EXHIBIT 99.1

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 2012 Results and Increases 2012 Crude Oil Production Growth Target to 37 Percent

· Reports Strong Year-Over-Year Growth in Earnings Per Share, Discretionary Cash Flow and Adjusted EBITDAX

· Achieves 52 Percent Crude Oil and Condensate Production Increase and 49 Percent Increase in Total Liquids Production Over Second Quarter 2011

· Increases 2012 Total Company Crude Oil Production Growth Target to 37 Percent from 33 Percent and Full Year Total Company Total Liquids Growth Target to 35 Percent from 33 Percent

· Raises 2012 Total Company Production Growth Target to 9 Percent from 7 Percent with Unchanged 2012 Capital Expenditure Budget

· Realizes Premium Crude Oil Prices from Rail Offloading Facility at St. James, Louisiana

· Attains New Marketing Opportunities for Eagle Ford Volumes Through Recently Completed Third-Party Crude Oil Pipeline and Natural Gas Processing Plant and Pipelines

· Delivers Best Crude Oil Well to Date as Solid Execution of Eagle Ford Drilling Program Continues

· Sustains Successful Bakken Drilling Program in Core, Antelope Extension and Stateline Areas

· Closes on $1.1 Billion of Asset Sales through June 30, 2012; Targets $1.2 to $1.25 Billion of Sales for Full Year 2012

            _______________________________________________________

FOR IMMEDIATE RELEASE: Thursday, August 2, 2012

HOUSTON - EOG Resources, Inc. (EOG) today reported second quarter 2012 net income of $395.8 million, or $1.47 per share. This compares to second quarter 2011 net income of $295.6 million, or $1.10 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 second quarter 2012 was $312.4 million, or $1.16 per share. Adjusted non-GAAP net income for the second quarter 2011 was $299.2 million, or $1.11 per share. The results for the second quarter 2012 included impairments of $1.5 million, net of tax ($0.01 per share) related to certain non-core North American assets, net gains on asset dispositions of $75.1 million, net of tax ($0.28 per share) and a previously disclosed non-cash net gain of $188.4 million ($120.7 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 $173.2 million ($110.9 million after tax, or $0.41 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

With 86 percent of North American wellhead revenues currently derived from crude oil, condensate and natural gas liquids, EOG delivered strong earnings per share growth of 64 percent for the first half of 2012 compared to the same period in 2011. Discretionary cash flow increased 29 percent and adjusted EBITDAX rose 28 percent over the first half of 2011. (Please refer to the attached tables for the reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP) and adjusted EBITDAX (non-GAAP) to income before interest expense and income taxes (GAAP).)

"EOG's financial and operating results get better and better. We are achieving this consistent string of home runs because EOG has captured the finest inventory of onshore crude oil assets in the entire United States and has the technical acumen to maximize reserve recoveries," said Mark G. Papa, Chairman and Chief Executive Officer. "EOG is the largest crude oil producer in the South Texas Eagle Ford and North Dakota Bakken with the sweet spot positions in both plays. In addition, we are uniquely positioned to market a significant portion of this crude oil at robust Brent-type pricing through our own rail offloading facility at St. James, Louisiana, and to reach the Houston Gulf Coast market via the recently completed Enterprise Eagle Ford pipeline."

Operational Highlights

Due to robust operational results from the Eagle Ford and Bakken plays, EOG's total crude oil and condensate production for the second quarter 2012 increased 52 percent compared to the second quarter 2011. Total crude oil, condensate and natural gas liquids production increased 49 percent over the same period in 2011. Based on these outstanding results, together with contributions from its West Texas Wolfcamp and New Mexico Leonard horizontal shale plays, EOG has increased its 2012 total company crude oil and condensate production growth target to 37 percent from 33 percent and its total liquids production growth target to 35 percent from 33 percent. Overall, EOG has increased its total company full year 2012 production growth target to 9 percent from 7 percent with no changes to its capital expenditure budget.

In the South Texas Eagle Ford, EOG drilled its best well to date. The Boothe Unit #10H in Gonzales County began initial production at 4,820 barrels of oil per day (Bopd) while an offset well, the Boothe Unit #9H, had an initial production rate of 3,708 Bopd. The Boothe wells produced 972 and 527 barrels per day (Bpd) of natural gas liquids (NGLs) and 4.5 and 2.4 million cubic feet per day (MMcfd) of associated natural gas production, respectively.

"We continually focus on making better wells and with an initial flow rate in excess of 4,800 barrels of crude oil per day, EOG's Boothe Unit #10H is clearly the top producing oil well in the entire Eagle Ford play to date," Papa added.

Drilled from the same pad as the Boothe wells to minimize costs, the Dreyer Unit #19H and #20H were turned to sales at initial rates of 3,703 and 2,650 Bopd with 460 and 300 Bpd of NGLs and 2.1 and 1.4 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these four wells.

Also in Gonzales County, the Henkhaus Unit #9H, #10H and #11H flowed at individual initial well rates of 4,184, 3,546, and 4,140 Bopd, with 633, 730 and 670 Bpd of NGLs and 2.9, 3.4 and 3.1 MMcfd of natural gas, respectively. The Guadalupe Unit #5H, #6H, #7H and #8H were turned to sales early in the second quarter at initial individual crude oil production rates ranging from 2,675 to 3,900 Bopd with 175 to 590 Bpd of NGLs and 800 thousand cubic feet per day (Mcfd) to 2.7 MMcfd of natural gas. EOG has 100 percent working interest in these seven wells.

In Karnes County, the Crews Unit #1H, #2H, #3H, #4H and #5H initially produced at individual well rates ranging from 2,645 to 2,986 Bopd with 193 to 390 Bpd of NGLs and 900 Mcfd to 1.8 MMcfd of natural gas. EOG has 100 percent working interest in these five wells.

EOG's marketing options for its prolific Eagle Ford production expanded in July when Enterprise Products Partners L.P. (Enterprise) began first commercial operation of the first phase of a 24-inch crude oil pipeline linking the Eagle Ford with extensive Houston area refining markets. Enterprise also has commissioned a new natural gas processing plant, as well as rich natural gas pipelines to gather and transport production to its Mont Belvieu NGL complex.

In the Bakken, EOG's 90,000 net acre Core Parshall Field has evolved into a growth engine fueled by success from drilling wells on tighter densities. Initial infill drilling results in the over-pressured Core area and simultaneous increased production rates from proximate existing wells indicate significant amounts of recoverable crude oil remain. In an effort to improve recovery of the resource in place, EOG plans to further develop the Core on 320-acre spacing and test even tighter drilling densities.

During the second quarter, EOG reported a number of favorable results from its ongoing infill drilling program in the Core area. In Mountrail County, the Liberty LR 12-11H and Liberty LR 15-26H tested at 1,037 and 1,114 Bopd with 720 and 552 Mcfd of natural gas, respectively. EOG has 66 percent and 95 percent working interest in the wells, respectively. Also in the Core area, the Fertile 42-3231H and the Fertile 49-3024H came online at 1,063 Bopd with 408 Mcfd of natural gas and 928 Bopd with 365 Mcfd of natural gas, respectively. EOG has 69 percent and 80 percent working interest, respectively, in the wells.

In McKenzie County, North Dakota, 25 miles southwest of the Bakken Core, EOG is realizing economic production from its inventory of both Bakken and Three Forks drilling locations on its Antelope Extension prospect. EOG has 94 percent working interest in the Riverview 04-3031H drilled in the Bakken and the Riverview 100-3031H drilled in the Three Forks. The wells had initial production rates of 1,863 Bopd with 730 Mcfd of natural gas and 1,834 Bopd with 1.3 MMcfd of natural gas, respectively. Completed in the Bakken, the Clarks Creek 10-0805H initially produced 1,478 Bopd with 576 Mcfd of natural gas, while the Clarks Creek 100-0805H had an initial rate of 1,437 Bopd with 635 Mcfd of natural gas from the Three Forks. EOG has 85 percent working interest in the two wells. Also in the Antelope prospect, the Mandaree 16-04H, in which EOG has 90 percent working interest, produced 1,059 Bopd with 960 Mcfd of natural gas from the Bakken formation. In Roosevelt County, Montana, EOG completed the Stateline 08-3328H, with an initial production rate of 1,260 Bopd with 687 Mcfd of natural gas. EOG has 39 percent working interest in the well.

Having identified a large, multi-year drilling inventory on its Bakken Core, Antelope Extension and Stateline acreage, EOG expects to post crude oil production growth from North Dakota and Montana in 2013 and beyond.

In the West Texas and New Mexico Permian Basin, EOG is operating a seven-rig drilling program. Five rigs are operating in the Texas Wolfcamp horizontal shale play in Irion, Crockett and Reagan counties where drilling operations are defining the pervasiveness of the Wolfcamp middle interval across EOG's acreage. During the second quarter and early July, a number of wells from the middle Wolfcamp were brought to sales. In Irion County, the Munson #1001H, #1002H and #1003H came on-line at 1,110, 856 and 1,015 Bopd with 80, 70 and 40 Bpd of NGLs and 455, 405 and 230 Mcfd of natural gas, respectively. EOG has 85 percent working interest in these three Munson wells. The University 43A-#0802H, 43A-#0803H, 43A-#0805H and 43A-#0807H began production at individual initial rates ranging from 610 to 760 Bopd with 35 to 105 Bpd of NGLs and 200 to 590 Mcfd of natural gas. EOG has 50 percent working interest in these four Irion County University 43A wells.

EOG is operating two rigs in the New Mexico Leonard horizontal shale play in Eddy and Lea counties. The Ross Draw 8 Fed #2H had 722 Bopd of initial production with 270 Bpd of NGLs and 1.9 MMcfd of natural gas. The Ross Gulch 8 Fed Com #1H began sales at 540 Bopd with 145 Bpd of NGLs and 990 Mcfd of natural gas. EOG has 88 and 91 percent working interest in these Eddy County wells, respectively. In Lea County, EOG has 100 percent working interest in the Pitchblende 29 Fed Com #1H, which had an initial production rate of 1,026 Bopd with 120 Bpd of NGLs and 650 Mcfd of natural gas. This significant step-out well sets up numerous additional drilling locations. Early in the third quarter, EOG completed the Vaca 14 Fed #4H in Lea County with first sales of 986 Bopd with 200 Bpd of NGLs and 1.1 MMcfd of natural gas. EOG has 100 percent working interest in the well. Following the Eagle Ford and Bakken, EOG's Permian Basin operation was the third largest contributor to its crude oil and condensate production growth during the second quarter.

Crude Oil and Liquids Activity

"We increased EOG's 2012 crude oil production growth target to 37 percent based on the strength of our drilling results for the first half of the year. This new goal sets EOG up to achieve an all-organic, five-year compounded annual crude oil production growth rate of 38 percent through year-end 2012," Papa said.

"Looking ahead, we expect EOG's resource-rich portfolio will continue to generate high crude oil production growth rates for a long time," Papa added.

Natural Gas Activity

Due to the ongoing weakness in natural gas pricing, EOG plans to further decrease drilling activity on its dry gas resource plays in the second half of 2012. Through active drilling programs in prior years and 2012 to date, EOG has captured strategic natural gas acreage in the Uinta, Horn River, Barnett, Haynesville and Marcellus plays. When natural gas prices rebound, EOG will hold an attractive portfolio of natural gas resources for future development.

Hedging Activity

EOG has hedged approximately 22 percent of its North American crude oil production from August 1 to December 31, 2012. EOG has crude oil financial price swap contracts in place for an average of 35,600 Bpd at a weighted average price of $106.69 per barrel, excluding unexercised options. For the period January 1 to June 30, 2013, EOG has crude oil financial price swap contracts in place for an average of 16,000 barrels per day at a weighted average price of $98.12.

EOG has hedged approximately 45 percent of its North American natural gas production for 2012. For the period September 1 through December 31, 2012, EOG has natural gas financial price swap contracts in place for 525,000 million British thermal units per day (MMBtud) at a weighted average price of $5.44 per million British thermal units (MMBtu), excluding unexercised options. For 2013, EOG has natural gas financial price swap contracts in place for 150,000 MMBtud at a weighted average price of $4.79 per MMBtu, excluding unexercised options. (For a comprehensive summary of EOG's crude oil and natural gas derivative contracts, please refer to the attached tables.)

Capital Structure

Through June 30, 2012 EOG's cash proceeds from asset sales were approximately $1,112 million. EOG is targeting total asset sales for the year of $1.2 to $1.25 billion. At June 30, 2012, EOG's total debt outstanding was $5,012 million for a debt-to-total capitalization ratio of 27 percent. Taking into account cash on the balance sheet of $280 million at the end of the second quarter, EOG's net debt was $4,732 million for a net debt-to-total capitalization ratio of 26 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

 "By harnessing our team's outstanding technical expertise and innovative marketing strengths to EOG's exceptional asset base, during the first half of 2012 we achieved a number of our corporate goals. EOG reported growth in earnings per share, discretionary cash flow and adjusted EBITDAX. With our tremendous momentum, we increased our crude oil production growth target twice, achieved our asset sales goal and maintained a strong balance sheet," Papa said. "Moving into the second half of the year, our focus is on realizing our 2012 goal of 37 percent crude oil production growth while we moderate our drilling activity level to stay within our capital budget."

Conference Call Scheduled for August 3, 2012

EOG's second quarter 2012 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Friday, August 3, 2012. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through August 17, 2012.

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, generate income or cash flows or pay dividends 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 and condensate, natural gas liquids, 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, advanced completion technologies and hydraulic fracturing;

· 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 and capital expenditure requirements 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, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

· 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, and to otherwise satisfy its capital expenditure requirements;

· 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 use of competing energy sources and the development of alternative energy sources;

· the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;

· acts of war and terrorism and responses to these acts; and

· the other factors described under Item 1A, "Risk Factors," on pages 15 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2011 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 "potential" reserves and/or other 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, 2011, 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.  In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

EOG RESOURCES, INC.
FINANCIAL REPORT
(Unaudited; in millions, except per share data)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Net Operating Revenues		$	2,909.3		$	2,570.3		$	5,716.0		$	4,467.4
Net Income		$	395.8		$	295.6		$	719.8		$	429.5
Net Income Per Share
Basic		$	1.48		$	1.11		$	2.70		$	1.65
Diluted		$	1.47		$	1.10		$	2.67		$	1.63
Average Number of Common Shares
Basic			266.9			265.8			266.7			259.8
Diluted			270.0			269.3			270.1			263.4

SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
Net Operating Revenues
Crude Oil and Condensate	$	1,376,250	$	938,518	$	2,686,585	$	1,695,880
Natural Gas Liquids		150,023		183,805		348,333		332,532
Natural Gas		359,421		599,993		726,705		1,183,912
Gains on Mark-to-Market Commodity Derivative Contracts		188,449		189,621		322,657		122,875
Gathering, Processing and Marketing		710,748		487,698		1,428,905		883,281
Gains on Asset Dispositions, Net		113,290		163,771		180,758		235,513
Other, Net		11,138		6,844		22,027		13,363
Total		2,909,319		2,570,250		5,715,970		4,467,356
Operating Expenses
Lease and Well		250,756		216,695		512,251		431,784
Transportation Costs		135,393		101,965		267,235		199,598
Gathering and Processing Costs		20,588		17,716		46,180		36,912
Exploration Costs		48,149		41,238		90,956		92,147
Dry Hole Costs		11,081		1,676		11,081		24,627
Impairments		54,217		358,654		187,364		447,982
Marketing Costs		694,118		469,437		1,399,586		854,846
Depreciation, Depletion and Amortization		808,765		602,944		1,557,508		1,171,170
General and Administrative		75,727		67,406		151,996		137,443
Taxes Other Than Income		118,186		104,266		239,702		210,143
Total		2,216,980		1,981,997		4,463,859		3,606,652
Operating Income		692,339		588,253		1,252,111		860,704
Other Income, Net		4,675		6,224		15,306		9,828
Income Before Interest Expense and Income Taxes		697,014		594,477		1,267,417		870,532
Interest Expense, Net		50,775		51,253		101,044		101,586
Income Before Income Taxes		646,239		543,224		1,166,373		768,946
Income Tax Provision		250,461		247,650		446,586		339,399
Net Income	$	395,778	$	295,574	$	719,787	$	429,547
Dividends Declared per Common Share	$	0.17	$	0.16	$	0.34	$	0.32

EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) (A)
United States		150.5		92.3		140.7		86.8
Canada		6.4		8.8		7.0		8.6
Trinidad		1.7		3.3		1.9		3.9
Other International (B)		0.1		0.1		0.1		0.1
Total		158.7		104.5		149.7		99.4
Average Crude Oil and Condensate Prices ($/Bbl) (C)
United States	$	95.80	$	99.50	$	98.61	$	94.05
Canada		82.78		102.65		86.33		93.65
Trinidad		88.68		99.49		94.76		92.33
Other International (B)		91.20		101.52		96.49		93.67
Composite		95.20		99.77		98.00		93.95
Natural Gas Liquids Volumes (MBbld) (A)
United States		54.6		38.4		52.4		36.5
Canada		0.9		0.7		0.9		0.8
Total		55.5		39.1		53.3		37.3
Average Natural Gas Liquids Prices ($/Bbl) (C)
United States	$	33.54	$	51.50	$	38.12	$	49.21
Canada		42.89		60.39		46.54		52.77
Composite		33.72		51.65		38.27		49.29
Natural Gas Volumes (MMcfd) (A)
United States		1,070		1,114		1,067		1,124
Canada		96		139		100		141
Trinidad		422		349		396		367
Other International (B)		10		13		10		13
Total		1,598		1,615		1,573		1,645
Average Natural Gas Prices ($/Mcf) (C)
United States	$	2.09	$	4.24	$	2.28	$	4.17
Canada		2.21		4.16		2.33		3.91
Trinidad		3.42		3.51		3.21		3.35
Other International (B)		5.64		5.61		5.72		5.62
Composite		2.47		4.08		2.54		3.98
Crude Oil Equivalent Volumes (MBoed) (D)
United States		383.3		316.4		370.9		310.7
Canada		23.4		32.6		24.6		32.9
Trinidad		72.0		61.4		67.9		65.0
Other International (B)		1.8		2.2		1.8		2.3
Total		480.5		412.6		465.2		410.9
Total MMBoe (D)		43.7		37.5		84.7		74.4
(A) Thousand barrels per day or million cubic feet per day, as applicable.
(B) Other International includes EOG's United Kingdom, China and Argentina 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,
	2012			2011
ASSETS
Current Assets
Cash and Cash Equivalents	$	280,374		$	615,726
Accounts Receivable, Net		1,375,092			1,451,227
Inventories		620,260			590,594
Assets from Price Risk Management Activities		421,135			450,730
Income Taxes Receivable		28,448			26,609
Other		222,749			119,052
Total		2,948,058			3,253,938
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		35,562,446			33,664,435
Other Property, Plant and Equipment		2,375,862			2,149,989
Total Property, Plant and Equipment		37,938,308			35,814,424
Less:  Accumulated Depreciation, Depletion and Amortization		(15,248,594	)		(14,525,600	)
Total Property, Plant and Equipment, Net		22,689,714			21,288,824
Other Assets		360,805			296,035
Total Assets	$	25,998,577		$	24,838,797
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,235,637		$	2,033,615
Accrued Taxes Payable		142,223			147,105
Dividends Payable		45,441			42,578
Deferred Income Taxes		121,059			135,989
Other		135,580			163,032
Total		2,679,940			2,522,319
Long-Term Debt		5,011,893			5,009,166
Other Liabilities		791,297			799,189
Deferred Income Taxes		4,160,306			3,867,219
Commitments and Contingencies
Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
270,226,599 Shares Issued at June 30, 2012 and
269,323,084 Shares Issued at December 31, 2011		202,702			202,693
Additional Paid in Capital		2,374,122			2,272,052
Accumulated Other Comprehensive Income		400,086			401,746
Retained Earnings		10,417,405			9,789,345
Common Stock Held in Treasury, 419,651 Shares at June 30, 2012
and 303,633 Shares at December 31, 2011		(39,174	)		(24,932	)
Total Stockholders' Equity		13,355,141			12,640,904
Total Liabilities and Stockholders' Equity	$	25,998,577		$	24,838,797

EOG RESOURCES, INC.
SUMMARY STATEMENTS OF CASH FLOWS
(Unaudited; in thousands)
	Six Months Ended
	June 30,
	2012			2011
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	719,787		$	429,547
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		1,557,508			1,171,170
Impairments		187,364			447,982
Stock-Based Compensation Expenses		55,466			53,427
Deferred Income Taxes		278,826			206,130
Gains on Asset Dispositions, Net		(180,758	)		(235,513	)
Other, Net		(3,404	)		(834	)
Dry Hole Costs		11,081			24,627
Mark-to-Market Commodity Derivative Contracts
Total Gains		(322,657	)		(122,875	)
Realized Gains		306,780			31,285
Excess Tax Benefits from Stock-Based Compensation		(22,115	)		-
Other, Net		9,890			13,268
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		115,419			(165,300	)
Inventories		(103,576	)		(127,062	)
Accounts Payable		176,355			189,250
Accrued Taxes Payable		14,363			94,311
Other Assets		(102,303	)		(4,796	)
Other Liabilities		(27,355	)		(12,017	)
Changes in Components of Working Capital Associated with Investing and
Financing Activities		(97,453	)		76,640
Net Cash Provided by Operating Activities		2,573,218			2,069,240
Investing Cash Flows
Additions to Oil and Gas Properties		(3,748,278	)		(3,122,567	)
Additions to Other Property, Plant and Equipment		(315,542	)		(340,140	)
Proceeds from Sales of Assets		1,111,517			944,481
Changes in Components of Working Capital Associated with Investing
Activities		97,746			(76,852	)
Net Cash Used in Investing Activities		(2,854,557	)		(2,595,078	)
Financing Cash Flows
Common Stock Sold		-			1,388,270
Dividends Paid		(88,892	)		(81,562	)
Excess Tax Benefits from Stock-Based Compensation		22,115			-
Treasury Stock Purchased		(22,663	)		(16,736	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		32,986			24,619
Other, Net		(293	)		212
Net Cash (Used in) Provided by Financing Activities		(56,747	)		1,314,803
Effect of Exchange Rate Changes on Cash		2,734			(380	)
(Decrease) Increase in Cash and Cash Equivalents		(335,352	)		788,585
Cash and Cash Equivalents at Beginning of Period		615,726			788,853
Cash and Cash Equivalents at End of Period	$	280,374		$	1,577,438

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 the three-month and six-month periods ended June 30, 2012 and 2011 reported Net Income (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market gains from these transactions, to add back impairment charges related to certain of EOG's North American assets in 2012 and 2011 and to eliminate the net gains on asset dispositions primarily in North America in 2012 and 2011.  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 non-recurring items.  EOG management uses this information for comparative purposes within the industry.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Reported Net Income (GAAP)	$	395,778		$	295,574		$	719,787		$	429,547
Mark-to-Market (MTM) Commodity Derivative Contracts Impact
Total Gains		(188,449	)		(189,621	)		(322,657	)		(122,875	)
Realized Gains		173,179			6,348			306,780			31,285
Subtotal		(15,270	)		(183,273	)		(15,877	)		(91,590	)
After-Tax MTM Impact		(9,776	)		(117,281	)		(10,165	)		(58,641	)
Add: Impairment of Certain North American Assets, Net of Tax		1,526			226,177			38,575			256,460
Less: Net Gains on Asset Dispositions, Net of Tax		(75,087	)		(105,224	)		(118,298	)		(151,110	)
Adjusted Net Income (Non-GAAP)	$	312,441		$	299,246		$	629,899		$	476,256
Net Income Per Share (GAAP)
Basic	$	1.48		$	1.11		$	2.70		$	1.65
Diluted	$	1.47		$	1.10		$	2.67	(a)	$	1.63	(b)
Percentage Increase - [(a) - (b)] / (b)								64	%
Adjusted Net Income Per Share (Non-GAAP)
Basic	$	1.17		$	1.13		$	2.36		$	1.83
Diluted	$	1.16		$	1.11		$	2.33		$	1.81
Average Number of Common Shares
Basic		266,874			265,830			266,718			259,766
Diluted		269,985			269,332			270,083			263,363

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, 2012 and 2011 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						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Net Cash Provided by Operating Activities (GAAP)	$	1,495,613		$	1,111,752		$	2,573,218		$	2,069,240
Adjustments
Exploration Costs (excluding Stock-Based Compensation Expenses)		41,890			35,775			78,078			80,542
Excess Tax Benefits from Stock-Based Compensation		5,464			-			22,115			-
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(205,367	)		51,445			(115,419	)		165,300
Inventories		113,784			59,329			103,576			127,062
Accounts Payable		60,270			(23,753	)		(176,355	)		(189,250	)
Accrued Taxes Payable		(19,526	)		(14,563	)		(14,363	)		(94,311	)
Other Assets		(6,537	)		(13,860	)		102,303			4,796
Other Liabilities		22,296			20,638			27,355			12,017
Changes in Components of Working Capital Associated
with Investing and Financing Activities		(126,222	)		(74,655	)		97,453			(76,640	)
Discretionary Cash Flow (Non-GAAP)	$	1,381,665		$	1,152,108		$	2,697,961	(a)	$	2,098,756	(b)
Percentage Increase - [(a) - (b)] / (b)								29	%

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF ADJUSTED EARNINGS BEFORE INTEREST EXPENSE,
INCOME TAXES, DEPRECIATION, DEPLETION AND AMORTIZATION, EXPLORATION COSTS,
DRY HOLE COSTS, IMPAIRMENTS AND ADDITIONAL ITEMS (ADJUSTED EBITDAX)
(NON-GAAP) TO INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP)
(Unaudited; in thousands)
The following chart adjusts the three-month and six-month periods ended June 30, 2012 and 2011 reported Income Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash realized from financial commodity derivative transactions by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net gains on asset dispositions primarily in North America in 2012 and 2011. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry.
	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2012				2011				2012					2011
Income Before Interest Expense and Income Taxes (GAAP)		$	697,014			$	594,477			$	1,267,417				$	870,532
Adjustments:
Depreciation, Depletion and Amortization			808,765				602,944				1,557,508					1,171,170
Exploration Costs			48,149				41,238				90,956					92,147
Dry Hole Costs			11,081				1,676				11,081					24,627
Impairments			54,217				358,654				187,364					447,982
EBITDAX (Non-GAAP)			1,619,226				1,598,989				3,114,326					2,606,458
Total (Gains) Losses on MTM Commodity Derivative Contracts			(188,449	)			(189,621	)			(322,657	)				(122,875	)
Realized Gains on MTM Commodity Derivative Contracts			173,179				6,348				306,780					31,285
Net Gains on Asset Dispositions			(113,290	)			(163,771	)			(180,758	)				(235,513	)
Adjusted EBITDAX (Non-GAAP)		$	1,490,666			$	1,251,945			$	2,917,691		(a)		$	2,279,355		(b)
Percentage Increase - [(a) - (b)] / (b)											28	%

EOG RESOURCES, INC.
CRUDE OIL AND NATURAL GAS FINANCIAL
COMMODITY DERIVATIVE CONTRACTS
Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at August 2, 2012, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.
CRUDE OIL DERIVATIVE CONTRACTS
				Weighted
		Volume		Average Price
		(Bbld)		($/Bbl)
2012 (1)
January 1, 2012 through February 29, 2012 (closed)			34,000	$	104.95
March 1, 2012 through June 30, 2012 (closed)			52,000		105.80
July 2012 (closed)			50,000		106.90
August 2012			50,000		106.90
September 1, 2012 through December 31, 2012			32,000		106.61
2013 (2)
January 1, 2013 through June 30, 2013			16,000	$	98.12
(1)	EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Options covering a notional volume of 18,000 Bbld are exercisable on August 31, 2012.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 18,000 Bbld at an average price of $107.42 per barrel for the period September 1, 2012 through February 28, 2013.  Options covering a notional volume of 15,000 Bbld are exercisable on December 31, 2012.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 15,000 Bbld at an average price of $110.03 per barrel for the period January 1, 2013 through June 30, 2013.
(2)	EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Options covering a notional volume of 16,000 Bbld are exercisable on June 28, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 16,000 Bbld at an average price of $98.12 per barrel for the period July 1, 2013 through December 31, 2013.
NATURAL GAS DERIVATIVE CONTRACTS
				Weighted
		Volume		Average Price
		(MMBtud)		($/MMBtu)
2012 (3)
January 1, 2012 through August 31, 2012 (closed)			525,000	$	5.44
September 1, 2012 through December 31, 2012			525,000	$	5.44
2013 (4)
January 1, 2013 through December 31, 2013			150,000	$	4.79
2014 (5)
(3)	EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from September 1, 2012 through December 31, 2012.
(4)	EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2013.
(5)	EOG settled natural gas financial price swap contracts for the period January 1, 2014 through December 31, 2014. In connection with these contracts, the counterparties retain an option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMbtud at an average price of $4.79 per MMBtu for each month of 2014.

Definitions
Bbld	Barrels per day.
$/Bbl	Dollars per barrel.
MMBtud	Million British thermal units per day.
$/MMBtu	Dollars per million British thermal units.

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 LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP)
(Unaudited; in millions, except ratio data)
The following chart reconciles 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,
	2012
Total Stockholders' Equity - (a)		$	13,355
Long-Term Debt - (b)			5,012
Less: Cash			(280	)
Net Debt (Non-GAAP) - (c)			4,732
Total Capitalization (GAAP) - (a) + (b)		$	18,367
Total Capitalization (Non-GAAP) - (a) + (c)		$	18,087
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]			27	%
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]			26	%

EOG RESOURCES, INC.
THIRD QUARTER AND FULL YEAR 2012 FORECAST AND BENCHMARK COMMODITY PRICING
(a)  Third Quarter and Full Year 2012 Forecast The forecast items for the third quarter and full year 2012 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 2012			Full Year 2012
Daily Production
Crude Oil and Condensate Volumes (MBbld)
United States	148.0	-	160.0	142.0	-	152.0
Canada	5.0	-	6.0	6.3	-	7.3
Trinidad	0.8	-	2.0	1.2	-	1.6
Other International	0.0	-	0.2	0.1	-	0.2
Total	153.8	-	168.2	149.6	-	161.1
Natural Gas Liquids Volumes (MBbld)
United States	52.0	-	58.0	51.0	-	58.3
Canada	0.6	-	1.0	0.7	-	0.9
Total	52.6	-	59.0	51.7	-	59.2
Natural Gas Volumes (MMcfd)
United States	1,000	-	1,025	1,021	-	1,041
Canada	80	-	100	89	-	99
Trinidad	333	-	362	358	-	373
Other International	8	-	10	10	-	11
Total	1,421	-	1,497	1,478	-	1,524
Crude Oil Equivalent Volumes (MBoed)
United States	366.7	-	388.8	363.2	-	383.8
Canada	18.9	-	23.7	21.8	-	24.7
Trinidad	56.3	-	62.3	60.9	-	63.8
Other International	1.3	-	1.8	1.8	-	2.0
Total	443.2	-	476.6	447.7	-	474.3

	ESTIMATED RANGES (Unaudited)
	3Q 2012							Full Year 2012
Operating Costs
Unit Costs ($/Boe)
Lease and Well	$	6.65		-	$	6.85		$	6.36		-	$	6.54
Transportation Costs	$	3.60		-	$	3.75		$	3.30		-	$	3.48
Depreciation, Depletion and Amortization	$	19.35		-	$	20.00		$	18.84		-	$	19.44
Expenses ($MM)
Exploration, Dry Hole and Impairment	$	122.0		-	$	142.0		$	476.2		-	$	516.2
General and Administrative	$	102.0		-	$	107.0		$	339.0		-	$	348.8
Gathering and Processing	$	23.2		-	$	27.2		$	93.6		-	$	101.6
Capitalized Interest	$	10.8		-	$	14.8		$	46.4		-	$	54.4
Net Interest	$	47.0		-	$	53.0		$	195.3		-	$	205.9
Taxes Other Than Income (% of Wellhead Revenue)		5.8	%	-		6.4	%		5.9	%	-		6.3	%
Income Taxes
Effective Rate		35	%	-		45	%		35	%	-		45	%
Current Taxes ($MM)	$	75		-	$	90		$	320		-	$	340
Capital Expenditures ($MM) - FY 2012 (Excluding Acquisitions)
Exploration and Development, Excluding Facilities								$	6,200		-	$	6,300
Exploration and Development Facilities								$	630		-	$	675
Gathering, Processing and Other								$	570		-	$	600
Pricing - (Refer to Benchmark Commodity Pricing in text)
Crude Oil and Condensate ($/Bbl)
Differentials
United States - (above) below WTI	$	(2.00	)	-	$	(4.00	)	$	(1.29	)	-	$	(2.37	)
Canada - (above) below WTI	$	6.50		-	$	8.00		$	9.41		-	$	10.17
Trinidad - (above) below WTI	$	8.75		-	$	10.25		$	3.00		-	$	4.00
Natural Gas Liquids
Realizations as % of WTI
United States		34	%	-		40	%		36	%	-		39	%
Canada		50	%	-		54	%		49	%	-		51	%
Natural Gas ($/Mcf)
Differentials
United States - (above) below NYMEX Henry Hub	$	0.15		-	$	0.30		$	0.20		-	$	0.27
Canada - (above) below NYMEX Henry Hub	$	0.57		-	$	0.77		$	0.37		-	$	0.47
Realizations
Trinidad	$	3.30		-	$	3.80		$	2.96		-	$	3.43
Other International	$	5.00		-	$	5.80		$	5.36		-	$	5.76

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