EOG 10-Q Quarterly Report Sept. 30, 2011

EOG RESOURCES INC

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10-Q 1 eog3qtr10-q.htm EOG FORM 10-Q eog3qtr10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-9743

EOG RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware		47-0684736
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

713-651-7000

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

Title of each class	Number of shares
Common Stock, par value $0.01 per share	268,850,778 (as of October 26, 2011)

EOG RESOURCES, INC.

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements (Unaudited)

		Consolidated Statements of Income - Three Months Ended September 30, 2011 and 2010 and Nine Months Ended September 30, 2011 and 2010	3

		Consolidated Balance Sheets - September 30, 2011 and December 31, 2010	4

		Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2011 and 2010	5

		Notes to Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	37

	ITEM 4.	Controls and Procedures	37

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	38

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38

	ITEM 5.	Other Information	38

	ITEM 6.	Exhibits	40

SIGNATURES			41

EXHIBIT INDEX			42

- 2 -

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands, Except Per Share Data)

(Unaudited)

	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

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

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

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

The accompanying notes are an integral part of these consolidated financial statements.

- 3 -

EOG RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Data)

(Unaudited)

	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 (Note 9)

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

The accompanying notes are an integral part of these consolidated financial statements.

- 4 -

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	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

The accompanying notes are an integral part of these consolidated financial statements.

- 5 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

General. The consolidated financial statements of EOG Resources, Inc., together with its subsidiaries (collectively, EOG), included herein have been prepared by management without audit pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Accordingly, they reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods presented. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures included either on the face of the financial statements or in these notes are sufficient to make the interim information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in EOG's Annual Report on Form 10-K for the year ended December 31, 2010, filed on February 24, 2011 (EOG's 2010 Annual Report).

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results to be expected for the full year.

Recently Issued Accounting Standards and Developments. In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, which amends the Fair Value Measurements and Disclosures topic of the Accounting Standards Codification. The amendments clarify the FASB's intent about the application of existing fair value measurement requirements and change certain principles or requirements for measuring fair value or disclosing information about fair value measurements. ASU 2011-04 is effective for interim and annual fiscal periods beginning after December 15, 2011. EOG does not expect that the adoption of ASU 2011-04 will have a material impact on its financial statements, but it may result in additional disclosures regarding fair value measurements.

In June 2011, the FASB issued ASU 2011-05 "Comprehensive Income (Topic 220): Presentation of Comprehensive Income." ASU 2011-05 is intended to increase the prominence of comprehensive income in the financial statements by requiring that an entity that reports items of comprehensive income do so in either one continuous or two consecutive financial statements. ASU 2011-05 also requires separate presentation on the face of the financial statements for items reclassified from other comprehensive income into net income. The provisions of ASU 2011-05 are effective for interim and annual fiscal periods beginning after December 15, 2011. Retroactive application is required.

- 6 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2. Stock-Based Compensation

As more fully discussed in Note 6 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included in the Consolidated Statements of Income based upon the job function of the employee receiving the grants as follows (in millions):

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

Lease and Well	$	9.5	$	8.0	$	24.4	$	20.3
Gathering and Processing Costs		0.2		0.1		0.6		0.4
Exploration Costs		7.8		7.3		19.4		18.1
General and Administrative		24.1		21.3		50.6		42.9
Total	$	41.6	$	36.7	$	95.0	$	81.7

The EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, as amended (2008 Plan), provides for grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units and other stock-based awards. At September 30, 2011, approximately 4.9 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares.

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan . The fair value of Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model. The fair value of stock option and SAR grants is estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $13.5 million and $12.6 million during the three months ended September 30, 2011 and 2010, respectively, and $33.4 million and $30.4 million during the nine months ended September 30, 2011 and 2010, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the nine-month periods ended September 30, 2011 and 2010 are as follows:

	Stock Options/SARs						ESPP
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010

Weighted Average Fair Value of Grants	$	29.87		$	32.10		$	22.35		$	25.42
Expected Volatility		40.92	%		39.74	%		29.68	%		38.18	%
Risk-Free Interest Rate		0.58	%		0.87	%		0.18	%		0.18	%
Dividend Yield		0.7	%		0.7	%		0.7	%		0.7	%
Expected Life	5.6 yrs			5.5 yrs			0.5 yrs			0.5 yrs

Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's common stock. The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant. The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants.

- 7 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth stock option and SAR transactions for the nine-month periods ended September 30, 2011 and 2010 (stock options and SARs in thousands):

	Nine Months Ended					Nine Months Ended
	September 30, 2011					September 30, 2010
				Weighted					Weighted
	Number of			Average		Number of			Average
	Stock			Grant		Stock			Grant
	Options/SARs			Price		Options/SARs			Price

Outstanding at January 1		8,445		$	64.49		8,335		$	57.08
Granted		1,470			85.25		1,420			93.02
Exercised (1)		(1,150	)		48.41		(924	)		40.11
Forfeited		(133	)		87.75		(80	)		80.12
Outstanding at September 30 (2)		8,632		$	69.80		8,751		$	64.49

Vested or Expected to Vest (3)		8,387		$	69.29		8,221		$	64.01

Exercisable at September 30 (4)		5,382		$	59.25		5,632		$	51.79

(1)

The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2011 and 2010 was $69 million and $58 million, respectively. The intrinsic value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the stock options/SARs.

(2)	The total intrinsic value of stock options/SARs outstanding at September 30, 2011 and 2010 was $91 million and $252 million, respectively. At September 30, 2011 and 2010, the weighted average remaining contractual life was 3.9 years and 4.1 years, respectively.

(3)	The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2011 and 2010 was $91 million and $241 million, respectively. At September 30, 2011 and 2010, the weighted average remaining contractual life was 3.8 years and 4.1 years, respectively.

(4)	The total intrinsic value of stock options/SARs exercisable at September 30, 2011 and 2010 was $91 million and $233 million, respectively. At September 30, 2011 and 2010, the weighted average remaining contractual life was 2.6 years and 3.0 years, respectively.

At September 30, 2011, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $100 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 3.0 years.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $28.1 million and $24.1 million for the three months ended September 30, 2011 and 2010, respectively, and $61.6 million and $51.3 million for the nine months ended September 30, 2011 and 2010, respectively.

- 8 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth the restricted stock and restricted stock units transactions for the nine-month periods ended September 30, 2011 and 2010 (shares and units in thousands):

	Nine Months Ended					Nine Months Ended
	September 30, 2011					September 30, 2010
				Weighted					Weighted
	Number of			Average		Number of			Average
	Shares and			Grant Date		Shares and			Grant Date
	Units			Fair Value		Units			Fair Value

Outstanding at January 1		4,009		$	79.13		3,636		$	73.69
Granted		917			90.93		840			93.36
Released (1)		(410	)		65.77		(308	)		53.99
Forfeited		(202	)		82.51		(57	)		77.71
Outstanding at September 30 (2)		4,314		$	82.75		4,111		$	79.13

(1)

The total intrinsic value of restricted stock and restricted stock units released for the nine months ended September 30, 2011 and 2010 was $40 million and $30 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.

(2)	The total intrinsic value of restricted stock and restricted stock units outstanding at September 30, 2011 and 2010 was $306 million and $382 million, respectively.

At September 30, 2011, unrecognized compensation expense related to restricted stock and restricted stock units totaled $153 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.7 years.

3. Net Income (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the three-month and nine-month periods ended September 30, 2011 and 2010 (in thousands, except per share data). For the three-month period ending September 30, 2010, the same number of shares was used in the calculation of both basic and diluted earnings per share as a result of the net loss during the period.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2011		2010			2011		2010
Numerator for Basic and Diluted Earnings Per Share -
Net Income (Loss)	$	540,878	$	(70,906	)	$	970,425	$	106,981

Denominator for Basic Earnings Per Share -
Weighted Average Shares		266,053		251,015			261,664		250,719
Potential Dilutive Common Shares -
Stock Options/SARs		1,479		-			1,759		2,059
Restricted Stock and Restricted Stock Units		1,760		-			1,822		1,666
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares		269,292		251,015			265,245		254,444

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

- 9 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The diluted earnings per share calculation excludes stock options, SARs and restricted stock and restricted stock units that were anti-dilutive. The excluded stock options and SARs totaled 0.6 million and 7.9 million shares for the three months ended September 30, 2011 and 2010, respectively, and 0.4 million and 0.3 million shares for the nine months ended September 30, 2011 and 2010, respectively. For the three months ended September 30, 2010, 4.1 million shares of restricted stock and restricted stock units were excluded.

4. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the nine-month periods ended September 30, 2011 and 2010 (in thousands):

	Nine Months Ended
	September 30,
	2011		2010

Interest (1)	$	111,111	$	71,177
Income Taxes, Net of Refunds Received	$	148,937	$	187,484

(1)	Net of capitalized interest of $44 million and $57 million for the nine months ended September 30, 2011 and 2010, respectively.

EOG’s accrued capital expenditures at September 30, 2011 and 2010 were $747 million and $679 million, respectively.

5. Comprehensive Income (Loss)

The following table presents the components of EOG's comprehensive income (loss) for the three-month and nine-month periods ended September 30, 2011 and 2010 (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Comprehensive Income (Loss)
Net Income (Loss)	$	540,878		$	(70,906	)	$	970,425		$	106,981
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		(119,338	)		61,687			(63,823	)		32,599
Foreign Currency Swap		646			(666	)		462			4,724
Income Tax Related to Foreign Currency Swap		(166	)		170			(114	)		(1,273	)
Interest Rate Swap		(2,503	)		-			(6,612	)		-
Income Tax Related to Interest Rate Swap		901			-			2,378			-
Other		28			25			86			77
Total	$	420,446		$	(9,690	)	$	902,802		$	143,108

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

6. Segment Information

Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, 2011 and 2010 (in thousands):

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

Net Operating Revenues
United States	$	2,640,739		$	1,359,896		$	6,549,392		$	3,603,758
Canada		103,842			103,587			360,380			357,186
Trinidad		134,542			110,904			421,884			328,900
Other International (1)		6,621			7,688			21,444			20,892
Total	$	2,885,744		$	1,582,075		$	7,353,100		$	4,310,736

Operating Income (Loss)
United States	$	923,810		$	252,871		$	1,938,349		$	562,194
Canada		(36,596	)		(330,985	)		(356,012	)		(386,205	)
Trinidad		96,304			76,028			279,413			222,997
Other International (1)		(33,488	)		(9,609	)		(51,016	)		(50,278	)
Total		950,030			(11,695	)		1,810,734			348,708

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

(1) Other International includes EOG's United Kingdom and China operations and, in 2011, EOG's Argentina operations.

Total assets by reportable segment are presented below at September 30, 2011 and December 31, 2010 (in thousands):

	At		At
	September 30,		December 31,
	2011		2010
Total Assets
United States	$	21,234,270	$	17,762,533
Canada		2,186,128		2,598,412
Trinidad		1,079,335		954,391
Other International (1)		294,945		308,897
Total	$	24,794,678	$	21,624,233

(1) Other International includes EOG's United Kingdom and China operations and, in 2011, EOG's Argentina operations.

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

7. Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the nine-month periods ended September 30, 2011 and 2010 (in thousands):

	Nine Months Ended
	September 30,
	2011			2010

Carrying Amount at Beginning of Period	$	498,288		$	456,484
Liabilities Incurred		45,754			27,439
Liabilities Settled (1)		(58,084	)		(21,653	)
Accretion		20,125			19,105
Revisions		61,668			53,824
Foreign Currency Translations		(3,688	)		1,980
Carrying Amount at End of Period	$	564,063		$	537,179

Current Portion	$	30,306		$	28,767
Noncurrent Portion	$	533,757		$	508,412

(1)	Includes settlements related to asset sales.

The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

8. Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the nine-month period ended September 30, 2011 are presented below (in thousands):

	Nine Months Ended
	September 30, 2011

Balance at December 31, 2010	$	99,801
Additions Pending the Determination of Proved Reserves		49,617
Reclassifications to Proved Properties		(28,568	)
Charged to Dry Hole Costs		(40,189	)
Foreign Currency Translations		(72	)
Balance at September 30, 2011	$	80,589

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table provides an aging of capitalized exploratory well costs at September 30, 2011 (in thousands, except well count):

	At
	September 30,
	2011

Capitalized exploratory well costs that have been capitalized for a period less than one year	$	36,557
Capitalized exploratory well costs that have been capitalized for a period greater than one year		44,032	(1)
Total	$	80,589
Number of exploratory wells that have been capitalized for a period greater than one year		4

(1)

Consists of costs related to an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($20 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($9 million), and a shale project in British Columbia, Canada (B.C.) ($6 million). In the Central North Sea project, the operator and partners are currently negotiating processing and transportation terms with export infrastructure owners. The operator has submitted a field development plan to the U.K. Department of Energy and Climate Change (DECC) and anticipates receiving approval of this plan by the end of the first quarter of 2012. In the East Irish Sea project, EOG submitted its field development plan to the DECC during the first quarter of 2011 with regulatory approval expected by the end of 2011. In addition, EOG is in the process of designing and constructing the infrastructure for the project in anticipation of final regulatory approval. The evaluation of the Sichuan Basin project is expected to be completed in early 2012. In the B.C. shale project, EOG drilled four additional wells during the first half of 2011 to further evaluate the project. The related well completion activities are expected to commence in 2013.

9. Commitments and Contingencies

There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes. While the ultimate outcome and impact on EOG cannot be predicted, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow. EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

10. Pension and Postretirement Benefits

EOG has a non-contributory defined contribution pension plan and a matched defined contribution savings plan in place for most of its employees in the United States, Canada, Trinidad and the United Kingdom, in addition to defined benefit pension plans covering certain employees of its Canadian and Trinidadian subsidiaries. For the nine months ended September 30, 2011 and 2010, EOG's total costs recognized for these pension plans were $21 million and $19 million, respectively. EOG also has postretirement medical and dental plans in place for eligible employees in the United States and Trinidad, the costs of which are not material.

11. Long-Term Debt and Common Stock

Long-Term Debt. EOG utilizes commercial paper and short-term borrowings from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding borrowings from commercial paper issuances or uncommitted credit facilities at September 30, 2011. The average borrowings outstanding under the commercial paper program were $2 million during the nine months ended September 30, 2011. The weighted average interest rate for commercial paper borrowings for the nine months ended September 30, 2011 was 0.32%.

- 13 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

At September 30, 2011, EOG had two $1.0 billion senior unsecured Revolving Credit Agreements with domestic and foreign lenders. There were no borrowings or letters of credit outstanding under either of these agreements at September 30, 2011. The first $1.0 billion unsecured Revolving Credit Agreement (2005 Agreement) was scheduled to mature on June 28, 2012. Advances under the 2005 Agreement accrue interest based, at EOG's option, on either the London Interbank Offering Rate (LIBOR) plus an applicable margin (Eurodollar rate) or the base rate (as defined in the 2005 Agreement). At September 30, 2011, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2005 Agreement, would have been 0.43% and 3.25%, respectively.

The second $1.0 billion senior unsecured Revolving Credit Agreement (2010 Agreement) was scheduled to mature on September 10, 2013. Advances under the 2010 Agreement accrue interest based, at EOG's option, on either the Eurodollar rate or the base rate (as defined in the 2010 Agreement) plus an applicable margin. At September 30, 2011, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2010 Agreement, would have been 1.81% and 3.83%, respectively.

On October 11, 2011, EOG entered into a $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks). The New Facility replaces the 2005 Agreement and 2010 Agreement described above. Unamortized fees related to the 2005 Agreement and 2010 Agreement will be written off in the fourth quarter of 2011.

The New Facility has a scheduled maturity date of October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods. The New Facility commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions. Advances under the New Facility will accrue interest based, at EOG's option, on either the LIBOR plus an applicable margin, or the base rate (as defined in the New Facility) plus an applicable margin. Consistent with terms in the 2005 Agreement and the 2010 Agreement, the New Facility contains representations, warranties, covenants and events of default that are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a total debt-to-total capitalization ratio of no greater than 65%.

Fair Value of Debt. At both September 30, 2011 and December 31, 2010, EOG had outstanding $5,260 million aggregate principal amount of debt, which had estimated fair values of approximately $5,816 million and $5,602 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, upon interest rates available to EOG at the end of each respective period.

Common Stock. On March 7, 2011, EOG completed the sale of 13,570,000 shares of EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share. Net proceeds from the sale of the Common Stock were approximately $1,388 million after deducting the underwriting discount and offering expenses. Proceeds from the sale were used for general corporate purposes, including funding capital expenditures.

On February 17, 2011, the EOG Board of Directors increased the quarterly cash dividend on the Common Stock from the previous $0.155 per share to $0.16 per share effective with the dividend paid on April 29, 2011 to stockholders of record as of April 15, 2011.

- 14 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

12. Fair Value Measurements

As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets. The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at September 30, 2011 and December 31, 2010 (in millions):

	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)
					Significant Unobservable Inputs (Level 3)


							Total
At September 30, 2011
Financial Assets:
Crude Oil and Natural Gas Price Swaps	$	-	$	215	$	-	$	215
Natural Gas Swaptions		-		211		-		211

Financial Liabilities:
Foreign Currency Rate Swap	$	-	$	46	$	-	$	46
Interest Rate Swap		-		5		-		5

At December 31, 2010
Financial Assets:
Natural Gas Price Swaps	$	-	$	62	$	-	$	62
Natural Gas Swaptions		-		6		-		6
Interest Rate Swap		-		2		-		2

Financial Liabilities:
Crude Oil Price Swaps and Natural Gas Basis Swaps	$	-	$	29	$	-	$	29
Foreign Currency Rate Swap		-		55		-		55

The estimated fair value of crude oil financial price swap contracts, natural gas financial price swap and basis swap contracts, natural gas swaption contracts and interest rate swap contracts was based upon forward commodity price and interest rate curves based on quoted market prices. The estimated fair value of the foreign currency rate swap contract was based upon forward currency rates.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on estimates of future retirement costs associated with oil and gas properties and other property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs, reserve lives and useful lives of other property, plant and equipment. A reconciliation of EOG's asset retirement obligations is presented in Note 7.

- 15 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Proved oil and gas properties with a carrying amount of $571 million were written down to their fair value of $180 million, resulting in a pretax impairment charge of $391 million for the nine months ended September 30, 2011. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. In connection with certain impairments of proved oil and gas properties and other property, plant and equipment, EOG utilized an accepted offer from a third-party buyer.

13. Risk Management Activities

Commodity Price Risk . As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, collar and basis swap contracts, as a means to manage this price risk. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices. EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $358 million and $61 million for the three months ended September 30, 2011 and 2010, respectively, and $481 million and $106 million for the nine months ended September 30, 2011 and 2010, respectively.

- 16 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Financial Price Swap Contracts. Presented below is a comprehensive summary of EOG's crude oil and natural gas financial price swap contracts at September 30, 2011, with notional volumes expressed in barrels per day (Bbld) and in million British thermal units per day (MMBtud) and prices expressed in dollars per barrel ($/Bbl) and in dollars per million British thermal units ($/MMBtu), as applicable.

Financial Price Swap Contracts
	Crude Oil				Natural Gas
	Volume (Bbld)		Weighted Average Price ($/Bbl)		Volume (MMBtud)		Weighted Average Price ($/MMBtu)
2011 (1)
January 2011 (closed)		17,000	$	90.44		275,000	$	5.19
February 2011 (closed)		18,000		90.69		425,000		5.09
March 2011 (closed)		20,000		91.82		425,000		5.09
April 2011 (closed)		24,000		93.61		475,000		5.03
May 2011 (closed)		24,000		93.61		650,000		4.90
June 1, 2011 through September 30, 2011 (closed)		30,000		97.02		650,000		4.90
October 1, 2011 through December 31, 2011 (2)		30,000		97.02		650,000		4.90

2012 (3)
January 1, 2012 through December 31, 2012		11,000	$	106.37		525,000	$	5.44

(1)

EOG has entered into natural gas financial price swap contracts which give counterparties the option of entering into price swap 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 financial price swap contracts will increase by 500,000 MMBtud at an average price of $4.73 per million British thermal units (MMBtu) for the period from November 1, 2011 through December 31, 2011.

(2)	The crude oil contracts for October 2011 closed on October 31, 2011. The natural gas contracts for October 2011 are closed.

(3)

EOG has entered into natural gas financial price swap contracts which give counterparties the option of entering into price swap 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 financial price swap contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for each month of 2012.

- 17 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Foreign Currency Exchange Rate Risk. As more fully described in Note 2 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, EOG is party to a foreign currency swap with multiple banks to eliminate any exchange rate impacts that may result from the $150 million principal amount of notes issued by one of EOG's Canadian subsidiaries. EOG accounts for the foreign currency swap using the hedge accounting method. Changes in the fair value of the foreign currency swap do not impact Net Income (Loss). The after-tax net impact from the foreign currency swap transaction was an increase in Other Comprehensive Income (OCI) of $0.5 million and a reduction in OCI of $0.5 million for the three months ended September 30, 2011 and 2010, respectively, and increases in OCI of $0.3 million and $3.5 million for the nine months ended September 30, 2011 and 2010, respectively.

Interest Rate Derivatives. As more fully discussed in Note 2 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, EOG is a party to an interest rate swap to mitigate its exposure to volatility in interest rates related to EOG's $350 million principal amount of Floating Rate Senior Notes due 2014 issued on November 23, 2010. EOG accounts for the interest rate swap transaction using the hedge accounting method. The after-tax net impact from the interest rate swap transaction was a reduction in OCI of $1.6 million and $4.2 million for the three and nine months ended September 30, 2011, respectively.

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding financial derivative financial instruments at September 30, 2011 and December 31, 2010. Certain amounts may be presented on a net basis in the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

		Fair Value at
		September 30,		December 31,
Description	Location on Balance Sheet	2011		2010

Asset Derivatives
Crude oil and natural gas price swaps and natural gas swaptions -
Current Portion	Assets from Price Risk Management Activities	$	365	$	51
Current Portion	Assets from Price Risk Management Activities	$	365	$	51
Noncurrent Portion	Other Assets	$	61	$	18

Liability Derivatives
Crude oil price swaps, natural gas price and basis swaps and natural gas swaptions -
Current Portion	Liabilities from Price Risk Management Activities	$	-	$	30
Current Portion	Liabilities from Price Risk Management Activities	$	-	$	30
Noncurrent Portion	Other Liabilities	$	-	$	-

Foreign currency swap - Noncurrent Portion	Other Liabilities	$	46	$	55

Interest rate swap - Noncurrent Portion	Other Assets	$	-	$	2
	Other Liabilities	$	5	$	-

- 18 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)

(Unaudited)

Credit Risk. Notional contract amounts are used to express the magnitude of commodity price, foreign currency and interest rate swap agreements. The amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 12). EOG evaluates its exposure to significant counterparties on an ongoing basis, including exposure arising from physical and financial transactions. In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk.

All of EOG's outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDA) with counterparties. The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit rating to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDAs to be settled immediately. See Note 12 for the aggregate fair value of all outstanding derivative instruments with credit-risk-related contingent features that are in a net liability position at September 30, 2011 and December 31, 2010. EOG had no collateral posted at either September 30, 2011 or December 31, 2010.

14. Acquisitions and Divestitures

In March 2011, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), purchased an additional 24.5% interest in the proposed Pacific Trail Pipelines (PTP) for $25.2 million. The PTP is intended to link western Canada's natural gas producing regions to the planned liquefied natural gas (LNG) export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia (Kitimat LNG Terminal). A portion of the purchase price ($15.3 million) was paid at closing with the remaining amount to be paid contingent on the decision to proceed with the construction of the Kitimat LNG Terminal. Additionally in March 2011, EOGRC and an affiliate of Apache Corporation (Apache), through a series of transactions, sold a portion of their interests in the Kitimat LNG Terminal and PTP to an affiliate of Encana Corporation (Encana). Subsequent to these transactions, ownership interests in both the Kitimat LNG Terminal and PTP are: Apache (operator) 40%, EOGRC 30% and Encana 30%. All future costs of the project will be paid by each party in proportion to its respective ownership percentage.

During the first nine months of 2011, EOG received proceeds of approximately $1.3 billion from sales of producing properties and acreage and certain midstream assets, primarily in the Rocky Mountain area and Texas, and the sale of a portion of EOG’s interest in the Kitimat LNG Terminal and PTP.

- 19 -

PART I. FINANCIAL INFORMATION

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EOG RESOURCES, INC.

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), 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 operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet. EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

United States and Canada. EOG's efforts to identify plays with large reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas production. EOG has placed an emphasis on applying its horizontal drilling expertise gained from its natural gas resources plays to unconventional crude oil reservoirs. In 2011, EOG has focused its efforts on developing its existing North American crude oil and condensate and natural gas liquids acreage. In addition, EOG continues to evaluate certain potential liquids-rich exploration and development prospects. For the first nine months of 2011, crude oil and condensate and natural gas liquids production accounted for approximately 35% of total company production as compared to 26% for the comparable period in 2010. North American liquids production accounted for approximately 40% of total North American production during the first nine months of 2011 as compared to 30% for the comparable period in 2010. This liquids growth reflects production from the Eagle Ford Shale Play near San Antonio, Texas, and increasing amounts of crude oil and condensate and natural gas liquids production in the Fort Worth Basin Barnett Shale area and in the Colorado Niobrara play. Based on current trends, EOG expects its 2011 crude oil and condensate and natural gas liquids production to continue to increase both in total and as a percentage of total company production as compared to 2010. EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada. EOG delivers its crude oil to various markets in the United States, including sales points on the Gulf Coast. Most recently, with increases in crude oil production from the Eagle Ford Sale Play, EOG has increased sales to the Gulf Coast and is receiving pricing based off of the Light Louisiana Sweet price. In order to create further market diversification for its growing crude oil production, EOG is expanding its crude-by-rail system to have the capability to increase deliveries of crude oil to St. James, Louisiana, beginning in early 2012. In addition, to further reduce well completion costs, EOG expects to begin using sand from its Wisconsin sand mines and processing facilities in late 2011.

- 20 -

International. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block and Modified U(b) Block, as well as the Pelican Field, have been developed and are producing crude oil and condensate and natural gas. During 2011, EOG drilled and completed six development wells in the Toucan Field on Block 4(a) and expects first production from this block in 2012. In the United Kingdom, EOG continues to make progress in field development plans for its East Irish Sea Conwy/Corfe crude oil discovery and its Central North Sea Columbus natural gas discovery. Also during 2011, EOG signed two exploration contracts and one farm-in agreement covering approximately 100,000 net acres in the Neuquen Basin in Neuquen Province, Argentina. During the third quarter of 2011, EOG performed exploration activity on a portion of this acreage in preparation for drilling a well targeting the Vaca Muerta oil shale in the Aguada del Chivato Block. EOG expects to begin drilling this well in the fourth quarter of 2011.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States and Canada primarily by pursuing exploitation opportunities in countries with large shale plays where crude oil and natural gas reserves have been identified.

Capital Structure . One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 29% at September 30, 2011 and 34% at December 31, 2010. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On October 11, 2011, EOG entered into a $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks). The New Facility replaces EOG's two $1.0 billion senior unsecured credit facilities existing at September 30, 2011. Unamortized fees totaling $5.7 million related to the facilities existing at September 30, 2011 will be written off in the fourth quarter of 2011.

The New Facility has a scheduled maturity date of October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods. The New Facility commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions. Advances under the New Facility will accrue interest based, at EOG's option, on either the London InterBank Offering Rate plus an applicable margin, or the base rate (as defined in the New Facility) plus an applicable margin. Consistent with terms in the credit facilities existing at September 30, 2011, the New Facility contains representations, warranties, covenants and events of default that are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a total debt-to-total capitalization ratio of no greater than 65%.

On March 7, 2011, EOG completed the sale of 13,570,000 shares of EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share. Net proceeds from the sale of the Common Stock were approximately $1.39 billion after deducting the underwriting discount and offering expenses. Proceeds from the sale were used for general corporate purposes, including funding capital expenditures. During the first nine months of 2011, EOG funded $5.3 billion in exploration and development and other property, plant and equipment expenditures and paid $124 million in dividends to common stockholders, primarily by utilizing cash on hand, cash provided from its operating activities, proceeds from the Common Stock sold and proceeds from asset sales.

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The total anticipated 2011 capital expenditures are estimated to range from $6.8 billion to $7.0 billion, excluding acquisitions. The majority of 2011 expenditures are focused on United States and Canada crude oil drilling activity and, to a lesser extent, natural gas drilling activity in the Haynesville, Marcellus and British Columbia Horn River Basin plays to hold acreage. EOG expects capital expenditures to be greater than cash flow from operating activities for 2011. Along with the sale of Common Stock discussed above, EOG's business plan includes selling certain non-core natural gas assets in 2011 to cover the anticipated shortfall. In the first nine months of 2011, proceeds of approximately $1.3 billion were received from sales of producing properties and acreage and certain midstream assets, primarily in the Rocky Mountain area and Texas, and the sale of a portion of EOG's interest in the Kitimat LNG Terminal and PTP. Producing properties sold represent approximately 3% of EOG's total daily production. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under the New Facility and equity and debt offerings. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

Results of Operations

The following review of operations for the three and nine months ended September 30, 2011 and 2010 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Three Months Ended September 30, 2011 vs. Three Months Ended September 30, 2010

Net Operating Revenues. During the third quarter of 2011, net operating revenues increased $1,304 million, or 82%, to $2,886 million from $1,582 million for the same period of 2010. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, natural gas liquids and natural gas, for the third quarter of 2011 increased $521 million, or 43%, to $1,737 million from $1,216 million for the same period of 2010. During the third quarter of 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $358 million compared to net gains of $61 million for the same period of 2010. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas, for the third quarter of 2011 increased $344 million, or 147%, to $578 million from $234 million for the same period of 2010. Gains on asset dispositions, net, totaled $207 million and $65 million for the third quarter of 2011 and 2010, respectively, primarily as a result of asset dispositions in the Rocky Mountain area and Texas in 2011 and in the Rocky Mountain area in 2010.

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Wellhead volume and price statistics for the three-month periods ended September 30, 2011 and 2010 were as follows:

	Three Months Ended
	September 30,
	2011		2010

Crude Oil and Condensate Volumes (MBbld) (1)
United States		108.9		66.6
Canada		6.8		5.9
Trinidad		3.1		4.8
Other International (2)		0.1		0.1
Total		118.9		77.4

Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States	$	87.22	$	71.54
Canada		90.54		69.12
Trinidad		89.70		65.06
Composite		87.49		70.96

Natural Gas Liquids Volumes (MBbld) (1)
United States		43.2		31.1
Canada		0.8		0.8
Total		44.0		31.9

Average Natural Gas Liquids Prices ($/Bbl) (3)
United States	$	50.90	$	36.56
Canada		57.69		40.34
Composite		51.02		36.66

Natural Gas Volumes (MMcfd) (1)
United States		1,122		1,175
Canada		123		200
Trinidad		330		333
Other International (2)		12		14
Total		1,587		1,722

Average Natural Gas Prices ($/Mcf) (3)
United States	$	4.06	$	4.21
Canada		3.81		3.42
Trinidad		3.59		2.53
Other International (2)		5.54		5.41
Composite		3.95		3.80

Crude Oil Equivalent Volumes (MBoed) (4)
United States		339.4		293.5
Canada		27.9		40.0
Trinidad		58.0		60.3
Other International (2)		2.0		2.5
Total		427.3		396.3

Total MMBoe (4)		39.3		36.5

(1)	Thousand barrels per day or million cubic feet per day, as applicable.

(2)	Other International includes EOG's United Kingdom and China operations.

(3)	Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments.

(4)

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.

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Wellhead crude oil and condensate revenues for the third quarter of 2011 increased $447 million, or 88%, to $953 million from $506 million for the same period of 2010, due to an increase of 42 MBbld, or 54%, in wellhead crude oil and condensate deliveries ($267 million) and a higher composite average wellhead crude oil and condensate price ($180 million). The increase in deliveries primarily reflects increased production in Texas (43 MBbld) and Colorado (4 MBbld), partially offset by decreased production in North Dakota (5 MBbld). Production increases in Texas were the result of increased production from the Eagle Ford and Fort Worth Basin Barnett Combo plays. EOG's composite average wellhead crude oil and condensate price for the third quarter of 2011 increased 23% to $87.49 per barrel compared to $70.96 per barrel for the same period of 2010.

Natural gas liquids revenues for the third quarter of 2011 increased $100 million, or 92%, to $207 million from $107 million for the same period of 2010, due to an increase of 12 MBbld, or 38%, in natural gas liquids deliveries ($41 million) and a higher composite average natural gas liquids price ($59 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale, Eagle Ford Shale and Rocky Mountain area. EOG’s composite average natural gas liquids price for the third quarter of 2011 increased 39% to $51.02 per barrel compared to $36.66 per barrel for the same period of 2010.

Wellhead natural gas revenues for the third quarter of 2011 decreased $25 million, or 4%, to $577 million from $602 million for the same period of 2010. The decrease was primarily due to a decrease in natural gas deliveries ($47 million), partially offset by a higher composite average wellhead natural gas price ($22 million). EOG's composite average wellhead natural gas price for the third quarter of 2011 increased 4% to $3.95 per Mcf compared to $3.80 per Mcf for the same period of 2010.

Natural gas deliveries for the third quarter of 2011 decreased 135 MMcfd, or 8%, to 1,587 MMcfd from 1,722 MMcfd for the same period of 2010. The decrease was primarily due to lower production in Canada (77 MMcfd) and the United States (53 MMcfd). The decreased production in Canada primarily reflects sales of certain shallow natural gas assets during the fourth quarter of 2010, partially offset by increased production from the Horn River Basin area. The decrease in the United States was primarily attributable to decreased production resulting from a decrease in natural gas drilling activity in Louisiana (45 MMcfd), the Rocky Mountain area (38 MMcfd), New Mexico (8 MMcfd) and Mississippi (8 MMcfd), partially offset by increased production in Pennsylvania (33 MMcfd) and Texas (17 MMcfd).

During the third quarter of 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $358 million compared to net gains of $61 million for the same period of 2010. During the third quarter of 2011, the net cash inflow related to settled crude oil and natural gas financial price swap contracts was $52 million compared to the net cash outflow related to settled natural gas financial collar, price swap and basis swap contracts of $14 million for the same period of 2010.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas. For the three months and nine months ended September 30, 2011 and 2010, gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas. The purchase and sale of third-party crude oil and natural gas are utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs.

During the third quarter of 2011, gathering, processing and marketing revenues and marketing costs increased primarily as a result of increased crude oil and natural gas marketing activities. Gathering, processing and marketing revenues less marketing costs for the third quarter of 2011 increased to $5 million from $2 million for the same period of 2010 due primarily to increased activity and higher margins from crude oil marketing activities, partially offset by lower margins in natural gas marketing activities.

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Operating and Other Expenses. For the third quarter of 2011, operating expenses of $1,936 million were $342 million higher than the $1,594 million incurred in the third quarter of 2010. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2011 and 2010:

	Three Months Ended
	September 30,
	2011		2010

Lease and Well	$	6.34	$	4.96
Transportation Costs		2.77		2.83
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties		15.87		13.09	(1)
Other Property, Plant and Equipment		0.73		0.71
General and Administrative (G&A)		2.09		2.23
Interest Expense, Net		1.33		0.90
Total (2)	$	29.13	$	24.72

(1)	The 2010 amount excludes the change in the estimated fair value of a contingent consideration liability relating to the acquisition of certain unproved acreage of $2 million, or $0.07 per Boe.

(2)	Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, and interest expense, net for the three months ended September 30, 2011 compared to the same period of 2010 are set forth below.

Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain EOG's crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time. In general, operating and maintenance costs for wells producing crude oil are higher than operating and maintenance costs for wells producing natural gas.

Lease and well expenses of $249 million for the third quarter of 2011 increased $68 million from $181 million for the same prior year period primarily due to higher operating and maintenance costs in the United States ($60 million), increased workover expenditures in Canada ($4 million) and the United States ($3 million), increased lease and well administrative expenses ($5 million) and unfavorable changes in the Canadian exchange rate ($2 million), partially offset by lower operating and maintenance costs in Canada ($7 million).

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees, fuel costs, transportation fees and costs associated with crude-by-rail operations.

Transportation costs of $109 million for the third quarter of 2011 increased $6 million from $103 million for the same prior year period primarily due to increased transportation costs in the San Antonio area ($8 million) and the Upper Gulf Coast area ($3 million), partially offset by decreased transportation costs in the Rocky Mountain area ($6 million). The net increase in transportation costs primarily reflects increased volumes transported to downstream markets.

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DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells, reserve revisions (upward or downward) primarily related to well performance and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from year to year. DD&A of the cost of other property, plant and equipment is calculated using the straight-line depreciation method over the useful lives of the assets. Other property, plant and equipment consists of gathering and processing assets, compressors, crude-by-rail assets, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

DD&A expenses for the third quarter of 2011 increased $151 million to $652 million from $501 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2011 were $148 million higher than the same prior year period primarily due to higher unit rates in the United States ($95 million), Canada ($9 million) and Trinidad ($4 million); increased production in the United States ($58 million); and unfavorable changes in the Canadian exchange rate ($4 million), partially offset by decreased production in Canada ($22 million).

DD&A expenses associated with other property, plant and equipment for the third quarter of 2011 were $3 million higher than the same prior year period primarily due to gathering and processing assets placed in service in the San Antonio area.

Interest expense, net, of $52 million for the third quarter of 2011 increased $19 million compared to the same prior year period primarily due to a higher average debt balance ($13 million) and lower capitalized interest ($6 million).

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties and other property, plant and equipment. Unproved properties with individually significant acquisition costs are amortized over the lease term and analyzed on a property-by-property basis for any impairment in value. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach as described in Accounting Standards Codification Topic 820, Fair Value Measurement and Disclosures. For certain natural gas assets held for sale, EOG utilizes accepted bids as the basis for determining fair value.

Impairments of $83 million for the third quarter of 2011 were $269 million lower than impairments for the same prior year period primarily due to decreased impairments of proved properties in Canada ($267 million) and lower amortization of unproved property costs in Canada ($10 million), partially offset by increased amortization of unproved property costs in the United States ($10 million). EOG recorded impairments of proved properties and other property, plant and equipment of $32 million and $302 million for the third quarter of 2011 and 2010, respectively. Included in the third quarter 2010 amount were impairments of $280 million related to certain Canadian shallow natural gas assets.

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on wellhead revenues and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income for the third quarter of 2011 increased $25 million to $99 million (5.7% of wellhead revenues) compared to $74 million (6.1% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes as a result of increased wellhead revenues in the United States ($26 million) and lower credits available to EOG in 2011 for Texas high-cost gas severance tax rate reductions ($8 million), partially offset by lower ad valorem/property taxes in the United States ($5 million) and Canada ($2 million) and decreased severance/production taxes in Canada as a result of asset dispositions during 2010 ($3 million).

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Income tax provision of $358 million for third quarter of 2011 increased $326 million compared to $32 million for the same prior year period due primarily to taxes associated with increased pretax earnings. The third quarter 2011 effective tax rate of 40% exceeded the United States statutory tax rate (35%) due primarily to foreign earnings in Trinidad (55% statutory tax rate) and foreign losses in China (25% statutory tax rate).

Nine Months Ended September 30, 2011 vs. Nine Months Ended September 30, 2010

Net Operating Revenues. During the first nine months of 2011, net operating revenues increased $3,042 million, or 71%, to $7,353 million from $4,311 million for the same period of 2010. Total wellhead revenues for the first nine months of 2011 increased $1,433 million, or 41%, to $4,949 million from $3,516 million for the same period of 2010. During the first nine months of 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $481 million compared to net gains of $106 million for the same period of 2010. Gathering, processing and marketing revenues for the first nine months of 2011 increased $859 million, or 143%, to $1,461 million from $602 million for the same period of 2010. Gains on asset dispositions, net, totaled $443 million and $72 million for the first nine months of 2011 and 2010, respectively, primarily as a result of asset dispositions in the Rocky Mountain area and Texas in 2011 and in the Rocky Mountain area in 2010.

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Wellhead volume and price statistics for the nine-month periods ended September 30, 2011 and 2010 were as follows:

	Nine Months Ended
	September 30,
	2011		2010

Crude Oil and Condensate Volumes (MBbld)
United States		94.3		59.5
Canada		8.0		6.1
Trinidad		3.6		4.7
Other International		0.1		0.1
Total		106.0		70.4

Average Crude Oil and Condensate Prices ($/Bbl) (1)
United States	$	91.40	$	72.58
Canada		92.76		71.32
Trinidad		91.56		66.91
Composite		91.52		72.09

Natural Gas Liquids Volumes (MBbld)
United States		38.7		27.4
Canada		0.8		0.9
Total		39.5		28.3

Average Natural Gas Liquids Prices ($/Bbl)
United States	$	49.85	$	40.68
Canada		54.36		42.90
Composite		49.93		40.75

Natural Gas Volumes (MMcfd)
United States		1,123		1,096
Canada		135		205
Trinidad		354		342
Other International		13		15
Total		1,625		1,658

Average Natural Gas Prices ($/Mcf) (1)
United States	$	4.13	$	4.50
Canada		3.88		4.09
Trinidad		3.42		2.54
Other International		5.60		4.64
Composite		3.97		4.05

Crude Oil Equivalent Volumes (MBoed)
United States		320.3		269.6
Canada		31.2		41.1
Trinidad		62.7		61.7
Other International		2.2		2.6
Total		416.4		375.0

Total MMBoe		113.7		102.4

(1) Excludes the impact of financial commodity derivative instruments.

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Wellhead crude oil and condensate revenues for the first nine months of 2011 increased $1,281 million, or 94%, to $2,649 million from $1,368 million for the same period of 2010, due to an increase of 36 MBbld, or 51%, in wellhead crude oil and condensate deliveries ($719 million) and a higher composite average wellhead crude oil and condensate price ($562 million). The increase in deliveries primarily reflects increased production in Texas (31 MBbld) and Colorado (4 MBbld). Production increases in Texas were the result of increased production from the Eagle Ford and Fort Worth Basin Barnett Combo plays. EOG's composite average wellhead crude oil and condensate price for the first nine months of 2011 increased 27% to $91.52 per barrel compared to $72.09 per barrel for the same period of 2010.

Natural gas liquids revenues for the first nine months of 2011 increased $224 million, or 71%, to $539 million from $315 million for the same period of 2010, due to an increase of 11 MBbld, or 40%, in natural gas liquids deliveries ($125 million) and a higher composite average natural gas liquids price ($99 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area. EOG’s composite average natural gas liquids price for the first nine months of 2011 increased 23% to $49.93 per barrel compared to $40.75 per barrel for the same period of 2010.

Wellhead natural gas revenues for the first nine months of 2011 decreased $72 million, or 4%, to $1,761 million from $1,833 million for the same period of 2010. The decrease was due to a lower composite average wellhead natural gas price ($36 million) and a decrease in natural gas deliveries ($36 million). EOG's composite average wellhead natural gas price for the first nine months of 2011 decreased 2% to $3.97 per Mcf compared to $4.05 per Mcf for the same period of 2010.

Natural gas deliveries for the first nine months of 2011 decreased 33 MMcfd, or 2%, to 1,625 MMcfd from 1,658 MMcfd for the same period of 2010. The decrease was primarily due to lower production in Canada (70 MMcfd), partially offset by increased production in the United States (27 MMcfd) and Trinidad (12 MMcfd). The decreased production in Canada primarily reflects sales of certain shallow natural gas assets in the fourth quarter of 2010, partially offset by increased production from the Horn River Basin area. The increase in the United States was primarily attributable to increased production in Texas (69 MMcfd) and Pennsylvania (23 MMcfd), partially offset by decreased production in the Rocky Mountain area (32 MMcfd), Mississippi (12 MMcfd), Louisiana (7 MMcfd), New Mexico (6 MMcfd) and Kansas (4 MMcfd). The increase in Trinidad was primarily attributable to an increase in contractual deliveries.

During the first nine months of 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $481 million compared to net gains of $106 million for the same period of 2010. During the first nine months of 2011, the net cash inflow related to settled crude oil and natural gas financial price swap contracts and natural gas basis swap contracts was $84 million compared to the net cash inflow related to settled natural gas financial collar, price swap and basis swap contracts of $25 million for the same period of 2010.

During the first nine months of 2011, gathering, processing and marketing revenues and marketing costs increased primarily as a result of increased crude oil and natural gas marketing activities. Gathering, processing and marketing revenues less marketing costs for the first nine months of 2011 totaled $34 million compared to $10 million for the same period of 2010, primarily as a result of increased activity and higher margins from crude oil and natural gas marketing activities.

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Operating and Other Expenses. For the first nine months of 2011, operating expenses of $5,542 million were $1,580 million higher than the $3,962 million incurred in the same period of 2010. The following table presents the costs per Boe for the nine-month periods ended September 30, 2011 and 2010:

	Nine Months Ended
	September 30,
	2011		2010

Lease and Well	$	5.99	$	4.97
Transportation Costs		2.71		2.80
DD&A -
Oil and Gas Properties		15.24		13.09	(1)
Other Property, Plant and Equipment		0.80		0.81
G&A		1.93		2.02
Interest Expense, Net		1.35		0.86
Total (2)	$	28.02	$	24.55

(1)	The 2010 amount excludes the change in the estimated fair value of a contingent consideration liability relating to the acquisition of certain unproved acreage of $22 million, or $0.21 per Boe.

(2)	Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A, and interest expense, net for the nine months ended September 30, 2011 compared to the same period of 2010 are set forth below.

Lease and well expenses of $681 million for the first nine months of 2011 increased $173 million from $508 million for the same prior year period primarily due to higher operating and maintenance costs in the United States ($142 million) and Trinidad ($3 million), increased lease and well administrative expenses ($23 million), increased workover expenditures in the United States ($7 million) and Canada ($3 million) and unfavorable changes in the Canadian exchange rate ($7 million), partially offset by lower operating and maintenance costs in Canada ($13 million).

Transportation costs of $308 million for the first nine months of 2011 increased $22 million from $286 million for the same prior year period primarily due to increased transportation costs in the Upper Gulf Coast area ($16 million), the San Antonio area ($13 million) and the Fort Worth Basin Barnett Shale area ($6 million), partially offset by decreased transportation costs in the Rocky Mountain area ($7 million) and Canada ($3 million). The net increase in transportation costs primarily reflects increased volumes transported to downstream markets.

DD&A expenses for the first nine months of 2011 increased $425 million to $1,823 million from $1,398 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2011 were $416 million higher than the same prior year period primarily as a result of higher unit rates in the United States ($224 million), Trinidad ($36 million) and Canada ($8 million); increased production in the United States ($191 million); and unfavorable changes in the Canadian exchange rate ($12 million), partially offset by decreased production in Canada ($58 million).

DD&A expenses associated with other property, plant and equipment for the first nine months of 2011 were $9 million higher than the same prior year period primarily due to gathering and processing assets placed in service in the Rocky Mountain area ($4 million) and in Texas ($2 million).

G&A expenses of $220 million for the first nine months of 2011 increased $13 million compared to the same prior year period primarily due to higher employee-related costs.

Interest expense, net, of $154 million for the first nine months of 2011 increased $66 million from $88 million for the same prior year period primarily due to a higher average debt balance ($53 million) and lower capitalized interest ($13 million).

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Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets.

Gathering and processing costs for the first nine months of 2011 increased $8 million to $55 million compared to the same prior year period primarily due to increased activities in the United States ($4 million), primarily in the Fort Worth Basin Barnett Shale area, and in Canada ($4 million).

Exploration costs of $141 million for the first nine months of 2011 decreased $8 million from $149 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States ($9 million), Canada ($2 million) and the United Kingdom ($2 million), partially offset by increased exploration administrative expenses ($5 million).

Impairments of $531 million for the first nine months of 2011 were $29 million higher than impairments for the same prior year period primarily due to increased impairments of proved properties and other property, plant and equipment in the United States ($24 million) and Canada ($18 million) and changes in the Canadian exchange rate ($18 million), partially offset by decreased amortization of unproved property costs in the United States ($20 million) and Canada ($11 million). EOG recorded impairments of proved properties and other property, plant and equipment of $391 million and $332 million for the first nine months of 2011 and 2010, respectively, related primarily to certain Canadian shallow natural gas assets.

Taxes other than income for the first nine months of 2011 increased $81 million to $309 million (6.2% of wellhead revenues) from $228 million (6.5% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes primarily as a result of increased wellhead revenues in the United States ($76 million) and lower credits available to EOG in 2011 for Texas high-cost gas severance tax rate reductions ($9 million), partially offset by lower ad valorem/property taxes in Canada as a result of property dispositions during 2010 ($5 million).

Other income (expense), net was $11 million for the first nine months of 2011 compared to $8 million for the same prior year period. The increase of $3 million was primarily due to higher equity income from EOG's investment in ammonia plants in Trinidad ($5 million) and lower deferred compensation expense ($2 million), partially offset by an increase in foreign currency transaction losses ($4 million).

Income tax provision of $698 million for the first nine months of 2011 increased $537 million compared to $161 million for the same prior year period due primarily to taxes associated with increased pretax earnings. The effective tax rate for the first nine months of 2011 decreased to 42% from 60% in the prior year. The effective tax rate for the first nine months of 2011 exceeded the United States statutory tax (35%) rate due mostly to foreign earnings in Trinidad (55% statutory tax rate) combined with foreign losses in Canada (27% statutory tax rate) and China (25% statutory tax rate).

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2011 were funds generated from operations, net proceeds from the sale of Common Stock, proceeds from asset sales and proceeds from stock options exercised and employee stock purchase plan activity. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; and dividend payments to stockholders. During the first nine months of 2011, EOG's cash balance increased $598 million to $1,387 million from $789 million at December 31, 2010.

Net cash provided by operating activities of $3,342 million for the first nine months of 2011 increased $1,256 million compared to the same period of 2010 primarily reflecting an increase in wellhead revenues ($1,433 million), a favorable change in net cash flow from the settlement of financial commodity derivative contracts ($59 million), a decrease in net cash paid for income taxes ($39 million) and favorable changes in working capital and other assets and liabilities ($12 million), partially offset by an increase in cash operating expenses ($276 million) and an increase in net cash paid for interest expense ($40 million).

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Net cash used in investing activities of $4,007 million for the first nine months of 2011 increased by $381 million compared to the same period of 2010 due primarily to an increase in additions to oil and gas properties ($925 million); unfavorable changes in working capital associated with investing activities ($350 million); and an increase in additions to other property, plant and equipment ($279 million); partially offset by an increase in proceeds from sales of assets ($1,168 million).

Net cash provided by financing activities of $1,270 million for the first nine months of 2011 included net proceeds from the sale of Common Stock ($1,388 million) and proceeds from stock options exercised and employee stock purchase plan activity ($27 million). Cash used in financing activities for the first nine months of 2011 included cash dividend payments ($124 million) and the purchase of treasury stock in connection with stock compensation plans ($21 million). Net cash provided by financing activities of $882 million for the first nine months of 2010 included proceeds from the issuances of long-term debt ($991 million), net commercial paper borrowings ($34 million) and proceeds from stock options exercised and employee stock purchase plan activity ($25 million). Cash used in financing activities for the first nine months of 2010 included cash dividend payments ($114 million), the repayment of long-term debt ($37 million), the purchase of treasury stock in connection with stock compensation plans ($10 million) and debt issuance costs ($6 million).

Total Expenditures. For 2011, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $6.8 billion to $7.0 billion, excluding acquisitions. The table below sets forth components of total expenditures for the nine-month periods ended September 30, 2011 and 2010 (in millions):

	Nine Months Ended
	September 30,
	2011		2010
Expenditure Category
Capital
Drilling and Facilities	$	4,377	$	3,263
Leasehold Acquisitions		192		354
Property Acquisitions		4		24
Capitalized Interest		44		57
Subtotal		4,617		3,698
Exploration Costs		141		149
Dry Hole Costs		47		45
Exploration and Development Expenditures		4,805		3,892
Asset Retirement Costs		111		79
Total Exploration and Development Expenditures		4,916		3,971
Other Property, Plant and Equipment		502		223
Total Expenditures	$	5,418	$	4,194

Exploration and development expenditures of $4,805 million for the first nine months of 2011 were $913 million higher than the same period of 2010 due primarily to increased drilling and facilities expenditures in the United States ($1,212 million), the United Kingdom ($38 million) and Trinidad ($15 million); and unfavorable changes in the foreign currency exchange rate in Canada ($11 million). These increases were partially offset by decreased leasehold acquisitions expenditures in the United States ($153 million) and Canada ($9 million), decreased drilling and facilities expenditures in Canada ($98 million) and China ($63 million), decreased property acquisitions expenditures in the United States ($20 million) and decreased capitalized interest in the United States ($13 million). The exploration and development expenditures for the first nine months of 2011 of $4,805 million include $4,335 million in development, $422 million in exploration, $44 million in capitalized interest and $4 million in property acquisitions. The exploration and development expenditures for the first nine months of 2010 of $3,892 million include $3,007 million in development, $804 million in exploration, $57 million in capitalized interest and $24 million in property acquisitions.

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The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

Commodity Derivative Transactions. As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2010, filed on February 24, 2011, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income. The related cash flow impact is reflected as Cash Flows from Operating Activities. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

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Financial Price Swap Contracts. The total fair value of EOG's crude oil and natural gas financial price swap contracts was reflected on the Consolidated Balance Sheets at September 30, 2011 as an asset of $149 million and a net asset of $277 million, respectively. Presented below is a comprehensive summary of EOG's crude oil and natural gas financial price swap contracts at November 1, 2011, with notional volumes expressed in barrels per day (Bbld) and in million British thermal units per day (MMBtud) and prices expressed in dollars per barrel ($/Bbl) and in dollars per million British thermal units ($/MMBtu), as applicable.

Financial Price Swap Contracts
	Crude Oil				Natural Gas
	Volume (Bbld)		Weighted Average Price ($/Bbl)		Volume (MMBtud)		Weighted Average Price ($/MMBtu)
2011 (1)
January 2011 (closed)		17,000	$	90.44		275,000	$	5.19
February 2011 (closed)		18,000		90.69		425,000		5.09
March 2011 (closed)		20,000		91.82		425,000		5.09
April 2011 (closed)		24,000		93.61		475,000		5.03
May 2011 (closed)		24,000		93.61		650,000		4.90
June 1, 2011 through October 31, 2011 (closed)		30,000		97.02		650,000		4.90
November 2011 (2)		30,000		97.02		650,000		4.90
December 31, 2011		30,000		97.02		650,000		4.90

2012 (3)
January 1, 2012 through December 31, 2012		11,000	$	106.37		525,000	$	5.44

(1)

(2)	The crude oil contracts for November 2011 will close on November 30, 2011. The natural gas contracts for November 2011 are closed.

(3)

EOG has entered into natural gas financial price swap contracts which give counterparties the option of entering into price swap 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 financial price swap contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for each month of 2012.

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Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q 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;

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·	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 year ended December 31, 2010.

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.

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PART I. FINANCIAL INFORMATION

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

EOG RESOURCES, INC.

EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in (i) the "Derivative Transactions," "Financing," "Foreign Currency Exchange Rate Risk" and "Outlook" sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity," on pages 41 through 45 of EOG's Annual Report on Form 10-K for the year ended December 31, 2010, filed on February 24, 2011 (EOG's 2010 Annual Report); and (ii) Note 11, "Risk Management Activities," to EOG's Consolidated Financial Statements on pages F-26 through F-29 of EOG's 2010 Annual Report. There have been no material changes in this information. For additional information regarding EOG's financial commodity derivative contracts and physical commodity contracts, see (i) Note 13 to Consolidated Financial Statements in this Quarterly Report on Form 10-Q; (ii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Net Operating Revenues" in this Quarterly Report on Form 10-Q; and (iii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions" in this Quarterly Report on Form 10-Q.

ITEM 4. CONTROLS AND PROCEDURES

EOG RESOURCES, INC.

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this Quarterly Report on Form 10-Q (Evaluation Date). Based on this evaluation, EOG's principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date in ensuring that information that is required to be disclosed by EOG in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to EOG's management as appropriate to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting. There were no changes in EOG's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act) that occurred during the quarterly period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

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PART II. OTHER INFORMATION

EOG RESOURCES, INC.

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item 1, Note 9 to Consolidated Financial Statements, which is incorporated herein by reference.

On December 13, 2010, an inadvertent spill of water (predominantly fresh water, along with a small amount of flowback water) occurred at the EOG-operated Punxsutawney Hunt Club #30 and #31 natural gas wells in Clearfield County, Pennsylvania. The Pennsylvania Fish and Boat Commission (PFBC) has alleged that the spill resulted in pollution of area waters, in violation of the water pollution provisions and water quality standards of Pennsylvania law. EOG is currently in discussions with the PFBC regarding the alleged violations and the monetary penalty sought by the PFBC, and anticipates resolving this matter in November 2011 or December 2011. This proceeding was instituted by the PFBC on September 13, 2011.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth, for the periods indicated, EOG's share repurchase activity:

					Total Number of
	Total				Shares Purchased as		Maximum Number
	Number of		Average		Part of Publicly		of Shares that May Yet
	Shares		Price Paid		Announced Plans or		Be Purchased Under
Period	Purchased (1)		Per Share		Programs		The Plans or Programs (2)

July 1, 2011 - July 31, 2011		2,885	$	102.11		-		6,386,200
August 1, 2011 - August 31, 2011		1,382		99.67		-		6,386,200
September 1, 2011 - September 30, 2011		48,086		87.11		-		6,386,200
Total		52,353		88.27		-

(1)

Represents shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock or restricted stock unit grants or (ii) in payment of the exercise price of employee stock options. These shares do not count against the 10 million aggregate share authorization by EOG's Board of Directors (Board) discussed below.

(2)	In September 2001, the Board authorized the repurchase of up to 10 million shares of EOG's common stock. During the third quarter of 2011, EOG did not repurchase any shares under the Board-authorized repurchase program.

ITEM 5. OTHER INFORMATION

Under the Dodd-Frank Wall Street Reform and Consumer Protection Act, each operator of a coal or other mine is required to disclose certain mine safety matters in its periodic reports filed with the United States Securities and Exchange Commission. This disclosure requirement became effective during, and for, the quarterly period ended September 30, 2010.

EOG has sand mining operations in Wisconsin and Texas, which support EOG's exploration operations. EOG's sand mining operations are subject to regulation by the federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Act). MSHA inspects mining facilities on a regular basis and issues citations and orders when it believes a violation has occurred under the Mine Act.

On June 30, 2011, EOG received a citation from MSHA for a violation of a mandatory health or safety standard that was deemed by the MSHA inspector to be significant and substantial under Section 104 of the Mine Act. EOG immediately remedied the violation, and the citation was terminated on the same day it was issued. In connection with the citation, EOG was assessed and has paid a one hundred dollar penalty.

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Except as described above, for the period from July 1, 2010 through September 30, 2011, none of EOG's sand mining operations have received from MSHA (i) a citation for a violation of a mandatory health or safety standard that could significantly and substantially contribute to the cause and effect of a mine health or safety hazard under Section 104 of the Mine Act; (ii) an order issued under Section 104(b) of the Mine Act; (iii) a citation or order for unwarrantable failure to comply with mandatory health or safety standards under Section 104(d) of the Mine Act; (iv) written notice of a flagrant violation under Section 110(b)(2) of the Mine Act; (v) an imminent danger order issued under Section 107(a) of the Mine Act; (vi) written notice of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under Section 104(e) of the Mine Act; or (vii) written notice of the potential to have such a pattern. Moreover, for the period from July 1, 2010 through September 30, 2011, none of EOG's sand mining operations experienced a mining-related fatality. In addition, as of November 1, 2011, none of EOG's sand mining operations have any pending legal action before the Federal Mine Safety and Health Review Commission.

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ITEM 6. EXHIBITS

Exhibit No. Description

10.1	-	Second Amendment to Amended and Restated Change of Control Agreement, dated and effective as of September 13, 2011, by and between EOG and Mark G. Papa (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.2	-	First Amendment to Change of Control Agreement, dated and effective as of September 13, 2011, by and between EOG and William R. Thomas (incorporated by reference to Exhibit 10.2 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.3	-	Second Amendment to Amended and Restated Change of Control Agreement, dated and effective as of September 13, 2011, by and between EOG and Gary L. Thomas (incorporated by reference to Exhibit 10.3 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.4	-	Second Amendment to Amended and Restated Change of Control Agreement, dated and effective as of September 13, 2011, by and between EOG and Timothy K. Driggers (incorporated by reference to Exhibit 10.4 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.5	-	Second Amendment to Change of Control Agreement, dated and effective as of September 13, 2011, by and between EOG and Frederick J. Plaeger, II (incorporated by reference to Exhibit 10.5 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.6	-	Revolving Credit Agreement, dated as of October 11, 2011, among EOG, JPMorgan Chase Bank, N.A., as Administrative Agent, the financial institutions as bank parties thereto, and the other parties thereto (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K, filed October 12, 2011).

* 31.1	-	Section 302 Certification of Periodic Report of Principal Executive Officer.

* 31.2	-	Section 302 Certification of Periodic Report of Principal Financial Officer.

* 32.1	-	Section 906 Certification of Periodic Report of Principal Executive Officer.

* 32.2	-	Section 906 Certification of Periodic Report of Principal Financial Officer.

* **101.INS	-	XBRL Instance Document.

* **101.SCH	-	XBRL Schema Document.

* **101.CAL	-	XBRL Calculation Linkbase Document.

* **101.DEF	-	XBRL Definition Linkbase Document.

* **101.LAB	-	XBRL Label Linkbase Document.

* **101.PRE	-	XBRL Presentation Linkbase Document.

* Exhibits filed herewith

** Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income - Three Months Ended September 30, 2011 and 2010 and Nine Months Ended September 30, 2011 and 2010, (ii) the Consolidated Balance Sheets - September 30, 2011 and December 31, 2010, (iii) the Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2011 and 2010 and (iv) Notes to Consolidated Financial Statements.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		EOG RESOURCES, INC.
		(Registrant)



Date: November 1, 2011	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

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EXHIBIT INDEX

Exhibit No. Description

10.1	-	Second Amendment to Amended and Restated Change of Control Agreement, dated and effective as of September 13, 2011, by and between EOG and Mark G. Papa (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.2	-	First Amendment to Change of Control Agreement, dated and effective as of September 13, 2011, by and between EOG and William R. Thomas (incorporated by reference to Exhibit 10.2 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.3	-	Second Amendment to Amended and Restated Change of Control Agreement, dated and effective as of September 13, 2011, by and between EOG and Gary L. Thomas (incorporated by reference to Exhibit 10.3 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.4	-	Second Amendment to Amended and Restated Change of Control Agreement, dated and effective as of September 13, 2011, by and between EOG and Timothy K. Driggers (incorporated by reference to Exhibit 10.4 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.5	-	Second Amendment to Change of Control Agreement, dated and effective as of September 13, 2011, by and between EOG and Frederick J. Plaeger, II (incorporated by reference to Exhibit 10.5 to EOG's Current Report on Form 8-K, filed September 13, 2011).

10.6	-	Revolving Credit Agreement, dated as of October 11, 2011, among EOG, JPMorgan Chase Bank, N.A., as Administrative Agent, the financial institutions as bank parties thereto, and the other parties thereto (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K, filed October 12, 2011).

* 31.1	-	Section 302 Certification of Periodic Report of Principal Executive Officer.

* 31.2	-	Section 302 Certification of Periodic Report of Principal Financial Officer.

* 32.1	-	Section 906 Certification of Periodic Report of Principal Executive Officer.

* 32.2	-	Section 906 Certification of Periodic Report of Principal Financial Officer.

* **101.INS	-	XBRL Instance Document.

* **101.SCH	-	XBRL Schema Document.

* **101.CAL	-	XBRL Calculation Linkbase Document.

* **101.DEF	-	XBRL Definition Linkbase Document.

* **101.LAB	-	XBRL Label Linkbase Document.

* **101.PRE	-	XBRL Presentation Linkbase Document.

* Exhibits filed herewith

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TABLE OF CONTENTS

Part I. Financial Informationprint Item 3. Quantitative and Qualitative Disclosures About Market Riskprint Item 4. Controls and Proceduresprint Part II. Other Informationprint Item 1. Legal Proceedingsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 5. Other Informationprint Item 6. Exhibitsprint

Customer name	Ticker
Adams Resources & Energy, Inc.	AE
Apache Corporation	APA
EQT Corporation	EQT
ManpowerGroup Inc.	MAN
Valero Energy Corporation	VLO

Supplier name	Ticker
Honeywell International Inc.	HON
Raytheon Technologies Corporation	RTX
American Water Works Company, Inc.	AWK
Ecopetrol S.A.	EC
Dover Corporation	DOV
Xylem Inc.	XYL
Broadridge Financial Solutions, Inc.	BR
Markel Corporation	MKL
Halliburton Company	HAL

EOG 10-Q Quarter ended Sept. 30, 2011