Edgar Filing: EOG RESOURCES INC

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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 o No o

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

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

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

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

Title of each class		Number of shares
Common Stock, par value $0.01 per share		250,278,726 (as of April 27, 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 March 31, 2009 and 2008	3

		Consolidated Balance Sheets - March 31, 2009 and December 31, 2008	4

		Consolidated Statements of Cash Flows - Three Months Ended March 31, 2009 and 2008	5

		Notes to Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	34

	ITEM 4.	Controls and Procedures	34

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	35

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35

	ITEM 6.	Exhibits	36

SIGNATURES			37

EXHIBIT INDEX			38

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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
				March 31,
				2009		2008

Net Operating Revenues
	Natural Gas		$	567,578	$	1,037,638
	Crude Oil, Condensate and Natural Gas Liquids			200,328		394,848
	Gains (Losses) on Mark-to-Market Commodity Derivative Contracts			351,383		(469,844)
	Gathering, Processing and Marketing			37,842		35,985
	Other, Net			1,078		135,391
		Total		1,158,209		1,134,018

Operating Expenses
	Lease and Well			145,506		124,107
	Transportation Costs			68,862		61,967
	Gathering and Processing Costs			17,713		8,359
	Exploration Costs			49,623		47,943
	Dry Hole Costs			2,994		8,428
	Impairments			65,471		32,574
	Marketing Costs			31,953		33,045
	Depreciation, Depletion and Amortization			389,329		297,199
	General and Administrative			57,946		52,926
	Taxes Other Than Income			47,400		86,750
		Total		876,797		753,298

Operating Income				281,412		380,720
Other Income, Net				1,739		1,583
Income Before Interest Expense and Income Taxes				283,151		382,303
Interest Expense, Net				18,376		12,191
Income Before Income Taxes				264,775		370,112
Income Tax Provision				106,065		129,156
Net Income				158,710		240,956
Preferred Stock Dividends				-		443
Net Income Available to Common Stockholders			$	158,710	$	240,513

Net Income Per Share Available to Common Stockholders
	Basic		$	0.64	$	0.98
	Diluted		$	0.63	$	0.96

Dividends Declared per Common Share			$	0.145	$	0.120

Average Number of Common Shares
	Basic			247,991		245,430
	Diluted			250,204		249,763

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)

						March 31,		December 31,
						2009		2008
ASSETS
Current Assets
		Cash and Cash Equivalents			$	85,214	$	331,311
		Accounts Receivable, Net				558,119		722,695
		Inventories				242,627		187,970
		Assets from Price Risk Management Activities				856,982		779,483
		Income Taxes Receivable				5,199		27,053
		Deferred Income Taxes				6,822		-
		Other				54,776		59,939
				Total		1,809,739		2,108,451

Property, Plant and Equipment
	Oil and Gas Properties (Successful Efforts Method)					21,460,167		20,803,629
		Other Property, Plant and Equipment				1,086,093		1,057,888
			Total Property, Plant and Equipment			22,546,260		21,861,517
		Less: Accumulated Depreciation, Depletion and Amortization				(8,539,730)		(8,204,215)
				Total Property, Plant and Equipment, Net		14,006,530		13,657,302
Other Assets						167,440		185,473
Total Assets					$	15,983,709	$	15,951,226


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
		Accounts Payable			$	774,434	$	1,122,209
		Accrued Taxes Payable				78,866		86,265
		Dividends Payable				35,943		33,461
		Liabilities from Price Risk Management Activities				9,610		4,429
		Deferred Income Taxes				296,468		368,231
		Current Portion of Long-Term Debt				-		37,000
		Other				87,976		113,321
				Total		1,283,297		1,764,916

Long-Term Debt						2,105,100		1,860,000
Other Liabilities						514,143		498,291
Deferred Income Taxes						2,965,632		2,813,522
Commitments and Contingencies (Note 9)

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
250,338,160 Shares Issued at March 31, 2009 and 249,758,577
Shares Issued at December 31, 2008						202,503		202,498
Additional Paid in Capital						349,210		323,805
Accumulated Other Comprehensive (Loss) Income						(21,694)		27,787
Retained Earnings						8,588,650		8,466,143
Common Stock Held in Treasury, 62,402 Shares at March 31, 2009
and 126,911 Shares at December 31, 2008						(3,132)		(5,736)
				Total Stockholders' Equity		9,115,537		9,014,497
Total Liabilities and Stockholders' Equity					$	15,983,709	$	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)

				Three Months Ended
				March 31,
				2009		2008
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	158,710	$	240,956
	Items Not Requiring (Providing) Cash
		Depreciation, Depletion and Amortization		389,329		297,199
		Impairments		65,471		32,574
		Stock-Based Compensation Expenses		26,407		19,783
		Deferred Income Taxes		83,215		83,390
		Other, Net		(652)		(127,968)
	Dry Hole Costs			2,994		8,428
	Mark-to-Market Commodity Derivative Contracts
		Total (Gains) Losses		(351,383)		469,844
		Realized Gains		310,964		23,210
	Other, Net			2,940		8,599
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		156,926		(177,684)
		Inventories		(22,896)		3,285
		Accounts Payable		(352,622)		93,452
		Accrued Taxes Payable		14,478		(29,265)
		Other Assets		1,430		(1,745)
		Other Liabilities		(18,070)		(22,165)
	Changes in Components of Working Capital Associated with
		Investing and Financing Activities		138,598		5,192
Net Cash Provided by Operating Activities				605,839		927,085

Investing Cash Flows
	Additions to Oil and Gas Properties			(822,583)		(1,060,035)
	Additions to Other Property, Plant and Equipment			(65,013)		(87,589)
	Proceeds from Sales of Assets			447		346,891
	Changes in Components of Working Capital Associated with
		Investing Activities		(138,532)		(4,750)
	Other, Net			554		(1,235)
Net Cash Used in Investing Activities				(1,025,127)		(806,718)

Financing Cash Flows
	Net Commercial Paper and Uncommitted Credit Facility Borrowings			208,100		-
	Dividends Paid			(33,491)		(22,089)
	Redemption of Preferred Stock			-		(5,395)
	Excess Tax Benefits from Stock-Based Compensation			4,688		35,496
	Treasury Stock Purchased			(4,904)		(5,508)
	Proceeds from Stock Options Exercised			1,152		29,537
	Other, Net			(66)		(442)
Net Cash Provided by Financing Activities				175,479		31,599

Effect of Exchange Rate Changes on Cash				(2,288)		(1,259)

Increase (Decrease) in Cash and Cash Equivalents				(246,097)		150,707
Cash and Cash Equivalents at Beginning of Period				331,311		54,231
Cash and Cash Equivalents at End of Period			$	85,214	$	204,938

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 (U.S. GAAP) have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures included either on the face of the financial statements or in these notes are sufficient to make the interim information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in EOG's Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 25, 2009 (EOG's 2008 Annual Report).

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three months ended March 31, 2009 are not necessarily indicative of the results to be expected for the full year.

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. EOG's gathering, processing and marketing revenues were previously presented net of related gas 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 months ended March 31, 2008 presentation in the Consolidated Statements of Income was to increase total net operating revenues and total operating expenses by $33 million. These changes did not impact previously reported operating income, net income or cash flows.

Recently Issued Accounting Standards and Developments. 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 financial statements.

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In March 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 161, "Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133" (SFAS No. 161). SFAS No. 161 does not change the scope or accounting of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133), but expands disclosure requirements about an entity's derivative instruments and hedging activities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. EOG adopted the provisions of SFAS No. 161 effective January 1, 2009. See Note 13.

In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157). SFAS No. 157 provides a definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The standard also requires additional disclosures on the use of fair value in measuring assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy. In February 2008, the FASB issued a Staff Position on SFAS No. 157, FASB Staff Position (FSP) No. FAS 157-2, "Effective Date of FASB Statement No. 157" (FSP 157-2). FSP 157-2 delays the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008. EOG partially adopted SFAS No. 157 effective January 1, 2008 and adopted the provisions related to nonfinancial assets and liabilities effective January 1, 2009. See Note 12.

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
		March 31,
		2009		2008

Lease and Well	$	6.0	$	4.4
Exploration Costs		5.2		4.0
General and Administrative		15.2		11.4
Total	$	26.4	$	19.8

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 March 31, 2009, approximately 3.9 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. Effective May 2005, 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 $8.7 million and $8.9 million during the three months ended March 31, 2009 and 2008, respectively.

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Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the three-month periods ended March 31, 2009 and 2008 are as follows:

		Stock Options/SARs				ESPP
		Three Months Ended				Three Months Ended
		March 31,				March 31,
		2009		2008		2009		2008

Weighted Average Fair Value of Grants	$	20.63	$	24.13	$	25.78	$	21.86
Expected Volatility		67.20%		31.84%		78.89%		31.67%
Risk-Free Interest Rate		0.60%		2.81%		0.25%		3.29%
Dividend Yield		1.0%		0.4%		1.0%		0.4%
Expected Life		2.7 yrs.		3.6 yrs.		0.5 yrs.		0.5 yrs.

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

The following table sets forth stock option and SAR transactions for the three-month periods ended March 31, 2009 and 2008 (stock options and SARs in thousands):

	Three Months Ended			Three Months Ended
	March 31, 2009			March 31, 2008
			Weighted			Weighted
	Number of		Average	Number of		Average
	Stock		Grant	Stock		Grant
	Options/SARs		Price	Options/ SARs		Price

Outstanding at January 1	7,802	$	52.56	9,373	$	41.04
Granted	17		67.64	22		99.68
Exercised ⁽¹⁾	(79)		18.16	(1,341)		24.13
Forfeited	(32)		71.90	(45)		60.90
Outstanding at March 31 ⁽²⁾	7,708	$	52.86	8,009	$	43.92

Vested or Expected to Vest ⁽³⁾	7,478	$	52.12	7,771	$	43.32

Exercisable at March 31 ⁽⁴⁾	4,651	$	37.71	4,319	$	28.50

                                (1) The total intrinsic value of stock options/SARs exercised for the three-month periods ended March 31, 2009
                                      and 2008 was $3.7 million and $113.7 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 March 31, 2009 and 2008 was $97.7 million and $609.3
                                      million, respectively. At March 31, 2009 and 2008, the weighted average remaining contractual life was 4.3 years and 4.9
                                      years, respectively.
                                (3) The total intrinsic value of stock options/SARs vested or expected to vest at March 31, 2009 and 2008 was $97.7
                                      million and $595.9 million, respectively. At March 31, 2009 and 2008, the weighted average remaining contractual
                                      life was 4.3 years and 4.9 years, respectively.
                                (4) The total intrinsic value of stock options/SARs exercisable at March 31, 2009 and 2008 was $97.6 million and $395.2
                                      million, respectively. At March 31, 2009 and 2008, the weighted average remaining contractual life was 3.6 years and 4.2
                                      years, respectively.

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At March 31, 2009, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $68.9 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.3 years.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $17.7 million and $10.9 million for the three months ended March 31, 2009 and 2008, respectively.

The following table sets forth the restricted stock and restricted stock units transactions for the three-month periods ended March 31, 2009 and 2008 (shares and units in thousands):

	Three Months Ended			Three Months Ended
	March 31, 2009			March 31, 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	664		48.67	203		120.01
Released ⁽¹⁾	(277)		22.33	(161)		20.77
Forfeited	(15)		84.01	(21)		67.85
Outstanding at March 31 ⁽²⁾	3,420	$	69.87	3,021	$	56.73

                                        (1) The total intrinsic value of restricted stock and restricted stock units released for the three-month periods
                                              ended March 31, 2009 and 2008 was $15.0 million and $16.1 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 aggregate intrinsic value of restricted stock and restricted stock units outstanding at March 31,
                                              2009 and 2008 was approximately $187.3 million and $362.5 million, respectively.

At March 31, 2009, unrecognized compensation expense related to restricted stock and restricted stock units totaled $136.0 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 periods ended March 31, 2009 and 2008 (in thousands, except per share data):

			Three Months Ended
			March 31,
			2009		2008

Numerator for Basic and Diluted Earnings Per Share -
	Net Income	$	158,710	$	240,956
	Less: Preferred Stock Dividends		-		443
	Net Income Available to Common Stockholders	$	158,710	$	240,513

Denominator for Basic Earnings Per Share -
	Weighted Average Shares		247,991		245,430
Potential Dilutive Common Shares -
	Stock Options/SARs		1,362		3,077
	Restricted Stock and Restricted Stock Units		851		1,256
Denominator for Diluted Earnings Per Share -
	Adjusted Diluted Weighted Average Shares		250,204		249,763

Net Income Per Share Available to Common Stockholders
	Basic	$	0.64	$	0.98
	Diluted	$	0.63	$	0.96

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. The excluded stock options and SARs totaled 4.4 million shares and 3,826 shares for the three months ended March 31, 2009 and 2008, respectively.

4. Supplemental Cash Flow Information

Cash paid (received) for interest and income taxes was as follows for the three-month periods ended March 31, 2009 and 2008 (in thousands):

		Three Months Ended
		March 31,
		2009		2008

Interest	$	10,037	$	17,479
Income Taxes	$	(6,581)	$	36,843

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5. Comprehensive Income

The following table presents the components of EOG's comprehensive income for the three-month periods ended March 31, 2009 and 2008 (in thousands):

					Three Months Ended
					March 31,
					2009		2008
Comprehensive Income
	Net Income			$	158,710	$	240,956
	Other Comprehensive Income (Loss)
		Foreign Currency Translation Adjustments			(51,288)		(77,090)
		Foreign Currency Swap Transaction			2,394		(974)
		Income Tax Related to Foreign
		Currency Swap Transaction			(609)		239
		Defined Benefit Pension and Postretirement Plans			34		35
		Income Tax Related to Defined Benefit
		Pension and Postretirement Plans			(12)		(64)
			Total	$	109,229	$	163,102

6. Segment Information

Selected financial information by reportable segment is presented below for the three-month periods ended March 31, 2009 and 2008 (in thousands):

					Three Months Ended
					March 31,
					2009		2008
Net Operating Revenues
	United States			$	1,002,904	$	838,047
	Canada				104,902		170,454
	Trinidad				41,262		109,884
	Other International ⁽¹⁾				9,141		15,633
			Total	$	1,158,209	$	1,134,018

Operating Income (Loss)
	United States			$	261,718	$	230,558
	Canada				2,389		59,788
	Trinidad				21,498		88,390
	Other International ⁽¹⁾				(4,193)		1,984
			Total		281,412		380,720

Reconciling Items
		Other Income, Net			1,739		1,583
		Interest Expense, Net			18,376		12,191
			Income Before Income Taxes	$	264,775	$	370,112

(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 March 31, 2009 and December 31, 2008 (in thousands):

				At		At
				March 31,		December 31,
				2009		2008
Total Assets
	United States		$	12,855,740	$	12,668,763
	Canada			2,331,095		2,421,979
	Trinidad			708,116		735,387
	Other International ⁽¹⁾			88,758		125,097
		Total	$	15,983,709	$	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 oil and gas properties pursuant to SFAS No. 143, "Accounting for Asset Retirement Obligations," at March 31, 2009 and 2008 (in thousands):

			Three Months Ended
			March 31,
			2009		2008

Carrying Amount at Beginning of Period		$	368,159	$	211,124
	Liabilities Incurred		11,670		10,224
	Liabilities Settled		(5,992)		(11,460)
	Accretion		4,559		2,933
	Revisions ⁽¹⁾		(8)		3,693
	Foreign Currency Translations		(2,030)		(1,946)
Carrying Amount at End of Period		$	376,358	$	214,568

Current Portion		$	17,557	$	2,306
Noncurrent Portion		$	358,801	$	212,262

(1) Revisions to asset retirement obligations 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 three-month period ended March 31, 2009 in accordance with FSP No. 19-1, "Accounting for Suspended Well Costs," are presented below (in thousands):

			Three Months
			Ended
			March 31,
			2009

Balance at December 31, 2008		$	85,255
	Additions Pending the Determination of Proved Reserves		53,488
	Reclassifications to Proved Properties		(10,804)
	Charged to Dry Hole Costs		(2,707)
	Foreign Currency Translations		(1,676)
Balance at March 31, 2009		$	123,556

The following table provides an aging of suspended well costs at March 31, 2009 (in thousands, except well count):

				At
				March 31,
				2009

Capitalized exploratory well costs that have been
	capitalized for a period less than one year		$	67,381
Capitalized exploratory well costs that have been
	capitalized for a period greater than one year			56,175	(1)
		Total	$	123,556
Number of exploratory wells that have been capitalized
	for a period greater than one year			4

                              (1) Costs related to three shale projects in British Columbia, Canada (B.C.) ($38 million) and an outside operated,
                                    offshore Central North Sea project in the United Kingdom ($18 million). In the B.C. 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 submitted a field development plan to the 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. In accordance with SFAS No. 5, "Accounting for Contingencies," 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 three months ended March 31, 2009 and 2008, EOG's total costs recognized for these pension plans were $5.6 million and $5.1 million, respectively.

In addition, as more fully discussed in Note 6 to Consolidated Financial Statements included 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 each of the three-month periods ended March 31, 2009 and 2008, combined contributions to these plans totaled $0.6 million.

Postretirement Plan. EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents. For the three months ended March 31, 2009, EOG's total contributions to these plans were approximately $31,000. The net periodic benefit costs recognized for the postretirement medical and dental plans were approximately $203,000 and $186,500, respectively, for the three months ended March 31, 2009 and 2008.

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 $191 million of outstanding borrowings from commercial paper and $17 million from uncommitted credit facilities at March 31, 2009. The weighted average interest rates for commercial paper and uncommitted credit facility borrowings at March 31, 2009 were 0.84% and 1.10%, respectively. The weighted average interest rates for commercial paper and uncommitted credit facility borrowings for the three months ended March 31, 2009 were 0.88% and 1.10%, respectively. Commercial paper and uncommitted credit facility borrowings outstanding at March 31, 2009 were classified as long-term debt based upon EOG's intent and ability to replace such amounts with other long-term debt.

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 March 31, 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 March 31, 2009, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 0.69% and 3.25%, respectively.

In May 2006, EOG Resources Trinidad Limited, a wholly owned foreign subsidiary of EOG, entered into a 3-year, $75 million Revolving Credit Agreement (Credit Agreement). 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. In the second quarter of 2008, EOG repaid $38 million of the $75 million outstanding and at March 31, 2009, $37 million remained outstanding under the Credit Agreement. The remaining outstanding balance was classified as long-term debt based upon EOG's intent and ability to replace such amount with other long-term debt. The applicable Eurodollar rate at March 31, 2009 was 2.89%. The weighted average Eurodollar rate for the amount outstanding during the first three months of 2009 was 2.79%. The Credit Agreement is scheduled to mature on May 12, 2009. EOG is currently negotiating an amendment to the Credit Agreement to extend the scheduled maturity date of the remaining outstanding balance of $37 million to May 12, 2010. EOG expects to enter into this amendment prior to the scheduled maturity date.

Common Stock. On February 4, 2009, the Board 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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12. Fair Value Measurements

Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value in the accompanying balance sheets. Effective January 1, 2008, EOG adopted the provisions of SFAS No. 157, "Fair Value Measurements," for its financial assets and liabilities. SFAS No. 157 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, SFAS No. 157 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 prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. SFAS No. 157 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. In accordance with the provisions of FSP 157-2, "Effective Date of FASB Statement No. 157," EOG adopted the provisions of SFAS No. 157 relating to its nonfinancial assets and liabilities effective January 1, 2009.

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 March 31, 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 March 31, 2009
Financial Assets:
	Natural gas collars, price swaps
	and basis swaps	$	-	$	898	$	-

Financial Liabilities:
	Natural gas collars, price swaps
	and basis swaps	$	-	$	27	$	-
	Foreign currency rate swap	$	-	$	19	$	-

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.

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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.

In accordance with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," proved oil and gas properties with a carrying amount of $32 million were written down to their fair value of $9 million at March 31, 2009, resulting in a pretax impairment charge of $23 million for the three months ended March 31, 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.

13. Risk Management Activities

Effective January 1, 2009, EOG adopted the provisions of SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133." SFAS No. 161 requires expanded disclosure about an entity's use of derivative instruments and the impact of those instruments on the Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows. 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 impact is reflected as Cash Flows from Operating Activities. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

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 SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. Changes in the fair value of the foreign currency swap do not impact Net Income Available to Common Stockholders. The after-tax net impact from the foreign currency swap transaction was an increase in Other Comprehensive Income of $1.8 million and a reduction in Other Comprehensive Income of $0.7 million for the three months ended March 31, 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 March 31, 2009 and December 31, 2008. Certain amounts may be presented on a net basis in the financial statements in accordance with master netting arrangements between EOG and the counter-parties to the transactions (in millions):

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

Asset Derivatives
	Natural gas collars, price swaps
	and basis swaps -
		Current portion	Assets from Price Risk
			Management Activities	$	876	$	786
		Noncurrent portion	Other Assets	$	58	$	63

Liability Derivatives
	Natural gas basis swaps
		Current portion	Liabilities from Price Risk
			Management Activities	$	28	$	11
		Noncurrent portion	Other Liabilities	$	35	$	14

	Foreign currency rate swaps -
		Noncurrent portion	Other Liabilities	$	19	$	26

EOG recognized a net gain on the mark-to-market of financial commodity derivative contracts of $351 million for the three months ended March 31, 2009 and a net loss of $470 million for the three months ended March 31, 2008.

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Financial Collar Contracts. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at March 31, 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 $10.00 per million British thermal units (MMBtu) and the average ceiling price was $12.32 per MMBtu.

Natural Gas Financial Collar Contracts
		Floor Price		Ceiling Price
			Weighted		Weighted
			Average		Average
	Volume	Floor Range	Price	Ceiling Range	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
July	40,000	9.40 - 9.45	9.43	11.60 - 11.70	11.65
August	40,000	9.47 - 9.52	9.50	11.68 - 11.80	11.74
September	40,000	9.50 - 9.55	9.52	11.73 - 11.85	11.79
October	40,000	9.58 - 9.63	9.61	11.83 - 11.95	11.89
November	40,000	9.88 - 9.93	9.91	12.30 - 12.40	12.35
December	40,000	9.87 - 10.30	10.09	12.55 - 12.71	12.63

Subsequent to March 31, 2009, EOG settled its natural gas financial collar contracts for the period July 1, 2010 to December 31, 2010 and received proceeds of $26.5 million. An updated summary of EOG's natural gas financial price collar contracts as of May 4, 2009 is presented in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions."

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Financial Price Swap Contracts. Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at March 31, 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 $8.98 per MMBtu and for 2010 was $9.87 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	610,000	9.16
June	710,000	8.53
July	710,000	8.62
August	710,000	8.67
September	710,000	8.69
October	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
July	20,000	9.31
August	20,000	9.38
September	20,000	9.40
October	20,000	9.49
November	20,000	9.80
December	20,000	10.21

Subsequent to March 31, 2009, EOG settled its natural gas financial price swap contracts for the period July 1, 2010 to December 31, 2010 and received proceeds of $12.1 million. An updated summary of EOG's natural gas financial price swap contracts as of May 4, 2009 is presented in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions."

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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 March 31, 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*	65,000	$(2.54)
Third Quarter	65,000	(2.60)
Fourth Quarter	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)

*Includes closed contracts for April 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 the other parties, 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 rating. In addition, the ISDA may also provide that as a result of certain circumstances, including certain events that cause EOG's credit rating to become materially weaker than its then-current rating, 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 March 31, 2009 and December 31, 2008. EOG had zero collateral posted at March 31, 2009 and December 31, 2008.

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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 North Sea 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 both the first quarter of 2009 and the first quarter of 2008. One of EOG's exploration strategies is to apply its horizontal drilling expertise gained in natural gas resources plays to unconventional oil reservoirs. During the first quarter 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 quarter of 2009, crude oil and natural gas liquids production accounted for approximately 21% of total company production as compared to 17% 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.

International. In the United Kingdom, a rig was contracted to drill two operated wells in the East Irish Sea in 2009 and drilling is expected to commence in the second quarter. In addition, EOG began drilling its first well in the Sichuan Basin, Sichuan Province, The People's Republic of China, in March 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.

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 March 31, 2009 EOG's debt-to-total capitalization ratio was 19% as compared to 17% at December 31, 2008. During the first quarter of 2009, EOG funded $937 million in exploration and development and other property, plant and equipment expenditures and paid $33 million in dividends to common stockholders, primarily by utilizing cash provided from its operating activities and proceeds from commercial paper and uncommitted credit facility borrowings.

For 2009, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.1 billion, excluding acquisitions. United States and Canada natural gas and crude oil drilling activity continues to be a key component of these expenditures. EOG intends to manage the 2009 capital budget while maintaining a strong balance sheet. 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.

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Results of Operations

The following review of operations for the three months ended March 31, 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.

Net Operating Revenues. During the first quarter of 2009, net operating revenues increased $24 million, or 2%, to $1,158 million from $1,134 million for the same period of 2008. Total wellhead revenues for the first quarter of 2009, which are revenues generated from sales of EOG's production of natural gas, crude oil and condensate and natural gas liquids, decreased $664 million, or 46%, to $768 million from $1,432 million for the same period of 2008. During the first quarter of 2009, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $351 million compared to net losses of $470 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 first quarter of 2009 increased $2 million, or 5%, to $38 million from $36 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.

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Wellhead volume and price statistics for the three-month periods ended March 31, 2009 and 2008 were as follows:

				Three Months Ended
				March 31,
				2009		2008
Natural Gas Volumes (MMcfd) ⁽¹⁾
	United States			1,193		1,085
	Canada			230		216
	Trinidad			263		231
	Other International ⁽²⁾			16		17
		Total		1,702		1,549

Average Natural Gas Prices ($/Mcf) ⁽³⁾
	United States		$	4.06	$	8.05
	Canada			4.43		7.44
	Trinidad			1.32		3.87
	Other International ⁽²⁾			6.03		9.85
		Composite		3.71		7.36

Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
	United States			44.9		30.6
	Canada			3.2		2.4
	Trinidad			3.0		3.6
	Other International ⁽²⁾			0.1		0.1
		Total		51.2		36.7

Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
	United States		$	33.24	$	92.08
	Canada			37.11		88.94
	Trinidad			33.45		87.90
	Other International ⁽²⁾			46.71		88.29
		Composite		33.51		91.46

Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
	United States			21.7		16.7
	Canada			1.1		1.0
		Total		22.8		17.7

Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
	United States		$	22.12	$	57.26
	Canada			25.52		57.14
		Composite		22.29		57.26

Natural Gas Equivalent Volumes (MMcfed) ⁽⁴⁾
	United States			1,593		1,370
	Canada			255		236
	Trinidad			281		252
	Other International ⁽²⁾			17		17
		Total		2,146		1,875

Total Bcfe ⁽⁴⁾				193.1		170.6

(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 and 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 and condensate or natural gas liquids.

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Wellhead natural gas revenues for the first quarter of 2009 decreased $470 million, or 45%, to $568 million from $1,038 million for the same period of 2008 due to a lower composite average wellhead natural gas price ($560 million), partially offset by increased natural gas deliveries ($90 million). EOG's composite average wellhead natural gas price decreased 50% to $3.71 per Mcf for the first quarter of 2009 from $7.36 per Mcf for the same period of 2008.

Natural gas deliveries for the first quarter of 2009 increased 153 MMcfd, or 10%, to 1,702 MMcfd from 1,549 MMcfd for the same period of 2008. The increase was due to higher production in the United States (108 MMcfd), Trinidad (32 MMcfd) and Canada (14 MMcfd). The increase in the United States was primarily attributable to increased production from Texas (88 MMcfd) and the Rocky Mountain area (48 MMcfd), partially offset by decreased production from Pittsburgh as a result of the February 2008 sale of EOG's Appalachian assets (8 MMcfd), Oklahoma (7 MMcfd), New Mexico (7 MMcfd) and Mississippi (7 MMcfd). The increase in Trinidad was primarily due to increased contractual demand. The increase in Canada was primarily attributable to British Columbia Horn River Basin production.

Wellhead crude oil and condensate revenues for the first quarter of 2009 decreased $149 million, or 49%, to $154 million from $303 million for the same period of 2008, due to a lower composite average wellhead crude oil and condensate price ($267 million), partially offset by an increase of 15 MBbld, or 40%, in wellhead crude oil and condensate deliveries ($119 million). The increase in deliveries primarily reflects increased production in North Dakota (11 MBbld). The composite average wellhead crude oil and condensate price for the first quarter of 2009 decreased 63% to $33.51 per barrel compared to $91.46 per barrel for the same period of 2008.

Natural gas liquids revenues for the first quarter of 2009 decreased $46 million, or 50%, to $46 million from $92 million for the same period of 2008, due to a lower composite average price ($71 million), partially offset by increased natural gas liquids deliveries ($25 million). The composite average natural gas liquids price for the first quarter of 2009 decreased 61% to $22.29 per barrel compared to $57.26 per barrel for the same period of 2008. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale and Rocky Mountain areas.

During the first quarter of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $351 million compared to a net loss of $470 million for the same period of 2008. During the first quarter of 2009, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $311 million compared to $23 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 March 31, 2009 and 2008, substantially all of such revenues were related to sales of third-party natural gas. 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 first quarter of 2009 increased $3 million to $6 million compared to $3 million for the same period of 2008. The increase resulted primarily from natural gas marketing operations in the Gulf Coast area.

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Operating and Other Expenses. For the first quarter of 2009, operating expenses of $877 million were $124 million higher than the $753 million incurred during the first quarter of 2008. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the three-month periods ended March 31, 2009 and 2008:

			Three Months Ended
			March 31,
			2009		2008

Lease and Well		$	0.75	$	0.73
Transportation Costs			0.36		0.36
Depreciation, Depletion and Amortization (DD&A) -
	Oil and Gas Properties		1.90		1.66
	Other Property, Plant and Equipment		0.12		0.08
General and Administrative (G&A)			0.30		0.31
Interest Expense, Net			0.10		0.07
	Total ⁽¹⁾	$	3.53	$	3.21

(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 net interest expense for the three months ended March 31, 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 fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating 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 of $146 million for the first quarter of 2009 increased $22 million from $124 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($18 million) and Canada ($5 million) and higher lease and well administrative expenses ($4 million), partially offset by changes in the Canadian exchange rate ($7 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 $69 million for the first quarter of 2009 increased $7 million from $62 million for the same prior year period primarily due to increased production and costs associated with marketing arrangements to transport production from the Fort Worth Basin Barnett Shale area ($5 million) and the Rocky Mountain area ($3 million) to downstream markets.

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

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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 first quarter of 2009 increased $92 million to $389 million from $297 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first quarter of 2009 were $82 million higher than the same prior year period primarily due to higher unit rates in the United States ($45 million), Canada ($5 million) and Trinidad ($4 million) and as a result of increased production in the United States ($34 million) and in Canada ($3 million), partially offset by changes in the Canadian exchange rate ($11 million).

DD&A expenses associated with other property, plant and equipment for the first quarter of 2009 were $10 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 ($5 million) and Rocky Mountain area ($2 million).

G&A expenses of $58 million for the first quarter of 2009 increased $5 million from the same prior year period primarily due to higher employee related costs.

Interest expense, net of $18 million for the first quarter of 2009 increased $6 million as compared to the same prior year period primarily due to a higher average debt balance ($9 million), partially offset by higher capitalized interest ($3 million).

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

Gathering and processing costs for the first quarter of 2009 increased $9 million to $18 million as compared to the same prior year period primarily due to increased activities in the Rocky Mountain area ($4 million) and Fort Worth Basin Barnett Shale area ($3 million).

Impairments include amortization of unproved leases, as well as impairments under Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144), which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $65 million for the first quarter of 2009 were $32 million higher than impairments of $33 million for the same prior year period primarily due to increased amortization costs of unproved leases in the United States ($18 million) and increased SFAS No. 144 related impairments in the United States ($16 million), partially offset by decreased SFAS No. 144 related impairments in Canada ($2 million). Under SFAS No. 144, EOG recorded impairments of $23 million and $9 million for the first 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.

Taxes other than income were $47 million (6.2% of wellhead revenues) for the first quarter of 2009 compared to $87 million (6.1% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to decreased severance/production taxes as a result of decreased wellhead revenues in the United States ($28 million) and Trinidad ($6 million) and an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions ($5 million).

Income tax provision of $106 million for the first quarter of 2009 decreased $23 million compared to the same prior year period primarily due to lower pretax income ($37 million), partially offset by higher state income taxes ($7 million). The net effective tax rate for the first quarter of 2009 increased to 40% from 35% in 2008.

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Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the three months ended March 31, 2009 were funds generated from operations and net commercial paper and uncommitted credit facility borrowings. 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 three months of 2009, EOG's cash balance decreased $246 million to $85 million from $331 million at December 31, 2008.

Net cash provided by operating activities of $606 million for the first three months of 2009 decreased $321 million compared to the same period of 2008 primarily reflecting a decrease in wellhead revenues ($665 million), partially offset by a favorable change in net cash flow from the settlement of financial commodity derivative contracts ($288 million), a decrease in net cash paid for income taxes ($43 million), a decrease in cash paid for interest expense ($7 million) and favorable changes in working capital and other assets and liabilities ($3 million).

Net cash used in investing activities of $1,025 million for the first three months of 2009 increased by $218 million compared to the same period of 2008 due primarily to a decrease in proceeds from sales of assets ($346 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 ($134 million), partially offset by a decrease in additions to oil and gas properties ($237 million) and a decrease in additions to other property, plant and equipment ($23 million).

Net cash provided by financing activities was $175 million for the first three months of 2009 compared to $32 million for the same period of 2008. Cash provided by financing activities for the first three months of 2009 included net commercial paper and uncommitted credit facility borrowings ($208 million) and excess tax benefits from stock-based compensation ($5 million). Cash used by financing activities for the first three months of 2009 included cash dividend payments ($33 million) and the purchase of treasury stock ($5 million).

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Total Expenditures. For 2009, EOG's budget for exploration and production and other property, plant and equipment expenditures is approximately $3.1 billion. The table below sets out components of total expenditures for the three-month periods ended March 31, 2009 and 2008 (in millions):

				Three Months Ended
				March 31,
				2009		2008

Expenditure Category
Capital
		Drilling and Facilities	$	731	$	888
		Leasehold Acquisitions		72		126
		Producing Property Acquisitions		4		29
		Capitalized Interest		12		9
		Subtotal		819		1,052
Exploration Costs				50		48
Dry Hole Costs				3		8
	Exploration and Development Expenditures			872		1,108
Asset Retirement Costs				12		14
	Total Exploration and Development Expenditures			884		1,122
Other Property, Plant and Equipment				65		88
	Total Expenditures		$	949	$	1,210

Exploration and development expenditures of $872 million for the first three months of 2009 were $236 million lower than the same period of 2008 due primarily to decreased drilling and facilities expenditures in the United States ($128 million) and Canada ($15 million), decreased leasehold acquisition expenditures in Canada ($48 million), changes in the Canadian exchange rate ($15 million) and decreased producing property acquisition expenditures in Trinidad ($15 million) and Canada ($14 million). The exploration and development expenditures for the first three months of 2009 of $872 million include $662 million in development, $194 million in exploration, $12 million in capitalized interest and $4 million in producing property acquisitions. The exploration and development expenditures for the first three months of 2008 of $1,108 million include $801 million in development, $269 million in exploration, $29 million in producing property acquisitions and $9 million in capitalized interest.

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 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 impact is reflected as Cash Flows from Operating Activities. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

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Financial Collar Contracts. The total fair value of EOG's natural gas financial collar contracts at March 31, 2009 was a positive $59 million, which is reflected in the Consolidated Balance Sheets. Subsequent to March 31, 2009, EOG settled its natural gas financial collar contracts for the period July 1, 2010 to December 31, 2010 and received proceeds of $26.5 million. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at May 4, 2009. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/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

Weighted

Average

Average

Volume

Floor Range

Price

Ceiling Range

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

July (closed)

40,000

9.40 -   9.45

9.43

11.60 - 11.70

11.65

August (closed)

40,000

9.47 -   9.52

9.50

11.68 - 11.80

11.74

September (closed)

40,000

9.50 -   9.55

9.52

11.73 - 11.85

11.79

October (closed)

40,000

9.58 -   9.63

9.61

11.83 - 11.95

11.89

November (closed)

40,000

9.88 -   9.93

9.91

12.30 - 12.40

12.35

December (closed)

40,000

9.87 - 10.30

10.09

12.55 - 12.71

12.63

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Financial Price Swap Contracts. The total fair value of EOG's natural gas financial price swap contracts at March 31, 2009 was a positive $874 million, which is reflected in the Consolidated Balance Sheets. Subsequent to March 31, 2009, EOG settled its natural gas financial price swap contracts for the period July 1, 2010 to December 31, 2010 and received proceeds of $12.1 million. Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at May 4, 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 $8.96 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	710,000	8.53
July	710,000	8.62
August	710,000	8.67
September	710,000	8.69
October	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
July (closed)	20,000	9.31
August (closed)	20,000	9.38
September (closed)	20,000	9.40
October (closed)	20,000	9.49
November (closed)	20,000	9.80
December (closed)	20,000	10.21

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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 March 31, 2009 was a negative $62 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 May 4, 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*	65,000	$(2.54)
Third Quarter	65,000	(2.60)
Fourth Quarter	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)

*Includes closed contracts for the months of April and May 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;

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;

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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 Analysis of Financial Condition and Results of Operations - Results of Operations - Net Operating Revenues" in this Quarterly Report on Form 10-Q; and (iii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions" in this Quarterly Report on Form 10-Q.

ITEM 4. CONTROLS AND PROCEDURES
EOG RESOURCES, INC.

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

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

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PART II. OTHER INFORMATION

EOG RESOURCES, INC.

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 2. 9; UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth, for the periods indicated, EOG Resources, Inc.'s (EOG) 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⁾

January 1, 2009 - January 31, 2009	765	$	69.04	-	6,386,200
February 1, 2009 - February 28, 2009	82,197		53.71	-	6,386,200
March 1, 2009 - March 31, 2009	6,925		63.03	-	6,386,200
Total	89,887	$	54.56	-

(1) Represents 89,887 total shares for the quarter ended March 31, 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 of EOG's Board of Directors (Board) discussed below.
(2) In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During the first quarter of 2009,
     EOG did not repurchase any shares under the Board-authorized repurchase program.

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ITEM 6. EXHIBITS

3.2	-	Bylaws, as amended and restated effective as of February 26, 2009 (incorporated by reference to Exhibit 3.2(a) to EOG's Current Report on Form 8-K filed March 4, 2009).

10.1(a)	-	First Amendment to Executive Employment Agreement between EOG and Mark G. Papa, effective as of March 16, 2009 (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K filed March 18, 2009).

*10.1(b)	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Mark G. Papa, effective as of April 30, 2009.

10.2(a)	-	First Amendment to Executive Employment Agreement between EOG and Loren M. Leiker, effective as of March 16, 2009 (incorporated by reference to Exhibit 10.2 to EOG's Current Report on Form 8-K filed March 18, 2009).

*10.2(b)	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Loren M. Leiker, effective as of April 30, 2009.

10.3(a)	-	First Amendment to Executive Employment Agreement between EOG and Gary L. Thomas, effective as of March 16, 2009 (incorporated by reference to Exhibit 10.3 to EOG's Current Report on Form 8-K filed March 18, 2009).

*10.3(b)	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Gary L. Thomas, effective as of April 30, 2009.

*10.4(a)	-	First Amendment to Executive Employment Agreement between EOG and Frederick J. Plaeger, II, effective as of April 30, 2009.

*10.4(b)	-	First Amendment to Change of Control Agreement between EOG and Frederick J. Plaeger, II, effective as of April 30, 2009.

*10.5	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of April 30, 2009.

*10.6	-	First Amendment to the EOG Resources, Inc. Change of Control Severance Plan, effective as of April 30, 2009.

10.7	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Plan Document, effective as of December 16, 2008 (incorporated by reference to Exhibit 10.2(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).

10.8	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Adoption Agreement, dated as of December 16, 2008 (incorporated by reference to Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).

*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.

*Exhibits filed herewith

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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: May 4, 2009	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

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EXHIBIT INDEX

Exhibit No.		Description

3.2	-	Bylaws, as amended and restated effective as of February 26, 2009 (incorporated by reference to Exhibit 3.2(a) to EOG's Current Report on Form 8-K filed March 4, 2009).

10.1(a)	-	First Amendment to Executive Employment Agreement between EOG and Mark G. Papa, effective as of March 16, 2009 (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K filed March 18, 2009).

*10.1(b)	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Mark G. Papa, effective as of April 30, 2009.

10.2(a)	-	First Amendment to Executive Employment Agreement between EOG and Loren M. Leiker, effective as of March 16, 2009 (incorporated by reference to Exhibit 10.2 to EOG's Current Report on Form 8-K filed March 18, 2009).

*10.2(b)	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Loren M. Leiker, effective as of April 30, 2009.

10.3(a)	-	First Amendment to Executive Employment Agreement between EOG and Gary L. Thomas, effective as of March 16, 2009 (incorporated by reference to Exhibit 10.3 to EOG's Current Report on Form 8-K filed March 18, 2009).

*10.3(b)	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Gary L. Thomas, effective as of April 30, 2009.

*10.4(a)	-	First Amendment to Executive Employment Agreement between EOG and Frederick J. Plaeger, II, effective as of April 30, 2009.

*10.4(b)	-	First Amendment to Change of Control Agreement between EOG and Frederick J. Plaeger, II, effective as of April 30, 2009.

*10.5	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of April 30, 2009.

*10.6	-	First Amendment to the EOG Resources, Inc. Change of Control Severance Plan, effective as of April 30, 2009.

10.7	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Plan Document, effective as of December 16, 2008 (incorporated by reference to Exhibit 10.2(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).

10.8	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Adoption Agreement, dated as of December 16, 2008 (incorporated by reference to Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).

*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.

*Exhibits filed herewith

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