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, 2007

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, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one): Large Accelerated Filer x Accelerated Filer o Non-accelerated filer 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 issuer's classes of common stock, as of July 25, 2007.

Title of each class		Number of shares
Common Stock, par value $0.01 per share		244,813,916

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, 2007 and 2006 and Six Months Ended June 30, 2007 and 2006	3

		Consolidated Balance Sheets - June 30, 2007 and December 31, 2006	4

		Consolidated Statements of Cash Flows - Six Months Ended June 30, 2007 and 2006	5

		Notes to Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	16

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	29

	ITEM 4.	Controls and Procedures	29

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	30

	ITEM 1A.	Risk Factors	30

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30

	ITEM 4.	Submission of Matters to a Vote of Security Holders	31

	ITEM 6.	Exhibits	31

SIGNATURES			32

EXHIBIT INDEX			33

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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				Six Months Ended
				June 30,				June 30,
				2007		2006		2007		2006


Net Operating Revenues
	Wellhead Natural Gas		$	790,456	$	642,969	$	1,526,098	$	1,432,030
	Wellhead Crude Oil, Condensate and Natural
	Gas Liquids			218,696		185,036		393,560		369,754
	Gains on Mark-to-Market Commodity
	Derivative Contracts			44,103		91,022		4,302		198,046
	Other, Net			1,988		61		6,496		3,794
		Total		1,055,243		919,088		1,930,456		2,003,624

Operating Expenses
	Lease and Well			123,188		87,287		227,513		174,771
	Transportation Costs			41,591		25,913		79,339		54,009
	Exploration Costs			41,216		35,313		67,600		74,705
	Dry Hole Costs			11,816		14,668		28,626		25,394
	Impairments			20,804		22,680		44,846		45,453
	Depreciation, Depletion and Amortization			259,780		192,928		504,122		370,580
	General and Administrative			47,183		38,607		91,062		74,898
	Taxes Other Than Income			62,047		46,858		102,695		100,552
		Total		607,625		464,254		1,145,803		920,362

Operating Income				447,618		454,834		784,653		1,083,262
Other Income, Net				29,069		21,844		34,993		36,400
Income Before Interest Expense and Income Taxes				476,687		476,678		819,646		1,119,662
Interest Expense, Net				10,818		12,384		18,456		25,537
Income Before Income Taxes				465,869		464,294		801,190		1,094,125
Income Tax Provision				158,816		132,877		276,470		336,001
Net Income				307,053		331,417		524,720		758,124
Preferred Stock Dividends				990		1,858		1,865		3,716
Net Income Available to Common			$	306,063	$	329,559	$	522,855	$	754,408

Net Income Per Share Available to Common
	Basic		$	1.26	$	1.36	$	2.15	$	3.13
	Diluted		$	1.24	$	1.34	$	2.12	$	3.07

Average Number of Common Shares
	Basic			243,227		241,613		242,976		241,370
	Diluted			247,261		245,887		247,009		245,827

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)

					June 30,		December 31,
					2007		2006
ASSETS
Current Assets
		Cash and Cash Equivalents		$	58,534	$	218,255
		Accounts Receivable, Net			741,907		754,134
		Inventories			116,300		113,591
		Assets from Price Risk Management Activities			60,850		130,612
		Income Taxes Receivable			39,671		94,311
		Other			46,506		39,177
			Total		1,063,768		1,350,080

Oil and Gas Properties (Successful Efforts Method)					15,890,787		13,893,851
		Less: Accumulated Depreciation, Depletion and Amortization			(6,550,931)		(5,949,804)
			Net Oil and Gas Properties		9,339,856		7,944,047
Other Assets					120,640		108,033
Total Assets				$	10,524,264	$	9,402,160


LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
		Accounts Payable		$	925,829	$	896,572
		Accrued Taxes Payable			101,372		130,984
		Dividends Payable			22,052		14,718
		Deferred Income Taxes			54,895		144,615
		Other			54,384		68,123
			Total		1,158,532		1,255,012

Long-Term Debt					883,842		733,442
Other Liabilities					328,121		300,907
Deferred Income Taxes					1,861,180		1,513,128

Shareholders' Equity
Preferred Stock, $0.01 Par, 10,000,000 Shares Authorized:
		Series B, Cumulative, $1,000 Liquidation Preference per Share,
		53,260 Shares Outstanding at June 30, 2007 and December 31,
	2006				52,951		52,887
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
249,460,000 Shares Issued					202,495		202,495
Additional Paid in Capital					162,594		129,986
Accumulated Other Comprehensive Income					328,918		176,704
Retained Earnings					5,640,660		5,151,034
Common Stock Held in Treasury, 4,655,082 Shares at
June 30, 2007 and 5,724,959 Shares at December 31, 2006					(95,029)		(113,435)
			Total Shareholders' Equity		6,292,589		5,599,671
Total Liabilities and Shareholders' Equity				$	10,524,264	$	9,402,160

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)

				Six Months Ended
				June 30,
				2007		2006
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	524,720	$	758,124
	Items Not Requiring Cash
		Depreciation, Depletion and Amortization		504,122		370,580
		Impairments		44,846		45,453
		Stock-Based Compensation Expenses		29,542		19,618
		Deferred Income Taxes		223,591		153,552
		Other, Net		(4,912)		(7,485)
	Dry Hole Costs			28,626		25,394
	Mark-to-Market Commodity Derivative Contracts
		Total Gains		(4,302)		(198,046)
		Realized Gains		65,880		93,913
	Other, Net			(3,951)		4,710
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		20,734		169,350
		Inventories		(2,476)		(35,066)
		Accounts Payable		14,651		(5,225)
		Accrued Taxes Payable		26,191		(11,470)
		Other Assets		(4,683)		28,160
		Other Liabilities		(20,420)		(25,422)
	Changes in Components of Working Capital Associated with
		Investing and Financing Activities		(20,471)		(9,708)
Net Cash Provided by Operating Activities				1,421,688		1,376,432

Investing Cash Flows
	Additions to Oil and Gas Properties			(1,748,483)		(1,189,927)
	Proceeds from Sales of Assets			37,988		14,553
	Changes in Components of Working Capital Associated with
		Investing Activities		20,412		9,742
	Other, Net			(32,114)		(14,256)
Net Cash Used in Investing Activities				(1,722,197)		(1,179,888)

Financing Cash Flows
	Net Commercial Paper and Revolving Credit Facility Borrowings			180,400		10,000
	Long-Term Debt Repayments			(30,000)		(102,550)
	Dividends Paid			(38,370)		(27,712)
	Excess Tax Benefits from Stock-Based Compensation Expenses			11,122		20,841
	Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			14,089		11,143
	Other, Net			(194)		(214)
Net Cash Provided by (Used in) Financing Activities				137,047		(88,492)

Effect of Exchange Rate Changes on Cash				3,741		7,245

(Decrease) Increase in Cash and Cash Equivalents				(159,721)		115,297
Cash and Cash Equivalents at Beginning of Period				218,255		643,811
Cash and Cash Equivalents at End of Period			$	58,534	$	759,108

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. and 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. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures are adequate to make the 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, 2006 (EOG's 2006 Annual Report).

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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, 2007 are not necessarily indicative of the results to be expected for the full year.

On January 31, 2007, the Board of Directors of EOG (Board) increased the quarterly cash dividend on the common stock from the previous $0.06 per share to $0.09 per share effective with the dividend paid on April 30, 2007 to record holders as of April 16, 2007.

Certain reclassifications have been made to prior period financial statements to conform with the current presentation.

Derivative Instruments. As more fully discussed in Note 11 to Consolidated Financial Statements included in EOG's 2006 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 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.

Recently Issued Accounting Standards and Developments. During February 2007, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FASB Statement No. 115." The new standard permits an entity to make an irrevocable election to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS No. 159 established presentation and disclosure requirements intended to help financial statement users understand the effect of the entity's election on earnings. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. Early adoption is permitted. EOG is currently analyzing SFAS No. 159.

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)." SFAS No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its balance sheet. The funded status is defined as the difference between the fair

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value of plan assets and the projected benefit obligation (for pension plans) or the accumulated postretirement benefit obligation (for other postretirement benefit plans). SFAS No. 158 also requires that actuarial gains and losses and changes in prior service costs not included in net periodic pension costs be included, net of tax, as a component of other comprehensive income. The statement does not affect the determination of net periodic benefit costs included in the income statement. SFAS No. 158 also requires that an employer measure defined benefit plan assets and benefit obligations as of the date of the employer's fiscal year-end statement of financial position. As of the year ended December 31, 2006, EOG adopted the recognition and disclosure requirements of SFAS No. 158. The impact of the adoption was immaterial. 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 provides a definition of fair value and provides a framework for measuring fair value. 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. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those years. EOG is assessing the impact, if any, that the adoption of SFAS No. 157 will have on its financial statements.

During July 2006, the FASB issued FASB Interpretation (FIN) No. 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109." FIN No. 48 addresses the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS No. 109, "Accounting for Income Taxes." FIN No. 48 prescribes specific criteria for the financial statement recognition and measurement of the tax effects of a position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition of previously recognized tax benefits, classification of tax liabilities on the balance sheet, recording interest and penalties on tax underpayments, accounting in interim periods, and disclosure requirements. FIN No. 48 is effective for fiscal periods beginning after December 15, 2006.

EOG adopted FIN No. 48 as of January 1, 2007. The cumulative effect of applying the provisions of FIN No. 48 has been reported as an increase to the opening balance of retained earnings for 2007 in the amount of $10.8 million, representing a reduction in the liability for unrecognized tax benefits. After adoption of FIN No. 48, the balance of unrecognized tax benefits was zero. EOG does not expect a significant increase in unrecognized tax benefits to occur during 2007. EOG or its subsidiaries file income tax returns in the United States federal jurisdiction and various state, local and foreign jurisdictions. EOG is generally no longer subject to income tax examinations by tax authorities in the United States (Federal), Canada and Trinidad before 2002, 2001 and 1999, respectively. EOG records interest and penalties related to unrecognized tax benefits to the income tax provision. EOG has no such accrued interest and penalties as of the date of adoption of FIN No. 48.

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2. Stock-Based Compensation

At June 30, 2007, 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,
		2007		2006		2007		2006

Lease and Well	$	2.8	$	2.0	$	5.8	$	3.6
Exploration Costs		3.0		2.3		6.0		4.0
General and Administrative		9.5		6.3		17.7		12.0
Total	$	15.3	$	10.6	$	29.5	$	19.6

EOG has various stock plans (Plans) under which employees and non-employee members of the Board have been or may be granted certain equity compensation. At June 30, 2007, approximately 2.6 million common shares remained available for grant under the Plans. EOG's policy is to issue shares related to the Plans from treasury stock. At June 30, 2007, EOG held approximately 4.7 million shares of treasury stock.

Stock Options and Stock Appreciation Rights. Under the Plans, participants have been or may be granted options to purchase shares of common stock of EOG at a price not less than the market price of the stock at the date of grant. In addition, participants have been or may be granted Stock-Settled Stock Appreciation Rights (SARs), representing the right to receive shares of EOG common stock based on the appreciation in the stock price from the date of the grant on the number of shares granted. Stock options and SARs granted under the Plans 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 under the Plans have not exceeded a maximum term of 10 years. For all grants made prior to August 2004 and all employee stock purchase plan (ESPP) grants, the fair value of each grant 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 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 is estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock options, SARs and ESPP grants totaled $8.7 million and $6.9 million during the three months ended June 30, 2007 and 2006, respectively. Such expense totaled $17.1 million and $13.5 million during the six months ended June 30, 2007 and 2006, respectively.

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Weighted average fair values and valuation assumptions used to value stock options, SARs and ESPP grants during the six-month periods ended June 30, 2007 and 2006 are as follows:

		Stock Options/SARs				ESPP
		Six Months Ended				Six Months Ended
		June 30,				June 30,
		2007		2006		2007		2006

Weighted Average Fair Value of Grants	$	21.96	$	25.29	$	15.07	$	21.14
Expected Volatility		29.35%		35.20%		32.47%		39.66%
Risk-Free Interest Rate		4.83%		4.97%		5.07%		4.47%
Dividend Yield		0.3%		0.3%		0.3%		0.3%
Expected Life		4.8 yrs		3.9 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 options, SARs and ESPP grants.

The following table sets forth the stock option and SAR transactions for the six-month periods ended June 30, 2007 and 2006 (stock options/SARs and dollars in thousands, except per share data):

	Six Months Ended			Six Months Ended
	June 30, 2007			June 30, 2006
			Weighted			Weighted
			Average			Average
	Number of Stock		Grant	Number of		Grant
	Options/SARs		Price	Stock Options		Price

Outstanding at January 1	10,150	$	35.29	9,698	$	28.26
Granted	216		71.61	154		73.59
Exercised ⁽¹⁾	(534)		21.86	(480)		16.25
Forfeited	(85)		52.59	(67)		45.10
Outstanding at June 30 ⁽²⁾	9,747	$	36.67	9,305	$	29.36

Vested or Expected to Vest ⁽³⁾	9,469	$	36.19	8,816	$	29.31

Exercisable at June 30 ⁽⁴⁾	4,998	$	22.08	4,231	$	17.27

(1) The total intrinsic value of stock options exercised for the six months ended June 30, 2007 and 2006 was $27 million and $30 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 options.
(2) The total intrinsic value of stock options/SARs outstanding at June 30, 2007 and 2006 was $355 million and $372 million, respectively. At June 30, 2007 and 2006,
      the weighted average remaining contractual life was 5.3 years and 6.2 years, respectively.
(3) The total intrinsic value of stock options/SARs vested or expected to vest at June 30, 2007 and 2006 was $350 million and $353 million, respectively. At June 30,
      2007 and 2006, the weighted average remaining contractual life was 5.3 years and 6.2 years, respectively.
(4) The total intrinsic value of stock options/SARs exercisable at June 30, 2007 and 2006 was $255 million and $220 million, respectively. At June 30, 2007 and 2006,
      the weighted average remaining contractual life was 4.5 years and 5.2 years, respectively.

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At June 30, 2007, unrecognized compensation expense related to non-vested stock options, SARs and ESPP grants totaled $66.3 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.8 years.

Restricted Stock and Units. Under the Plans, employees may be granted restricted (non-vested) stock and/or units without cost to them. The restricted stock and units generally vest five years after the date of grant, except for certain bonus grants, and as defined in individual grant agreements. Upon vesting, restricted stock is released to the employee and restricted units are converted into common stock and released to the employee. Stock-based compensation expense related to restricted stock and units totaled $6.6 million and $3.7 million for the three months ended June 30, 2007 and 2006, respectively, and $12.4 million and $6.1 million for the six months ended June 30, 2007 and 2006, respectively.

The following table sets forth the restricted stock and units transactions for the six-month periods ended June 30, 2007 and 2006 (shares and units and dollars in thousands, except per share data):

	Six Months Ended			Six Months Ended
	June 30, 2007			June 30, 2006
			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	2,301	$	36.13	2,544	$	26.04
Granted	520		67.99	267		67.07
Released ⁽¹⁾	(245)		18.37	(649)		20.68
Forfeited	(47)		53.13	(11)		51.31
Outstanding at June 30 ⁽²⁾	2,529	$	44.08	2,151	$	32.62

(1) The total intrinsic value of restricted stock and units released for the six months ended June 30, 2007 and 2006 was $16 million and $47 million, respectively. The
intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and units are released.
(2) The aggregate intrinsic value of restricted stock and units outstanding at June 30, 2007 and 2006 was approximately $185 million and $149 million, respectively.

At June 30, 2007, unrecognized compensation expense related to restricted stock and units totaled $77 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.7 years.

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3. Earnings Per Share

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

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2007		2006		2007		2006

Numerator for Basic and Diluted Earnings Per Share -
	Net Income	$	307,053	$	331,417	$	524,720	$	758,124
	Less: Preferred Stock Dividends		990		1,858		1,865		3,716
	Net Income Available to Common	$	306,063	$	329,559	$	522,855	$	754,408

Denominator for Basic Earnings Per Share -
	Weighted Average Shares		243,227		241,613		242,976		241,370
Potential Dilutive Common Shares -
	Stock Options/SARs		3,077		3,356		2,996		3,453
	Restricted Stock and Units		957		918		1,037		1,004
Denominator for Diluted Earnings Per Share -
	Adjusted Diluted Weighted Average Shares		247,261		245,887		247,009		245,827

Net Income Per Share Available to Common
	Basic	$	1.26	$	1.36	$	2.15	$	3.13
	Diluted	$	1.24		1.34	$	2.12	$	3.07

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. The excluded stock options and SARs totaled 1.9 million and 1.6 million for the three months ended June 30, 2007 and 2006, respectively, and 3.3 million and 1.6 million for the six months ended June 30, 2007 and 2006, respectively.

4. Supplemental Cash Flow Information

Cash paid for interest and income taxes (net of receipts) for the six-month periods ended June 30 was as follows (in thousands):

		Six Months Ended
		June 30,
		2007		2006

Interest	$	17,226	$	22,074
Income Taxes	$	27,426	$	132,580

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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 (in thousands):

					Three Months Ended				Six Months Ended
					June 30,				June 30,
					2007		2006		2007		2006
Comprehensive Income
	Net Income			$	307,053	$	331,417	$	524,720	$	758,124
	Other Comprehensive Income
		Foreign Currency Translation Adjustments			132,137		66,633		148,489		64,876
		Foreign Currency Swap Transaction			3,203		1,610		5,353		2,156
		Income Tax Provision Related
		to Foreign Currency Swap Transaction			(1,090)		(1,159)		(1,705)		(1,342)
		Deferred Postretirement Benefit Costs			40		-		77		-
			Total	$	441,343	$	398,501	$	676,934	$	823,814

6. Segment Information

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

				Three Months Ended				Six Months Ended
				June 30,				June 30,
				2007		2006		2007		2006

Net Operating Revenues
	United States		$	813,231	$	676,637	$	1,442,390	$	1,455,039
	Canada			158,826		145,288		302,293		322,267
	Trinidad			73,830		81,840		160,938		174,429
	United Kingdom			9,356		15,323		24,835		51,889
		Total	$	1,055,243	$	919,088	$	1,930,456	$	2,003,624

Operating Income (Loss)
	United States		$	324,246	$	325,203	$	535,990	$	758,959
	Canada			70,138		69,707		128,935		166,481
	Trinidad			52,810		53,119		116,400		123,568
	United Kingdom			434		6,837		3,400		34,286
	Other			(10)		(32)		(72)		(32)
		Total		447,618		454,834		784,653		1,083,262

Reconciling Items
	Other Income, Net			29,069		21,844		34,993		36,400
	Interest Expense, Net			10,818		12,384		18,456		25,537
		Income Before Income Taxes	$	465,869	$	464,294	$	801,190	$	1,094,125

-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 (in thousands):

			Six Months Ended
			June 30,
			2007		2006

Carrying Amount at Beginning of Period		$	182,407	$	161,488
	Liabilities Incurred		10,123		4,633
	Liabilities Settled		(5,339)		(2,937)
	Accretion		5,062		4,623
	Revisions		(126)		(52)
	Foreign Currency Translations		799		1,904
Carrying Amount at End of Period		$	192,926	$	169,659

Current Portion		$	8,614	$	5,424
Noncurrent Portion		$	184,312	$	164,235

8. Suspended Well Costs

EOG's net changes in suspended well costs for the six-month period ended June 30, 2007 in accordance with FASB Staff Position No. 19-1, "Accounting for Suspended Well Costs," are presented below (in thousands):

			Six Months
			Ended
			June 30,
			2007

Balance at December 31, 2006		$	77,365
	Additions Pending the Determination of Proved Reserves		78,784
	Reclassifications to Proved Properties		(18,450)
	Charged to Dry Hole Costs		(4,250)
	Foreign Currency Translations		5,463
Balance at June 30, 2007		$	138,912

-13-

The following table provides an aging of suspended well costs as of June 30, 2007 (in thousands, except well count):

			As of
			June 30,
			2007

Capitalized exploratory well costs that have been
	capitalized for a period less than one year	$	114,193
Capitalized exploratory well costs that have been
	capitalized for a period greater than one year		24,719	(1)
	Total	$	138,912
Number of projects that have exploratory well costs that have been
	capitalized for a period greater than one year		1

(1) Amount represents an outside operated, winter access only, Northwest Territories discovery. During the first six months of 2007, the Canadian government indicated
      they were prepared to grant a significant discovery license for the D-57 area. The size of the license is being negotiated by the operator prior to the formal acceptance
      of the license. The operator plans to submit a second significant discovery application in the second half of 2007 for the B-44 area after the size of the D-57 license
      has been determined. A significant discovery license holds the lease indefinitely for the licensee.

9. Commitments and Contingencies

There are various suits and claims against EOG that have arisen in the ordinary course of business. Management believes that the chance that these suits and claims will individually, or in the aggregate, have a material adverse effect on the financial condition or results of operations of EOG is remote. When necessary, EOG has made accruals in accordance with SFAS No. 5, "Accounting for Contingencies," in order to provide for these matters.

-14-

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, 2007 and 2006, EOG's total costs recognized for these pension plans were $8.0 million and $6.9 million, respectively.

In addition, as more fully discussed in Note 6 to Consolidated Financial Statements in EOG's 2006 Annual Report, EOG's Canadian, Trinidadian and United Kingdom subsidiaries maintain various pension and savings plans for most of their employees. For the six months ended June 30, 2007 and 2006, combined contributions to these pension plans were $1.0 million and $1.4 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, 2007, EOG's total contributions to these plans amounted to approximately $55,000. The net periodic pension costs recognized for the postretirement medical and dental plans were approximately $357,000 and $334,000, respectively, for the six months ended June 30, 2007 and 2006.

11. Long-Term Debt

At June 30, 2007, the $98 million principal amount of the 6.50% Notes due 2007 and $170 million principal amount of commercial paper were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amounts with long-term debt.

The weighted average interest rate for commercial paper borrowings was 5.55% at June 30, 2007. The weighted average interest rate for commercial paper borrowings for the six months ended June 30, 2007 was 5.36%.

On May 18, 2007, EOG amended its 5-year, $600 million unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders and JP Morgan Chase Bank N.A., as Administrative Agent, to increase the facility from $600 million to $1.0 billion and to provide EOG the option to request letters of credit to be issued in an aggregate amount of up to $1.0 billion, replacing the previous limitation of up to $200 million. Concurrent with the effectiveness of the amendment, the maturity date of the Agreement was extended from June 28, 2011 to June 28, 2012. At June 30, 2007 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 London InterBank Offering Rate plus an applicable margin (Eurodollar rate) or the base rate of the Agreement's administrative agent. At June 30, 2007, the Eurodollar rate and applicable base rate, had there been an amount borrowed under the Agreement, would have been 5.51% and 8.25%, respectively.

In the first six months of 2007, EOGI International Company, a wholly owned foreign subsidiary of EOG, repaid $30 million of the $60 million year-end 2006 outstanding balance of its $600 million, 3-year unsecured Senior Term Loan Agreement (Term Loan Agreement). Borrowings under the Term Loan Agreement accrue interest based, at EOG's option, on either the Eurodollar rate or the base rate of the Term Loan Agreement's administrative agent. The applicable Eurodollar rate for the $30 million outstanding at June 30, 2007 was 5.72%. The weighted average Eurodollar rate for the amounts outstanding for the six months ended June 30, 2007 was 5.72%.

On May 12, 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. At June 30, 2007, EOG had $75 million outstanding under the Credit Agreement. The applicable Eurodollar rate at June 30, 2007 was 5.72%. The weighted average Eurodollar rate for the amounts outstanding during the first six months of 2007 was 5.75%.

-15-

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. and its subsidiaries (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, offshore Trinidad and the United Kingdom North Sea. 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 plans to continue to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas production. Production in the United States and Canada accounted for approximately 82% of total company production in the first six months of 2007. Based on current trends, EOG expects its United States production to increase at a greater rate than its other operating areas in the second half of 2007. EOG's major United States producing areas are Louisiana, New Mexico, Oklahoma, Texas, Utah and Wyoming.

Although EOG continues to focus on United States and Canada natural gas, EOG sees an increasing linkage between United States and Canada natural gas demand and Trinidad natural gas supply. For example, liquefied natural gas (LNG) imports from existing and planned facilities in Trinidad are contenders to meet increasing United States natural gas demand. In addition, ammonia, methanol and chemical production has been relocating from the United States and Canada to Trinidad, driven by attractive natural gas feedstock prices in the island nation. EOG believes that its existing position with the supply contracts to two ammonia plants, a methanol plant and the Atlantic LNG Train 4 (ALNG) plant will continue to give its portfolio an even broader exposure to United States and Canada natural gas fundamentals. EOG delivered gas at the contractual rate of 30 MMcfd, gross (13 MMcfd, net) beginning in May 2007 when ALNG reached commercial status.

In July 2007, EOG executed a 15 year natural gas contract with the National Gas Company of Trinidad and Tobago (NGC) for the sale of approximately 110 MMcfd, gross (75 MMcfd, net to EOG, based on current pricing and operating assumptions). EOG expects to begin initial delivery under this contract in early 2010 from its first discovery on Block 4(a) , subject to the completion of a pipeline by NGC.

In addition to EOG's ongoing production from the Valkyrie and Arthur Fields in the United Kingdom North Sea, EOG participated in the drilling and successful testing of the Columbus prospect, a farm-in opportunity, in the Central North Sea Block 23/16f at the end of 2006. A rig has been contracted by the operator to drill an appraisal well on this prospect in the third quarter of 2007. EOG is also participating in an exploratory well that spud in July 2007 on the Eos prospect located in the Southern North Sea Block 48/11c.

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.

-16-

Capital Structure. One of management's key strategies is to keep 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 12% at June 30, 2007 and March 31, 2007. During the first six months of 2007, EOG funded its capital programs by utilizing cash provided from its operating activities and net commercial paper and revolving credit facility borrowings. Management believes that cash provided by operating activities will continue to be the primary funding source for capital expenditures. Cash from operating activities is sensitive to many factors, including commodity prices, which may cause capital expenditures to exceed cash provided by operating activities. For the remainder of 2007, management anticipates increasing debt to fund any shortfall between cash provided by operating activities and EOG's 2007 capital program.

For 2007, EOG's estimated exploration and development expenditure budget is approximately $3.6 billion, excluding acquisitions. United States and Canada natural gas drilling activity continues to be a key component of this effort. 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.

Other. EOG has decided to sell the majority of its producing shallow gas assets and surrounding acreage in the Appalachian Basin in order to reallocate resources to focus on larger potential plays in North America. The Appalachian area includes approximately 2,400 wells which account for approximately 2% of EOG's United States production and its total year-end 2006 proved reserves. EOG will retain certain of its undeveloped acreage in this area and continue its shale exploration program. EOG intends to solicit bids from interested parties and will agree to a sale only if the terms are acceptable to management.

Results of Operations

The following review of operations for the three and six months ended June 30, 2007 and 2006 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, 2007 vs. Three Months Ended June 30, 2006

Net Operating Revenues. During the second quarter of 2007, net operating revenues increased $136 million, or 15%, to $1,055 million from $919 million for the same period of 2006. Total wellhead revenues, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, increased $181 million, or 22%, to $1,009 million from $828 million for the same period of 2006.

-17-

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

					Three Months Ended
					June 30,
					2007		2006
Natural Gas Volumes (MMcfd) ⁽¹⁾
	United States				960		776
	Canada				232		225
			United States and Canada		1,192		1,001
	Trinidad				250		265
	United Kingdom				22		25
		Total			1,464		1,291

Average Natural Gas Prices ($/Mcf) ⁽²⁾
	United States			$	6.80	$	6.33
	Canada				6.70		6.28
			United States and Canada Composite		6.78		6.32
	Trinidad				2.04		2.18
	United Kingdom				4.35		6.34
		Composite			5.93		5.47

Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
	United States				23.4		19.5
	Canada				2.4		2.4
			United States and Canada		25.8		21.9
	Trinidad				4.0		4.8
	United Kingdom				0.1		0.1
		Total			29.9		26.8

Average Crude Oil and Condensate Prices ($/Bbl) ⁽²⁾
	United States			$	61.38	$	67.69
	Canada				60.08		62.62
			United States and Canada Composite		61.26		67.06
	Trinidad				75.16		67.47
	United Kingdom				68.82		65.80
		Composite			63.15		67.13

Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
	United States				10.4		9.0
	Canada				1.1		0.6
		Total			11.5		9.6

Average Natural Gas Liquids Prices ($/Bbl) ⁽²⁾
	United States			$	45.35	$	41.02
	Canada				42.30		46.55
		Composite			45.04		41.38

Natural Gas Equivalent Volumes (MMcfed) ⁽³⁾
	United States				1,163		947
	Canada				253		244
			United States and Canada		1,416		1,191
	Trinidad				274		293
	United Kingdom				23		26
		Total			1,713		1,510

Total Bcfe ⁽³⁾					155.8		137.4

(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.

-18-

Wellhead natural gas revenues for the second quarter of 2007 increased $147 million, or 23%, to $790 million from $643 million for the same period of 2006. The increase was due to increased natural gas deliveries ($86 million) and a higher composite average wellhead natural gas price ($61 million). The composite average wellhead price for natural gas increased 8% to $5.93 per Mcf for the second quarter of 2007 from $5.47 per Mcf for the same period of 2006.

Natural gas deliveries increased 173 MMcfd, or 13%, to 1,464 MMcfd for the second quarter of 2007 from 1,291 MMcfd for the same period of 2006. The increase was primarily due to higher production in the United States (184 MMcfd) and Canada (7 MMcfd), partially offset by decreased production in Trinidad (15 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (127 MMcfd), the Rocky Mountain area (28 MMcfd), Kansas (19 MMcfd) and Mississippi (9 MMcfd). The decrease in Trinidad was primarily due to second quarter 2006 volumes reflecting higher demand and EOG supplying gas for use in ALNG's start-up phase. In 2007, ALNG remained in the start-up phase but did not require any gas from EOG until May when ALNG reached commercial status and EOG began supplying gas under the ALNG take-or-pay contract.

Wellhead crude oil and condensate revenues for the second quarter of 2007 increased $23 million, or 15%, to $172 million from $149 million for the same period of 2006. The increase was due to increased wellhead crude oil and condensate deliveries ($34 million), partially offset by a lower composite average wellhead crude oil and condensate price ($11 million). The composite average wellhead crude oil and condensate price for the second quarter of 2007 was $63.15 per barrel compared to $67.13 per barrel for the same period of 2006.

Natural gas liquids revenues for the second quarter of 2007 increased $11 million, or 30%, to $47 million from $36 million for the same period of 2006. The increase was due to increased deliveries ($7 million) and a higher composite average price ($4 million).

During the second quarter of 2007, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $44 million compared to a gain of $91 million for the same period of 2006. During the second quarter of 2007, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $19 million compared to the net cash inflow related to settled natural gas financial collar and price swap contracts of $64 million for the same period of 2006.

Operating and Other Expenses. For the second quarter of 2007, operating expenses of $608 million were $144 million higher than the $464 million incurred in the second quarter of 2006. The following table presents the costs per Mcfe for the three-month periods ended June 30:

			Three Months Ended
			June 30,
			2007		2006

Lease and Well		$	0.79	$	0.64
Transportation Costs			0.27		0.19
Depreciation, Depletion and Amortization (DD&A)			1.67		1.42
General and Administrative (G&A)			0.30		0.28
Interest Expense, Net			0.07		0.09
	Total Per-Unit Costs⁽¹⁾	$	3.10	$	2.62

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

The changes in per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the three months ended June 30, 2007 compared to the same period of 2006 were due primarily to the reasons set forth below.

-19-

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 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 $123 million for the second quarter of 2007 increased $36 million from $87 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($18 million) and Canada ($7 million); higher workover expenditures in the United States ($6 million); and higher lease and well administrative expenses ($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 down-stream 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 $42 million for the second quarter of 2007 increased $16 million from $26 million for the same prior year period primarily due to increased production in the Fort Worth Basin Barnett Shale Play.

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 the 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 $260 million for the second quarter of 2007 increased $67 million from the same prior year period primarily due to increased production ($36 million) and DD&A rates ($29 million) in the United States.

G&A expenses of $47 million for the second quarter of 2007 were $9 million higher than the same prior year period primarily due to higher employee-related costs ($6 million) and higher office rent ($1 million).

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 sales 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 2007 increased $15 million to $62 million (6.1% of wellhead revenues) from $47 million (5.7% of wellhead revenues) for the same prior year period. The increase was due to an increase in severance/production taxes as a result of increased wellhead revenues in the United States ($10 million) and lower 2007 credits taken for Texas high cost gas severance tax rate reductions ($2 million).

Exploration costs of $41 million for the second quarter of 2007 increased $6 million from $35 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($4 million) and Canada ($1 million).

-20-

Impairments include amortization of unproved leases, as well as impairments under SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $21 million for the second quarter of 2007 decreased by $2 million compared to $23 million in the same prior year period primarily due to decreased SFAS No. 144 related impairments ($4 million), partially offset by increased amortization of unproved leases in the United States ($2 million). Under SFAS No. 144, EOG recorded impairments of $6 million and $10 million for the second quarters of 2007 and 2006, respectively.

Other income, net was $29 million for the second quarter of 2007 compared to $22 million for the same prior year period. The increase of $7 million was primarily due to higher gains on sales of properties ($11 million) and net foreign currency transaction gains in 2007 ($2 million), partially offset by decreased interest income ($6 million).

Income tax provision of $159 million for the second quarter of 2007 increased $26 million compared to the same prior year period due primarily to an increase in foreign income taxes ($29 million), largely related to the 2006 reductions in the Canadian federal tax rate ($19 million) and the Alberta, Canada provincial tax rate ($13 million), partially offset by lower 2007 United States state income taxes ($6 million). The net effective tax rate for the second quarter of 2007 increased to 34% from 29% for the same prior year period.

Six Months Ended June 30, 2007 vs. Six Months Ended June 30, 2006

Net Operating Revenues. During the first six months of 2007, net operating revenues decreased $74 million, or 4%, to $1,930 million from $2,004 million for the same period of 2006. Total wellhead revenues increased $118 million, or 7%, to $1,920 million from $1,802 million for the same period of 2006.

-21-

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

					Six Months Ended
					June 30,
					2007		2006
Natural Gas Volumes (MMcfd)
	United States				938		767
	Canada				227		227
			United States and Canada		1,165		994
	Trinidad				251		274
	United Kingdom				26		30
		Total			1,442		1,298

Average Natural Gas Prices ($/Mcf)
	United States			$	6.61	$	7.04
	Canada				6.57		7.08
			United States and Canada Composite		6.60		7.04
	Trinidad				2.42		2.31
	United Kingdom				5.04		9.32
		Composite			5.85		6.10

Crude Oil and Condensate Volumes (MBbld)
	United States				22.6		20.2
	Canada				2.5		2.5
			United States and Canada		25.1		22.7
	Trinidad				4.2		5.2
	United Kingdom				0.1		0.1
		Total			29.4		28.0

Average Crude Oil and Condensate Prices ($/Bbl)
	United States			$	57.75	$	63.70
	Canada				55.88		57.12
			United States and Canada Composite		57.56		62.92
	Trinidad				67.32		64.45
	United Kingdom				59.61		61.04
		Composite			58.96		63.21

Natural Gas Liquids Volumes (MBbld)
	United States				10.0		8.1
	Canada				1.1		0.7
		Total			11.1		8.8

Average Natural Gas Liquids Prices ($/Bbl)
	United States			$	41.40	$	39.32
	Canada				39.39		44.56
		Composite			41.20		39.72

Natural Gas Equivalent Volumes (MMcfed)
	United States				1,134		937
	Canada				248		246
			United States and Canada		1,382		1,183
	Trinidad				276		305
	United Kingdom				27		30
		Total			1,685		1,518

Total Bcfe					305.0		274.8

-22-

Wellhead natural gas revenues for the first six months of 2007 increased $94 million, or 7%, to $1,526 million from $1,432 million for the same period of 2006. The increase was due to increased natural gas deliveries ($160 million), partially offset by a lower composite wellhead natural gas price ($66 million). The composite average wellhead price for natural gas decreased 4% to $5.85 per Mcf for the first six months of 2007 from $6.10 per Mcf for the same period of 2006.

Natural gas deliveries increased 144 MMcfd, or 11%, to 1,442 MMcfd for the first six months of 2007 from 1,298 MMcfd for the same period of 2006. The increase was due to higher production in the United States (171 MMcfd), partially offset by decreased production in Trinidad (23 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (125 MMcfd), the Rocky Mountain area (25 MMcfd) and Kansas (17 MMcfd). The decrease in Trinidad was due to volumes in the first six months of 2006 reflecting higher demand and EOG supplying gas for use in ALNG's start-up phase. In 2007, ALNG remained in the start-up phase but did not require any gas from EOG until May when ALNG reached commercial status and EOG began supplying gas under the ALNG take-or-pay contract.

Wellhead crude oil and condensate revenues for the first six months of 2007 increased $5 million, or 2%, to $311 million from $306 million for the same period of 2006. The increase was due to increased wellhead crude oil and condensate deliveries ($27 million), partially offset by a lower composite average wellhead crude oil and condensate price ($22 million). The composite average wellhead crude oil and condensate price for the first six months of 2007 was $58.96 per barrel compared to $63.21 per barrel for the same period of 2006.

Natural gas liquids revenues for the first six months of 2007 increased $19 million, or 30%, to $83 million from $64 million for the same period of 2006. The increase was due to increases in deliveries ($16 million) and composite average price ($3 million).

During the first six months of 2007, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $4 million compared to a gain of $198 million for the same period of 2006. During the first six months of 2007, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $66 million compared to the net cash inflow related to settled natural gas financial collar and price swap contracts of $94 million for the same period of 2006.

Operating and Other Expenses. For the first six months of 2007, operating expenses of $1,146 million were $226 million higher than the $920 million incurred in the same period of 2006. The following table presents the costs per Mcfe for the six-month periods ended June 30:

			Six Months Ended
			June 30,
			2007		2006

Lease and Well		$	0.75	$	0.64
Transportation Costs			0.26		0.20
DD&A			1.65		1.36
G&A			0.30		0.27
Interest Expense, Net			0.06		0.09
	Total Per-Unit Costs⁽¹⁾	$	3.02	$	2.56

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

The changes in per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the six months ended June 30, 2007 compared to the same period of 2006 were due primarily to the reasons set forth below.

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Lease and well expenses of $228 million for the first six months of 2007 were $53 million higher than the same prior year period primarily due to higher operating and maintenance expenses in the United States ($31 million) and Canada ($6 million); higher lease and well administrative expenses ($9 million); and higher workover expenditures in the United States ($8 million).

Transportation costs of $79 million for the first six months of 2007 increased $25 million from $54 million for the same prior year period primarily due to increased production in the Fort Worth Basin Barnett Shale Play.

DD&A expenses of $504 million for the first six months of 2007 increased $134 million from the same prior year period primarily due to increased DD&A rates in the United States ($64 million), Canada ($8 million) and the United Kingdom ($2 million); and increased production in the United States ($59 million).

G&A expenses of $91 million for the first six months of 2007 were $16 million higher than the same prior year period primarily due to higher employee-related expenses ($13 million) and higher office rent ($2 million).

Taxes other than income for the first six months of 2007 increased $2 million to $103 million (5.3% of wellhead revenues) from $101 million (5.6% of wellhead revenues) for the same prior year period. The increase was primarily due to increased ad valorem/property taxes, partially offset by decreased severance/production taxes. Ad valorem/property taxes increased primarily due to higher property valuations in the United States ($3 million). Severance/production taxes in the United States decreased primarily due to higher 2007 credits taken for Texas high cost gas severance tax rate reductions ($15 million), partially offset by an increase in wellhead revenues in the United States ($11 million) and changes to Trinidad tax legislation governing the Supplemental Petroleum Tax which resulted in an adjustment that decreased production tax expense in the first six months of 2006 ($3 million).

Interest expense, net was $18 million for the first six months of 2007, down $7 million compared to the same prior year period primarily due to higher capitalized interest ($4 million) and a slightly lower average debt balance ($2 million).

Exploration costs of $68 million for the first six months of 2007 decreased $7 million from $75 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States ($12 million), partially offset by increased geological and geophysical expenditures in Canada ($2 million) and higher employee-related costs ($4 million).

Impairments were $45 million for both six-month periods ended June 30, 2007 and 2006. SFAS No. 144 related impairments decreased ($4 million) and amortization of unproved leases increased in the United States ($3 million) and Canada ($1 million). Under SFAS No. 144, EOG recorded impairments of $16 million and $20 million for the six months ended June 30, 2007 and 2006, respectively.

Income tax provision of $276 million for the first six months of 2007 decreased $60 million compared to the same prior year period due primarily to a lower tax provision resulting from decreased pretax income ($103 million), partially offset by an increase in foreign income taxes ($46 million), largely related to the 2006 reductions in the Canadian federal tax rate ($19 million) and the Alberta, Canada provincial tax rate ($13 million). The net effective tax rate for the first six months of 2007 increased to 35% from 31% for the same prior year period.

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Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2007 were funds generated from operations and net commercial paper and revolving credit facility borrowings. The primary uses of cash were funds used in operations, exploration and development expenditures, dividend payments to shareholders and repayment of debt. During the first six months of 2007, EOG's cash balance decreased $160 million to $58 million from $218 million at December 31, 2006.

Net cash provided by operating activities of $1,422 million for the first six months of 2007 increased $45 million compared to the same period of 2006 primarily reflecting an increase in wellhead revenues ($118 million) and a decrease in cash paid for interest and income taxes ($110 million), partially offset by unfavorable changes in working capital and other assets and liabilities ($135 million), an increase in cash operating expenses ($54 million) and a decrease in the net cash flows from settlement of financial commodity derivative contracts ($28 million).

Net cash used in investing activities of $1,722 million for the first six months of 2007 increased by $542 million compared to the same period of 2006 due primarily to increased additions to oil and gas properties.

Net cash provided by financing activities was $137 million for the first six months of 2007 compared to net cash used in financing activities of $88 million for the same period of 2006. Cash provided by financing activities for 2007 included net commercial paper and Trinidad revolving credit facility borrowings ($180 million), proceeds from sales of treasury stock attributable to employee stock option exercises and employee stock purchase plan ($14 million), and excess tax benefits from stock-based compensation expenses ($11 million). Cash used by financing activities for 2007 included cash dividend payments ($38 million) and repayments of long-term debt borrowings ($30 million).

Total Exploration and Development Expenditures. The table below presents total exploration and development expenditures for the six-month periods ended June 30 (in millions):

				Six Months Ended
				June 30,
				2007		2006

United States			$	1,540	$	1,024
Canada				182		153
		United States and Canada		1,722		1,177
Trinidad				89		70
United Kingdom				3		15
Other				2		3
	Exploration and Development Expenditures			1,816		1,265
Asset Retirement Costs				11		4
	Total Exploration and Development Expenditures		$	1,827	$	1,269

Total exploration and development expenditures of $1,827 million for the first six months of 2007 were $558 million higher than the same period of 2006. The 2007 exploration and development expenditures of $1,816 included $1,441 million in development, $361 million in exploration, $13 million in capitalized interest and $1 million in property acquisitions. The 2006 exploration and development expenditures of $1,265 included $920 million in development, $330 million in exploration, $9 million in capitalized interest and $6 million in property acquisitions.

Higher development expenditures for the first six months of 2007 of $521 million were due primarily to increased development drilling expenditures in the United States ($349 million), Trinidad ($48 million) and Canada ($12 million); and increased expenditures related to infrastructure facilities in the United States ($104 million) and Canada ($7 million).

Higher exploration expenditures for the first six months of 2007 of $31 million were primarily due to increased expenditures for leasehold acquisitions in the United States ($36 million), increased exploratory drilling

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expenditures, including dry hole costs, in the United States ($27 million) and Canada ($8 million), partially offset by decreased exploratory drilling expenditures, including dry hole costs, in Trinidad ($26 million); and decreased geological and geophysical expenditures in the United States ($12 million).

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 and the United Kingdom North Sea, 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, 2006, 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.

The total fair value of the natural gas financial price swap contracts at June 30, 2007 was a positive $63 million. Subsequent to June 30, 2007, EOG has entered into additional natural gas financial price swap contracts covering notional volumes of 90,000 million British thermal units per day (MMBtud) for the period January 2008 through December 2008 at an average price of $8.54 per million British thermal units (MMBtu). Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at August 1, 2007 with notional volumes expressed in MMBtud and prices in dollars per MMBtu ($/MMBtu).

Natural Gas Financial Price Swap Contracts
		Weighted
	Volume	Average Price
	(MMBtud)	($/MMBtu)
2007
July (closed)	120,000	$ 8.84
August (closed)	120,000	8.92
September	120,000	9.00
October	120,000	9.14
November	120,000	9.94
December	120,000	10.70
2008
January	160,000	$ 9.44
February	160,000	9.44
March	160,000	9.25
April	160,000	8.28
May	160,000	8.21
June	160,000	8.29
July	160,000	8.38
August	160,000	8.46
September	160,000	8.51
October	160,000	8.62
November	160,000	9.07
December	160,000	9.53

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The total fair value of the crude oil financial price swap contracts at June 30, 2007 was a positive $5 million. Presented below is a comprehensive summary of EOG's 2007 crude oil financial price swap contracts at August 1, 2007 with notional volumes expressed in barrels per day (Bbld) and prices in dollars per barrel ($/Bbl).

Crude Oil Financial Price Swap Contracts
		Weighted
	Volume	Average Price
	(Bbld)	($/Bbl)
2007
July (closed)	4,000	$ 78.28
August	4,000	78.16
September	4,000	78.03
October	4,000	77.91
November	4,000	77.75
December	4,000	77.57

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 and Section 21E of the Securities Exchange Act of 1934. 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 of them or by 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 its expectations reflected in 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 the 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;

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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;

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 might not occur. 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 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 29 through 32 of the Annual Report on Form 10-K for the year ended December 31, 2006, filed on February 28, 2007.

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, the principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date to ensure 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 that occurred during the 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 1A. RISK FACTORS

There have been no material changes from the risk factors previously disclosed in Item 1A "Risk Factors" of EOG's Annual Report on Form 10-K for the year ended December 31, 2006.

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

Issuer Purchases of Equity Securities

				(c)
	(a)			Total Number of	(d)
	Total		(b)	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, 2007 - April 30, 2007	182	$	73.44	-	6,386,200
May 1, 2007 - May 31, 2007	-		-	-	6,386,200
June 1, 2007 - June 30, 2007	-		-	-	6,386,200
Total	182		73.44	-

(1) Represents 182 shares that were withheld by or returned to EOG to satisfy tax withholding obligations that arose upon the exercise of employee stock options or the vesting
of restricted stock or 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.

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

The Annual Meeting of Shareholders of EOG Resources, Inc. was held on April 24, 2007, in Houston, Texas, for the purpose of electing a board of directors and ratifying the appointment of auditors. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934, and there was no solicitation in opposition to management's solicitations.

(a) Each of the directors nominated by the Board and listed in the proxy statement was elected with votes as follows:

	Shares	Shares
Nominee	For	Withheld

George A. Alcorn	220,920,462	3,443,794
Charles R. Crisp	220,962,051	3,402,205
Mark G. Papa	219,833,565	4,530,692
Edmund P. Segner, III ⁽¹⁾	211,442,073	12,922,183
William D. Stevens	220,984,475	3,379,782
H. Leighton Steward	220,988,035	3,376,222
Donald F. Textor	209,987,868	14,376,389
Frank G. Wisner	220,955,315	3,408,941

(1) EOG has approved Mr. Segner's request for "Company-approved retirement prior to age 62" effective November 30, 2008.
Effective June 30, 2007, Mr. Segner remains an officer, but is no longer principal financial officer, an executive officer, or a
director of EOG.

(b) The ratification of the appointment of Deloitte & Touche LLP, independent registered public accountants, as EOG's independent auditors for the year ending December 31, 2007 was ratified by the following vote: 223,141,463 shares for; 63,492 shares against; and 1,159,301 shares abstaining.

ITEM 6. Exhibits

*10.1 -	Second Amendment, dated May 18, 2007, to Revolving Credit Agreement, dated June 28, 2005, among EOG Resources, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.

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

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

*32.1 -	Section 906 Certification of Periodic Report of Chief 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, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		EOG RESOURCES, INC.
		(Registrant)



Date: August 2, 2007	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

*10.1 -	Second Amendment, dated May 18, 2007, to Revolving Credit Agreement, dated June 28, 2005, among EOG Resources, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.

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

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

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

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

*Exhibits filed herewith

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