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 September 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 October 23, 2007.

Title of each class		Number of shares
Common Stock, par value $0.01 per share		245,991,344

EOG RESOURCES, INC.
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements (Unaudited)

		Consolidated Statements of Income - Three Months Ended September 30, 2007 and 2006 and Nine Months Ended September 30, 2007 and 2006	3

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

		Consolidated Statements of Cash Flows - Nine Months Ended September 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 6.	Exhibits	31

SIGNATURES			32

EXHIBIT INDEX			33

-2-

PART I. FINANCIAL INFORMATION

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

				Three Months Ended				Nine Months Ended
				September 30,				September 30,
				2007		2006		2007		2006


Net Operating Revenues
	Wellhead Natural Gas		$	684,292	$	661,920	$	2,210,390	$	2,093,950
	Wellhead Crude Oil, Condensate and Natural
	Gas Liquids			258,273		200,724		651,833		570,478
	Gains on Mark-to-Market Commodity
	Derivative Contracts			43,591		104,696		47,893		302,742
	Other, Net			4,307		1,386		29,871		13,999
		Total		990,463		968,726		2,939,987		2,981,169

Operating Expenses
	Lease and Well			120,091		93,693		347,604		268,464
	Transportation Costs			44,213		26,632		123,552		80,641
	Exploration Costs			38,840		35,174		106,440		109,879
	Dry Hole Costs			46,046		16,356		74,672		41,750
	Impairments			42,014		22,106		86,860		67,559
	Depreciation, Depletion and Amortization			279,189		216,071		783,311		586,651
	General and Administrative			48,101		42,362		139,163		117,260
	Taxes Other Than Income			47,111		54,066		149,806		154,618
		Total		665,605		506,460		1,811,408		1,426,822

Operating Income				324,858		462,266		1,128,579		1,554,347
Other Income, Net				6,311		13,832		22,236		41,413
Income Before Interest Expense and Income Taxes				331,169		476,098		1,150,815		1,595,760
Interest Expense, Net				12,571		10,102		31,027		35,639
Income Before Income Taxes				318,598		465,996		1,119,788		1,560,121
Income Tax Provision				114,595		166,860		391,065		502,861
Net Income				204,003		299,136		728,723		1,057,260
Preferred Stock Dividends				1,637		1,858		3,502		5,574
Net Income Available to Common			$	202,366	$	297,278	$	725,221	$	1,051,686

Net Income Per Share Available to Common
	Basic		$	0.83	$	1.23	$	2.98	$	4.35
	Diluted		$	0.82	$	1.21	$	2.93	$	4.28

Average Number of Common Shares
	Basic			243,486		241,911		243,140		241,550
	Diluted			247,425		246,136		247,275		245,990

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

-3-

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

				September 30,		December 31,
				2007		2006
ASSETS
Current Assets
	Cash and Cash Equivalents		$	301,944	$	218,255
	Accounts Receivable, Net			678,762		754,134
	Inventories			109,838		113,591
	Assets from Price Risk Management Activities			68,354		130,612
	Income Taxes Receivable			92,569		94,311
	Other			58,758		39,177
		Total		1,310,225		1,350,080

Oil and Gas Properties (Successful Efforts Method)				16,955,361		13,893,851
	Less: Accumulated Depreciation, Depletion and Amortization			(6,921,155)		(5,949,804)
		Net Oil and Gas Properties		10,034,206		7,944,047
Other Assets				123,276		108,033
Total Assets			$	11,467,707	$	9,402,160


LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
	Accounts Payable		$	964,515	$	896,572
	Accrued Taxes Payable			102,518		130,984
	Dividends Payable			22,095		14,718
	Deferred Income Taxes			84,499		144,615
	Current Portion of Long-Term Debt			98,442		-
	Other			69,484		68,123
		Total		1,341,553		1,255,012

Long-Term Debt				1,185,000		733,442
Other Liabilities				353,331		300,907
Deferred Income Taxes				1,960,675		1,513,128

Shareholders' Equity
Preferred Stock, $0.01 Par, 10,000,000 Shares Authorized:
	Series B, Cumulative, $1,000 Liquidation Preference per Share,
	43,260 Shares Outstanding at September 30, 2007 and 53,260 Shares Outstanding at December 31, 2006			43,035		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				186,256		129,986
Accumulated Other Comprehensive Income				450,500		176,704
Retained Earnings				5,820,884		5,151,034
Common Stock Held in Treasury, 3,647,754 Shares at
September 30, 2007 and 5,724,959 Shares at December 31, 2006				(76,022)		(113,435)
		Total Shareholders' Equity		6,627,148		5,599,671
Total Liabilities and Shareholders' Equity			$	11,467,707	$	9,402,160

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

-4-

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

				Nine Months Ended
				September 30,
				2007		2006
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	728,723	$	1,057,260
	Items Not Requiring (Providing) Cash
		Depreciation, Depletion and Amortization		783,311		586,651
		Impairments		86,860		67,559
		Stock-Based Compensation Expenses		46,732		38,407
		Deferred Income Taxes		328,005		258,465
		Other, Net		(21,080)		(19,271)
	Dry Hole Costs			74,672		41,750
	Mark-to-Market Commodity Derivative Contracts
		Total Gains		(47,893)		(302,742)
		Realized Gains		99,188		166,892
	Other, Net			20,778		17,849
	Changes in Components of Working Capital and Other Assets and Liabilities
		Accounts Receivable		78,283		110,517
		Inventories		4,232		(54,021)
		Accounts Payable		42,830		104,592
		Accrued Taxes Payable		(22,834)		(49,083)
		Other Assets		(7,780)		27,623
		Other Liabilities		(3,765)		(6,904)
	Changes in Components of Working Capital Associated with
		Investing and Financing Activities		(44,314)		(65,996)
Net Cash Provided by Operating Activities				2,145,948		1,979,548

Investing Cash Flows
	Additions to Oil and Gas Properties			(2,641,871)		(1,953,209)
	Proceeds from Sales of Assets			43,972		15,655
	Changes in Components of Working Capital Associated with
		Investing Activities		44,325		66,054
	Other, Net			(38,997)		(20,474)
Net Cash Used in Investing Activities				(2,592,571)		(1,891,974)

Financing Cash Flows
	Net Commercial Paper and Revolving Credit Facility Borrowings			10,000		-
	Long-Term Debt Borrowings			600,000		37,000
	Long-Term Debt Repayments			(60,000)		(192,550)
	Dividends Paid			(61,253)		(44,015)
	Excess Tax Benefits from Stock-Based Compensation			17,422		27,139
	Preferred Stock Redemptions			(10,641)		-
	Proceeds from Stock Options Exercised and Employee Stock Purchase Plans			32,747		29,284
	Debt Issuance Costs			(4,752)		-
	Other, Net			(11)		(448)
Net Cash Provided by (Used in) Financing Activities				523,512		(143,590)

Effect of Exchange Rate Changes on Cash				6,800		8,136

Increase (Decrease) in Cash and Cash Equivalents				83,689		(47,880)
Cash and Cash Equivalents at Beginning of Period				218,255		643,811
Cash and Cash Equivalents at End of Period			$	301,944	$	595,931

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 (SEC). Accordingly, they reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods. 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 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 U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three and nine months ended September 30, 2007 are not necessarily indicative of the results to be expected for the full year.

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 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.

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 at specific election dates 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. Currently, EOG has elected not to adopt the fair value option provision allowed under SFAS No. 159.

In September 2006, 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 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

-6-

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. The adoption of SFAS No. 157 is not expected to have a material impact on EOG's financial statements, but will result in additional disclosures related to the use of fair values in the financial statements.

During July 2006, the FASB issued Financial 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 and 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) and Canada for taxable years before 2002 and in Trinidad for taxable years before 1999. EOG records interest and penalties related to unrecognized tax benefits to its income tax provision. EOG had no such accrued interest and penalties as of the date of adoption of FIN No. 48.

-7-

2. Stock-Based Compensation

At September 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				Nine Months Ended
		September 30,				September 30,
		2007		2006		2007		2006

Lease and Well	$	3.7	$	3.9	$	9.5	$	7.5
Exploration Costs		3.6		4.4		9.6		8.4
General and Administrative		9.9		10.5		27.6		22.5
	$	17.2	$	18.8	$	46.7	$	38.4

EOG has various stock plans (Plans) under which employees and non-employee members of the Board of Directors of EOG (Board) have been or may be granted certain equity compensation. At September 30, 2007, approximately 1.1 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 September 30, 2007, EOG held approximately 3.6 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. 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 grant on the number of shares granted. Stock options and SARs are granted at a price not less than the market price of the stock at the date of grant. 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. The fair value of all grants made prior to August 2004 and all employee stock purchase plan (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 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 $9.3 million and $14.5 million during the three months ended September 30, 2007 and 2006, respectively. Such expense totaled $26.5 million and $28.0 million during the nine months ended September 30, 2007 and 2006, respectively.

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

		Stock Options/SARs				ESPP
		Nine Months Ended				Nine Months Ended
		September 30,				September 30,
		2007		2006		2007		2006

Weighted Average Fair Value of Grants	$	24.20	$	22.53	$	16.11	$	20.32
Expected Volatility		30.67%		34.26%		29.76%		41.09%
Risk-Free Interest Rate		4.49%		4.96%		5.01%		4.89%
Dividend Yield		0.30%		0.30%		0.30%		0.30%
Expected Life		5.2 yrs		5.1 yrs		0.5 yrs		0.5 yrs

-8-

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 SARs transactions for the nine-month periods ended September 30 (stock options/SARs and dollars in thousands, except per share data):


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

Outstanding at January 1	10,150	$	35.29	9,698	$	28.26
Granted	1,188		73.36	1,987		62.12
Exercised ⁽¹⁾	(1,140)		27.76	(1,171)		24.20
Forfeited	(145)		54.97	(163)		44.06
Outstanding at September 30 ⁽²⁾	10,053	$	40.36	10,351	$	34.83

Vested or Expected to Vest ⁽³⁾	9,802	$	39.78	9,794	$	34.74

Exercisable at September 30 ⁽⁴⁾	6,182	$	27.23	5,492	$	20.60

(1) The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2007 and 2006 was $50 million and $56 million, respectively.
      The intrinsic value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the
      stock options/SARs.
(2) The total intrinsic value of stock options/SARs outstanding at September 30, 2007 and 2006 was $324 million and $315 million, respectively. At September 30,
      2007 and 2006, the weighted average remaining contractual life was 5.1 years and 6.0 years, respectively.
(3) The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2007 and 2006 was $321 million and $298 million, respectively.
      At September 30, 2007 and 2006, the weighted average remaining contractual life was 5.1 years and 6.0 years, respectively.
(4) The total intrinsic value of stock options/SARs exercisable at September 30, 2007 and 2006 was $279 million and $244 million, respectively. At September 30,
      2007 and 2006, the weighted average remaining contractual life was 4.5 years and 5.2 years, respectively.

At September 30, 2007, unrecognized compensation expense related to non-vested stock options, SARs and ESPP grants totaled $81.9 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.4 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 $7.9 million and $4.3 million for the three months ended September 30, 2007 and 2006, respectively, and $20.2 million and $10.4 million for the nine months ended September 30, 2007 and 2006, respectively.

-9-

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

	Nine Months Ended			Nine Months Ended
	September 30, 2007			September 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	1,120		71.08	525		64.22
Released ⁽¹⁾	(301)		19.62	(660)		20.74
Forfeited	(75)		52.41	(56)		41.71
Outstanding at September 30 ⁽²⁾	3,045		50.23	2,353		35.68

                        (1) The total intrinsic value of restricted stock and units released for the nine months ended September 30, 2007 and 2006 was $20 million and $48 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 September 30, 2007 and 2006 was approximately $220 million and $153 million, respectively.

At September 30, 2007, unrecognized compensation expense related to restricted stock and units totaled $112.1 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.9 years.

3. Earnings Per Share

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

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2007		2006		2007		2006

Numerator for Basic and Diluted Earnings Per Share -
	Net Income	$	204,003	$	299,136	$	728,723	$	1,057,260
	Less: Preferred Stock Dividends		1,637		1,858		3,502		5,574
	Net Income Available to Common	$	202,366	$	297,278	$	725,221	$	1,051,686

Denominator for Basic Earnings Per Share -
	Weighted Average Shares		243,486		241,911		243,140		241,550
Potential Dilutive Common Share -
	Stock Options/SARs		2,828		3,224		2,926		3,364
	Restricted Stock and Units		1,111		1,001		1,209		1,076
Denominator for Diluted Earnings Per Share -
	Adjusted Weighted Average Shares		247,425		246,136		247,275		245,990

Net Income Per Share Available to Common
	Basic	$	0.83	$	1.23	$	2.98	$	4.35
	Diluted	$	0.82	$	1.21	$	2.93	$	4.28

-10-

The diluted earnings per share calculation excludes stock options/SARs that were anti-dilutive. The excluded stock options/SARs totaled 2.5 million and 2.0 million for the three months ended September 30, 2007 and 2006, respectively, and 3.7 million and 1.7 million for the nine months ended September 30, 2007 and 2006, respectively.

4. Supplemental Cash Flow Information

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

		Nine Months Ended
		September 30,
		2007		2006

Interest	$	26,551	$	25,174
Income Taxes	$	80,009	$	268,065

5. Comprehensive Income

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

					Three Months Ended				Nine Months Ended
					September 30,				September 30,
					2007		2006		2007		2006

Comprehensive Income
	Net Income			$	204,003	$	299,136	$	728,723	$	1,057,260
	Other Comprehensive Income (Loss)
		Foreign Currency Translation Adjustments			120,246		41		268,735		64,917
		Foreign Currency Swap Transaction			1,965		(1,741)		7,318		415
		Income Tax (Provision) Benefit Related
		to Foreign Currency Swap Transaction			(666)		513		(2,371)		(829)
		Deferred Postretirement Benefit Costs			37		-		114		-
			Total	$	325,585	$	297,949	$	1,002,519	$	1,121,763

-11-

6. Segment Information

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

				Three Months Ended				Nine Months Ended
				September 30,				September 30,
				2007		2006		2007		2006

Net Operating Revenues
	United States		$	770,259	$	747,894	$	2,231,717	$	2,207,153
	Canada			128,502		134,728		430,795		456,995
	Trinidad			79,315		69,928		240,253		244,357
	United Kingdom			12,387		16,176		37,222		72,664
		Total	$	990,463	$	968,726	$	2,939,987	$	2,981,169

Operating Income (Loss)
	United States		$	273,786	$	349,977	$	828,844	$	1,113,156
	Canada			14,987		58,574		143,922		225,055
	Trinidad			42,619		47,673		159,019		171,241
	United Kingdom			(6,453)		6,177		(3,053)		45,062
	Other			(81)		(135)		(153)		(167)
		Total		324,858		462,266		1,128,579		1,554,347

Reconciling Items
	Other Income, Net			6,311		13,832		22,236		41,413
	Interest Expense, Net			12,571		10,102		31,027		35,639
		Income Before Income Taxes	$	318,598	$	465,996	$	1,119,788	$	1,560,121

Total assets by reportable segment are presented below at September 30, 2007 and December 31, 2006 (in thousands):

				At		At
				September 30,		December 31,
				2007		2006
Total Assets
	United States		$	7,996,463	$	6,523,148
	Canada			2,653,772		2,146,846
	Trinidad			729,497		636,885
	United Kingdom			87,919		95,220
	Other			56		61
		Total	$	11,467,707	$	9,402,160

-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 nine-month periods ended September 30 (in thousands):

			Nine Months Ended
			September 30,
			2007		2006

Carrying Amount at Beginning of Period		$	182,406	$	161,488
	Liabilities Incurred		12,767		9,478
	Liabilities Settled		(4,768)		(4,706)
	Accretion		7,616		6,342
	Revisions		(126)		(52)
	Foreign Currency Translations		1,443		1,993
Carrying Amount at End of Period		$	199,338	$	174,543

Current Portion		$	8,709	$	5,371
Noncurrent Portion		$	190,629	$	169,172

8. Suspended Well Costs

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

			Nine Months
			Ended
			September 30,
			2007

Balance at December 31, 2006		$	77,365
	Additions Pending the Determination of Proved Reserves		104,821
	Reclassifications to Proved Properties		(21,388)
	Charged to Dry Hole Costs		(8,690)
	Foreign Currency Translations		6,782
	Other		(25,634)	(1)
Balance at September 30, 2007		$	133,256

(1) During the third quarter of 2007, EOG decided to no longer participate in the further evaluation of the Northwest Territories (NWT)
      discovery. In September 2007, EOG signed a purchase and sale agreement to sell all of its NWT interest to the outside operator, subject
      to certain conditions, with an anticipated closing during the fourth quarter of 2007. In conjunction with this decision, EOG recorded
      an impairment charge of approximately $21 million and reclassified the remaining NWT value of $5 million as an asset held for sale in Current Assets -
      Other on the Consolidated Balance Sheet.

-13-

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

			At
			September 30,
			2007

Capitalized exploratory well costs that have been
	capitalized for a period less than one year	$	125,509
Capitalized exploratory well costs that have been
	capitalized for a period greater than one year		7,747	(1)
	Total	$	133,256
Number of projects that have exploratory well costs that have been
	capitalized for a period greater than one year		1

(1) Amount represents costs incurred related to a domestic shale project. EOG has drilled and completed an exploratory well and is currently
collecting and analyzing well data in order to further assess the project's reserves.

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 is reasonably estimable.

10. Pension and Postretirement Benefits

Pension Plans. EOG has a non-contributory defined contribution pension plan and a matched defined contribution savings plan in place for most of its employees in the United States. For the nine months ended September 30, 2007 and 2006, EOG's total costs recognized for these pension plans were $11.6 million and $10.0 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 nine months ended September 30, 2007 and 2006, combined contributions to these pension plans were $1.5 million and $1.9 million, respectively.

Postretirement Plan. EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents. For the nine months ended September 30, 2007, EOG's total contributions to these plans amounted to approximately $88,000. The net periodic pension costs recognized for the postretirement medical and dental plans were approximately $536,000 and $501,000, respectively, for the nine months ended September 30, 2007 and 2006.

-14-

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

Long-Term Debt. EOG had no commercial paper borrowings outstanding at September 30, 2007. The weighted average interest rate for commercial paper borrowings for the nine months ended September 30, 2007 was 5.53%. EOG will repay at maturity the remaining $98 million principal amount of its 6.50% Notes due December 2007 and does not intend to refinance such notes on a long-term basis.

In addition to commercial paper, during August and September 2007, EOG utilized short-term funding from uncommitted credit facilities bearing market interest rates. There were no borrowings under these uncommitted credit facilities at September 30, 2007. The weighted average interest rate for such borrowings for the periods outstanding was 6.0%.

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. On September 14, 2007, EOG further amended the Agreement to provide EOG the ability to borrow up to $150 million within the facility at interest rates based on overnight rates for Federal funds. At September 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 the London InterBank Offering Rate plus an applicable margin (Eurodollar rate) or the base rate of the Agreement's administrative agent. At September 30, 2007, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 5.25% and 7.75%, respectively.

On September 10, 2007, EOG completed its public offering of $600 million aggregate principal amount of 5.875% Senior Notes due 2017. Interest on the notes is payable semi-annually on March 15 and September 15 of each year, beginning March 15, 2008. Net proceeds from the offering were approximately $594 million and were used for general corporate purposes, including repayment of outstanding commercial paper and borrowings under other uncommitted credit facilities.

During the first nine months of 2007, EOGI International Company, a wholly owned foreign subsidiary of EOG, repaid the remaining $60 million year-end 2006 outstanding balance of its $600 million, 3-year unsecured Senior Term Loan Agreement (Loan Agreement). As previously reported, EOG terminated its remaining borrowing capacity under the Loan Agreement during July 2006.

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 September 30, 2007, EOG had $75 million outstanding under the Credit Agreement. The applicable Eurodollar rate at September 30, 2007 was 5.97%. The weighted average Eurodollar rate for the amounts outstanding during the first nine months of 2007 was 5.76%.

Preferred Stock. During August 2007, EOG repurchased 10,000 shares of its 7.195% Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B for $11 million, plus accrued dividends up to the date of purchase. The premium associated with the repurchase is included as a component of preferred stock dividends.

Common Stock. On January 31, 2007, the Board increased EOG's quarterly cash dividend on its 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.

-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., together with 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 nine months of 2007 as compared to 79% in the same period of 2006. Based on current trends, EOG expects its total United States production to increase at a greater rate than its other operating areas for the remainder of 2007 and in 2008. EOG's major United States producing areas are Louisiana, Mississippi, New Mexico, Oklahoma, Texas, Utah and Wyoming.

In Trinidad, EOG continued to deliver natural gas under existing supply contracts. Under the Atlantic LNG Train 4 (ALNG) contract, EOG delivered gas at the contractual rate of 30 million cubic feet per day (MMcfd), gross (13 MMcfd, net) beginning in May 2007 when the ALNG plant 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 the third quarter of 2007, EOG executed a one-year term sheet, effective July 1, 2007, with Petroleum Company of Trinidad & Tobago that sets forth the pricing for the sales of crude oil and condensate produced in Trinidad. The pricing terms are based on the valuation of the distillation yield of the crude oil and condensate produced less a refining margin. This term sheet replaces the pricing provisions of a previous crude oil and condensate sales contract that expired on June 30, 2007 and will be incorporated into a new crude oil and condensate sales contract expected to be finalized in the fourth quarter of 2007.

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. An appraisal well is being drilled on this prospect with results expected in the fourth quarter of 2007. EOG also participated in the drilling of an unsuccessful exploratory well in August 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.

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 16% at September 30, 2007 compared to 12% at both June 30, 2007 and December 31, 2006. During the first nine months of 2007, EOG funded its capital programs by utilizing cash provided from its operating activities and net commercial paper, other uncommitted credit facilities and revolving credit facility borrowings. In September 2007, EOG issued $600 million aggregate principal amount of its 5.875% Senior Notes due 2017. Net proceeds of approximately $594 million from this issuance were used for general corporate purposes, including repayment of outstanding commercial paper and borrowings under other uncommitted credit facilities.

-16-

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 short-term 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 $3.7 billion, including 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. The Appalachian area includes approximately 3,000 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. In the third quarter of 2007, EOG began marketing these assets with the anticipation of receiving bids during the fourth quarter of 2007. If an acceptable bid is received, EOG expects to close the transaction during the first quarter of 2008.

Results of Operations

The following review of operations for the three and nine months ended September 30, 2007 and 2006 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Three Months Ended September 30, 2007 vs. Three Months Ended September 30, 2006

Net Operating Revenues. During the third quarter of 2007, net operating revenues increased $22 million, or 2%, to $990 million from $968 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 $80 million, or 9%, to $943 million from $863 million for the same period of 2006.

-17-

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

					Three Months Ended
					September 30,
					2007		2006
Natural Gas Volumes (MMcfd)
	United States				997		837
	Canada				216		224
			United States and Canada		1,213		1,061
	Trinidad				262		255
	United Kingdom				22		28
		Total			1,497		1,344

Average Natural Gas Prices ($/Mcf)⁽¹⁾
	United States			$	5.56	$	6.21
	Canada				5.49		5.65
			United States and Canada Composite		5.55		6.09
	Trinidad				2.20		2.21
	United Kingdom				5.89		6.09
		Composite			4.97		5.35

Crude Oil and Condensate Volumes (MBbld)⁽²⁾
	United States				25.3		20.6
	Canada				2.4		2.6
			United States and Canada		27.7		23.2
	Trinidad				4.2		4.4
	United Kingdom				0.1		0.1
		Total			32.0		27.7

Average Crude Oil and Condensate Prices ($/Bbl)⁽¹⁾
	United States			$	70.86	$	67.35
	Canada				69.99		63.87
			United States and Canada Composite		70.78		66.96
	Trinidad				67.03		74.26
	United Kingdom				66.96		59.09
		Composite			70.27		67.68

Natural Gas Liquids Volumes (MBbld)⁽²⁾
	United States				10.8		8.8
	Canada				0.9		0.7
		Total			11.7		9.5

Average Natural Gas Liquids Prices ($/Bbl)⁽¹⁾
	United States			$	47.94	$	44.33
	Canada				46.71		52.21
		Composite			47.84		44.89

Natural Gas Equivalent Volumes (MMcfed)⁽³⁾
	United States				1,213		1,015
	Canada				236		243
			United States and Canada		1,449		1,258
	Trinidad				288		281
	United Kingdom				22		29
		Total			1,759		1,568

Total Bcfe⁽³⁾					161.9		144.2

(1) Dollars per thousand cubic feet or per barrel, as applicable.
(2) Thousand barrels per day.
(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 third quarter of 2007 increased $22 million, or 3%, to $684 million from $662 million for the same period of 2006. The increase was due to increased natural gas deliveries ($75 million), partially offset by a lower composite average wellhead natural gas price ($53 million). The composite average wellhead price for natural gas decreased 7% to $4.97 per Mcf for the third quarter of 2007 from $5.35 per Mcf for the same period of 2006.

Natural gas deliveries increased 153 MMcfd, or 11%, to 1,497 MMcfd for the third quarter of 2007 from 1,344 MMcfd for the same period of 2006. The increase was due to higher production in the United States (160 MMcfd) and in Trinidad (7 MMcfd), partially offset by decreased production in Canada (8 MMcfd) and the United Kingdom (6 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (124 MMcfd), Kansas (16 MMcfd) and the Rocky Mountain area (14 MMcfd). The increase in Trinidad was due primarily to increased demand under the ALNG contract. The decrease in the United Kingdom was due primarily to production declines in the Valkyrie field.

Wellhead crude oil and condensate revenues for the third quarter of 2007 increased $45 million, or 28%, to $207 million from $162 million for the same period of 2006. The increase was due to increased wellhead crude oil and condensate deliveries ($37 million) and a higher composite average wellhead crude oil and condensate price ($8 million). The composite average wellhead crude oil and condensate price increased 4% to $70.27 per barrel for the third quarter of 2007 from $67.68 per barrel for the same period of 2006.

Natural gas liquids revenues for the third quarter of 2007 increased $12 million, or 31%, to $51 million from $39 million for the same period of 2006. The increase was due to increased deliveries ($9 million) and a higher composite average price ($3 million).

During the third quarter of 2007, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $44 million compared to a gain of $105 million for the same period of 2006. During the third quarter of 2007, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $33 million compared to the net cash inflow related to settled natural gas financial collar and price swap contracts of $73 million for the same period of 2006.

Operating and Other Expenses. For the third quarter of 2007, operating expenses of $666 million were $160 million higher than the $506 million incurred in the third quarter of 2006. The following table presents the costs per Mcfe for the three-month periods ended September 30:

			Three Months Ended
			September 30,
			2007		2006

Lease and Well		$	0.74	$	0.65
Transportation Costs			0.27		0.19
Depreciation, Depletion and Amortization (DD&A)			1.73		1.51
General and Administrative (G&A)			0.30		0.30
Interest Expense, Net			0.08		0.07
	Total Per-Unit Costs ⁽¹⁾	$	3.12	$	2.72

(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, and interest expense, net for the three months ended September 30, 2007 compared to the same period of 2006 are 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 $120 million for the third quarter of 2007 increased $26 million from $94 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($14 million) and Canada ($6 million), higher lease and well administrative expenses ($3 million), higher workover expenditures in the United States ($2 million) and changes in the Canadian exchange rate ($2 million).

Transportation costs represent costs incurred directly by EOG from third-party carriers associated with the delivery of hydrocarbon products from the lease to a 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 $44 million for the third quarter of 2007 increased $17 million from $27 million for the same prior year period primarily due to increased production in the Fort Worth Basin Barnett Shale Play and increased costs to transport such production to new 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 any of these factors may cause EOG's composite DD&A rate and expense to fluctuate from quarter to quarter.

DD&A expenses of $279 million for the third quarter of 2007 increased $63 million from the same prior year period primarily due to increased production in the United States ($33 million) and increased DD&A rates in the United States ($23 million) and Canada ($6 million).

Interest expense, net was $13 million for the third quarter of 2007, up $3 million compared to the same prior year period due to a slightly higher average debt balance ($5 million), partially offset by higher capitalized interest ($2 million).

Exploration costs of $39 million for the third quarter of 2007 increased $4 million from $35 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($7 million), partially offset by decreased geological and geophysical expenditures in Canada ($3 million).

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 $42 million for the third quarter of 2007 increased by $20 million compared to $22 million in the same prior year period primarily due to increased SFAS No. 144 related impairments ($16 million) and increased amortization of unproved leases in the United Kingdom ($2 million). The increase in SFAS No. 144 related impairments is due to an increase in Canada ($21 million) related to the Northwest Territories (NWT) discovery (see Note 8 to Consolidated Financial Statements), partially offset by a decrease in the United States ($5 million). Under SFAS No. 144, EOG recorded impairments of $24 million and $8 million for the third quarters of 2007 and 2006, respectively.

-20-

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 third quarter of 2007 decreased $7 million to $47 million (5.0% of wellhead revenues) from $54 million (6.3% of wellhead revenues) for the same prior year period. The decrease was due to higher 2007 credits taken for Texas high cost gas severance tax rate reductions ($9 million) and lower ad valorem/property taxes in the United States ($2 million), partially offset by an increase in severance/production taxes as a result of increased wellhead revenues in the United States ($4 million).

Other income, net was $6 million for the third quarter of 2007 compared to $14 million for the same prior year period. The decrease of $8 million was primarily due to lower interest income ($5 million) and lower equity income from investments in the Nitrogen (2000) Unlimited (Nitro2000) and Caribbean Nitrogen Company Limited ammonia plants ($2 million).

Income tax provision of $115 million for the third quarter of 2007 decreased $52 million compared to the same prior year period due primarily to decreased pretax income. The net effective tax rate of 36% was comparable to the same prior year period.

Nine Months Ended September 30, 2007 vs. Nine Months Ended September 30, 2006

Net Operating Revenues. During the first nine months of 2007, net operating revenues decreased $41 million, or 1%, to $2,940 million from $2,981 million for the same period of 2006. Total wellhead revenues increased $198 million, or 7%, to $2,862 million from $2,664 million for the same period of 2006.

-21-

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

					Nine Months Ended
					September 30,
					2007		2006
Natural Gas Volumes (MMcfd)
	United States				958		791
	Canada				223		226
			United States and Canada		1,181		1,017
	Trinidad				255		267
	United Kingdom				25		29
		Total			1,461		1,313

Average Natural Gas Prices ($/Mcf)
	United States			$	6.24	$	6.74
	Canada				6.22		6.60
			United States and Canada Composite		6.24		6.71
	Trinidad				2.35		2.28
	United Kingdom				5.29		8.27
		Composite			5.54		5.84

Crude Oil and Condensate Volumes (MBbld)
	United States				23.6		20.4
	Canada				2.4		2.5
			United States and Canada		26.0		22.9
	Trinidad				4.2		4.9
	United Kingdom				0.1		0.1
		Total			30.3		27.9

Average Crude Oil and Condensate Prices ($/Bbl)
	United States			$	62.52	$	65.00
	Canada				60.54		59.42
			United States and Canada Composite		62.33		64.35
	Trinidad				67.22		66.50
	United Kingdom				61.57		60.49
		Composite			63.01		64.68

Natural Gas Liquids Volumes (MBbld)
	United States				10.3		8.4
	Canada				1.0		0.7
		Total			11.3		9.1

Average Natural Gas Liquids Prices ($/Bbl)
	United States			$	43.73	$	41.10
	Canada				41.52		47.15
		Composite			43.52		41.55

Natural Gas Equivalent Volumes (MMcfed)
	United States				1,161		964
	Canada				244		245
			United States and Canada		1,405		1,209
	Trinidad				280		296
	United Kingdom				25		30
		Total			1,710		1,535

Total Bcfe					466.8		419.1

-22-

Wellhead natural gas revenues for the first nine months of 2007 increased $116 million, or 6%, to $2,210 million from $2,094 million for the same period of 2006. The increase was due to increased natural gas deliveries ($235 million), partially offset by a lower composite average wellhead natural gas price ($119 million).

Natural gas deliveries increased 148 MMcfd, or 11%, to 1,461 MMcfd for the first nine months of 2007 from 1,313 MMcfd for the same period of 2006. The increase was mainly due to higher production in the United States (167 MMcfd), partially offset by decreased production in Trinidad (12 MMcfd) and in the United Kingdom (4 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (124 MMcfd), the Rocky Mountain area (22 MMcfd) and Kansas (17 MMcfd). The decline in Trinidad was due primarily to reduced 2007 deliveries to ALNG (21 MMcfd), partially offset by increased contractual demand (9 MMcfd). During the first nine months of 2006, EOG supplied 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 2007 when ALNG reached commercial status and EOG began supplying gas under the ALNG take-or-pay contract. The decrease in the United Kingdom was due primarily to production declines in both the Arthur and Valkyrie fields.

Wellhead crude oil and condensate revenues for the first nine months of 2007 increased $50 million, or 11%, to $518 million from $468 million for the same period of 2006. The increase was due to increased wellhead crude oil and condensate deliveries ($64 million), partially offset by a lower composite average wellhead crude oil and condensate price ($14 million). The composite average wellhead crude oil and condensate price decreased 3% to $63.01 per barrel for the first nine months of 2007 from $64.68 per barrel for the same period of 2006.

Natural gas liquids revenues for the first nine months of 2007 increased $31 million, or 30%, to $134 million from $103 million for the same period of 2006. The increase was due to increased deliveries ($25 million) and a higher composite average price ($6 million).

During the first nine months of 2007, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $48 million compared to a gain of $303 million for the same period of 2006. During the first nine months of 2007, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $99 million compared to the net cash inflow related to settled natural gas financial collar and price swap contracts of $167 million for the same period of 2006.

Operating and Other Expenses. For the first nine months of 2007, operating expenses of $1,811 million were $384 million higher than the $1,427 million incurred in the same period of 2006. The following table presents the costs per Mcfe for the nine-month periods ended September 30:

			Nine Months Ended
			September 30,
			2007		2006

Lease and Well		$	0.75	$	0.64
Transportation Costs			0.26		0.19
DD&A			1.68		1.41
G&A			0.30		0.28
Interest Expense, Net			0.07		0.09
	Total Per-Unit Costs⁽¹⁾	$	3.06	$	2.61

(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 nine months ended September 30, 2007 compared to the same period of 2006 are set forth below.

-23-

Lease and well expenses of $348 million for the first nine months of 2007 were $79 million higher than the same prior year period primarily due to higher operating and maintenance expenses in the United States ($45 million) and Canada ($12 million), higher lease and well administrative expenses ($12 million) and higher workover expenditures in the United States ($10 million).

Transportation costs of $124 million for the first nine months of 2007 increased $43 million from $81 million for the same prior year period primarily due to increased production in the Fort Worth Basin Barnett Shale Play and increased costs to transport such production to new markets.

DD&A expenses of $783 million for the first nine months of 2007 increased $197 million from the same prior year period primarily due to increased production in the United States ($92 million), increased DD&A rates in the United States ($86 million) and Canada ($14 million) and changes in the Canadian exchange rate ($3 million).

G&A expenses of $139 million for the first nine months of 2007 were $22 million higher than the same prior year period primarily due to higher employee-related expenses ($16 million), higher office rent ($3 million) and higher insurance costs ($2 million).

Interest expense, net was $31 million for the first nine months of 2007, down $5 million compared to the same prior year period primarily due to higher capitalized interest ($6 million).

Exploration costs of $106 million for the first nine months of 2007 decreased $4 million from $110 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States ($6 million) and Canada ($1 million), partially offset by higher exploration administrative expenses ($2 million).

Impairments of $87 million for the first nine months of 2007 increased $19 million from $68 million for the same prior year period primarily due to increased SFAS No. 144 related impairments ($11 million) and increased amortization of unproved leases in the United States ($4 million), the United Kingdom ($2 million) and Canada ($1 million). The increase in SFAS No. 144 related impairments is due to an increase in Canada ($22 million) primarily related to the NWT discovery (see Note 8 to Consolidated Financial Statements), partially offset by a decrease in the United States ($11 million). Under SFAS No. 144, EOG recorded impairments of $40 million and $29 million for the nine months ended September 30, 2007 and 2006, respectively.

Taxes other than income for the first nine months of 2007 decreased $5 million to $150 million (5.2% of wellhead revenues) from $155 million (5.8% of wellhead revenues) for the same prior year period. The decrease was primarily due to a decrease in the United States offset by an increase in production taxes in Trinidad. In the United States, the decrease was due primarily to higher 2007 credits taken for Texas high cost gas severance tax rate reductions ($25 million), partially offset by an increase in severance/production taxes as a result of increased wellhead revenues ($14 million) and increased franchise taxes ($2 million). In Trinidad, increased production taxes were due to changes to legislation governing the Supplemental Petroleum Tax which resulted in an adjustment that decreased net production tax expense in the first nine months of 2006 ($2 million).

Other income, net was $22 million for the first nine months of 2007 compared to $41 million for the same prior year period. The decrease of $19 million was primarily due to lower interest income ($16 million) and lower equity income from Nitro2000 ($3 million).

Income tax provision of $391 million for the first nine months of 2007 decreased $112 million compared to the same prior year period due primarily to decreased pretax income ($154 million), partially offset by an increase in foreign income taxes ($40 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 nine months of 2007 increased to 35% from 32% for the same prior year period.

-24-

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2007 were funds generated from operations, the issuance of long-term debt, proceeds from employee stock option exercises and employee stock purchase plans, excess tax benefits from stock-based compensation and net commercial paper, other uncommitted credit facilities and revolving credit facility borrowings. The primary uses of cash were funds used in operations, exploration and development expenditures, dividend payments, repayments of debt, redemptions of preferred stock and debt issuance costs. During the first nine months of 2007, EOG's cash balance increased $84 million to $302 million from $218 million at December 31, 2006.

Net cash provided by operating activities of $2,146 million for the first nine months of 2007 increased $166 million compared to the same period of 2006 primarily reflecting an increase in wellhead revenues ($198 million) and a decrease in cash paid for income taxes ($188 million), partially offset by an increase in cash operating expenses ($80 million), a decrease in the net cash flows from settlement of financial commodity derivative contracts ($68 million) and unfavorable changes in working capital and other assets and liabilities ($46 million).

Net cash used in investing activities of $2,593 million for the first nine months of 2007 increased by $701 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 $524 million for the first nine months of 2007 compared to net cash used in financing activities of $144 million for the same period of 2006. Cash provided by financing activities for 2007 included the issuance of long-term debt ($600 million), proceeds from employee stock option exercises and employee stock purchase plans ($33 million), excess tax benefits from stock-based compensation ($17 million) and Trinidad revolving credit facility borrowings ($10 million). Cash used by financing activities for 2007 included cash dividends payments ($61 million), repayments of long-term borrowings ($60 million), redemptions of preferred stock ($11 million) and debt issuance costs ($5 million).

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

				Nine Months Ended
				September 30,
				2007		2006

United States			$	2,335	$	1,656
Canada				283		290
		United States and Canada		2,618		1,946
Trinidad				121		92
United Kingdom				14		20
Other				4		5
	Exploration and Development Expenditures			2,757		2,063
Asset Retirement Costs				15		10
	Total Exploration and Development Expenditures		$	2,772	$	2,073

Total exploration and development expenditures of $2,772 million for the first nine months of 2007 were $699 million higher than the same period of 2006. The 2007 exploration and development expenditures of $2,757 included $2,114 million in development, $620 million in exploration, $21 million in capitalized interest and $2 million in property acquisitions. The 2006 exploration and development expenditures of $2,063 included $1,546 million in development, $489 million in exploration, $14 million in property acquisitions and $14 million in capitalized interest.

Development expenditures were $568 million higher for the first nine months of 2007 due primarily to increased development drilling expenditures in the United States ($434 million) and increased expenditures related to infrastructure facilities in the United States ($136 million).

-25-

Exploration expenditures were $131 million higher for the first nine months of 2007 primarily due to increased expenditures for leasehold acquisitions in the United States ($55 million) and Canada ($13 million); and increased exploratory drilling expenditures, including dry hole costs, in the United States ($54 million), the United Kingdom ($12 million) and Canada ($9 million); partially offset by decreased exploratory drilling expenditures, including dry hole costs, in Trinidad ($14 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 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.

The total fair value of the natural gas financial price swap contracts at September 30, 2007 was a positive $80 million. Subsequent to September 30, 2007, EOG entered into additional natural gas financial price swap contracts covering notional volumes of 85,000 million British thermal units per day (MMBtud) for the period January 2008 through December 2008. Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at October 26, 2007 with notional volumes expressed in MMBtud and prices in dollars per million British thermal units ($/MMBtu). The average price of EOG's natural gas financial price swap contracts outstanding for 2008 is $8.55 per million British thermal units.

Natural Gas Financial Price Swap Contracts
		Weighted
	Volume	Average Price
	(MMBtud)	($/MMBtu)
2007
October (closed)	120,000	$ 9.14
November (closed)	120,000	9.94
December	120,000	10.70
2008
January	260,000	$ 9.03
February	260,000	9.04
March	260,000	8.85
April	260,000	8.10
May	260,000	8.06
June	260,000	8.14
July	260,000	8.22
August	260,000	8.30
September	260,000	8.34
October	260,000	8.43
November	260,000	8.86
December	260,000	9.30

-26-

The total fair value of the crude oil financial price swap contracts at September 30, 2007 was a negative $1 million. Presented below is a comprehensive summary of EOG's 2007 crude oil financial price swap contracts at October 26, 2007 with notional volumes expressed in barrels per day (Bbld) and prices in dollars per barrel ($/Bbl).

Crude Oil Financial Price Swap Contracts
		Weighted
	Volume	Average Price
	(Bbld)	($/Bbl)
2007
October	4,000	$ 77.91
November	4,000	77.75
December	4,000	77.57

-27-

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 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;

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.

-28-

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 29 through 32 of EOG's Annual Report on Form 10-K for the year ended December 31, 2006, filed on February 28, 2007; and (ii) Note 11, "Price, Interest Rate and Credit Risk Management Activities," on pages F-27 and F-28, to EOG's consolidated financial statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2006. There have been no material changes to this information.

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.

-29-

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 in 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⁾

July 1, 2007 - July 31, 2007	-	$	-	-	6,386,200
August 1, 2007 - August 31, 2007	32,209		71.90	-	6,386,200
September 1, 2007 - September 30, 2007	5,147		72.40	-	6,386,200
Total	37,356		71.97	-

(1) Represents 21,798 shares that were withheld by or returned to 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 units and 15,558 shares that were returned to EOG in payment
of the exercise price of employee stock options.
(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.

-30-

ITEM 6. EXHIBITS

4.1 -	Indenture, dated as of September 1, 1991, between EOG and The Bank of New York Trust Company, N.A. (as successor in interest to JPMorgan Chase Bank, N.A. (formerly known as Texas Commerce Bank National Association)) (incorporated by reference to Exhibit 4(a) to EOG's Registration Statement on Form S-3, Registration Statement No. 33-42640, filed September 6, 1991).

4.2 -	Officers' Certificate Establishing 5.875% Senior Notes due 2017 of EOG, dated September 10, 2007 (incorporated by reference to Exhibit 4.2 to EOG's Current Report on Form 8-K, filed September 10, 2007).

4.3 -	Form of Global Note with respect to the 5.875% Senior Notes due 2017 of EOG (incorporated by reference to Exhibit 4.3 to EOG's Current Report on Form 8-K, filed September 10, 2007).

*10.1 -	Third Amendment, dated September 14, 2007, to Revolving Credit Agreement, dated June 28, 2005, by and 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

-31-

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: October 29, 2007	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

-32-

EXHIBIT INDEX

Exhibit No.	Description

4.1 -	Indenture, dated as of September 1, 1991, between EOG and The Bank of New York Trust Company, N.A. (as successor in interest to JPMorgan Chase Bank, N.A. (formerly known as Texas Commerce Bank National Association)) (incorporated by reference to Exhibit 4(a) to EOG's Registration Statement on Form S-3, Registration Statement No. 33-42640, filed September 6, 1991).

4.2 -	Officers' Certificate Establishing 5.875% Senior Notes due 2017 of EOG, dated September 10, 2007 (incorporated by reference to Exhibit 4.2 to EOG's Current Report on Form 8-K, filed September 10, 2007).

4.3 -	Form of Global Note with respect to the 5.875% Senior Notes due 2017 of EOG (incorporated by reference to Exhibit 4.3 to EOG's Current Report on Form 8-K, filed September 10, 2007).

*10.1 -	Third Amendment, dated September 14, 2007, to Revolving Credit Agreement, dated June 28, 2005, by and 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

-33-