EX-99 2 exh99_1.htm PRESS RELEASE OF EOG RESOURCES, INC.

		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 THIRD QUARTER 2010 RESULTS

Records 30 Percent Total Crude Oil and Condensate Production Increase Over Third Quarter 2009

Increases Confidence in South Texas Eagle Ford Crude Oil Potential

Delivers Outstanding Well Results from Resource Play Drilling Programs

Proves Up Additional Acreage in New Mexico Leonard Shale

Targets 9 Percent Total Company Organic Production Growth in 2010

FOR IMMEDIATE RELEASE: Tuesday, November 2, 2010

HOUSTON - EOG Resources, Inc. (EOG) today reported a third quarter 2010 net loss of $70.9 million, or $0.28 per share. This compares to third quarter 2009 net income of $4.2 million, or $0.02 per share.

The results for the third quarter 2010 included a $208.3 million, net of tax ($0.82 per share) impairment of certain Canadian shallow natural gas assets held for sale, $41.4 million gain, net of tax ($0.16 per share) on property dispositions and a previously disclosed non-cash net gain of $61.0 million ($39.1 million after tax, or $0.16 per share) on the mark-to-market of financial commodity transactions. During the quarter, the net cash outflow related to financial commodity contracts was $13.6 million ($8.7 million after tax, or $0.03 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 $46.6 million, or $0.18 per share. Adjusted non-GAAP net income for the third quarter 2009 was $203.9 million, or $0.81 per share. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

Operational Highlights

EOG reported a 30 percent increase in total company crude oil and condensate production for the third quarter, compared to the same period in 2009. In the United States, crude and condensate production increased 29 percent.

In the South Texas Eagle Ford Play, EOG has steadily escalated the pace of both its drilling and completion operations. Results from the 77 wells drilled to date across its 120-mile, 505,000 net acre position in the mature oil window, reinforce EOG's confidence in its estimated 900 million barrels of oil equivalent, net after royalty resource potential, 77 percent of which is crude oil.

Patterned after successful development activity in its other resource plays, EOG is drilling and completing wells in batches to optimize resource recovery. Significant production increases are expected in 2011 as numerous clusters of wells are turned to production. Currently operating a 10-rig drilling program in the Eagle Ford, EOG plans to add one more rig by year-end and average 14 rigs in 2011.

Among EOG's South Texas Eagle Ford wells, in which EOG has a 100 percent working interest, are:

Cusack Clampit #1H, #2H, #3H and #4H - This cluster of Gonzales County wells began flowing to sales at rates of 860 to 1,800 barrels of oil per day (Bopd) with 1,020 to 1,770 thousand cubic feet per day (Mcfd) of rich natural gas.
Beynon #1H - This Karnes County well was completed at an initial peak rate of 902 Bopd with 1,110 Mcfd of rich natural gas.
Greenlow #5H - Drilled in Karnes County, this well began initial production at a rate of 720 Bopd with 1,030 Mcfd of rich natural gas.

"Well data generated throughout the year from the Eagle Ford reflects an increase in our estimates of recoveries per well relative to our April 2010 estimates. This upside not only enhances the rate of return of the play but indicates fewer wells than we originally anticipated will be needed to capture our net reserve potential of 900 million barrels of oil equivalent," said Mark G. Papa, Chairman and Chief Executive Officer.

With an active 16-rig drilling program in the Fort Worth Barnett Combo, this key EOG asset is in full development mode. After alleviating fracture crew constraints during the first half of 2010, EOG is focusing on multi-well development patterns in Montague and western Cooke Counties. Recent drilling results in Cooke County have expanded EOG's Core area from 150,000 to 160,000 net acres. EOG expects to exit 2010 with strong crude oil production momentum that will carry into 2011 and beyond. In the current natural gas environment, Combo economics are bolstered by the mix of oil and rich natural gas production with total liquids production contributing over 90 percent of revenue. In the past, liquids had contributed roughly 66 percent of the revenue stream from the play.

EOG's Barnett Shale Combo well highlights from Cooke and Montague Counties include:

Christian C #3H - This Cooke County well, in which EOG has a 98 percent working interest, began producing to sales at a gross rate of 954 Bopd with 1,608 Mcfd of rich natural gas.
Strickland A #2H - Drilled horizontally, this Cooke County well began flowing to sales at a gross rate of 1,118 Bopd with 1,801 Mcfd of rich natural gas. EOG has a 90 percent working interest in the well.
Strickland #1 - This vertically drilled Cooke County well, in which EOG has a 96 percent working interest, began production at a gross rate of 865 Bopd with 1,212 Mcfd of rich natural gas.
Settle C #3H - EOG has a 91 percent working interest in this Cooke County well that was completed at a rate of 731 Bopd with 2,135 Mcfd of rich natural gas, gross.
Nutter #1H - Drilled in western Cooke County, this well began flowing to sales at a rate of 672 Bopd with 838 Mcfd of rich natural gas, gross. EOG has a 99 percent working interest in the well.
Slagle #2H and #1 - Drilled in the western part of Cooke County, these wells were completed with initial rates of 495 and 539 Bopd with 138 and 307 Mcfd of rich natural gas, respectively. The Slagle #2H was drilled and completed horizontally, while the Slagle #1 was drilled and completed vertically. EOG has a 100 percent working interest in both wells.
Posey C#3H - Brought to sales at a rate of 536 Bopd with 416 Mcfd of rich natural gas, this well, in which EOG has a 100 percent working interest, was drilled in western Montague County.

In EOG's largest crude oil producing asset, the North Dakota Bakken, well completion operations resumed during the second quarter following the winter 2009-2010 drilling program. A significant number of wells began flowing to sales, contributing to EOG's overall crude oil production increase. These results included a number of horizontal Mandaree wells on EOG's 18,000 net acres in McKenzie County, North Dakota, southwest of Parshall. These wells were turned to sales in the third quarter with strong initial production rates and favorable economics.

EOG's North Dakota and Montana Bakken well highlights are:

Mandaree 4-15H - This well was completed in the second quarter at a peak production rate of 1,490 Bopd, gross. EOG has a 69 percent working interest in the well.
Mandaree 2-9H - EOG holds an 88 percent working interest in this well, which was drilled and completed to sales at a maximum rate of 1,358 Bopd, gross.
Mandaree 1-10H - Maximum initial production from this well, in which EOG has a 90 percent working interest, was 1,659 Bopd, gross.
Ed and Paul 1-17H - EOG has an 80 percent working interest in the well, which was drilled in Richland County, Montana and was completed to sales at a maximum gross rate of over 2,000 Bopd.

In its sixth year of development in the Bakken, EOG is operating a 10-rig drilling program in North Dakota and Montana.

In the New Mexico Leonard Shale, EOG reported continued drilling success on an additional 18,000 acres and, combined with previous reported success on 31,000 acres, has now proven up 49,000 of its 120,000 total net acre position. The Elk Wallow 11 State #1H has been producing for over 30 days at an average rate of 337 Bopd with 3,070 Mcfd of rich natural gas. The Elk Wallow 11 State #2H has been producing for 11 days at an average rate of 505 Bopd with 4,770 Mcfd of rich natural gas. EOG has 100 percent working interest in these Eddy County wells.

"EOG is delivering remarkable organic production growth from its portfolio of crude oil and liquids resource plays. In 2011, approximately 67 percent of EOG's North American revenue will be derived from liquids," said Papa. "By mid-2011, EOG expects to have optimized its South Texas Eagle Ford crude oil production such that it will be a meaningful long-term crude oil producer both for EOG and for the United States."

Based on reduced cash flows resulting from weak natural gas prices and fracture equipment delays, EOG has reduced its 2010 total company organic production growth forecast from 13 percent to 9 percent. Decreases in North American natural gas drilling activity account for 70 percent of the 2010 volume reduction. For 2011 and 2012, EOG has provided preliminary total company organic production growth forecasts of 10 percent and 12 percent, respectively. EOG expects crude oil and condensate production increases of 53 percent and 30 percent, respectively, to drive total company production growth for that two-year period.

Capital Structure

At September 30, 2010, EOG's total debt was $3,769 million for a debt-to-total capitalization ratio of 27 percent. Taking into account cash on the balance sheet of $28 million, at the end of the quarter EOG's net debt was $3,741 million and the net debt-to-total capitalization ratio was 27 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).)

To maintain a low debt-to-total capitalization ratio, during 2010 EOG has marketed certain of its properties, primarily natural gas. EOG expects to sell between $600 million and $1 billion of both producing and non-producing properties in North America. The majority of these transactions are expected to close during the fourth quarter of 2010. EOG incurred a $208.3 million, net of tax, impairment during the third quarter associated with certain of its Canadian shallow natural gas assets held for sale.

2011 Strategy

Following a comparison of its inventory of attractive rate of return, liquids-rich drilling opportunities against depressed natural gas prices, EOG has elected to pursue additional natural gas asset sales in 2011. Proceeds from these sales will be used primarily to offset any funding gap between planned capital expenditures and estimated cash flows. While previously targeting a maximum net debt-to-total capitalization ratio of 25 percent, EOG has set the maximum net debt-to-total capitalization ratio at 30 percent to 35 percent in order to optimally fund its portfolio of liquids-rich drilling opportunities.

"EOG remains committed to its long-term philosophy of delivering strong returns to shareholders and maintaining a conservative balance sheet," Mr. Papa said. "However, EOG does not intend to sell-down or joint venture any of its crude oil resource plays as we continue our strategic shift from natural gas to liquids. The growth potential of these robust assets is expected to accelerate EOG's shift toward liquids, while increasing our margins in the coming years."

Conference Call Scheduled for November 3, 2010

EOG's third quarter 2010 results conference call will be available via live audio webcast at 8 a.m. Central Daylight Time (9 a.m. Eastern Daylight Time) on Wednesday, November 3, 2010. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through November 17, 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 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 closely 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				Nine Months Ended
			September 30,				September 30,
			2010		2009		2010		2009

Net Operating Revenues			$	1,582.1	$	1,006.8	$	4,310.7	$	3,026.1
Net Income (Loss)			$	(70.9)	$	4.2	$	107.0	$	146.2
Net Income (Loss) Per Share
	Basic		$	(0.28)	$	0.02	$	0.43	$	0.59
	Diluted		$	(0.28)	$	0.02	$	0.42	$	0.58
Average Number of Shares Outstanding
	Basic			251.0		249.5		250.7		248.6
	Diluted			251.0		252.4		254.4		251.3


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


			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2010		2009		2010		2009
Net Operating Revenues
	Natural Gas		$	602,242	$	450,304	$	1,832,578	$	1,477,926
	Crude Oil, Condensate and Natural Gas Liquids			613,850		398,806		1,683,088		886,268
	Gains on Mark-to-Market Commodity Derivative Contracts			60,998		20,877		105,816		405,830
	Gathering, Processing and Marketing			233,971		134,553		601,790		249,679
	Gains (Losses) on Property Dispositions			64,809		(232)		72,441		510
	Other, Net			6,205		2,541		15,023		5,884
		Total		1,582,075		1,006,849		4,310,736		3,026,097
Operating Expenses
	Lease and Well			180,921		142,183		507,647		422,288
	Transportation Costs			103,262		70,971		286,318		205,844
	Gathering and Processing Costs			18,472		13,318		47,353		44,552
	Exploration Costs			47,307		44,910		148,635		128,840
	Dry Hole Costs			2,700		3,016		45,095		39,653
	Impairments			352,908		69,404		502,865		181,921
	Marketing Costs			231,758		131,816		591,735		237,819
	Depreciation, Depletion and Amortization			500,888		385,330		1,398,137		1,150,251
	General and Administrative			81,310		62,775		206,470		179,481
	Taxes Other Than Income			74,244		47,823		227,773		118,715
		Total		1,593,770		971,546		3,962,028		2,709,364

Operating Income (Loss)				(11,695)		35,303		348,708		316,733

Other Income (Expense), Net				5,772		(339)		7,910		2,637

Income (Loss) Before Interest Expense and Income Taxes				(5,923)		34,964		356,618		319,370

Interest Expense, Net				32,890		30,407		88,215		73,594

Income (Loss) Before Income Taxes				(38,813)		4,557		268,403		245,776

Income Tax Provision				32,093		361		161,422		99,576

Net Income (Loss)			$	(70,906)	$	4,196	$	106,981	$	146,200

Dividends Declared per Common Share			$	0.155	$	0.145	$	0.465	$	0.435

EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2010		2009		2010		2009
Wellhead Volumes and Prices
Natural Gas Volumes (MMcfd) ^(A)
	United States			1,175		1,128		1,096		1,153
	Canada			200		219		205		224
	Trinidad			333		268		342		266
	Other International ^(B)			14		13		15		15
		Total		1,722		1,628		1,658		1,658

Average Natural Gas Prices ($/Mcf) ^(C)
	United States		$	4.21	$	3.27	$	4.50	$	3.57
	Canada			3.42		3.15		4.09		3.67
	Trinidad			2.53		1.77		2.54		1.54
	Other International ^(B)			5.41		3.53		4.64		4.45
		Composite		3.80		3.01		4.05		3.27

Crude Oil and Condensate Volumes (MBbld) ^(A)
	United States			66.6		51.7		59.5		46.5
	Canada			5.9		4.7		6.1		3.6
	Trinidad			4.8		3.0		4.7		3.0
	Other International ^(B)			0.1		0.1		0.1		0.1
		Total		77.4		59.5		70.4		53.2

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
	United States		$	71.54	$	60.79	$	72.58	$	49.54
	Canada			69.12		61.43		71.32		51.91
	Trinidad			65.06		57.07		66.91		46.13
	Other International ^(B)			74.14		57.93		72.80		50.11
		Composite		70.96		60.65		72.09		49.51

Natural Gas Liquids Volumes (MBbld) ^(A)
	United States			31.1		23.1		27.4		22.2
	Canada			0.8		1.0		0.9		1.1
		Total		31.9		24.1		28.3		23.3

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
	United States		$	36.56	$	31.15	$	40.68	$	26.42
	Canada			40.34		30.96		42.90		27.29
		Composite		36.66		31.14		40.75		26.46

Natural Gas Equivalent Volumes (MMcfed) ^(D)
	United States			1,761		1,577		1,617		1,566
	Canada			240		253		247		252
	Trinidad			362		286		370		284
	Other International ^(B)			15		13		16		15
		Total		2,378		2,129		2,250		2,117

Total Bcfe ^(D)				218.8		195.9		614.1		578.1

(A)	Million cubic feet per day or thousand barrels per day, as applicable.
(B)	Other International includes EOG's United Kingdom and China operations.
(C)	Dollars per thousand cubic feet or per barrel, as applicable. Excludes the impact of financial commodity derivative instruments.
(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. Bcfe is calculated by multiplying the MMcfed 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)


			September 30,		December 31,
			2010		2009

	ASSETS
Current Assets
	Cash and Cash Equivalents		$	27,832	$	685,751
	Accounts Receivable, Net			897,732		771,417
	Inventories			381,263		261,723
	Assets from Price Risk Management Activities			60,728		20,915
	Income Taxes Receivable			89,357		37,009
	Other			77,533		62,726
	Total			1,534,445		1,839,541

Property, Plant and Equipment
	Oil and Gas Properties (Successful Efforts Method)			28,208,613		24,614,311
	Other Property, Plant and Equipment			1,598,453		1,350,132
	Total Property, Plant and Equipment			29,807,066		25,964,443
	Less: Accumulated Depreciation, Depletion and Amortization			(11,557,256)		(9,825,218)
	Total Property, Plant and Equipment, Net			18,249,810		16,139,225
Other Assets				160,604		139,901
Total Assets			$	19,944,859	$	18,118,667

	LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
	Accounts Payable		$	1,541,268	$	979,139
	Accrued Taxes Payable			114,763		92,858
	Dividends Payable			38,946		36,286
	Liabilities from Price Risk Management Activities			29,144		27,218
	Deferred Income Taxes			45,367		35,414
	Current Portion of Long-Term Debt			-		37,000
	Other			168,812		137,645
	Total			1,938,300		1,345,560


Long-Term Debt				3,768,638		2,760,000
Other Liabilities				695,855		632,652
Deferred Income Taxes				3,423,942		3,382,413
Commitments and Contingencies

Stockholders' Equity
	Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
	253,985,680 Shares Issued at September 30, 2010 and
	252,627,177 Shares Issued at December 31, 2009			202,540		202,526
	Additional Paid In Capital			695,046		596,702
	Accumulated Other Comprehensive Income			375,847		339,720
	Retained Earnings			8,855,869		8,866,747
	Common Stock Held in Treasury, 145,613 Shares at September 30, 2010
	and 118,525 Shares at December 31, 2009			(11,178)		(7,653)
		Total Stockholders' Equity		10,118,124		9,998,042
Total Liabilities and Stockholders' Equity			$	19,944,859	$	18,118,667

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

			Nine Months Ended
			September 30,
			2010		2009
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	106,981	$	146,200
	Items Not Requiring (Providing) Cash
		Depreciation, Depletion and Amortization		1,398,137		1,150,251
		Impairments		502,865		181,921
		Stock-Based Compensation Expenses		81,700		74,532
		Deferred Income Taxes		53,067		39,793
		Gains on Property Dispositions, Net		(72,441)		(510)
		Other, Net		(2,317)		3,248
	Dry Hole Costs			45,095		39,653
	Mark-to-Market Commodity Derivative Contracts
		Total Gains		(105,816)		(405,830)
		Realized Gains		25,180		986,980
	Excess Tax Benefits from Stock-Based Compensation			-		(34,052)
	Other, Net			13,354		9,385
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		(124,813)		119,099
		Inventories		(134,181)		(23,592)
		Accounts Payable		527,418		(361,698)
		Accrued Taxes Payable		(40,104)		16,097
		Other Assets		(16,051)		(4,255)
		Other Liabilities		44,348		9,357
	Changes in Components of Working Capital Associated with Investing and
	Financing Activities			(216,695)		147,097
Net Cash Provided by Operating Activities				2,085,727		2,093,676

Investing Cash Flows
	Additions to Oil and Gas Properties			(3,740,883)		(2,267,884)
	Additions to Other Property, Plant and Equipment			(223,072)		(240,614)
	Proceeds from Sales of Assets			126,371		2,515
	Changes in Components of Working Capital Associated with Investing
	Activities			216,546		(146,783)
	Other, Net			(4,206)		1,405
Net Cash Used in Investing Activities				(3,625,244)		(2,651,361)

Financing Cash Flows
	Net Commercial Paper Borrowings			33,700		-
	Long-Term Debt Borrowings			991,395		900,000
	Long-Term Debt Repayments			(37,000)		-
	Dividends Paid			(114,277)		(105,989)
	Excess Tax Benefits from Stock-Based Compensation			-		34,052
	Treasury Stock Purchased			(10,298)		(9,888)
	Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			24,527		13,691
	Debt Issuance Costs			(6,469)		(8,887)
	Other, Net			149		(314)
Net Cash Provided by Financing Activities				881,727		822,665

Effect of Exchange Rate Changes on Cash				(129)		12,220

(Decrease) Increase in Cash and Cash Equivalents				(657,919)		277,200
Cash and Cash Equivalents at Beginning of Period				685,751		331,311
Cash and Cash Equivalents at End of Period			$	27,832	$	608,511

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


The following chart adjusts three-month and nine-month periods ended September 30, 2010 and 2009 reported Net Income (Loss) (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 the loss on the impairment of certain of EOG's Canadian shallow natural gas assets in the third quarter 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 and to eliminate the gains on property dispositions primarily in the Rocky Mountain area. 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				Nine Months Ended
		September 30,				September 30,
		2010		2009		2010		2009

Reported Net Income (Loss) (GAAP)		$	(70,906)	$	4,196	$	106,981	$	146,200

Mark-to-Market (MTM) Commodity Derivative Contracts Impact
	Total Gains		(60,998)		(20,877)		(105,816)		(405,830)
	Realized Gains (Losses)		(13,647)		331,240		25,180		986,980
	Subtotal		(74,645)		310,363		(80,636)		581,150

	After-Tax MTM Impact		(47,791)		199,719		(51,627)		373,970

Add: Impairment of Canadian Shallow Natural Gas Assets, Net of Tax			208,331		-		208,331		-
Less: Gains on Property Dispositions, Net of Tax			(41,494)		-		(46,381)		-
Less: Change in Fair Value of Contingent Consideration Liability, Net of Tax			(1,587)		-		(12,941)		-

Adjusted Net Income (Non-GAAP)		$	46,553	$	203,915	$	204,363	$	520,170

Net Income (Loss) Per Share (GAAP)
	Basic	$	(0.28)	$	0.02	$	0.43	$	0.59
	Diluted	$	(0.28)	$	0.02	$	0.42	$	0.58

Adjusted Net Income Per Share (Non-GAAP)
	Basic	$	0.19	$	0.82	$	0.82	$	2.09
	Diluted	$	0.18	$	0.81	$	0.80	$	2.07

Average Number of Shares (GAAP)
	Basic		251,015		249,535		250,719		248,647
	Diluted		251,015		252,422		254,444		251,288

Average Number of Shares (Non-GAAP)
	Basic		251,015		249,535		250,719		248,647
	Diluted		254,572		252,422		254,444		251,288

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 nine-month periods ended September 30, 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				Nine Months Ended
			September 30,				September 30,
			2010		2009		2010		2009

Net Cash Provided by Operating Activities (GAAP)			$	784,387	$	816,458	$	2,085,727	$	2,093,676

Adjustments
	Exploration Costs (excluding Stock-Based Compensation Expenses)			40,095		39,814		130,598		113,644
	Excess Tax Benefits from Stock-Based Compensation			-		12,178		-		34,052
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		85,538		29,922		124,813		(119,099)
		Inventories		66,818		1,441		134,181		23,592
		Accounts Payable		(272,540)		(53,125)		(527,418)		361,698
		Accrued Taxes Payable		34,093		(11,966)		40,104		(16,097)
		Other Assets		(8,448)		(3,232)		16,051		4,255
		Other Liabilities		(55,278)		(34,199)		(44,348)		(9,357)
	Changes in Components of Working Capital Associated
		with Investing and Financing Activities		80,722		22,086		216,695		(147,097)

Discretionary Cash Flow (Non-GAAP)			$	755,387	$	819,377	$	2,176,403	$	2,339,267

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.


		September 30,
		2010

	Total Stockholders' Equity - (a)	$	10,118

	Current and Long-Term Debt - (b)		3,769
	Less: Cash		(28)
	Net Debt (Non-GAAP) - (c)		3,741

	Total Capitalization (GAAP) - (a) + (b)	$	13,887

	Total Capitalization (Non-GAAP) - (a) + (c)	$	13,859

	Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		27%

	Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		27%

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

(a) Fourth Quarter and Full Year 2010 Forecast The forecast items for the fourth 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)
				4Q 2010				Full Year 2010
Daily Production
	Natural Gas Volumes (MMcfd)
		United States		1,200	-	1,290		1,122	-	1,145
		Canada		165	-	200		195	-	205
		Trinidad		265	-	335		322	-	340
		Other International		10	-	14		13	-	15
			Total	1,640	-	1,839		1,652	-	1,705

	Crude Oil and Condensate Volumes (MBbld)
		United States		71.0	-	84.0		62.4	-	65.7
		Canada		7.0	-	9.0		6.3	-	6.8
		Trinidad		4.0	-	5.0		4.5	-	4.8
			Total	82.0	-	98.0		73.2	-	77.3

	Natural Gas Liquids Volumes (MBbld)
		United States		28.0	-	40.0		27.5	-	30.5
		Canada		0.5	-	1.0		0.8	-	1.0
			Total	28.5	-	41.0		28.3	-	31.5

	Natural Gas Equivalent Volumes (MMcfed)
		United States		1,794	-	2,034		1,661	-	1,722
		Canada		210	-	260		238	-	252
		Trinidad		289	-	365		349	-	369
		Other International		10	-	14		13	-	15
			Total	2,303	-	2,673		2,261	-	2,358


				ESTIMATED RANGES
				(Unaudited)
				4Q 2010				Full Year 2010
Operating Costs
	Unit Costs ($/Mcfe)
		Lease and Well		$ 0.80	-	$ 0.85		$ 0.81	-	$ 0.84
		Transportation Costs		$ 0.45	-	$ 0.50		$ 0.45	-	$ 0.48
		Depreciation, Depletion and Amortization		$ 2.38	-	$ 2.48		$ 2.31	-	$ 2.38

Expenses ($MM)
	Exploration, Dry Hole and Impairment			$ 160.0	-	$ 175.0		$ 577.0	-	$ 592.0	*
	General and Administrative			$ 75.0	-	$ 80.0		$ 280.0	-	$ 288.0
	Gathering and Processing			$ 16.5	-	$ 19.0		$ 64.0	-	$ 66.5
	Capitalized Interest			$ 19.0	-	$ 21.5		$ 75.0	-	$ 78.5
	Net Interest			$ 35.0	-	$ 37.0		$ 122.0	-	$ 125.0

Taxes Other Than Income (% of Revenue)				6.3%	-	6.6%		6.4%	-	6.7%

Income Taxes
	Effective Rate			30%	-	45%		40%	-	50%
	Current Taxes ($MM)			$ 75	-	$ 90		$ 180	-	$ 200

Capital Expenditures ($MM) - FY 2010 (Excluding Acquisitions)
	Exploration and Development, Excluding Facilities						Approximately			$ 4,970
	Exploration and Development Facilities						Approximately			$ 380
	Gathering, Processing and Other						Approximately			$ 400

Pricing - (Refer to Benchmark Commodity Pricing in text)
	Natural Gas ($/Mcf)
		Differentials (include the effect of physical contracts)
			United States - below NYMEX Henry Hub	$ 0.15	-	$ 0.25		$ 0.14	-	$ 0.18
			Canada - below NYMEX Henry Hub	$ 0.26	-	$ 0.36		$ 0.45	-	$ 0.50

		Realizations
			Trinidad	$ 1.90	-	$ 2.60		$ 2.34	-	$ 2.62
			Other International	$ 4.00	-	$ 6.50		$ 4.25	-	$ 5.25

	Crude Oil and Condensate ($/Bbl)
		Differentials
			United States - below WTI	$ 4.00	-	$ 6.50		$ 4.45	-	$ 5.00
			Canada - below WTI	$ 6.25	-	$ 7.50		$ 5.90	-	$ 6.50
			Trinidad - below WTI	$ 10.00	-	$ 12.80		$ 10.00	-	$ 11.75

* Excludes $280 million impairment of certain Canadian shallow natural gas assets held for sale.

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