EOG Resources - 10-Q quarterly report FY

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended September 30, 2009

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 (Section 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 xNo 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 oNo 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		252,355,378 (as of November 2, 2009)

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, 2009 and 2008 and Nine Months Ended September 30, 2009 and 2008	3

		Consolidated Balance Sheets - September 30, 2009 and December 31, 2008	4

		Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2009 and 2008	5

		Notes to Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	39

	ITEM 4.	Controls and Procedures	39

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	40

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40

	ITEM 6.	Exhibits	41

SIGNATURES			42

EXHIBIT INDEX			43

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,
				2009		2008		2009		2008


Net Operating Revenues
	Natural Gas		$	450,304	$	1,259,130	$	1,477,926	$	3,637,325
	Crude Oil, Condensate and Natural Gas Liquids			398,806		574,402		886,268		1,494,043
	Gains on Mark-to-Market Commodity
	Derivative Contracts			20,877		1,381,733		405,830		69,067
	Gathering, Processing and Marketing			134,553		51,145		249,679		150,907
	Other, Net			2,309		(2,524)		6,394		142,074
		Total		1,006,849		3,263,886		3,026,097		5,493,416

Operating Expenses
	Lease and Well			142,183		142,238		422,288		396,294
	Transportation Costs			70,971		78,136		205,844		203,205
	Gathering and Processing Costs			13,318		9,104		44,552		26,385
	Exploration Costs			44,910		37,943		128,840		145,397
	Dry Hole Costs			3,016		12,849		39,653		28,062
	Impairments			69,404		32,142		181,921		113,591
	Marketing Costs			131,816		44,380		237,819		140,411
	Depreciation, Depletion and Amortization			385,330		346,247		1,150,251		958,740
	General and Administrative			62,775		70,893		179,481		185,459
	Taxes Other Than Income			47,823		97,771		118,715		279,866
		Total		971,546		871,703		2,709,364		2,477,410

Operating Income				35,303		2,392,183		316,733		3,016,006
Other Income (Expense), Net				(339)		13,864		2,637		28,756
Income Before Interest Expense and Income Taxes				34,964		2,406,047		319,370		3,044,762
Interest Expense, Net				30,407		12,095		73,594		33,315
Income Before Income Taxes				4,557		2,393,952		245,776		3,011,447
Income Tax Provision				361		837,667		99,576		1,036,000
Net Income				4,196		1,556,285		146,200		1,975,447
Preferred Stock Dividends				-		-		-		443
Net Income Available to Common Stockholders			$	4,196	$	1,556,285	$	146,200	$	1,975,004

Net Income Per Share Available to Common Stockholders
	Basic		$	0.02	$	6.30	$	0.59	$	8.02
	Diluted		$	0.02	$	6.20	$	0.58	$	7.88

Dividends Declared per Common Share			$	0.145	$	0.135	$	0.435	$	0.375

Average Number of Common Shares
	Basic			249,535		247,155		248,647		246,343
	Diluted			252,422		250,930		251,288		250,765

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

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EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
(Unaudited)

						September 30,		December 31,
						2009		2008
ASSETS
Current Assets
		Cash and Cash Equivalents			$	608,511	$	331,311
		Accounts Receivable, Net				604,260		722,695
		Inventories				240,230		187,970
		Assets from Price Risk Management Activities				290,536		779,483
		Income Taxes Receivable				27,134		27,053
		Other				61,018		59,939
				Total		1,831,689		2,108,451

Property, Plant and Equipment
		Oil and Gas Properties (Successful Efforts Method)				23,515,362		20,803,629
		Other Property, Plant and Equipment				1,261,505		1,057,888
			Total Property, Plant and Equipment			24,776,867		21,861,517
		Less: Accumulated Depreciation, Depletion and Amortization				(9,524,312)		(8,204,215)
				Total Property, Plant and Equipment, Net		15,252,555		13,657,302
Other Assets						137,049		185,473
Total Assets					$	17,221,293	$	15,951,226


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
		Accounts Payable			$	783,764	$	1,122,209
		Accrued Taxes Payable				86,334		86,265
		Dividends Payable				36,255		33,461
		Liabilities from Price Risk Management Activities				16,370		4,429
		Deferred Income Taxes				114,304		368,231
		Current Portion of Long-Term Debt				37,000		37,000
		Other				127,124		113,321
				Total		1,201,151		1,764,916

Long-Term Debt						2,760,000		1,860,000
Other Liabilities						609,150		498,291
Deferred Income Taxes						3,133,252		2,813,522
Commitments and Contingencies (Note 9)

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized:
	252,421,628 Shares Issued at September 30, 2009 and 249,758,577
	Shares Issued at December 31, 2008					202,524		202,498
Additional Paid in Capital						528,544		323,805
Accumulated Other Comprehensive Income						291,627		27,787
Retained Earnings						8,502,940		8,466,143
Common Stock Held in Treasury, 128,898 Shares at September 30, 2009
and 126,911 Shares at December 31, 2008						(7,895)		(5,736)
				Total Stockholders' Equity		9,517,740		9,014,497
Total Liabilities and Stockholders' Equity					$	17,221,293	$	15,951,226

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

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EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)

				Nine Months Ended
				September 30,
				2009		2008
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	146,200	$	1,975,447
	Items Not Requiring (Providing) Cash
		Depreciation, Depletion and Amortization		1,150,251		958,740
		Impairments		181,921		113,591
		Stock-Based Compensation Expenses		74,532		76,344
		Deferred Income Taxes		39,793		790,699
		Other, Net		2,738		(135,325)
	Dry Hole Costs			39,653		28,062
	Mark-to-Market Commodity Derivative Contracts
		Total Gains		(405,830)		(69,067)
		Realized Gains (Losses)		986,980		(237,326)
	Other, Net			9,385		14,390
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		119,099		(219,947)
		Inventories		(23,592)		(45,354)
		Accounts Payable		(361,698)		221,449
		Accrued Taxes Payable		(17,955)		135,747
		Other Assets		(4,255)		(18,756)
		Other Liabilities		9,357		(3,397)
	Changes in Components of Working Capital Associated with
		Investing and Financing Activities		147,097		14,389
Net Cash Provided by Operating Activities				2,093,676		3,599,686

Investing Cash Flows
	Additions to Oil and Gas Properties			(2,267,884)		(3,532,343)
	Additions to Other Property, Plant and Equipment			(240,614)		(320,699)
	Proceeds from Sales of Assets			2,515		369,669
	Changes in Components of Working Capital Associated with
		Investing Activities		(146,783)		(14,501)
	Other, Net			1,405		(1,316)
Net Cash Used in Investing Activities				(2,651,361)		(3,499,190)

Financing Cash Flows
	Long-Term Debt Borrowings			900,000		750,000
	Long-Term Debt Repayments			-		(38,000)
	Dividends Paid			(105,989)		(81,453)
	Redemptions of Preferred Stock			-		(5,395)
	Excess Tax Benefits from Stock-Based Compensation			34,052		69,824
	Treasury Stock Purchased			(9,888)		(11,266)
	Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			13,691		67,414
	Debt Issuance Costs			(8,887)		(6,704)
	Other, Net			(314)		112
Net Cash Provided by Financing Activities				822,665		744,532

Effect of Exchange Rate Changes on Cash				12,220		(13,282)

Increase in Cash and Cash Equivalents				277,200		831,746
Cash and Cash Equivalents at Beginning of Period				331,311		54,231
Cash and Cash Equivalents at End of Period			$	608,511	$	885,977

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

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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 (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 conju nction 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, 2008, filed on February 25, 2009 (EOG's 2008 Annual Report).

The preparation of financial statements in conformity with 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, 2009 are not necessarily indicative of the results to be expected for the full year.

net of related purchase and transportation costs in Net Operating Revenues - Other, Net. In addition, certain other expenses previously included in Lease and Well have been reclassified to Gathering and Processing Costs. The effect of these reclassifications on the three and nine months ended September 30, 2008 presentation in the Consolidated Statements of Income was to increase total net operating revenues and total operating expenses by $44 million and $140 million, respectively. These changes did not impact previously reported operating income, net income or cash flows.

Recently Issued Accounting Standards and Developments. In June 2009, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 168, "The FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162" (SFAS No. 168), which establishes the FASB Accounting Standards Codification (ASC) as the source of authoritative accounting principles recognized by the FASB to be applied in the preparation of financial statements in conformity with GAAP. SFAS No. 168 explicitly recognizes rules and interpretive releases of the SEC under federal securities laws as authoritative GAAP for SEC registrants. The ASC became effective for interim and annual periods ending after September 15, 2009. EOG has modified its disclosures to appropriately update references to GAAP included in this Quarterly Report on Form 10-Q.

Effective June 30, 2009, EOG adopted the interim disclosure provisions of the Financial Instruments Topic of the ASC. The new interim disclosure provisions were issued by the FASB in April 2009 and require disclosures about fair value of financial instruments for interim reporting periods as well as in annual financial statements. The new interim disclosure provisions became effective for interim periods ending after June 15, 2009. See Note 11.

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Effective April 1, 2009, EOG adopted the provisions of the Subsequent Events Topic of the ASC (ASC Topic 855). ASC Topic 855 clarifies that management must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date and through the date that the financial statements are issued or available to be issued, both for interim and annual reporting periods. The provisions of ASC Topic 855 became effective prospectively for interim and annual reporting periods ending after June 15, 2009. Based on an analysis of subsequent events through November 5, 2009, EOG has determined that there are no subsequent events which require recognition or disclosure in these consolidated financial statements.

Effective January 1, 2009, EOG adopted the provisions of the Business Combinations Topic of the ASC (ASC Topic 805). ASC Topic 805 establishes principles and requirements for how the acquirer recognizes and measures in the financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired, as well as determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. In April 2009, the FASB amended the provisions of ASC Topic 805 related to recognition, measurement and disclosure of assets and liabilities assumed in a business combination that arise from contingencies. The amended provisions of ASC Topic 805 became effective January 1, 2009.

Effective January 1, 2009, EOG adopted the expanded disclosure provisions of the Derivatives and Hedging Topic of the ASC (ASC Topic 815). The new provisions, which were issued by the FASB in March 2008, do not expand the scope of ASC Topic 815, but require expanded disclosures about an entity's derivative instruments and hedging activities. The expanded disclosure provisions became effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. See Note 13.

The Fair Value Measurements and Disclosures Topic of the ASC (ASC Topic 820) was issued by the FASB in September 2006 and provides a definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC Topic 820 also establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy. In February 2008, the FASB amended ASC Topic 820 to delay the effective date of the measurement and disclosure provisions for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008. EOG partially adopted ASC Topic 820 effective January 1, 2008 and adopted the provisions related to nonfinancial assets and liabilities effective January 1, 2009. See Note 12.

In December 2008, the SEC released a final rule, "Modernization of Oil and Gas Reporting," which amends the oil and gas reporting requirements. The key revisions to the reporting requirements include: using a 12-month average price to determine reserves; including nontraditional resources in reserves if they are intended to be upgraded to synthetic oil and gas; ability to use new technologies to determine and estimate reserves; and permitting the disclosure of probable and possible reserves. In addition, the final rule includes the requirements to report the independence and qualifications of the reserve preparer or auditor; to file a report as an exhibit when a third party is relied upon to prepare reserve estimates or conduct reserve audits; and to disclose the development of any proved undeveloped reserves (PUDs), including the total quantity of PUDs at year-end, material changes to PUDs during the year, investments and progress toward the development of PUDs and an explanation of the reasons why material concentrations of PUDs have remained undeveloped for five years or more after disclosure as PUDs. The accounting changes resulting from changes in definitions and pricing assumptions should be treated as a change in accounting principle that is inseparable from a change in accounting estimate, which is to be applied prospectively. The final rule is effective for annual reports for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. EOG is assessing the impact that this final rule will have on its consolidated financial statements.

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2. Stock-Based Compensation

As more fully discussed in Note 6 to the Consolidated Financial Statements included in EOG's 2008 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included in the Consolidated Statements of Income based upon job functions of the employees receiving the grants as follows (in millions):

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2009		2008		2009		2008

Lease and Well	$	6.3	$	5.7	$	17.7	$	14.2
Exploration Costs		5.1		5.1		15.2		13.5
General and Administrative		14.6		20.9		41.6		48.6
Total	$	26.0	$	31.7	$	74.5	$	76.3

The EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units and other stock-based awards, up to an aggregate maximum of 6.0 million shares of common stock, plus shares underlying forfeited or cancelled grants under the prior stock plans. At September 30, 2009, approximately 2.2 million common shares remained available for grant under the 2008 Plan. Effective with the adoption of the 2008 Plan, EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares.

Stock Options and Stock Appreciation Rights and Employee Stock Purchase Plan. The fair value of all Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model. Certain of EOG's stock options granted in 2005 contain a feature that limits the potential gain that can be realized by requiring vested options to be exercised if the market price of EOG's common stock reaches 200% of the grant price for five consecutive trading days (Capped Option). EOG may or may not issue Capped Options in the future. The fair value of each Capped Option grant was estimated using a Monte Carlo simulation. The fair value of stock option grants not containing the Capped Option feature and SAR grants was estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $10.3 million and $11.1 million during the three months ended September 30, 2009 and 2008, respectively, and $2 9.4 million and $28.9 million during the nine months ended September 30, 2009 and 2008, 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, 2009 and 2008 are as follows:

		Stock Options/SARs				ESPP
		Nine Months Ended				Nine Months Ended
		September 30,				September 30,
		2009		2008		2009		2008

Weighted Average Fair Value of Grants	$	30.11	$	32.17	$	25.78	$	27.81
Expected Volatility		41.92%		38.40%		78.89%		36.17%
Risk-Free Interest Rate		1.42%		2.55%		0.25%		2.79%
Dividend Yield		0.7%		0.6%		1.0%		0.5%
Expected Life		5.5 yrs		5.3 yrs		0.5 yrs		0.5 yrs

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Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's 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 options, SAR and ESPP grants.

EOG suspended the ESPP, effective for the July 1, 2009 - December 31, 2009 offering period, due to an insufficient number of shares remaining available under the ESPP. Subject to stockholder approval of an amendment to the ESPP to increase the shares available under the ESPP at the 2010 Annual Meeting of Stockholders, EOG expects to resume the ESPP for the January 1, 2010 - June 30, 2010 offering period. The ESPP was originally approved by EOG's stockholders in 2001.

The following table sets forth the stock option and SAR transactions for the nine-month periods ended September 30, 2009 and 2008 (stock options and SARs in thousands):

	Nine Months Ended			Nine Months Ended
	September 30, 2009			September 30, 2008
			Weighted			Weighted
	Number of		Average	Number of		Average
	Stock Options/SARs		Grant Price	Stock Options/SARs		Grant Price

Outstanding at January 1	7,802	$	52.56	9,373	$	41.04
Granted	1,251		80.87	1,211		90.70
Exercised ⁽¹⁾	(387)		41.67	(2,544)		27.99
Forfeited	(87)		73.85	(116)		65.67
Outstanding at September 30 ⁽²⁾	8,579		56.96	7,924		52.46

Vested or Expected to Vest ⁽³⁾	8,336		56.28	7,685		51.70

Exercisable at September 30 ⁽⁴⁾	5,603		44.69	4,759		36.99

(1) The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2009 and 2008 was $12 million and $214 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, 2009 and 2008 was $236 million and $295 million, respectively. At September 30, 2009
      and 2008, the weighted average remaining contractual life was 4.3 years and 4.8 years, respectively.
(3) The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2009 and 2008 was $235 million and $292 million, respectively. At
      September 30, 2009 and 2008, the weighted average remaining contractual life was 4.3 years and 4.7 years, respectively.
(4) The total intrinsic value of stock options/SARs exercisable at September 30, 2009 and 2008 was $220 million and $250 million, respectively. At September 30, 2009
      and 2008, the weighted average remaining contractual life was 3.5 years and 4.1 years, respectively.

At September 30, 2009, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $85.8 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.9 years.

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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 $15.7 million and $20.6 million for the three months ended September 30, 2009 and 2008, respectively, and $45.1 million and $47.4 million for the nine months ended September 30, 2009 and 2008, respectively.

The following table sets forth the restricted stock and restricted stock unit transactions for the nine-month periods ended September 30, 2009 and 2008 (shares and units in thousands):

	Nine Months Ended			Nine Months Ended
	September 30, 2009			September 30, 2008
			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	3,048	$	70.24	3,000	$	50.61
Granted	1,184		62.88	788		106.88
Released ⁽¹⁾	(500)		28.16	(330)		20.97
Forfeited	(47)		78.06	(71)		69.04
Outstanding at September 30 ⁽²⁾	3,685		73.49	3,387		66.19

(1) The total intrinsic value of restricted stock and restricted stock units released for the nine months ended September 30, 2009 and 2008
      was $32 million and $33 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, 2009 and 2008 was $308 million and
      $303 million, respectively.

At September 30, 2009, unrecognized compensation expense related to non-vested restricted stock and restricted stock units totaled $149 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 3.2 years.

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3. Earnings Per Share

The following table sets forth the computation of Net Income Per Share Available to Common Stockholders for the three-month and nine-month periods ended September 30, 2009 and 2008 (in thousands, except per share data):

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2009		2008		2009		2008

Numerator for Basic and Diluted Earnings Per Share -
	Net Income	$	4,196	$	1,556,285	$	146,200	$	1,975,447
	Less: Preferred Stock Dividends		-		-		-		443
	Net Income Available to Common
	Stockholders	$	4,196	$	1,556,285	$	146,200	$	1,975,004

Denominator for Basic Earnings Per Share -
	Weighted Average Shares		249,535		247,155		248,647		246,343
Potential Dilutive Common Shares -
	Stock Options/SARs		1,718		2,409		1,558		2,927
	Restricted Stock and Restricted Stock Units		1,169		1,366		1,083		1,495
Denominator for Diluted Earnings Per Share -
	Adjusted Diluted Weighted Average Shares		252,422		250,930		251,288		250,765

Net Income Per Share Available to Common
Stockholders
	Basic	$	0.02	$	6.30	$	0.59	$	8.02
	Diluted	$	0.02	$	6.20	$	0.58	$	7.88

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. The excluded stock options and SARs totaled 2.4 million and 40,800 for the three months ended September 30, 2009 and 2008, respectively, and 2.5 million and 21,170 for the nine months ended September 30, 2009 and 2008, respectively.

4. Supplemental Cash Flow Information

Cash paid for interest and income taxes for the nine-month periods ended September 30, 2009 and 2008 was as follows (in thousands):

		Nine Months Ended
		September 30,
		2009		2008

Interest	$	54,179	$	46,309
Income Taxes, Net of Refunds Received	$	45,823	$	76,412

Non-cash investing and financing activities for the nine months ended September 30, 2009 included the issuance of 1,450,000 shares of EOG common stock valued at $89.6 million at the transaction closing date in connection with EOG's purchase of certain proved developed and undeveloped reserves and unproved acreage (see Note 14).

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5. Comprehensive Income

The following table presents the components of EOG's comprehensive income for the three-month and nine-month periods ended September 30, 2009 and 2008 (in thousands):

					Three Months Ended				Nine Months Ended
					September 30,				September 30,
					2009		2008		2009		2008

Comprehensive Income
	Net Income			$	4,196	$	1,556,285	$	146,200	$	1,975,447
	Other Comprehensive Income (Loss)
		Foreign Currency Translation Adjustments			161,044		(87,094)		260,007		(148,371)
		Foreign Currency Swap Transaction			504		(1,533)		5,470		(4,502)
		Income Tax Related to Foreign Currency
		Swap Transaction			(446)		392		(1,704)		1,137
		Defined Benefit Pension and
		Postretirement Plans			34		35		104		105
		Income Tax Related to Defined Benefit
		Pension and Postretirement Plans			(12)		(13)		(37)		(89)
			Total	$	165,320	$	1,468,072	$	410,040	$	1,823,727

6. Segment Information

Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, 2009 and 2008 (in thousands):

				Three Months Ended				Nine Months Ended
				September 30,				September 30,
				2009		2008		2009		2008

Net Operating Revenues
	United States		$	849,338	$	2,925,237	$	2,571,956	$	4,527,278
	Canada			92,678		206,237		283,722		591,752
	Trinidad			60,353		118,425		151,765		333,440
	Other International ⁽¹⁾			4,480		13,987		18,654		40,946
		Total	$	1,006,849	$	3,263,886	$	3,026,097	$	5,493,416

Operating Income (Loss)
	United States		$	26,971	$	2,196,363	$	282,601	$	2,491,392
	Canada			(18,883)		101,186		(27,281)		276,509
	Trinidad			38,370		95,946		89,640		248,507
	Other International ⁽¹⁾			(11,155)		(1,312)		(28,227)		(402)
		Total		35,303		2,392,183		316,733		3,016,006

Reconciling Items
	Other Income (Expense), Net			(339)		13,864		2,637		28,756
	Interest Expense, Net			30,407		12,095		73,594		33,315
		Income Before Income Taxes	$	4,557	$	2,393,952	$	245,776	$	3,011,447

(1) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.

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Total assets by reportable segment are presented below at September 30, 2009 and December 31, 2008 (in thousands):

				At		At
				September 30,		December 31,
				2009		2008
Total Assets
	United States		$	13,376,603	$	12,668,763
	Canada			2,803,808		2,421,979
	Trinidad			812,648		735,387
	Other International ⁽¹⁾			228,234		125,097
		Total	$	17,221,293	$	15,951,226

(1) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.

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, 2009 and 2008 (in thousands):

			Nine Months Ended
			September 30,
			2009		2008

Carrying Amount at Beginning of Period		$	368,159	$	211,124
	Liabilities Incurred		38,817		31,312
	Liabilities Settled		(13,701)		(18,734)
	Accretion		16,285		10,262
	Revisions ⁽¹⁾		13,827		131,098
	Foreign Currency Translations		10,462		(4,297)
Carrying Amount at End of Period		$	433,849	$	360,765

Current Portion		$	22,923	$	17,619
Noncurrent Portion		$	410,926	$	343,146

(1) Revisions to asset retirement obligations primarily reflect changes in abandonment cost estimates.

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.

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8. Suspended Well Costs

EOG's net changes in suspended well costs for the nine-month period ended September 30, 2009 are presented below (in thousands):

			Nine Months
			Ended
			September 30,
			2009

Balance at December 31, 2008		$	85,255
	Additions Pending the Determination of Proved Reserves		85,047
	Reclassifications to Proved Properties		(22,848)
	Charged to Dry Hole Costs		(11,503)
	Foreign Currency Translations		7,873
Balance at September 30, 2009		$	143,824

The following table provides an aging of suspended well costs at September 30, 2009 (in thousands, except well count):

			At
			September 30,
			2009

Capitalized exploratory well costs that have been
	capitalized for a period less than one year	$	77,811
Capitalized exploratory well costs that have been
	capitalized for a period greater than one year		66,013	⁽¹⁾
	Total	$	143,824
Number of exploratory wells that have been
	capitalized for a period greater than one year		4

(1) Consists of costs related to three shale projects in British Columbia, Canada (B.C.) ($44 million)
      and an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($22 million).
      In the B.C. shale projects, further reserve evaluations will be made based on drilling and completion
      activities during 2009 and 2010. In addition, EOG is evaluating infrastructure alternatives for the B.C.
      shale projects. In the Central North Sea project, the operator expects to receive approval in late 2010 of
      the field development plan submitted to the U.K. Department of Energy and Climate Change during
      the fourth quarter of 2008. EOG is currently focused on securing an export route for production from the
      Central North Sea project.

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 with certainty, 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.

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10. Pension and Postretirement Benefits

Pension Plans. 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. For the nine months ended September 30, 2009 and 2008, EOG's total costs recognized for these pension plans were $15.2 million and $14.4 million, respectively.

In addition, as more fully discussed in Note 6 to Consolidated Financial Statements in EOG's 2008 Annual Report, EOG's Canadian, Trinidadian and United Kingdom subsidiaries maintain various pension and savings plans for most of their respective employees. For the nine months ended September 30, 2009 and 2008, combined contributions to these pension and savings plans were $1.8 million and $1.9 million, respectively.

Postretirement Plan. EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents. For the nine months ended September 30, 2009, EOG's total contributions to these plans amounted to $97,000. The net periodic benefit costs recognized for these plans were $0.6 million and $0.5 million for the nine months ended September 30, 2009 and 2008, respectively.

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 or uncommitted credit facilities at September 30, 2009. The weighted average interest rates for commercial paper and uncommitted credit facility borrowings for the nine months ended September 30, 2009 were 0.98% and 1.07%, respectively.

On May 21, 2009, EOG completed its public offering of $900 million aggregate principal amount of 5.625% Senior Notes due 2019 (Notes). Interest on the Notes is payable semi-annually in arrears on June 1 and December 1 of each year, beginning December 1, 2009. Net proceeds from the offering of approximately $891 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings.

EOG currently has a $1.0 billion unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The Agreement matures on June 28, 2012. At September 30, 2009, there were no borrowings or letters of credit outstanding under the Agreement. Advances under the Agreement accrue interest based, at EOG's option, on either the London InterBank Offering Rate plus an applicable margin (Eurodollar rate) or the base rate of the Agreement's administrative agent. At September 30, 2009, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 0.44% and 3.25%, respectively.

On May 11, 2009, EOG Resources Trinidad Limited, a wholly owned foreign subsidiary of EOG, amended its 3-year, $75 million Revolving Credit Agreement (Credit Agreement) to extend the scheduled maturity date of the remaining outstanding balance of $37 million from May 12, 2009 to May 12, 2010. Borrowings under the Credit Agreement accrue interest based, at EOG's option, on either the Eurodollar rate or the base rate of the Credit Agreement's administrative agent. The applicable Eurodollar rate at September 30, 2009 was 2.75%. The weighted average Eurodollar rate for the amount outstanding during the first nine months of 2009 was 2.80%.

At September 30, 2009 and December 31, 2008, EOG had outstanding $2,797 million and $1,897 million, respectively, of long-term debt, which had estimated fair values of approximately $3,085 million and $1,933 million, respectively. The estimated fair value of long-term debt was based upon quoted market prices and, where such quotes were not available, upon interest rates available to EOG at period-end.

Common Stock. On February 4, 2009, EOG's Board of Directors increased the quarterly cash dividend on EOG's common stock from the previous $0.135 per share to $0.145 per share effective with the dividend paid on April 30, 2009 to record holders as of April 16, 2009.

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On October 7, 2009, EOG entered into an amendment (Amendment) to the Rights Agreement, dated as of February 14, 2000, as amended, by and between EOG and Computershare Trust Company, N.A., as the rights agent (Rights Agreement). The Amendment modifies the definition of "Qualified Institutional Investor" set forth in Section 1 of the Rights Agreement, specifically to delete from clause (A) of the exception to such definition the requirement that a person shall, subsequent to December 31, 2004, continuously beneficially own greater than five percent of the outstanding shares of EOG's common stock prior to the time of determination of such person's "Qualified Institutional Investor" status. Under the Rights Agreement, a person described in Rule 13d-l(b)(1) promulgated under the Securities Exchange Act of 1934 who is eligible to report beneficial ownership of EOG's common stock on Schedule 13G and who beneficially owns 15% or greater of EOG's outstanding common stock will nevertheless be deemed to be a "Qualified Institutional Investor" (and thus not an "Acquiring Person" which would trigger the protections of the Rights Agreement) if such person satisfies the amended exception to the "Qualified Institutional Investor" definition, including the requirement that such person beneficially own less than 30% of EOG's outstanding common stock.

12. Fair Value Measurements

Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the accompanying Consolidated Balance Sheets. Effective January 1, 2008, EOG adopted the provisions of the Fair Value Measurements and Disclosures Topic of the ASC (ASC Topic 820) for its financial assets and liabilities. ASC Topic 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted pr ices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. ASC Topic 820 requires that an entity give consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value. EOG adopted the provisions of ASC Topic 820 relating to nonfinancial assets and liabilities effective January 1, 2009.

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The following table provides fair value measurement information within the hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at September 30, 2009 and December 31, 2008 (in millions):

			Fair Value Measurements Using:
			Quoted		Significant
			Prices in		Other		Significant
			Active		Observable		Unobservable
			Markets		Inputs		Inputs
			(Level 1)		(Level 2)		(Level 3)
At September 30, 2009
Financial Assets:
	Natural gas collars, price swaps
	and basis swaps	$	-	$	290	$	-

Financial Liabilities:
	Natural gas collars, price swaps
	and basis swaps	$	-	$	41	$	-
	Foreign currency rate swap	$	-	$	46	$	-

At December 31, 2008
Financial Assets:
	Natural gas collars, price swaps
	and basis swaps	$	-	$	836	$	-

Financial Liabilities:
	Natural gas collars, price swaps
	and basis swaps	$	-	$	12	$	-
	Foreign currency rate swap	$	-	$	26	$	-

The estimated fair value of natural gas collar, price swap and basis swap contracts was based upon forward commodity price curves based on quoted market prices. The estimated fair value of the foreign currency rate swap 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 internal estimates of future retirement costs associated with oil and gas properties. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 7.

Proved oil and gas properties with a carrying amount of $50 million were written down to their fair value of $11 million, resulting in a pretax impairment charge of $39 million for the nine months ended September 30, 2009. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future natural gas and crude oil prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

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13. Risk Management Activities

Effective January 1, 2009, EOG adopted the expanded disclosure provisions of the Derivatives and Hedging Topic of the ASC. The new provisions require expanded disclosure about an entity's use of derivative instruments and hedging activities and the impact of those instruments on the consolidated financial statements. Information concerning EOG's derivative instruments and hedging activities is presented below.

Commodity Price Risk. As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2008 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 natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collar, price swap 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 (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income. The related cash flow impac t is reflected as Cash Flows from Operating Activities. In addition to financial transactions, from time to time, 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.

Foreign Currency Exchange Rate Risk. As more fully described in Note 2 to the Consolidated Financial Statements included in EOG's 2008 Annual Report, EOG is party to a foreign currency swap transaction 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 transaction using the hedge accounting method, pursuant to the provisions of the Derivatives and Hedging Topic of the ASC. Changes in the fair value of the foreign currency swap do not impact Net Income Available to Common Stockholders. The after-tax net impact of the foreign currency swap transaction was an increase in Other Comprehensive Income of $58,000 and a reduction in Other Comprehensive Income of $1.1 million for the three months ended September 30, 2009 and 2008, respectively, and a $3.8 million increase in Other Comprehensive Income and a $3.4 million reduction in Other Comprehensive Income for the nine months ended September 30, 2009 and 2008, respectively (see Note 5).

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The following table sets forth the amount, on a gross basis, and classification of EOG's outstanding derivative financial instruments at September 30, 2009 and December 31, 2008. Certain amounts may be presented on a net basis in the consolidated financial statements in accordance with master netting arrangements between EOG and the counter-parties to the transactions (in millions):

					Fair Value at
					September 30,		December 31,
Description			Location on Balance Sheet		2009		2008

Asset Derivatives
	Natural gas collars and price swaps -
		Current portion	Assets from Price Risk
			Management Activities	$	324	$	786
		Noncurrent portion	Other Assets	$	-	$	63

Liability Derivatives
	Natural gas basis swaps -
		Current portion	Liabilities from Price Risk
			Management Activities	$	50	$	11
		Noncurrent portion	Other Liabilities	$	25	$	14

	Foreign currency rate swaps -
		Noncurrent portion	Other Liabilities	$	46	$	26

EOG recognized a net gain on the mark-to-market of financial commodity derivative contracts of $406 million and $69 million for the nine months ended September 30, 2009 and 2008, respectively.

Financial Collar Contracts. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at September 30, 2009. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/MMBtu). The average floor price of EOG's outstanding natural gas financial collar contracts for 2010 was $10.33 per million British thermal units (MMBtu) and the average ceiling price was $12.63 per MMBtu.

Natural Gas Financial Collar Contracts
		Floor Price		Ceiling Price
			Weighted		Weighted
	Volume	Floor Range	Average Price	Ceiling Range	Average Price
	(MMBtud)	($/MMBtu)	($/MMBtu)	($/MMBtu)	($/MMBtu)
2010
January	40,000	$11.44 - 11.47	$11.45	$13.79 - 13.90	$13.85
February	40,000	11.38 - 11.41	11.40	13.75 - 13.85	13.80
March	40,000	11.13 - 11.15	11.14	13.50 - 13.60	13.55
April	40,000	9.40 - 9.45	9.42	11.55 - 11.65	11.60
May	40,000	9.24 - 9.29	9.26	11.41 - 11.55	11.48
June	40,000	9.31 - 9.36	9.34	11.49 - 11.60	11.55

On April 29, 2009, EOG settled its natural gas financial collar contracts with notional volumes of 40,000 MMBtud for the July 1, 2010 - December 31, 2010 period and received proceeds of $26.5 million.

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Financial Price Swap Contracts. Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at September 30, 2009. The notional volumes are expressed in MMBtud and prices are expressed in $/MMBtu. The average price of EOG's outstanding natural gas financial price swap contracts for 2009 was $9.83 per MMBtu and for 2010 was $10.14 per MMBtu.

Natural Gas Financial Price Swap Contracts
		Weighted
	Volume	Average Price
	(MMBtud)	($/MMBtu)
2009
January (closed)	585,000	$10.76
February (closed)	585,000	10.73
March (closed)	585,000	10.50
April (closed)	610,000	9.24
May (closed)	610,000	9.16
June (closed)	710,000	8.53
July (closed)	710,000	8.62
August (closed)	710,000	8.67
September (closed)	710,000	8.69
October (closed)	710,000	8.76
November	610,000	9.66
December	610,000	9.99

2010
January	20,000	$11.20
February	20,000	11.15
March	20,000	10.89
April	20,000	9.29
May	20,000	9.13
June	20,000	9.21

On April 24, 2009, EOG settled its natural gas financial price swap contracts with notional volumes of 20,000 MMBtud for the July 1, 2010 - December 31, 2010 period and received proceeds of $12.1 million.

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Financial Basis Swap Contracts. Prices received by EOG for its natural gas production generally vary from New York Mercantile Exchange (NYMEX) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas financial basis swap contracts in order to fix the differential between prices in the Rocky Mountain area and NYMEX Henry Hub prices. Presented below is a comprehensive summary of EOG's natural gas financial basis swap contracts at September 30, 2009. The weighted average price differential represents the amount of reduction to NYMEX gas prices per MMBtu for the notional volumes covered by the basis swap. Notional volumes are expressed in MMBtud and price differentials are expressed in $/MMBtu.

Natural Gas Financial Basis Swap Contracts
		Weighted
		Average Price
	Volume	Differential
	(MMBtud)	($/MMBtu)
2009
Second Quarter (closed)	65,000	$(2.54)
Third Quarter (closed)	65,000	(2.60)
Fourth Quarter ⁽¹⁾	65,000	(3.03)

2010
First Quarter	65,000	$(1.72)
Second Quarter	65,000	(2.56)
Third Quarter	65,000	(3.17)
Fourth Quarter	65,000	(3.73)

2011
First Quarter	65,000	$(1.89)

(1) Includes closed contracts for October 2009.

Credit Risk. Notional contract amounts are used to express the magnitude of commodity price and foreign currency swap agreements. The amounts potentially subject to credit risk, in the event of nonperformance by EOG's counterparties, are equal to the fair value of such contracts. EOG evaluates its exposure to significant counterparties on an ongoing basis, including those 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 (ISDA) Master Agreements 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 ISDA may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDA to be settled immediately. See Note 12 for the aggregate fair value of all derivative instruments with credit-risk related contingent features that are in a net liability position at September 30, 2009 and December 31, 2008. EOG had zero collateral posted at both September 30, 2009 and December 31, 2008.

14. Acquisitions

During the third quarter of 2009, EOG completed three transactions to acquire certain crude oil and natural gas properties and related assets located in Montague and Cooke Counties, Texas (Barnett Shale Combo Assets). The Barnett Shale Combo Assets consist of proved developed and undeveloped reserves and unproved acreage. The aggregate purchase price of the transactions, which is subject to customary post-closing adjustments, totaled $196.7 million, consisting of cash consideration of $107.1 million and 1,450,000 shares of EOG common stock valued at $89.6 million at the closing date of the applicable transaction.

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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) 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 achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.

United States and Canada. EOG's effort to identify plays with larger 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 natural gas and crude oil production. Production in the United States and Canada accounted for approximately 86% of total company production in the first nine months of both 2009 and 2008. One of EOG's exploration strategies is to apply its horizontal drilling expertise gained in natural gas resource plays to unconventional oil reservoirs. During the first nine months of 2009, the Fort Worth Basin Barnett Shale and North Dakota Bakken areas produced an increasing amount of crude oil and natural gas liquids as compared to the comparable period in 2008. For the first nine months of 2009, crude oil and natural gas liquids production accounted for approximately 22% of total company production as compared to approximately 18% for the comparable period in 2008. Based on current trends, EOG expects its 2009 crude oil and natural gas liquids production to continue to increase as compared to 2008. EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

During the third quarter of 2009, EOG completed three transactions to acquire certain crude oil and natural gas properties and related assets located in Montague and Cooke Counties, Texas (Barnett Shale Combo Assets). The Barnett Shale Combo Assets consist of proved developed and undeveloped reserves and approximately 33,000 net unproved acres. Production from these assets averaged approximately 2,300 barrels equivalent per day, net, at the time of acquisition. The aggregate purchase price of the transactions, which is subject to customary post-closing adjustments, totaled $196.7 million, consisting of cash consideration of $107.1 million and 1,450,000 shares of EOG common stock valued at $89.6 million at the closing date of the applicable transaction.

International. In the United Kingdom, EOG completed a farm-in agreement with owners of the Central North Sea Block 15/30a Area AB during the third quarter of 2009. An exploratory well, which EOG will operate with a 65% working interest, is planned for the fourth quarter of 2009. Subsequent to its June 2009 oil discovery in the East Irish Sea Block 110/12, EOG plans to drill two additional exploratory wells during the fourth quarter of 2009 and first quarter of 2010. EOG has a 100% working interest in this Block. In the Sichuan Basin, Sichuan Province, The People's Republic of China, EOG drilled a horizontal well in the third quarter of 2009 and plans to complete and test this well during the fourth quarter of 2009 and first quarter of 2010. In addition, to evaluate a different zone, EOG began drilling a second monitoring well during the third quarter of 2009 and plans to begin a second horizontal well in the fourth quarter of 2009.

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

- -22-

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. At September 30, 2009, EOG's debt-to-total capitalization ratio was 23% as compared to 17% at December 31, 2008. On May 21, 2009, EOG completed its public offering of $900 million aggregate principal amount of 5.625% Senior Notes due 2019 (Notes). Interest on the Notes is payable semi-annually in arrears on June 1 and December 1 of each year, beginning December 1, 2009. Net proceeds from the offering of approximately $891 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings. During the first nine months of 2009, EOG funded $2.7 billion in exploration and development and other property, plant and equipment expenditures (including $206 million of acquisitions) and paid $106 million in dividends to common s tockholders, primarily by utilizing cash provided from its operating activities, proceeds from commercial paper and uncommitted credit facility borrowings and proceeds from the offering of the Notes.

For 2009, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.7 billion, including acquisitions of approximately $300 million. United States and Canada natural gas and crude oil drilling activity continues to be a key component of these expenditures. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG 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, 2009 and 2008 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, 2009 vs. Three Months Ended September 30, 2008

Net Operating Revenues. During the third quarter of 2009, net operating revenues decreased $2,257 million, or 69%, to $1,007 million from $3,264 million for the same period of 2008. Total wellhead revenues for the third quarter of 2009, which are revenues generated from sales of natural gas, crude oil and condensate and natural gas liquids, decreased $985 million, or 54%, to $849 million from $1,834 million for the same period of 2008. During the third quarter of 2009, EOG recognized a net gain on mark-to-market commodity derivative contracts of $21 million compared to a net gain of $1,382 million for the same period of 2008. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party natural gas, crude oil and natural gas liquids as well as gathering fees associated with gathering third-party natural gas, for the third quarter of 2009 increased $84 million, or 163%, to $135 million from $51 million for the same period of 2008.

-23-

Wellhead volume and price statistics for the three-month periods ended September 30, 2009 and 2008 were as follows:

				Three Months Ended
				September 30,
				2009		2008
Natural Gas Volumes (MMcfd) ⁽¹⁾
	United States			1,128		1,196
	Canada			219		224
	Trinidad			268		240
	Other International ⁽²⁾			13		19
		Total		1,628		1,679

Average Natural Gas Prices ($/Mcf) ⁽³⁾
	United States		$	3.27	$	8.99
	Canada			3.15		8.15
	Trinidad			1.77		4.04
	Other International ⁽²⁾			3.53		7.41
		Composite		3.01		8.15

Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
	United States			51.7		41.8
	Canada			4.7		3.0
	Trinidad			3.0		3.4
	Other International ⁽²⁾			0.1		0.1
		Total		59.5		48.3

Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
	United States		$	60.79	$	109.86
	Canada			61.43		109.71
	Trinidad			57.07		111.39
	Other International ⁽²⁾			57.93		112.77
		Composite		60.65		109.96

Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
	United States			23.1		13.2
	Canada			1.0		1.1
		Total		24.1		14.3

Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
	United States		$	31.15	$	69.79
	Canada			30.96		64.01
		Composite		31.14		69.33

Natural Gas Equivalent Volumes (MMcfed) ⁽⁴⁾
	United States			1,577		1,525
	Canada			253		249
	Trinidad			286		261
	Other International ⁽²⁾			13		20
		Total		2,129		2,055

Total Bcfe ⁽⁴⁾				195.9		189.1

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.
(3) Dollars per thousand cubic feet or per barrel, as applicable.
(4) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural
gas liquids. Natural gas equivalents are determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil, condensate
or natural gas liquids.

-24-

Wellhead natural gas revenues for the third quarter of 2009 decreased $809 million, or 64%, to $450 million from $1,259 million for the same period of 2008. The decrease was due to a lower composite average wellhead natural gas price ($770 million) and decreased natural gas deliveries ($39 million). EOG's composite average wellhead natural gas price decreased 63% to $3.01 per thousand cubic feet (Mcf) for the third quarter of 2009 from $8.15 per Mcf for the same period of 2008.

Natural gas deliveries for the third quarter of 2009 decreased 51 MMcfd, or 3%, to 1,628 MMcfd from 1,679 MMcfd for the same period of 2008. The decrease was primarily due to lower production in the United States (68 MMcfd), Canada (5 MMcfd) and the United Kingdom (5 MMcfd), partially offset by increased production in Trinidad (28 MMcfd). The decrease in the United States was primarily attributable to decreased production in Texas (50 MMcfd), the Rocky Mountain area (14 MMcfd), New Mexico (8 MMcfd), Kansas (5 MMcfd) and Mississippi (3 MMcfd), partially offset by increased production in Louisiana (14 MMcfd). The decrease in the United Kingdom primarily resulted from reduced production in the Arthur field. The increase in Trinidad was primarily due to increased net contractual deliveries.

Wellhead crude oil and condensate revenues for the third quarter of 2009 decreased $153 million, or 32%, to $330 million from $483 million for the same period of 2008, due to a lower composite average wellhead crude oil and condensate price ($268 million), partially offset by an increase of 11 MBbld, or 23%, in wellhead crude oil and condensate deliveries ($115 million). The increase in deliveries primarily reflects increased production in North Dakota (9 MBbld), Texas (2 MBbld) and Canada (2 MBbld). The composite average wellhead crude oil and condensate price for the third quarter of 2009 decreased 45% to $60.65 per barrel compared to $109.96 per barrel for the same period of 2008.

Natural gas liquids revenues for the third quarter of 2009 decreased $22 million, or 24%, to $69 million from $91 million for the same period of 2008, due to a lower composite average price ($84 million), partially offset by an increase of 10 MBbld, or 69%, in natural gas liquids deliveries ($62 million). The composite average natural gas liquids price for the third quarter of 2009 decreased 55% to $31.14 per barrel compared to $69.33 per barrel for the same period of 2008. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area (6 MBbld) and the Mid-Continent area (2 MBbld).

During the third quarter of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $21 million compared to a net gain of $1,382 million for the same period of 2008. During the third quarter of 2009, the net cash inflow related to settled natural gas financial collar, price swap and basis swap contracts was $331 million compared to the net cash outflow related to settled natural gas and crude oil financial price swap contracts of $122 million for the same period of 2008.

Gathering, processing and marketing revenues represent sales of third-party natural gas, crude oil and natural gas liquids as well as gathering fees associated with gathering third-party natural gas. During the three months ended September 30, 2009 and 2008, substantially all of such revenues were related to sales of third-party natural gas and crude oil. Marketing costs represent the costs of purchasing third-party natural gas and crude oil and the associated transportation costs.

Gathering, processing and marketing revenues less marketing costs for the third quarter of 2009 decreased $4 million to $3 million compared to $7 million for the same period of 2008, reflecting lower margins associated with natural gas marketing activities.

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Operating and Other Expenses. For the third quarter of 2009, operating expenses of $972 million were $100 million higher than the $872 million incurred in the third quarter of 2008. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the three-month periods ended September 30, 2009 and 2008:

				Three Months Ended
				September 30,
				2009		2008

Lease and Well			$	0.73	$	0.75
Transportation Costs				0.36		0.41
Depreciation, Depletion and Amortization (DD&A) -
		Oil and Gas Properties		1.84		1.73
		Other Property, Plant and Equipment		0.13		0.10
General and Administrative (G&A)				0.32		0.38
Interest Expense, Net				0.16		0.06
	Total ⁽¹⁾		$	3.54	$	3.43

(1) 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 three months ended September 30, 2009 compared to the same period of 2008 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 natural gas and crude oil wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance expenses include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are costs of operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuate 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 costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses were $142 million for the third quarter of both 2009 and 2008. During 2009, increased operating and maintenance expenses in Canada ($5 million) and China ($1 million) and increased lease and well administrative expenses in Canada ($1 million) were offset by decreased lease and well administrative expenses in the United States ($3 million), decreased operating and maintenance expenses in the United States ($2 million) and changes in the Canadian exchange rate ($2 million).

Transportation costs represent costs incurred directly by EOG from third-party carriers 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 and transportation fees.

Transportation costs of $71 million for the third quarter of 2009 decreased $7 million from $78 million for the same prior year period primarily due to decreased costs associated with marketing arrangements to transport production from the Fort Worth Basin Barnett Shale area ($10 million) to downstream markets, partially offset by increased costs associated with marketing arrangements to transport production from the Rocky Mountain area ($5 million) 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 consist of natural gas gathering and processing facilities, compressors, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

DD&A expenses for the third quarter of 2009 increased $39 million to $385 million from $346 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2009 were $32 million higher than the same prior year period primarily due to higher unit rates in the United States ($18 million), Trinidad ($3 million) and Canada ($3 million) and as a result of increased production in the United States ($9 million), partially offset by changes in the Canadian exchange rate ($3 million).

DD&A expenses associated with other property, plant and equipment for the third quarter of 2009 were $7 million higher than the same prior year period primarily due to increased expenditures associated with natural gas gathering systems and processing plants in the Fort Worth Basin Barnett Shale area ($3 million) and Rocky Mountain area ($3 million).

G&A expenses of $63 million for the third quarter of 2009 decreased $8 million from the same prior year period primarily due to lower employee-related costs.

Interest expense, net of $30 million for the third quarter of 2009 increased $18 million compared to the same prior year period primarily due to a higher average debt balance ($20 million), partially offset by higher capitalized interest ($2 million).

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

Gathering and processing costs for the third quarter of 2009 increased $4 million to $13 million as compared to the same prior year period primarily due to increased activities in the Rocky Mountain area.

Exploration costs of $45 million for the third quarter of 2009 increased $7 million from the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($4 million) and the United Kingdom ($2 million).

Impairments include amortization and impairments of unproved oil and gas properties, as well as impairments of proved oil and gas properties. Unproved properties with individually significant acquisition costs are assessed on a property-by-property basis, and any impairment in value is recognized. 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 average holding period. 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 calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

Impairments of $69 million for the third quarter of 2009 increased $37 million from $32 million for the same prior year period primarily due to increased amortization and impairments of unproved properties in the United States ($28 million) and increased impairments of proved properties in the United States ($8 million). EOG recorded impairments of proved properties of $15 million and $7 million for the third quarter of 2009 and 2008, respectively.

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

-27-

Taxes other than income for the third quarter of 2009 decreased $50 million to $48 million (5.6% of wellhead revenues) from $98 million (5.3% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to a decrease in severance/production taxes as a result of decreased wellhead revenues in the United States ($33 million) and Trinidad ($4 million) and an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions ($12 million).

Other income (expense), net for the third quarter of 2009 decreased $14 million from the same prior year period. The decrease was primarily due to lower equity income from ammonia plants in Trinidad ($7 million) and lower interest income ($3 million).

EOG recognized an income tax provision of less than $1 million for the third quarter of 2009 compared to $838 million for the same prior year period. The change was primarily due to decreased pretax income. The net effective tax rate for the third quarter of 2009 decreased to 8% from 35% for the same prior year period due primarily to lower pretax income and lower Canadian taxes.

Nine Months Ended September 30, 2009 vs. Nine Months Ended September 30, 2008

Net Operating Revenues. During the first nine months of 2009, net operating revenues decreased $2,467 million, or 45%, to $3,026 million from $5,493 million for the same period of 2008. Total wellhead revenues for the first nine months of 2009 decreased $2,767 million, or 54%, to $2,364 million from $5,131 million for the same period of 2008. During the first nine months of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $406 million compared to a net gain of $69 million for the same period of 2008. Gathering, processing and marketing revenues for the first nine months of 2009 increased $99 million, or 66%, to $250 million from $151 million for the same period of 2008. Other, net operating revenues in 2008 primarily consist of a gain of $128 million on the sale of EOG's Appalachian assets in February 2008.

-28-

Wellhead volume and price statistics for the nine-month periods ended September 30, 2009 and 2008 were as follows:

				Nine Months Ended
				September 30,
				2009		2008
Natural Gas Volumes (MMcfd)
	United States			1,153		1,141
	Canada			224		218
	Trinidad			266		229
	Other International			15		16
		Total		1,658		1,604

Average Natural Gas Prices ($/Mcf)
	United States		$	3.57	$	9.15
	Canada			3.67		8.33
	Trinidad			1.54		3.86
	Other International			4.45		8.90
		Composite		3.27		8.28

Crude Oil and Condensate Volumes (MBbld)
	United States			46.5		35.9
	Canada			3.6		2.7
	Trinidad			3.0		3.4
	Other International			0.1		0.1
		Total		53.2		42.1

Average Crude Oil and Condensate Prices ($/Bbl)
	United States		$	49.54	$	107.36
	Canada			51.91		104.57
	Trinidad			46.13		103.80
	Other International			50.11		104.66
		Composite		49.51		106.89

Natural Gas Liquids Volumes (MBbld)
	United States			22.2		14.7
	Canada			1.1		1.0
		Total		23.3		15.7

Average Natural Gas Liquids Prices ($/Bbl)
	United States		$	26.42	$	63.08
	Canada			27.29		62.45
		Composite		26.46		63.04

Natural Gas Equivalent Volumes (MMcfed)
	United States			1,566		1,445
	Canada			252		240
	Trinidad			284		250
	Other International			15		16
		Total		2,117		1,951

Total Bcfe				578.1		534.5

-29-

Wellhead natural gas revenues for the first nine months of 2009 decreased $2,159 million, or 59%, to $1,478 million from $3,637 million for the same period of 2008. The decrease was due to a lower composite average wellhead natural gas price ($2,268 million), partially offset by increased natural gas deliveries ($109 million). EOG's composite average wellhead natural gas price decreased 61% to $3.27 per Mcf for the first nine months of 2009 from $8.28 per Mcf for the same period of 2008.

Natural gas deliveries for the first nine months of 2009 increased 54 MMcfd, or 3%, to 1,658 MMcfd from 1,604 MMcfd for the same period of 2008. The increase was due to higher production in Trinidad (37 MMcfd), the United States (12 MMcfd) and Canada (6 MMcfd). The increase in Trinidad was primarily due to increased net contractual deliveries and reduced plant shutdowns for maintenance during 2009. The increase in the United States was primarily attributable to increased production in the Rocky Mountain area (15 MMcfd), Texas (12 MMcfd) and Louisiana (6 MMcfd), partially offset by decreased production in Mississippi (7 MMcfd), New Mexico (5 MMcfd), Oklahoma (3 MMcfd), Kansas (3 MMcfd) and as a result of the February 2008 sale of EOG's Appalachian assets (3 MMcfd). The increase in Canada was primarily attributable to British Columbia Horn River Basin production.

Wellhead crude oil and condensate revenues for the first nine months of 2009 decreased $505 million, or 41%, to $718 million from $1,223 million for the same period of 2008, due to a lower composite average wellhead crude oil and condensate price ($832 million), partially offset by an increase of 11 MBbld, or 26%, in wellhead crude oil and condensate deliveries ($327 million). The increase in deliveries primarily reflects increased production in North Dakota (9 MBbld) and Texas (2 MBbld). The composite average wellhead crude oil and condensate price for the first nine months of 2009 decreased 54% to $49.51 per barrel compared to $106.89 per barrel for the same period of 2008.

Natural gas liquids revenues for the first nine months of 2009 decreased $103 million, or 38%, to $168 million from $271 million for the same period of 2008, due to a lower composite average price ($233 million), partially offset by an increase of 8 MBbld, or 48%, in natural gas liquids deliveries ($130 million). The composite average natural gas liquids price for the first nine months of 2009 decreased 58% to $26.46 per barrel compared to $63.04 per barrel for the same period of 2008. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area.

During the first nine months of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $406 million compared to a net gain of $69 million for the same period of 2008. During the first nine months of 2009, the net cash inflow related to settled natural gas financial collar, price swap and basis swap contracts was $987 million compared to a net cash outflow related to settled natural gas and crude oil financial price swap contracts of $237 million for the same period of 2008.

Gathering, processing and marketing revenues less marketing costs for the first nine months of 2009 increased $1 million to $12 million compared to the same prior year period of 2008. The increase resulted primarily from increased natural gas marketing operations in the Gulf Coast area.

-30-

Operating and Other Expenses. For the first nine months of 2009, operating expenses of $2,709

million were $232 million higher than the $2,477 million incurred in the same period of 2008. The following table presents the costs per Mcfe for the nine-month periods ended September 30, 2009 and 2008:

			Nine Months Ended
			September 30,
			2009		2008

Lease and Well		$	0.73	$	0.74
Transportation Costs			0.36		0.38
DD&A -
	Oil and Gas Properties		1.87		1.71
	Other Property, Plant and Equipment		0.12		0.09
G&A			0.31		0.35
Interest Expense, Net			0.13		0.06
	Total ⁽¹⁾	$	3.52	$	3.33

(1) 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, 2009 compared to the same period of 2008 are set forth below.

Lease and well expenses of $422 million for the first nine months of 2009 increased $26 million from $396 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($25 million), Canada ($11 million) and China ($3 million), partially offset by changes in the Canadian exchange rate ($13 million).

Transportation costs of $206 million for the first nine months of 2009 increased $3 million from $203 million for the same prior year period primarily due to increased transportation costs in the United States ($4 million) and Trinidad ($1 million), partially offset by decreased transportation costs in the United Kingdom ($1 million) and Canada ($1 million). The increased transportation costs in the United States were primarily due to increased transportation costs in the Rocky Mountain area ($11 million), partially offset by decreased transportation costs in the Fort Worth Basin Barnett Shale area ($4 million).

DD&A expenses for the first nine months of 2009 increased $191 million to $1,150 million from $959 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2009 were $166 million higher than the same prior year period primarily due to higher unit rates in the United States ($92 million), Canada ($11 million), Trinidad ($10 million) and China ($3 million) and increased production in the United States ($60 million), Canada ($6 million) and in Trinidad ($2 million), partially offset by changes in the Canadian exchange rate ($21 million).

DD&A expenses associated with other property, plant and equipment for the first nine months of 2009 were $25 million higher than the same prior year period primarily due to increased expenditures associated with natural gas gathering systems and processing plants in the Fort Worth Basin Barnett Shale area ($11 million) and Rocky Mountain area ($7 million).

G&A expenses of $179 million for the first nine months of 2009 decreased $6 million from the same prior year period primarily due to lower employee-related costs.

Interest expense, net of $74 million for the first nine months of 2009 increased $40 million compared to the same prior year period primarily due to a higher average debt balance ($48 million), partially offset by higher capitalized interest ($8 million).

-31-

Gathering and processing costs for the first nine months of 2009 increased $18 million to $45 million as compared to the same prior year period primarily due to increased activities in the Rocky Mountain area ($11 million) and the Fort Worth Basin Barnett Shale area ($6 million).

Exploration costs of $129 million for the first nine months of 2009 decreased $17 million compared to the same prior year period primarily due to decreased geological and geophysical expenditures in the United States.

Impairments of $182 million for the first nine months of 2009 increased $68 million compared to the same prior year period primarily due to increased amortization and impairments of unproved properties in the United States ($69 million) and increased impairments of proved properties in the United States ($20 million), partially offset by an impairment in Trinidad recorded in the second quarter of 2008 as a result of EOG's relinquishment of its rights to Block Lower Reverse "L" (LRL) ($20 million). EOG recorded impairments of proved properties of $39 million and $40 million for the nine months ended September 30, 2009 and 2008, respectively.

Taxes other than income for the first nine months of 2009 decreased $161 million to $119 million (5.0% of wellhead revenues) from $280 million (5.5% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to decreased severance/production taxes primarily as a result of decreased wellhead revenues in the United States ($103 million) and Trinidad ($16 million), an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions ($32 million) and lower ad valorem/property taxes in the United States ($13 million), partially offset by an increase in franchise taxes in the United States ($5 million). The decline in taxes other than income as a percentage of wellhead revenues primarily reflects an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions combined with a decline in non-revenue based taxes.

Other income (expense), net was $3 million for the first nine months of 2009 compared to $29 million for the same prior year period. The decrease of $26 million was primarily due to lower equity income from ammonia plants in Trinidad ($17 million), lower interest income ($6 million) and settlements received related to the Enron Corp. bankruptcy in the second quarter of 2008 ($2 million), partially offset by increased foreign currency transaction gains ($5 million).

Income tax provision of $100 million for the first nine months of 2009 decreased $936 million compared to $1,036 million for the same prior year period due primarily to decreased pretax income ($968 million), partially offset by higher foreign taxes ($28 million). The net effective tax rate for the first nine months of 2009 increased to 41% from 34% for the same prior year period primarily as a result of higher state and foreign tax rates and the absence of 2008 tax benefits related to the impairment of LRL.

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2009 were funds generated from operations, net commercial paper and uncommitted credit facility borrowings and proceeds from the offering of the Notes. 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 2009, EOG's cash balance increased $278 million to $609 million from $331 million at December 31, 2008.

Net cash provided by operating activities of $2,094 million for the first nine months of 2009 decreased $1,506 million compared to the same period of 2008 primarily reflecting a decrease in wellhead revenues ($2,767 million), unfavorable changes in working capital and other assets and liabilities ($62 million) and an increase in cash paid for interest expense ($8 million), partially offset by a favorable change in net cash flow from the settlement of financial commodity derivative contracts ($1,224 million), a decrease in cash operating expenses ($137 million) and a decrease in net cash paid for income taxes ($31 million).

-32-

Net cash used in investing activities of $2,651 million for the first nine months of 2009 decreased by $848 million compared to the same period of 2008 due primarily to a decrease in additions to oil and gas properties ($1,264 million) and a decrease in additions to other property, plant and equipment ($80 million), partially offset by a decrease in proceeds from sales of assets ($367 million), primarily reflecting net proceeds from the sale of EOG's Appalachian assets in February 2008, and unfavorable changes in working capital associated with investing activities ($132 million).

Net cash provided by financing activities was $823 million for the first nine months of 2009 compared to $745 million for the same period of 2008. Cash provided by financing activities for the first nine months of 2009 included the proceeds from the offering of the Notes ($900 million), excess tax benefits from stock-based compensation ($34 million) and proceeds from stock options exercised and employee stock purchase plan activity ($14 million). Cash used by financing activities for the first nine months of 2009 included cash dividend payments ($106 million), the purchase of treasury stock ($10 million) and debt issuance costs ($9 million).

Total Expenditures. For 2009, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.7 billion, including acquisitions of approximately $300 million. The table below sets out components of total expenditures for the nine-month periods ended September 30, 2009 and 2008 (in millions):

				Nine Months Ended
				September 30,
				2009		2008
Expenditure Category
Capital
		Drilling and Facilities	$	1,780	$	2,988
		Leasehold Acquisitions		293		377
		Property Acquisitions		206		109
		Capitalized Interest		38		30
		Subtotal		2,317		3,504
Exploration Costs				129		145
Dry Hole Costs				40		28
	Exploration and Development Expenditures			2,486		3,677
Asset Retirement Costs				53		164
	Total Exploration and Development Expenditures			2,539		3,841
Other Property, Plant and Equipment				241		321
	Total Expenditures		$	2,780	$	4,162

Exploration and development expenditures of $2,486 million for the first nine months of 2009 were $1,191 million lower than the same period of 2008 due primarily to decreased drilling and facilities expenditures in the United States ($1,150 million), Trinidad ($42 million) and Canada ($29 million), decreased leasehold acquisition expenditures in Canada ($105 million), changes in the foreign currency exchange rate in Canada ($27 million) and the United Kingdom ($5 million), decreased geological and geophysical expenditures in the United States ($17 million) and decreased property acquisition expenditures in Trinidad ($15 million) and Canada ($14 million). These decreases were partially offset by increased property acquisition expenditures in the United States ($136 million), increased leasehold acquisition expenditures in the United States ($27 million), increased drilling and facilities expenditures in China ($24 million) and the United Kingdom ($14 million), increased capitalized int erest in the United States ($10 million) and increased dry hole costs in the United Kingdom ($9 million) and the United States ($8 million). The exploration and development expenditures for the first nine months of 2009 of $2,486 million included $1,589 million in development, $653 million in exploration, $206 million in property acquisitions and $38 million in capitalized interest. The exploration and development expenditures for the first nine months of 2008 of $3,677 million included $2,722 million in development, $816 million in exploration, $109 million in property acquisitions and $30 million in capitalized interest.

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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 operations in the United States, Canada, Trinidad, the United Kingdom and China, 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, 2008, filed on February 25, 2009, 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 natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collar, price swap 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 (Losses) on Mark-to-Market Comm odity 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, from time to time, 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.

Financial Collar Contracts. The total fair value of EOG's natural gas financial collar contracts at September 30, 2009 was a positive $32 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at November 5, 2009. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/MMBtu). The average floor price of EOG's outstanding natural gas financial collar contracts for 2010 is $10.33 per million British thermal units (MMBtu) and the average ceiling price is $12.63 per MMBtu.

Natural Gas Financial Collar Contracts
		Floor Price		Ceiling Price
			Weighted	Ceiling	Weighted
	Volume	Floor Range	Average Price	Range	Average Price
	(MMBtud)	($/MMBtu)	($/MMBtu)	($/MMBtu)	($/MMBtu)
2010
January	40,000	$11.44 - 11.47	$11.45	$13.79 - 13.90	$13.85
February	40,000	11.38 - 11.41	11.40	13.75 - 13.85	13.80
March	40,000	11.13 - 11.15	11.14	13.50 - 13.60	13.55
April	40,000	9.40 - 9.45	9.42	11.55 - 11.65	11.60
May	40,000	9.24 - 9.29	9.26	11.41 - 11.55	11.48
June	40,000	9.31 - 9.36	9.34	11.49 - 11.60	11.55

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Financial Price Swap Contracts. The total fair value of EOG's natural gas financial price swap contracts at September 30, 2009 was a positive $292 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at November 5, 2009. The notional volumes are expressed in MMBtud and prices are expressed in $/MMBtu. The average price of EOG's outstanding natural gas financial price swap contracts for 2009 is $9.99 per MMBtu and for 2010 is $10.14 per MMBtu.

Natural Gas Financial Price Swap Contracts
		Weighted
	Volume	Average Price
	(MMBtud)	($/MMBtu)
2009
January (closed)	585,000	$10.76
February (closed)	585,000	10.73
March (closed)	585,000	10.50
April (closed)	610,000	9.24
May (closed)	610,000	9.16
June (closed)	710,000	8.53
July (closed)	710,000	8.62
August (closed)	710,000	8.67
September (closed)	710,000	8.69
October (closed)	710,000	8.76
November (closed)	610,000	9.66
December	610,000	9.99

2010
January	20,000	$11.20
February	20,000	11.15
March	20,000	10.89
April	20,000	9.29
May	20,000	9.13
June	20,000	9.21

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Financial Basis Swap Contracts.
Prices received by EOG for its natural gas production generally vary from New York Mercantile Exchange (NYMEX) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas financial basis swap contracts in order to fix the differential between prices in the Rocky Mountain area and NYMEX Henry Hub prices. The total fair value of EOG's natural gas financial basis swap contracts at September 30, 2009 was a negative $75 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial basis swap contracts at November 5, 2009. The weighted average price differential represents the amount of reduction to NYMEX gas prices per MMBtu for the notional volumes covered by the basis swap. The notional volumes are expressed in MMBtud and price differentials expressed in $/MMBtu.

Natural Gas Financial Basis Swap Contracts
		Weighted
	Volume	Average Price Differential
	(MMBtud)	($/MMBtu)
2009
Second Quarter (closed)	65,000	$(2.54)
Third Quarter (closed)	65,000	(2.60)
Fourth Quarter ⁽¹⁾	65,000	(3.03)

2010
First Quarter	65,000	$(1.72)
Second Quarter	65,000	(2.56)
Third Quarter	65,000	(3.17)
Fourth Quarter	65,000	(3.73)

2011
First Quarter	65,000	$(1.89)

(1) Includes closed contracts for the months of October and November 2009.

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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, budgets, reserve information, 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 these expectations will be achieved or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known and unknown risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

the timing and extent of changes in prices for natural gas, crude oil and related commodities;

changes in demand for natural gas, crude oil and related commodities, including ammonia and methanol;

the extent to which EOG is successful in its efforts to discover, develop, market and produce reserves and to acquire natural gas and crude oil properties;

the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling and advanced completion technologies;

the extent to which EOG is successful in its efforts to economically develop its acreage in the Barnett Shale, the Bakken Formation, its Horn River Basin and Haynesville plays and its other exploration and development areas;

EOG's ability to achieve anticipated production levels from existing and future natural gas and crude oil development projects, given the risks and uncertainties inherent in drilling, completing and operating natural gas and crude oil wells and the potential for interruptions of production, whether involuntary or intentional as a result of market or other conditions;

the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights of way;

competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

EOG's ability to obtain access to surface locations for drilling and production facilities;

the extent to which EOG's third-party-operated natural gas and crude oil properties are operated successfully and economically;

EOG's ability to effectively integrate acquired natural gas and crude oil properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

weather, including its impact on natural gas and crude oil demand, and weather-related delays in drilling and in the installation and operation of gathering and production facilities;

the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all;

the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

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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;
the extent and effect of any hedging activities engaged in by EOG;

the timing and impact of liquefied natural gas imports;

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

political developments around the world, including in the areas in which EOG operates;

changes in government policies, legislation and regulations, including environmental regulations;

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 13 through 19 of EOG's Annual Report on Form 10-K for the year ended December 31, 2008 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and 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 to update or revise its forward-looking statements, whether as a result of new information, future events 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 36 through 42 of EOG's Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 25, 2009 (EOG's 2008 Annual Report); and (ii) Note 11, "Price, Interest Rate and Credit Risk Management Activities," on pages F-26 through F-29, to EOG's Consolidated Financial Statements included in EOG's 2008 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 Analys is 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 al low 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.

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, 2009 - July 31, 2009	2,203	$	72.97	-	6,386,200
August 1, 2009 - August 31, 2009	44,063		76.62	-	6,386,200
September 1, 2009 - September 30, 2009	2,869		78.86	-	6,386,200
Total	49,135		76.59	-

(1) Represents 49,135 total shares for the quarter ended September 30, 2009 that consist solely of 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 2009,
      EOG did not repurchase any shares under the Board-authorized repurchase program.

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ITEM 6. EXHIBITS

Exhibit No. Description

4.1	-	Amendment No. 7 to Rights Agreement, dated as of October 7, 2009, between EOG and Computershare Trust Company, N.A., as rights agent (via succession) (incorporated by reference to Exhibit 4.12 to EOG's Current Report on Form 8-K, filed October 7, 2009).

* 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.LAB	-	XBRL Label Linkbase Document.

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

* **101.DEF	-	XBRL Definition 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, 2009 and 2008 and Nine Months Ended September 30, 2009 and 2008, (ii) the Consolidated Balance Sheets - September 30, 2009 and December 31, 2008, (iii) the Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2009 and 2008 and (iv) Notes to Consolidated Financial Statements. Users of this data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

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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 5, 2009	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial and Accounting Officer and Duly Authorized Officer)

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EXHIBIT INDEX

Exhibit No. Description

4.1	-	Amendment No. 7 to Rights Agreement, dated as of October 7, 2009, between EOG and Computershare Trust Company, N.A., as rights agent (via succession) (incorporated by reference to Exhibit 4.12 to EOG's Current Report on Form 8-K, filed October 7, 2009).

* 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.LAB	-	XBRL Label Linkbase Document.

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

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

* Exhibits filed herewith

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EOG Resources - 10-Q quarterly report FY

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