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)
		Elizabeth M. Ivers
		(713) 651-7132

		Media
		K Leonard
		(713) 571-3870

EOG Resources Reports Second Quarter 2011 Results

Reports 13 Percent Total Company Production Growth in the First Half of 2011 Versus 2010

Achieves 60 Percent Growth in Second Quarter United States Crude Oil and Condensate Volumes Year-Over-Year

On Track to Achieve 9.5 Percent Total Company Production Growth in 2011

Continues to Realize Top Quality, Consistent Results from Eagle Ford Oil

Adds Oklahoma Panhandle Marmaton to Horizontal Crude Oil Play Book

Announces Favorable Well Completions from West Texas Wolfcamp and New Mexico Leonard and Bone Spring Plays

Maintains Strong Performance in North Dakota

Raises Prospectivity Level of Colorado Niobrara Acreage

Anticipates Additional $600 Million of 2011 Asset Dispositions to Offset Capital Expenditure Increase

FOR IMMEDIATE RELEASE: Thursday, August 4, 2011

HOUSTON - EOG Resources, Inc. (EOG) today reported second quarter 2011 net income of $295.6 million, or $1.10 per share. This compares to second quarter 2010 net income of $59.9 million, or $0.24 per share.

Consistent with some analysts' practice of matching cash flow realizations to settlement months, and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the second quarter 2011 was $299.2 million, or $1.11 per share. Adjusted non-GAAP net income for the second quarter 2010 was $44.9 million, or $0.18 per share. The results for the second quarter 2011 included a $226.2 million, net of tax ($0.84 per share) impairment of certain non-core North American natural gas assets, gains on property dispositions, net of tax, of $105.2 million ($0.39 per share) and a previously disclosed non-cash net gain of $189.6 million ($121.4 million after tax, or $0.45 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $6.3 million ($4.0 million after tax, or $0.01 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

Operational Highlights

Total company production increased 13 percent in the first half of 2011 compared to the same period in 2010. Driven by a 60 percent rise in United States crude oil and condensate production during the second quarter, EOG delivered 46 percent total company crude oil, condensate and natural gas liquids production growth versus the second quarter 2010. Leading the crude oil production growth was the South Texas Eagle Ford followed by the Fort Worth Barnett Shale Combo. Also contributing to the increase were newer crude oil and liquids-rich plays such as the Colorado Niobrara, Oklahoma Marmaton, West Texas Wolfcamp and New Mexico Leonard.

"Demonstrating the depth and quality of our portfolio, EOG's crude oil and liquids-rich plays delivered strong, consistent second quarter production results, driving our overall first half 2011 production growth," said Mark G. Papa, Chairman and Chief Executive Officer. "Just as we had forecast, EOG's natural gas production is decreasing due to asset sales and the priority we have placed on developing our outstanding crude oil and liquids investment opportunities."

EOG is on track to achieve its targeted 9.5 percent total company organic production growth for 2011. Total company 2011 crude oil and condensate production is projected to increase by 52 percent, while total company crude oil, condensate and natural gas liquids production is forecast to rise 47 percent over 2010.

Crude Oil and Liquids Activity

Early in its transition to a liquids-focused company, EOG identified the rich oil potential of the South Texas Eagle Ford Shale and amassed a large acreage position in the sweet spot of the crude oil window.

"We are finding that well results across our 535,000 net acre position in the Eagle Ford oil window are remarkably similar. The wealth of drilling, completion and production data at our fingertips is reflected in the steadily rising momentum of our operations and success in achieving more predictable results," Papa said.

As EOG further defines geologic sub-trends and refines completion techniques, the majority of its Eagle Ford wells are being completed to sales at initial production rates in excess of 1,000 barrels of crude oil per day (Bopd). Leveraging this consistency, EOG ramped up its drilling activity from 10 rigs at the beginning of 2011 to its current intensive program of 22 rigs.

In Gonzales County where EOG is actively drilling, the King Fehner Unit #2H, #4H, #5H and #6H wells began initial production at maximum rates ranging from 1,238 to 1,487 Bopd with 1.2 to 1.6 million cubic feet per day (MMcfd) of rich natural gas.

"These are the first Eagle Ford wells that EOG has tested with a tighter spacing pattern. If downspacing proves economically viable, we have the potential to significantly increase our reserves in the Eagle Ford," Papa said.

EOG reported production rates from other successful wells in Gonzales County. The Merritt #4H had a peak initial production rate of 1,361 Bopd with 0.6 MMcfd of rich natural gas. The Steen Unit #1H, #2H, #4H and #6H came online with production rates ranging from 663 to 1,269 Bopd with 0.7 to 1.4 MMcfd of rich natural gas. In its far northeastern acreage where EOG announced success from a fault block earlier this year, the Hill Unit #1H and #3H were completed. They flowed to sales at peak rates of 1,461 and 1,734 Bopd with 1.0 and 1.3 MMcfd of rich natural gas, respectively.

In La Salle County, the Naylor Jones A #2H, 99 #1H and 96 #1H provided additional confirmation of the consistent quality of EOG's 120-mile acreage trend. The wells, located in the southwestern part of EOG's block, had strong production rates ranging from 997 to 1,153 Bopd with 1.0 to 2.3 MMcfd of rich natural gas. In Karnes County, the heart of EOG's extensive acreage, the Max Unit #1H had a peak initial production rate of 1,591 Bopd with 1.5 MMcfd of rich natural gas. Also in Karnes County, the Braune Unit #1H was turned to sales at an initial rate of 1,611 Bopd with 1.0 MMcfd of rich natural gas. EOG has 100 percent working interest in all 16 of these Eagle Ford wells.

"With the 77 percent crude oil mix of our Eagle Ford acreage position, this large, highly rated resource play has become a significant contributor to fueling EOG's transition to an oil company in a short period of time," Papa said.

EOG announced positive drilling results from a new horizontal crude oil play, the Marmaton sandstone in the Oklahoma Panhandle. In Ellis County where EOG has drilled a series of wells, the Brown 18 #1VH and Opal 31 #1H were completed to sales at production rates of 620 and 1,312 Bopd with 0.7 and 2.6 MMcfd of natural gas, respectively. EOG has 58 and 49 percent working interest in the wells, respectively. EOG has 88 percent working interest in the Fischer 12 #1VH, which began initial production at 508 Bopd, with strong natural gas production. Encouraging well results provide the potential for additional development drilling locations on its 34,000 net acre position. To identify further exploration opportunities, EOG plans to acquire 3D seismic over this acreage.

EOG continues to post excellent drilling results from its 131,400 net acre position in the West Texas Wolfcamp and its 108,000 net acre position in the New Mexico Leonard Shale and Bone Spring Sands plays. The current moderate level of drilling activity is expected to ramp up in 2012 and beyond. Following refinements in completion techniques, recent well results show improvement in crude oil production flow rates.

Drilled and completed in the West Texas Wolfcamp, the University 40-A #0401H began flowing to sales at a maximum oil rate of 935 Bopd with 838 thousand cubic feet per day (Mcfd) of rich natural gas. EOG has 85 percent working interest in this Irion County well. Also in Irion County, the Linthicum M #1H and I #5H had production rates of 809 and 664 Bopd with 892 and 1,178 Mcfd of rich natural gas, respectively. EOG has 75 and 85 percent working interest in the wells, respectively. EOG has 100 percent working interest in the University 9 #2802H, drilled in Reagan County, northwest of its Irion County and Crockett County activity. The well had a peak production rate of 583 Bopd with 254 Mcfd of rich natural gas.

In Lea County, New Mexico where EOG is developing its Leonard Shale acreage, the Caballo 23 #1H was completed at a production rate of 665 Bopd with 1.2 MMcfd of rich natural gas. EOG has 86 percent working interest in the well. In Eddy County, the Elk Wallow 11 St. #4 had a maximum production rate of 735 Bopd with 2.0 MMcfd of rich natural gas. EOG has 75 percent working interest in this Leonard Shale well. Also in Eddy County, EOG drilled the Parkway 23 State #3H in the Bone Spring Sands, which is producing 511 Bopd with 726 Mcfd of natural gas. EOG holds 81 percent working interest in the well.

Since mid-2009, EOG's Denver-Julesburg Basin drilling activity has been concentrated on its 80,000 net acre Hereford Ranch Field in Weld County, Colorado. The Jake 2-01H discovery, which was drilled as a horizontal well targeting the Niobrara formation, began initial production in late 2009 at a first month average rate of 645 Bopd. Since the first quarter 2011, it has been producing at a relatively stable rate of 250 to 300 Bopd. Following the Jake well, the Elmer 8-31H, which was drilled in March 2010 with a short lateral, had an initial average 30-day production rate of 283 Bopd and is currently producing approximately 225 Bopd. Encouraging data from long-term stabilized crude oil production rates indicate that the Niobrara wells will be characterized by lower initial flow rates, but flatter decline curves than other crude oil resource plays.

Acreage outside EOG's Hereford Ranch Field was also proven productive during the quarter. Southeast of the Hereford Ranch Field, the Fiscus Mesa 9-10H was drilled and completed to sales at an initial controlled rate of 335 Bopd with 174 Mcfd of natural gas. EOG has 86 percent working interest in the well. West of the Fiscus Mesa well, EOG has 75 percent working interest in the Gravel Draw 9-09H that began production at an initial controlled rate of 277 Bopd with 146 Mcfd of natural gas. Based on long-term well production results from its Hereford Ranch Field and new drilling results and production data, EOG has established the economic potential for crude oil development on 169,000 of its 220,000 net acre Niobrara position.

In the Texas Fort Worth Barnett Combo, EOG's program in Montague County and western Cooke County continues to deliver successful production results with efficiency gains in both drilling and completion operations. In western Cooke County, the Gaedke A Unit #3H and #4H and B Unit #5H, #6H and #7H wells were brought to sales at rates ranging from 338 to 696 Bopd with 807 to 2,152 Mcfd of rich natural gas. EOG has 99 percent working interest in the wells. In Montague County, EOG has 100 percent working interest in the Stoddard A Unit #1H, B Unit #2H, C Unit #3H and D Unit #4H that came online at rates ranging from 777 to 918 Bopd with 1,262 to 2,677 Mcfd of rich natural gas. While EOG's efforts have focused on testing new completion techniques in the sweet spot of its core acreage, an inventory of several years of drilling locations has been identified in the play.

Despite weather challenges in the North Dakota Williston Basin over the last eight to nine months, EOG continued its drilling and production activities, as well as operating its proprietary crude-by-rail transportation system. Although EOG minimized the adverse impact of abnormally wet weather on production goals during the second quarter, completion operations were impacted and area flooding remains an issue.

Drilled with a 9,968 foot long-reach lateral, the Liberty LR #21-36H was completed to sales at a maximum rate of 1,201 Bopd with 1,147 Mcfd of natural gas. EOG has 95 percent working interest in the well. The Fertile #19-29H and #45-29H were both completed in the Bakken formation in Mountrail County. The wells, in which EOG has 38 and 75 percent working interest, respectively, came online at maximum rates of 1,008 and 1,223 Bopd, respectively. In Williams County, EOG has 67 percent working interest in the Hardscrabble 13-3526H, which began flowing to sales at 1,474 Bopd. EOG holds 85 percent working interest in the Clarks Creek 3-0805H, which was completed in the Three Forks formation in McKenzie County at a maximum production rate of 1,384 Bopd.

"EOG's early innovative crude-by-rail midstream investments in the Bakken and Eagle Ford have proven valuable in delivering our crude oil directly to major market hubs given the current lack of available pipeline capacity in these two prolific plays," Papa said. "Our Bakken crude oil rail transportation system was particularly beneficial during the recent North Dakota flooding because it enabled EOG to continue to make crude oil deliveries."

Natural Gas Activity

In North America, EOG's natural gas production decreased 1.6 percent in the second quarter compared to the same prior year period due to reduced drilling activity and natural gas asset sales. In the United States where EOG is employing drilling capital to maintain core leasehold positions, it posted strong operational results from its Marcellus Shale and Haynesville/Bossier Shale natural gas horizontal resource plays. In Canada, EOG's natural gas production decreased due to asset divestitures and the reallocation of capital toward liquids-rich reinvestment opportunities.

Capital Structure

During the second quarter, total cash proceeds from sales of acreage, producing natural gas properties and midstream assets were approximately $684 million. Through the first half of 2011, total cash proceeds from assets sales were $944 million. Based on negotiated purchase and sale agreements and other pending transactions, EOG anticipates property sales for the full year of approximately $1.6 billion, or $600 million higher than the original $1 billion target for 2011. Estimated exploration and production expenditures will range from $6.8 billion to $7.0 billion, including exploration, development and production facilities and midstream expenditures, an increase of approximately $400 million from EOG's previously stated targets.

At June 30, 2011, EOG's total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 30 percent. Taking into account $1.6 billion of cash on the balance sheet at the end of the quarter, EOG's net debt was $3.6 billion for a net debt-to-total capitalization ratio of 23 percent. EOG is targeting a net debt-to-total capitalization ratio of 30 percent or less at both year-end 2011 and 2012. (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).)

"Our well-timed efforts to recreate EOG as a high margin, crude oil-focused company are paying off," Papa said. "On the basis of both per share earnings and cash flow growth, EOG is positioned to be an industry leader for years to come."

Conference Call Scheduled for August 5, 2011

EOG's second quarter 2011 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Friday, August 5, 2011. To listen, log onto www.eogresources.com. The webcast will be archived on EOG's website through August 19, 2011.

EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Canada, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."

This press release 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, and demand for, crude oil, natural gas and related commodities;
the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
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 crude oil and natural gas exploration and development projects, given the risks and uncertainties inherent in drilling, completing and operating crude oil and natural gas wells and the potential for interruptions of development and production, whether involuntary or intentional as a result of market or other conditions;
the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;
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;
the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal and hydraulic fracturing and laws and regulations imposing conditions and restrictions on drilling and completion operations;
EOG's ability to effectively integrate acquired crude oil and natural gas 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;
the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
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;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
weather, including its impact on crude oil and natural gas 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 extent and effect of any hedging activities engaged in by EOG;
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 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 20 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2010 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

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) 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, 2010, 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				Six Months Ended
			June 30,				June 30,
			2011		2010		2011		2010

Net Operating Revenues			$	2,570.3	$	1,358.0	$	4,467.4	$	2,728.7
Net Income			$	295.6	$	59.9	$	429.5	$	177.9
Net Income Per Share
	Basic		$	1.11	$	0.24	$	1.65	$	0.71
	Diluted		$	1.10	$	0.24	$	1.63	$	0.70
Average Number of Shares Outstanding
	Basic			265.8		250.8		259.8		250.6
	Diluted			269.3		254.5		263.4		254.2


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


			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2011		2010		2011		2010
Net Operating Revenues
	Crude Oil and Condensate		$	938,518	$	455,808	$	1,695,880	$	861,970
	Natural Gas Liquids			183,805		104,241		332,532		207,268
	Natural Gas			599,993		553,354		1,183,912		1,230,336
	Gains on Mark-to-Market Commodity Derivative Contracts			189,621		37,015		122,875		44,818
	Gathering, Processing and Marketing			487,698		195,876		883,281		367,819
	Gains on Asset Dispositions, Net			163,771		8,307		235,513		7,632
	Other, Net			6,844		3,367		13,363		8,818
		Total		2,570,250		1,357,968		4,467,356		2,728,661
Operating Expenses
	Lease and Well			216,695		160,734		431,784		326,726
	Transportation Costs			101,965		94,345		199,598		183,056
	Gathering and Processing Costs			17,716		13,220		36,912		28,881
	Exploration Costs			41,238		50,131		92,147		101,328
	Dry Hole Costs			1,676		19,318		24,627		42,395
	Impairments			358,654		80,362		447,982		149,957
	Marketing Costs			469,437		191,213		854,846		359,977
	Depreciation, Depletion and Amortization			602,944		465,343		1,171,170		897,249
	General and Administrative			67,406		64,737		137,443		125,160
	Taxes Other Than Income			104,266		78,064		210,143		153,529
		Total		1,981,997		1,217,467		3,606,652		2,368,258

Operating Income				588,253		140,501		860,704		360,403

Other Income (Expense), Net				6,224		(545)		9,828		2,138

Income Before Interest Expense and Income Taxes				594,477		139,956		870,532		362,541

Interest Expense, Net				51,253		29,897		101,586		55,325

Income Before Income Taxes				543,224		110,059		768,946		307,216

Income Tax Provision				247,650		50,187		339,399		129,329

Net Income			$	295,574	$	59,872	$	429,547	$	177,887

Dividends Declared per Common Share			$	0.160	$	0.155	$	0.320	$	0.310

EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2011		2010		2011		2010
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) ^(A)
	United States			92.3		57.6		86.8		55.9
	Canada			8.8		6.6		8.6		6.2
	Trinidad			3.3		5.4		3.9		4.6
	Other International ^(B)			0.1		0.1		0.1		0.1
		Total		104.5		69.7		99.4		66.8

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
	United States		$	99.50	$	73.18	$	94.05	$	73.23
	Canada			102.65		71.63		93.65		72.39
	Trinidad			99.49		68.90		92.33		67.89
	Other International ^(B)			101.52		73.21		93.67		72.18
		Composite		99.77		72.69		93.95		72.77

Natural Gas Liquids Volumes (MBbld) ^(A)
	United States			38.4		27.5		36.5		25.6
	Canada			0.7		0.9		0.8		0.9
		Total		39.1		28.4		37.3		26.5

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
	United States		$	51.50	$	40.31	$	49.21	$	43.23
	Canada			60.39		42.55		52.77		44.09
		Composite		51.65		40.38		49.29		43.25

Natural Gas Volumes (MMcfd) ^(A)
	United States			1,114		1,069		1,124		1,055
	Canada			139		204		141		208
	Trinidad			349		341		367		346
	Other International ^(B)			13		15		13		16
		Total		1,615		1,629		1,645		1,625

Average Natural Gas Prices ($/Mcf) ^(C)
	United States		$	4.24	$	4.12	$	4.17	$	4.67
	Canada			4.16		3.60		3.91		4.42
	Trinidad			3.51		2.58		3.35		2.54
	Other International ^(B)			5.61		4.27		5.62		4.27
		Composite		4.08		3.73		3.98		4.18

Crude Oil Equivalent Volumes (MBoed) ^(D)
	United States			316.4		263.2		310.7		257.5
	Canada			32.6		41.5		32.9		41.7
	Trinidad			61.4		62.2		65.0		62.3
	Other International ^(B)			2.2		2.7		2.3		2.7
		Total		412.6		369.6		410.9		364.2

Total MMBoe ^(D)				37.5		33.6		74.4		65.9

(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)


		June 30,		December 31,
		2011		2010

	ASSETS
Current Assets
	Cash and Cash Equivalents	$	1,577,438	$	788,853
	Accounts Receivable, Net		1,279,740		1,113,279
	Inventories		540,094		415,792
	Assets from Price Risk Management Activities		109,225		48,153
	Income Taxes Receivable		27,694		54,916
	Deferred Income Taxes		-		9,260
	Other		103,759		97,193
	Total		3,637,950		2,527,446

Property, Plant and Equipment
	Oil and Gas Properties (Successful Efforts Method)		31,588,860		29,263,809
	Other Property, Plant and Equipment		1,871,497		1,733,073
	Total Property, Plant and Equipment		33,460,357		30,996,882
	Less: Accumulated Depreciation, Depletion and Amortization		(13,463,534)		(12,315,982)
	Total Property, Plant and Equipment, Net		19,996,823		18,680,900
Other Assets			324,606		415,887
Total Assets		$	23,959,379	$	21,624,233

	LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
	Accounts Payable	$	1,870,172	$	1,664,944
	Accrued Taxes Payable		148,645		82,168
	Dividends Payable		42,976		38,962
	Liabilities from Price Risk Management Activities		12,393		28,339
	Deferred Income Taxes		50,180		41,703
	Current Portion of Long-Term Debt		220,000		220,000
	Other		131,872		143,983
	Total		2,476,238		2,220,099


Long-Term Debt			5,006,251		5,003,341
Other Liabilities			718,696		667,455
Deferred Income Taxes			3,681,009		3,501,706
Commitments and Contingencies

Stockholders' Equity
	Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
	268,698,963 Shares Issued at June 30, 2011 and
	254,223,521 Shares Issued at December 31, 2010		202,687		202,542
	Additional Paid In Capital		2,181,157		729,992
	Accumulated Other Comprehensive Income		492,880		440,071
	Retained Earnings		9,213,356		8,870,179
	Common Stock Held in Treasury, 143,309 Shares at June 30, 2011
	and 146,186 Shares at December 31, 2010		(12,895)		(11,152)
	Total Stockholders' Equity		12,077,185		10,231,632
Total Liabilities and Stockholders' Equity		$	23,959,379	$	21,624,233

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

			Six Months Ended
			June 30,
			2011		2010
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	429,547	$	177,887
	Items Not Requiring (Providing) Cash
		Depreciation, Depletion and Amortization		1,171,170		897,249
		Impairments		447,982		149,957
		Stock-Based Compensation Expenses		53,427		44,953
		Deferred Income Taxes		206,130		24,493
		Gains on Asset Dispositions, Net		(235,513)		(7,632)
		Other, Net		(834)		(1,252)
	Dry Hole Costs			24,627		42,395
	Mark-to-Market Commodity Derivative Contracts
		Total Gains		(122,875)		(44,818)
		Realized Gains		31,285		38,827
	Other, Net			13,268		8,454
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		(165,300)		(39,275)
		Inventories		(127,062)		(67,363)
		Accounts Payable		189,250		254,878
		Accrued Taxes Payable		94,311		(6,011)
		Other Assets		(4,796)		(24,499)
		Other Liabilities		(12,017)		(10,930)
	Changes in Components of Working Capital Associated with Investing and Financing Activities			76,640		(135,973)
Net Cash Provided by Operating Activities				2,069,240		1,301,340

Investing Cash Flows
	Additions to Oil and Gas Properties			(3,122,567)		(2,288,270)
	Additions to Other Property, Plant and Equipment			(340,140)		(115,661)
	Proceeds from Sales of Assets			944,481		41,939
	Changes in Components of Working Capital Associated with Investing Activities			(76,852)		135,693
	Other, Net			-		(4,157)
Net Cash Used in Investing Activities				(2,595,078)		(2,230,456)

Financing Cash Flows
	Common Stock Sold			1,388,270		-
	Long-Term Debt Borrowings			-		991,395
	Long-Term Debt Repayments			-		(37,000)
	Dividends Paid			(81,562)		(75,179)
	Treasury Stock Purchased			(16,736)		(7,307)
	Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			24,619		21,023
	Debt Issuance Costs			-		(1,194)
	Other, Net			212		280
Net Cash Provided by Financing Activities				1,314,803		892,018

Effect of Exchange Rate Changes on Cash				(380)		1,461

Increase (Decrease) in Cash and Cash Equivalents				788,585		(35,637)
Cash and Cash Equivalents at Beginning of Period				788,853		685,751
Cash and Cash Equivalents at End of Period			$	1,577,438	$	650,114

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 six-month periods ended June 30, 2011 and 2010 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 non-core North American natural gas assets in the first and second quarters of 2011, to eliminate the gains on asset dispositions primarily in North America in the first and second quarters of 2011, and 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 in the first and second quarters of 2010. 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				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010

Reported Net Income (GAAP)		$	295,574	$	59,872	$	429,547	$	177,887

Mark-to-Market (MTM) Commodity Derivative Contracts Impact
	Total Gains		(189,621)		(37,015)		(122,875)		(44,818)
	Realized Gains		6,348		15,867		31,285		38,827
	Subtotal		(183,273)		(21,148)		(91,590)		(5,991)

	After-Tax MTM Impact		(117,281)		(13,540)		(58,641)		(3,836)

Add: Impairments of Certain Non-core North American Natural Gas Assets, Net of Tax			226,177		-		256,460		-
Less: Gains on Asset Dispositions, Net of Tax			(105,224)		-		(151,110)		-
Less: Change in Fair Value of Contingent Consideration Liability, Net of Tax			-		(1,421)		-		(11,354)

Adjusted Net Income (Non-GAAP)		$	299,246	$	44,911	$	476,256	$	162,697

Net Income Per Share (GAAP)
	Basic	$	1.11	$	0.24	$	1.65	$	0.71
	Diluted	$	1.10	$	0.24	$	1.63	$	0.70

Adjusted Net Income Per Share (Non-GAAP)
	Basic	$	1.13	$	0.18	$	1.83	$	0.65
	Diluted	$	1.11	$	0.18	$	1.81	$	0.64

Average Number of Shares
	Basic		265,830		250,825		259,766		250,596
	Diluted		269,332		254,503		263,363		254,206

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 the three-month and six-month periods ended June 30, 2011 and 2010 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), 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				Six Months Ended
			June 30,				June 30,
			2011		2010		2011		2010

Net Cash Provided by Operating Activities (GAAP)			$	1,111,752	$	681,053	$	2,069,240	$	1,301,340

Adjustments
	Exploration Costs (excluding Stock-Based Compensation Expenses)			35,775		44,820		80,542		90,503
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		51,445		(56,495)		165,300		39,275
		Inventories		59,329		14,051		127,062		67,363
		Accounts Payable		(23,753)		(107,246)		(189,250)		(254,878)
		Accrued Taxes Payable		(14,563)		2,221		(94,311)		6,011
		Other Assets		(13,860)		11,005		4,796		24,499
		Other Liabilities		20,638		5,376		12,017		10,930
	Changes in Components of Working Capital Associated
		with Investing and Financing Activities		(74,655)		61,381		(76,640)		135,973

Discretionary Cash Flow (Non-GAAP)			$	1,152,108	$	656,166	$	2,098,756	$	1,421,016

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.

		June 30,
		2011

	Total Stockholders' Equity - (a)	$	12,077

	Current and Long-Term Debt - (b)		5,226
	Less: Cash		(1,577)
	Net Debt (Non-GAAP) - (c)		3,649

	Total Capitalization (GAAP) - (a) + (b)	$	17,303

	Total Capitalization (Non-GAAP) - (a) + (c)	$	15,726

	Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		30%

	Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		23%

EOG RESOURCES, INC.
THIRD QUARTER AND FULL YEAR 2011 FORECAST AND BENCHMARK COMMODITY PRICING

(a) Third Quarter and Full Year 2011 Forecast The forecast items for the third 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. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, 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)
				3Q 2011			Full Year 2011
Daily Production
	Crude Oil and Condensate Volumes (MBbld)
		United States		103.5	-	113.5	99.4	-	105.7
		Canada		6.5	-	8.0	7.0	-	8.2
		Trinidad		2.2	-	3.2	3.0	-	3.5
			Total	112.2	-	124.7	109.4	-	117.4

	Natural Gas Liquids Volumes (MBbld)
		United States		38.5	-	43.5	38.5	-	40.9
		Canada		0.7	-	1.1	0.8	-	1.0
			Total	39.2	-	44.6	39.3	-	41.9

	Natural Gas Volumes (MMcfd)
		United States		1,100	-	1,130	1,114	-	1,130
		Canada		115	-	125	126	-	130
		Trinidad		300	-	320	338	-	360
		Other International		9	-	13	12	-	16
			Total	1,524	-	1,588	1,590	-	1,636

	Crude Oil Equivalent Volumes (MBoed)
		United States		325.3	-	345.4	323.6	-	334.9
		Canada		26.4	-	29.9	28.8	-	30.9
		Trinidad		52.2	-	56.5	59.3	-	63.5
		Other International		1.5	-	2.2	2.0	-	2.7
			Total	405.4	-	434.0	413.7	-	432.0


				ESTIMATED RANGES
				(Unaudited)
				3Q 2011			Full Year 2011
Operating Costs
	Unit Costs ($/Boe)
		Lease and Well		$ 5.85	-	$ 6.45	$ 5.88	-	$ 6.24
		Transportation Costs		$ 2.89	-	$ 3.25	$ 2.82	-	$ 3.00
		Depreciation, Depletion and Amortization		$ 16.20	-	$ 17.16	$ 16.12	-	$ 16.54

Expenses ($MM)
	Exploration, Dry Hole and Impairment			$ 145.0	-	$ 175.0	$ 518.0	-	$ 563.0
	General and Administrative			$ 92.0	-	$ 99.0	$ 311.0	-	$ 325.0
	Gathering and Processing			$ 16.5	-	$ 20.5	$ 70.0	-	$ 77.0
	Capitalized Interest			$ 13.0	-	$ 17.0	$ 56.0	-	$ 64.0
	Net Interest			$ 48.5	-	$ 53.5	$ 197.5	-	$ 207.0

Taxes Other Than Income (% of Revenue)				5.8%	-	6.4%	6.0%	-	6.7%

Income Taxes
	Effective Rate			35%	-	50%	35%	-	45%
	Current Taxes ($MM)			$ 60	-	$ 75	$ 260	-	$ 280

Capital Expenditures ($MM) - FY 2011 (Excluding Acquisitions)
	Exploration and Development, Excluding Facilities						$ 5,750	-	$ 5,850
	Exploration and Development Facilities						$ 450	-	$ 500
	Gathering, Processing and Other						$ 600	-	$ 650

Pricing - (Refer to Benchmark Commodity Pricing in text)
	Crude Oil and Condensate ($/Bbl)
		Differentials
			United States - below WTI	$ 3.75	-	$ 6.25	$ 4.00	-	$ 6.00
			Canada - below WTI	$ 7.00	-	$ 8.15	$ 5.50	-	$ 6.75
			Trinidad - below WTI	$ 8.15	-	$ 12.15	$ 6.35	-	$ 9.25

	Natural Gas ($/Mcf)
		Differentials
			United States - below NYMEX Henry Hub	$ 0.05	-	$ 0.15	$ 0.03	-	$ 0.15
			Canada - below NYMEX Henry Hub	$ 0.35	-	$ 0.55	$ 0.30	-	$ 0.50

		Realizations
			Trinidad	$ 2.25	-	$ 3.00	$ 2.80	-	$ 3.15
			Other International	$ 5.25	-	$ 6.00	$ 5.35	-	$ 6.00

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