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, 2006

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.)

333 Clay Street, Suite 4200, Houston, Texas 77002-7361
(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, 2006.

Title of each class		Number of shares
Common Stock, par value $0.01 per share		243,471,673

EOG RESOURCES, INC.
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements

		Consolidated Statements of Income - Three Months Ended September 30, 2006 and 2005 and Nine Months Ended September 30, 2006 and 2005	3

		Consolidated Balance Sheets - September 30, 2006 and December 31, 2005	4

		Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2006 and 2005	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	28

	ITEM 4.	Controls and Procedures	28

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	29

	ITEM 1A.	Risk Factors	29

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29

	ITEM 6.	Exhibits	29

SIGNATURES			30

EXHIBIT INDEX			31

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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				Nine Months Ended
				September 30,				September 30,
				2006		2005		2006		2005


Net Operating Revenues
	Wellhead Natural Gas		$	661,920	$	751,239	$	2,093,950	$	1,919,909
	Wellhead Crude Oil, Condensate and Natural
	Gas Liquids			200,724		181,741		570,478		483,584
	Gains (Losses) on Mark-to-Market Commodity
	Derivative Contracts			104,696		-		302,742		(940)
	Other, Net			908		1,465		4,702		3,972
		Total		968,248		934,445		2,971,872		2,406,525

Operating Expenses
	Lease and Well			93,693		71,035		268,464		203,361
	Transportation Costs			26,632		20,975		80,641		58,375
	Exploration Costs			35,174		32,023		109,879		94,833
	Dry Hole Costs			16,356		19,130		41,750		56,249
	Impairments			22,106		18,292		67,559		54,695
	Depreciation, Depletion and Amortization			216,071		164,372		586,651		477,284
	General and Administrative			42,362		30,079		117,260		88,879
	Taxes Other Than Income			54,066		56,383		154,618		135,909
		Total		506,460		412,289		1,426,822		1,169,585

Operating Income				461,788		522,156		1,545,050		1,236,940
Other Income, Net				14,310		10,159		50,710		22,498
Income Before Interest Expense and Income Taxes				476,098		532,315		1,595,760		1,259,438
Interest Expense, Net				10,102		13,877		35,639		42,521
Income Before Income Taxes				465,996		518,438		1,560,121		1,216,917
Income Tax Provision				166,860		174,677		502,861		420,997
Net Income				299,136		343,761		1,057,260		795,920
Preferred Stock Dividends				1,858		1,857		5,574		5,573
Net Income Available to Common			$	297,278	$	341,904	$	1,051,686	$	790,347

Net Income Per Share Available to Common
	Basic		$	1.23	$	1.43	$	4.35	$	3.32
	Diluted		$	1.21	$	1.40	$	4.28	$	3.25

Average Number of Common Shares
	Basic			241,911		239,344		241,550		238,291
	Diluted			246,136		244,900		245,990		243,530

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

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

				September 30,		December 31,
				2006		2005
ASSETS
Current Assets
	Cash and Cash Equivalents		$	595,931	$	643,811
	Accounts Receivable, Net			656,523		762,207
	Inventories			117,385		63,215
	Assets from Price Risk Management Activities			125,893		11,415
	Deferred Income Taxes			-		24,376
	Other			87,269		58,214
		Total		1,583,001		1,563,238

Oil and Gas Properties (Successful Efforts Method)				13,188,912		11,173,389
	Less: Accumulated Depreciation, Depletion and Amortization			(5,734,736)		(5,086,210)
		Net Oil and Gas Properties		7,454,176		6,087,179
Other Assets				127,839		102,903
Total Assets			$	9,165,016	$	7,753,320


LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
	Accounts Payable		$	794,588	$	679,548
	Accrued Taxes Payable			143,896		140,902
	Dividends Payable			14,844		9,912
	Deferred Income Taxes			122,147		164,659
	Current Portion of Long-Term Debt			124,075		126,075
	Other			59,418		50,945
		Total		1,258,968		1,172,041

Long-Term Debt				705,442		858,992
Other Liabilities				310,063		283,407
Deferred Income Taxes				1,416,310		1,122,588

Shareholders' Equity
Preferred Stock, $0.01 Par, 10,000,000 Shares Authorized:
	Series B, 100,000 Shares Issued, Cumulative,
	$100,000,000 Liquidation Preference			99,240		99,062
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
249,460,000 Shares Issued				202,495		202,495
Additional Paid in Capital				121,298		84,705
Unearned Compensation				-		(36,246)
Accumulated Other Comprehensive Income				241,640		177,137
Retained Earnings				4,928,453		3,920,483
Common Stock Held in Treasury, 6,008,852 Shares at
September 30, 2006 and 7,385,862 Shares at December 31, 2005				(118,893)		(131,344)
		Total Shareholders' Equity		5,474,233		4,316,292
Total Liabilities and Shareholders' Equity			$	9,165,016	$	7,753,320

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

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

				Nine Months Ended
				September 30,
				2006		2005
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	1,057,260	$	795,920
	Items Not Requiring Cash
		Depreciation, Depletion and Amortization		586,651		477,284
		Impairments		67,559		54,695
		Stock-Based Compensation Expenses		38,407		8,825
		Deferred Income Taxes		258,465		172,015
		Other, Net		(9,738)		(103)
	Dry Hole Costs			41,750		56,249
	Mark-to-Market Commodity Derivative Contracts
		Total (Gains) Losses		(302,742)		940
		Realized Gains		166,892		9,807
	Tax Benefits from Stock Options Exercised			-		40,347
	Other, Net			8,316		(10,558)
	Changes in Components of Working Capital and Other Liabilities
		Accounts Receivable		110,517		(171,428)
		Inventories		(54,021)		(14,736)
		Accounts Payable		104,592		79,239
		Accrued Taxes Payable		(49,083)		8,018
		Other Liabilities		2,626		(1,164)
		Other, Net		18,093		804
	Changes in Components of Working Capital Associated with
		Investing and Financing Activities		(65,996)		(1,942)
Net Cash Provided by Operating Activities				1,979,548		1,504,212

Investing Cash Flows
	Additions to Oil and Gas Properties			(1,953,209)		(1,223,715)
	Proceeds from Sales of Assets			15,655		56,990
	Changes in Components of Working Capital Associated with
		Investing Activities		66,054		2,572
	Other, Net			(20,474)		(13,986)
Net Cash Used in Investing Activities				(1,891,974)		(1,178,139)

Financing Cash Flows
	Net Commercial Paper and Line of Credit Borrowings			-		40,150
	Long-Term Debt Borrowings			37,000		-
	Long-Term Debt Repayments			(192,550)		(75,000)
	Dividends Paid			(44,015)		(31,575)
	Excess Tax Benefits from Stock-Based Compensation Expenses			27,139		-
	Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			29,284		56,437
	Other, Net			(448)		(1,462)
Net Cash Used in Financing Activities				(143,590)		(11,450)

Effect of Exchange Rate Changes on Cash				8,136		5,458

(Decrease) Increase in Cash and Cash Equivalents				(47,880)		320,081
Cash and Cash Equivalents at Beginning of Period				643,811		20,980
Cash and Cash Equivalents at End of Period			$	595,931	$	341,061

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 (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 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, 2005 (EOG's 2005 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.

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 2005 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. In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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 benefit costs included in the income statement. SFAS No. 158 is effective for fiscal years ending after December 15, 2006 and requires prospective application. EOG does not expect the adoption of SFAS No. 158 to have a material impact on its financial statements.

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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 is currently assessing the impact, if any, that the adoption of FIN No. 48 will have on its financial statements.

As discussed more fully in Note 2, EOG adopted SFAS No. 123(R), "Share Based Payment," effective January 1, 2006, using the modified prospective application method. The standard requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, eliminating the exception to account for such awards using the intrinsic method previously allowable under Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." Prior to the adoption of SFAS No. 123(R), EOG included tax benefits resulting from the exercise of stock options in the operating activities section of the Consolidated Statements of Cash Flows. SFAS No. 123(R) requires that cash flows provided by excess tax benefits from stock compensation deductions be reflected in the financing activities section of the Consolidated Statements of Cash Flows and Unearned Compensation previously included separately in Shareholders' Equity be written off against Additional Paid in Capital at the date of adoption.

In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty." EITF Issue No. 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. The adoption of EITF Issue No. 04-13 did not have a material impact on EOG's financial statements.

Shelf Registration. On September 15, 2006, EOG filed an automatically effective shelf registration statement on Form S-3 (New Registration Statement) for the offer and sale from time to time of up to $688,237,500 of EOG's debt securities, preferred stock and common stock. The New Registration Statement was filed to replace EOG's existing shelf registration statement declared effective by the SEC in October 2000, under which EOG had sold no securities. As of the date hereof, EOG has not sold any securities under the New Registration Statement.

2. Stock-Based Compensation

At September 30, 2006, EOG maintained various stock-based compensation plans as discussed below. EOG adopted SFAS No. 123(R) effective January 1, 2006 using the modified prospective application method and accordingly has not restated any of its prior year results. Prior to the adoption of SFAS 123(R), EOG recognized compensation expense for its stock-based compensation plans under the provisions of APB Opinion No. 25. Stock-based compensation expense prior to January 1, 2006 consisted of amounts recognized in connection with grants of restricted stock and units. The adoption of SFAS No. 123(R) resulted in EOG recognizing compensation expense on grants made under its employee stock option plans and its employee stock purchase plan (ESPP). Stock-based compensation expense for the three and nine months ended September 30, 2006 included expense for all stock-based compensation awards that were not yet vested as of January 1, 2006 and all such awards granted after January 1, 2006 based upon the grant date estimated fair value of the awards. Such expense is computed net of forfeitures estimated based upon EOG's historical employee turnover rate. For awards made prior to January 1, 2006, compensation expense is amortized over the vesting period on a straight-line basis. For awards made subsequent to January 1, 2006, compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval. For periods subsequent to January 1, 2006, stock-based compensation expense is

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included in the Consolidated Statements of Income based upon job functions of the employees receiving the grants.

For the three and nine months ended September 30, 2006 and 2005, EOG compensation expense related to its stock-based compensation plans was as follows (in millions):

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2006		2005		2006		2005

Lease and Well	$	3.9	$	-	$	7.5	$	-
Exploration Costs		4.4		-		8.4		-
General and Administrative		10.5		3.1		22.5		8.8
	$	18.8	$	3.1	$	38.4	$	8.8

The impact of SFAS No. 123(R) was to reduce income before income taxes and net income during the three months ended September 30, 2006 by $7.4 million and $4.8 million, respectively, and to reduce both basic and diluted net income per share by $0.02. During the nine months ended September 30, 2006, the impact of SFAS No. 123(R) was to reduce income before income taxes and net income by $19.9 million and $12.8 million, respectively, and to reduce both basic and diluted net income per share by $0.05. Presented below are EOG's pro forma net income and net income per share available to common had compensation expense been recorded in accordance with SFAS No. 123, "Accounting for Stock-Based Compensation" for the three and nine months ended September 30, 2005 (in millions, except per share data):

			Three Months		Nine Months
			Ended		Ended
			September 30,		September 30,
			2005		2005

Net Income Available to Common - As Reported		$	341.9	$	790.3

Deduct: Total Stock-Based Employee Compensation
Expense, Net of Income Tax			(3.5)		(9.7)
Net Income Available to Common - Pro Forma		$	338.4	$	780.6

Net Income Per Share Available to Common
	Basic - As Reported	$	1.43	$	3.32
	Basic - Pro Forma	$	1.41	$	3.28
	Diluted - As Reported	$	1.40	$	3.25
	Diluted - Pro Forma	$	1.38	$	3.21

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 September 30, 2006, approximately 3.2 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, 2006, EOG held approximately 6.0 million shares of treasury stock.

Stock Options and Stock Appreciation Rights. Under the Plans, participants have been or may be granted the rights to acquire shares of common stock of EOG. In September 2006, EOG began granting Stock-Settled Stock Appreciation Rights (SARs) to the participants of the Plans. The SARs represent the right to receive shares of EOG common stock based on the appreciation in the stock price 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

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August 2004 and all 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 model. Effective May 2005, the fair value of stock option grants not containing the Capped Option feature and the fair value of SARs was estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock options, SARs and ESPP grants totaled $14.5 million and $28.0 million during the three and nine months ended September 30, 2006, respectively.

Weighted average fair values and valuation assumptions used to value stock options, SARs and ESPP grants during the nine months ended September 30, 2006 and 2005 are as follows:

		Stock Options/SARs				ESPP
		Nine Months Ended				Nine Months Ended
		September 30,				September 30,
		2006		2005		2006		2005

Weighted Average Fair Value of Grants	$	22.53	$	19.68	$	20.32	$	9.81
Expected Volatility		34.26%		31.84%		41.09%		30.32%
Risk-Free Interest Rate		4.96%		4.16%		4.89%		2.98%
Dividend Yield		0.30%		0.36%		0.30%		0.38%
Expected Life		5.1 yrs		5.0 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 SARs transactions for the nine months ended September 30, 2006 (options, SARs and dollars in thousands, except per share data):

						Weighted
			Weighted			Average
			Average		Aggregate	Remaining
	Number of		Grant		Intrinsic	Contractual
	Options/SARs		Price		Value⁽²⁾	Life
						(in years)
Outstanding at January 1, 2006	9,698	$	28.12
Granted	1,987		62.12
Exercised⁽¹⁾	(1,171)		24.20
Forfeited	(163)		44.06
Outstanding at September 30, 2006	10,351		34.83	$	314,507	6.0

Options/SARs Vested or Expected to Vest	9,794	$	34.74	$	298,485	6.0

Options/SARs Exercisable at September 30, 2006	5,492	$	20.60	$	244,106	5.2

(1) The total intrinsic value of options exercised for the nine months ended September 30, 2006 and 2005 was $55.7 million and $126.7 million, respectively. The intrinsic
value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the options.
(2) Based upon the difference between the closing market price of EOG's common stock on the last trading day of the quarter and the grant price of in-the-money options
and SARs.

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At September 30, 2006, unrecognized compensation expense related to non-vested stock options, SARs and ESPP grants totaled $85.6 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.7 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 granted vest to the employee at various times ranging from one to five years from the date of grant based on the nature of the 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 $4.3 million and $3.1 million for the three months ended September 30, 2006 and 2005, respectively, and $10.4 million and $8.8 million for the nine months ended September 30, 2006 and 2005, respectively.

The following table sets forth the restricted stock and units transactions for the nine months ended September 30, 2006 (shares, units and dollars in thousands, except per share data):

			Weighted
	Number of		Average		Aggregate
	Shares and		Grant Date		Intrinsic
	Units		Fair Value		Value⁽³⁾

Outstanding at January 1, 2006	2,544	$	26.04
Granted⁽¹⁾	525		64.22
Released⁽²⁾	(660)		20.74
Forfeited	(56)		41.71
Outstanding at September 30, 2006	2,353		35.68	$	153,036

(1) The weighted average grant date fair value of restricted stock and units granted for the nine months ended September 30, 2006 and 2005 was $64.22 and $32.41,
respectively.
(2) The total intrinsic value of restricted stock and units released for the nine months ended September 30, 2006 and 2005 was $47.6 million and $13.4 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.
(3) Based upon the closing market price of EOG's common stock on the last trading day of the quarter.

At September 30, 2006, unrecognized compensation expense related to restricted stock and units totaled $58.8 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 and nine months ended September 30 (in thousands, except per share data):

				Three Months Ended				Nine Months Ended
				September 30,				September 30,
				2006		2005		2006		2005

Numerator for Basic and Diluted Earnings Per Share -
	Net Income Available to Common		$	297,278	$	341,904	$	1,051,686	$	790,347

Denominator for Basic Earnings Per Share -
	Weighted Average Shares			241,911		239,344		241,550		238,291
	Potential Dilutive Common Shares -
		Stock Options and SARs		3,224		4,251		3,364		4,034
		Restricted Stock and Units		1,001		1,305		1,076		1,205
Denominator for Diluted Earnings Per Share -
	Adjusted Weighted Average Shares			246,136		244,900		245,990		243,530

Net Income Per Share Available to Common
	Basic		$	1.23	$	1.43	$	4.35	$	3.32
	Diluted		$	1.21	$	1.40	$	4.28	$	3.25

4. Supplemental Cash Flow Information

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

		Nine Months Ended
		September 30,
		2006		2005

Interest	$	25,174	$	30,892
Income Taxes	$	268,065	$	225,933

5. Comprehensive Income

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

					Three Months Ended				Nine Months Ended
					September 30,				September 30,
					2006		2005		2006		2005

Comprehensive Income
	Net Income			$	299,136	$	343,761	$	1,057,260	$	795,920
	Other Comprehensive Income (Loss)
		Foreign Currency Translation Adjustments			41		65,812		64,917		45,597
		Foreign Currency Swap Transaction			(1,741)		(2,537)		415		(7,267)
		Income Tax Benefit (Provision) Related
		to Foreign Currency Swap Transaction			513		904		(829)		2,519
			Total	$	297,949	$	407,940	$	1,121,763	$	836,769

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6. Segment Information

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

				Three Months Ended				Nine Months Ended
				September 30,				September 30,
				2006		2005		2006		2005

Net Operating Revenues
	United States		$	747,403	$	689,521	$	2,202,442	$	1,724,342
	Canada			134,728		162,203		456,995		434,402
	Trinidad			69,928		60,308		244,357		186,135	(1)
	United Kingdom			16,189		22,413		68,078		61,646
		Total	$	968,248	$	934,445	$	2,971,872	$	2,406,525

Operating Income (Loss)
	United States		$	349,486	$	386,642	$	1,108,445	$	851,792
	Canada			58,574		89,586		225,055		233,244
	Trinidad			47,673		38,406		171,241		131,818	(1)
	United Kingdom			6,190		7,522		40,476		20,086
	Other			(135)		-		(167)		-
		Total		461,788		522,156		1,545,050		1,236,940

Reconciling Items
	Other Income, Net			14,310		10,159		50,710		22,498
	Interest Expense, Net			10,102		13,877		35,639		42,521
		Income Before Income Taxes	$	465,996	$	518,438	$	1,560,121	$	1,216,917

(1) Includes $19.3 million recorded in the second quarter of 2005 related to an amended Trinidad take-or-pay contract.

Total assets by reportable segment is presented below at September 30, 2006 and December 31, 2005 (in thousands):

				At		At
				September 30,		December 31,
				2006		2005
Total Assets
	United States		$	6,255,357	$	5,176,701
	Canada			2,229,536		1,958,655
	Trinidad			595,273		538,671
	United Kingdom			84,826		79,293
	Other			24		-
		Total	$	9,165,016	$	7,753,320

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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 months ended September 30, 2006 (in thousands):

			Asset Retirement Obligations
			Short-Term		Long-Term		Total

Balance at December 31, 2005		$	6,235	$	155,253	$	161,488
	Liabilities Incurred		-		9,478		9,478
	Liabilities Settled		(3,753)		(953)		(4,706)
	Accretion		263		6,079		6,342
	Revisions		14		(66)		(52)
	Reclassifications		2,574		(2,574)		-
	Foreign Currency Translations		38		1,955		1,993
Balance at September 30, 2006		$	5,371	$	169,172	$	174,543

8. Suspended Well Costs

EOG's net changes in suspended well costs for the nine months ended September 30, 2006 in accordance with FASB Staff Position No. 19-1, "Accounting for Suspended Well Costs," are presented below (in thousands):

			Nine Months
			Ended
			September 30,
			2006

Balance at December 31, 2005		$	27,868
	Additions Pending the Determination of Proved Reserves		73,815
	Reclassifications to Proved Properties		(4,539)
	Charged to Dry Hole Costs		(405)
	Foreign Currency Translation		639
Balance at September 30, 2006		$	97,378

The following table provides an aging of suspended well costs as of September 30, 2006 (in thousands, except well count):

			As of
			September 30,
			2006

Capitalized exploratory well costs that have been
	capitalized for a period less than one year	$	69,915
Capitalized exploratory well costs that have been
	capitalized for a period greater than one year		27,463
	Total	$	97,378
Number of projects that have exploratory well costs that have been
	capitalized for a period greater than one year		2

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As of September 30, 2006, exploratory well costs capitalized for a period greater than one year included an outside operated, deepwater offshore Gulf of Mexico project ($4.3 million) and an outside operated, winter access only, Northwest Territories (NWT) project in Canada ($23.2 million). In the Gulf of Mexico project, EOG plans to participate in the drilling of an additional well in late 2006 or early 2007. In the NWT project, EOG is evaluating seismic data gathered in the third quarter of 2006.

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.

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, 2006 and 2005, EOG's total contributions to these pension plans were $10.0 million and $8.4 million, respectively.

In addition, as more fully discussed in Note 6 to Consolidated Financial Statements in EOG's 2005 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, 2006 and 2005, total contributions to these defined contribution pension plans were $0.9 million for both periods. For the nine months ended September 30, 2006, total contributions to these defined benefit pension plans amounted to approximately $270,000. The net periodic pension costs recognized for these pension plans were approximately $177,000 and $53,000, respectively, for the nine months ended September 30, 2006 and 2005.

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, 2006, EOG's total contributions to these plans amounted to approximately $81,000. The net periodic pension costs recognized for the postretirement medical and dental plans were approximately $501,000 and $273,000, respectively, for the nine months ended September 30, 2006 and 2005.

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11. Long-Term Debt and Preferred Stock

Long-Term Debt. In the first nine months of 2006, EOGI International Company, a wholly owned foreign subsidiary of EOG, repaid $190 million of the $250 million outstanding balance of its $600 million, 3-year unsecured Senior Term Loan Agreement (Term Loan Agreement). EOG terminated all remaining borrowing capacity under the Term Loan Agreement effective July 17, 2006. Borrowings under the Term Loan Agreement accrue interest based, at EOG's option, on either a London InterBank Offering Rate (LIBOR) plus an applicable margin or the base rate of the Term Loan Agreement's administrative agent. The applicable interest rate for the $60 million outstanding at September 30, 2006 was 5.72%. The weighted average interest rate for the amounts outstanding for the nine months ended September 30, 2006 was 5.37%.

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 LIBOR plus an applicable margin or the base rate of the Credit Agreement's administrative agent. EOG had $37 million outstanding under the Credit Agreement at September 30, 2006. The applicable interest rate at September 30, 2006 was 5.83%. The weighted average interest rate for the amounts outstanding for the period ended September 30, 2006 was 6.01%.

In June 2005, EOG entered into a 5-year $600 million unsecured Revolving Credit Agreement (Agreement). The Agreement was amended on June 21, 2006, effectively extending the scheduled maturity date to June 28, 2011. The Agreement provides for the allocation, at the option of EOG, of up to $75 million each to EOG's United Kingdom subsidiary and one of its Canadian subsidiaries. The Agreement also provides EOG the option to request letters of credit to be issued in an aggregate amount of up to $200 million. Interest accrues on advances based, at EOG's option, on either LIBOR plus an applicable margin (Eurodollar rate) or the base rate of the Agreement's administrative agent. There are no borrowings or letters of credit currently outstanding under the Agreement. The applicable base rate and Eurodollar rate, had there been an amount borrowed under the Agreement, would have been 8.25% and 5.50%, respectively, at September 30, 2006.

Preferred Stock. On October 11, 2006, EOG commenced a cash tender offer to purchase any and all of its 100,000 outstanding shares of its 7.195% Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 Liquidation Preference per share, at a price of $1,074.01 per share plus accrued and unpaid dividends up to the date of purchase. The tender offer will expire on November 8, 2006, unless it is extended or terminated by EOG.

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PART I. FINANCIAL INFORMATION

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EOG RESOURCES, INC.

Overview

EOG Resources, Inc. (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. EOG has several larger potential plays under way in Wyoming, Utah, Texas, Oklahoma and western Canada.

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), an LNG plant in Point Fortin, Trinidad, will continue to give its portfolio an even broader exposure to United States and Canada natural gas fundamentals.

In December 2005, ALNG began taking start-up gas and remained in the start-up phase through the third quarter of 2006. In the first quarter of 2006, a subsidiary of EOG, EOG Resources Trinidad Block 4(a) Unlimited, drilled two successful wells on Block 4(a). The subsidiary has obtained an exemption allowing it to bypass the market development phase and obtained an approval to develop Block 4(a) under a production sharing contract with the Government of Trinidad and Tobago signed in July 2005.

A subsidiary of EOG, EOG Resources Trinidad Limited (EOGRT), and the other participants in the South East Coast Consortium (SECC) Block signed a farm-out agreement covering the SECC Deep Ibis prospect with BP Trinidad and Tobago LLC (BP) during 2004. The SECC Deep Ibis well spud in April 2006, was drilled to a depth of approximately 19,000 feet and was abandoned and classified as a dry hole in the third quarter. BP paid the entire cost for drilling the exploratory well.

EOG continues its activities in the Southern Gas Basin of the United Kingdom North Sea. In addition to EOG's ongoing production from the Valkyrie and Arthur Fields, the Arthur 3 well began production in July 2006. EOG plans to review additional opportunities in the United Kingdom North Sea.

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 keep a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. At September 30, 2006, EOG's debt-to-total capitalization ratio was 13%, down slightly from 15% at June 30, 2006. During the first nine months of 2006, EOG funded its capital programs by utilizing cash provided from its operating activities. As management continues to assess price forecast and demand trends for 2006, EOG believes that operations and capital expenditure activity can be largely funded by cash from operations.

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For 2006, EOG's estimated exploration and development expenditure budget is $2.75 billion to $2.90 billion, including acquisitions. United States and Canada natural gas drilling activity continues to be a key component of these expenditures. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

On September 15, 2006, EOG filed an automatically effective shelf registration statement on Form S-3 (New Registration Statement) for the offer and sale from time to time of up to $688,237,500 of EOG's debt securities, preferred stock and common stock. The New Registration Statement was filed to replace EOG's existing shelf registration statement declared effective by the Securities and Exchange Commission in October 2000, under which EOG had sold no securities. As of the date hereof, EOG has not sold any securities under the New Registration Statement.

On October 11, 2006, EOG commenced a cash tender offer to purchase any and all of its 100,000 outstanding shares of its 7.195% Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 Liquidation Preference per share, at a price of $1,074.01 per share plus accrued and unpaid dividends up to the date of purchase. The tender offer will expire on November 8, 2006, unless it is extended or terminated by EOG.

Stock-Based Compensation. EOG adopted Statement of Financial Accounting Standards (SFAS) No. 123(R), "Share-Based Payment" effective January 1, 2006 using the modified prospective application method and accordingly has not restated any of its prior year results. See Note 2 to Consolidated Financial Statements. Prior to the adoption of SFAS No. 123(R), EOG recognized compensation expense for its stock-based compensation plans under the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." Stock-based compensation expense prior to January 1, 2006 consisted of amounts recognized in connection with grants of restricted stock and units. The adoption of SFAS No. 123(R) resulted in EOG recognizing compensation expense on grants made under its employee stock option plans and its employee stock purchase plan. For periods subsequent to January 1, 2006, stock-based compensation expense is included in the Consolidated Statements of Income based upon job functions of employees receiving the grants. For the three and nine months ended September 30, 2006 and 2005, EOG compensation expense related to its stock-based compensation plans was as follows (in millions):

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2006		2005		2006		2005

Lease and Well	$	3.9	$	-	$	7.5	$	-
Exploration Costs		4.4		-		8.4		-
General and Administrative		10.5		3.1		22.5		8.8
	$	18.8	$	3.1	$	38.4	$	8.8

Results of Operations

The following review of operations for the three and nine months ended September 30, 2006 and 2005 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 September 30, 2006 vs. Three Months Ended September 30, 2005

Net Operating Revenues. During the third quarter of 2006, net operating revenues increased $34 million, or 4%, to $968 million from $934 million for the same period in 2005. Total wellhead revenues, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, decreased $70 million, or 8%, to $863 million from $933 million for the same period in 2005.

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Wellhead volume and price statistics for the three months ended September 30 were as follows:

					Three Months Ended
					September 30,
					2006		2005
Natural Gas Volumes (MMcfd)⁽¹⁾
	United States				837		724
	Canada				224		226
			United States and Canada		1,061		950
	Trinidad				255		213
	United Kingdom				28		44
		Total			1,344		1,207

Average Natural Gas Prices ($/Mcf)⁽²⁾
	United States			$	6.21	$	8.19
	Canada				5.65		7.12
			United States and Canada Composite		6.09		7.94
	Trinidad				2.21		1.86
	United Kingdom				6.09		5.14
		Composite			5.35		6.77

Crude Oil and Condensate Volumes (MBbld)⁽¹⁾
	United States				20.6		21.2
	Canada				2.6		2.3
			United States and Canada		23.2		23.5
	Trinidad				4.4		4.2
	United Kingdom				0.1		0.3
		Total			27.7		28.0

Average Crude Oil and Condensate Prices ($/Bbl)⁽²⁾
	United States			$	67.35	$	61.63
	Canada				63.87		57.08
			United States and Canada Composite		66.96		61.19
	Trinidad				74.26		61.93
	United Kingdom				59.09		53.80
		Composite			67.68		61.22

Natural Gas Liquids Volumes (MBbld)⁽¹⁾
	United States				8.8		6.0
	Canada				0.7		0.3	(3)
		Total			9.5		6.3

Average Natural Gas Liquids Prices ($/Bbl)⁽²⁾
	United States			$	44.33	$	39.80
	Canada				52.21		69.43	(3)
		Composite			44.89		41.25

Natural Gas Equivalent Volumes (MMcfed)⁽⁴⁾
	United States				1,015		887
	Canada				243		242
			United States and Canada		1,258		1,129
	Trinidad				281		238
	United Kingdom				29		46
		Total			1,568		1,413

Total Bcfe⁽⁴⁾					144.2		130.0

(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) Includes 0.08 MBbld adjustment in the third quarter of 2005. Excluding the adjustment, the average
natural gas liquids price was $44.50.
(4) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural
gas, crude oil, condensate and natural gas liquids.

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Wellhead natural gas revenues for the third quarter of 2006 decreased $89 million, or 12%, to $662 million from $751 million for the same period in 2005. The decrease was due to a lower composite average wellhead natural gas price ($174 million), partially offset by increased natural gas deliveries ($85 million). The composite average wellhead price for natural gas decreased 21% to $5.35 per Mcf for the third quarter of 2006 from $6.77 per Mcf for the same period in 2005.

Natural gas deliveries increased 137 MMcfd, or 11%, to 1,344 MMcfd for the third quarter of 2006 from 1,207 MMcfd for the same period in 2005. The increase was primarily due to higher production in the United States (113 MMcfd) and Trinidad (42 MMcfd), partially offset by decreased production in the United Kingdom (16 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (89 MMcfd) and the Rocky Mountain area (28 MMcfd). The increase in Trinidad was due to the commencement of two contracts in the fourth quarter of 2005 (25 MMcfd) and increased contractual demand (67 MMcfd), partially offset by a decrease in volumes as a result of the completion of a cost recovery arrangement (50 MMcfd). 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 third quarter of 2006 increased $4 million, or 3%, to $162 million from $158 million for the same period in 2005. The increase was due to a higher composite average wellhead crude oil and condensate price ($15 million), partially offset by decreased wellhead crude oil and condensate sales ($11 million). The composite average wellhead crude oil and condensate price increased 11% to $67.68 per barrel for the third quarter of 2006 from $61.22 per barrel for the same period in 2005.

Natural gas liquids revenues for the third quarter of 2006 increased $15 million, or 63%, to $39 million from $24 million for the same period in 2005. The increase was due to increases in deliveries ($12 million) and the composite average price ($3 million).

During the third quarter of 2006, EOG recognized a gain of $105 million from natural gas financial collar and natural gas and crude oil financial price swap contracts, and the net cash inflow related to settled natural gas financial collar and price swap contracts was $73 million. During the third quarter of 2005, EOG was not a party to any financial commodity derivative contracts.

Operating and Other Expenses. For the third quarter of 2006, operating expenses of $506 million were $94 million higher than the $412 million incurred in the third quarter of 2005. The following table presents the costs per Mcfe for the three months ended September 30:

			Three Months Ended
			September 30,
			2006		2005

Lease and Well		$	0.65	$	0.55
Transportation Costs			0.19		0.16
Depreciation, Depletion and Amortization (DD&A)			1.51		1.26
General and Administrative (G&A)			0.30		0.23
Taxes Other Than Income			0.38		0.43
Interest Expense, Net			0.07		0.11
	Total Per-Unit Costs⁽¹⁾	$	3.10	$	2.74

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

The higher per-unit rates of lease and well, transportation costs, DD&A and G&A for the three months ended September 30, 2006 compared to the same period in 2005 were due primarily to the reasons set forth below.

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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 $94 million for the third quarter of 2006 increased $23 million from $71 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($10 million), Trinidad ($2 million) and Canada ($1 million); higher lease and well administrative expenses, including stock-based compensation expenses, in the United States ($6 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 $27 million for the third quarter of 2006 increased $6 million from $21 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 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 period to period.

DD&A expenses of $216 million for the third quarter of 2006 increased $52 million from the same prior year period primarily due to increased DD&A rates in the United States ($28 million), United Kingdom ($3 million), and Canada ($2 million); increased production in the United States ($17 million); and changes in the Canadian exchange rate ($2 million); partially offset by decreased production in the United Kingdom ($2 million).

G&A expenses of $42 million for the third quarter of 2006 were $12 million higher than the same prior year period primarily due to higher employee-related costs ($10 million) and higher insurance costs ($1 million). The increase in employee-related costs primarily reflects higher stock-based compensation expense ($7 million).

Interest expense, net was $10 million for the third quarter of 2006, down $4 million compared to the same prior year period due to a lower average debt balance ($2 million) and higher capitalized interest ($2 million).

Exploration costs of $35 million for the third quarter of 2006 increased $3 million from $32 million for the same prior year period primarily due to higher employee-related costs ($7 million), including stock-based compensation expenses ($4 million), partially offset by decreased geological and geophysical expenditures in the United States ($5 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 $22 million for the third quarter of 2006 increased by $4 million compared to $18 million in the same prior year period primarily due to increased SFAS No. 144 related impairments in the United States ($2 million) and increased amortization of

-20-

unproved leases in the United States ($1 million) and Canada ($1 million). EOG recorded impairments of $8 million and $6 million for the third quarters of 2006 and 2005, respectively, under SFAS No. 144 for properties in the United States.

Other income, net was $14 million for the third quarter of 2006 compared to $10 million for the same prior year period. The increase of $4 million was primarily due to higher interest income ($6 million) and increased equity income from investment in the Nitrogen (2000) Unlimited (Nitro2000) ammonia plant ($2 million), partially offset by lower gains on sales of properties ($5 million).

Income tax provision of $167 million for the third quarter of 2006 decreased $8 million compared to the same prior year period due primarily to decreased pretax income ($18 million), partially offset by higher foreign income taxes ($10 million), largely related to a United Kingdom corporate tax rate increase ($7 million). The net effective tax rate for the third quarter of 2006 increased to 36% from 34% for the same prior year period.

Nine Months Ended September 30, 2006 vs. Nine Months Ended September 30, 2005

Net Operating Revenues. During the first nine months of 2006, net operating revenues increased $565 million, or 23%, to $2,972 million from $2,407 million for the same period in 2005. Total wellhead revenues increased $261 million, or 11%, to $2,664 million from $2,403 million for the same period in 2005.

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Wellhead volume and price statistics for the nine months ended September 30 were as follows:

					Nine Months Ended
					September 30,
					2006		2005
Natural Gas Volumes (MMcfd)
	United States				791		707
	Canada				226		229
			United States and Canada		1,017		936
	Trinidad				267		210
	United Kingdom				29		38
		Total			1,313		1,184

Average Natural Gas Prices ($/Mcf)
	United States			$	6.74	$	6.96
	Canada				6.60		6.28
			United States and Canada Composite		6.71		6.79
	Trinidad				2.28		2.18	(1)
	United Kingdom				8.27		5.72
		Composite			5.84		5.94

Crude Oil and Condensate Volumes (MBbld)
	United States				20.4		21.8
	Canada				2.5		2.4
			United States and Canada		22.9		24.2
	Trinidad				4.9		4.2
	United Kingdom				0.1		0.2
		Total			27.9		28.6

Average Crude Oil and Condensate Prices ($/Bbl)
	United States			$	65.00	$	53.75
	Canada				59.42		49.26
			United States and Canada Composite		64.35		53.30
	Trinidad				66.50		53.56
	United Kingdom				60.49		48.75
		Composite			64.68		53.30

Natural Gas Liquids Volumes (MBbld)
	United States				8.4		6.5
	Canada				0.7		1.0
		Total			9.1		7.5

Average Natural Gas Liquids Prices ($/Bbl)
	United States			$	41.10	$	33.07
	Canada				47.15		33.10
		Composite			41.55		33.08

Natural Gas Equivalent Volumes (MMcfed)
	United States				964		876
	Canada				245		250
			United States and Canada		1,209		1,126
	Trinidad				296		236
	United Kingdom				30		39
		Total			1,535		1,401

Total Bcfe					419.1		382.3

(1) Includes $0.34 per Mcf as a result of a revenue adjustment in the second quarter of 2005 related to an amended Trinidad take-or-pay contract.

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Wellhead natural gas revenues for the first nine months of 2006 increased $174 million, or 9%, to $2,094 million from $1,920 million for the same period in 2005. The increase was due to increased natural gas deliveries ($207 million), offset by a lower composite average wellhead natural gas price ($14 million) and a revenue adjustment related to an amended Trinidad take-or-pay contract ($19 million) in the second quarter of 2005.

Natural gas deliveries increased 129 MMcfd, or 11%, to 1,313 MMcfd for the first nine months of 2006 from 1,184 MMcfd for the same period in 2005. The increase was mainly due to higher production in the United States (84 MMcfd) and Trinidad (57 MMcfd), partially offset by decreased production in the United Kingdom (9 MMcfd). The increase in the United States was attributable to increased production in Texas (73 MMcfd), the Rocky Mountain area (22 MMcfd) and Louisiana (7 MMcfd), partially offset by decreased production in offshore Gulf of Mexico (18 MMcfd). The decrease in Gulf of Mexico production was partially due to continued shut-in production from hurricanes Katrina and Rita. The increase in Trinidad was due to the commencement of two contracts in the fourth quarter of 2005 (61 MMcfd) and increased contractual demand (47 MMcfd), partially offset by a decrease in volumes as a result of the completion of a cost recovery arrangement (51 MMcfd). 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 2006 increased $52 million, or 13%, to $468 million from $416 million for the same period in 2005. The increase was due to a higher composite average wellhead crude oil and condensate price ($82 million), partially offset by decreased wellhead crude oil and condensate sales ($30 million). The composite average wellhead crude oil and condensate price increased 21% to $64.68 per barrel for the first nine months of 2006 from $53.30 per barrel for the same period in 2005.

Natural gas liquids revenues for the first nine months of 2006 increased $35 million, or 52%, to $102 million from $67 million for the same period in 2005. The increase was due to increases in the composite average price ($21 million) and deliveries ($14 million).

During the first nine months of 2006, EOG recognized a gain of $303 million from natural gas financial collar and natural gas and crude oil financial price swap contracts, and the net cash inflow related to settled natural gas financial collar and price swap contracts was $167 million. During the first nine months of 2005, EOG recognized a loss of $1 million from natural gas financial collar contracts, and the net cash inflow related to settled natural gas financial collar contracts was $10 million.

Operating and Other Expenses. For the first nine months of 2006, operating expenses of $1,427 million were $257 million higher than the $1,170 million incurred in the same period in 2005. The following table presents the costs per Mcfe for the nine months ended September 30:

			Nine Months Ended
			September 30,
			2006		2005

Lease and Well		$	0.64	$	0.53
Transportation Costs			0.19		0.15
DD&A			1.41		1.25
G&A			0.28		0.23
Taxes Other Than Income			0.37		0.36
Interest Expense, Net			0.09		0.11
	Total Per-Unit Costs⁽¹⁾	$	2.98	$	2.63

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

The higher per-unit rates of lease and well, transportation costs, DD&A, G&A and taxes other than income for the nine months ended September 30, 2006 compared to the same period in 2005 were due primarily to the reasons set forth below.

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Lease and well expenses of $268 million for the first nine months of 2006 were $65 million higher than the same prior year period primarily due to higher operating and maintenance expenses in the United States ($27 million), Canada ($12 million) and Trinidad ($4 million); higher lease and well administrative expenses, including stock-based compensation expenses, in the United States ($11 million) and Canada ($3 million); and changes in the Canadian exchange rate ($6 million).

Transportation costs of $81 million for the first nine months of 2006 increased $23 million from $58 million for the same prior year period primarily due to increased production in the Fort Worth Basin Barnett Shale Play.

DD&A expenses of $587 million for the first nine months of 2006 increased $110 million from the same prior year period primarily due to increased DD&A rates in the United States ($52 million), Canada ($8 million) and the United Kingdom ($8 million), increased production in the United States ($33 million) and Trinidad ($4 million), and changes in the Canadian exchange rate ($8 million).

G&A expenses of $117 million for the first nine months of 2006 were $28 million higher than the same prior year period primarily due to higher employee-related expenses ($21 million) and higher insurance costs ($3 million). The increase in employee-related costs primarily reflects higher stock-based compensation expense ($14 million).

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Taxes other than income of $155 million for the first nine months of 2006 were $19 million higher than the same prior year period primarily due to increases in the United States and Trinidad. In the United States, severance/production taxes increased due primarily to increased wellhead revenues ($10 million), partially offset by an increase in credits taken for a Texas high cost gas severance tax exemption ($8 million). Ad valorem/property taxes increased primarily due to higher property valuations in the United States ($10 million). In Trinidad, increased production taxes were due to increased revenues from crude oil and condensate ($12 million), partially offset by changes to the tax legislation governing the Supplemental Petroleum Tax ($9 million).

Interest expense, net was $36 million for the first nine months of 2006, down $7 million compared to the same prior year period primarily due to higher capitalized interest ($4 million) and a lower average debt balance ($3 million).

Exploration costs of $110 million for the first nine months of 2006 increased $15 million from $95 million for the same prior year period primarily due to higher employee-related costs, including stock-based compensation expenses.

Impairments of $68 million for the first nine months of 2006 were $13 million higher than the same prior year period primarily due to increased impairments to the carrying value of long-lived assets in the United States ($9 million), increased amortization of unproved leases in Canada ($2 million) and the United States ($1 million) and changes in the Canadian exchange rate ($1 million). EOG recorded impairments of $29 million and $20 million for the nine months ended September 30, 2006 and 2005, respectively, under SFAS No. 144 for properties in the United States.

Other income, net was $51 million for the first nine months of 2006 compared to $22 million for the same prior year period. The increase of $29 million was primarily due to higher interest income ($19 million), increased equity income from investments in Nitro2000 and Caribbean Nitrogen Company Limited ($5 million), and decreased net foreign currency transaction losses ($3 million).

Income tax provision of $503 million for the first nine months of 2006 increased $82 million compared to the same prior year period due primarily to increased pretax income ($120 million) and a United Kingdom corporate tax rate increase ($7 million), partially offset by a decrease in other foreign income taxes ($45 million), largely related to a Canadian federal tax rate reduction ($19 million) and an Alberta, Canada provincial tax rate reduction ($13 million). The net effective tax rate for the first nine months of 2006 decreased to 32% from 35% for the same prior year period.

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Capital Resources and Liquidity

Cash Flow. The primary source of cash for EOG during the nine months ended September 30, 2006 was funds generated from operations. The primary uses of cash were funds used in operations, exploration and development expenditures, repayment of debt and dividend payments to shareholders. During the first nine months of 2006, EOG's cash balance decreased $48 million to $596 million from $644 million at December 31, 2005.

Net cash provided by operating activities of $1,980 million for the first nine months of 2006 increased $475 million compared to the same period in 2005 primarily reflecting an increase in wellhead revenues ($261 million), favorable changes in working capital and other liabilities ($168 million) and a change in the net cash flows from settlement of financial commodity derivative contracts ($157 million), partially offset by an increase in cash operating expenses ($150 million).

Net cash used in investing activities of $1,892 million for the first nine months of 2006 increased by $714 million compared to the same period in 2005 due primarily to increased additions to oil and gas properties ($729 million), decreased proceeds from sales of oil and gas properties ($23 million) and proceeds received in 2005 from sales of partial interests in certain equity investments in Trinidad ($18 million), partially offset by changes in working capital associated with investing activities ($63 million).

Net cash used in financing activities was $144 million for the first nine months of 2006 compared to net cash used of $11 million for the same period in 2005. Financing activities in 2006 included repayment of long-term debt ($193 million), cash dividend payments ($44 million), long-term debt borrowings ($37 million), proceeds from sales of treasury stock attributable to employee stock option exercises and employee stock purchase plan ($29 million) and excess tax benefits from stock-based compensation expenses ($27 million).

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

				Nine Months Ended
				September 30,
				2006		2005

United States			$	1,661	$	1,030
Canada				290		221
		United States and Canada		1,951		1,251
Trinidad				92		36
United Kingdom				20		32
	Exploration and Development Expenditures			2,063		1,319
Asset Retirement Costs				10		6
	Total Exploration and Development Expenditures		$	2,073	$	1,325

Total exploration and development expenditures of $2,073 million for the first nine months of 2006 were $748 million higher than the same period in 2005. The 2006 exploration and development expenditures of $2,063 included $1,546 million in development, $489 million in exploration, $14 million in capitalized interest and $14 million in property acquisitions. The 2005 exploration and development expenditures of $1,319 included $911 million in development, $367 million in exploration, $30 million in property acquisitions and $11 million in capitalized interest.

Development expenditures were $635 million higher for the first nine months of 2006 due primarily to increased development drilling expenditures in the United States ($491 million) and Canada ($43 million), increased expenditures related to infrastructure facilities in the United States ($52 million) and Trinidad ($13 million), increased recompletions in the United States ($30 million) and changes in the Canadian exchange rate ($16 million).

Exploration expenditures were $122 million higher for the first nine months of 2006 primarily due to increased exploratory drilling expenditures, including dry hole costs, in the United States ($42 million) and Trinidad ($41 million); increased expenditures for leasehold acquisitions in the United States ($29 million); higher exploration

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administrative expenses, including stock-based compensation expense ($16 million); and changes in the Canadian exchange rate ($8 million); partially offset by decreased exploratory drilling expenditures, including dry hole costs, in the United Kingdom ($17 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. There are no material continuing commitments associated with expenditure plans.

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, 2005, 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.

Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at October 31, 2006 with prices expressed in dollars per million British thermal units ($/MMBtu) and notional volumes in million British thermal units per day (MMBtud). The average price of EOG's 2007 natural gas financial price swap contracts is $9.76 per MMBtu. Currently, EOG is not a party to any natural gas financial collar contracts. The total fair value of the natural gas financial price swap contracts at September 30, 2006 was a positive $133 million.

Natural Gas Financial Price Swap Contracts
		Weighted
	Volume	Average Price
	(MMBtud)	($/MMBtu)
2006
October (closed)	305,000	$ 8.18
November (closed)	100,000	9.12
December	100,000	10.39
2007
January	105,000	$11.24
February	105,000	11.26
March	105,000	11.07
April	105,000	8.90
May	105,000	8.72
June	105,000	8.82
July	105,000	8.92
August	105,000	9.00
September	105,000	9.09
October	105,000	9.23
November	105,000	10.08
December	105,000	10.89

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Presented below is a comprehensive summary of EOG's 2007 crude oil price swap contracts at October 31, 2006 with prices expressed in dollars per barrels ($/Bbl) and notional volumes in barrels per day (Bbld). The average price of EOG's 2007 crude oil financial price swap contracts is $78.22 per Bbl. The total fair value of the crude oil financial price swap contracts at September 30, 2006 was a positive $14 million.

Crude Oil Financial Price Swap Contracts
		Weighted
	Volume	Average Price
	(Bbld)	($/Bbl)
2007
January	4,000	$78.42
February	4,000	78.55
March	4,000	78.58
April	4,000	78.57
May	4,000	78.50
June	4,000	78.40
July	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 and interest rates; the timing and impact of liquefied natural gas imports and changes in demand or prices for ammonia or methanol; the extent and effect of any hedging activities engaged in by EOG; 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 availability and cost of drilling rigs, experienced drilling crews, materials and equipment used in well completions, and tubular steel; the availability, terms and timing of governmental and other permits and rights of way; the availability of pipeline transportation capacity; 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; acts of war and terrorism and responses to these acts; weather; and financial market conditions. 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 31 through 33 of EOG's Annual Report on Form 10-K for the year ended December 31, 2005, filed on February 23, 2006.

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 SEC'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, 2005.

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, 2006 - July 31, 2006	1,036	$	68.49	-	6,386,200
August 1, 2006 - August 31, 2006	40,500		69.62	-	6,386,200
September 1, 2006 - September 30, 2006	15		62.15	-	6,386,200
Total	41,551			-

(1) Comprises 21,802 shares that were returned to EOG in payment of the exercise price of employee stock options and 19,749 shares that were 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.

ITEM 6. EXHIBITS

*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: November 1, 2006	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Accounting Officer (Principal Accounting Officer)

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EXHIBIT INDEX

Exhibit No.	Description

*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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