Press Release : EOG Resources, Inc.

Press Release

EOG Resources Reports Third Quarter 2011 Results

FOR IMMEDIATE RELEASE: November 1, 2011

Achieves 11 Percent Total Company Organic Production Growth for First Nine Months of 2011 Versus Prior Year Period
Reports 54 Percent Total Company Crude Oil and Condensate Volume Growth Third Quarter Year-Over-Year and 51 Percent Growth for First Nine Months Year-Over-Year
Announces 49 Percent Total Liquids Volume Increase in Third Quarter and 47 Percent Growth for First Nine Months Year-Over-Year
Records Continued Positive Results from Tighter Eagle Ford Well Spacing
Realizes Ongoing Success in Permian Basin Wolfcamp
Delivers Consistent Results from North Dakota Bakken and Fort Worth Barnett Combo
Verifies 2011 Asset Disposition Program Still On Track

HOUSTON, Nov. 1, 2011 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) today reported third quarter 2011 net income of $540.9 million, or $2.01 per diluted share. This compares to a third quarter 2010 net loss of $70.9 million, or $0.28 per diluted share.

Consistent with some analysts' practice of matching cash flow realizations to settlement months, and making certain other adjustments in order to exclude non-recurring items, adjusted non-GAAP net income for the third quarter 2011 was $223.2 million, or $0.83 per share. Adjusted non-GAAP net income for the third quarter 2010 was $46.6 million, or $0.18 per share. The results for the third quarter 2011 included net gains on asset dispositions of $132.9 million, net of tax ($0.49 per share), a $10.6 million, net of tax ($0.04 per share) impairment of certain non-core North American assets and a previously disclosed non-cash net gain of $357.7 million ($229.0 million after tax, or $0.85 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $52.5 million ($33.6 million after tax, or $0.12 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income (loss).)

Operational Highlights

Driven by a 64 percent rise in United States crude oil and condensate production during the third quarter 2011, EOG delivered 54 percent total company crude oil and condensate production growth versus the third quarter 2010. For the first nine months of 2011, year-over-year crude oil and condensate production increased 51 percent. The South Texas Eagle Ford led the surge in crude oil production growth, followed by the Fort Worth Barnett Shale Combo.

Total company liquids production increased 49 percent in the third quarter 2011 over the same period in the prior year and 47 percent year-over-year for the first nine months of 2011.

EOG achieved 11 percent total company organic production growth for the first nine months of 2011 versus 2010. For the full year 2011, total company crude oil and condensate production is projected to increase by 51 percent, while total company liquids production is forecast to rise 47 percent compared to 2010.

"These extraordinary double-digit liquids growth rates, driven primarily by high value organic crude oil production, confirm that EOG's transition to a crude oil and liquids-focused company is complete," said Mark G. Papa, Chairman and Chief Executive Officer. "After assembling a best-in-class U.S. onshore liquids-rich portfolio, we are now harvesting these existing assets by maximizing their resource potential. Meanwhile, we continue to pursue new opportunities."

Crude Oil and Liquids Activity

Across its dominant acreage position in the South Texas Eagle Ford crude oil window, EOG's 2011 improved completion techniques and cost optimization practices continue to drive operational gains and enhanced well production results. Reflecting this combination, EOG has posted its best wells to date in the South Texas Eagle Ford. In Gonzales County, the northeastern-most part of EOG's acreage, the Mitchell Unit #1H and #2H began initial production at peak rates of 2,821 and 3,090 barrels of crude oil per day (Bopd) with 2.8 and 2.9 million cubic feet per day (MMcfd) of rich natural gas, respectively. The Meyer Unit #1H, #2H and #6H started sales at peak crude oil rates of 2,372, 1,600 and 2,918 Bopd, respectively, and produced 1.8, 2.2 and 2.7 MMcfd of associated rich natural gas, respectively. The Kerner Carson Unit #1H, #2H, #4H, #6H, #8H and #10H wells were turned to sales at crude oil production rates ranging from 1,580 to 2,239 Bopd with 1.2 to 1.9 MMcfd of rich natural gas. EOG has 100 percent working interest in these Gonzales County wells.

South of Gonzales in Karnes County, the center of EOG's acreage, the AFO Unit #1H, #2H and #3H began initial maximum production at 2,289, 1,700 and 1,548 Bopd, respectively, with rich natural gas production ranging from 1.2 to 1.6 MMcfd. EOG has 100 percent working interest in these wells. EOG has 50 percent working interest in the Deleon-Reinhard Unit #1H and Deleon-Wiatrek Unit #1H wells, which were completed at peak crude oil rates of 2,235 Bopd with 1.2 MMcfd and 2,161 Bopd with 1.7 MMcfd of rich natural gas, respectively.

In LaSalle County, EOG's southwestern-most acreage, the Naylor Jones A #6H and A #7H began initial production at 1,582 and 1,342 Bopd with 1.5 and 1.6 MMcfd of rich natural gas, respectively. EOG has 100 percent working interest in these wells.

"As we apply what we've learned about the Eagle Ford across our extensive operations, EOG's production results just get better and better," Papa said. "We are also seeing early positive results from each of our seven downspacing pilot programs. Drilling wells more tightly spaced than our original 130-acre patterns provides even more development opportunities for EOG."

Across its other crude oil and liquids-rich shale plays, EOG also recorded strong, consistent performance. In the Rocky Mountains, EOG has maintained a steady level of drilling activity in the Colorado Niobrara Shale and Wyoming Powder River Basin plays. Drilling results from the Mid-Continent Marmaton and Permian Basin Leonard also continued to be positive.

In the Permian Basin Wolfcamp in Texas, EOG has been operating a two-rig program and plans to ramp up drilling activity early in 2012. Recent efforts have focused on completion techniques that increase reserves per well and improve cost efficiencies. In Irion and Crockett Counties, the University 40 #1306H, 40 #1308H and 40 #1504H were completed to sales with initial maximum production rates of 1,426, 1,293 and 1,338 Bopd with 0.9, 1.0 and 1.2 MMcfd of rich natural gas, respectively. EOG has 94 percent, 88 percent and 89 percent working interest in these wells, respectively. In Irion County, EOG has 88 percent working interest in the Mayer #5002H, which was turned to sales at 686 Bopd with 1.3 MMcfd of rich natural gas.

Operational improvements are evidenced by individual well results in EOG's North Texas Fort Worth Barnett Shale Combo. The play was a significant contributor to EOG's crude oil and liquids growth both during the third quarter and in the first nine months of 2011 versus the same period in 2010. In Montague County, the Ketchum Unit #1H and #2H were brought to sales at 496 and 638 Bopd with increasing rich natural gas rates of 354 and 455 thousand cubic feet per day, respectively. Also in Montague County, the Farrell Unit A #1H, A #2H, B #3H and B #4H began initial production at crude oil rates ranging from 335 to 475 Bopd with 1.0 to 1.4 MMcfd of rich natural gas. EOG has 100 percent working interest in these wells.

In North Dakota, EOG again reported consistent results from its drilling program. A number of wells were completed across the Bakken with strong initial production rates. In Mountrail County, the Liberty 18-14H LR, drilled with a 12,675-foot lateral, began initial production at 1,215 Bopd. EOG has 96 percent working interest in the well. In Dunn County, EOG has 84 percent working interest in the Horse Camp 2-11H and 101-11H. Completed in the Bakken and Three Forks formations, respectively, the wells began flowing to sales at initial maximum production rates of 1,323 and 1,833 Bopd, respectively. Also in the Three Forks, EOG has a 55 percent working interest in the Mandaree 102-05H, which was completed to sales at a maximum peak rate of 1,189 Bopd.

EOG has resumed normal operations in both North Dakota and Waskada, Manitoba following spring flooding that temporarily impacted drilling activity. In a new area of EOG's horizontal Waskada crude oil play, three recent wells were completed with initial production rates ranging from 300 to 400 Bopd, rates consistent with its 2010 drilling program results.

"EOG continues to deliver consistent long-term production growth at high rates of return from our liquids-rich portfolio. We have the potential to see this growth trend continue for many years to come," Papa said.

Natural Gas Activity

Consistent with EOG's overall strategy and emphasis on crude oil and liquids-rich production growth, North America natural gas production decreased 9 percent in the third quarter 2011 compared to the same prior year period. This reflects reduced drilling activity in a weak natural gas price environment, as well as previously announced natural gas asset sales.

Capital Structure

During the first nine months of 2011, total cash proceeds from asset sales were $1.3 billion. EOG anticipates full-year property sales of approximately $1.6 billion.

At September 30, 2011, EOG's total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 29 percent. Taking into account $1.4 billion of cash on the balance sheet at the end of the third quarter, EOG's net debt was $3.8 billion for a net debt-to-total capitalization ratio of 24 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 successful pursuit of high value crude oil and natural gas liquids growth is producing strong results for EOG. Most importantly, the majority of our liquids growth is oil as opposed to lower valued NGLs," Papa said. "EOG's strategy is consistent with the game plan we articulated four years ago."

Conference Call Scheduled for November 2, 2011

EOG's third quarter 2011 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, November 2, 2011. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through November 16, 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.

Investors
Maire A. Baldwin
(713) 651-6EOG (651-6364)
Elizabeth M. Ivers
(713) 651-7132

Media
K Leonard
(713) 571-3870

EOG RESOURCES, INC.
FINANCIAL REPORT
(Unaudited; in millions, except per share data)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010

Net Operating Revenues	$	2,885.7	$	1,582.1	$	7,353.1	$	4,310.7
Net Income (Loss)	$	540.9	$	(70.9)	$	970.4	$	107.0
Net Income (Loss) Per Share
Basic	$	2.03	$	(0.28)	$	3.71	$	0.43
Diluted	$	2.01	$	(0.28)	$	3.66	$	0.42
Average Number of Shares Outstanding
Basic		266.1		251.0		261.7		250.7
Diluted		269.3		251.0		265.2		254.4


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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Net Operating Revenues
Crude Oil and Condensate	$	953,154	$	506,368	$	2,649,034	$	1,368,338
Natural Gas Liquids		206,572		107,482		539,104		314,750
Natural Gas		576,803		602,242		1,760,715		1,832,578
Gains on Mark-to-Market Commodity Derivative Contracts		357,664		60,998		480,539		105,816
Gathering, Processing and Marketing		578,022		233,971		1,461,303		601,790
Gains on Asset Dispositions, Net		207,468		64,809		442,981		72,441
Other, Net		6,061		6,205		19,424		15,023
Total		2,885,744		1,582,075		7,353,100		4,310,736
Operating Expenses
Lease and Well		248,926		180,921		680,710		507,647
Transportation Costs		108,678		103,262		308,276		286,318
Gathering and Processing Costs		18,532		18,472		55,444		47,353
Exploration Costs		48,469		47,307		140,616		148,635
Dry Hole Costs		22,604		2,700		47,231		45,095
Impairments		83,431		352,908		531,413		502,865
Marketing Costs		572,604		231,758		1,427,450		591,735
Depreciation, Depletion and Amortization		651,684		500,888		1,822,854		1,398,137
General and Administrative		82,260		81,310		219,703		206,470
Taxes Other Than Income		98,526		74,244		308,669		227,773
Total		1,935,714		1,593,770		5,542,366		3,962,028

Operating Income (Loss)		950,030		(11,695)		1,810,734		348,708

Other Income, Net		1,377		5,772		11,205		7,910

Income (Loss) Before Interest Expense and Income Taxes		951,407		(5,923)		1,821,939		356,618

Interest Expense, Net		52,186		32,890		153,772		88,215

Income (Loss) Before Income Taxes		899,221		(38,813)		1,668,167		268,403

Income Tax Provision		358,343		32,093		697,742		161,422

Net Income (Loss)	$	540,878	$	(70,906)	$	970,425	$	106,981

Dividends Declared per Common Share	$	0.160	$	0.155	$	0.480	$	0.465

EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) (A)
United States		108.9		66.6		94.3		59.5
Canada		6.8		5.9		8.0		6.1
Trinidad		3.1		4.8		3.6		4.7
Other International (B)		0.1		0.1		0.1		0.1
Total		118.9		77.4		106.0		70.4

Average Crude Oil and Condensate Prices ($/Bbl) ^(c)
United States	$	87.22	$	71.54	$	91.40	$	72.58
Canada		90.54		69.12		92.76		71.32
Trinidad		89.70		65.06		91.56		66.91
Composite		87.49		70.96		91.52		72.09

Natural Gas Liquids Volumes (MBbld) (A)
United States		43.2		31.1		38.7		27.4
Canada		0.8		0.8		0.8		0.9
Total		44.0		31.9		39.5		28.3

Average Natural Gas Liquids Prices ($/Bbl) ^(c)
United States	$	50.90	$	36.56	$	49.85	$	40.68
Canada		57.69		40.34		54.36		42.90
Composite		51.02		36.66		49.93		40.75

Natural Gas Volumes (MMcfd) (A)
United States		1,122		1,175		1,123		1,096
Canada		123		200		135		205
Trinidad		330		333		354		342
Other International (B)		12		14		13		15
Total		1,587		1,722		1,625		1,658

Average Natural Gas Prices ($/Mcf) ^(c)
United States	$	4.06	$	4.21	$	4.13	$	4.50
Canada		3.81		3.42		3.88		4.09
Trinidad		3.59		2.53		3.42		2.54
Other International (B)		5.54		5.41		5.60		4.64
Composite		3.95		3.80		3.97		4.05

Crude Oil Equivalent Volumes (MBoed) (D)
United States		339.4		293.5		320.3		269.6
Canada		27.9		40.0		31.2		41.1
Trinidad		58.0		60.3		62.7		61.7
Other International (B)		2.0		2.5		2.2		2.6
Total		427.3		396.3		416.4		375.0

Total MMBoe (D)		39.3		36.5		113.7		102.4

(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)


		September 30,		December 31,
		2011		2010

ASSETS
Current Assets
Cash and Cash Equivalents		$	1,386,728	$	788,853
Accounts Receivable, Net			1,249,649		1,113,279
Inventories			580,355		415,792
Assets from Price Risk Management Activities			364,991		48,153
Income Taxes Receivable			28,013		54,916
Deferred Income Taxes			-		9,260
Other			125,626		97,193
Total			3,735,362		2,527,446

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)			32,196,279		29,263,809
Other Property, Plant and Equipment			1,993,824		1,733,073
Total Property, Plant and Equipment			34,190,103		30,996,882
Less: Accumulated Depreciation, Depletion and Amortization			(13,453,905)		(12,315,982)
Total Property, Plant and Equipment, Net			20,736,198		18,680,900
Other Assets			323,118		415,887
Total Assets		$	24,794,678	$	21,624,233

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable		$	1,926,455	$	1,664,944
Accrued Taxes Payable			157,297		82,168
Dividends Payable			43,015		38,962
Liabilities from Price Risk Management Activities			-		28,339
Deferred Income Taxes			139,646		41,703
Current Portion of Long-Term Debt			220,000		220,000
Other			179,910		143,983
Total			2,666,323		2,220,099


Long-Term Debt			5,007,746		5,003,341
Other Liabilities			768,518		667,455
Deferred Income Taxes			3,858,243		3,501,706
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
269,124,759 Shares Issued at September 30, 2011 and
254,223,521 Shares Issued at December 31, 2010			202,691		202,542
Additional Paid In Capital			2,230,600		729,992
Accumulated Other Comprehensive Income			372,448		440,071
Retained Earnings			9,711,207		8,870,179
Common Stock Held in Treasury, 281,595 Shares at September 30, 2011
and 146,186 Shares at December 31, 2010			(23,098)		(11,152)
Total Stockholders' Equity			12,493,848		10,231,632
Total Liabilities and Stockholders' Equity		$	24,794,678	$	21,624,233

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

		Nine Months Ended
		September 30,
		2011		2010
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income		$	970,425	$	106,981
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization			1,822,854		1,398,137
Impairments			531,413		502,865
Stock-Based Compensation Expenses			95,057		81,700
Deferred Income Taxes			499,279		53,067
Gains on Asset Dispositions, Net			(442,981)		(72,441)
Other, Net			2,270		(2,317)
Dry Hole Costs			47,231		45,095
Mark-to-Market Commodity Derivative Contracts
Total Gains			(480,539)		(105,816)
Realized Gains			83,765		25,180
Other, Net			21,052		13,354
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable			(128,965)		(124,813)
Inventories			(167,611)		(134,181)
Accounts Payable			245,385		527,418
Accrued Taxes Payable			101,239		(40,104)
Other Assets			(28,600)		(16,051)
Other Liabilities			37,022		44,348
Changes in Components of Working Capital Associated with Investing and
Financing Activities			133,227		(216,695)
Net Cash Provided by Operating Activities			3,341,523		2,085,727

Investing Cash Flows
Additions to Oil and Gas Properties			(4,665,535)		(3,740,883)
Additions to Other Property, Plant and Equipment			(502,112)		(223,072)
Proceeds from Sales of Assets			1,294,627		126,371
Changes in Components of Working Capital Associated with Investing
Activities			(133,512)		216,546
Other, Net			-		(4,206)
Net Cash Used in Investing Activities			(4,006,532)		(3,625,244)

Financing Cash Flows
Common Stock Sold			1,388,270		-
Net Commercial Paper Borrowings			-		33,700
Long-term Debt Borrowings			-		991,395
Long-term Debt Repayments			-		(37,000)
Dividends Paid			(124,133)		(114,277)
Treasury Stock Purchased			(21,357)		(10,298)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			26,887		24,527
Debt Issuance Costs			-		(6,469)
Other, Net			285		149
Net Cash Provided by Financing Activities			1,269,952		881,727

Effect of Exchange Rate Changes on Cash			(7,068)		(129)

Increase (Decrease) in Cash and Cash Equivalents			597,875		(657,919)
Cash and Cash Equivalents at Beginning of Period			788,853		685,751
Cash and Cash Equivalents at End of Period		$	1,386,728	$	27,832

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP)

TO NET INCOME (LOSS) (GAAP)

(Unaudited; in thousands, except per share data)

The following chart adjusts three-month and nine-month periods ended September 30, 2011 and 2010 reported Net Income (Loss) (GAAP) to reflect actual net cash

realized from financial commodity price transactions by eliminating the unrealized mark-to-market gains from these transactions, to add back impairment charges

related to certain of EOG's non-core North American assets in the first nine months of 2011 and third quarter of 2010, to eliminate the net gains on asset dispositions

primarily in North America in the first nine months of 2011 and 2010, and to eliminate the change in the estimated fair value of a contingent consideration liability in

2010 related to EOG's previously disclosed acquisition of Haynesville and Bossier Shale unproved acreage. EOG believes this presentation may be useful to

investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make

certain other adjustments to exclude one-time items. EOG management uses this information for comparative purposes within the industry.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010

Reported Net Income (Loss) (GAAP)	$	540,878	$	(70,906)	$	970,425	$	106,981

Mark-to-Market (MTM) Commodity Derivative Contracts Impact
Total Gains		(357,664)		(60,998)		(480,539)		(105,816)
Realized Gains (Losses)		52,480		(13,647)		83,765		25,180
Subtotal		(305,184)		(74,645)		(396,774)		(80,636)

After-Tax MTM Impact		(195,394)		(47,791)		(254,035)		(51,627)

Add: Impairments of Certain Non-Core North American Assets, Net of Tax		10,654		208,331		267,114		208,331
Less: Net Gains on Asset Dispositions, Net of Tax		(132,895)		(41,494)		(284,005)		(46,381)
Less: Change in Fair Value of Contingent Consideration Liability, Net of Tax		-		(1,587)		-		(12,941)

Adjusted Net Income (Non-GAAP)	$	223,243	$	46,553	$	699,499	$	204,363

Net Income (Loss) Per Share (GAAP)
Basic	$	2.03	$	(0.28)	$	3.71	$	0.43
Diluted	$	2.01	$	(0.28)	$	3.66	$	0.42

Adjusted Net Income Per Share (Non-GAAP)
Basic	$	0.84	$	0.19	$	2.67	$	0.82
Diluted	$	0.83	$	0.18	$	2.64	$	0.80

Average Number of Shares (GAAP)
Basic		266,053		251,015		261,664		250,719
Diluted		269,292		251,015		265,245		254,444

Average Number of Shares (Non-GAAP)
Basic		266,053		251,015		261,664		250,719
Diluted		269,292		254,572		265,245		254,444

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 nine-month periods ended September 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				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010

Net Cash Provided by Operating Activities (GAAP)	$	1,272,283	$	784,387	$	3,341,523	$	2,085,727

Adjustments
Exploration Costs (excluding Stock-Based Compensation Expenses)		40,624		40,095		121,166		130,598
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(36,335)		85,538		128,965		124,813
Inventories		40,549		66,818		167,611		134,181
Accounts Payable		(56,135)		(272,540)		(245,385)		(527,418)
Accrued Taxes Payable		(6,928)		34,093		(101,239)		40,104
Other Assets		23,804		(8,448)		28,600		16,051
Other Liabilities		(49,039)		(55,278)		(37,022)		(44,348)
Changes in Components of Working Capital Associated
with Investing and Financing Activities		(56,587)		80,722		(133,227)		216,695

Discretionary Cash Flow (Non-GAAP)	$	1,172,236	$	755,387	$	3,270,992	$	2,176,403

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AND TOTAL
CAPITALIZATION (NON-GAAP) AS USED IN THE CALCULATION OF
THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO (NON-GAAP)
TO CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP)
(Unaudited; in millions, except ratio data)

The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.

	September 30,
	2011

Total Stockholders' Equity - (a)	$	12,494

Current and Long-Term Debt - (b)		5,227
Less: Cash		(1,387)
Net Debt (Non-GAAP) - ^(c)		3,840

Total Capitalization (GAAP) - (a) + (b)	$	17,721

Total Capitalization (Non-GAAP) - (a) + ^(c)	$	16,334

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		29%

Net Debt-to-Total Capitalization (Non-GAAP) - ^(c) / [(a) + ^(c)]		24%

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

(a) Fourth Quarter and Full Year 2011 Forecast The forecast items for the fourth 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)
	4Q 2011			Full Year 2011
Daily Production
Crude Oil and Condensate Volumes (MBbld)
United States	119.0	-	126.0	98.5	-	104.8
Canada	6.3	-	9.5	7.2	-	9.0
Trinidad	2.2	-	2.6	3.1	-	3.6
Total	127.5	-	138.1	108.8	-	117.4

Natural Gas Liquids Volumes (MBbld)
United States	41.4	-	47.2	37.0	-	43.5
Canada	0.6	-	0.8	0.7	-	1.0
Total	42.0	-	48.0	37.7	-	44.5

Natural Gas Volumes (MMcfd)
United States	1,070	-	1,116	1,105	-	1,127
Canada	106	-	116	126	-	132
Trinidad	310	-	346	338	-	357
Other International	8	-	14	12	-	14
Total	1,494	-	1,592	1,581	-	1,630

Crude Oil Equivalent Volumes (MBoed)
United States	338.7	-	359.2	319.7	-	336.1
Canada	24.6	-	29.6	28.9	-	32.0
Trinidad	53.9	-	60.3	59.4	-	63.1
Other International	1.3	-	2.3	2.0	-	2.3
Total	418.5	-	451.4	410.0	-	433.6

Operating Costs
Unit Costs ($/Boe)
Lease and Well	$ 6.60	-	$ 6.96	$ 6.14	-	$ 6.24
Transportation Costs	$ 2.82	-	$ 3.06	$ 2.74	-	$ 2.77
Depreciation, Depletion and Amortization	$ 16.92	-	$ 17.52	$ 16.20	-	$ 16.50

Expenses ($MM)
Exploration, Dry Hole and Impairment	$ 187.0	-	$ 217.0	$ 535.0	-	$ 575.0
General and Administrative	$ 85.0	-	$ 90.0	$ 304.5	-	$ 309.5
Gathering and Processing	$ 20.0	-	$ 25.0	$ 75.5	-	$ 80.5
Capitalized Interest	$ 12.5	-	$ 16.5	$ 56.8	-	$ 60.8
Net Interest	$ 45.0	-	$ 55.0	$ 199.0	-	$ 209.0

Taxes Other Than Income (% of Revenue)	5.5%	-	6.5%	6.1%	-	6.3%

Income Taxes
Effective Rate	40%	-	50%	40%	-	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	$ 2.75	-	$ 3.50	$ 4.00	-	$ 5.00
Canada - below WTI	$ 5.00	-	$ 5.50	$ 3.25	-	$ 3.75
Trinidad - below WTI	$ 2.50	-	$ 3.00	$ 2.50	-	$ 3.20

Natural Gas ($/Mcf)
Differentials
United States - below NYMEX Henry Hub	$ 0.08	-	$ 0.16	$ 0.07	-	$ 0.11
Canada - below NYMEX Henry Hub	$ 0.48	-	$ 0.58	$ 0.35	-	$ 0.43

Realizations
Trinidad	$ 2.50	-	$ 3.25	$ 3.20	-	$ 3.39
Other International	$ 5.55	-	$ 6.55	$ 5.58	-	$ 5.78

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

SOURCE EOG Resources, Inc.

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