EX-99 2 exh99_1.htm EOG PRESS RELEASE

		EXHIBIT 99.1


EOG Resources, Inc.
News Release
For Further Information Contact:		Investors
		Maire A. Baldwin
		(713) 651-6EOG (651-6364)

		Media and Investors
		Elizabeth M. Ivers
		(713) 651-7132

EOG RESOURCES REPORTS 2009 RESULTS AND INCREASES DIVIDEND

Delivers 6.5 Percent 2009 Year-Over-Year Production Growth
Reports Consistent Operational Results in Top North American Plays
Targets 13 Percent Total Company and 47 Percent Liquids Production Growth in 2010
Posts 364 Percent Total Reserve Replacement at Attractive Finding Costs in 2009
Increases Dividend on Common Stock for 11^th Time in 11 Years

FOR IMMEDIATE RELEASE: Tuesday, February 9, 2010

HOUSTON - EOG Resources, Inc. (EOG) today reported fourth quarter 2009 net income available to common stockholders of $400.4 million, or $1.58 per share. This compares to fourth quarter 2008 net income available to common stockholders of $461.5 million, or $1.84 per share. For the full year 2009, EOG reported net income available to common stockholders of $546.6 million, or $2.17 per share as compared to $2,436.5 million, or $9.72 per share, for the full year 2008.

The results for the fourth quarter 2009 included a non-cash gain on a property exchange in the Rocky Mountain area of $389.6 million ($244.2 million after tax, or $0.97 per share), a gain on sale of assets of $146.5 million ($91.8 million after tax, or $0.36 per share) related to the disposition of crude oil assets and surrounding acreage in California and a previously disclosed non-cash net gain of $25.9 million ($16.7 million after tax, or $0.07 per share) on the mark-to-market of financial commodity transactions. During the quarter, the net cash inflow related to financial commodity contracts was $290.6 million ($186.6 million after tax, or $0.74 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 available to common stockholders for the quarter was $234.3 million, or $0.92 per share. Adjusted non-GAAP net income available to common stockholders for the fourth quarter 2008 was $186.0 million, or $0.74 per share. On a similar basis, eliminating the items detailed in the attached table, adjusted non-GAAP net income available to common stockholders for the full year 2009 was $754.5 million, or $3.00 per share, and for the full year 2008 was $1,879.1 million, or $7.50 per share. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income available to common stockholders to GAAP net income available to common stockholders.)

2009 Operational Highlights

EOG delivered 6.5 percent total company production growth over 2008. Total liquids production in North America increased 30 percent, comprised of 23 percent growth in crude oil and condensate and 48 percent in natural gas liquids. In the United States, the substantial increase in total liquids production was primarily driven by ongoing exploration and development drilling in the North Dakota Bakken and Fort Worth Barnett Shale Combo Plays.

"Over the last several years, we have channeled a greater amount of EOG's capital expenditure program toward crude oil and liquids-rich opportunities. The resulting increase in our liquids volumes, which is significant, reflects EOG's progress in shifting toward a more balanced mix in our North American production portfolio," said Mark G. Papa, Chairman and Chief Executive Officer.

With a position in excess of 500,000 net acres in the North Dakota Bakken, EOG focused drilling operations on its 100,000 net acres in the Bakken Core during the first part of 2009. As crude oil pricing gradually improved over the course of the year, EOG expanded its drilling program outside of the Parshall Field to its Bakken Lite acreage. Additionally, EOG began testing its first wells in the Three Forks Formation in both the Core Parshall Field and the Bakken Lite. Initial production profiles are encouraging with recoverable reserves expected to be similar to those in the Bakken Lite.

The Van Hook 100-15H, which was drilled in Mountrail County, N.D., tested the Three Forks Formation in the Parshall Field. EOG has 30 percent working interest in the well, which began initial production at a rate of 1,390 barrels of oil per day (Bopd). Also in Mountrail County, EOG drilled two Bakken Lite wells toward the end of the year. The Ross 05-08H began initial production at 370 Bopd with estimated reserves of 350 thousand barrels of oil (Mbo). EOG has 100 percent working interest in the well. To test a longer length lateral, EOG drilled the James Hill 01-31H. The well began initial production at 650 Bopd, in-line with pre-drill expectations. EOG holds 79 percent working interest in this well. Extending the productive area of its acreage, EOG drilled a well in Williams County, 90 miles west of the Parshall Field. The Round Prairie 1-17H, in which EOG has 95 percent working interest, is producing at a stabilized rate of 450 Bopd and is expected to have a similar production profile as a Bakken Lite well.

Having recognized the need for additional crude oil takeaway capacity from the Williston Basin, EOG designed, constructed and placed in service at year-end a rail and pipeline system to transport its crude oil from the core of this prolific basin, Stanley, N.D., to a market hub, Cushing, Okla. This unique transportation solution will improve the pricing and overall economics of EOG's Bakken crude oil production. In addition, EOG's Prairie Rose Pipeline was recently placed in service, which interconnects with a mainline system that transports natural gas to a processing plant near Chicago, Ill.

In an effort to focus on its more geographically concentrated western U.S. drilling operations, EOG divested its non-core California crude oil properties during the fourth quarter.

In the Fort Worth Basin, EOG commissioned a plant in February 2009 that extracts natural gas liquids from the rich natural gas production stream of the Barnett Combo Play. This enabled EOG to move into development drilling of both vertical and horizontal wells in Montague and Cooke Counties. EOG recently completed four vertical wells in Cooke County. The Dangelmayr #5 and B#6 began initial production at rates of 700 Bopd with 450 thousand cubic feet of natural gas per day (Mcfd), and 500 Bopd with 300 Mcfd, respectively. The Fitzgerald #2 and #14 began production at initial rates of 300 Bopd with 200 Mcfd and 450 Bopd with 400 Mcfd, respectively. EOG has 100 percent working interest in the wells. In Montague County, using horizontal technology, EOG recently completed the Boyd B #1H, which began flowing to sales at 300 Bopd with 1,500 Mcfd, and the Flying V #1H, at 250 Bopd with 1,400 Mcfd. EOG has 96 and 100 percent working interest in the wells, respectively. Already realizing the benefits of its refined completion techniques and improved operational efficiencies, EOG is testing optimal well spacing on its Fort Worth Barnett Combo acreage.

In an area where EOG had previously focused on the Haynesville, EOG reported strong production results from its first Bossier natural gas test. The Sustainable Forest 5 - No. 2 Alt., drilled to a vertical depth of 11,400 feet in the Trenton prospect area in DeSoto Parish, La., began producing at 13 million cubic feet per day. EOG has 100 percent working interest in the well that is estimated to have reserves in excess of 8 billion cubic feet. EOG is currently operating five rigs in the Trenton prospect where it is drilling and developing both the Bossier and Haynesville reservoirs concurrently.

2010 Operational Plans and Targets

Carrying the momentum of a strong operational year forward into 2010, EOG continues to target 13 percent total company full year organic production growth over 2009 with a 47 percent increase in total liquids production. The liquids growth will be driven by expanded operations in the North Dakota Bakken where EOG plans to execute an active drilling program in the Bakken Core and Lite, as well as the Three Forks Formation. Also fueling the liquids growth will be an increased level of drilling activity in the Fort Worth Barnett Combo and the Waskada Field in Manitoba.

EOG's North American natural gas production is expected to increase 2 percent over 2009. Plans are to ramp up activity levels in the Haynesville, Bossier and Marcellus Shales during the second half of the year. In the Horn River Basin, EOG will operate an active drilling program in the first half of the year, with the goal of completing and turning wells to sales during the second half of 2010.

Reserves

At December 31, 2009, total company proved reserves were approximately 10.8 trillion cubic feet equivalent, an increase of 2,087 billion cubic feet equivalent (Bcfe), or 24 percent higher than year-end 2008.

For the year-end 2009 reserve report, EOG applied new Securities and Exchange Commission (SEC) rules regarding the estimation of proved natural gas and crude oil reserves. In accordance with those rules, the proved undeveloped reserves (PUDs) category has been revised to allow the use of "reliable technology" to establish "reasonable certainty" of production for drilling locations beyond "one offset" for a producing well. The SEC has also imposed a five-year limit for the development of PUDs unless there is a specific reason for a longer period. Based on this definition and its applicability to large resource plays, EOG has added significant PUDs in the Haynesville, Horn River, Barnett Combo and Marcellus Shale Plays at precisely mapped locations which have been tied back to a plan that is executable within the next five years.

In 2009:

Total reserve replacement from all sources - the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production - was 364 percent at a total reserve replacement cost of $1.18 per thousand cubic feet equivalent (Mcfe) based on cash exploration and development expenditures of $3,436 million. (Please refer to the attached tables for the calculation of total reserve replacement and total reserve replacement cost.)
In the United States, total reserve replacement from all sources was 431 percent at a reserve replacement cost of $1.21 per Mcfe based on cash exploration and development expenditures of $3,037 million. (Please refer to the attached tables for the calculation of total reserve replacement and total reserve replacement cost.)
During 2009, price related revisions were negative 786 Bcfe. Excluding the impact of price related revisions, total reserve replacement was 464 percent at a reserve replacement cost of $0.93 per Mcfe.

For the 22^nd 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 2009, D&M prepared a complete independent engineering analysis of properties containing 81 percent of EOG's proved reserves on a Bcfe basis.

Capital Structure

At December 31, 2009, EOG's total debt outstanding was $2,797 million for a debt-to-total capitalization ratio of 22 percent. Taking into account cash on the balance sheet of $686 million, at the end of the year EOG's net debt was $2,111 million and the net debt-to-total capitalization ratio was 17 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 (GAAP).)

"We expect our year-end net debt-to-total capital ratio of 17 percent will be among the lowest of our peer group," said Papa. "This accomplishment, coupled with our 10-year average ROCE of 18 percent, reflects EOG's long standing commitment to deliver superior stockholder returns. It is likely that EOG will be one of a few peer E&P companies to report positive GAAP net income for 2009."

(Please refer to the attached tables for the calculation of return on capital employed (ROCE) and the related reconciliations of after-tax interest expense (non-GAAP), net debt (non-GAAP), and total capitalization (non-GAAP) as used in the calculations of ROCE, to interest expense (GAAP), current and long-term debt (GAAP), and total capitalization (GAAP).)

Dividend Increase

Following an increase in the common stock dividend in 2009, EOG's Board of Directors has again increased the cash dividend on the common stock. Effective with the dividend payable on April 30, 2010 to holders of record as of April 16, 2010, the quarterly dividend on the common stock will be $0.155 per share, an increase of 7 percent over the previous indicated annual rate. The indicated annual rate of $0.62 per share is the 11th increase in 11 years.

Conference Call Scheduled for February 10, 2010

EOG's fourth quarter and full year 2009 results conference call will be available via live audio webcast at 8 a.m. Central Standard Time (9 a.m. Eastern Standard Time) on Wednesday, February 10, 2010. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through February 24, 2010.

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 Unites 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, budgets, reserve information, 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 these expectations will be achieved 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, develop, market and produce 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 the Barnett Shale, the Bakken Formation, its Horn River Basin and Haynesville plays and its other exploration and development areas;

EOG's ability to achieve anticipated production levels from existing and future natural gas and crude oil 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;

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 gathering and production 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;
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;

political developments around the world, including in the areas in which EOG operates;

changes in government policies, legislation and regulations, including environmental regulations;

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 13 through 19 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2008 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and 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 to update or revise its forward-looking statements, whether as a result of new information, future events 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 presentation 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 closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2008, 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,
			2009		2008		2009		2008
Net Operating Revenues			$	1,760.9	$	1,633.7	$	4,787.0	$	7,127.1
Net Income Available to Common Stockholders			$	400.4	$	461.5	$	546.6	$	2,436.5
Net Income Per Share Available to Common Stockholders
	Basic		$	1.60	$	1.86	$	2.20	$	9.88
	Diluted		$	1.58	$	1.84	$	2.17	$	9.72
Average Number of Common Shares
	Basic			250.1		247.7		249.0		246.7
	Diluted			253.5		250.2		251.9		250.5


SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data)


			Three Months Ended				Twelve Months Ended
			December 31,				December 31,
			2009		2008		2009		2008
Net Operating Revenues
	Natural Gas		$	573,037	$	814,733	$	2,050,963	$	4,452,058
	Crude Oil, Condensate and Natural Gas Liquids			462,242		275,883		1,348,510		1,769,926
	Gains on Mark-to-Market Commodity Derivative Contracts			25,927		528,844		431,757		597,911
	Gathering, Processing and Marketing			157,437		13,628		407,116		164,535
	Gains (Losses) on Property Dispositions			534,926		(321)		535,436		123,473
	Other, Net			7,293		960		13,177		19,240
		Total		1,760,862		1,633,727		4,786,959		7,127,143
Operating Expenses
	Lease and Well			157,002		162,891		579,290		559,185
	Transportation Costs			77,485		70,885		283,329		274,090
	Gathering and Processing Costs			13,080		14,165		57,632		40,550
	Exploration Costs			40,752		48,489		169,592		193,886
	Dry Hole Costs			11,590		27,105		51,243		55,167
	Impairments			123,911		79,268		305,832		192,859
	Marketing Costs			159,556		12,431		397,375		152,842
	Depreciation, Depletion and Amortization			398,937		368,135		1,549,188		1,326,875
	General and Administrative			68,793		58,249		248,274		243,708
	Taxes Other Than Income			55,648		40,930		174,363		320,796
		Total		1,106,754		882,548		3,816,118		3,359,958

Operating Income				654,108		751,179		970,841		3,767,185

Other Income (Expense), Net				(566)		2,257		2,071		31,012

Income Before Interest Expense and Income Taxes				653,542		753,436		972,912		3,798,197

Interest Expense, Net				27,307		18,343		100,901		51,658

Income Before Income Taxes				626,235		735,093		872,011		3,746,539

Income Tax Provision				225,808		273,621		325,384		1,309,620

Net Income				400,427		461,472		546,627		2,436,919

Preferred Stock Dividends				-		-		-		443

Net Income Available to Common Stockholders			$	400,427	$	461,472	$	546,627	$	2,436,476

Dividends Declared per Common Share			$	0.145	$	0.135	$	0.580	$	0.510

EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)

			Three Months Ended				Twelve Months Ended
			December 31,				December 31,
			2009		2008		2009		2008
Wellhead Volumes and Prices
Natural Gas Volumes (MMcfd) ^(A)
	United States			1,075		1,231		1,134		1,162
	Canada			225		231		224		222
	Trinidad			294		184		273		218
	Other International ^(B)			13		18		14		17
		Total		1,607		1,664		1,645		1,619

Average Natural Gas Prices ($/Mcf) ^(C)
	United States		$	4.21	$	5.65	$	3.72	$	8.22
	Canada			4.41		5.71		3.85		7.64
	Trinidad			2.26		2.53		1.73		3.58
	Other International ^(B)			3.96		6.23		4.34		8.18
		Composite		3.88		5.32		3.42		7.51

Crude Oil and Condensate Volumes (MBbld) ^(A)
	United States			52.0		50.4		47.9		39.5
	Canada			5.5		2.7		4.1		2.7
	Trinidad			3.3		2.5		3.1		3.2
	Other International ^(B)			0.1		0.1		0.1		0.1
		Total		60.9		55.7		55.2		45.5

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
	United States		$	67.61	$	46.03	$	54.42	$	87.68
	Canada			68.92		45.60		57.72		89.70
	Trinidad			63.44		47.67		50.85		92.90
	Other International ^(B)			63.64		84.33		53.07		99.30
		Composite		67.50		46.12		54.46		88.18

Natural Gas Liquids Volumes (MBbld) ^(A)
	United States			23.3		15.9		22.5		15.0
	Canada			1.1		0.9		1.1		1.0
		Total		24.4		16.8		23.6		16.0

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
	United States		$	40.29	$	26.45	$	30.03	$	53.33
	Canada			39.31		30.08		30.49		54.77
		Composite		40.25		26.65		30.05		53.42

Natural Gas Equivalent Volumes (MMcfed) ^(D)
	United States			1,526		1,629		1,556		1,490
	Canada			265		253		256		244
	Trinidad			314		199		291		237
	Other International ^(B)			14		18		15		17
		Total		2,119		2,099		2,118		1,988

Total Bcfe ^(D)				194.9		193.1		773.0		727.6

(A)	Million cubic feet per day or thousand barrels per day, as applicable.
(B)	Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.
(C)	Dollars per thousand cubic feet or per barrel, as applicable.
(D)	Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil
	and 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 and condensate or natural gas liquids.

	EOG RESOURCES, INC.
	SUMMARY BALANCE SHEETS
	(Unaudited; in thousands, except share data)


						December 31,		December 31,
						2009		2008

	ASSETS
Current Assets
	Cash and Cash Equivalents					$	685,751	$	331,311
	Accounts Receivable, Net						771,417		722,695
	Inventories						261,723		187,970
	Assets from Price Risk Management Activities						20,915		779,483
	Income Taxes Receivable						37,009		27,053
	Other						62,726		59,939
			Total				1,839,541		2,108,451

Property, Plant and Equipment
	Oil and Gas Properties (Successful Efforts Method)						24,614,311		20,803,629
	Other Property, Plant and Equipment						1,350,132		1,057,888
	Total Property, Plant and Equipment						25,964,443		21,861,517
	Less: Accumulated Depreciation, Depletion and Amortization						(9,825,218)		(8,204,215)
			Total Property, Plant and Equipment, Net				16,139,225		13,657,302
Other Assets							139,901		185,473
Total Assets						$	18,118,667	$	15,951,226

	LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
	Accounts Payable					$	979,139	$	1,122,209
	Accrued Taxes Payable						92,858		86,265
	Dividends Payable						36,286		33,461
	Liabilities from Price Risk Management Activities						27,218		4,429
	Deferred Income Taxes						35,414		368,231
	Current Portion of Long-Term Debt						37,000		37,000
	Other						137,645		113,321
			Total				1,345,560		1,764,916


Long-Term Debt							2,760,000		1,860,000
Other Liabilities							632,652		498,291
Deferred Income Taxes							3,382,413		2,813,522
Commitments and Contingencies

Stockholders' Equity
	Common Stock, $0.01 Par, 640,000,000 Shares Authorized:
		252,627,177 Shares and 249,758,577 Shares Issued
					at December 31, 2009 and 2008, respectively		202,526		202,498
	Additional Paid In Capital						596,702		323,805
	Accumulated Other Comprehensive Income						339,720		27,787
	Retained Earnings						8,866,747		8,466,143
	Common Stock Held in Treasury, 118,525 Shares and 126,911 Shares
		at December 31, 2009 and 2008, respectively					(7,653)		(5,736)
				Total Stockholders' Equity			9,998,042		9,014,497
Total Liabilities and Stockholders' Equity						$	18,118,667	$	15,951,226

	EOG RESOURCES, INC.
	SUMMARY STATEMENTS OF CASH FLOWS
	(Unaudited; in thousands)

			Twelve Months Ended
			December 31,
			2009		2008
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	546,627	$	2,436,919
	Items Not Requiring (Providing) Cash
		Depreciation, Depletion and Amortization		1,549,188		1,326,875
		Impairments		305,832		192,859
		Stock-Based Compensation Expenses		95,180		97,493
		Deferred Income Taxes		174,392		1,133,630
		Gains on Property Dispositions		(535,436)		(123,473)
		Other, Net		6,761		(14,919)
	Dry Hole Costs			51,243		55,167
	Mark-to-Market Commodity Derivative Contracts
		Total Gains		(431,757)		(597,911)
		Realized Gains (Losses)		1,277,584		(136,625)
	Excess Tax Benefits from Stock-Based Compensation			(76,134)		(6,446)
	Other, Net			18,862		13,229
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		(47,818)		95,165
		Inventories		(50,146)		(92,049)
		Accounts Payable		(153,565)		30,253
		Accrued Taxes Payable		90,929		72,467
		Other Assets		(5,515)		(10,715)
		Other Liabilities		(12,305)		9,061
	Changes in Components of Working Capital Associated with
	Investing and Financing Activities			118,517		152,269
Net Cash Provided by Operating Activities				2,922,439		4,633,249

Investing Cash Flows
	Additions to Oil and Gas Properties			(3,176,783)		(4,718,860)
	Additions to Other Property, Plant and Equipment			(326,226)		(476,611)
	Proceeds from Sales of Assets			212,000		383,559
	Changes in Components of Working Capital Associated with
	Investing Activities			(118,221)		(152,374)
	Other, Net			(5,321)		(2,232)
Net Cash Used in Investing Activities				(3,414,551)		(4,966,518)

Financing Cash Flows
	Long-Term Debt Borrowings			900,000		750,000
	Long-Term Debt Repayments			-		(38,000)
	Dividends Paid			(142,260)		(115,204)
	Redemption of Preferred Stock			-		(5,395)
	Excess Tax Benefits from Stock-Based Compensation			76,134		6,446
	Treasury Stock Purchased			(10,986)		(17,834)
	Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			20,465		72,572
	Debt Issuance Costs			(8,895)		(7,585)
	Other, Net			(296)		105
Net Cash Provided by Financing Activities				834,162		645,105

Effect of Exchange Rate Changes on Cash				12,390		(34,756)

Increase in Cash and Cash Equivalents				354,440		277,080
Cash and Cash Equivalents at Beginning of Period				331,311		54,231
Cash and Cash Equivalents at End of Period			$	685,751	$	331,311

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS (Non-GAAP)
TO NET INCOME AVAILABLE TO COMMON STOCKHOLDERS (GAAP)
(Unaudited; in thousands, except per share data)


The following chart adjusts three-month and twelve-month periods ended December 31, 2009 and 2008 reported Net Income Available to Common Stockholders (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the gain on a property exchange in the Rocky Mountain area and the gain on the sale of EOG's California assets in the fourth quarter of 2009 and to eliminate the gain on the sale of EOG's Appalachian assets in the first quarter of 2008. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts 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,
		2009		2008		2009		2008
Reported Net Income Available to Common Stockholders (GAAP)		$	400,427	$	461,472	$	546,627	$	2,436,476

Mark-to-Market (MTM) Commodity Derivative Contracts Impact
	Total Gains		(25,927)		(528,844)		(431,757)		(597,911)
	Realized Gains (Losses)		290,604		100,701		1,277,584		(136,625)
	Subtotal		264,677		(428,143)		845,827		(734,536)

	After Tax MTM Impact		169,976		(275,510)		543,946		(472,674)

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)		-
Less: Gain on Sale of Appalachian Assets, Net of Tax			-		-		-		(84,748)

Adjusted Net Income Available to Common Stockholders (Non-GAAP)		$	234,333	$	185,962	$	754,503	$	1,879,054

Net Income Per Share Available to Common Stockholders (GAAP)
	Basic	$	1.60	$	1.86	$	2.20	$	9.88
	Diluted	$	1.58	$	1.84	$	2.17	$	9.72

Adjusted Net Income Per Share Available to Common Stockholders (Non-GAAP)
	Basic	$	0.94	$	0.75	$	3.03	$	7.62
	Diluted	$	0.92	$	0.74	$	3.00	$	7.50

Average Number of Common Shares
	Basic		250,127		247,672		248,996		246,662
	Diluted		253,493		250,162		251,884		250,542

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW
AVAILABLE TO COMMON STOCKHOLDERS (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, 2009 and 2008 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow Available to Common Stockholders (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, Changes in Components of Working Capital Associated with Investing and Financing Activities and Preferred Stock Dividends. EOG management uses this information for comparative purposes within the industry.

			Three Months				Twelve Months
			Ended December 31,				Ended December 31,
			2009		2008		2009		2008

Net Cash Provided by Operating Activities (GAAP)			$	828,763	$	1,033,563	$	2,922,439	$	4,633,249

Adjustments
	Exploration Costs (excluding Stock-Based Compensation Expenses)			35,432		43,448		149,076		175,357
	Excess Tax Benefits from Stock-Based Compensation			42,082		(63,378)		76,134		6,446
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		166,917		(315,112)		47,818		(95,165)
		Inventories		26,554		46,695		50,146		92,049
		Accounts Payable		(208,133)		191,196		153,565		(30,253)
		Accrued Taxes Payable		(74,832)		133,104		(90,929)		(72,467)
		Other Assets		1,260		(8,041)		5,515		10,715
		Other Liabilities		21,662		(12,458)		12,305		(9,061)
	Changes in Components of Working Capital Associated
	with Investing and Financing Activities			28,580		(137,880)		(118,517)		(152,269)
	Preferred Stock Dividends			-		-		-		(443)

Discretionary Cash Flow Available to Common Stockholders (Non-GAAP)			$	868,285	$	911,137	$	3,207,552	$	4,558,158

EOG RESOURCES, INC.
FIRST QUARTER AND FULL YEAR 2010 FORECAST AND BENCHMARK COMMODITY PRICING

(a) First Quarter and Full Year 2010 Forecast The forecast items for the first quarter and full year 2010 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 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. 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.
						ESTIMATED RANGES
						(Unaudited)
				1Q 2010			Full Year 2010
Daily Production
	Natural Gas (MMcfd)
			United States	1,040	-	1,070	1,160	-	1,190
			Canada	202	-	222	200	-	230
			Trinidad	290	-	310	285	-	300
			Other International	10	-	15	12	-	16
			Total	1,542	-	1,617	1,657	-	1,736

	Crude Oil and Condensate (MBbld)
			United States	48.0	-	54.0	62.0	-	85.0
			Canada	5.0	-	6.0	7.0	-	9.0
			Trinidad	2.7	-	3.2	3.0	-	5.0
			Total	55.7	-	63.2	72.0	-	99.0

	Natural Gas Liquids (MBbld)
			United States	22.0	-	28.0	25.0	-	34.0
			Canada	0.7	-	0.9	0.5	-	0.9
			Total	22.7	-	28.9	25.5	-	34.9

	Natural Gas Equivalent Volumes (MMcfed)
			United States	1,460	-	1,562	1,682	-	1,904
			Canada	236	-	264	245	-	289
			Trinidad	306	-	329	303	-	330
			Other International	10	-	15	12	-	16
			Total	2,012	-	2,170	2,242	-	2,539


EOG RESOURCES, INC.
FIRST QUARTER AND FULL YEAR 2010 FORECAST AND BENCHMARK COMMODITY PRICING (CONTINUED)

						ESTIMATED RANGES
						(Unaudited)
Operating Costs				1Q 2010			Full Year 2010
	Unit Costs ($/Mcfe)
			Lease and Well	$ 0.81	-	$ 0.85	$ 0.75	-	$ 0.80
			Transportation Costs	$ 0.42	-	$ 0.46	$ 0.39	-	$ 0.42
			Depreciation, Depletion and Amortization	$ 2.20	-	$ 2.30	$ 2.16	-	$ 2.30

Expenses ($MM)
	Exploration, Dry Hole and Impairment			$ 130.0	-	$ 175.0	$ 525.0	-	$ 675.0
	General and Administrative			$ 60.0	-	$ 68.0	$ 260.0	-	$ 290.0
	Gathering and Processing			$ 14.0	-	$ 18.0	$ 50.0	-	$ 70.0
	Capitalized Interest			$ 17.0	-	$ 21.0	$ 60.0	-	$ 85.0
	Net Interest			$ 24.0	-	$ 29.0	$ 110.0	-	$ 130.0

Taxes Other Than Income (% of Revenue)				5.5%	-	6.5%	5.5%	-	6.5%

Income Taxes
	Effective Rate			35%	-	45%	35%	-	45%
	Current Taxes ($MM)			$ 50	-	$ 60	$ 205	-	$ 225

Pricing - (Refer to Benchmark Commodity Pricing in text)
	Natural Gas ($/Mcf)
		Differentials (include the effect of physical contracts)
			United States - below NYMEX Henry Hub	$ 0.02	-	$ 0.30	$ 0.05	-	$ 0.30
			Canada - below NYMEX Henry Hub	$ 0.30	-	$ 0.60	$ 0.25	-	$ 0.55

		Realizations
			Trinidad	$ 1.60	-	$ 2.60	$ 1.60	-	$ 2.60
			Other International	$ 3.00	-	$ 5.00	$ 3.00	-	$ 5.00

	Crude Oil and Condensate ($/Bbl)
		Differentials
			United States - below WTI	$ 3.00	-	$ 8.00	$ 3.00	-	$ 6.00
			Canada - below WTI	$ 6.50	-	$ 8.50	$ 5.00	-	$ 8.00
			Trinidad - below WTI	$ 9.00	-	$ 12.50	$ 8.65	-	$ 12.65

Definitions
	$/Bbl		U.S. Dollars per barrel
	$/Mcf		U.S. Dollars per thousand cubic feet
	$/Mcfe		U.S. Dollars per thousand cubic feet equivalent
	$MM		U.S. Dollars in millions
	MBbld		Thousand barrels per day
	MMcfd		Million cubic feet per day
	MMcfed		Million cubic feet equivalent per day
	NYMEX		New York Mercantile Exchange
	WTI		West Texas Intermediate

EOG RESOURCES, INC.
RESERVES SUPPLEMENTAL DATA
(Unaudited)

2009 NET PROVED RESERVES RECONCILIATION SUMMARY

	United		North		Other	Total
NATURAL GAS (Bcf)	States	Canada	America	Trinidad	Int'l	Int'l	Total
Beginning Reserves	4,889.0	1,237.2	6,126.2	1,198.1	14.9	1,213.0	7,339.2
Revisions	(378.0)	(447.2)	(825.2)	(104.9)	3.0	(101.9)	(927.1)
Purchases in place	450.8	-	450.8	-	-	-	450.8
Extensions, discoveries and other additions	1,925.0	846.5	2,771.5	-	-	-	2,771.5
Sales in place	(114.4)	(5.1)	(119.5)	-	-	-	(119.5)
Production	(422.3)	(81.9)	(504.2)	(107.4)	(5.2)	(112.6)	(616.8)

Ending Reserves	6,350.1	1,549.5	7,899.6	985.8	12.7	998.5	8,898.1

CRUDE OIL & CONDENSATE (MMBbls)
Beginning Reserves	133.4	7.5	140.9	8.3	0.1	8.4	149.3
Revisions	4.4	(0.2)	4.2	(1.8)	-	(1.8)	2.4
Purchases in place	15.7	-	15.7	-	-	-	15.7
Extensions, discoveries and other additions	58.2	19.8	78.0	-	-	-	78.0
Sales in place	(5.8)	-	(5.8)	-	-	-	(5.8)
Production	(17.5)	(1.5)	(19.0)	(1.1)	-	(1.1)	(20.1)

Ending Reserves	188.4	25.6	214.0	5.4	0.1	5.5	219.5

NATURAL GAS LIQUIDS (MMBbls)
Beginning Reserves	72.5	3.3	75.8	-	-	-	75.8
Revisions	6.1	(0.9)	5.2	-	-	-	5.2
Purchases in place	5.8	-	5.8	-	-	-	5.8
Extensions, discoveries and other additions	18.5	-	18.5	-	-	-	18.5
Sales in place	(3.2)	-	(3.2)	-	-	-	(3.2)
Production	(8.2)	(0.4)	(8.6)	-	-	-	(8.6)

Ending Reserves	91.5	2.0	93.5	-	-	-	93.5

NATURAL GAS EQUIVALENTS (Bcfe)
Beginning Reserves	6,124.0	1,302.0	7,426.0	1,248.1	15.3	1,263.4	8,689.4
Revisions	(314.9)	(453.8)	(768.7)	(115.5)	3.1	(112.4)	(881.1)
Purchases in place	579.6	-	579.6	-	-	-	579.6
Extensions, discoveries and other additions	2,385.8	965.3	3,351.1	-	-	-	3,351.1
Sales in place	(168.2)	(5.4)	(173.6)	-	-	-	(173.6)
Production	(576.6)	(93.2)	(669.8)	(114.1)	(5.4)	(119.5)	(789.3)

Ending Reserves	8,029.7	1,714.9	9,744.6	1,018.5	13.0	1,031.5	10,776.1


Net Proved Developed Reserves (Bcfe)
At December 31, 2008	4,502.3	1,166.2	5,668.5	929.6	15.3	944.9	6,613.4
At December 31, 2009	4,466.0	745.9	5,211.9	633.3	13.0	646.3	5,858.2

EOG RESOURCES, INC.
RESERVES SUPPLEMENTAL DATA (CONTINUED)
(Unaudited)

2009 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Million)

	United		North		Other	Total
	States	Canada	America	Trinidad	Int'l	Int'l	Total


Acquisition Cost of Unproved Properties	$ 613.0	$ 17.8	$ 630.8	$ 0.8	$ (0.3)	$ 0.5	$ 631.3
Exploration Costs	473.5	51.2	524.7	14.2	71.9	86.1	610.8
Development Costs	1,839.1	219.8	2,058.9	21.3	2.0	23.3	2,082.2

Total Drilling	2,925.6	288.8	3,214.4	36.3	73.6	109.9	3,324.3

Acquisition Cost of Proved Properties	111.7	-	111.7	-	-	-	111.7

Total Exploration & Development Expenditures	3,037.3	288.8	3,326.1	36.3	73.6	109.9	3,436.0

Gathering, Processing and Other	324.6	1.0	325.6	0.2	0.4	0.6	326.2
Asset Retirement Costs	59.8	17.8	77.6	6.1	(0.1)	6.0	83.6
Non-Cash Acquisition Costs	387.9	-	387.9	-	-	-	387.9

Total Expenditures	3,809.6	307.6	4,117.2	42.6	73.9	116.5	4,233.7

Proceeds from Sales in Place	(211.1)	(0.9)	(212.0)	-	-	-	(212.0)

Net Expenditures	$ 3,598.5	$ 306.7	$ 3,905.2	$ 42.6	$ 73.9	$ 116.5	$ 4,021.7


RESERVE REPLACEMENT COSTS ($ / Mcfe ) *
Total Drilling, Before Revisions	$ 1.23	$ 0.30	$ 0.96	$ -	$ -	$ -	$ 0.99
All-in Total, Net of Revisions	$ 1.21	$ 0.56	$ 1.10	$ (0.31)	$ 23.74	$ (0.98)	$ 1.18

RESERVE REPLACEMENT *
Drilling Only	414%	1036%	500%	-	-	-	425%
All-in Total, Net of Revisions & Dispositions	431%	543%	446%	-101%	57%	-94%	364%

* 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)	$ 3,485.0	$ 306.6	$ 3,791.6	$ 42.4	$ 73.5	$ 115.9	$ 3,907.5

Less: Asset Retirement Costs	(59.8)	(17.8)	(77.6)	(6.1)	0.1	(6.0)	(83.6)
Acquisition Cost of Proved Properties	(111.7)	-	(111.7)	-	-	-	(111.7)
Non-Cash Acquisition Costs	(387.9)	-	(387.9)	-	-	-	(387.9)

Total Exploration & Development Expenditures
for Drilling Only (Non-GAAP) (a)	$ 2,925.6	$ 288.8	$ 3,214.4	$ 36.3	$ 73.6	$ 109.9	$ 3,324.3

Total Costs Incurred in Exploration and
Development Activities (GAAP)	$ 3,485.0	$ 306.6	$ 3,791.6	$ 42.4	$ 73.5	$ 115.9	$ 3,907.5

Less: Asset Retirement Costs	(59.8)	(17.8)	(77.6)	(6.1)	0.1	(6.0)	(83.6)
Non-Cash Acquisition Costs	(387.9)	-	(387.9)	-	-	-	(387.9)

Total Exploration & Development Expenditures (Non-GAAP) (1) (b)	$ 3,037.3	$ 288.8	$ 3,326.1	$ 36.3	$ 73.6	$ 109.9	$ 3,436.0

Net Proved Reserve Additions From All Sources
- Natural Gas Equivalents (Bcfe)
Revisions due to price (c)	(536.3)	(249.7)	(786.0)	-	-	-	(786.0)
Revisions other than price	221.4	(204.1)	17.3	(115.5)	3.1	(112.4)	(95.1)
Purchases in place	579.6	-	579.6	-	-	-	579.6
Extensions, discoveries and other additions (d)	2,385.8	965.3	3,351.1	-	-	-	3,351.1

Total Proved Reserve Additions (e)	2,650.5	511.5	3,162.0	(115.5)	3.1	(112.4)	3,049.6

Disposition in Property Exchange (f)	(131.5)	-	(131.5)	-	-	-	(131.5)
Sales in place	(36.7)	(5.4)	(42.1)	-	-	-	(42.1)

Net Proved Reserve Additions From All Sources (g)	2,482.3	506.1	2,988.4	(115.5)	3.1	(112.4)	2,876.0

Production (h)	576.6	93.2	669.8	114.1	5.4	119.5	789.3

RESERVE REPLACEMENT COSTS ($ / Mcfe)
Total Drilling, Before Revisions (a / d )	$ 1.23	$ 0.30	$ 0.96	$ -	$ -	$ -	$ 0.99
All-in Total, Net of Revisions (b / (e + f))	$ 1.21	$ 0.56	$ 1.10	$ (0.31)	$ 23.74	$ (0.98)	$ 1.18
All-in Total, Excluding Revisions Due to Price (b / (e + f - c ))	$ 0.99	$ 0.38	$ 0.87	$ (0.31)	$ 23.74	$ (0.98)	$ 0.93

RESERVE REPLACEMENT
Drilling Only (d / h )	414%	1036%	500%	-	-	-	425%
All-in Total, Net of Revisions & Dispositions (g / h )	431%	543%	446%	-101%	57%	-94%	364%
All-in Total, Excluding Revisions Due to Price ((g - c ) / h )	524%	811%	564%	-101%	57%	-94%	464%

(1) Acquisition costs for certain properties in Montague and Cooke counties, Texas, were partially settled with EOG common stock valued at $89.6 million.

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,
		2009

	Total Stockholders' Equity - (a)	$	9,998

	Current and Long-Term Debt - (b)		2,797
	Less: Cash		(686)
	Net Debt (Non-GAAP) - (c)		2,111

	Total Capitalization (GAAP) - (a) + (b)	$	12,795

	Total Capitalization (Non-GAAP) - (a) + (c)	$	12,109

	Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		22%

	Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		17%

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF AFTER-TAX INTEREST EXPENSE (Non-GAAP), NET DEBT (Non-GAAP) AND TOTAL
CAPITALIZATION (Non-GAAP) AS USED IN THE CALCULATION OF RETURN ON CAPITAL EMPLOYED (Non-GAAP) TO INTEREST
EXPENSE (GAAP), CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP), RESPECTIVELY
(Unaudited; in millions, except ratio data)

The following chart reconciles Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Interest Expense, Net Debt and Total Capitalization in their ROCE calculation. EOG management uses this information for comparative purposes within the industry.

	1999		2000		2001		2002		2003		2004		2005		2006		2007		2008		2009

Interest Expense			$	61.0	$	45.1	$	59.7	$	58.7	$	63.1	$	62.5	$	43.2	$	46.8	$	51.7	$	100.9
Tax Benefit Imputed (based on 35%)				(21.4)		(15.8)		(20.9)		(20.5)		(22.1)		(21.9)		(15.1)		(16.4)		(18.1)		(35.3)
After-Tax Interest Expense (Non-GAAP) - (a)			$	39.6	$	29.3	$	38.8	$	38.2	$	41.0	$	40.6	$	28.1	$	30.4	$	33.6	$	65.6

Net Income - (b)			$	396.9	$	398.6	$	87.2	$	430.1	$	624.9	$	1,259.6	$	1,299.9	$	1,089.9	$	2,436.9	$	546.6

Total Stockholders' Equity - (c)	$	1,129.6	$	1,380.9	$	1,642.7	$	1,672.4	$	2,223.4	$	2,945.4	$	4,316.3	$	5,599.7	$	6,990.1	$	9,014.5	$	9,998.0

Current and Long-Term Debt - (d)	$	990.3	$	859.0	$	856.0	$	1,145.1	$	1,108.9	$	1,077.6	$	985.1	$	733.4	$	1,185.0	$	1,897.0	$	2,797.0
Less: Cash		(24.8)		(20.2)		(2.5)		(9.8)		(4.4)		(21.0)		(643.8)		(218.3)		(54.2)		(331.3)		(685.8)
Net Debt (Non-GAAP) - (e)	$	965.5	$	838.8	$	853.5	$	1,135.3	$	1,104.5	$	1,056.6	$	341.3	$	515.1	$	1,130.8	$	1,565.7	$	2,111.2

Total Capitalization (GAAP) - (c) + (d)	$	2,119.9	$	2,239.9	$	2,498.7	$	2,817.5	$	3,332.3	$	4,023.0	$	5,301.4	$	6,333.1	$	8,175.1	$	10,911.5	$	12,795.0

Total Capitalization (Non-GAAP) - (c) + (e)	$	2,095.1	$	2,219.7	$	2,496.2	$	2,807.7	$	3,327.9	$	4,002.0	$	4,657.6	$	6,114.8	$	8,120.9	$	10,580.2	$	12,109.2

Average Total Capitalization (Non-GAAP)* - (f)			$	2,157.4	$	2,358.0	$	2,652.0	$	3,067.8	$	3,665.0	$	4,329.8	$	5,386.2	$	7,117.9	$	9,350.6	$	11,344.7


Return on Capital Employed (Non-GAAP) - [(a) + (b)] / (f)				20.2%		18.1%		4.8%		15.3%		18.2%		30.0%		24.7%		15.7%		26.4%		5.4%

Average Return on Capital Employed (Non-GAAP) 2000 - 2009																						17.9%

* Average of "Total Capitalization (Non-GAAP)" for the current and immediately preceding year