8-K

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

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 17, 2011

_______________

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

Delaware
(State or other jurisdiction
of incorporation) 1-9743
(Commission File
Number) 47-0684736
(I.R.S. Employer
Identification No.)

1111 Bagby, Sky Lobby 2
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)

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

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

EOG RESOURCES, INC.

Item 2.02 Results of Operations and Financial Condition.

    On February 17, 2011, EOG Resources, Inc. issued a press release announcing fourth quarter 2010 financial and operational results and first quarter and full year 2011 forecast and benchmark commodity pricing information (see Item 7.01 below). A copy of this release is attached as Exhibit 99.1 to this filing and is incorporated herein by reference. This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.

Item 7.01 Regulation FD Disclosure.

    Accompanying the press release announcing fourth quarter 2010 financial and operational results attached hereto as Exhibit 99.1 is first quarter and full year 2011 forecast and benchmark commodity pricing information for EOG Resources, Inc., which information is incorporated herein by reference. This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.

Item 9.01 Financial Statements and Exhibits.

    (d) Exhibits

        99.1     Press Release of EOG Resources, Inc. dated February 17, 2011 (including the accompanying first quarter and full year 2011 forecast and benchmark commodity pricing information).

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

		EOG RESOURCES, INC. (Registrant)
Date: February 17, 2011	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

EXHIBIT INDEX

Exhibit No.                                     Description

99.1 Press Release of EOG Resources, Inc. dated February 17, 2011 (including the accompanying first quarter and full year 2011 forecast and benchmark commodity pricing information).

EX-99

	EXHIBIT 99.1
EOG Resources, Inc.
News Release
For Further Information Contact:	Investors
	Maire A. Baldwin
	(713) 651-6EOG (651-6364)
	Elizabeth M. Ivers
	(713) 651-7132
	Media
	K Leonard
	(713) 571-3870

EOG RESOURCES REPORTS 2010 RESULTS AND INCREASES DIVIDEND

• Delivers 9.5 Percent Year-Over-Year Production Growth
• Fourth Quarter Crude Oil Revenues Surpass Natural Gas Revenues
• Records Consistent Drilling Results Across 120-Mile Trend in South Texas Eagle Ford Crude Oil Window and Drills First Well in Liquids-Rich Natural Gas Window
• Adds Permian Basin Wolfcamp Play to Suite of High Quality Crude Oil Assets
• Reports Increased Confidence in Colorado DJ Basin Niobrara Crude Oil Play
• Notes Strong Production Results from Bradford County Marcellus Shale
• Continues Advancement of Kitimat LNG Project
• Increases Total Company Proved Reserves 8.5 Percent at Attractive Finding Costs
• Targets 49 Percent Total Liquids Production Growth and 9.5 Percent Total Company Production Growth in 2011
• Raises Dividend on Common Stock for 12^th Time in 12 Years

FOR IMMEDIATE RELEASE: Thursday, February 17, 2011

HOUSTON - EOG Resources, Inc. (EOG) today reported fourth quarter 2010 net income of $53.7 million, or $0.21 per share. This compares to fourth quarter 2009 net income of $400.4 million, or $1.58 per share. For the full year 2010, EOG reported net income of $160.7 million, or $0.63 per share, as compared to $546.6 million, or $2.17 per share, for the full year 2009.

The results for the fourth quarter 2010 included a $122.3 million, net of tax ($0.48 per share) impairment of certain non-core North American onshore and offshore natural gas assets, gains on property dispositions of $98.8 million, net of tax ($0.39 per share) and a previously disclosed non-cash net loss of $43.9 million ($28.0 million after tax, or $0.11 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash outflow related to financial commodity contracts was $18.1 million ($11.6 million after tax, or $0.05 per share). Consistent with some analysts' practice of matching realizations to settlement months, and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the quarter was $92.0 million, or $0.36 per share. Adjusted non-GAAP net income for the fourth quarter 2009 was $234.3 million, or $0.92 per share.

On a similar basis, eliminating the items detailed in the attached table, adjusted non-GAAP net income for the full year 2010 was $296.4 million, or $1.16 per share, and for the full year 2009 was $754.5 million, or $3.00 per share. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

2010 Operational Highlights

EOG's total company production increased 9.5 percent in 2010 over 2009. Total company liquids rose 33 percent, driven by a 35 percent increase in crude oil and condensate production and a 29 percent increase in natural gas liquids. For the full year 2010, total company revenues from crude oil, condensate and natural gas liquids exceeded those from natural gas. For the fourth quarter 2010, crude oil revenues surpassed those from natural gas with almost half of total company wellhead revenues emanating from crude oil.

In the United States, crude oil and condensate production increased 32 percent in 2010 over the prior year primarily from EOG's continued development of the North Dakota Bakken/Three Forks, the Fort Worth Barnett Combo and the South Texas Eagle Ford Plays. At year-end 2010, EOG ranked as the largest crude oil producer in both the North Dakota Bakken and South Texas Eagle Ford Plays.

"EOG has become a formidable onshore U.S. crude oil producer through early identification and extensive acreage capture in a number of premier horizontal resource plays," said Mark G. Papa, Chairman and Chief Executive Officer.

Across its large acreage position in the mature crude oil window of the South Texas Eagle Ford, EOG drilled and completed numerous wells in the fourth quarter while still maintaining its 100 percent success rate. In the eastern part of EOG's acreage in Dewitt County, the Hansen Kullin Unit 2-H and 4-H were completed in December at peak rates of 1,625 and 1,700 barrels of oil per day (Bopd), respectively. On the west side of the play, the Naylor Jones Unit 86 #1H averaged over 870 Bopd for the first 30 days. In Atascosa County, the Peeler Ranch 4-H showed a peak crude oil production rate in excess of 1,300 Bopd. EOG has a 100 percent working interest in all these wells. During the quarter, EOG increased its prospective acreage in the mature crude oil window from 505,000 to 520,000 net acres.

"I continue to be pleased by the consistency of EOG's Eagle Ford results across our 120-mile long holdings," said Papa. "Our confidence in taking an early-mover role in this new play is being rewarded."

In the fourth quarter, EOG drilled its first successful horizontal Eagle Ford well outside the crude oil window. The Tully C. Garner #100H, located southwest of EOG's established crude oil acreage in Webb County, began production at a pipeline restricted rate of 2.8 million cubic feet per day (MMcfd) of rich natural gas with 239 barrels per day of condensate. EOG has a 100 percent working interest in the well. EOG has 26,000 net acres in the liquids-rich natural gas window.

EOG expanded its inventory of organic horizontal liquids plays with first-mover drilling success in the West Texas Permian Basin Wolfcamp Shale. To date, EOG has drilled and completed four wells in this liquids-rich play where it holds 120,000 net acres in Irion and Crockett Counties. Across the Wolfcamp, EOG's production mix is projected to be 78 percent crude oil, condensate and natural gas liquids with 22 percent natural gas. Potential reserves are estimated to be at least 40 million barrels of oil equivalent (MMboe), net after royalty, from one of multiple potential productive intervals. During 2011, EOG plans to operate a three-rig Wolfcamp development drilling program.

Drilling results from Weld County, Colorado, have increased EOG's confidence in the economic viability of the DJ Basin Niobrara crude oil play. To date, EOG has focused drilling efforts on its 80,000 net acre Hereford Ranch prospect where it has drilled multiple successful wells. Most importantly, EOG has made progress in establishing productivity from the Niobrara rock by successfully converting it from one dependent on fractures to a more matrix-dominated play. This increases the likelihood that the Niobrara is another true crude oil resource play that can be developed with tighter spacing and a greater number of economic wells than originally estimated.

In the Fort Worth Barnett Shale Combo where it drilled over 230 net wells in 2010, EOG continues to make operational improvements that are increasing per well reserves and lowering individual well costs. The Ava Unit #1H and #2H were completed with initial production rates of 337 and 489 Bopd with 311 and 524 thousand cubic feet per day (Mcfd) of liquids-rich natural gas, respectively. The Hailey Unit #1H and #2H were completed with initial rates of 335 and 320 Bopd with 207 and 261 Mcfd, respectively. EOG has 100 percent working interest in all four Montague County wells. EOG plans to run an active drilling program in the Barnett Shale Combo again this year.

EOG has accumulated a 600,000 net acre position in the Bakken, primarily in North Dakota. Current activity is primarily focused outside the Bakken Core on Bakken Lite and Three Forks development and drilling. As previously reported, EOG had exceptional well results from McKenzie County, North Dakota, southwest of its Core Parshall Field. During the fourth quarter, the Mandaree 12-07H and Liberty 16-36 were completed to sales at initial net production rates of 1,559 and 1,066 Bopd, plus associated liquids-rich natural gas. EOG has 86 and 95 percent working interests, respectively, in the wells.

"By augmenting our existing suite of quality crude oil assets during 2010 with exploration success in the South Texas Eagle Ford, the DJ Basin Niobrara and the Permian Basin Wolfcamp Shale Plays, we made meaningful strides in EOG's transition to a more liquids-focused company," said Papa. "In addition, by applying the operational efficiencies we have developed, EOG is moving into a highly efficient manufacturing mode of development drilling in plays such as the North Dakota Bakken/Three Forks, Fort Worth Barnett Combo, South Texas Eagle Ford and Manitoba Waskada."

Natural Gas Activity

EOG's North American natural gas production decreased 2 percent in 2010 from 2009. This retraction reflects not only EOG's continued transition to crude oil and liquids-rich drilling activities but is indicative of weak natural gas pricing fundamentals, as well as the sale of certain natural gas producing assets. In 2011, EOG plans to limit its dry gas drilling program to hold leases in the East Texas/North Louisiana Haynesville and Bossier, the Pennsylvania Marcellus and the British Columbia Horn River Basin Plays.

In the Marcellus Shale, EOG has approximately 210,000 net acres. On its 50,000 net acre position in Bradford County, EOG completed the Hoppaugh No. 3H using improved completion techniques. The well, in which EOG has a 96 percent working interest, tested at a rate of 14 MMcfd of natural gas. This is EOG's best producer in the field to date. Applying similar completion methodology in Clearfield County, EOG brought three wells to sales at rates that ranged from 7 to 9 MMcfd. EOG has a 50 percent working interest in these wells.

EOG is encouraged by early production results in the British Columbia Horn River Basin where its winter operations are being finalized. In addition, EOG and its partner continue to make progress on the Kitimat LNG export facility project with initial natural gas sales targeted for late 2015. EOG anticipates committing a percentage of its approximately 9 trillion cubic feet, net after royalty, of natural gas reserve potential in British Columbia for export through the terminal. Plans are to sell the LNG to international markets, primarily in Asia.

Reserves

EOG's total company proved reserves for 2010 increased 8.5 percent over the prior year from 1,796 to 1,950 MMBoe, all organic. Excluding the impact of property dispositions, total company and total North American net proved developed reserves increased 9.6 percent and 12.6 percent, respectively. Total liquids proved reserves increased from 17 percent to 28 percent of total proved reserves.

In 2010:

• Total reserve replacement from all sources - the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production - was 207 percent at a total reserve replacement cost of $15.05 per barrel of oil equivalent (Boe), based on exploration and development expenditures of $5,383 million. (Please refer to the attached tables for the calculation of total reserve replacement and total reserve replacement costs.)
• Proved developed reserve replacement from drilling - the ratio of net reserve additions from drilling to total production - was 180 percent.
• In the United States, total reserve replacement from all sources was 339 percent at a reserve replacement cost of $12.96 per Boe based on exploration and development expenditures of $4,676 million. (Please refer to the attached tables for the calculation of United States total reserve replacement and total reserve replacement costs.)

For the 23^rd consecutive year, internal reserve estimates were within 5 percent of those prepared by the independent reserve engineering firm of DeGolyer and MacNaughton (D&M). For 2010, D&M prepared a complete independent engineering analysis of properties containing 77 percent of EOG's proved reserves on a Boe basis.

2011 Operational Plans and Targets

EOG is targeting total company production growth of 9.5 percent in 2011. Total liquids production is forecast to increase 49 percent, comprised of 55 percent crude oil growth and 34 percent natural gas liquids growth. In North America, natural gas production is expected to decrease 5 percent from 2010, reflecting the impact of producing property sales and a weak natural gas pricing environment. Estimated exploration and production expenditures for 2011 will range from $6.4 to $6.6 billion, including exploration, development and production facilities and midstream expenditures. To offset any funding gap between estimated cash flows and capital expenditures, EOG expects to sell approximately $1 billion of natural gas and midstream assets during 2011. With a continued focus on the balance sheet, EOG plans to maintain a net debt-to-total capitalization ratio below 35 percent at both year-end 2011 and 2012.

For the period March 1 through December 31, 2011, EOG has 425,000 million British thermal units per day (MMbtud) of natural gas financial price swap contracts in place at a weighted average price of $5.09 per million British thermal units (MMbtu), excluding unexercised swaptions. For the full year 2012, EOG has 250,000 MMbtud of natural gas financial price swap contracts in place at a weighted average price of $5.56 per MMbtu, excluding unexercised swaptions. For February 1 through December 31, 2011, EOG has 18,000 barrels per day (Bbld) of crude oil financial price swap contracts in place at a weighted average price of $90.69 per barrel. For the full year 2012, EOG has 2,000 Bbld of crude oil financial price swap contracts in place at a weighted average price of $100.50 per barrel.

Capital Structure

During 2010, total cash proceeds from the sale of acreage and natural gas producing assets were $673 million. At December 31, 2010, EOG's total debt outstanding was $5,223 million for a debt-to-total capitalization ratio of 34 percent. Taking into account cash on the balance sheet of $789 million at year-end, EOG's net debt was $4,434 million for a net debt-to-total capitalization ratio of 30 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (non-GAAP).)

Dividend Increase

Following an increase in the common stock dividend in 2010, EOG's Board of Directors has again increased the cash dividend on the common stock. Effective with the dividend payable on April 29, 2011, to holders of record as of April 15, 2011, the quarterly dividend on the common stock will be $0.16 per share, an increase of 3 percent over the previous indicated annual rate. The indicated annual rate of $0.64 per share reflects the 12^th increase in 12 years.

Conference Call Scheduled for February 18, 2011

EOG's fourth quarter and full year 2010 results conference call will be available via live audio webcast at 8 a.m. Central standard time (9 a.m. Eastern standard time) on Friday, February 18, 2011. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through March 4, 2011.

EOG Resources, Inc. 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, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."

This press release, including the accompanying forecast and benchmark commodity pricing information, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production or generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known and unknown risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

• the timing and extent of changes in prices for natural gas, crude oil and related commodities;
• changes in demand for natural gas, crude oil and related commodities, including ammonia and methanol;
• the extent to which EOG is successful in its efforts to discover and market reserves and to acquire natural gas and crude oil properties;
• the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling and advanced completion technologies;
• the extent to which EOG is successful in its efforts to economically develop its acreage in, and to produce reserves and achieve anticipated production levels from, its existing and future natural gas and crude oil exploration and development projects, given the risks and uncertainties inherent in drilling, completing and operating natural gas and crude oil wells and the potential for interruptions of production, whether involuntary or intentional as a result of market or other conditions;
• the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;
• the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights of way;
• changes in government policies, laws and regulations, including environmental and tax laws and regulations;
• competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;
• EOG's ability to obtain access to surface locations for drilling and production facilities;
• the extent to which EOG's third-party-operated natural gas and crude oil properties are operated successfully and economically;
• EOG's ability to effectively integrate acquired natural gas and crude oil properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
• weather, including its impact on natural gas and crude oil demand, and weather-related delays in drilling and in the installation and operation of production, gathering, processing, compression and transportation facilities;
• the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
• EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all;
• the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
• the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
• political developments around the world, including in the areas in which EOG operates;
• the extent and effect of any hedging activities engaged in by EOG;
• the timing and impact of liquefied natural gas imports;
• the use of competing energy sources and the development of alternative energy sources;
• the extent to which EOG incurs uninsured losses and liabilities;
• acts of war and terrorism and responses to these acts; and
• the other factors described under Item 1A, "Risk Factors," on pages 14 through 19 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

Effective January 1, 2010, the United States Securities and Exchange Commission (SEC) now permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider clos ely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2009, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.

EOG RESOURCES, INC.
FINANCIAL REPORT
(Unaudited; in millions, except per share data)
			Three Months Ended				Twelve Months Ended
			December 31,				December 31,
			2010		2009		2010		2009
Net Operating Revenues			$	1,789.2	$	1,760.9	$	6,099.9	$	4,787.0
Net Income			$	53.7	$	400.4	$	160.7	$	546.6
Net Income Per Share
	Basic		$	0.21	$	1.60	$	0.64	$	2.20
	Diluted		$	0.21	$	1.58	$	0.63	$	2.17
Average Number of Shares Outstanding
	Basic			251.4		250.1		250.9		249.0
	Diluted			254.7		253.5		254.5		251.9
SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data)
			Three Months Ended				Twelve Months Ended
			December 31,				December 31,
			2010		2009		2010		2009
Net Operating Revenues
	Crude Oil and Condensate		$	630,433	$	372,044	$	1,998,771	$	1,089,711
	Natural Gas Liquids			147,595		90,198		462,345		258,799
	Natural Gas			587,521		573,037		2,420,099		2,050,963
	Gains (Losses) on Mark-to-Market Commodity Derivative Contracts			(43,904)		25,927		61,912		431,757
	Gathering, Processing and Marketing			307,890		157,437		909,680		407,116
	Gains on Property Dispositions			151,097		534,926		223,538		535,436
	Other, Net			8,528		7,293		23,551		13,177
		Total		1,789,160		1,760,862		6,099,896		4,786,959
Operating Expenses
	Lease and Well			190,783		157,002		698,430		579,290
	Transportation Costs			98,871		77,485		385,189		283,329
	Gathering and Processing Costs			19,405		13,080		66,758		57,632
	Exploration Costs			38,746		40,752		187,381		169,592
	Dry Hole Costs			27,391		11,590		72,486		51,243
	Impairments			239,782		123,911		742,647		305,832
	Marketing Costs			292,477		159,556		884,212		397,375
	Depreciation, Depletion and Amortization			543,789		398,937		1,941,926		1,549,188
	General and Administrative			74,004		68,793		280,474		248,274
	Taxes Other Than Income			89,301		55,648		317,074		174,363
		Total		1,614,549		1,106,754		5,576,577		3,816,118
Operating Income				174,611		654,108		523,319		970,841
Other Income (Expense), Net				6,333		(566)		14,243		2,071
Income Before Interest Expense and Income Taxes				180,944		653,542		537,562		972,912
Interest Expense, Net				41,371		27,307		129,586		100,901
Income Before Income Taxes				139,573		626,235		407,976		872,011
Income Tax Provision				85,900		225,808		247,322		325,384
Net Income			$	53,673	$	400,427	$	160,654	$	546,627
Dividends Declared per Common Share			$	0.155	$	0.145	$	0.620	$	0.580

EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)
			Three Months Ended				Twelve Months Ended
			December 31,				December 31,
			2010		2009		2010		2009
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) (A)
	United States			74.4		52.0		63.2		47.9
	Canada			8.6		5.5		6.7		4.1
	Trinidad			4.7		3.3		4.7		3.1
	Other International (B)			0.1		0.1		0.1		0.1
		Total		87.8		60.9		74.7		55.2
Average Crude Oil and Condensate Prices ($/Bbl) (C)
	United States		$	80.38	$	67.61	$	74.88	$	54.42
	Canada			75.47		68.92		72.66		57.72
	Trinidad			74.36		63.44		68.80		50.85
	Other International (B)			74.29		63.64		73.11		53.07
		Composite		79.55		67.50		74.29		54.46
Natural Gas Liquids Volumes (MBbld) (A)
	United States			35.7		23.3		29.5		22.5
	Canada			0.8		1.1		0.9		1.1
		Total		36.5		24.4		30.4		23.6
Average Natural Gas Liquids Prices ($/Bbl) (C)
	United States		$	43.95	$	40.29	$	41.68	$	30.03
	Canada			44.98		39.31		43.40		30.49
		Composite		43.97		40.25		41.73		30.05
Natural Gas Volumes (MMcfd) (A)
	United States			1,241		1,075		1,133		1,134
	Canada			185		225		200		224
	Trinidad			340		294		341		273
	Other International (B)			12		13		14		14
		Total		1,778		1,607		1,688		1,645
Average Natural Gas Prices ($/Mcf) (C)
	United States		$	3.78	$	4.21	$	4.30	$	3.72
	Canada			3.30		4.41		3.91		3.85
	Trinidad			2.99		2.26		2.65		1.73
	Other International (B)			5.91		3.96		4.90		4.34
		Composite		3.59		3.88		3.93		3.42
Crude Oil Equivalent Volumes (MBoed) (D)
	United States			317.0		254.4		281.5		259.4
	Canada			40.3		44.1		40.9		42.6
	Trinidad			61.3		52.3		61.5		48.5
	Other International (B)			2.0		2.3		2.5		2.4
		Total		420.6		353.1		386.4		352.9
Total MMBoe (D)				38.7		32.5		141.1		128.8
(A)	Thousand barrels per day or million cubic feet per day, as applicable.
(B)	Other International includes EOG's United Kingdom and China operations.
(C)	Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments.
(D)	Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

	EOG RESOURCES, INC.
	SUMMARY BALANCE SHEETS
	(Unaudited; in thousands, except share data)
			December 31,		December 31,
			2010		2009
	ASSETS
Current Assets
	Cash and Cash Equivalents		$	788,853	$	685,751
	Accounts Receivable, Net			1,113,279		771,417
	Inventories			415,792		261,723
	Assets from Price Risk Management Activities			48,153		20,915
	Income Taxes Receivable			54,916		37,009
	Deferred Income Taxes			9,260		-
	Other			97,193		62,726
	Total			2,527,446		1,839,541
Property, Plant and Equipment
	Oil and Gas Properties (Successful Efforts Method)			29,263,809		24,614,311
	Other Property, Plant and Equipment			1,733,073		1,350,132
	Total Property, Plant and Equipment			30,996,882		25,964,443
	Less: Accumulated Depreciation, Depletion and Amortization			(12,315,982)		(9,825,218)
	Total Property, Plant and Equipment, Net			18,680,900		16,139,225
Other Assets				415,887		139,901
Total Assets			$	21,624,233	$	18,118,667
	LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
	Accounts Payable		$	1,664,944	$	979,139
	Accrued Taxes Payable			82,168		92,858
	Dividends Payable			38,962		36,286
	Liabilities from Price Risk Management Activities			28,339		27,218
	Deferred Income Taxes			41,703		35,414
	Current Portion of Long-Term Debt			220,000		37,000
	Other			143,983		137,645
	Total			2,220,099		1,345,560
Long-Term Debt				5,003,341		2,760,000
Other Liabilities				667,455		632,652
Deferred Income Taxes				3,501,706		3,382,413
Commitments and Contingencies
Stockholders' Equity
	Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
	254,223,521 Shares Issued at December 31, 2010 and
	252,627,177 Shares Issued at December 31, 2009			202,542		202,526
	Additional Paid In Capital			729,992		596,702
	Accumulated Other Comprehensive Income			440,071		339,720
	Retained Earnings			8,870,179		8,866,747
	Common Stock Held in Treasury, 146,186 Shares at December 31, 2010
	and 118,525 Shares at December 31, 2009			(11,152)		(7,653)
		Total Stockholders' Equity		10,231,632		9,998,042
Total Liabilities and Stockholders' Equity			$	21,624,233	$	18,118,667

	EOG RESOURCES, INC.
	SUMMARY STATEMENTS OF CASH FLOWS
	(Unaudited; in thousands)
			Twelve Months Ended
			December 31,
			2010		2009
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	160,654	$	546,627
	Items Not Requiring (Providing) Cash
		Depreciation, Depletion and Amortization		1,941,926		1,549,188
		Impairments		742,647		305,832
		Stock-Based Compensation Expenses		107,378		95,180
		Deferred Income Taxes		76,245		174,392
		Gains on Property Dispositions, Net		(223,538)		(535,436)
		Other, Net		(468)		6,761
	Dry Hole Costs			72,486		51,243
	Mark-to-Market Commodity Derivative Contracts
		Total Gains		(61,912)		(431,757)
		Realized Gains		7,033		1,277,584
	Excess Tax Benefits from Stock-Based Compensation			-		(76,134)
	Other, Net			17,273		18,862
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		(339,126)		(47,818)
		Inventories		(171,791)		(50,146)
		Accounts Payable		654,688		(153,565)
		Accrued Taxes Payable		(53,098)		90,929
		Other Assets		(32,169)		(5,515)
		Other Liabilities		19,342		(12,305)
	Changes in Components of Working Capital Associated with Investing and
	Financing Activities			(208,968)		118,517
Net Cash Provided by Operating Activities				2,708,602		2,922,439
Investing Cash Flows
	Additions to Oil and Gas Properties			(5,210,612)		(3,176,783)
	Additions to Other Property, Plant and Equipment			(370,770)		(326,226)
	Acquisition of Galveston LNG Inc.			(210,000)		-
	Proceeds from Sales of Assets			672,593		212,000
	Changes in Components of Working Capital Associated with Investing
	Activities			208,933		(118,221)
	Other, Net			7,082		(5,321)
Net Cash Used in Investing Activities				(4,902,774)		(3,414,551)
Financing Cash Flows
	Long-Term Debt Borrowings			2,478,659		900,000
	Long-Term Debt Repayments			(37,000)		-
	Dividends Paid			(153,240)		(142,260)
	Excess Tax Benefits from Stock-Based Compensation			-		76,134
	Treasury Stock Purchased			(11,295)		(10,986)
	Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			34,560		20,465
	Debt Issuance Costs			(8,300)		(8,895)
	Other, Net			35		(296)
Net Cash Provided by Financing Activities				2,303,419		834,162
Effect of Exchange Rate Changes on Cash				(6,145)		12,390
Increase in Cash and Cash Equivalents				103,102		354,440
Cash and Cash Equivalents at Beginning of Period				685,751		331,311
Cash and Cash Equivalents at End of Period			$	788,853	$	685,751

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP)
TO NET INCOME (GAAP)
(Unaudited; in thousands, except per share data)
The following chart adjusts three-month and twelve-month periods ended December 31, 2010 and 2009 reported Net Income (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market gains from these transactions, to add back impairment charges related to certain of EOG's North American onshore and offshore natural gas assets in the third and fourth quarters of 2010, to eliminate the change in the estimated fair value of a contingent consideration liability related to EOG's previously disclosed acquisition of Haynesville and Bossier Shale unproved acreage, to eliminate the gains on property dispositions primarily in the Rocky Mountain area and to eliminate gains realized in the fourth quarter of 2009 on a property exchange in the Rocky Mountain area and on the sale of EOG's California assets. EOG believes this presentation may be useful to investors who follow the practice of some industry analys ts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude one-time items.  EOG management uses this information for comparative purposes within the industry.
		Three Months Ended				Twelve Months Ended
		December 31,				December 31,
		2010		2009		2010		2009
Reported Net Income (GAAP)		$	53,673	$	400,427	$	160,654	$	546,627
Mark-to-Market (MTM) Commodity Derivative Contracts Impact
	Total (Gains) Losses		43,904		(25,927)		(61,912)		(431,757)
	Realized Gains (Losses)		(18,147)		290,604		7,033		1,277,584
	Subtotal		25,757		264,677		(54,879)		845,827
	After-Tax MTM Impact		16,424		169,976		(35,203)		543,946
Add: Impairment of Certain North American Onshore and Offshore Natural
	Gas Assets, Net of Tax		122,344		-		330,675		-
Less: Gains on Property Dispositions, Net of Tax			(98,835)		-		(145,216)		-
Less: Change in Fair Value of Contingent Consideration Liability, Net of Tax			(1,580)		-		(14,521)		-
Less: Gain on Property Exchange, Net of Tax			-		(244,248)		-		(244,248)
Less: Gain on Sale of California Assets, Net of Tax			-		(91,822)		-		(91,822)
Adjusted Net Income (Non-GAAP)		$	92,026	$	234,333	$	296,389	$	754,503
Net Income Per Share (GAAP)
	Basic	$	0.21	$	1.60	$	0.64	$	2.20
	Diluted	$	0.21	$	1.58	$	0.63	$	2.17
Adjusted Net Income Per Share (Non-GAAP)
	Basic	$	0.37	$	0.94	$	1.18	$	3.03
	Diluted	$	0.36	$	0.92	$	1.16	$	3.00
Average Number of Shares
	Basic		251,365		250,127		250,876		248,996
	Diluted		254,716		253,493		254,500		251,884

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW (NON-GAAP)
TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)
(Unaudited; in thousands)
The following chart reconciles three-month and twelve-month periods ended December 31, 2010 and 2009 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry.
			Three Months Ended				Twelve Months Ended
			December 31,				December 31,
			2010		2009		2010		2009
Net Cash Provided by Operating Activities (GAAP)			$	622,875	$	828,763	$	2,708,602	$	2,922,439
Adjustments
	Exploration Costs (excluding Stock-Based Compensation Expenses)			32,676		35,432		163,274		149,076
	Excess Tax Benefits from Stock-Based Compensation			-		42,082		-		76,134
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		214,313		166,917		339,126		47,818
		Inventories		37,610		26,554		171,791		50,146
		Accounts Payable		(127,270)		(208,133)		(654,688)		153,565
		Accrued Taxes Payable		12,994		(74,832)		53,098		(90,929)
		Other Assets		16,118		1,260		32,169		5,515
		Other Liabilities		25,006		21,662		(19,342)		12,305
	Changes in Components of Working Capital Associated
		with Investing and Financing Activities		(7,727)		28,580		208,968		(118,517)
Discretionary Cash Flow (Non-GAAP)			$	826,595	$	868,285	$	3,002,998	$	3,207,552

EOG RESOURCES, INC.
RESERVES SUPPLEMENTAL DATA
(Unaudited)
2010 NET PROVED RESERVES RECONCILIATION SUMMARY
	United		North		Other	Total
CRUDE OIL & CONDENSATE (MMBbls )	States	Canada	America	Trinidad	Int'l	Int'l	Total
Beginning Reserves	188.4	25.6	214.0	5.4	0.1	5.5	219.5
Revisions	(8.2)	(0.1)	(8.3)	(0.8)	-	(0.8)	(9.1)
Purchases in place	-	-	-	-	-	-	-
Extensions, discoveries and other additions	199.5	3.2	202.7	1.8	-	1.8	204.5
Sales in place	(1.1)	(0.6)	(1.7)	-	-	-	(1.7)
Production	(23.1)	(2.5)	(25.6)	(1.7)	-	(1.7)	(27.3)
Ending Reserves	355.5	25.6	381.1	4.7	0.1	4.8	385.9
NATURAL GAS LIQUIDS (MMBbls )
Beginning Reserves	91.5	2.0	93.5	-	-	-	93.5
Revisions	27.5	(0.2)	27.3	-	-	-	27.3
Purchases in place	-	-	-	-	-	-	-
Extensions, discoveries and other additions	42.2	-	42.2	-	-	-	42.2
Sales in place	-	-	-	-	-	-	-
Production	(10.8)	(0.3)	(11.1)	-	-	-	(11.1)
Ending Reserves	150.4	1.5	151.9	-	-	-	151.9
NATURAL GAS (Bcf)
Beginning Reserves	6,350.1	1,549.5	7,899.6	985.8	12.7	998.5	8,898.1
Revisions	(222.7)	(29.9)	(252.6)	(88.6)	1.9	(86.7)	(339.3)
Purchases in place	-	-	-	-	-	-	-
Extensions, discoveries and other additions	821.3	3.4	824.7	63.0	7.9	70.9	895.6
Sales in place	(34.6)	(316.2)	(350.8)	-	-	-	(350.8)
Production	(422.6)	(73.0)	(495.6)	(132.6)	(5.2)	(137.8)	(633.4)
Ending Reserves	6,491.5	1,133.8	7,625.3	827.6	17.3	844.9	8,470.2
OIL EQUIVALENTS (MMBoe)
Beginning Reserves	1,338.3	285.8	1,624.1	169.7	2.2	171.9	1,796.0
Revisions	(17.9)	(5.3)	(23.2)	(15.5)	0.3	(15.2)	(38.4)
Purchases in place	-	-	-	-	-	-	-
Extensions, discoveries and other additions	378.6	3.8	382.4	12.3	1.3	13.6	396.0
Sales in place	(6.9)	(53.3)	(60.2)	-	-	-	(60.2)
Production	(104.3)	(14.9)	(119.2)	(23.8)	(0.9)	(24.7)	(143.9)
Ending Reserves	1,587.8	216.1	1,803.9	142.7	2.9	145.6	1,949.5
Net Proved Developed Reserves (MMBoe)
At December 31, 2009	744.3	124.3	868.6	105.5	2.2	107.7	976.3
At December 31, 2010	839.8	79.8	919.6	90.4	3.0	93.4	1,013.0
Net Proved Developed Reserves (MMBoe) - Excluding Sales
At December 31, 2009	738.0	78.7	816.7	105.5	2.2	107.7	924.4
At December 31, 2010	839.8	79.8	919.6	90.4	3.0	93.4	1,013.0
EOG RESOURCES, INC.
RESERVES SUPPLEMENTAL DATA (CONTINUED)
(Unaudited)
2010 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions)
	United		North		Other	Total
	States	Canada	America	Trinidad	Int'l	Int'l	Total
Acquisition Cost of Unproved Properties	$   400.7	$   14.0	$   414.7	$        -	$   (0.1)	$ (0.1)	$ 414.6
Exploration Costs	454.4	38.6	493.0	23.4	86.8	110.2	603.2
Development Costs	3,821.2	414.7	4,235.9	118.1	11.6	129.7	4,365.6
Total Drilling	4,676.3	467.3	5,143.6	141.5	98.3	239.8	5,383.4
Acquisition Cost of Proved Properties	-	-	-	-	-	-	-
Total Exploration & Development Expenditures	4,676.3	467.3	5,143.6	141.5	98.3	239.8	5,383.4
Gathering, Processing and Other	369.6	210.7	580.3	0.1	0.3	0.4	580.7
Asset Retirement Costs	71.2	2.4	73.6	(3.1)	1.8	(1.3)	72.3
Non-Cash Acquisition Costs	2.8	-	2.8	-	-	-	2.8
Total Expenditures	5,119.9	680.4	5,800.3	138.5	100.4	238.9	6,039.2
Proceeds from Sales in Place	(325.9)	(344.7)	(670.6)	(2.0)	-	(2.0)	(672.6)
Net Expenditures	$ 4,794.0	$ 335.7	$ 5,129.7	$ 136.5	$ 100.4	$ 236.9	$ 5,366.6
RESERVE REPLACEMENT COSTS ($ / Boe ) *
Total Drilling, Before Revisions	$ 12.35	$   122.97	$ 13.45	$   11.50	$ 75.62	$     17.63	$ 13.59
All-in Total, Net of Revisions	$ 12.96	$ (311.53)	$ 14.32	$ (44.22)	$ 61.44	$ (149.88)	$ 15.05
RESERVE REPLACEMENT *
Drilling Only	363%	26%	321%	52%	144%	55%	275%
All-in Total, Net of Revisions & Dispositions	339%	-368%	251%	-13%	178%	-6%	207%
* See attached reconciliation schedule for calculation methodology

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF TOTAL EXPLORATION AND DEVELOPMENT EXPENDITURES
FOR DRILLING ONLY (NON-GAAP) AND TOTAL EXPLORATION AND DEVELOPMENT EXPENDITURES (NON-GAAP)
AS USED IN THE CALCULATION OF RESERVE REPLACEMENT COSTS ($ / MCFE)
TO TOTAL COSTS INCURRED IN EXPLORATION AND DEVELOPMENT ACTIVITIES (GAAP)
(Unaudited; in millions, except ratio information)
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Mcfe. There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures.  Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs.  EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.
	United		North		Other	Total
	States	Canada	America	Trinidad	Int'l	Int'l	Total
Total Costs Incurred in Exploration and
Development Activities (GAAP)	$ 4,750.3	$ 469.7	$ 5,220.0	$ 138.4	$ 100.1	$ 238.5	$ 5,458.5
Less: Asset Retirement Costs	(71.2)	(2.4)	(73.6)	3.1	(1.8)	1.3	(72.3)
Acquisition Cost of Proved Properties	-	-	-	-	-	-	-
Non-Cash Acquisition Costs	(2.8)	-	(2.8)	-	-	-	(2.8)
Total Exploration & Development Expenditures
for Drilling Only (Non-GAAP) (a)	$ 4,676.3	$ 467.3	$ 5,143.6	$ 141.5	$ 98.3	$ 239.8	$ 5,383.4
Total Costs Incurred in Exploration and
Development Activities (GAAP)	$ 4,750.3	$ 469.7	$ 5,220.0	$ 138.4	$ 100.1	$ 238.5	$ 5,458.5
Less: Asset Retirement Costs	(71.2)	(2.4)	(73.6)	3.1	(1.8)	1.3	(72.3)
Non-Cash Acquisition Costs	(2.8)	-	(2.8)	-	-	-	(2.8)
Total Exploration & Development Expenditures (Non-GAAP) (b)	$ 4,676.3	$ 467.3	$ 5,143.6	$ 141.5	$ 98.3	$ 239.8	$ 5,383.4
Net Proved Reserve Additions From All Sources
- Oil Equivalents (MMBoe)
Revisions due to price (c)	15.7	14.5	30.2	(2.0)	-	(2.0)	28.2
Revisions other than price	(33.6)	(19.8)	(53.4)	(13.5)	0.3	(13.2)	(66.6)
Purchases in place	-	-	-	-	-	-	-
Extensions, discoveries and other additions (d)	378.6	3.8	382.4	12.3	1.3	13.6	396.0
Total Proved Reserve Additions (e)	360.7	(1.5)	359.2	(3.2)	1.6	(1.6)	357.6
Sales in place	(6.9)	(53.3)	(60.2)	-	-	-	(60.2)
Net Proved Reserve Additions From All Sources (f)	353.8	(54.8)	299.0	(3.2)	1.6	(1.6)	297.4
Production (g)	104.3	14.9	119.2	23.8	0.9	24.7	143.9
RESERVE REPLACEMENT COSTS ($ / BOE)
Total Drilling, Before Revisions (a / d )	$ 12.35	$   122.97	$ 13.45	$     11.50	$ 75.62	$     17.63	$ 13.59
All-in Total, Net of Revisions (b / e)	$ 12.96	$ (311.53)	$ 14.32	$   (44.22)	$ 61.44	$ (149.88)	$ 15.05
All-in Total, Excluding Revisions Due to Price (b / (e - c ))	$ 13.55	$   (29.21)	$ 15.63	$ (117.92)	$ 61.44	$   599.50	$ 16.34
RESERVE REPLACEMENT
Drilling Only (d / g )	363%	26%	321%	52%	144%	55%	275%
All-in Total, Net of Revisions & Dispositions (f / g )	339%	-368%	251%	-13%	178%	-6%	207%
All-in Total, Excluding Revisions Due to Price ((f - c ) / g )	324%	-465%	226%	-5%	178%	2%	187%

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AND TOTAL
CAPITALIZATION (NON-GAAP) AS USED IN THE CALCULATION OF
THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO (NON-GAAP)
TO CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP)
(Unaudited; in millions, except ratio data)
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.
		December 31,
		2010
	Total Stockholders' Equity - (a)	$	10,232
	Current and Long-Term Debt - (b)		5,223
	Less: Cash		(789)
	Net Debt (Non-GAAP) - (c)		4,434
	Total Capitalization (GAAP) - (a) + (b)	$	15,455
	Total Capitalization (Non-GAAP) - (a) + (c)	$	14,666
	Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		34%
	Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		30%

EOG RESOURCES, INC.
FIRST QUARTER AND FULL YEAR 2011 FORECAST AND BENCHMARK COMMODITY PRICING
(a) First Quarter and Full Year 2011 Forecast The forecast items for the first quarter and full year 2011 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. This forecast replaces and supersedes any previously issued guidance or forecast.    (b) Benchmark Commodity Pricing EOG bases United States, Canada and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. EOG bases United States and Canada natural gas price differentials upon the natural gas price at Henry Hub, Louisiana using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.
				ESTIMATED RANGES
				(Unaudited)
				1Q 2011			Full Year 2011
Daily Production
	Crude Oil and Condensate Volumes (MBbld)
		United States		72.0	-	84.0	94.2	-	114.2
		Canada		7.5	-	8.5	7.0	-	9.5
		Trinidad		4.0	-	5.0	2.5	-	4.1
			Total	83.5	-	97.5	103.7	-	127.8
	Natural Gas Liquids Volumes (MBbld)
		United States		31.0	-	37.0	34.8	-	44.8
		Canada		0.8	-	1.2	0.7	-	0.9
			Total	31.8	-	38.2	35.5	-	45.7
	Natural Gas Volumes (MMcfd)
		United States		1,120	-	1,150	1,133	-	1,170
		Canada		122	-	140	100	-	133
		Trinidad		344	-	376	307	-	330
		Other International		14	-	16	12	-	16
			Total	1,600	-	1,682	1,552	-	1,649
	Crude Oil Equivalent Volumes (MBoed)
		United States		289.7	-	312.7	317.8	-	354.0
		Canada		28.6	-	33.0	24.4	-	32.6
		Trinidad		61.3	-	67.7	53.6	-	59.1
		Other International		2.3	-	2.7	2.0	-	2.6
			Total	381.9	-	416.1	397.8	-	448.3
				ESTIMATED RANGES
				(Unaudited)
				1Q 2011			Full Year 2011
Operating Costs
	Unit Costs ($/Boe)
		Lease and Well		$   5.40	-	$   5.88	$   5.16	-	$   5.64
		Transportation Costs		$   2.82	-	$   3.18	$   3.06	-	$   3.42
		Depreciation, Depletion and Amortization		$ 14.88	-	$ 15.96	$ 15.48	-	$ 16.50
Expenses ($MM)
	Exploration, Dry Hole and Impairment			$ 115.0	-	$ 130.0	$ 495.0	-	$ 540.0
	General and Administrative			$   72.0	-	$   78.0	$ 315.0	-	$ 335.0
	Gathering and Processing			$   16.0	-	$   20.0	$   63.0	-	$   80.0
	Capitalized Interest			$   18.0	-	$   22.0	$   75.0	-	$   90.0
	Net Interest			$   43.0	-	$   48.0	$ 170.0	-	$ 190.0
Taxes Other Than Income (% of Revenue)				6.2%	-	6.8%	5.6%	-	6.5%
Income Taxes
	Effective Rate			35%	-	50%	35%	-	45%
	Current Taxes ($MM)			$ 50	-	$ 65	$ 215	-	$ 235
Capital Expenditures ($MM) - FY 2011 (Excluding Acquisitions)
	Exploration and Development, Excluding Facilities						$ 5,350	-	$ 5,450
	Exploration and Development Facilities						$    550	-	$    600
	Gathering, Processing and Other						$    500	-	$    550
Pricing - (Refer to Benchmark Commodity Pricing in text)
	Natural Gas ($/Mcf)
		Differentials (include the effect of physical contracts)
			United States - below NYMEX Henry Hub	$ 0.09	-	$ 0.17	$ 0.03	-	$ 0.15
			Canada - below NYMEX Henry Hub	$ 0.45	-	$ 0.60	$ 0.50	-	$ 0.60
		Realizations
			Trinidad	$ 2.10	-	$ 2.60	$ 2.00	-	$ 2.60
			Other International	$ 3.00	-	$ 5.75	$ 5.00	-	$ 5.70
	Crude Oil and Condensate ($/Bbl)
		Differentials
			United States - below WTI	$ 4.00	-	$   6.00	$ 3.50	-	$   5.50
			Canada - below WTI	$ 7.00	-	$   8.00	$ 6.60	-	$   7.50
			Trinidad - below WTI	$ 8.00	-	$ 12.00	$ 8.25	-	$ 13.00
Definitions
	$/Bbl		U.S. Dollars per barrel
	$/Boe		U.S. Dollars per barrel equivalent
	$/Mcf		U.S. Dollars per thousand cubic feet
	$MM		U.S. Dollars in millions
	MBbld		Thousand barrels per day
	Mboed		Thousand barrels equivalent per day
	MMcfd		Million cubic feet per day
	NYMEX		New York Mercantile Exchange
	WTI		West Texas Intermediate