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 June 30, 2008

or

¨ 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, including 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 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		248,802,460 (as of July 23, 2008)

EOG RESOURCES, INC.
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements (Unaudited)

		Consolidated Statements of Income - Three Months Ended June 30, 2008 and 2007 and Six Months Ended June 30, 2008 and 2007	3

		Consolidated Balance Sheets - June 30, 2008 and December 31, 2007	4

		Consolidated Statements of Cash Flows - Six Months Ended June 30, 2008 and 2007	5

		Notes to Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	31

	ITEM 4.	Controls and Procedures	31

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	32

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32

	ITEM 4.	Submission of Matters to a Vote of Security Holders	33

	ITEM 6.	Exhibits	34

SIGNATURES			35

EXHIBIT INDEX			36

-2-

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Data)
(Unaudited)

				Three Months Ended				Six Months Ended
				June 30,				June 30,
				2008		2007		2008		2007


Net Operating Revenues
	Natural Gas		$	1,340,557	$	785,837	$	2,378,195	$	1,516,298
	Crude Oil, Condensate and Natural
	Gas Liquids			524,793		218,696		919,641		393,560
	(Losses) Gains on Mark-to-Market Commodity
	Derivative Contracts			(842,822)		44,103		(1,312,666)		4,302
	Other, Net			9,998		19,851		148,329		25,564
		Total		1,032,526		1,068,487		2,133,499		1,939,724

Operating Expenses
	Lease and Well			138,871		123,188		271,337		227,513
	Transportation Costs			63,102		36,971		125,069		69,538
	Exploration Costs			59,511		41,216		107,454		67,600
	Dry Hole Costs			6,785		11,816		15,213		28,626
	Impairments			48,875		20,804		81,449		44,846
	Depreciation, Depletion and Amortization			315,294		259,780		612,493		504,122
	General and Administrative			61,640		47,183		114,566		91,062
	Taxes Other Than Income			95,345		62,047		182,095		102,695
		Total		789,423		603,005		1,509,676		1,136,002

Operating Income				243,103		465,482		623,823		803,722
Other Income, Net				13,309		11,205		14,892		15,924
Income Before Interest Expense and Income Taxes				256,412		476,687		638,715		819,646
Interest Expense, Net				9,029		10,818		21,220		18,456
Income Before Income Taxes				247,383		465,869		617,495		801,190
Income Tax Provision				69,177		158,816		198,333		276,470
Net Income				178,206		307,053		419,162		524,720
Preferred Stock Dividends				-		990		443		1,865
Net Income Available to Common Stockholders			$	178,206	$	306,063	$	418,719	$	522,855

Net Income Per Share Available to Common Stockholders
	Basic		$	0.72	$	1.26	$	1.70	$	2.15
	Diluted		$	0.71	$	1.24	$	1.67	$	2.12

Average Number of Common Shares
	Basic			246,536		243,227		245,950		242,976
	Diluted			251,135		247,261		250,553		247,009

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

-3-

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

					June 30,		December 31,
					2008		2007
ASSETS
Current Assets
		Cash and Cash Equivalents		$	108,101	$	54,231
		Accounts Receivable, Net			1,228,560		835,670
		Inventories			109,971		102,322
		Assets from Price Risk Management Activities			-		100,912
		Income Taxes Receivable			239,442		110,370
		Deferred Income Taxes			347,928		33,533
		Other			54,095		55,001
			Total		2,088,097		1,292,039

Property, Plant and Equipment
	Oil and Gas Properties (Successful Efforts Method)				18,929,852		16,981,836
		Other Property, Plant and Equipment			776,864		581,402
					19,706,716		17,563,238
		Less: Accumulated Depreciation, Depletion and Amortization			(7,717,996)		(7,133,984)
			Total Property, Plant and Equipment, Net		11,988,720		10,429,254
Long-Term Assets Held for Sale					-		254,376
Other Assets					147,950		113,238
Total Assets				$	14,224,767	$	12,088,907


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
		Accounts Payable		$	1,379,602	$	1,152,140
		Accrued Taxes Payable			137,589		104,647
		Dividends Payable			29,607		22,045
		Liabilities from Price Risk Management Activities			762,560		3,404
		Deferred Income Taxes			61,048		108,980
		Other			74,634		82,954
			Total		2,445,040		1,474,170

Long-Term Debt					1,147,000		1,185,000
Other Liabilities					661,417		368,336
Deferred Income Taxes					2,545,139		2,071,307

Stockholders' Equity
Preferred Stock, $0.01 Par, 10,000,000 Shares Authorized:
		Series B, Cumulative, $1,000 Liquidation Preference per Share,
		5,000 Shares Outstanding at December 31, 2007			-		4,977
Common Stock, $0.01 Par, 640,000,000 Shares Authorized:
249,470,617 Shares Issued at June 30, 2008 and 249,460,000 Shares
Issued at December 31, 2007					202,495		202,495
Additional Paid in Capital					321,026		221,102
Accumulated Other Comprehensive Income					403,195		466,702
Retained Earnings					6,515,795		6,156,721
Common Stock Held in Treasury, 678,003 Shares at
June 30, 2008 and 2,935,313 Shares at December 31, 2007					(16,340)		(61,903)
			Total Stockholders' Equity		7,426,171		6,990,094
Total Liabilities and Stockholders' Equity				$	14,224,767	$	12,088,907

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

-4-

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

				Six Months Ended
				June 30,
				2008		2007
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	419,162	$	524,720
	Items Not Requiring (Providing) Cash
		Depreciation, Depletion and Amortization		612,493		504,122
		Impairments		81,449		44,846
		Stock-Based Compensation Expenses		44,566		29,542
		Deferred Income Taxes		123,330		223,591
		Other, Net		(127,693)		(24,091)
	Dry Hole Costs			15,213		28,626
	Mark-to-Market Commodity Derivative Contracts
		Total Losses (Gains)		1,312,666		(4,302)
		Realized (Losses) Gains		(114,859)		65,880
	Other, Net			9,077		15,228
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		(395,526)		20,734
		Inventories		(9,176)		(2,476)
		Accounts Payable		255,495		14,651
		Accrued Taxes Payable		(92,738)		26,191
		Other Assets		(61,623)		(4,683)
		Other Liabilities		(8,440)		(15,492)
	Changes in Components of Working Capital Associated with
		Investing and Financing Activities		(775)		(20,471)
Net Cash Provided by Operating Activities				2,062,621		1,426,616

Investing Cash Flows
	Additions to Oil and Gas Properties			(2,144,769)		(1,621,542)
	Additions to Other Property, Plant and Equipment			(196,353)		(157,515)
	Proceeds from Sales of Assets			354,413		37,988
	Changes in Components of Working Capital Associated with
		Investing Activities		648		20,412
	Other, Net			(20,429)		(1,540)
Net Cash Used in Investing Activities				(2,006,490)		(1,722,197)

Financing Cash Flows
	Net Commercial Paper Borrowings			-		170,400
	Long-Term Debt Borrowings			-		10,000
	Long-Term Debt Repayments			(38,000)		(30,000)
	Dividends Paid			(51,647)		(38,370)
	Redemption of Preferred Stock			(5,395)		-
	Excess Tax Benefits from Stock-Based Compensation			55,552		11,122
	Treasury Stock Purchased			(6,865)		(4,928)
	Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			48,509		14,089
	Other, Net			127		(194)
Net Cash Provided by Financing Activities				2,281		132,119

Effect of Exchange Rate Changes on Cash				(4,542)		3,741

Increase (Decrease) in Cash and Cash Equivalents				53,870		(159,721)
Cash and Cash Equivalents at Beginning of Period				54,231		218,255
Cash and Cash Equivalents at End of Period			$	108,101	$	58,534

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

-5-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Summary of Significant Accounting Policies

General. The consolidated financial statements of EOG Resources, Inc., together with its subsidiaries (EOG), included herein have been prepared by management without audit pursuant to the rules and regulations of the Securities and Exchange Commission. 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, 2007 (EOG's 2007 Annual Report).

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three and six months ended June 30, 2008 are not necessarily indicative of the results to be expected for the full year.

Derivative Instruments. As more fully discussed in Note 11 to Consolidated Financial Statements included in EOG's 2007 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 and price swap contracts, as a means to manage this price risk. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. 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.

As of January 1, 2008, EOG adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) FASB Interpretation (FIN) No. 39-1, "Amendment of FASB Interpretation No. 39," (FSP FIN No. 39-1) which effectively amends FIN No. 39, "Offsetting of Amounts Related to Certain Contracts." FSP FIN No. 39-1 permits netting fair values of derivative assets and liabilities for financial reporting purposes, if such assets and liabilities are with the same counterparty, and subject to a master netting arrangement. EOG has elected to employ net presentation of derivative assets and liabilities when FSP FIN No. 39-1 conditions are met. FSP FIN No. 39-1 also requires that when derivative assets and liabilities are presented net, fair value of the right to reclaim collateral assets (receivable) or the obligation to return cash collateral (payable) is also offset against the net fair value of the corresponding derivative. Netting collateral assets and liabilities against corresponding derivative balances represents a change in accounting policy. At June 30, 2008, collateral assets totaling $44 million have been netted against Liabilities from Price Risk Management Activities on the Consolidated Balance Sheets. There were no collateral assets or liabilities outstanding at December 31, 2007. See Note 12.

-6-

Recently Issued Accounting Standards and Developments. In March 2008, the 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, 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. Early adoption is permitted and comparative disclosures for earlier periods are encouraged. The adoption of SFAS No. 161 will result in additional disclosures related to derivative instruments and hedging activities.

In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Post Retirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)." The requirement to measure plan assets and benefit obligations as of the date of the employer's fiscal year-end is effective for fiscal years ending after December 15, 2008, and will not have an impact on EOG's financial statements since plan assets and benefit obligations are currently measured as of the date of EOG's fiscal year-end.

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 FSP on SFAS No. 157, 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. Except as provided by FSP 157-2, SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those years. FSP 157-2 requires an entity that does not adopt SFAS No. 157 in its entirety to disclose, at each reporting date until fully adopted, that it has only partially adopted SFAS No. 157 and the categories of assets and liabilities recorded or disclosed at fair value to which SFAS No. 157 has not been applied. EOG partially adopted SFAS No. 157 effective January 1, 2008. See Note 12.

2. Stock-Based Compensation

During 2008, EOG maintained various stock-based compensation plans as discussed below. 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				Six Months Ended
		June 30,				June 30,
		2008		2007		2008		2007

Lease and Well	$	4.1	$	2.8	$	8.5	$	5.8
Exploration Costs		4.4		3.0		8.4		6.0
General and Administrative		16.3		9.5		27.7		17.7
Total	$	24.8	$	15.3	$	44.6	$	29.5

EOG's stockholders approved the EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Plan) at the 2008 Annual Meeting of Stockholders. The 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. Under the Plan, grants may be made to employees and non-employee members of EOG's Board of Directors (Board). At June 30, 2008, approximately 6.0 million common shares remained available for grant under the Plan. Effective with the adoption of the Plan, EOG's policy is to issue shares related to the Plan from previously authorized unissued shares.

-7-

Stock Options and Stock Appreciation Rights and Employee Stock Purchase Plan. Participants in EOG's stock plans (including the Plan) have been or may be granted options to purchase shares of common stock of EOG. In addition, participants in EOG's stock plans (including the Plan) have been or may be granted SARs, representing the right to receive shares of EOG common stock based on the appreciation in the stock price from the date of grant on the number of SARs granted. Stock options and SARs are granted at a price not less than the market price of the common stock at the date of grant. Stock options and SARs granted vest on a graded vesting schedule up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Terms for stock options and SARs granted have not exceeded a maximum term of 10 years. EOG also has an employee stock purchase plan (ESPP) in place that allows eligible employees to semi-annually purchase, through payroll deductions, shares of EOG common stock at 85 percent of the fair market value at specified dates. Contributions to the ESPP are limited to 10 percent of the employee's pay (subject to certain ESPP limits) during each of the two six-month offering periods each year.

The fair value of all stock option grants made prior to August 2004 and all ESPP grants is estimated using the Black-Scholes-Merton model. Certain of EOG's stock options granted in 2005 and 2004 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 SARs was estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $8.9 million and $8.7 million during the three months ended June 30, 2008 and 2007, respectively. Such expense totaled $17.8 million and $17.1 million during the six months ended June 30, 2008 and 2007, respectively.

Weighted average fair values and valuation assumptions used to value stock options, SARs and ESPP grants during the six-month periods ended June 30, 2008 and 2007 are as follows:

		Stock Options/SARs				ESPP
		Six Months Ended				Six Months Ended
		June 30,				June 30,
		2008		2007		2008		2007

Weighted Average Fair Value of Grants	$	34.22	$	21.96	$	21.86	$	15.07
Expected Volatility		33.47%		29.35%		31.67%		32.47%
Risk-Free Interest Rate		2.47%		4.83%		3.29%		5.07%
Dividend Yield		0.4%		0.3%		0.4%		0.3%
Expected Life		4.4 yrs		4.8 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.

-8-

The following table sets forth the stock option and SAR transactions for the six-month periods ended June 30, 2008 and 2007 (stock options and SARs in thousands):

	Six Months Ended			Six Months Ended
	June 30, 2008			June 30, 2007
			Weighted			Weighted
	Number of		Average	Number of		Average
	Stock		Grant	Stock		Grant
	Options/SARs		Price	Options/SARs		Price

Outstanding at January 1	9,373	$	41.04	10,150	$	35.29
Granted	51		117.58	216		71.61
Exercised ⁽¹⁾	(1,937)		25.71	(534)		21.86
Forfeited	(64)		61.92	(85)		52.59
Outstanding at June 30 ⁽²⁾	7,423		45.39	9,747		36.67

Vested or Expected to Vest ⁽³⁾	7,192		44.79	9,469		36.19

Exercisable at June 30 ⁽⁴⁾	3,886		30.04	4,998		22.08

(1) The total intrinsic value of stock options/SARs exercised for the six months ended June 30, 2008 and 2007 was $176 million and $27 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 June 30, 2008 and 2007 was $637 million and $355 million, respectively.
      At June 30, 2008 and 2007, the weighted average remaining contractual life was 4.7 years and 5.3 years, respectively.
(3) The total intrinsic value of stock options/SARs vested or expected to vest at June 30, 2008 and 2007 was $621 million and $350 million, respectively.
      At June 30, 2008 and 2007, the weighted average remaining contractual life was 4.7 years and 5.3 years, respectively.
(4) The total intrinsic value of stock options/SARs exercisable at June 30, 2008 and 2007 was $393 million and $255 million, respectively.
      At June 30, 2008 and 2007, the weighted average remaining contractual life was 4.1 years and 4.5 years, respectively.

At June 30, 2008, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $57.2 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.9 years.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. The restricted stock and restricted stock units generally vest five years after the date of grant, except for certain bonus grants, and as defined in individual grant agreements. Upon vesting of restricted stock, common shares are released to the employee. Restricted stock units are converted into common shares upon vesting and released to the employee. Stock-based compensation expense related to restricted stock and restricted stock units totaled $15.9 million and $6.6 million for the three months ended June 30, 2008 and 2007, respectively, and $26.8 million and $12.4 million for the six months ended June 30, 2008 and 2007, respectively.

-9-

The following table sets forth the restricted stock and restricted stock units transactions for the six-month periods ended June 30, 2008 and 2007 (shares and units in thousand):

	Six Months Ended			Six Months Ended
	June 30, 2008			June 30, 2007
			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	3,000	$	50.61	2,301	$	36.13
Granted	374		125.06	520		67.99
Released ⁽¹⁾	(181)		21.43	(245)		18.37
Forfeited	(32)		66.47	(47)		53.13
Outstanding at June 30 ⁽²⁾	3,161		60.91	2,529		44.08

(1) The total intrinsic value of restricted stock and restricted stock units released for the six months ended June 30, 2008 and
      2007 was $19 million and $16 million, respectively. The intrinsic value is based upon the closing price of EOG's common
      stock on the date restricted stock and restricted stock units are released.
(2) The total intrinsic value of restricted stock and restricted stock units outstanding at June 30, 2008 and 2007 was approximately
      $415 million and $185 million, respectively.

At June 30, 2008, unrecognized compensation expense related to restricted stock and restricted stock units totaled $121.0 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 3.0 years.

3. Earnings Per Share

The following table sets forth the computation of Net Income Per Share Available to Common Stockholders for the three-month and six-month periods ended June 30, 2008 and 2007 (in thousands, except per share data):

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2008		2007		2008		2007

Numerator for Basic and Diluted Earnings Per Share -
	Net Income	$	178,206	$	307,053	$	419,162	$	524,720
	Less: Preferred Stock Dividends		-		990		443		1,865
	Net Income Available to Common Stockholders	$	178,206	$	306,063	$	418,719	$	522,855

Denominator for Basic Earnings Per Share -
	Weighted Average Shares		246,536		243,227		245,950		242,976
Potential Dilutive Common Shares -
	Stock Options/SARs		3,141		3,077		3,183		2,996
	Restricted Stock and Restricted Stock Units		1,458		957		1,420		1,037
Denominator for Diluted Earnings Per Share -
	Adjusted Diluted Weighted Average Shares		251,135		247,261		250,553		247,009

Net Income Per Share Available to Common Stockholders
	Basic	$	0.72	$	1.26	$	1.70	$	2.15
	Diluted	$	0.71	$	1.24	$	1.67	$	2.12

-10-

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. The excluded stock options and SARs totaled 7,500 and 1.9 million for the three months ended June 30, 2008 and 2007, respectively, and 11,986 and 3.3 million for the six months ended June 30, 2008 and 2007, respectively.

4. Supplemental Cash Flow Information

Cash paid for interest and income taxes for the six-month periods ended June 30, 2008 and 2007 was as follows (in thousands):

		Six Months Ended
		June 30,
		2008		2007

Interest	$	23,780	$	17,226
Income Taxes	$	138,941	$	27,426

5. Comprehensive Income

The following table presents the components of EOG's comprehensive income for the three-month and six-month periods ended June 30, 2008 and 2007 (in thousands):

					Three Months Ended				Six Months Ended
					June 30,				June 30,
					2008		2007		2008		2007
Comprehensive Income
	Net Income			$	178,206	$	307,053	$	419,162	$	524,720
	Other Comprehensive Income (Loss)
		Foreign Currency Translation Adjustments			15,813		132,137		(61,277)		148,489
		Foreign Currency Swap Transaction			(1,983)		3,203		(2,957)		5,353
		Income Tax Benefit (Provision) Related
		to Foreign Currency Swap Transaction			494		(1,090)		733		(1,705)
		Deferred Benefit Pension and
		Postretirement Plans			35		40		70		77
		Income Tax Provision Related to Defined
		Benefit Pension and Postretirement Plans			(12)		-		(76)		-
			Total	$	192,553	$	441,343	$	355,655	$	676,934

-11-

6. Segment Information

Selected financial information by reportable segment is presented below for the three-month and six-month periods ended June 30, 2008 and 2007 (in thousands):

				Three Months Ended				Six Months Ended
				June 30,				June 30,
				2008		2007		2008		2007

Net Operating Revenues
	United States		$	701,008	$	826,475	$	1,506,010	$	1,451,658
	Canada			215,061		158,826		385,515		302,293
	Trinidad			105,131		73,830		215,015		160,938
	United Kingdom			11,326		9,356		26,959		24,835
		Total	$	1,032,526	$	1,068,487	$	2,133,499	$	1,939,724

Operating Income (Loss)
	United States		$	64,471	$	342,110	$	295,029	$	555,059
	Canada			115,535		70,138		175,323		128,935
	Trinidad			64,159		52,810		152,561		116,400
	United Kingdom			4,207		434		12,385		3,400
	Other			(5,269)		(10)		(11,475)		(72)
		Total		243,103		465,482		623,823		803,722

Reconciling Items
	Other Income, Net			13,309		11,205		14,892		15,924
	Interest Expense, Net			9,029		10,818		21,220		18,456
		Income Before Income Taxes	$	247,383	$	465,869	$	617,495	$	801,190

Total assets by reportable segment are presented below at June 30, 2008 and December 31, 2007 (in thousands):

				At			At
				June 30,			December 31,
				2008			2007
Total Assets
	United States		$	10,692,841		$	8,687,320
	Canada			2,699,331			2,649,925
	Trinidad			758,900			692,353
	United Kingdom			52,718			58,255
	Other			20,977	(1)		1,054
		Total	$	14,224,767		$	12,088,907

(1) Includes amounts on deposit at June 30, 2008 in connection with the July 2008 acquisition from
ConocoPhillips of rights under a Petroleum Contract covering the Chuanzhong Block exploration area in Sichuan Basin,
Sichuan Province, The People's Republic of China.

-12-

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," for the six-month periods ended June 30, 2008 and 2007 (in thousands):

			Six Months Ended
			June 30,
			2008		2007

Carrying Amount at Beginning of Period		$	211,124	$	182,407
	Liabilities Incurred		15,246		10,123
	Liabilities Settled		(13,795)		(5,339)
	Accretion		5,801		5,062
	Revisions		5,217		(126)
	Foreign Currency Translations		(2,242)		799
Carrying Amount at End of Period		$	221,351	$	192,926

Current Portion		$	5,318	$	8,614
Noncurrent Portion		$	216,033	$	184,312

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

8. Suspended Well Costs

EOG's net changes in suspended well costs for the six-month period ended June 30, 2008 in accordance with FSP No. 19-1, "Accounting for Suspended Well Costs," are presented below (in thousands):

			Six Months
			Ended
			June 30,
			2008

Balance at December 31, 2007		$	148,881
	Additions Pending the Determination of Proved Reserves		111,255
	Reclassifications to Proved Properties		(85,800)
	Charged to Dry Hole Costs		(9,022)
	Foreign Currency Translations		(1,913)
Balance at June 30, 2008		$	163,401

-13-

The following table provides an aging of suspended well costs at June 30, 2008 (in thousands, except project count):

			At
			June 30,
			2008

Capitalized exploratory well costs that have been
	capitalized for a period less than one year	$	98,866
Capitalized exploratory well costs that have been
	capitalized for a period greater than one year		64,535	(1)
	Total	$	163,401
Number of projects that have exploratory well costs that have been
	capitalized for a period greater than one year		3

(1) Costs related to two shale projects in British Columbia (B.C.), Canada ($50.9 million) and an outside-operated offshore Central
      North Sea project in the United Kingdom ($13.6 million). In the B.C. projects, drilling and completion activities are continuing and
      further reserve evaluation will be made based on initial production during the second half of 2008. EOG is evaluating infrastructure
      alternatives for the B.C. shale projects. In the Central North Sea project, EOG is planning a phased development and considering
      alternative export routes. A development plan decision is expected in early 2009.

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.

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 six months ended June 30, 2008 and 2007, EOG's total costs recognized for these pension plans were $9.7 million and $8.0 million, respectively.

In addition, as more fully discussed in Note 6 to Consolidated Financial Statements included in EOG's 2007 Annual Report, EOG's Canadian, Trinidadian and United Kingdom subsidiaries maintain various pension and savings plans for most of their respective employees. For the six months ended June 30, 2008 and 2007, combined contributions to these pension plans were $1.2 million and $1.0 million, respectively.

Postretirement Plan. EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents. For the six months ended June 30, 2008, EOG's total contributions to these plans were approximately $58,000. The net periodic benefit costs recognized for the postretirement medical and dental plans were approximately $373,000 and $357,500, respectively, for the six months ended June 30, 2008 and 2007.

-14-

11. Long-Term Debt, Preferred Stock and Common Stock

Long-Term Debt. EOG utilizes commercial paper and short-term borrowings from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding borrowings from commercial paper or uncommitted credit facilities at June 30, 2008. The weighted average interest rates for commercial paper and uncommitted credit facility borrowings for the six months ended June 30, 2008 were 3.25% and 3.37%, respectively.

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 June 30, 2008, 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 June 30, 2008, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 2.65% and 5.00%, 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 June 30, 2008, $37 million remained outstanding under the Credit Agreement. The applicable Eurodollar rate at June 30, 2008 was 2.88%. The weighted average Eurodollar rate for the amounts outstanding during the first six months of 2008 was 3.63%.

Preferred Stock. In January 2008, EOG repurchased the remaining outstanding 5,000 shares of its 7.195% Fixed Rate Cumulative Senior Perpetual Preferred Stock, Series B, with a $1,000 liquidation preference per share (Series B), for approximately $5.4 million plus accrued dividends up to the date of repurchase. The premium of $0.4 million associated with the repurchase has been included as a component of preferred stock dividends. In March 2008, the Board approved the filing with the Delaware Secretary of State of a Certificate of Elimination with respect to the Series B. The Certificate of Elimination provides that all matters set forth in the Certificate of Designation, Preferences and Rights, filed on July 19, 2000 with the Delaware Secretary of State with respect to the Series B, are eliminated from EOG's Restated Certificate of Incorporation.

Common Stock. On February 7, 2008, the Board increased the quarterly cash dividend on EOG's common stock from the previous $0.09 per share to $0.12 per share effective with the dividend paid on April 30, 2008 to record holders as of April 16, 2008. On July 28, 2008, the Board increased the quarterly cash dividend on EOG's common stock from the previous $0.12 per share to $0.135 per share effective with the dividend payable on October 31, 2008 to record holders as of October 17, 2008.

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 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 its own credit risk when measuring financial assets and liabilities at fair value. In accordance with FSP 157-2, EOG has not applied the provisions of SFAS No. 157 to its asset retirement obligations or in the measurement of nonfinancial long-lived assets under SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets."

-15-

The following table provides fair value measurement information within the hierarchy for EOG's financial assets and liabilities at June 30, 2008 (in millions):

			At June 30, 2008
			Fair Value Measurements Using:
			Quoted		Significant
			Prices in		Other		Significant
			Active		Observable		Unobservable
			Markets		Inputs		Inputs
			(Level 1)		(Level 2)		(Level 3)		Collateral ⁽¹⁾		Total
Financial Assets (Liabilities):
	Crude oil and natural
	gas price swaps	$	-	$	(1,084)	$	-	$	44	$	(1,040)
	Foreign currency rate
	swap	$	-	$	(55)	$	-	$	-	$	(55)

(1) Represents cash collateral on deposit with counterparties where the right of offset exists.

The estimated fair value of crude oil and natural gas price 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.

13. Sale of Appalachian Properties

In February 2008, EOG completed a sale of the majority of its producing shallow gas assets and surrounding acreage in the Appalachian Basin to a subsidiary of EXCO Resources, Inc., an independent oil and gas company. The Appalachian area divested included approximately 2,400 operated wells that accounted for approximately 1% of EOG's total 2007 production and approximately 2% of its total year-end 2007 proved reserves. Net proceeds from the sale, including a $40 million deposit received in December 2007, totaled $386 million. The purchase price is subject to customary adjustments under the agreement. EOG retained certain of its undeveloped acreage in this area, including rights in the Marcellus Shale, and will continue its shale exploration program. EOG recognized a pre-tax gain of $128 million on the sale of these properties that is included in Net Operating Revenues - Other, Net on the Consolidated Statements of Income.

-16-

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 (EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Canada, offshore 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.

Operations. EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's natural gas and crude oil production. Production in the United States and Canada accounted for approximately 86% of total company production in the first six months of 2008 as compared to 82% in the same period of 2007. For the first six months of 2008, crude oil and natural gas liquids production accounted for approximately 17% of total company production as compared to 14% for the same period of 2007. Based on current trends, EOG expects its production profile for the remainder of 2008 to be similar to the first six months of 2008. EOG's major producing areas are in New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

In the first six months of 2008, EOG's Trinidad operations realized higher prices for natural gas sales as compared to the same period of 2007. This increase was due to higher ammonia, methanol and liquefied natural gas prices as certain of EOG's contracts provide for prices which are either entirely or partially dependent upon the prices of these commodities. In the second quarter of 2008, EOG decided to relinquish its rights to Block Lower Reverse "L" (LRL) resulting in an impairment of $20 million.

In addition to EOG's ongoing production from the Valkyrie and Arthur Fields in the United Kingdom North Sea, EOG is evaluating development plans for its Columbus prospect in the Central North Sea Block 23/16f. A phased development and alternative export routes are being considered and a development plan decision is expected in early 2009.

On July 1, 2008, EOG acquired rights under a Petroleum Contract covering the Chuanzhong Block exploration area in Sichuan Basin, Sichuan Province, The People's Republic of China from ConocoPhillips. The acquisition includes production of approximately 8 million cubic feet equivalent per day, net, on 130,000 acres.

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. EOG's debt-to-total capitalization ratio was 13% at June 30, 2008 compared to 14% at December 31, 2007. During the first six months of 2008, EOG funded $2.5 billion in exploration and development and other property, plant and equipment expenditures, paid $52 million in dividends to common and preferred stockholders, repaid $38 million of debt and paid $5 million for the redemption of all remaining shares of its outstanding 7.195% Fixed Rate Cumulative Senior Perpetual Preferred Stock primarily by utilizing cash provided from its operating activities and proceeds from the sale of its Appalachian properties. Cash on hand increased to $108 million at June 30, 2008 from $54 million at December 31, 2007. Management continues to assess price forecast and demand trends for 2008 and believes that operations and capital expenditure activity can be funded with cash from operating activities.

EOG's 2008 budget for exploration and development and other property, plant and equipment expenditures is approximately $4.8 billion, excluding acquisitions. United States and Canada natural gas drilling activity continues to be a key component of these expenditures. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe that EOG currently has one of the strongest prospect inventories in EOG's history.

-17-

Results of Operations

The following review of operations for the three and six months ended June 30, 2008 and 2007 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included with this Quarterly Report on Form 10-Q.

Three Months Ended June 30, 2008 vs. Three Months Ended June 30, 2007

Net Operating Revenues. During the second quarter of 2008, net operating revenues decreased $35 million, or 3%, to $1,033 million from $1,068 million for the same period of 2007. Total wellhead revenues for the second quarter of 2008, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, increased $860 million, or 86%, to $1,865 million from $1,005 million for the same period of 2007. During the second quarter of 2008, EOG recognized a loss on mark-to-market commodity derivative contracts of $843 million compared to a net gain of $44 million for the same period of 2007.

-18-

Wellhead volume and price statistics for the three-month periods ended June 30, 2008 and 2007 were as follows:

				Three Months Ended
				June 30,
				2008		2007
Natural Gas Volumes (MMcfd) ⁽¹⁾
	United States			1,139		960
	Canada			215		232
	Trinidad			217		250
	United Kingdom			12		22
		Total		1,583		1,464

Average Natural Gas Prices ($/Mcf) ⁽²⁾
	United States		$	10.36	$	6.74
	Canada			9.42		6.70
	Trinidad			3.64		2.04
	United Kingdom			9.95		4.35
		Composite		9.31		5.90

Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
	United States			35.4		23.4
	Canada			2.6		2.4
	Trinidad			3.2		4.0
	United Kingdom			-		0.1
		Total		41.2		29.9

Average Crude Oil and Condensate Prices ($/Bbl) ⁽²⁾
	United States		$	117.60	$	61.38
	Canada			112.55		60.08
	Trinidad			113.29		75.16
	United Kingdom			114.40		68.82
		Composite		116.94		63.15

Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
	United States			14.2		10.4
	Canada			0.9		1.1
		Total		15.1		11.5

Average Natural Gas Liquids Prices ($/Bbl) ⁽²⁾
	United States		$	63.62	$	45.35
	Canada			66.39		42.30
		Composite		63.78		45.04

Natural Gas Equivalent Volumes (MMcfed) ⁽³⁾
	United States			1,437		1,163
	Canada			236		253
	Trinidad			236		274
	United Kingdom			12		23
		Total		1,921		1,713

Total Bcfe ⁽³⁾				174.8		155.8

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids. Natural gas
equivalents are determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil, condensate or natural gas liquids.

-19-

Wellhead natural gas revenues for the second quarter of 2008 increased $555 million, or 71%, to $1,341 million from $786 million for the same period of 2007. The increase was due to a higher composite average wellhead natural gas price ($491 million) and increased natural gas deliveries ($64 million). The composite average wellhead price for natural gas increased 58% to $9.31 per million cubic feet (Mcf) for the second quarter of 2008 from $5.90 per Mcf for the same period of 2007.

Natural gas deliveries increased 119 MMcfd, or 8%, to 1,583 MMcfd for the second quarter of 2008 from 1,464 MMcfd for the same period of 2007. The increase was primarily due to higher production in the United States (179 MMcfd), partially offset by decreased production in Trinidad (33 MMcfd), Canada (17 MMcfd) and the United Kingdom (10 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (142 MMcfd) and the Rocky Mountain area (40 MMcfd), partially offset by decreased production due to the February 2008 sale of the Appalachian assets (17 MMcfd). The decline in Trinidad was primarily due to decreased deliveries as a result of plant shutdowns due to maintenance activities (35 MMcfd), partially offset by increased deliveries to Atlantic LNG Train 4 (ALNG) (5 MMcfd).

Wellhead crude oil and condensate revenues for the second quarter of 2008 increased $265 million, or 155%, to $437 million from $172 million for the same period of 2007. The increase was due to a higher composite average wellhead crude oil and condensate price ($201 million) and increased wellhead crude oil and condensate deliveries ($64 million). The composite average wellhead crude oil and condensate price for the second quarter of 2008 increased 85% to $116.94 per barrel from $63.15 per barrel for the same period of 2007. The increase in deliveries was primarily due to increased production in North Dakota.

Natural gas liquids revenues for the second quarter of 2008 increased $41 million, or 86%, to $88 million from $47 million for the same period of 2007. The increase was due to a higher composite average price ($26 million) and increased deliveries ($15 million). The composite average natural gas liquids price for the second quarter of 2008 increased 42% to $63.78 per barrel from $45.04 per barrel for the same period of 2007. The increase in deliveries primarily reflects increased production in the Fort Worth Basin Barnett Shale Play.

As a result of increasing natural gas and crude oil prices, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $843 million for the second quarter of 2008 compared to a net gain of $44 million for the same period of 2007. During the second quarter of 2008, the cash outflow related to settled natural gas and crude oil financial price swap contracts was $138 million compared to the net cash inflow related to settled natural gas and crude oil financial price swap contracts of $19 million for the same period of 2007.

Operating and Other Expenses. For the second quarter of 2008, operating expenses of $790 million were $187 million higher than the $603 million incurred in the second quarter of 2007. The following table presents the costs per Mcfe for the three-month periods ended June 30, 2008 and 2007:

			Three Months Ended
			June 30,
			2008		2007

Lease and Well		$	0.79	$	0.79
Transportation Costs			0.36		0.24
Depreciation, Depletion and Amortization (DD&A)			1.80		1.67
General and Administrative (G&A)			0.35		0.30
Interest Expense, Net			0.05		0.07
	Total Per-Unit Costs⁽¹⁾	$	3.35	$	3.07

(1) Total per-unit costs do not include exploration costs, dry hole costs, impairments and taxes other than income.

The primary factors impacting per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the three months ended June 30, 2008 compared to the same period of 2007 are set forth below.

-20-

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

Each of these categories of costs individually fluctuate from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses of $139 million for the second quarter of 2008 increased $16 million from $123 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($13 million) and higher lease and well administrative expenses ($9 million), partially offset by lower operating and maintenance expenses in Canada ($5 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 $63 million for the second quarter of 2008 increased $26 million from $37 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 Play ($10 million) and the Rocky Mountain area ($11 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 performance, and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from quarter to quarter.

DD&A expenses of $315 million for the second quarter of 2008 increased $56 million from the same prior year period primarily due to increased production in the United States ($49 million), increased DD&A rates in the United States ($5 million) and Canada ($4 million) and unfavorable changes in the Canadian exchange rate ($4 million), partially offset by decreased production in Canada ($3 million) and the United Kingdom ($2 million).

G&A expenses of $62 million for the second quarter of 2008 were $14 million higher than the same prior year period primarily due to higher employee-related costs ($13 million).

Interest expense, net of $9 million for the second quarter of 2008 decreased $2 million compared to the same prior year period primarily due to higher capitalized interest ($3 million).

Exploration costs of $60 million for the second quarter of 2008 increased $18 million from the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($15 million) and higher employee-related costs ($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 $49 million for the second quarter of 2008 increased $28 million from $21 million for the same prior year period primarily due to SFAS No. 144 related impairment in Trinidad as a result of EOG's relinquishment of its rights to LRL ($20 million) and increased amortization of unproved leases in the United

-21-

States ($5 million) and Canada ($4 million). Under SFAS No. 144, EOG recorded impairments of $24 million and $6 million for the second quarter of 2008 and 2007, 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 for the second quarter of 2008 increased $33 million to $95 million (5.1% of wellhead revenues) from $62 million (6.2% of wellhead revenues) for the same prior year period primarily due to an increase in severance/production taxes as a result of increased wellhead revenues in the United States. The decline in taxes other than income as a percentage of wellhead revenues primarily reflects higher wellhead revenues combined with a slight decline in non-revenue based taxes.

Income tax provision of $69 million for the second quarter of 2008 decreased $90 million compared to the same prior year period due primarily to decreased pretax income. The net effective tax rate for the second quarter of 2008 decreased to 28% from 34% for the same prior year period primarily as a result of tax benefits related to the impairment of LRL.

Six Months Ended June 30, 2008 vs. Six Months Ended June 30, 2007

Net Operating Revenues. During the first six months of 2008, net operating revenues increased $193 million, or 10%, to $2,133 million from $1,940 million for the same period of 2007. Total wellhead revenues for the first six months of 2008 increased $1,388 million, or 73%, to $3,298 million from $1,910 million for the same period of 2007. During the first six months of 2008, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $1,313 million compared to a net gain of $4 million for the same period of 2007.

-22-

Wellhead volume and price statistics for the six-month periods ended June 30, 2008 and 2007 were as follows:

				Six Months Ended
				June 30,
				2008		2007
Natural Gas Volumes (MMcfd)
	United States			1,112		938
	Canada			215		227
	Trinidad			224		251
	United Kingdom			15		26
		Total		1,566		1,442

Average Natural Gas Prices ($/Mcf)
	United States		$	9.23	$	6.55
	Canada			8.42		6.57
	Trinidad			3.76		2.42
	United Kingdom			9.89		5.04
		Composite		8.34		5.81

Crude Oil and Condensate Volumes (MBbld)
	United States			33.0		22.6
	Canada			2.5		2.5
	Trinidad			3.4		4.2
	United Kingdom			-		0.1
		Total		38.9		29.4

Average Crude Oil and Condensate Prices ($/Bbl)
	United States		$	105.78	$	57.75
	Canada			101.41		55.88
	Trinidad			99.92		67.32
	United Kingdom			96.84		59.61
		Composite		104.97		58.96

Natural Gas Liquids Volumes (MBbld)
	United States			15.5		10.0
	Canada			0.9		1.1
		Total		16.4		11.1

Average Natural Gas Liquids Prices ($/Bbl)
	United States		$	60.19	$	41.40
	Canada			61.52		39.39
		Composite		60.26		41.20

Natural Gas Equivalent Volumes (MMcfed)
	United States			1,403		1,134
	Canada			236		248
	Trinidad			244		276
	United Kingdom			15		27
		Total		1,898		1,685

Total Bcfe				345.4		305.0

-23-

Wellhead natural gas revenues for the first six months of 2008 increased $862 million, or 57%, to $2,378 million from $1,516 million for the same period of 2007. The increase was due to a higher composite wellhead natural gas price ($723 million) and increased natural gas deliveries ($139 million). The composite average wellhead price for natural gas increased 44% to $8.34 per Mcf for the first six months of 2008 from $5.81 per Mcf for the same period of 2007.

Natural gas deliveries increased 124 MMcfd, or 9%, to 1,566 MMcfd for the first six months of 2008 from 1,442 MMcfd for the same period of 2007. The increase was due to higher production in the United States (174 MMcfd), partially offset by decreased production in Trinidad (27 MMcfd), Canada (12 MMcfd) and the United Kingdom (11 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (137 MMcfd), the Rocky Mountain area (30 MMcfd), Mississippi (13 MMcfd) and Kansas (6 MMcfd), partially offset by decreased production due to the February 2008 sale of the Appalachian assets (12 MMcfd). The decline in Trinidad was primarily due to decreased deliveries as a result of plant shutdowns due to maintenance activities (24 MMcfd) and a decrease in overall contractual demand (11 MMcfd), partially offset by increased deliveries to ALNG (8 MMcfd).

Wellhead crude oil and condensate revenues for the first six months of 2008 increased $429 million, or 138%, to $740 million from $311 million for the same period of 2007. The increase was due to a higher composite average wellhead crude oil and condensate price ($324 million) and increased wellhead crude oil and condensate deliveries ($105 million). The composite average wellhead crude oil and condensate price increased 78% to $104.97 per barrel for the first six months of 2008 from $58.96 per barrel for the same period of 2007. The increase in deliveries was primarily due to increased production in North Dakota.

Natural gas liquids revenues for the first six months of 2008 increased $97 million, or 118%, to $180 million from $83 million for the same period of 2007. The increase was due to a higher composite average price ($57 million) and increased deliveries ($40 million). The composite average natural gas liquids price for the first six months of 2008 increased 46% to $60.26 per barrel from $41.20 per barrel for the same period of 2007. The increase in deliveries primarily reflects increased production in the Fort Worth Basin Barnett Shale Play.

As a result of increasing natural gas and crude oil prices, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $1,313 million for the first six months of 2008 compared to a net gain of $4 million for the same period of 2007. During the first six months of 2008, the net cash outflow related to settled natural gas and crude oil financial price swap contracts was $115 million compared to the net cash inflow related to settled natural gas and crude oil financial price swap contracts of $66 million for the same period of 2007.

Operating and Other Expenses. For the first six months of 2008, operating expenses of $1,510 million were $374 million higher than the $1,136 million incurred in the same period of 2006. The following table presents the costs per Mcfe for the six-month periods ended June 30, 2008 and 2007:

			Six Months Ended
			June 30,
			2008		2007

Lease and Well		$	0.79	$	0.75
Transportation Costs			0.36		0.23
DD&A			1.77		1.65
G&A			0.33		0.30
Interest Expense, Net			0.06		0.06
	Total Per-Unit Costs⁽¹⁾	$	3.31	$	2.99

(1) Total per-unit costs do not include exploration costs, dry hole costs, impairments and taxes other than income.

The primary factors impacting per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the six months ended June 30, 2008 compared to the same period of 2007 are set forth below.

-24-

Lease and well expenses of $271 million for the first six months of 2008 were $44 million higher than the same prior year period primarily due to higher operating and maintenance expenses in the United States ($30 million) and higher lease and well administrative expenses ($16 million).

Transportation costs of $125 million for the first six months of 2008 increased $55 million from $70 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 Play ($26 million) and the Rocky Mountain area ($19 million) to downstream markets.

DD&A expenses of $612 million for the first six months of 2008 increased $108 million from the same prior year period primarily due to increased production in the United States ($97 million), unfavorable changes in the Canadian exchange rate ($11 million) and increased DD&A rates in the United States ($7 million) and Canada ($5 million), partially offset by decreased production in the United Kingdom ($5 million) and Canada ($3 million) and decreased DD&A rates in the United Kingdom ($2 million).

G&A expenses of $115 million for the first six months of 2008 were $24 million higher than the same prior year period primarily due to higher employee-related expenses ($19 million) and an increase in legal fees and other professional services ($4 million).

Interest expense, net was $21 million for the first six months of 2008, up $3 million compared to the same prior year period primarily due to higher average debt balance ($9 million), partially offset by higher capitalized interest ($6 million).

Exploration costs of $107 million for the first six months of 2008 increased $40 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($31 million) and higher employee-related costs ($6 million). The increase in the United States was primarily attributable to the Fort Worth Basin Barnett Shale Play ($18 million).

Impairments of $81 million for the first six months of 2008 increased $36 million from $45 million for the same prior year period primarily due to SFAS No. 144 related impairment in Trinidad as a result of EOG's relinquishment of its rights to LRL ($20 million) and increased amortization of unproved leases in the United States ($12 million) and Canada ($7 million). Under SFAS No. 144, EOG recorded impairments of $33 million and $16 million for the six months ended June 30, 2008 and 2007, respectively.

Taxes other than income for the first six months of 2008 increased $79 million to $182 million (5.5% of wellhead revenues) from $103 million (5.4% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes primarily as a result of increased wellhead revenues in the United States ($57 million) and Trinidad ($2 million) and a decrease in credits taken for Texas high cost gas severance tax rate reductions ($16 million).

Income tax provision of $198 million for the first six months of 2008 decreased $78 million compared to the same prior year period due primarily to decreased pretax income. The net effective tax rate for the first six months of 2008 decreased to 32% from 35% for the same prior year period primarily as a result of tax benefits related to the impairment of LRL.

-25-

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2008 were funds generated from operations, proceeds from the sale of its producing shallow gas assets and surrounding acreage in the Appalachian Basin, proceeds from stock options exercised and employee stock purchase plan activity and excess tax benefits from stock-based compensation. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; dividend payments to stockholders; and Trinidad revolving credit facility repayment. During the first six months of 2008, EOG's cash balance increased $54 million to $108 million from $54 million at December 31, 2007.

Net cash provided by operating activities of $2,063 million for the first six months of 2008 increased $636 million compared to the same period of 2007 primarily reflecting an increase in wellhead revenues ($1,388 million), partially offset by an increase in cash operating expenses ($221 million), unfavorable changes in working capital and other assets and liabilities ($212 million), an unfavorable change in the net cash flow from the settlement of financial commodity derivative contracts ($181 million), an increase in cash paid for income taxes ($112 million) and an increase in cash paid for interest expense ($7 million).

Net cash used in investing activities of $2,006 million for the first six months of 2008 increased by $284 million compared to the same period of 2007 due primarily to an increase in additions to oil and gas properties ($523 million), partially offset by an increase in proceeds from sales of assets ($316 million), primarily reflecting net proceeds from the sale of EOG's Appalachian assets.

Net cash provided by financing activities was $2 million for the first six months of 2008 compared to $132 million for the same period of 2007. Cash provided by financing activities for the first six months of 2008 included excess tax benefits from stock-based compensation ($56 million) and proceeds from stock options exercised and employee stock purchase plan activity ($48 million). Cash used by financing activities for the first six months of 2008 included cash dividend payments ($52 million), Trinidad revolving credit facility repayment ($38 million), treasury stock repurchased ($7 million) and the redemption of preferred stock ($5 million).

Total Expenditures. The table below sets out components of total expenditures for the six-month periods ended June 30, 2008 and 2007 (in millions):

				Six Months Ended
				June 30,
				2008		2007
Expenditure Category
Capital
		Drilling and Facilities	$	1,856	$	1,451
		Leasehold Acquisitions		218		127
		Producing Property Acquisitions		35		1
		Capitalized Interest		20		13
		Subtotal		2,129		1,592
Exploration Costs				107		68
Dry Hole Costs				15		29
	Exploration and Development Expenditures			2,251		1,689
Asset Retirement Costs				22		11
	Total Exploration and Development Expenditures			2,273		1,700
	Other Property, Plant and Equipment			196		158
	Total Expenditures		$	2,469	$	1,858

Exploration and development expenditures of $2,251 million for the first six months of 2008 were $562 million higher than the same period of 2007 due primarily to increased drilling and facilities expenditures ($405 million), increased lease acquisitions in Canada ($44 million) and in the United States ($39 million), increased geological and geophysical expenditures in the United States ($31 million) and changes in the Canadian exchange rate ($23 million). The increased drilling and facilities expenditures of $405 million primarily resulted from higher drilling

-26-

and facilities expenditures in the United States ($499 million), partially offset by lower drilling and facilities expenditures in Trinidad ($55 million) and Canada ($51 million). The exploration and development expenditures for the first six months of 2008 of $2,251 million include $1,682 million in development, $514 million in exploration, $35 million in property acquisitions and $20 million in capitalized interest. The increase in expenditures for other property, plant and equipment was primarily related to gathering systems and processing plants in the Fort Worth Basin Barnett Shale Play and North Dakota. The exploration and development expenditures for the first six months of 2007 of $1,689 million include $1,314 million in development, $361 million in exploration, $13 million in capitalized interest and $1 million in property acquisitions.

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 North Sea 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 Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2007, 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 and price swap contracts, as the means to manage this price risk. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. 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.

-27-

Financial Price Swap Contracts. The total fair value of EOG's natural gas and crude oil financial price swap contracts at June 30, 2008 was a negative $1,084 million, which is reflected as a liability in the Consolidated Balance Sheets. Subsequent to June 30, 2008, EOG has entered into additional natural gas financial price swap contracts for 2009 and 2010. Presented below is a comprehensive summary of EOG's 2008, 2009 and 2010 natural gas and crude oil financial price swap contracts at July 28, 2008. The notional volumes are expressed in million British thermal units per day (MMBtud) and in barrels per day (Bbld) and prices are expressed in dollars per million British thermal units ($/MMBtu) and in dollars per barrel ($/Bbl), as applicable. The average price of EOG's outstanding natural gas financial price swap contracts for 2008 is $8.64 per million British thermal units (MMBtu), for 2009 is $9.71 per MMBtu and for 2010 is $9.87 per MMBtu. The average price of EOG's outstanding crude oil financial price swap contracts is $92.19 per barrel.

Financial Price Swap Contracts
	Natural Gas		Crude Oil
		Weighted		Weighted
	Volume	Average Price	Volume	Average Price
	(MMBtud)	($/MMBtu)	(Bbld)	($/Bbl)
2008
January (closed)	385,000	$ 8.92	-	$ -
February (closed)	420,000	8.88	6,000	90.86
March (closed)	455,000	8.64	10,000	91.02
April (closed)	455,000	8.11	14,000	92.20
May (closed)	455,000	8.10	14,000	92.20
June (closed)	455,000	8.18	14,000	92.20
July ⁽¹⁾	455,000	8.26	14,000	92.20
August	455,000	8.33	14,000	92.20
September	455,000	8.36	14,000	92.20
October	455,000	8.44	14,000	92.20
November	455,000	8.83	14,000	92.20
December	455,000	9.23	4,000	91.96

2009
January	585,000	$10.76	-	-
February	585,000	10.74	-	-
March	585,000	10.50	-	-
April	610,000	9.24	-	-
May	610,000	9.16	-	-
June	610,000	9.21	-	-
July	610,000	9.29	-	-
August	610,000	9.34	-	-
September	610,000	9.36	-	-
October	610,000	9.42	-	-
November	610,000	9.66	-	-
December	610,000	9.98	-	-

-28-

Financial Price Swap Contracts
	Natural Gas		Crude Oil
		Weighted		Weighted
	Volume	Average Price	Volume	Average Price
	(MMBtud)	($/MMBtu)	(Bbld)	($/Bbl)
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	-	-

(1) The natural gas contracts for July 2008 are closed. The crude oil contracts for July 2008 will close on July 31, 2008.

Financial Collar Contracts. Subsequent to June 30, 2008, EOG has entered into natural gas financial collar contracts for 2010. Presented below is a comprehensive summary of EOG's 2010 natural gas financial collar contracts at July 28, 2008. The average floor price of EOG's outstanding natural gas financial collar contracts is $10.00 per MMBtu and the average ceiling price is $12.32 per MMBtu.

Natural Gas Financial Collar Contracts
		Floor Price		Ceiling Price
			Weighted		Weighted
			Average	Ceiling	Average
	Volume	Floor Range	Price	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

-29-

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 regarding EOG's future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "strategy," "intend," "plan," "target" 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 future operating results, the ability to replace or increase reserves or to increase production, or the ability to 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 based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause 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 commodity prices for crude oil, natural gas and related products, foreign currency exchange rates, interest rates and financial market conditions;

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

the timing and impact of liquefied natural gas imports;

changes in demand or prices for ammonia or methanol;

the extent of EOG's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties;

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

the ability to achieve production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reservoir performance;

the availability and cost of drilling rigs, experienced drilling crews, tubular steel and other materials, equipment and services used in drilling and well completions;

the availability, terms and timing of mineral licenses and leases and governmental and other permits and rights of way;

access to surface locations for drilling and production facilities;

the availability and capacity of gathering, processing and pipeline transportation facilities;

the availability of compression uplift capacity;

the extent to which EOG can economically develop its Barnett Shale acreage outside of Johnson County, Texas;

whether EOG is successful in its efforts to more densely develop its acreage in the Barnett Shale and other production areas;

political developments around the world and the enactment of new government policies, legislation and regulations, including environmental regulations;

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

weather, including weather-related delays in the installation of gathering and production facilities.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur. 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.

-30-

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 32 through 36 of EOG's Annual Report on Form 10-K for the year ended December 31, 2007, filed on February 28, 2008; and (ii) Note 11, "Price, Interest Rate and Credit Risk Management Activities," on pages F-27 through F-29, to EOG's Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2007. For additional information regarding EOG's financial commodity derivative contracts and physical commodity contracts, see (i) Note 1 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.

-31-

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

Issuer Purchases of Equity Securities

				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⁾

April 1, 2008 - April 30, 2008	1,393	$	124.55	-	6,386,200
May 1, 2008 - May 31, 2008	6,373		137.59	-	6,386,200
June 1, 2008 - June 30, 2008	2,350		130.27	-	6,386,200
Total	10,116		134.10	-

(1) Represents 10,116 shares that were withheld by or returned to EOG Resources, Inc. (EOG) to satisfy tax withholding obligations that arose
upon the exercise of employee stock options, stock-settled stock appreciation rights or the vesting of restricted stock or restricted stock units.
(2) In September 2001, EOG announced that its Board of Directors authorized the repurchase of up to 10,000,000 shares of EOG's common stock.

-32-

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The 2008 Annual Meeting of Stockholders of EOG Resources, Inc. (Annual Meeting) was held on May 8, 2008 in Houston, Texas for the following purposes: (i) to elect six directors to hold office until EOG's 2009 Annual Meeting of Stockholders and until their respective successors are duly elected and qualified; (ii) to ratify the appointment by the Audit Committee of EOG's Board of Directors (Board) of Deloitte & Touche LLP, independent public accountants, as EOG's auditors for the year ending December 31, 2008; and (iii) to approve the EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan.

Proxies for the Annual Meeting were solicited by the Board pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended, and there was no solicitation in opposition to the Board's nominees for director.

Each of the nominees for director was duly elected, with votes as follows:

	Shares	Shares
Nominee	For	Withheld

George A. Alcorn	222,138,814	4,564,699
Charles R. Crisp	222,231,264	4,472,249
Mark G. Papa	221,545,273	5,158,239
H. Leighton Steward	222,141,714	4,561,799
Donald F. Textor	222,227,010	4,476,503
Frank G. Wisner	221,491,195	5,212,318

The appointment of Deloitte & Touche LLP, independent public accountants, as EOG's auditors for the year ending December 31, 2008, was ratified by EOG's stockholders by the following vote: 224,908,466 shares for; 203,478 shares against; and 1,591,568 shares abstaining.

The EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan was approved by EOG's stockholders by the following vote: 207,924,714 shares for; 8,334,821 shares against; and 1,709,467 shares abstaining.

-33-

ITEM 6. EXHIBITS

10.1 -	EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.2 -	Form of Stock Option Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.2 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.3 -	Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.3 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.4 -	Form of Nonemployee Director Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.4 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.5 -	Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.5 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.6 -	Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.6 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.7 -	Form of Nonemployee Director Restricted Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.7 to EOG's Current Report on Form 8-K, filed May 14, 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

-34-

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: July 29, 2008	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

-35-

EXHIBIT INDEX

Exhibit No.	Description

10.1 -	EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.2 -	Form of Stock Option Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.2 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.3 -	Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.3 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.4 -	Form of Nonemployee Director Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.4 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.5 -	Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.5 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.6 -	Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.6 to EOG's Current Report on Form 8-K, filed May 14, 2008).

10.7 -	Form of Nonemployee Director Restricted Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.7 to EOG's Current Report on Form 8-K, filed May 14, 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

-36-