints restrict our ability to deliver oil and gas volumes to the delivery point to which the hedging transaction is indexed.
If we acquire oil and gas properties, our failure to fully identify potential problems, to properly estimate reserves or production rates or costs, or to effectively integrate the acquired operations could seriously harm us.
	From time to time, we seek to acquire oil and gas properties. Although we perform reviews of acquired properties that we believe are consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, nor do they permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Even when problems with a property are identified, we often assume environmental and other risks and liabilities in connection with acquired properties.
	There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs with respect to acquired properties. Actual results may vary substantially from those assumed in the estimates.
	In addition, acquisitions may have adverse effects on our operating results, particularly during the periods in which the operations of acquired properties are being integrated into our ongoing operations.
Terrorist activities and military and other actions could adversely affect our business.
	Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the military or other actions taken in response to these acts, cause instability in the global financial and energy markets. The United States government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These actions could adversely affect us in unpredictable ways, including the disruption of fuel supplies and markets, increased volatility in crude oil and natural gas prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terror.
Competition in the oil and gas exploration and production industry is intense, and many of our competitors have greater resources than we have.
	We compete with major integrated and other independent oil and gas companies for acquisition of oil and gas leases, properties and reserves, equipment and labor required to explore, develop and operate those properties and the marketing of crude oil and natural gas production. Higher recent crude oil and natural gas prices have increased the costs of properties available for acquisition and there are a greater number of companies with the financial resources to pursue acquisition opportunities.
	Many of our competitors have financial and other resources substantially larger than those we possess and have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil and natural gas production, such as changing worldwide prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also compete in attracting and retaining personnel, including geologists, geophysicists, engineers and other specialists.
We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.
	We make, and will continue to make, substantial capital expenditures for the acquisition, development, production, exploration and abandonment of our oil and gas reserves. We intend to finance our capital expenditures primarily through cash flow from operations, commercial paper and to a lesser extent and if necessary, bank borrowings, public and private equity and debt offerings. Lower crude oil and natural gas prices, however, would
	reduce our cash flow. Further, if the condition of the capital markets materially declines, we might not be able to obtain financing on terms we consider acceptable. In addition, a substantial rise in interest rates would decrease our net cash flows available for reinvestment.
ITEM 1B.
ITEM 1B. Unresolved Staff Comments
	None.
ITEM 2.
ITEM 2. Properties
Oil and Gas Exploration and Production Properties and Reserves
	Reserve Information. For estimates of EOG's net proved and proved developed reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see Supplemental Information to Consolidated Financial Statements.
	There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas, crude oil, condensate and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.
	In general, production from EOG's oil and gas properties declines as reserves are depleted. Except to the extent EOG acquires additional properties containing proved reserves or conducts successful exploration, exploitation and development activities, the proved reserves of EOG will decline as reserves are produced. Volumes generated from future activities of EOG are therefore highly dependent upon the level of success in finding or acquiring additional reserves and the costs incurred in so doing. EOG's estimates of reserves filed with other federal agencies agree with the information set forth in Supplemental Information to Consolidated Financial Statements.
	Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2006. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.
	Producing Well Summary. The following table reflects EOG's ownership in producing natural gas and crude oil wells located in the United States, Canada, Trinidad and the United Kingdom at December 31, 2006. Gross natural gas and crude oil wells include 2,365 with multiple completions.
	Drilling and Acquisition Activities. During the years ended December 31, 2006, 2005 and 2004, EOG expended $2,996 million, $1,878 million and $1,510 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties, including asset retirement obligations of $22 million, $20 million and $16 million, respectively. EOG drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated:
(1)	Includes the acquisition of additional interests in certain wells in which EOG previously owned an interest.
	All of EOG's drilling activities are conducted on a contract basis with independent drilling contractors. EOG owns no drilling equipment.
ITEM 3.
ITEM 3. Legal Proceedings
	The information required by this Item is included in this report as set forth in the Contingencies section in Note 7 of Notes to Consolidated Financial Statements on page.
ITEM 4.
ITEM 4. Submission of Matters to a Vote of Security Holders
	There were no matters submitted to a vote of security holders during the fourth quarter of 2006.
	PART II
ITEM 5.
ITEM 5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity 	Securities
	The following table sets forth, for the periods indicated, the high and low price per share for the common stock of EOG, as reported on the New York Stock Exchange Composite Tape, and the amount of common stock dividend declared per share.
	On February 1, 2006, EOG's Board of Directors (Board) increased the quarterly cash dividend on the common stock from the previous $0.04 per share to $0.06 per share.
	On January 31, 2007, the Board increased the quarterly cash dividend on the common stock from the previous $0.06 per share to $0.09 per share.
	As of February 16, 2007, there were approximately 260 record holders of EOG's common stock, including individual participants in security position listings. There are an estimated 123,000 beneficial owners of EOG's common stock, including shares held in street name.
	EOG currently intends to continue to pay quarterly cash dividends on its outstanding shares of common stock. However, the determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, the financial condition, funds from operations, level of exploration, exploitation and development expenditure opportunities and future business prospects of EOG.
	The following table sets forth, for the periods indicated, EOG's repurchase activity:
Period
(a)
Total
Number of
Shares
Purchased(1)
(b)
Average
Price Paid
per Share
(c)
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs
(d)
Maximum Number
of Shares that May Yet
Be Purchased Under
the Plans or Programs(2)
October 1, 2006 - October 31, 2006
-
-
6,386,200
November 1, 2006 - November 30, 2006
-
-
6,386,200
December 1, 2006 - December 31, 2006
3,759
$69.19
-
6,386,200
Total
3,759
$69.19
(1)	The quarterly total number of shares of 3,759 consists solely of 1,430 shares (23,232 shares for the full year 2006) that were returned to EOG in
payment of the exercise price of employee stock options and 2,329 shares (241,931 shares for the full year 2006) that were withheld by or returned
to EOG to satisfy tax withholding obligations that arose upon the exercise of employee stock options or the vesting of restricted stock or units.
(2)	In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During 2006, EOG did not repurchase
any shares under the Board authorized repurchase program.
ITEM 6.
ITEM 6. Selected Financial Data
(In Thousands, Except Per Share Data)
(1)	EOG adopted Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. Pro forma net
income for 2002 is not presented since the pro forma application of SFAS No. 143 to the prior periods would not result in pro forma net income materially
different from the actual amount reported.
(2)	Years 2002 through 2004 restated for two-for-one stock split effective March 1, 2005.
At December 31
Balance Sheet Data:
Net Oil and Gas Properties
$
7,944,047
$
6,087,179
$
5,101,603
$
4,248,917
$
3,321,548
Total Assets
9,402,160
7,753,320
5,798,923
4,749,015
3,813,568
Current and Long-Term Debt
733,442
985,067
1,077,622
1,108,872
1,145,132
Shareholders' Equity
5,599,671
4,316,292
2,945,424
2,223,381
1,672,395
ITEM 7.
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview
	EOG Resources, Inc. (EOG) is one of the largest independent (non-integrated) oil and natural gas companies in the United States with proved reserves in the United States, Canada, offshore Trinidad and the United Kingdom North Sea. EOG operates under a consistent business and operational strategy that focuses predominantly on achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.
	Net income available to common for 2006 of $1,289 million was up 3% compared to 2005 net income available to common of $1,252 million. At December 31, 2006, EOG's total reserves were 6.8 trillion cubic feet equivalent, an increase of 607 billion cubic feet equivalent (Bcfe) from December 31, 2005.
	Operations
	Several important developments have occurred since January 1, 2006.
United States and Canada. EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG plans to continue to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas production. Production in the United States and Canada accounted for approximately 79% of total company production in both 2006 and 2005. Based on current trends, EOG expects its 2007 production profile to be similar. EOG's major producing areas are in Louisiana, New Mexico, Oklahoma, Texas, Utah, Wyoming and western Canada.
	International. Although EOG continues to focus on United States and Canada natural gas, EOG sees an increasing linkage between United States and Canada natural gas demand and Trinidad natural gas supply. For example, liquefied natural gas (LNG) imports from existing and planned facilities in Trinidad are contenders to meet increasing United States natural gas demand. In addition, ammonia, methanol and chemical production has been relocating from the United States and Canada to Trinidad, driven by attractive natural gas feedstock prices in the island nation. EOG believes that its existing position with the supply contracts to two ammonia plants, a methanol plant and the Atlantic LNG Train 4 (ALNG) plant will continue to give its portfolio an even broader exposure to United States and Canada natural gas fundamentals.
	Beginning December 2005, ALNG began taking start-up gas and remained in the start-up phase through December 2006. In the first quarter of 2006, a subsidiary of EOG, EOG Resources Trinidad Block 4(a) Unlimited, drilled two successful wells on Block 4(a). The subsidiary obtained approval to develop Block 4(a) under a production sharing contract with the Government of Trinidad and Tobago signed in July 2005.
	A subsidiary of EOG, EOG Resources Trinidad Limited, and the other participants in the South East Coast Consortium (SECC) Block signed a farm-out agreement covering the SECC Deep Ibis prospect with BP Trinidad and Tobago LLC (BP) during 2004. The SECC Deep Ibis well spud in April 2006, was drilled to a depth of approximately 19,000 feet and was abandoned and classified as a dry hole in the third quarter of 2006. BP paid the entire cost for drilling the SECC Deep Ibis exploratory well.
	During 2006, notwithstanding difficulties in accessing rig slots in the Southern Gas Basin of the United Kingdom North Sea, Arthur 3 was drilled and completed and began producing in early third quarter. In addition to EOG's ongoing production from Valkyrie and Arthur Fields, EOG participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f. The Columbus well was a farm-in opportunity, and its future appraisal and development is currently being evaluated.
	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. At December 31, 2006, EOG's debt-to-total capitalization ratio was 12%, down from 19% at year-end 2005. By primarily utilizing cash on hand and cash provided from its operating activities, EOG funded its $2,974 million exploration and development expenditures, paid down $317 million of debt, paid dividends to common shareholders of $60 million and redeemed $47 million of preferred stock. As management continues to assess price forecast and demand trends for 2007, EOG believes that operations and capital expenditure activity can be largely funded by cash from operations.
	For 2007, EOG's estimated exploration and development expenditure budget is approximately $3.4 billion, excluding acquisitions. United States and Canada natural gas drilling activity continues to be a key component of these expenditures. 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.
	On September 15, 2006, EOG filed an automatically effective shelf registration statement on Form S-3 (New Registration Statement) for the offer and sale from time to time of up to $688,237,500 of EOG's debt securities, preferred stock and common stock. The New Registration Statement was filed to replace EOG's existing shelf registration statement declared effective by the Securities and Exchange Commission (SEC) in October 2000, under which EOG had sold no securities. As of February 26, 2007, the entire amount registered remains available under the New Registration Statement.
	On October 11, 2006, EOG commenced a cash tender offer to purchase any and all of the 100,000 outstanding shares of the 7.195% Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 Liquidation Preference per share (Series B), at a price of $1,074.01 per share plus accrued and unpaid dividends up to the date of purchase. The tender offer expired on November 8, 2006, and on November 10, 2006, EOG redeemed 46,740 shares of the Series B for an aggregate purchase price, including redemption premium, fees and dividends, of $51 million. EOG has included as a component of preferred dividends the $4 million of premium and fees associated with the redemption of the Series B shares. A total of 53,260 shares of the Series B remain outstanding at December 31, 2006.
	Stock-Based Compensation. EOG adopted Statement of Financial Accounting Standards (SFAS) No. 123(R), "Share-Based Payment" effective January 1, 2006 using the modified prospective application method and accordingly has not restated any of its prior year results. See Note 6 to Consolidated Financial Statements. Prior to the adoption of SFAS No. 123(R), EOG recognized compensation expense for its stock-based compensation plans under the provisions of Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." Stock-based compensation expense prior to January 1, 2006 consisted of amounts recognized in connection with grants of restricted stock and units. The adoption of SFAS No. 123(R) resulted in EOG recognizing compensation expense on grants made under its employee stock option plans and its employee stock purchase plan. For periods subsequent to January 1, 2006, stock-based compensation expense is included in the Consolidated Statements of Income based upon job functions of employees receiving the grants. For the years ended December 31, 2006, 2005 and 2004, EOG compensation expense related to its stock-based compensation plans was as follows (in millions):
Lease and Well
$
$
-
$
-
Exploration Costs
-
-
General and Administrative
Total
$
$
$
Results of Operations
	The following review of operations for each of the three years in the period ended December 31, 2006 should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning with page.
	Net Operating Revenues
During 2006, net operating revenues increased $284 million, or 8%, to $3,904 million from $3,620 million in 2005. Total wellhead revenues, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, decreased $42 million, or 1%, to $3,565 million from $3,607 million in 2005. Wellhead volume and price statistics for the years ended December 31, were as follows:
(1)	Million cubic feet per day or thousand barrels per day, as applicable.
(2)	Dollars per thousand cubic feet or per barrel, as applicable.
(3)	Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and
natural gas liquids. Natural gas equivalents are determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil,
condensate or natural gas liquids.
(4)	Includes $0.23 per Mcf as a result of a revenue adjustment related to an amended Trinidad take-or-pay contract.
	2006 compared to 2005. Wellhead natural gas revenues for 2006 decreased $136 million, or 5%, to $2,803 million from $2,939 million for 2005 due to a lower composite average wellhead natural gas price ($407 million) and a second quarter 2005 revenue adjustment related to an amended Trinidad take-or-pay contract ($19 million), partially offset by increased natural gas deliveries ($290 million). The composite average wellhead natural gas price decreased 13% to $5.74 per Mcf for 2006 from $6.62 per Mcf in 2005. The Trinidad take-or-pay contract adjustment increased the average Trinidad wellhead natural gas price by $0.23 per Mcf for 2005.
	Natural gas deliveries increased 121 MMcfd, or 10%, to 1,337 MMcfd for 2006 from 1,216 MMcfd in 2005. The increase was due to higher production of 99 MMcfd in the United States and 33 MMcfd in Trinidad, partially offset by lower production of 9 MMcfd in the United Kingdom and 2 MMcfd in Canada. The increase in the United States was primarily attributable to increased production from Texas (83 MMcfd), the Rocky Mountain area (24 MMcfd) and Kansas (7 MMcfd), partially offset by decreased production in the Gulf of Mexico (16 MMcfd). The decrease in Gulf of Mexico production was partially due to continued shut-in production caused by infrastructure damage from hurricanes Katrina and Rita. The increase in Trinidad was due to the commencement of two contracts late in the fourth quarter of 2005 (43 MMcfd) and increased contractual demand (34 MMcfd), partially offset by a decrease in volumes as a result of the December 2005 completion of a cost recovery arrangement (44 MMcfd). The decrease in production in the United Kingdom was a result of production declines in both the Arthur and Valkyrie fields.
	Wellhead crude oil and condensate revenues increased $54 million, or 9%, to $625 million from $571 million as compared to 2005, due to an increase in the composite average wellhead crude oil and condensate price ($78 million), partially offset by a decrease in the wellhead crude oil and condensate deliveries ($24 million). The composite average wellhead crude oil and condensate price for 2006 was $62.38 per barrel compared to $54.63 per barrel for 2005.
	Natural gas liquids revenues increased $40 million, or 41%, to $137 million from $97 million as compared to 2005, due to increases in deliveries ($24 million) and the composite average price ($16 million).
	During 2006, EOG recognized gains on mark-to-market financial commodity derivative contracts of $334 million, which included realized gains of $215 million. During 2005, EOG recognized gains on mark-to-market financial commodity derivative contracts of $10 million, which included realized gains of $10 million.
	2005 compared to 2004. Wellhead natural gas revenues for 2005 increased $1,097 million, or 60%, to $2,939 million from $1,842 million for 2004 due to a higher composite average wellhead natural gas price ($763 million), increased natural gas deliveries ($315 million) and a second quarter 2005 revenue adjustment related to an amended Trinidad take-or-pay contract ($19 million). The composite average wellhead natural gas price increased 36% to $6.62 per Mcf for 2005 from $4.86 per Mcf in 2004. Excluding the aforementioned adjustment, the composite average wellhead natural gas price increased 35% to $6.58 per Mcf for 2005. This adjustment increased the average Trinidad wellhead natural gas price by $0.23 per Mcf for 2005.
	Natural gas deliveries increased 180 MMcfd, or 17%, to 1,216 MMcfd for 2005 from 1,036 MMcfd in 2004. The increase was due to higher production of 87 MMcfd in the United States, 45 MMcfd in Trinidad, 32 MMcfd in the United Kingdom and 16 MMcfd in Canada. The increase in the United States was primarily attributable to increased production from Texas (63 MMcfd) and Louisiana (20 MMcfd). The increase in Trinidad was due to the increased contractual requirements and demand related to the ammonia and methanol plants. The increase in the United Kingdom was due to the commencement of production from the Arthur field in January 2005 (24 MMcfd) and the full year production from the Valkyrie field, which commenced production in August 2004 (8 MMcfd). The increase in Canada was attributable to the drilling program, primarily in the Wapiti, Drumheller and Connorsville areas.
	Wellhead crude oil and condensate revenues increased $168 million, or 42%, to $571 million from $403 million as compared to 2004, due to increases in both the composite average wellhead crude oil and condensate price ($151 million) and the wellhead crude oil and condensate deliveries ($17 million). The composite average wellhead crude oil and condensate price for 2005 was $54.63 per barrel compared to $40.22 per barrel for 2004.
	Natural gas liquids revenues increased $42 million, or 76%, to $97 million from $55 million as compared to 2004, due to increases in the composite average price ($23 million) and deliveries ($19 million).
	During 2005, EOG recognized gains on mark-to-market financial commodity derivative contracts of $10 million, which included realized gains of $10 million. During 2004, EOG recognized losses on mark-to-market financial commodity derivative contracts of $33 million, which included realized losses of $82 million and collar premium payments of $1 million.
	Operating and Other Expenses
2006 compared to 2005. During 2006, operating expenses of $2,009 million were $381 million higher than the $1,628 million incurred in 2005. The following table presents the costs per Mcfe for the years ended December 31:
(1)	Total per-unit costs do not include exploration costs, dry hole costs and impairments.
	The change in per-unit rates of lease and well, transportation costs, DD&A, G&A, taxes other than income and net interest expense for 2006 as compared to 2005 were due primarily to the reasons 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 EOG's oil and natural gas wells, the cost of workovers, and lease and well administrative expenses. Operating and maintenance expenses include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep, and fuel and power. Workovers are costs of 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 costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.
	Lease and well expenses of $373 million in 2006 were $86 million higher than 2005 due primarily to higher operating and maintenance expenses in the United States ($34 million) and Canada ($16 million); higher lease and well administrative expenses ($21 million), including stock-based compensation expense ($10 million); changes in the Canadian exchange rate ($6 million); and higher workover expenditures in the United States ($6 million).
	Transportation costs represent costs incurred directly by EOG from third-party carriers associated with the delivery of hydrocarbon products from the lease to a down-stream point of sale. Transportation costs include the cost of compression (compressing natural gas to meet pipeline pressure requirements), dehydration (removing water from natural gas to meet pipeline requirements), gathering fees, fuel costs and transportation fees.
	Transportation costs of $110 million in 2006 were $23 million higher than 2005 due primarily to increased production in the Fort Worth Basin Barnett Shale play.
	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; and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from year to year.
	DD&A expenses of $817 million in 2006 were $163 million higher than 2005 primarily due to higher unit rates described below and as a result of increased production in the United States ($56 million) and Trinidad ($3 million), partially offset by a decrease in production in the United Kingdom ($4 million). DD&A rates increased due primarily to a gradual proportional increase in production from higher cost properties in the United States ($78 million) and Canada ($11 million), and a downward reserve revision in the United Kingdom ($11 million). The Canadian exchange rate also contributed to the DD&A expense increase ($9 million).
	G&A expenses of $165 million in 2006 were $39 million higher than 2005 due primarily to higher employee-related costs ($31 million) and higher insurance costs ($4 million). The increase in employee-related costs primarily reflects higher stock-based compensation expenses ($17 million).
	Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Taxes other than income of $201 million in 2006 were $2 million higher than 2005.
	Severance taxes in the United States decreased primarily due to increased credits taken for Texas high cost gas severance tax rate reductions ($14 million). Severance/production taxes in Trinidad increased due primarily to increased wellhead revenues from crude oil and condensate ($12 million), partially offset by changes to the tax legislation governing the Supplemental Petroleum Tax ($7 million). Ad valorem/property taxes increased primarily due to higher property valuation in the United States ($7 million) and Canada ($2 million).
	Net interest expense of $43 million in 2006 decreased $19 million compared to 2005 primarily due to lower average debt balance ($9 million), costs in 2005 associated with the early retirement of the 6.00% Notes due 2008 ($8 million), and higher capitalized interest ($5 million).
	Exploration costs of $155 million in 2006 were $22 million higher than 2005 due primarily to higher employee-related costs, including stock-based compensation expenses.
	Impairments include amortization of unproved leases, as well as impairments under SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $108 million in 2006 were $30 million higher than 2005 due primarily to increased SFAS No. 144 related impairments in the United States ($17 million) and Canada ($7 million) and higher amortization of unproved leases in Canada ($4 million) and the United States ($2 million). EOG recorded impairments of $55 million and $31 million for 2006 and 2005, respectively, under SFAS No. 144 for properties in the United States and Canada.
	Other income, net was $60 million in 2006 compared to $36 million in 2005. The increase of $24 million was primarily due to higher interest income ($19 million), settlements received related to the Enron Corp. bankruptcy ($4 million) and increased net foreign currency transaction gains ($3 million), partially offset by lower gains on sales of properties ($5 million).
	Income tax provision of $613 million in 2006 decreased $93 million compared to 2005 due primarily to a net decrease in foreign income taxes ($37 million), largely related to a Canadian federal tax rate reduction ($19 million) and an Alberta, Canada corporate tax rate reduction ($13 million), partially offset by a United Kingdom corporate tax rate increase ($7 million); reduced income taxes associated with the repatriation of foreign earnings in 2005 ($24 million); decreased pretax income ($18 million); and reduced state income taxes ($18 million), partially offset by a decrease in the Domestic Production Activities Deduction ($7 million). The effective tax rate for 2006 decreased to 32% from 36% in 2005.
2005 compared to 2004. During 2005, operating expenses of $1,628 million were $336 million higher than the $1,292 million incurred in 2004. The following table presents the costs per Mcfe for the years ended December 31:
(1)	Total per-unit costs do not include exploration costs, dry hole costs and impairments.
	The per-unit rates of lease and well, including transportation, DD&A, taxes other than income and interest expense, net for 2005 compared to 2004 were due primarily to the reasons set forth below.
	Lease and well expenses, including transportation, of $373 million were $102 million higher than 2004 due primarily to higher operating and maintenance expenses in the United States ($40 million); increased transportation related costs in the United States ($28 million) and the United Kingdom ($7 million); higher lease and well administrative expenses in the United States ($11 million); changes in the Canadian exchange rate ($6 million); and higher workover expenditures in the United States ($3 million) and Trinidad ($2 million).
	DD&A expenses of $654 million in 2005 were $150 million higher than 2004 primarily as a result of increased production in the United States ($46 million), Canada ($6 million) and Trinidad ($5 million) and the commencement of production in the United Kingdom ($14 million). DD&A rates increased in the United States due to a gradual proportional increase in production from higher cost properties ($59 million) and in Canada predominantly from the development of acquired proved reserves ($9 million). The Canadian exchange rate also contributed to the DD&A expense increase ($8 million).
	Taxes other than income of $199 million in 2005 were $65 million higher than 2004. Severance/production taxes increased due primarily to increased wellhead revenues in the United States ($41 million), Trinidad ($7 million) and Canada ($3 million), partially offset by the increase in credits taken for Texas high cost gas severance tax rate reductions ($10 million) and a production tax audit lawsuit in the first quarter of 2004 ($5 million). Other items contributing to the increase were an additional Trinidadian Supplemental Petroleum Tax expense as a result of 2005 tax legislation that increased the tax expense retroactively to January 2004 ($7 million) and 2004 production tax relief in Trinidad ($6 million). Ad valorem/property taxes increased primarily due to higher property valuation in the United States ($11 million).
	Net interest expense in 2005 included costs associated with the early retirement of the 2008 Notes ($8 million) (see Note 2 to Consolidated Financial Statements). Excluding these early retirement costs, the 2005 net interest expense decreased $8 million compared to 2004 primarily due to higher capitalized interest ($5 million), an interest charge related to the results of a production tax audit lawsuit in the first quarter of 2004 ($2 million) and lower average debt balance in the United States ($1 million).
	Exploration costs of $133 million in 2005 were $39 million higher than 2004 due primarily to increased geological and geophysical expenditures in the Fort Worth Basin Barnett Shale play.
	Impairments of $78 million were $4 million lower than 2004 due primarily to lower amortization of unproved leases in the United States ($12 million) and lower impairments to the carrying value of certain long-lived assets in Canada ($8 million), partially offset by higher impairments to the carrying value of certain long-lived assets in the United States ($14 million) and higher amortization of unproved leases in Canada ($2 million). EOG recorded impairments of $31 million and $25 million for 2005 and 2004, respectively, under SFAS No. 144 for certain properties in the United States and Canada.
	Other income, net of $36 million in 2005 increased $26 million compared to 2004 primarily as a result of higher gains on sales of properties ($7 million), interest income ($6 million) and equity income from investments in the Caribbean Nitrogen Company Limited (CNCL) and Nitrogen (2000) Unlimited (N2000) ammonia plants in 2005
	($5 million); decreased net foreign currency transaction losses ($4 million); and a gain on the sale of part of EOG's interest in the N2000 ammonia plant in the first quarter of 2005 ($2 million).
	Income tax provision of $706 million increased $404 million as compared to 2004, due primarily to higher pretax income ($383 million) and income taxes associated with the repatriation of foreign earnings ($24 million). The effective tax rate for 2005 increased to 36% from 33% in 2004.
Capital Resources and Liquidity
	Cash Flow
	The primary sources of cash for EOG during the three-year period ended December 31, 2006 included funds generated from operations, funds from new borrowings, proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan, and proceeds from the sale of oil and gas properties. The primary uses of cash were funds used in operations, exploration and development expenditures, repayment of debt, dividend payments to shareholders and redemption of preferred stock.
	2006 compared to 2005. Net cash provided by operating activities of $2,579 million in 2006 increased $209 million compared to 2005 primarily reflecting a favorable change in the net cash flows from settlement of financial commodity derivative contracts ($205 million), favorable changes in working capital and other liabilities ($162 million) and a decrease in cash paid for income taxes and interest expense ($54 million), partially offset by an increase in cash operating expenses ($173 million) and a decrease in wellhead revenues ($42 million).
	Net cash used in investing activities of $2,710 million in 2006 increased by $1,032 million compared to 2005 due primarily to increased additions to oil and gas properties ($1,094 million) and decreased proceeds from sales of oil and gas properties ($51 million), partially offset by favorable changes in working capital related to investing activities ($125 million). Changes in Components of Working Capital Associated with Investing Activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent material and equipment used in drilling and related activities.
	Cash used in financing activities of $299 million in 2006 increased $227 million compared to 2005. Cash used by financing activities for 2006 included repayments of long-term debt borrowings ($317 million), cash dividend payments ($60 million) and redemption of preferred stock, including premium paid ($50 million). Cash provided by financing activities for 2006 included borrowing under a revolving credit facility ($65 million), proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan ($36 million) and excess tax benefits from stock-based compensation expenses ($28 million).
	2005 compared to 2004. Net cash provided by operating activities of $2,369 million in 2005 increased $925 million as compared to 2004 primarily reflecting an increase in wellhead revenues ($1,306 million), a favorable change in the net cash flows from settlement of financial commodity derivative contracts ($93 million) and favorable changes in working capital and other liabilities ($35 million), partially offset by an increase in cash operating expenses ($217 million) and an increase in cash paid for income taxes ($279 million).
	Net cash used in investing activities of $1,678 million in 2005 increased by $281 million as compared to 2004 due primarily to increased additions to oil and gas properties ($308 million) and unfavorable changes in working capital related to investing activities ($28 million), partially offset by an increase in proceeds from the sale of oil and gas properties in 2005 ($40 million) and the sale of part of EOG's interest in the N2000 ammonia plant in 2005 ($18 million). Changes in Components of Working Capital Associated with Investing Activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent material and equipment used in drilling and related activities.
	Cash used in financing activities of $72 million in 2005 increased $29 million as compared to 2004. Cash provided by financing activities for 2005 included a long-term debt borrowing ($250 million) and proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan ($65 million). Cash used by financing activities for 2005 included repayments of long-term debt borrowings ($343 million) and cash dividend payments ($43 million).
	Total Exploration and Development Expenditures
	The table below sets out components of total exploration and development expenditures for the years ended December 31, 2006, 2005 and 2004, along with the total budgeted for 2007, excluding acquisitions (in millions):
	Exploration and development expenditures of $2,974 million for 2006 were $1,116 million higher than the prior year due primarily to increased drilling and facilities expenditures of $1,014 million resulting from higher drilling and facilities expenditures in the United States ($843 million), Trinidad ($79 million), Canada ($57 million) and the United Kingdom ($13 million); increased lease acquisitions in the United States ($74 million) and Canada ($16 million); and changes in the Canadian exchange rate ($28 million). The 2006 exploration and development expenditures of $2,974 million includes $2,228 million in development, $704 million in exploration, $22 million in property acquisitions and $20 million in capitalized interest. The 2005 exploration and development expenditures of $1,858 million includes $1,300 million in development, $487 million in exploration, $56 million in property acquisitions and $15 million in capitalized interest. The 2004 exploration and development expenditures of $1,511 million includes $1,009 million in development, $440 million in exploration, $52 million in property acquisitions and $10 million in capitalized interest.
	The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in the United States, Canada, Trinidad and the United Kingdom, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.
	Derivative Transactions
	During 2006, EOG recognized gains on mark-to-market financial commodity derivative contracts of $334 million, which included realized gains of $215 million. During 2005, EOG recognized gains on mark-to-market financial commodity derivative contracts of $10 million, which included realized gains of $10 million. (See Note 11 to Consolidated Financial Statements.)
	Presented below is a comprehensive summary of EOG's 2007 natural gas and crude oil financial price swap contracts at February 26, 2007, with prices expressed in dollars per million British thermal units ($/MMBtu) and in dollars per barrel ($/Bbl), as applicable, and notional volumes in million British thermal units per day (MMBtud) and in barrels per day (Bbld), as applicable. Currently, EOG is not a party to any financial collar contracts. EOG accounts for these price swap contracts using the mark-to-market accounting method.
	(1) The natural gas contracts for February 2007 are closed. The crude oil contracts
for February 2007 will close on February 28, 2007.
	Financing
	EOG's debt-to-total capitalization ratio was 12% as of December 31, 2006 compared to 19% as of December 31, 2005.
	During 2006, total debt decreased $252 million to $733 million (see Note 2 to Consolidated Financial Statements). The estimated fair value of EOG's debt at December 31, 2006 and 2005 was $754 million and $1,025 million, respectively. The estimated fair value was based upon quoted market prices and, where such prices were not available, upon interest rates available to EOG at year-end. EOG's debt is primarily at fixed interest rates. At December 31, 2006, a 1% decline in interest rates would result in a $39 million increase in the estimated fair value of the fixed rate obligations (see Note 11 to Consolidated Financial Statements).
	During 2006 and 2005, EOG utilized cash provided by operating activities and commercial paper to fund its operations. While EOG maintains a $600 million commercial paper program, the maximum outstanding at any time during 2006 was $172 million, and the amount outstanding at year-end was zero. EOG considers this excess availability, which is backed by the $600 million Revolving Credit Agreement with domestic and foreign lenders described in Note 2 to Consolidated Financial Statements, combined with approximately $688 million of availability under its shelf registration described below, to be ample to meet its ongoing operating needs.
	During 2006, EOG repaid the $126 million, 6.70% Notes due in 2006 primarily with cash generated from operating activities. In 2006, a foreign subsidiary of EOG repaid $190 million of the $250 million borrowed in 2005 (see Note 2 to Consolidated Financial Statements). The foreign subsidiary has the option to pay off the remaining $60 million of the $250 million borrowed in 2005 at any time prior to maturity. EOG plans to replace the $98 million, 6.50% Notes due 2007 with other long-term debt.
	On October 11, 2006, EOG commenced a cash tender offer to purchase any and all of the 100,000 outstanding shares of the 7.195% Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 Liquidation Preference per share (Series B), at a price of $1,074.01 per share plus accrued and unpaid dividends up to the date of purchase. The tender offer expired on November 8, 2006, and on November 10, 2006, EOG redeemed 46,740 shares of the Series B for an aggregate purchase price, including redemption premium, fees and dividends, of
	$51 million. EOG has included as a component of preferred dividends the $4 million of premium and fees associated with the redemption of the Series B shares. A total of 53,260 shares of the Series B remain outstanding at December 31, 2006.
	Contractual Obligations
	The following table summarizes EOG's contractual obligations at December 31, 2006 (in thousands):
(1)	This table does not include the liability for dismantlement, abandonment and restoration costs of oil and gas properties. In addition,
this table does not include EOG's pension or postretirement benefit obligations (see Note 6 to Consolidated Financial Statements).
(2)	Amounts shown are based on current pipeline transportation rates and the foreign currency exchange rates used to convert Canadian
Dollars and British Pounds into United States Dollars at December 31, 2006. Management does not believe that any future changes
in these rates before the expiration dates of these commitments will have a material adverse effect on the financial condition or results
of operations of EOG.
(3)	Amounts shown represent minimum future expenditures for drilling rig services.
Shelf Registration
	On September 15, 2006, EOG filed an automatically effective shelf registration statement on Form S-3 (New Registration Statement) for the offer and sale from time to time of up to $688,237,500 of EOG's debt securities, preferred stock and common stock. The New Registration Statement was filed to replace EOG's existing shelf registration statement declared effective by the SEC in October 2000, under which EOG had sold no securities. As of February 26, 2007, the entire amount registered remains available under the New Registration Statement.
	Off-Balance Sheet Arrangements
	EOG does not participate in financial transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities, often referred to as variable interest entities (VIE) or special purpose entities (SPE), are generally established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. EOG was not involved in any unconsolidated VIE or SPE financial transactions or any other off-balance sheet arrangements during any of the reporting periods in this document and has no intention to participate in such transactions or arrangements in the foreseeable future.
	Foreign Currency Exchange Rate Risk
	During 2006, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Canada, Trinidad and the United Kingdom. The foreign currency most significant to EOG's operations during 2006 was the Canadian Dollar. The fluctuation of the Canadian Dollar in 2006 impacted both the revenues and expenses of EOG's Canadian subsidiaries. However, since the Canadian natural gas prices are largely correlated to United States prices, the changes in the Canadian currency exchange rate have less of an impact on the Canadian revenues than the Canadian expenses. EOG continues to monitor the foreign currency exchange rates of countries in which it is currently conducting business and may implement measures to protect against the foreign currency exchange rate risk.
	Effective March 9, 2004, EOG entered into a foreign currency swap transaction with multiple banks to eliminate any exchange rate impacts that may result from the notes offered by one of the Canadian subsidiaries on the same date (see Note 2 to Consolidated Financial Statements). EOG accounts for the foreign currency swap transaction using the hedge accounting method, pursuant to the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137, 138 and 149. Under those provisions, as of December 31, 2006, EOG recorded the fair value of the swap of $36 million in Other Liabilities on the Consolidated Balance Sheets. Changes in the fair value of the foreign currency swap resulted in no net impact to Net Income Available to Common on the Consolidated Statements of Income and Comprehensive Income. The after-tax net impact from the foreign currency swap transaction resulted in a negative change of $1 million for the year ended December 31, 2006. This amount is included in Accumulated Other Comprehensive Income in the Shareholders' Equity section of the Consolidated Balance Sheets.
	Outlook
	Natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of future United States and Canada natural gas and crude oil price trends, and there remains a rather wide divergence in the opinions held by some in the industry. Being primarily a natural gas producer, EOG is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. Longer term natural gas prices will be determined by the supply and demand for natural gas as well as the prices of competing fuels, such as oil and coal.
	Assuming a totally unhedged position for 2007, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2007 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $27 million for net income and operating cash flow. EOG's price sensitivity in 2007 for each $1.00 per barrel change in wellhead crude oil price is approximately $6 million for net income and operating cash flow. For information regarding EOG's natural gas and crude oil hedge position as of December 31, 2006, see Note 11 to Consolidated Financial Statements.
	EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States and Canada. However, in order to diversify its overall asset portfolio and as a result of its overall success realized in Trinidad and the United Kingdom North Sea, EOG anticipates expending a portion of its available funds in the further development of opportunities outside the United States and Canada. In addition, EOG expects to conduct exploratory activity in other areas outside of the United States and Canada and will continue to evaluate the potential for involvement in additional exploitation type opportunities. Budgeted 2007 exploration and development expenditures, excluding acquisitions, are approximately $3.4 billion and are structured to maintain the flexibility necessary under EOG's strategy of funding its exploration, development, exploitation and acquisition activities primarily from available internally generated cash flow.
	The level of exploration and development expenditures may vary in 2007 and will vary in future periods depending on energy market conditions and other related economic factors. Based upon existing economic and market conditions, EOG believes net operating cash flow and available financing alternatives in 2007 will be sufficient to fund its net investing cash requirements for the year. However, EOG has significant flexibility with respect to its financing alternatives and adjustment of its exploration, exploitation, development and acquisition expenditure plans if circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in the United States, Canada, Trinidad and the United Kingdom, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.
	Environmental Regulations
	Various foreign, federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, affect EOG's operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations and could cause EOG to incur remediation or other corrective action costs in connection with a release of regulated substances, including crude oil, into the environment. In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, EOG could be responsible under environmental laws and regulations for oil and gas properties in which EOG owns an interest but is not the operator. Compliance with such
	laws and regulations increases EOG's overall cost of business, but has not had a material adverse effect on EOG's operations or financial condition. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program in order to comply with environmental laws and regulations but, inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance. EOG also could incur costs related to the clean up of sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such sites.
Summary of Critical Accounting Policies
	EOG prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which requires management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. EOG identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of EOG's financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Following is a discussion of EOG's most critical accounting policies:
Proved Oil and Gas Reserves
	EOG's engineers estimate proved oil and gas reserves, which directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.
	Oil and Gas Exploration Costs
	Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is complete if it is determined that there is economic producibility supported by either actual production, a conclusive formation test or by certain technical data if the discovery is located offshore in the Gulf of Mexico. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of December 31, 2006 and 2005, EOG had exploratory drilling costs related to two projects that have been deferred for more than one year (see Note 15 to Consolidated Financial Statements). These costs meet the accounting requirements outlined above for continued capitalization. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and crude oil, are capitalized.
	Impairments
	Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
	When circumstances indicate that a producing asset may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future
	undiscounted cash flows, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
	Depreciation, Depletion and Amortization for Oil and Gas Properties
	The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively.
	Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.
	Assets are grouped in accordance with paragraph 30 of SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
	Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions, and 4) impairments.
Stock-Based Compensation
	Effective January 1, 2006, EOG accounts for stock-based compensation under the provisions of SFAS No. 123(R), "Share Based Payment." SFAS No. 123(R) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, eliminating the exception to account for such awards using the intrinsic method previously allowable under APB Opinion No. 25, "Accounting for Stock Issued to Employees." In applying the provisions of SFAS 123(R), judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs required by those valuation methodologies. Assumptions regarding expected volatility of EOG's common stock, the level of risk free interest rates, expected dividend yields on EOG's stock, the expected term of the awards and other valuation inputs are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized in the Consolidated Statements of Income and Comprehensive Income.
Information Regarding Forward-Looking Statements
	This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts, including, among others, statements regarding EOG's future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "strategy," "intend," "plan," "target" and "believe" or the negative of those terms or other variations of them or by comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning future operating results, the ability to replace or increase reserves or to increase production, or the ability to generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes its expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, among others: the timing and extent of changes in commodity prices for crude oil, natural gas and related products, foreign currency exchange rates and interest rates; the timing and impact of liquefied natural gas imports and changes in demand or prices for ammonia or methanol; the extent and effect of any hedging activities engaged in by EOG; the extent of EOG's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; the availability and cost of drilling rigs, experienced drilling crews, materials and equipment used in well completions, and tubular steel; the availability, terms and timing of governmental and other permits and rights of way; the availability of pipeline transportation capacity; the availability of compression uplift capacity; the extent to which EOG can economically develop its Barnett Shale acreage outside of Johnson County, Texas; whether EOG is successful in its efforts to more densely develop its acreage in the Barnett Shale and other production areas; political developments around the world; acts of war and terrorism and responses to these acts; weather; and financial market conditions. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements might not occur. Forward-looking statements speak only as of the date made and EOG undertakes no obligation to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise.
ITEM 7A.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
	EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in the Derivative Transactions, Financing, Foreign Currency Exchange Rate Risk and Outlook sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity."
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data
	Information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page.
ITEM 9.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
	None.
ITEM 9A.
ITEM 9A. Controls and Procedures
Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this report (Evaluation Date). Based on this evaluation, the principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date to ensure that information that is required to be disclosed by EOG in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to EOG's management as appropriate to allow timely decisions regarding required disclosure.
Management's Report on Internal Control over Financial Reporting. EOG's management is responsible for establishing and maintaining effective internal control over financial reporting (as defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act). Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of an internal control system in future periods can change with conditions.
	EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2006. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on this assessment, management believes that, as of December 31, 2006, EOG's internal control over financial reporting is effective based on those criteria. EOG's assessment also appears on page.
	EOG's independent registered public accounting firm has issued an audit report on EOG's assessment of its internal control over financial reporting. This report begins on page.
	There were no changes in EOG's internal control over financial reporting that occurred during the fiscal quarter ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.
ITEM 9B.
ITEM 9B. Other Information
	None.
	PART III
ITEM 10.
ITEM 10. Directors, Executive Officers and Corporate Governance
	Directors and Executive Officers of the Registrant. The information required by this Item regarding directors is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2006, under the caption "Election of Directors" of Item 1.
	Audit Committee and Corporate Governance Related Matters and Code of Ethics for the CEO and CFO. The information required by this Item regarding audit committee related matters is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2006, under the caption "Corporate Governance."
	Compliance with Section 16(a) of the Exchange Act. The information required by this Item regarding compliance with Section 16(a) of the Exchange Act is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2006, under the caption "Section 16(a) Beneficial Ownership Reporting Compliance."
ITEM 11.
ITEM 11. Executive Compensation
	The information required by this Item is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2006, under the captions "Executive Compensation " and "Director Compensation."
ITEM 12.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
	The information required by this Item with respect to security ownership of certain beneficial owners and management is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2006, under the caption "Voting Rights and Principal Stockholders."
Equity Compensation Plan Information
	EOG has various plans under which employees and nonemployee members of the Board of Directors of EOG and its subsidiaries have been or may be granted certain equity compensation consisting of stock options, restricted stock, restricted stock units and phantom stock. The 1992 Stock Plan, the 1993 Nonemployee Directors Stock Option Plan and the Employee Stock Purchase Plan have been approved by security holders. Plans that have not been approved by security holders are described below. The following table sets forth data for EOG's equity compensation plans aggregated by the various plans approved by security holders and those plans not approved by security holders as of December 31, 2006.
(c)
Number of Securities
(a)
(b)
Remaining Available
Number of Securities to be
Weighted-Average
for Future Issuance Under
Issued Upon Exercise of
Exercise Price of
Equity Compensation
Outstanding Options,
Outstanding Options,
Plans (Excluding Securities
Plan Category
Warrants and Rights
Warrants and Rights
Reflected in Column (a))
Equity Compensation
Plans Approved by
Security Holders
8,184,012
$43.40
3,135,549(1) (2)
Equity Compensation
Plans Not Approved
by Security Holders
4,329,301
$20.18(3)
131,667(4) (5)
Total
12,513,313
$35.44(3)
3,267,216
(1)	Of these securities, 315,762 shares remain available for purchase under the Employee Stock Purchase Plan.
(2)	Of these securities, 1,254,466 could be issued as restricted stock or restricted stock units under the 1992 Stock Plan.
(3)	Weighted-average exercise price does not include 62,098 phantom stock units in the 1996 Deferral Plan which are included in column (a).
(4)	Of these securities, 34,051 phantom stock units remain available for issuance under the 1996 Deferral Plan.
(5)	Of these securities, 97,616 could be issued as restricted stock or restricted stock units under the 1994 Stock Plan.
	Stock Plan Not Approved by Security Holders. The Board of Directors of EOG approved the 1994 Stock Plan, which provides equity compensation to employees who are not officers within the meaning of Rule 16a-1 of the Securities Exchange Act of 1934, as amended. Under the plan, employees have been or may be granted stock options (rights to purchase shares of EOG common stock at a price not less than the market price of the stock at the date of grant). Stock options vest either immediately at the date of grant or up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Terms for stock options granted under the plan have not exceeded a maximum term of 10 years. Employees have also been or may be granted shares of restricted stock and/or restricted stock units without cost to the employee. The shares and units granted vest to the employee at various times ranging from one to five years as defined in individual grant agreements. Upon vesting, restricted shares are released to the employee. Upon vesting, each restricted stock unit is converted into one share of EOG common stock and released to the employee.
	Deferral Plan Phantom Stock Account. The Board of Directors of EOG approved the 1996 Deferral Plan, under which payment of base salary, annual bonus and directors fees may be deferred into a phantom stock account. In the phantom stock account, deferrals are treated as if shares of EOG common stock were purchased at the closing stock price on the date of deferral. Dividends are credited quarterly and treated as if reinvested in EOG common stock. Payment of the phantom stock account is made in actual shares of EOG common stock. A total of 120,000 shares have been registered for issuance under the plan. As of December 31, 2006, 85,949 phantom stock units had been issued and 34,051 units remained available for issuance under the plan.
ITEM 13.
ITEM 13. Certain Relationships and Related Transactions, and Director Independence
	Information regarding Certain Relationships and Related Transactions is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2006, under the caption "Related Party Transactions."
	Information regarding Director Independence is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2006, under the caption "Corporate Governance."
ITEM 14.
ITEM 14. Principal Accounting Fees and Services
	Information regarding auditor fees, audit-related fees, tax fees and all other fees and services billed by the principal accountant is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2006, under the caption "Ratification of Appointment of Auditors - General" of Item 2.
	PART IV
ITEM 15.
ITEM 15. Exhibits and Financial Statement Schedules
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedule
	 	See "Index to Financial Statements" set forth on page.
(a)(3)	Exhibits
	 	See pages E-1 through E-4 for a listing of the exhibits.
EOG RESOURCES, INC.
Other financial statement schedules have been omitted because they are inapplicable or the information required
therein is included elsewhere in the consolidated financial statements or notes thereto.
	MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
	The following consolidated financial statements of EOG Resources, Inc. and its subsidiaries (EOG) were prepared by management, which is responsible for their integrity, objectivity and fair presentation. The statements have been prepared in conformity with generally accepted accounting principles in the United States of America and, accordingly, include some amounts that are based on the best estimates and judgments of management.
	EOG's management is also responsible for establishing and maintaining effective internal control over financial reporting. The system of internal control of EOG is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. This system consists of 1) entity level controls, including written policies and guidelines relating to the ethical conduct of business affairs, 2) general computer controls and 3) process controls over initiating, authorizing, recording, processing and reporting transactions. Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of an internal control system in future periods can change with conditions.
	The adequacy of financial controls of EOG and the accounting principles employed in financial reporting by EOG are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of EOG. The independent registered public accounting firm and internal auditors have full, free, separate and direct access to the Audit Committee and meet with the committee from time to time to discuss accounting, auditing and financial reporting matters.
	EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2006. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. These criteria cover the control environment, risk assessment process, control activities, information and communication systems, and monitoring activities. Based on this assessment, management believes that, as of December 31, 2006, EOG's internal control over financial reporting is effective based on those criteria.
	Deloitte & Touche LLP, independent registered public accounting firm, was engaged to audit the consolidated financial statements and management's assessment of the effectiveness of EOG's internal control over financial reporting, and to issue a report thereon. In the conduct of the audit, Deloitte & Touche LLP was given unrestricted access to all financial records and related data including minutes of all meetings of shareholders, the Board of Directors and committees of the Board. Management believes that all representations made to Deloitte & Touche LLP during the audit were valid and appropriate. Their audit was made in accordance with standards of the Public Company Accounting Oversight Board (United States) and included a review of the system of internal controls to the extent considered necessary to determine the audit procedures required to support their opinion on the consolidated financial statements, management's assessment of EOG's internal control over financial reporting and the effectiveness of EOG's internal control over financial reporting. Their report begins on page.
MARK G. PAPA
EDMUND P. SEGNER, III
TIMOTHY K. DRIGGERS
Chairman of the Board and
Senior Executive Vice President and
Vice President and Chief
Chief Executive Officer
Chief of Staff
Accounting Officer
Houston, Texas
February 26, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
EOG Resources, Inc.
Houston, Texas
	We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. and subsidiaries (the "Company") as of December 31, 2006 and 2005, and the related consolidated statements of income and comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited management's assessment, included in the accompanying Management's Responsibility for Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule, an opinion on management's assessment, and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audits.
	We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
	A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
	Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
	In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EOG Resources, Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
	As discussed in Note 6 to the consolidated financial statements, on January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (R), "Share Based Payment."
DELOITTE & TOUCHE LLP
Houston, Texas
February 26, 2007
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In Thousands, Except Per Share Data)
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(In Thousands, Except Per Share Data)
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
	Principles of Consolidation. The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All material intercompany accounts and transactions have been eliminated.
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	Certain reclassifications have been made to prior period financial statements to conform with the current presentation.
	On February 2, 2005, EOG announced that the Board of Directors (Board) had approved a two-for-one stock split in the form of a stock dividend, payable to record holders as of February 15, 2005 and issued on March 1, 2005. All share and per share data in the financial statements and accompanying footnotes for all periods have been restated to reflect the two-for-one stock split paid to common shareholders.
Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, marketable securities, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt. The carrying values of cash and cash equivalents, marketable securities, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Note 11).
	Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.
	Oil and Gas Operations. EOG accounts for its natural gas and crude oil exploration and production activities under the successful efforts method of accounting.
	Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
	Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is complete if it is determined that there is economic producibility supported by either actual production, a conclusive formation test or by certain technical data if the discovery is located offshore in the Gulf of Mexico. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of December 31, 2006 and 2005, EOG had exploratory drilling costs related to two projects that have been deferred for more than one year (see Note 15). These costs meet the accounting requirements outlined above for continued capitalization. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and crude oil, are capitalized.
	Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.
	Assets are grouped in accordance with paragraph 30 of Statement of Financial Accounting Standards (SFAS) No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
	Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions, and 4) impairments.
	EOG accounts for impairments under the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." When circumstances indicate that an asset may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
	Inventories, consisting primarily of tubular goods and well equipment held for use in the exploration for and development and production of natural gas and crude oil reserves, are carried at cost with adjustments made from time to time to recognize any reductions in value.
	Arrangements for natural gas, crude oil, condensate and natural gas liquids sales are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered. A significant majority of the purchasers of these products have investment grade credit ratings and material credit losses have been rare. Revenues are recorded on the entitlement method based on EOG's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold on that owner's behalf may differ from that owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs.
	Capitalized Interest Costs. Interest capitalization is required for those properties if its effect, compared with the effect of expensing interest, is material. Accordingly, certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. The amount capitalized is an allocation of the interest cost incurred during the reporting period. Capitalized interest is computed only during the exploration and development activities and not on proved properties. The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings.
	Accounting for Price Risk Management Activities. EOG accounts for its price risk management activities under the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137, 138 and 149. The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. During the three-year period ending December 31, 2006, EOG elected not to designate any of its commodity price risk management activities as accounting hedges under SFAS No. 133, and accordingly, accounted for them using the mark-to-market accounting method. Under this accounting method, the changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. The gains or losses are recorded in Gains (Losses) on Mark-to-Market Commodity Derivative Contracts. The related cash flow impact is reflected as cash flows from operating activities (see Note 11).
	Income Taxes. EOG accounts for income taxes under the provisions of SFAS No. 109, "Accounting for Income Taxes." SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis (see Note 5).
	Foreign Currency Translation. For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Income. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period.
	Net Income Per Share. In accordance with the provisions of SFAS No. 128, "Earnings per Share," basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted net income per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities (see Note 8).
Stock-Based Compensation. Effective January 1, 2006, EOG accounts for stock-based compensation under the provisions of SFAS No. 123(R), "Share Based Payment." EOG adopted SFAS No. 123(R) using the modified prospective application method and has therefore not restated its previously issued financial statements. SFAS No. 123(R) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, eliminating the exception to account for such awards using the intrinsic method previously allowable under Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." Prior to the adoption of SFAS No. 123(R), EOG included tax benefits resulting from the exercise of stock options in the operating activities section of the Consolidated Statements of Cash Flows. SFAS No. 123(R) requires that cash flows provided by excess tax benefits from stock-based compensation deductions be reflected in the financing activities section of the Consolidated Statements of Cash Flows and Unearned Compensation previously included separately in Shareholders' Equity be written off against Additional Paid in Capital at the date of adoption.
	EOG has adopted the alternative transition method prescribed in FASB Staff Position (FSP) FAS 123R-3, "Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards," for calculating the beginning balance of excess tax benefits related to employee stock-based compensation included in additional paid in capital (APIC Pool). The APIC Pool represents the amount of tax benefits available to absorb future tax deficiencies that may result in connection with employee stock-based compensation. FSP FAS 123R-3 also provides a simplified method to determine the subsequent impact on the APIC Pool of stock-based compensation awards that are fully vested at the date of adoption of SFAS 123(R).
	Recently Issued Accounting Standards and Developments. In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Post Retirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)." SFAS No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its balance sheet. The funded status is defined as the difference between the fair value of plan assets and the projected benefit obligation (for pension plans) or the accumulated postretirement benefit obligation (for other postretirement benefit plans). SFAS No. 158 also requires that actuarial gains and losses and changes in prior service costs not included in net periodic pension costs be included, net of tax, as a component of other comprehensive income. The statement does not affect the determination of net periodic benefit costs included in the income statement. SFAS No. 158 also requires that an employer measure defined benefit plan assets and benefit obligations as of the date of the employer's fiscal year-end statement of financial position.
	The requirement to recognize the funded status of defined benefit plans and to provide required disclosures is effective as of the end of fiscal years ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer's fiscal year-end is effective for fiscal years ending after December 15, 2008. The adoption of the recognition and disclosure provisions of SFAS No. 158 did not have a material impact on EOG's financial statements. EOG does not expect that the adoption of the measurement date provisions of SFAS No. 158 will have a material impact on EOG's financial statements since plan assets and benefit obligations are currently measured as of the date of EOG's fiscal year end.
	In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements." SFAS No. 157 provides a definition of fair value and provides a framework for measuring fair value. The standard also requires additional disclosures on the use of fair value in measuring assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those years. EOG is assessing the impact, if any, that the adoption of SFAS No. 157 will have on its financial statements.
	During July 2006, the FASB issued FASB Interpretation (FIN) No. 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109." FIN No. 48 addresses the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS No. 109, "Accounting for Income Taxes." FIN No. 48 prescribes specific criteria for the financial statement recognition and measurement of the tax effects of a position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition of previously recognized tax benefits, classification of tax liabilities on the balance sheet, recording interest and penalties on tax underpayments, accounting in interim periods and disclosure requirements. FIN No. 48 is effective for fiscal periods beginning after December 15, 2006. EOG adopted FIN No. 48 as of January 1, 2007. The cumulative effect of applying the provisions of FIN No. 48 will be reported as an adjustment to the opening balance of retained earnings for 2007. EOG expects to record an adjustment increasing retained earnings by approximately $10 million.
	In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty." EITF Issue 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. EOG presents purchase and sale activities related to its marketing activities on a net basis in the Consolidated Statements of Income and Comprehensive Income. The adoption of EITF Issue No. 04-13 did not have a material impact on EOG's financial statements.
	In March 2005, the FASB issued FIN No. 47, "Accounting for Conditional Asset Retirement Obligations." The interpretation clarifies the requirement to record abandonment liabilities stemming from legal obligations when the retirement depends on a conditional future event. FIN No. 47 requires that the uncertainty about the timing or method of settlement of a conditional retirement obligation be factored into the measurement of the liability when sufficient information exists. FIN No. 47 is effective for fiscal years ending after December 15, 2005. The adoption of FIN No. 47 did not have a material impact on EOG's financial statements.
2. Long-Term Debt
	Long-Term Debt at December 31 consisted of the following (in thousands):
6.70% Notes due 2006
$
-
$
126,075
6.50% Notes due 2007
98,442
98,992
6.65% Notes due 2028
140,000
140,000
Subsidiary Senior Unsecured Term Loan Facility due 2008
60,000
250,000
Subsidiary Revolving Credit Facility due 2009
65,000
-
7.00% Subsidiary Debt due 2011
220,000
220,000
4.75% Subsidiary Debt due 2014
150,000
150,000
733,442
985,067
Less: Current Portion of Long-Term Debt
-
126,075
Total
$
733,442
$
858,992
	At December 31, 2006, the aggregate annual maturities of long-term debt were $98 million in 2007, $60 million in 2008, $65 million in 2009, zero in 2010 and $220 million in 2011. At December 31, 2006, the $98 million principal amount of the 6.50% Notes due 2007 was classified as long-term debt based upon EOG's intent and ability to ultimately replace such amount with other long-term debt.
	On November 15, 2006, EOG repaid the remaining principal amount of its 6.70% Notes due November 15, 2006 at par plus accrued and unpaid interest through the maturity date.
	On May 12, 2006, EOG Resources Trinidad Limited, a wholly-owned foreign subsidiary of EOG, entered into a 3-year $75 million Revolving Credit Agreement (Credit Agreement). Borrowings under the Credit Agreement accrue interest based, at EOG's option, on either a London InterBank Offering Rate (LIBOR) plus an applicable margin or the base rate of the Credit Agreement's administrative agent. EOG had $65 million outstanding under the Credit Agreement at December 31, 2006. The applicable interest rate at December 31, 2006 was 5.78%. The weighted average interest rate for the amounts outstanding during the year ended December 31, 2006 was 5.90%.
	In accordance with notice delivered to holders on November 1, 2005, EOG redeemed the remaining $174 million outstanding principal amount of its 6.00% Notes due 2008 (2008 Notes) on December 5, 2005, at a redemption price of $1,039.22 per each $1,000.00 of principal amount, plus accrued and unpaid interest through the redemption date. The redemption was made in accordance with terms of the indenture and the officer's certificate establishing the terms of the 2008 Notes. In connection with the redemption, EOG recognized a loss on extinguishment of debt in the amount of $8 million, included in Net Interest Expense, representing prepaid interest and the write-off of deferred bond issuance costs.
	In October 2005, EOGI International Company (EOGI), a wholly-owned foreign subsidiary of EOG, entered into a $600 million, 3-year unsecured Senior Term Loan Agreement (Term Loan Agreement) with The Bank of Nova Scotia, as Administrative Agent, and certain banks, as lenders. All borrowings under this agreement were to be made as term loans and be guaranteed by EOG. Proceeds from the Term Loan Agreement were to be used for general corporate purposes, including funding distributions ultimately to EOG from its foreign subsidiaries to realize a benefit of the favorable United States tax legislation regarding repatriation of foreign earnings under the American Jobs Creation Act of 2004. Borrowings up to $600 million under the Term Loan Agreement were available in multiple drawings through December 31, 2005, and prior to such date, EOGI elected to borrow $250 million, which was used to fund the distributions ultimately to EOG as described above. Subsequent to December 31, 2005, borrowing capacity under the Term Loan Agreement was reduced to $100 million and such amount was to be available for an additional one-year period. During 2006, EOGI repaid $190 million of the $250 million outstanding balance of the Term Loan Agreement. Effective July 17, 2006, EOG terminated all remaining borrowing capacity under the Term Loan Agreement. Borrowings under the Term Loan Agreement accrue interest based, at EOG's option, on either a LIBOR plus an applicable margin or at the base rate of the Term Loan Agreement's administrative agent. The applicable interest rate for the $60 million outstanding balance at December 31, 2006 was 5.75%. The weighted average interest rate for the amounts outstanding during the year ended December 31, 2006 was 5.46%.
	On June 28, 2005, EOG entered into a 5-year $600 million unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. The Agreement was amended on June 21, 2006, effectively extending the scheduled maturity date to June 28, 2011. The Agreement provides for the allocation, at the option of EOG, of up to $75 million each to EOG's United Kingdom subsidiary and one of its Canadian subsidiaries. The Agreement also provides EOG the option to request letters of credit to be issued in an aggregate amount of up to $200 million. Interest accrues on advances based, at EOG's option, on either LIBOR plus an applicable margin (Eurodollar rate) or the base rate of the Agreement's administrative agent. Advances to the Canadian or the United Kingdom subsidiaries, should they occur, would be guaranteed by EOG and would bear interest at a rate calculated in accordance with the Agreement. There are no borrowings or letters of credit currently outstanding under the Agreement. At December 31, 2006, the applicable base rate and Eurodollar rate, had there been an amount borrowed under the Agreement, would have been 8.25% and 5.50%, respectively.
	The Agreement, the Term Loan Agreement and the Credit Agreement each contain certain restrictive covenants applicable to EOG, including a financial covenant with a maximum debt-to-total capitalization ratio of 65%. Other than this financial covenant, there are no other financial covenants in EOG's financing agreements. EOG continues to comply with this financial covenant and does not view it as materially restrictive.
	During 2005, EOG repaid the remaining $75 million outstanding balance of its $150 million 3-year Senior Unsecured Term Loan Facility with a group of banks with a maturity date of October 30, 2005.
	The 6.50% and 6.65% Notes due 2007 and 2028 were issued through public offerings and have effective interest rates of 6.50% to 6.65%. The Subsidiary Debt due 2011 bears interest at a fixed rate of 7.00% and is guaranteed by EOG.
	On March 9, 2004, under Rule 144A of the Securities Act of 1933, as amended, EOG Resources Canada Inc., a wholly-owned subsidiary of EOG, issued notes with a total principal amount of $150 million, an annual interest rate of 4.75% and a maturity date of March 15, 2014. The notes are guaranteed by EOG. In conjunction with the offering, EOG entered into a foreign currency swap transaction with multiple banks for the equivalent amount of the notes and related interest, which has in effect converted this indebtedness into Canadian Dollars 201.3 million with a 5.275% interest rate.
	Shelf Registration. On September 15, 2006, EOG filed an automatically effective shelf registration statement on Form S-3 (New Registration Statement) for the offer and sale from time to time of up to $688,237,500 of EOG's debt securities, preferred stock and common stock. The New Registration Statement was filed to replace EOG's existing shelf registration statement declared effective by the SEC in October 2000, under which EOG had sold no securities. As of February 26, 2007, the entire amount registered remains available under the New Registration Statement.
	Fair Value of Current and Long-Term Debt. At December 31, 2006 and 2005, EOG had $733 million and $985 million, respectively, of long-term debt (including current portion), which had fair values of approximately $754 million and $1,025 million, respectively. The fair value of long-term debt is the value EOG would have to pay to retire the debt, including any premium or discount to the debt-holder for the differential between the stated interest rate and the year-end market rate. The fair value of long-term debt is based upon quoted market prices and, where such quotes were not available, upon interest rates available to EOG at year-end.
3. Shareholders' Equity
	Common Stock. EOG purchases its common stock from time to time in the open market to be held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock plans and any other approved transactions or activities for which such common stock shall be required. In September 2001, the Board authorized the purchase of an aggregate maximum of 10 million shares of common stock of EOG which superseded all previous authorizations. At December 31, 2006, 6,386,200 shares remain available for repurchases under this authorization. On February 2, 2005, EOG announced that the Board had approved a two-for-one stock split in the form of a stock dividend, payable to record holders as of February 15, 2005 and issued on March 1, 2005. In addition, the Board increased the quarterly cash dividend on the common stock to a quarterly cash dividend of $0.04 per share post-split. On February 1, 2006, the Board increased the quarterly cash dividend on the common stock to $0.06 per share. On January 31, 2007, the Board increased the quarterly cash dividend on the common stock to $0.09 per share.
	The following summarizes shares of common stock outstanding at December 31, for each of the years ended December 31 (in thousands):
	On February 14, 2000, EOG's Board declared a dividend of one preferred share purchase right (a Right, and the agreement governing the terms of such Rights, the Rights Agreement) for each outstanding share of common stock, par value $0.01 per share. The Board has adopted this Rights Agreement to protect shareholders from coercive or otherwise unfair takeover tactics. The dividend was distributed to the shareholders of record on February 24, 2000. As mentioned above, on March 1, 2005, EOG effected a two-for-one stock split in the form of a stock dividend. In accordance with the Rights Agreement, each share of common stock issued in connection with the two-for-one stock split effective March 1, 2005 also had one Right associated with it. Each Right, expiring February 24, 2010, represents a right to buy from EOG one hundredth (1/100) of a share of Series E Junior Participating Preferred Stock (Series E) for $90, once the Rights become exercisable. This portion of a Series E share will give the shareholder approximately the same dividend, voting, and liquidation rights as would one share of common stock. Prior to exercise, the Right does not give its holder any dividend, voting, or liquidation rights. If issued, each one hundredth (1/100) of a Series E share (i) will not be redeemable; (ii) will entitle holders to quarterly dividend payments of $0.01 per share, or an amount equal to the dividend paid on one share of common stock, whichever is greater; (iii) will entitle holders upon liquidation either to receive $1 per share or an amount equal to the payment made on one share of common stock, whichever is greater; (iv) will have the same voting power as one share of common stock; and (v) if shares of EOG's common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock.
	The Rights will not be exercisable until ten days after a public announcement that a person or group has become an acquiring person (Acquiring Person) by obtaining beneficial ownership of 10% or more of EOG's common stock, or if earlier, ten business days (or a later date determined by EOG's Board before any person or group becomes an Acquiring Person) after a person or group begins a tender or exchange offer which, if consummated, would result in that person or group becoming an Acquiring Person. On February 24, 2005, the Rights Agreement was amended to create an exception to the definition of Acquiring Person to permit a qualified institutional investor to hold 10% or more but less than 20% of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the following requirements: (i) the institutional investor is described in Rule 13d-1(b)(1) promulgated under the Securities Exchange Act of 1934 and is eligible to report (and, if such institutional investor is the beneficial owner of greater than 5% of EOG's common stock, does in fact report) beneficial ownership of common stock on Schedule 13G; (ii) the institutional investor is not required to file a Schedule 13D (or any successor or comparable report) with respect to its beneficial ownership of EOG's common stock; (iii) the institutional investor does not beneficially own 15% or more of EOG's common stock (including in such calculation the holdings of all of the institutional investor's affiliates and associates other than those which, under published interpretations of the United States Securities and Exchange Commission or its staff, are eligible to file separate reports on Schedule 13G with respect to their beneficial ownership of EOG's common stock); and (iv) the institutional investor does not beneficially own 20% or more of EOG's common stock (including in such calculation the holdings of all of the institutional investor's affiliates and associates). On June 15, 2005, the Rights Agreement was amended again to revise the exception to the definition of Acquiring Person to permit a qualified institutional investor to hold 10% or more but less than 30% of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the other requirements of the definition of qualified institutional investor described in the amendment.
	If a person or group becomes an Acquiring Person, all holders of Rights, except the Acquiring Person may, for $90, purchase shares of EOG's common stock with a market value of $180 based on the market price of the common stock prior to such acquisition. If EOG is later acquired in a merger or similar transaction after the Rights become exercisable, all holders of Rights except the Acquiring Person may, for $90, purchase shares of the acquiring corporation with a market value of $180 based on the market price of the acquiring corporation's stock prior to such merger.
	EOG's Board may redeem the Rights for $0.005 per Right at any time before any person or group becomes an Acquiring Person. If the Board redeems any Rights, it must redeem all of the Rights. Once the Rights are redeemed, the only right of the holders of Rights will be to receive the redemption price of $0.005 per Right. The redemption price has been adjusted for the two-for-one stock split effective March 1, 2005 and will be adjusted for any future stock split or stock dividends of EOG's common stock. After a person or group becomes an Acquiring Person, but before an Acquiring Person owns 50% or more of EOG's outstanding common stock, the Board may exchange the Rights for common stock or equivalent security at an exchange ratio of one share of common stock or an equivalent security for each such Right, other than Rights held by the Acquiring Person.
	Preferred Stock. EOG currently has two authorized series of preferred stock. On February 14, 2000, EOG's Board, in connection with the Rights Agreement described above, authorized 1,500,000 shares of the Series E with the rights and preferences described above. On February 24, 2005, EOG's Board increased the authorized shares of the Series
	E to 3,000,000 as a result of the two-for-one stock split of EOG's common stock effective March 1, 2005. Currently, there are no shares of the Series E outstanding.
	On July 19, 2000, EOG's Board authorized 100,000 shares of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 Liquidation Preference per share (Series B). Dividends are payable on the shares only if declared by EOG's Board and will be cumulative. If declared, dividends will be payable at a rate of $71.95 per share, per year on March 15, June 15, September 15 and December 15 of each year beginning September 15, 2000. EOG may redeem all or part of the Series B at any time beginning on December 15, 2009 at $1,000 per share, plus accrued and unpaid dividends. The Series B is not convertible into, or exchangeable for, common stock of EOG. On October 11, 2006, EOG commenced a cash tender offer to purchase any and all of the 100,000 outstanding shares of the Series B at a price of $1,074.01 per share plus accrued and unpaid dividends up to the date of purchase. The tender offer expired on November 8, 2006, and on November 10, 2006, EOG redeemed 46,740 shares of the Series B for an aggregate purchase price, including redemption premium, fees and dividends of $51 million. In accordance with the provisions of EITF Topic D-42, EOG has included as a component of preferred dividends the $4 million of premium and fees associated with the redemption of the Series B shares. A total of 53,260 shares of the Series B remain outstanding at December 31, 2006.
	Following the December 2004 redemption of all outstanding shares of EOG's Flexible Money Market Cumulative Preferred Stock, Series D, EOG filed a Certificate of Elimination with the Secretary of State of the State of Delaware on February 24, 2005 to eliminate the series from EOG's Restated Certificate of Incorporation, as amended.
4. Other Income, Net
	Other income, net for 2006 included interest income ($27 million), equity income from investments in the Caribbean Nitrogen Company Limited (CNCL) and Nitrogen (2000) Unlimited (N2000) ammonia plants ($18 million), net gains on sales of properties ($8 million) and settlements received related to the Enron Corp. bankruptcy ($4 million). Other income, net for 2005 included equity income from investments in CNCL and N2000 ammonia plants ($16 million), gains on sales of properties ($13 million), interest income ($8 million), a gain on the sale of part of EOG's interest in the N2000 ammonia plant ($2 million) and net foreign currency transaction losses ($2 million).
5. Income Taxes
	The principal components of EOG's net deferred income tax liability at December 31 were as follows (in thousands):
	
		The components of Income Before Income Taxes for the years indicated below were as follows (in thousands):
	The principal components of EOG's Income Tax Provision for the years indicated below were as follows (in thousands):
	The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows:
	On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was enacted. The Act created a temporary incentive for United States corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. During the fourth quarter of 2005, EOG made a qualifying distribution in the amount of $450 million resulting in a federal income tax of approximately $24 million.
	EOG's foreign subsidiaries' undistributed earnings of approximately $1.8 billion at December 31, 2006 are considered to be indefinitely invested outside the United States and, accordingly, no United States or state income taxes have been provided thereon. Upon distribution of those earnings, EOG may be subject to both foreign withholding taxes and United States income taxes, net of allowable foreign tax credits. Determination of any potential amount of unrecognized deferred income tax liabilities is not practicable.
	EOG incurred a tax net operating loss of $191 million in 2002. During 2003, EOG utilized $176 million of the 2002 net operating loss. The remaining net operating loss of $15 million was utilized in 2004.
	Through 2004, EOG incurred foreign net operating losses of approximately $70 million, of which $51 million was utilized in 2005. The remaining $19 million net operating loss was utilized in 2006.
	EOG had an alternative minimum tax credit carryforward from prior years of $6 million which was used to offset regular income taxes in 2004.
6. Employee Benefit Plans
Pension Plans and Postretirement Benefits
	At December 31, 2006, EOG and its subsidiaries in Canada and Trinidad maintained certain defined benefit pension and postretirement medical plans covering certain eligible employees. EOG adopted the provisions of SFAS No. 158 applicable to 2006 during the fourth quarter of 2006 and recognized the funded status of the defined benefit plans as of December 31, 2006. The impact of SFAS No. 158 was to recognize a non-current asset of $0.1 million, current liability of $0.1 million, a non-current liability of $0.8 million and related deferred income taxes of $0.3 million, with an offsetting charge to accumulated other comprehensive income of $0.5 million representing previously unrecognized prior service costs and actuarial gains and losses associated with the defined benefit plans. During 2007, approximately $0.2 million of such costs will be amortized from accumulated other comprehensive income through net periodic benefit costs.
	Pension Plan. EOG has a non-contributory defined contribution pension plan and a matched defined contribution savings plan in place for most of its employees in the United States. EOG's contributions to these pension plans are based on various percentages of compensation, and in some instances, are based upon the amount of the employees' contributions. EOG's total contributions to these pension plans amounted to $14 million, $12 million and $11 million for 2006, 2005 and 2004, respectively.
	In addition, EOG's Canadian subsidiary maintains both a non-contributory defined benefit pension plan and a non-contributory defined contribution pension plan, as well as a matched defined contribution savings plan. EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan. With the exception of Canada's contributory defined benefit pension plan, which is closed to new employees, these pension plans are available to most employees of the Canadian and Trinidadian subsidiaries. EOG's combined contributions to these pension plans were $2.1 million, $2.0 million and $0.9 million for 2006, 2005 and 2004, respectively.
	For the Canadian and Trinidadian defined benefit pension plans, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $6.7 million, $6.0 million and $0.7 million, respectively, at December 31, 2006 and $6.4 million, $5.3 million and $1.1 million, respectively, at December 31, 2005. Weighted average discount rate and expected return on plan assets assumptions used to determine benefit obligations for the pension plans were 5.75% and 7.10% respectively, at December 31, 2006 and 5.54% and 6.57%, respectively, at December 31, 2005. Weighted average discount rate assumptions used to determine net periodic benefit cost for the pension plans for the years ended December 31, 2006, 2005 and 2004 were 5.98%, 6.50% and 6.50%, respectively. The weighted average asset allocation of the pension plans at December 31, 2006 consisted of equities (55%), debt and fixed income securities (40%) and other assets (5%). The asset allocation at December 31, 2005 consisted of equities (57%), debt and fixed income securities (38%) and other (5%).
	The investment policy for the defined benefit pension plan in Trinidad is determined by the pension plan's trustee, with input from EOG. The plan's asset allocation policy is largely dictated by local statutory requirements which restricts total investment in equities to a maximum of 50% of the plan's assets and investment overseas to 20% of the plan's assets. The investment policy for the defined benefit pension plan in Canada provides that EOG shall invest the plan assets in one or more balanced funds with Canadian and foreign equity components as deemed appropriate for the purpose of diversification.
	EOG's United Kingdom subsidiary introduced a pension plan as of January 2005, which includes a non-contributory defined contribution pension plan and a matched defined contribution savings plan. The pension plan is available to all employees of the United Kingdom subsidiary. EOG's combined contributions to these pension plans were approximately $0.1 million for both 2006 and 2005.
Postretirement Health Care. EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents. EOG accrues these postretirement benefit costs over the service lives of the employees expected to be eligible to receive such benefits.
	The benefit obligation and accrued benefit cost for the postretirement benefit plans totaled $3.7 million each at December 31, 2006 and $3.4 million and $2.0 million, respectively, at December 31, 2005. Weighted average discount rate assumptions used to determine benefit obligations for the postretirement plans at December 31, 2006 and 2005 were 5.95% and 5.67%, respectively. Weighted average discount rate assumptions used to determine net periodic benefit cost for the years ended December 31, 2006, 2005 and 2004 were 5.68%, 5.98% and 6.15%, respectively. Net periodic benefit cost recognized for the postretirement benefit plans totaled $0.7 million, $0.4 million and $0.5 million for the years ended December 31, 2006, 2005 and 2004.
Estimated Future Employer-Paid Benefits. The following benefits, which reflect expected future service, as appropriate, are expected to be paid by EOG in the next 10 years (in thousands):
Pension
Postretirement
Plans
		Plans
$
$
2012 - 2016
1,885
1,890
	Postretirement health care trend rates had minimal effect on the amounts reported for the postretirement health care plans for both 2006 and 2005. Most future increases or decreases in healthcare costs would be borne by the employee.
Stock-Based Compensation
	At December 31, 2006, EOG maintained various stock-based compensation plans as discussed below. EOG adopted SFAS No. 123(R) effective January 1, 2006 using the modified prospective application method and accordingly has not restated any of its prior year results. Prior to the adoption of SFAS 123(R), EOG recognized compensation expense for its stock-based compensation plans under the provisions of APB Opinion No. 25 as allowed by SFAS No. 123 "Accounting for Stock-Based Compensation." Stock-based compensation expense prior to January 1, 2006 consisted of amounts recognized in connection with grants of restricted stock and units. The adoption of SFAS No. 123(R) resulted in EOG recognizing compensation expense on grants of stock options, Stock-Settled Stock Appreciation Rights (SARs) and grants made under its employee stock purchase plan (ESPP). Stock-based compensation expense for the year ended December 31, 2006 included expense for all stock-based compensation awards that were not yet vested as of January 1, 2006 and all such awards granted after January 1, 2006 based upon the grant date estimated fair value of the awards. Such expense is computed net of forfeitures estimated based upon EOG's historical employee turnover rate. For awards made prior to January 1, 2006, compensation expense is amortized over the vesting period on a straight-line basis. For awards made subsequent to January 1, 2006, compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval.
	Stock-based compensation expense for periods subsequent to January 1, 2006 is included in the Consolidated Statements of Income based upon job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years 2006, 2005 and 2004 was as follows (in millions):
Lease and Well
$
$
-
$
-
Exploration Costs
-
-
General and Administrative
Total (1)
$
$
$
(1)	The 2006 amount includes $1 million of expense related to stock-based compensation awards issued to retirement-eligible
employees prior to January 1, 2006, which is being amortized over the vesting period on a straight-line basis.
	The impact of SFAS No. 123(R) was to reduce income before income taxes and net income during the year ended December 31, 2006 by $28.7 million and $18.5 million, respectively, and to reduce both basic and diluted net income per share available to common by $0.08. EOG's pro forma net income and net income per share available to common for 2005 and 2004 had compensation costs been recorded in accordance with SFAS No. 123, are presented below (in millions, except per share data):
	EOG has various stock plans (Plans) under which employees and non-employee members of the Board of Directors of EOG and its subsidiaries have been or may be granted certain equity compensation. Since the inception of the Plans, there have been 62,890,000 shares authorized for grant. At December 31, 2006, 3,233,165 shares remain available for grant.
	Stock Options and Stock Appreciation Rights. Under the Plans, participants have been or may be granted options to purchase shares of common stock of EOG at a price not less than the market price of the stock on the date of grant. In September 2006, EOG began granting SARs to the participants of the Plans. Each SAR represents the right to receive shares of EOG common stock based on the appreciation in the stock price from the date of grant on the number of shares granted. Stock options and SARs granted under the Plans vest on a graded vesting schedule up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Terms for stock options and SARs granted under the Plans have not exceeded a maximum term of 10 years. For all grants made prior to August 2004 and all ESPP grants, the fair value of each grant was estimated using the Black-Scholes-Merton model. Certain of EOG's stock options granted in 2005 and 2004 contain a feature that limits the potential gain that can be realized by requiring vested options to be exercised if the market price reaches 200% of the grant price for five consecutive trading days (Capped Option). EOG may or may not issue Capped Options in the future. The fair value of each Capped Option grant was estimated using a Monte Carlo simulation. Effective May 2005, the fair value of stock option grants not containing the Capped Option feature and the fair value of SARs was estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock options, SARs and ESPP grants totaled $34.8 million for the year ended December 31, 2006.
	Weighted average fair values and valuation assumptions used to value stock options, SARs and ESPP grants for the years 2006, 2005 and 2004 were as follows:
	Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's stock. The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant. The expected life is based upon historical experience and contractual terms of stock options, SARs and ESPP grants.
	The following table sets forth the stock option and SARs transactions for the years ended December 31 (stock options and SARs in thousands):
(1)	The total intrinsic value of stock options exercised during the years 2006, 2005 and 2004 was $65.0 million, $154.5 million and $92.0 million,
respectively. The intrinsic value is based upon the difference between the market price of EOG common stock on the date of exercise and the
grant price of the stock options.
	At December 31, 2006, there are 9,608,721 stock options/SARs vested or expected to vest with a weighted average grant price of $35.18, an intrinsic value of $265 million and a weighted average remaining contractual life of 5.8 years.
	At December 31, 2006, unrecognized compensation expense related to non-vested stock options, SARs and ESPP grants totaled $78.1 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.1 years.
	The following table summarizes certain information for the stock options and SARs outstanding at December 31, 2006 (stock options and SARs in thousands):
(1)	Based upon the difference between the closing market price of EOG common stock on the last trading day of the year and the grant
price of in-the-money stock options and SARs.
	Restricted Stock and Units. Under the Plans, employees may be granted restricted (non-vested) stock and/or units without cost to them. The restricted stock and units granted vest to the employee at various times ranging from one to five years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Upon vesting, restricted stock is released to the employee and restricted units are converted into common stock and released to the employee. Stock-based compensation expense related to restricted stock and units totaled $15 million, $12 million and $10 million for the years ended December 31, 2006, 2005 and 2004, respectively.
	The following table sets forth the restricted stock and units transactions for the year 2006 (shares, units and dollars in thousands, except per share data):
(1)	The total intrinsic value of restricted stock and units released during the years ended December 31, 2006, 2005 and 2004 was
$50.3 million, $14.6 million and $2.5 million, respectively. The intrinsic value is based upon the closing price of EOG's
common stock on the date restricted stock and units are released.
(2)	The aggregate intrinsic value of restricted stock and units outstanding at December 31, 2006 was approximately $143.7 million.
	At December 31, 2006, unrecognized compensation expense related to restricted stock and units totaled $54.8 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.4 years.
	Employee Stock Purchase Plan. EOG has an ESPP in place that allows eligible employees to semi-annually purchase, through payroll deductions, shares of EOG common stock at 85 percent of the fair market value at specified dates. Contributions to the ESPP are limited to 10 percent of the employees' pay (subject to certain ESPP limits) during each of the two six-month offering periods. As of December 31, 2006, approximately 315,800 common shares remained available for issuance under the ESPP.
	The following table summarizes ESPP activities for the years ended December 31 (in thousands, except number of participants):
Approximate Number of Participants
Shares Purchased
Aggregate Purchase Price
$5,110
$3,889
$3,021
	During 2006, 2005 and 2004, EOG issued treasury shares in connection with stock option exercises, restricted stock grants, restricted unit releases and ESPP purchases. The difference between the cost of the treasury shares and the exercise price of the options is reflected as an adjustment to additional paid in capital to the extent EOG has accumulated additional paid in capital relating to treasury stock and to retained earnings thereafter. Additionally, EOG recognized as an adjustment to additional paid in capital, federal income tax benefits of $31 million, $51 million and $29 million for 2006, 2005 and 2004, respectively, related to the exercise of stock options and the release of restricted stock and units.
7. Commitments and Contingencies
	Letters of Credit. At December 31, 2006, EOG had standby letters of credit and guarantees outstanding totaling approximately $630 million of which $505 million represents guarantees of subsidiary indebtedness included under Note 2 "Long-Term Debt" and $125 million primarily represents guarantees of payment obligations on behalf of subsidiaries. At December 31, 2005, EOG had standby letters of credit and guarantees outstanding totaling approximately $711 million of which $620 million represents guarantees of subsidiary indebtedness and $91 million primarily represents guarantees of payment obligations on behalf of subsidiaries. As of February 26, 2007, there were no demands for payment under these guarantees.
	Minimum Commitments. At December 31, 2006, total minimum commitments from long-term non-cancelable operating leases, drilling rig commitments, seismic purchase and other purchase obligations, and pipeline transportation service commitments, based on current pipeline transportation rates and the foreign currency exchange rates used to convert Canadian Dollars and British Pounds into United States Dollars at December 31, 2006, are as follows (in thousands):
Total Minimum
Commitments
$
363,861
2008 - 2010
770,807
2011 - 2012
374,021
2013 and beyond
867,169
$
2,375,858
	Included in the table above are leases for buildings, facilities and equipment with varying expiration dates through 2022. Rental expenses associated with existing leases amounted to $46 million, $34 million and $26 million for 2006, 2005 and 2004, respectively.
	Contingencies. There are various suits and claims against EOG that have arisen in the ordinary course of business. Management believes that the chance that these suits and claims will individually, or in the aggregate, have a material adverse effect on the financial condition or results of operations of EOG is remote. When necessary, EOG has made accruals in accordance with SFAS No. 5, "Accounting for Contingencies," in order to provide for these matters.
8. Net Income Per Share Available to Common
	The following table sets forth the computation of Net Income Per Share Available to Common for the years ended December 31 (in thousands, except per share data):
	The diluted earnings per share calculation excludes 0.1 million, 1.0 million and 0.5 million of SARs and stock options that were anti-dilutive for the years ended December 31, 2006, 2005, and 2004, respectively.
	On November 10, 2006, EOG redeemed 46,740 shares of the Series B for an aggregate purchase price, including premium, fees and dividends of $51 million. See Note 3.
9. Supplemental Cash Flow Information
	Cash paid for interest and income taxes was as follows for the years ended December 31 (in thousands):
Interest
$
41,174
$
60,467
$
60,967
Income taxes
301,214
335,628
56,654
10. Business Segment Information
	EOG's operations are all natural gas and crude oil exploration and production related. SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," establishes standards for reporting information about operating segments in annual financial statements. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance. EOG's chief operating decision making process is informal and involves the Chairman and Chief Executive Officer and other key officers. This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States, Canada, Trinidad and the United Kingdom. For segment reporting purposes, the chief operating decision maker considers the major United States producing areas to be one operating segment.
Financial information by operating segment is presented below for the years ended December 31, or at December 31 (in thousands):
(1)	EOG had sales activity with a single significant purchaser in the United States and Canada segments in 2006 that totaled $397 million of consolidated Net Operating Revenues.
(2)	EOG had sales activity with a single significant purchaser in the United States and Canada segments in 2005 that totaled $385 million of consolidated Net Operating Revenues.
(3)	EOG had sales activity with a single significant purchaser in the United States and Canada segments in 2004 that totaled $280 million of consolidated Net Operating Revenues.
11. Price, Interest Rate and Credit Risk Management Activities
Price and Interest Rate Risks. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collar and price swap contracts, as the means to manage this price risk. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchases and normal sales exception and therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.
	During 2006, 2005 and 2004, EOG elected not to designate any of its financial commodity derivative contracts as accounting hedges and accordingly, accounted for these financial commodity derivative contracts using the mark-to-market accounting method. During 2006, EOG recognized gains on mark-to-market financial commodity derivative contracts of $334 million, which included realized gains of $215 million. During 2005, EOG recognized gains on mark-to-market financial commodity derivative contracts of $10 million, which included realized gains of $10 million. During 2004, EOG recognized losses on mark-to-market financial commodity derivative contracts of $33 million, which included realized losses of $82 million and collar premium payments of $1 million.
	Presented below is a comprehensive summary of EOG's 2007 natural gas and crude oil financial price swap contracts at December 31, 2006 with prices expressed in dollars per million British thermal units ($/MMBtu) and in dollars per barrel ($/Bbl), as applicable, and notional volumes in million British thermal units per day (MMBtud) and in barrels per day (Bbld), as applicable. Currently, EOG is not a party to any financial collar contracts. The total fair value of the natural gas and crude oil financial price swap contracts at December 31, 2006 was $131 million.
	(1) The natural gas contracts for February 2007 are closed. The crude oil contracts
for February 2007 will close on February 28, 2007.
	The following table summarizes the estimated fair value of financial instruments and related transactions at December 31 of the years indicated as follows (in millions):
(1)	Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is required in interpreting
market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts.
(2)	See Note 2.
	Credit Risk.
While notional contract amounts are used to express the magnitude of commodity price and foreign currency swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by the other parties, are substantially smaller. EOG evaluates its exposure to all counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk. At December 31, 2006, EOG's net accounts receivable balance related to Unites States and Canada hydrocarbon sales included one receivable balance which constituted 12% of the total balance. This receivable was due from an integrated oil and gas company. The related amount was collected in January 2007. At December 31, 2005, no individual purchaser's accounts receivable balance related to United States and Canada hydrocarbon sales accounted for 10% or more of the total balance. In 2006 and 2005, natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago.
	At December 31, 2006, EOG had an allowance for doubtful accounts of $17 million, of which $15 million is associated with the Enron Corp. bankruptcies recorded in December 2001.
	Substantially all of EOG's accounts receivable at December 31, 2006 and 2005 resulted from hydrocarbon sales and/or joint interest billings to third party companies including foreign state-owned entities in the oil and gas industry. This concentration of customers and joint interest owners may impact EOG's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral or other credit enhancements from a customer or joint interest owner, EOG analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. During the three-year period ended December 31, 2006, credit losses incurred on receivables by EOG have been immaterial.
12. Accounting for Certain Long-Lived Assets
	EOG reviews its oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. During 2006, 2005 and 2004, such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields. As a result, EOG recorded pretax charges of $48 million, $31 million and $17 million in the United States operating segment during 2006, 2005 and 2004, respectively, and $7 million and $8 million in the Canada operating segment during 2006 and 2004, respectively. There were no pretax charges recorded in the Canada operating segment in 2005. The pretax charges are included in Impairments on the Consolidated Statements of Income and Comprehensive Income. The carrying values for assets determined to be impaired were adjusted to estimated fair values based on projected future net cash flows discounted using EOG's risk-adjusted discount rate. Amortization expenses of lease acquisition costs of unproved properties, including amortization of capitalized interest, were $53 million, $47 million and $57 million for 2006, 2005 and 2004, respectively.
13. Accounting for Asset Retirement Obligations
	The following table presents the reconciliation of the beginning and ending aggregate carrying amount of legal obligations associated with the retirement of oil and gas properties pursuant to SFAS No. 143 (in thousands):
14. Investment in Caribbean Nitrogen Company Limited and Nitrogen (2000) Unlimited
	EOG, through certain wholly-owned subsidiaries, owns equity interests in two Trinidadian companies: CNCL and N2000. During the first quarters of 2005 and 2004, EOG completed separate share sale agreements whereby portions of the EOG subsidiaries' shareholdings in CNCL and N2000 were sold to a third party energy company. The 2005 N2000 sale resulted in a pretax gain of $2 million. The 2004 sale did not result in any gain or loss. At December 31, 2006, EOG's equity interests in CNCL and N2000 were 12% and 10%, respectively.
	At December 31, 2006, the investment in CNCL was $19 million. CNCL commenced ammonia production in June 2002. At December 31, 2006, CNCL had a long-term debt balance of $142 million, which is non-recourse to CNCL's shareholders. EOG will be liable for its share of any post-completion deficiency funds, loans to fund the costs of operation, payment of principal and interest to the principal creditor and other cash deficiencies of CNCL up to $30 million, approximately $4 million of which is net to EOG's interest. The shareholders' agreement governing CNCL requires the consent of the holders of 90% or more of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOG is able to exercise significant influence over the operating and financial policies of CNCL and therefore, it accounts for the investment using the equity method. During 2006, EOG recognized equity income of $8 million and received cash dividends of $7
million from CNCL.
	At December 31, 2006, the investment in N2000 was $17 million. N2000 commenced ammonia production in August 2004. At December 31, 2006, N2000 had a long-term debt balance of $166 million, which is non-recourse to N2000's shareholders. At December 31, 2006, EOG was liable for its share of any post-completion deficiency funds, loans to fund the costs of operation, payment of principal and interest to the principal creditor and other cash deficiencies of N2000 up to $30 million, approximately $3 million of which is net to EOG's interest. The shareholders' agreement governing N2000 requires the consent of the holders of 100% of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOG is able to exercise significant influence over the operating and financial policies of N2000 and therefore, it accounts for the investment using the equity method. During 2006, EOG recognized equity income of $10 million and received cash dividends of $9 million
from N2000.
15. Suspended Well Costs
	EOG's net changes in suspended well costs for the years ended December 31, 2006, 2005 and 2004, in accordance with FSP No. 19-1, "Accounting for Suspended Well Costs," are presented below (in thousands):
	The following table provides an aging of suspended well costs for the years ended December 31, 2006, 2005 and 2004 (in thousands, except well count):
(1)	Costs related to an outside operated, deepwater offshore Gulf of Mexico discovery ($4 million) and an outside operated, winter access only,
Northwest Territories (NWT) discovery in Northern Canada ($23 million). In the Gulf of Mexico project, EOG is currently participating in the
drilling of an additional well. In the NWT project, EOG interpreted seismic data and identified potential drilling locations for the
2007 and 2008 winter drilling season.
(2)	Costs related to the deepwater offshore Gulf of Mexico discovery ($4 million) and the winter access only NWT discovery ($9 million).
(3)	Costs related to the deepwater offshore Gulf of Mexico discovery.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(In Thousands Except Per Share Data Unless Otherwise Indicated)
(Unaudited Except for Results of Operations for Oil and Gas Producing Activities)
Oil and Gas Producing Activities
	The following disclosures are made in accordance with Statement of Financial Accounting Standards (SFAS) No. 69, "Disclosures about Oil and Gas Producing Activities":
	Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
	Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.
	Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.
	Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
	Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and EOG's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause EOG's share of future production from Canadian reserves to be materially different from that presented.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Estimates of proved and proved developed reserves at December 31, 2006, 2005 and 2004 were based on studies performed by the engineering staff of EOG for all reserves. Opinions by DeGolyer and MacNaughton (D&M), independent petroleum consultants, for the years ended December 31, 2006, 2005 and 2004 covered producing areas containing 82%, 82% and 77%, respectively, of proved reserves of EOG on a net-equivalent-cubic-feet-of-gas basis. D&M's opinions indicate that the estimates of proved reserves prepared by EOG's engineering staff for the properties reviewed by D&M, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by D&M. Such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the engineering staff of EOG. All reports by D&M were developed utilizing geological and engineering data provided by EOG.
	No major discovery or other favorable or adverse event subsequent to December 31, 2006 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
	The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2006, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2006, as estimated by the engineering staff of EOG.
	NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(1)	Billion cubic feet or billion cubic feet equivalent, as applicable. Natural gas equivalents are determined using the
ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil, condensate or natural gas liquids.
(2)	Thousand barrels; includes crude oil, condensate and natural gas liquids.
	Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized costs relating to EOG's natural gas and crude oil producing activities at December 31 of the years indicated as follows:
	Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" and SFAS No. 143, "Accounting for Asset Retirement Obligations."
	Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property.
	Exploration costs include additions to exploratory wells including those in progress and exploration expenses.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Development costs include additions to production facilities and equipment and additions to development wells including those in progress.
	The following tables set forth costs incurred related to EOG's oil and gas activities for the years ended December 31:
(1)	Includes Asset Retirement Costs of $10 million, $6 million, $1 million and $5 million for the United States, Canada, Trinidad and the United Kingdom, respectively.
(2)	Includes Asset Retirement Costs of $8 million, $11 million, $0 million and $1 million for the United States, Canada, Trinidad and the United Kingdom, respectively.
(3)	Includes Asset Retirement Costs of $6 million, $7 million, $2 million and $2 million for the United States, Canada, Trinidad and the United Kingdom, respectively.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Results of Operations for Oil and Gas Producing Activities(1). The following tables set forth results of operations for oil and gas producing activities for the years ended December 31:
(1)	Excludes gains or losses on mark-to-market financial commodity derivative contracts, interest charges and general corporate expenses for each of the three years in the
period ended December 31, 2006.
(2)	Other includes other international operations.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the engineering staff of EOG. The estimates were based on commodity prices at year-end. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.
	The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.
	Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's crude oil and natural gas reserves for the years ended December 31:
(1)	Estimated natural gas prices used to calculate 2006 future cash inflows for the United States, Canada, Trinidad and the United Kingdom were $5.18,
$5.22, $3.10 and $4.72, respectively. Estimated liquids prices used to calculate 2006 future cash inflows for the United States, Canada, Trinidad and the
United Kingdom were $51.63, $50.90, $56.82 and $55.98, respectively.
(2)	Estimated natural gas prices used to calculate 2005 future cash inflows for the United States, Canada, Trinidad and the United Kingdom were $8.46,
$8.51, $2.84 and $12.65, respectively. Estimated liquids prices used to calculate 2005 future cash inflows for the United States, Canada, Trinidad and
the United Kingdom were $55.08, $50.39, $61.16 and $50.46, respectively.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2006:
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
Unaudited Quarterly Financial Information
(In Thousands, Except Per Share Data)
(1)	The sum of quarterly net income per share available to common may not agree with total year net income per share available to common as each
quarterly computation is based on the weighted average of common shares outstanding.
Schedule II
EOG RESOURCES, INC.
VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2006, 2005 and 2004
(In Thousands)
S-1
EXHIBITS
	Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to EOG's Form S-1 Registration Statement, Registration No. 33-30678, filed on August 24, 1989 (Form S-1), or as otherwise indicated.
Exhibit
Number 	Description
3.1(a)
-
Restated Certificate of Incorporation (Exhibit 3.1 to Form S-1).
3.1(b)
-
Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 4.1(b) to Form S-8 Registration Statement No. 33-52201, filed February 8, 1994).
3.1(c)
-
Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 4.1(c) to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995).
3.1(d)
-
Certificate of Amendment of Restated Certificate of Incorporation, dated June 11, 1996 (Exhibit 3(d) to Form S-3 Registration Statement No. 333-09919, filed August 9, 1996).
3.1(e)
-
Certificate of Amendment of Restated Certificate of Incorporation, dated May 7, 1997 (Exhibit 3(e) to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998).
3.1(f)
-
Certificate of Ownership and Merger, dated August 26, 1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999).
3.1(g)
-
Certificate of Designations of Series E Junior Participating Preferred Stock, dated February 14, 2000 (Exhibit 2 to Form 8-A Registration Statement, filed February 18, 2000).
3.1(h)
-
Certificate of Designation, Preferences and Rights of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated July 19, 2000 (Exhibit 3.1(h) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000).
3.1(i)
-
Certificate of Elimination of the Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, dated September 15, 2000 (Exhibit 3.1(j) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000).
3.1(j)
-
Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series C, dated September 15, 2000 (Exhibit 3.1(k) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000).
3.1(k)
-
Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series D, dated February 24, 2005 (Exhibit 3.1(k) to EOG's Annual Report on Form 10-K for the year ended December 31, 2004).
3.1(l)
-
Certificate of Amendment to Restated Certificate of Incorporation, dated May 3, 2005 (Exhibit 3.1(l) to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005).
3.2
-
By-laws, dated August 23, 1989, as amended and restated effective as of February 24, 2004 (Exhibit 3.2 to EOG's Annual Report on Form 10-K for the year ended December 31, 2003).
4.1(a)
-
Specimen of Certificate evidencing the Common Stock (Exhibit 3.3 to EOG's Annual Report on Form 10-K for the year ended December 31, 1999).
4.1(b)
-
Specimen of Certificate Evidencing Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B (Exhibit 4.3(g) to EOG's Registration Statement on Form S-4 Registration Statement No. 333-36056, filed June 7, 2000).
E-1
Exhibit
Number 	Description
4.2
-
Rights Agreement, dated as of February 14, 2000, between EOG and First Chicago Trust Company of New York, which includes the form of Rights Certificate as Exhibit B and the Summary of Rights to Purchase Preferred Shares as Exhibit C (Exhibit 1 to EOG's Registration Statement on Form 8-A, filed February 18, 2000).
4.3
-
Form of Rights Certificate (Exhibit 3 to EOG's Registration Statement on Form 8-A, filed February 18, 2000).
4.4
-
Indenture dated as of September 1, 1991, between EOG and JPMorgan Chase Bank, National Association (formerly, Texas Commerce Bank National Association) (Exhibit 4(a) to EOG's Registration Statement on Form S-3 Registration Statement No. 33-42640, filed September 6, 1991).
4.5
-
Amendment, dated as of December 13, 2001, to the Rights Agreement, dated as of February 14, 2000, between EOG and First Chicago Trust Company of New York, as rights agent (Exhibit 2 to Amendment No. 1 to EOG's Registration Statement on Form 8-A/A filed December 14, 2001).
4.6
-
Letter dated December 13, 2001, from First Chicago Trust Company of New York to EOG resigning as rights agent effective January 12, 2002 (Exhibit 3 to Amendment No. 2 to EOG's Registration Statement on Form 8-A/A filed February 7, 2002).
4.7
-
Amendment, dated as of December 20, 2001, to the Rights Agreement, dated as of February 14, 2000, as amended, between EOG and First Chicago Trust Company of New York, as rights agent (Exhibit 4 to Amendment No. 2 to EOG's Registration Statement on Form 8-A/A filed February 7, 2002).
4.8
-
Letter dated December 20, 2001, from EOG Resources, Inc. to EquiServe Trust Company, N.A. appointing EquiServe Trust Company, N.A. as successor rights agent (Exhibit 5 to Amendment No. 2 to EOG's Registration Statement on Form 8-A/A filed February 7, 2002).
4.9
-
Amendment, dated as of April 11, 2002, to the Rights Agreement, dated as of February 14, 2000, as amended, between EOG and EquiServe Trust Company, N.A., as rights agent (Exhibit 4.1 to EOG's Current Report on Form 8-K, filed April 12, 2002).
4.10
-
Amendment, dated as of December 10, 2002, to the Rights Agreement, dated as of February 14, 2000, as amended, between EOG and EquiServe Trust Company, N.A., as rights agent (Exhibit 4.1 to EOG's Current Report on Form 8-K, filed December 11, 2002).
4.11
-
Amendment, dated as of February 24, 2005, to the Rights Agreement, dated as of February 14, 2000, as amended, between EOG and EquiServe Trust Company, N.A., as rights agent (Exhibit 4.12 to EOG's Annual Report on Form 10-K for the year ended December 31, 2004).
4.12
-
Amendment, dated as of June 15, 2005, to the Rights Agreement, dated as of February 14, 2000, as amended, between EOG and EquiServe Trust Company, N.A., as rights agent (Exhibit 4.1 to EOG's Current Report on Form 8-K, filed June 21, 2005).
10.1(a)
-
Amended and Restated 1994 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995).
10.1(b)
-
Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 12, 1995 (Exhibit 4.3(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 1995).
10.1(c)
-
Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 10, 1996 (Exhibit 4.3(a) to Form S-8 Registration Statement No. 333-20841, filed January 31, 1997).
E-2
Exhibit
Number 	Description
10.1(d)
-
Third Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 9, 1997 (Exhibit 4.3(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 1997).
10.1(e)
-
Fourth Amendment to Amended and Restated 1994 Stock Plan, dated effective as of May 5, 1998 (Exhibit 4.3(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998).
10.1(f)
-
Fifth Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 8, 1998 (Exhibit 4.3(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1998).
10.1(g)
-
Sixth Amendment to Amended and Restated 1994 Stock Plan, dated effective as of May 8, 2001 (Exhibit 10.1(g) to EOG's Annual Report on Form 10-K for the year ended December 31, 2001).
10.1(h)
-
Seventh Amendment to Amended and Restated 1994 Stock Plan, dated effective as of December 30, 2005 (Exhibit 10.1(h) to EOG's Annual Report on Form 10-K for the year ended December 31, 2005).
10.2(a)
-
Amended and Restated 1993 Nonemployee Directors Stock Option Plan (Exhibit A to EOG's Proxy Statement, dated March 28, 2002, with respect to EOG's Annual Meeting of Shareholders).
10.2(b)
-
First Amendment to Amended and Restated 1993 Nonemployee Directors Stock Option Plan, dated effective as of December 30, 2005 (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2005).
10.3(a)
-
Amended and Restated 1992 Stock Plan (Exhibit B to EOG's Proxy Statement, dated March 29, 2004, with respect to EOG's Annual Meeting of Shareholders).
10.3(b)
-
First Amendment to Amended and Restated 1992 Stock Plan, dated effective as of December 30, 2005 (Exhibit 10.3(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2005).
10.4(a)
-
Amended and Restated 1996 Deferral Plan (Exhibit 4.4 to Form S-8 Registration Statement No. 333-84014, filed March 8, 2002).
10.4(b)
-
First Amendment to Amended and Restated 1996 Deferral Plan, effective as of September 10, 2002 (Exhibit 10.9(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 2002).
10.5(a)
-
Executive Employment Agreement between EOG and Mark G. Papa, effective as of June 15, 2005 (Exhibit 99.1 to EOG's Current Report on Form 8-K filed, June 21, 2005).
10.5(b)
-
Amended and Restated Change of Control Agreement between EOG and Mark G. Papa, effective as of June 15, 2005 (Exhibit 99.6 to EOG's Current Report on Form 8-K, filed June 21, 2005).
10.6(a)
-
Executive Employment Agreement between EOG and Edmund P. Segner, III, effective as of June 15, 2005 (Exhibit 99.2 to EOG's Current Report on Form 8-K, filed June 21, 2005).
10.6(b)
-
Amended and Restated Change of Control Agreement between EOG and Edmund P. Segner, III, effective as of June 15, 2005 (Exhibit 99.7 to EOG's Current Report on Form 8-K, filed June 21, 2005).
10.7(a)
-
Executive Employment Agreement between EOG and Barry Hunsaker, Jr., effective as of June 15, 2005 (Exhibit 99.5 to EOG's Current Report on Form 8-K, filed June 21, 2005).
10.7(b)
-
Amended and Restated Change of Control Agreement between EOG and Barry Hunsaker, Jr., effective as of June 15, 2005 (Exhibit 99.10 to EOG's Current Report on Form 8-K, filed June 21, 2005).
10.8(a)
-
Executive Employment Agreement between EOG and Loren M. Leiker, effective as of June 15, 2005 (Exhibit 99.3 to EOG's Current Report on Form 8-K, filed June 21, 2005).
E-3
Exhibit
Number Description
	9;
E-4
SIGNATURES
	Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
EOG RESOURCES, INC.
(Registrant)
Date: February 26, 2007
By:
/s/ TIMOTHY K. DRIGGERS 	
Timothy K. Driggers
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
	Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of registrant and in the capacities with EOG Resources, Inc. indicated and on the 26th day of February, 2007.
Signature
Title
/s/ MARK G. PAPA
Chairman of the Board and Chief Executive Officer and
(Mark G. Papa)
Director (Principal Executive Officer)
/s/ EDMUND P. SEGNER, III
Senior Executive Vice President and Chief of Staff and
(Edmund P. Segner, III)
Director (Principal Financial Officer)
/s/ TIMOTHY K. DRIGGERS
Vice President and Chief Accounting Officer
(Timothy K. Driggers)
(Principal Accounting Officer)
*GEORGE A. ALCORN
Director
(George A. Alcorn)
*CHARLES R. CRISP
Director
(Charles R. Crisp)
*WILLIAM D. STEVENS
Director
(William D. Stevens)
*H. LEIGHTON STEWARD
Director
(H. Leighton Steward)
*DONALD F. TEXTOR
Director
(Donald F. Textor)
*FRANK G. WISNER
Director
(Frank G. Wisner)
*
/s/ PATRICIA L. EDWARDS
(Patricia L. Edwards)
(Attorney-in-fact for persons indicated)
EOG RESOURCES, INC. AND SUBSIDIARIES
EXHIBITS TO FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006
INDEX OF EXHIBITS
Exhibit
Number 	Description
*12
-
Computation of Ratio of Earnings to Fixed Charges and to Combined Fixed Charges and Preferred Stock Dividends.
*21
-
List of subsidiaries.
*23.1
-
Consent of DeGolyer and MacNaughton.
*23.2
-
Opinion of DeGolyer and MacNaughton dated January 29, 2007.
*23.3
-
Consent of Deloitte & Touche LLP.
*24
-
Powers of Attorney.
*31.1
-
Section 302 Certification of Annual Report of Chief Executive Officer.
*31.2
-
Section 302 Certification of Annual Report of Principal Financial Officer.
*32.1
-
Section 906 Certification of Annual Report of Chief Executive Officer.
*32.2
-
Section 906 Certification of Annual Report of Principal Financial Officer.
*Exhibits filed herewith.