Edgar Filing: EOG RESOURCES INC

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

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 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 July 25, 2006.

Title of each class		Number of shares
Common Stock, par value $0.01 per share		242,609,724

EOG RESOURCES, INC.
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements

		Consolidated Statements of Income - Three Months Ended June 30, 2006 and 2005 and Six Months Ended June 30, 2006 and 2005	3

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

		Consolidated Statements of Cash Flows - Six Months Ended June 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	15

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	27

	ITEM 4.	Controls and Procedures	27

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	28

	ITEM 1A.	Risk Factors	28

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28

	ITEM 4.	Submission of Matters to a Vote of Security Holders	28

	ITEM 6.	Exhibits	29

SIGNATURES			30

EXHIBIT INDEX			31

PART I. FINANCIAL INFORMATION

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

				Three Months Ended				Six Months Ended
				June 30,				June 30,
				2006		2005		2006		2005


Net Operating Revenues
	Wellhead Natural Gas		$	642,969	$	625,564	$	1,432,030	$	1,168,670
	Wellhead Crude Oil, Condensate and Natural
	Gas Liquids			185,036		157,307		369,754		301,843
	Gains (Losses) on Mark-to-Market Commodity
	Derivative Contracts			91,022		-		198,046		(940)
	Other, Net			61		1,053		3,794		2,507
		Total		919,088		783,924		2,003,624		1,472,080

Operating Expenses
	Lease and Well			87,287		66,558		174,771		132,326
	Transportation Costs			25,913		20,293		54,009		37,400
	Exploration Costs			35,313		27,994		74,705		62,810
	Dry Hole Costs			14,668		22,537		25,394		37,119
	Impairments			22,680		24,231		45,453		36,403
	Depreciation, Depletion and Amortization			192,928		159,896		370,580		312,912
	General and Administrative			38,607		30,113		74,898		58,800
	Taxes Other Than Income			46,858		37,613		100,552		79,526
		Total		464,254		389,235		920,362		757,296

Operating Income				454,834		394,689		1,083,262		714,784
Other Income, Net				21,844		6,874		36,400		12,339
Income Before Interest Expense and Income Taxes				476,678		401,563		1,119,662		727,123
Interest Expense, Net				12,384		14,687		25,537		28,644
Income Before Income Taxes				464,294		386,876		1,094,125		698,479
Income Tax Provision				132,877		137,420		336,001		246,320
Net Income				331,417		249,456		758,124		452,159
Preferred Stock Dividends				1,858		1,858		3,716		3,716
Net Income Available to Common			$	329,559	$	247,598	$	754,408	$	448,443

Net Income Per Share Available to Common
	Basic		$	1.36	$	1.04	$	3.13	$	1.89
	Diluted		$	1.34	$	1.02	$	3.07	$	1.85

Average Number of Common Shares
	Basic			241,613		238,252		241,370		237,752
	Diluted			245,887		243,414		245,827		242,771

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

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

				June 30,		December 31,
				2006		2005
ASSETS
Current Assets
	Cash and Cash Equivalents		$	759,108	$	643,811
	Accounts Receivable, Net			597,564		762,207
	Inventories			98,430		63,215
	Assets from Price Risk Management Activities			108,344		11,415
	Deferred Income Taxes			-		24,376
	Other			35,264		58,214
		Total		1,598,710		1,563,238

Oil and Gas Properties (Successful Efforts Method)				12,446,522		11,173,389
	Less: Accumulated Depreciation, Depletion and Amortization			(5,512,505)		(5,086,210)
		Net Oil and Gas Properties		6,934,017		6,087,179
Other Assets				109,430		102,903
Total Assets			$	8,642,157	$	7,753,320


LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
	Accounts Payable		$	680,575	$	679,548
	Accrued Taxes Payable			131,150		140,902
	Dividends Payable			14,799		9,912
	Deferred Income Taxes			83,672		164,659
	Current Portion of Long-Term Debt			124,075		126,075
	Other			48,246		50,945
		Total		1,082,517		1,172,041

Long-Term Debt				768,442		858,992
Other Liabilities				296,407		283,407
Deferred Income Taxes				1,346,395		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			99,181		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				91,852		84,705
Unearned Compensation				-		(36,246)
Accumulated Other Comprehensive Income				242,827		177,137
Retained Earnings				4,645,763		3,920,483
Common Stock Held in Treasury, 6,861,919 Shares at
June 30, 2006 and 7,385,862 Shares at December 31, 2005				(133,722)		(131,344)
		Total Shareholders' Equity		5,148,396		4,316,292
Total Liabilities and Shareholders' Equity			$	8,642,157	$	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)

				Six Months Ended
				June 30,
				2006		2005
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
	Net Income		$	758,124	$	452,159
	Items Not Requiring Cash
		Depreciation, Depletion and Amortization		370,580		312,912
		Impairments		45,453		36,403
		Stock-Based Compensation Expenses		19,618		5,699
		Deferred Income Taxes		153,552		109,278
		Other, Net		(7,485)		(366)
	Dry Hole Costs			25,394		37,119
	Mark-to-Market Commodity Derivative Contracts
		Total (Gains) Losses		(198,046)		940
		Realized Gains		93,913		9,807
	Tax Benefits from Stock Options Exercised			-		18,309
	Other, Net			4,710		(5,323)
	Changes in Components of Working Capital and Other Liabilities
		Accounts Receivable		169,350		(5,081)
		Inventories		(35,066)		(12,185)
		Accounts Payable		(5,225)		16,934
		Accrued Taxes Payable		(11,470)		5,200
		Other Liabilities		(936)		(5,325)
		Other, Net		3,674		(10,917)
	Changes in Components of Working Capital Associated with
		Investing and Financing Activities		(9,708)		19,842
Net Cash Provided by Operating Activities				1,376,432		985,405

Investing Cash Flows
	Additions to Oil and Gas Properties			(1,189,927)		(762,347)
	Proceeds from Sales of Assets			14,553		31,578
	Changes in Components of Working Capital Associated with
		Investing Activities		9,742		(19,950)
	Other, Net			(14,256)		(16,111)
Net Cash Used in Investing Activities				(1,179,888)		(766,830)

Financing Cash Flows
	Net Commercial Paper and Line of Credit Borrowings			-		39,475
	Long-Term Debt Borrowing			10,000		-
	Long-Term Debt Repayments			(102,550)		-
	Dividends Paid			(27,712)		(20,220)
	Excess Tax Benefits from Stock-Based Compensation Expenses			20,841		-
	Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			11,143		24,372
	Other, Net			(214)		108
Net Cash (Used in) Provided by Financing Activities				(88,492)		43,735

Effect of Exchange Rate Changes on Cash				7,245		(589)

Increase in Cash and Cash Equivalents				115,297		261,721
Cash and Cash Equivalents at Beginning of Period				643,811		20,980
Cash and Cash Equivalents at End of Period			$	759,108	$	282,701

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

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

1. Summary of Significant Accounting Policies

General. The consolidated financial statements of EOG Resources, Inc. and subsidiaries (EOG) included herein have been prepared by management without audit pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, they reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in EOG's Annual Report on Form 10-K for the year ended December 31, 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.

On February 1, 2006, the Board of Directors of EOG (Board) increased the quarterly cash dividend on the common stock from the previous $0.04 per share to $0.06 per share effective with the dividend payable on April 28, 2006 to record holders as of April 13, 2006.

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. During July 2006, the Financial Accounting Standards Board (FASB) issued Financial Interpretation (FIN) No. 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109." FIN 48 addresses the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes." FIN 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 48 is effective for fiscal periods beginning after December 15, 2006. EOG is currently assessing the impact, if any, that the adoption of FIN 48 will have on its financial statements.

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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.

2. Stock-Based Compensation

At June 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 and as a result, stock-based compensation expense consisted only 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 six months ended June 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 and amortized over the vesting period on a straight-line basis. Stock-based compensation expense is included in the Consolidated Statements of Income based upon job functions of the employees receiving the grants. For the three and six months ended June 30, 2006 and 2005, EOG compensation expense related to its stock-based compensation plans was as follows (in millions):

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2006		2005		2006		2005

Lease and Well	$	2.0	$	-	$	3.6	$	-
Exploration Costs		2.3		-		4.0		-
General and Administrative		6.3		3.0		12.0		5.7
	$	10.6	$	3.0	$	19.6	$	5.7

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The impact of SFAS No. 123(R) was to reduce income before income taxes and net income during the three months ended June 30, 2006 by $6.9 million and $4.5 million, respectively, and to reduce both basic and diluted net income per share by $0.02. During the six months ended June 30, 2006, the impact of SFAS No. 123(R) was to reduce income before income taxes and net income by $12.5 million and $8.1 million, respectively, and to reduce both basic and diluted net income per share by $0.03. 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 six months ended June 30, 2005 (in millions, except per share data):

			Three Months		Six Months
			Ended		Ended
			June 30,		June 30,
			2005		2005

Net Income Available to Common - As Reported		$	247.6	$	448.4

Deduct: Total Stock-Based Employee Compensation
Expense, Net of Income Tax			(3.0)		(6.2)
Net Income Available to Common - Pro Forma		$	244.6	$	442.2

Net Income Per Share Available to Common
	Basic - As Reported	$	1.04	$	1.89
	Basic - Pro Forma	$	1.03	$	1.86
	Diluted - As Reported	$	1.02	$	1.85
	Diluted - Pro Forma	$	1.00	$	1.82

EOG has various stock plans (Plans) under which employees and non-employee members of the Board have been or may be granted certain equity compensation. At June 30, 2006, approximately 5.2 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 June 30, 2006, EOG held approximately 6.9 million shares of treasury stock.

Stock Options. Under the Plans, participants have been or may be granted rights to purchase shares of common stock of EOG at a price not less than the market price of the stock at the date of grant. Stock options 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 granted under the Plans have not exceeded a maximum term of 10 years. For all grants made prior to 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. Effective May 2005, the fair value of stock option grants not containing the Capped Option feature was estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock options and ESPP grants totaled $6.9 million and $13.5 million during the three and six months ended June 30, 2006, respectively.

-8-

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

		Stock Options				ESPP
		Six Months Ended				Six Months Ended
		June 30,				June 30,
		2006		2005		2006		2005

Weighted Average Fair Value of Grants	$	25.29	$	15.09	$	21.14	$	6.88
Expected Volatility		35.20%		33.36%		39.66%		28.13%
Risk-Free Interest Rate		4.97%		3.96%		4.47%		2.58%
Dividend Yield		0.3%		0.4%		0.3%		0.4%
Expected Life		3.9 yrs		4.8 yrs		0.5 yrs		0.5 yrs

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

The following table sets forth the option transactions for the six months ended June 30, 2006 (options and dollars in thousands, except per share data):

						Weighted
			Weighted			Average
			Average		Aggregate	Remaining
	Number of		Grant		Intrinsic	Contractual
	Options		Price		Value⁽²⁾	Life
						(in years)
Outstanding at January 1, 2006	9,698	$	28.12
Granted	154		73.59
Exercised⁽¹⁾	(480)		16.25
Forfeited	(67)		45.10
Outstanding at June 30, 2006	9,305		29.36	$	372,330	6.2

Options Vested or Expected to Vest	8,816	$	29.31	$	353,201	6.2

Options Exercisable at June 30, 2006	4,231	$	17.27	$	220,054	5.2

(1) The total intrinsic value of options exercised for the six months ended June 30, 2006 and 2005 was $29.8 million and $56.6 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.

At June 30, 2006, unrecognized compensation expense related to non-vested stock options and ESPP grants totaled $51.2 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.0 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 $3.7 million and $3.0 million for the three months ended June 30, 2006 and 2005, respectively, and $6.1 million and $5.7 million for the six months ended June 30, 2006 and 2005, respectively.

-9-

The following table sets forth the restricted stock and units transactions for the six months ended June 30, 2006 (shares and 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⁾	267		67.07
Released⁽²⁾	(649)		20.68
Forfeited	(11)		51.31
Outstanding at June 30, 2006	2,151		32.62	$	148,971

                           (1) The weighted average grant date fair value of restricted stock and units granted for the six months ended June 30, 2006 and 2005 was $67.07 and $45.67, respectively.
                           (2) The total intrinsic value of restricted stock and units released for the six months ended June 30, 2006 and 2005 was $46.9 million and $13.2 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 June 30, 2006, unrecognized compensation expense related to restricted stock and units totaled $47.8 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.8 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 six-month periods ended June 30 (in thousands, except per share data):

				Three Months Ended				Six Months Ended
				June 30,				June 30,
				2006		2005		2006		2005

Numerator for Basic and Diluted Earnings Per Share -
	Net Income Available to Common		$	329,559	$	247,598	$	754,408	$	448,443

Denominator for Basic Earnings Per Share -
	Weighted Average Shares			241,613		238,252		241,370		237,752
	Potential Dilutive Common Shares -
		Stock Options		3,356		4,038		3,453		3,914
		Restricted Stock and Units		918		1,124		1,004		1,105
Denominator for Diluted Earnings Per Share -
	Adjusted Weighted Average Shares			245,887		243,414		245,827		242,771

Net Income Per Share Available to Common
	Basic		$	1.36	$	1.04	$	3.13	$	1.89
	Diluted		$	1.34	$	1.02	$	3.07	$	1.85

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4. Supplemental Cash Flow Information

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

		Six Months Ended
		June 30,
		2006		2005

Interest	$	22,074	$	27,770
Income Taxes	$	132,580	$	122,964

5. Comprehensive Income

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

					Three Months Ended				Six Months Ended
					June 30,				June 30,
					2006		2005		2006		2005

Comprehensive Income
	Net Income			$	331,417	$	249,456	$	758,124	$	452,159
	Other Comprehensive Income (Loss)
		Foreign Currency Translation Adjustments			66,633		(15,289)		64,876		(20,215)
		Foreign Currency Swap Transaction			1,610		(1,139)		2,156		(4,730)
		Income Tax (Provision) Benefit Related
		to Foreign Currency Swap Transaction			(1,159)		372		(1,342)		1,615
			Total	$	398,501	$	233,400	$	823,814	$	428,829

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6. Segment Information

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

				Three Months Ended				Six Months Ended
				June 30,				June 30,
				2006		2005		2006		2005

Net Operating Revenues
	United States		$	676,637	$	551,131	$	1,455,039	$	1,034,821
	Canada			145,288		138,212		322,267		272,199
	Trinidad⁽¹⁾			81,840		76,836		174,429		125,827
	United Kingdom			15,323		17,745		51,889		39,233
		Total	$	919,088	$	783,924	$	2,003,624	$	1,472,080

Operating Income (Loss)
	United States		$	325,203	$	256,349	$	758,959	$	465,150
	Canada			69,707		78,352		166,481		143,658
	Trinidad			53,119		63,156		123,568		93,412
	United Kingdom			6,837		(3,168)		34,286		12,564
	Other			(32)		-		(32)		-
		Total		454,834		394,689		1,083,262		714,784

Reconciling Items
	Other Income, Net			21,844		6,874		36,400		12,339
	Interest Expense, Net			12,384		14,687		25,537		28,644
		Income Before Income Taxes	$	464,294	$	386,876	$	1,094,125	$	698,479

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

7. Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of oil and gas properties pursuant to SFAS No. 143, "Accounting for Asset Retirement Obligations," for the six months ended June 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		-		4,633		4,633
	Liabilities Settled		(2,264)		(673)		(2,937)
	Accretions		171		4,452		4,623
	Revisions		14		(66)		(52)
	Reclassifications		1,241		(1,241)		-
	Foreign Currency Translations		27		1,877		1,904
Balance at June 30, 2006		$	5,424	$	164,235	$	169,659

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8. Suspended Well Costs

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

			Six Months
			Ended
			June 30,
			2006

Balance at December 31, 2005		$	27,868
	Additions Pending the Determination of Proved Reserves		37,302
	Reclassifications to Proved Properties		(5,604)
	Charged to Dry Hole Costs		(404)
	Foreign Currency Translation		673
Balance at June 30, 2006		$	59,835

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

			As of
			June 30,
			2006

Capitalized exploratory well costs that have been
	capitalized for a period less than one year	$	34,302
Capitalized exploratory well costs that have been
	capitalized for a period greater than one year		25,533
	Total	$	59,835
Number of projects that have exploratory well costs that have been
	capitalized for a period greater than one year		2

As of June 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 ($21.2 million). In the Gulf of Mexico project, EOG plans to participate in the drilling of an additional well. In the NWT project, EOG is evaluating the data gathered from additional wells drilled during the first quarter of 2006 and gathering seismic data.

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.

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10. Pension and Postretirement Benefits

Pension Plans. EOG has a non-contributory defined contribution pension plan and a matched defined contribution savings plan in place for most of its employees in the United States. For the six-month periods ended June 30, 2006 and 2005, EOG's total contributions to these pension plans were $6.9 million and $5.6 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 six-month periods ended June 30, 2006 and 2005, total contributions to these defined contribution pension plans were $0.7 million and $0.6 million, respectively. For the six-month period ended June 30, 2006, total contributions to these defined benefit pension plans amounted to approximately $180,000. The net periodic pension costs recognized for these pension plans were approximately $118,000 and $35,000, respectively, for the six-month periods ended June 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 six-month period ended June 30, 2006, EOG's total contributions to these plans amounted to approximately $48,000. The net periodic pension costs recognized for the postretirement medical and dental plans were approximately $334,000 and $184,000, respectively, for the six-month periods ended June 30, 2006 and 2005.

11. Long-Term Debt

In the first six months of 2006, EOGI International Company, a wholly owned foreign subsidiary of EOG, repaid $100 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 $150 million outstanding at June 30, 2006 was 5.53%. The weighted average interest rate for the amounts outstanding for the six months ended June 30, 2006 was 5.18%.

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 $10 million outstanding under the Credit Agreement at June 30, 2006. The applicable interest rate at June 30, 2006 was 5.79%. The weighted average interest rate for the amount outstanding for the period ended June 30, 2006 was 6.40%.

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 5.56%, respectively, at June 30, 2006.

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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 gas and remained in the start-up phase through the second 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) and in April 2006, applied to enter the market development phase under the production sharing contract with the Government of Trinidad and Tobago.

A subsidiary of EOG, EOG Resources Trinidad Limited (EOGRT), and the other participants in the South East Coast Consortium (SECC) Block signed a farm-in 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 and is expected to reach total depth during the third quarter of 2006. BP will pay the entire cost for drilling the exploratory well. EOGRT will retain a 50.6% working interest in the prospect and will develop the prospect, if successful.

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.

-15-

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 June 30, 2006, EOG's debt-to-total capitalization ratio was 15%, down slightly from 16% at March 31, 2006. During the first six 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.

For 2006, EOG's estimated exploration and development expenditure budget is $2.60 billion to $2.75 billion, excluding acquisitions. United States and Canada natural gas drilling activity continues to be a key component of this effort. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

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," and as a result, stock-based compensation expense consisted only 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. 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 six months ended June 30, 2006 and 2005, EOG compensation expense related to its stock-based compensation plans was as follows (in millions):

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2006		2005		2006		2005

Lease and Well	$	2.0	$	-	$	3.6	$	-
Exploration Costs		2.3		-		4.0		-
General and Administrative		6.3		3.0		12.0		5.7
	$	10.6	$	3.0	$	19.6	$	5.7

Results of Operations

The following review of operations for the three-month and six-month periods ended June 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 June 30, 2006 vs. Three Months Ended June 30, 2005

Net Operating Revenues. During the second quarter of 2006, net operating revenues increased $135 million, or 17%, to $919 million from $784 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, increased $45 million, or 6%, to $828 million from $783 million for the same period in 2005.

-16-

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

					Three Months Ended
					June 30,
					2006		2005
Natural Gas Volumes (MMcfd)⁽¹⁾
	United States				776		706
	Canada				225		228
			United States and Canada		1,001		934
	Trinidad				265		214
	United Kingdom				25		34
		Total			1,291		1,182

Average Natural Gas Prices ($/Mcf)⁽²⁾
	United States			$	6.33	$	6.64
	Canada				6.28		6.02
			United States and Canada		6.32		6.49
	Trinidad⁽³⁾				2.18		2.92
	United Kingdom				6.34		5.54
		Composite			5.47		5.82

Crude Oil and Condensate Volumes (MBbld)⁽¹⁾
	United States				19.5		21.7
	Canada				2.4		2.5
			United States and Canada		21.9		24.2
	Trinidad				4.8		4.2
	United Kingdom				0.1		0.1
		Total			26.8		28.5

Average Crude Oil and Condensate Prices ($/Bbl)⁽²⁾
	United States			$	67.69	$	51.03
	Canada				62.62		46.58
			United States and Canada		67.06		50.58
	Trinidad				67.47		53.05
	United Kingdom				65.80		49.10
		Composite			67.13		50.93

Natural Gas Liquids Volumes (MBbld)⁽¹⁾
	United States				9.0		7.9
	Canada				0.6		1.2
		Total			9.6		9.1

Average Natural Gas Liquids Prices ($/Bbl)⁽²⁾
	United States			$	41.02	$	30.51
	Canada				46.55		30.52
		Composite			41.38		30.51

Natural Gas Equivalent Volumes (MMcfed)⁽⁴⁾
	United States				947		885
	Canada				244		249
			United States and Canada		1,191		1,134
	Trinidad				293		238
	United Kingdom				26		35
		Total			1,510		1,407

Total Bcfe⁽⁴⁾					137.4		128.1

(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 $0.99 per Mcf as a result of a revenue adjustment in the second quarter of 2005 related to an amended Trinidad take-or-pay contract.
(4) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids.

-17-

Wellhead natural gas revenues for the second quarter of 2006 increased $17 million, or 3%, to $643 million from $626 million for the same period in 2005. The increase was due to increased natural gas deliveries ($58 million), partially offset by a lower composite average wellhead natural gas price ($41 million). The composite average wellhead price for natural gas decreased 6% to $5.47 per Mcf for the second quarter of 2006 from $5.82 per Mcf for the same period in 2005.

Natural gas deliveries increased 109 MMcfd, or 9%, to 1,291 MMcfd for the second quarter of 2006 from 1,182 MMcfd for the same period in 2005. The increase was primarily due to higher production in the United States (70 MMcfd) and Trinidad (51 MMcfd), partially offset by decreased production in the United Kingdom (9 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (64 MMcfd) and the Rocky Mountain area (18 MMcfd), partially offset by decreased production in offshore Gulf of Mexico (21 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 (67 MMcfd) and increased contractual demand (34 MMcfd), partially offset by a decrease in volume 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 second quarter of 2006 increased $17 million, or 13%, to $149 million from $132 million for the same period in 2005. The increase was due to a higher composite average wellhead crude oil and condensate price ($36 million), partially offset by decreased wellhead crude oil and condensate sales ($19 million). The composite average wellhead crude oil and condensate price for the second quarter of 2006 was $67.13 per barrel compared to $50.93 per barrel for the same period in 2005.

Natural gas liquids revenues for the second quarter of 2006 increased $11 million, or 44%, to $36 million from $25 million for the same period in 2005. The increase was due to increases in the composite average price ($9 million) and deliveries ($2 million).

During the second quarter of 2006, EOG recognized a gain on mark-to-market financial commodity derivative contracts of $91 million, and the net cash inflow related to settled natural gas financial collar and price swap contracts was $64 million. During the second quarter of 2005, EOG was not a party to any financial commodity derivative contracts.

Operating and Other Expenses. For the second quarter of 2006, operating expenses of $464 million were $75 million higher than the $389 million incurred in the second quarter of 2005. The following table presents the costs per Mcfe for the three-month periods ended June 30:

			Three Months Ended
			June 30,
			2006		2005

Lease and Well		$	0.64	$	0.52
Transportation Costs			0.19		0.16
Depreciation, Depletion and Amortization (DD&A)			1.42		1.25
General and Administrative (G&A)			0.28		0.24
Taxes Other Than Income			0.34		0.29
Interest Expense, Net			0.09		0.11
	Total Per-Unit Costs⁽¹⁾	$	2.96	$	2.57

(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 three-month period ended June 30, 2006 compared to the same period in 2005 were due primarily to the reasons set forth below.

-18-

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 $87 million for the second quarter of 2006 increased $20 million from $67 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($9 million) and Canada ($4 million); higher lease and well administrative expenses, including stock-based compensation expense, in the United States ($4 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 $26 million for the second quarter of 2006 increased $6 million from $20 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 $193 million for the second quarter of 2006 increased $33 million from the same prior year period primarily due to increased DD&A rates in the United States ($17 million), Canada ($3 million) and the United Kingdom ($3 million); increased production in the United States ($6 million); and changes in the Canadian exchange rate ($4 million).

G&A expenses of $39 million for the second quarter of 2006 were $8 million higher than the same prior year period primarily due to higher employee-related costs ($6 million) and higher insurance costs ($1 million). The increase in employee-related costs primarily reflects higher stock-based compensation expense ($3 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 $47 million for the second quarter of 2006 were $9 million higher than the same prior year period. Severance/production taxes increased due primarily to increased wellhead revenues in Trinidad ($4 million) and the United States ($3 million), partially offset by an increase in credits taken for a Texas high cost gas severance tax exemption ($3 million). Ad valorem/property taxes increased primarily due to higher property valuations in the United States ($3 million).

Interest expense, net was $12 million for the second quarter of 2006, down $2 million compared to the same prior year period primarily due to a slightly lower average debt balance ($1 million) and higher capitalized interest ($1 million).

Exploration costs of $35 million for the second quarter of 2006 increased $7 million from $28 million for the same prior year period primarily due to higher employee-related costs, including stock-based compensation expenses.

-19-

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. EOG recorded impairments of $10 million and $12 million for the second quarters of 2006 and 2005, respectively, under SFAS No. 144 for properties in the United States.

Other income, net was $22 million for the second quarter of 2006 compared to $7 million for the same prior year period. The increase of $15 million was primarily due to higher interest income ($7 million), higher gains on sales of properties ($3 million) and decreased net foreign currency transaction losses ($2 million).

Income tax provision of $133 million for the second quarter of 2006 decreased $5 million compared to the same prior year period due primarily to a Canadian federal tax rate reduction ($19 million) and an Alberta, Canada provincial tax rate reduction ($13 million), partially offset by a higher tax provision resulting from increased pretax income ($27 million). The net effective tax rate for the second quarter of 2006 decreased to 29% from 36% for the same prior year period.

Six Months Ended June 30, 2006 vs. Six Months Ended June 30, 2005

Net Operating Revenues. During the first six months of 2006, net operating revenues increased $532 million, or 36%, to $2,004 million from $1,472 million for the same period in 2005. Total wellhead revenues increased $331 million, or 23%, to $1,802 million from $1,471 million for the same period in 2005.

-20-

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

					Six Months Ended
					June 30,
					2006		2005
Natural Gas Volumes (MMcfd)
	United States				767		698
	Canada				227		231
			United States and Canada		994		929
	Trinidad				274		209
	United Kingdom				30		34
		Total			1,298		1,172

Average Natural Gas Prices ($/Mcf)
	United States			$	7.04	$	6.31
	Canada				7.08		5.85
			United States and Canada		7.04		6.20
	Trinidad⁽¹⁾				2.31		2.35
	United Kingdom				9.32		6.10
		Composite			6.10		5.51

Crude Oil and Condensate Volumes (MBbld)
	United States				20.2		22.1
	Canada				2.5		2.5
			United States and Canada		22.7		24.6
	Trinidad				5.2		4.1
	United Kingdom				0.1		0.2
		Total			28.0		28.9

Average Crude Oil and Condensate Prices ($/Bbl)
	United States			$	63.70	$	49.90
	Canada				57.12		45.68
			United States and Canada		62.92		49.47
	Trinidad				64.45		49.22
	United Kingdom				61.04		43.93
		Composite			63.21		49.41

Natural Gas Liquids Volumes (MBbld)
	United States				8.1		6.7
	Canada				0.7		1.3
		Total			8.8		8.0

Average Natural Gas Liquids Prices ($/Bbl)
	United States			$	39.32	$	30.01
	Canada				44.56		28.80
		Composite			39.72		29.81

Natural Gas Equivalent Volumes (MMcfed)
	United States				937		870
	Canada				246		254
			United States and Canada		1,183		1,124
	Trinidad				305		235
	United Kingdom				30		35
		Total			1,518		1,394

Total Bcfe					274.8		252.3

(1) Includes $0.51 per Mcf as a result of a revenue adjustment in the second quarter of 2005 related to an amended Trinidad take-or-pay contract.

-21-

Wellhead natural gas revenues for the first six months of 2006 increased $263 million, or 23%, to $1,432 million from $1,169 million for the same period in 2005. The increase was due to a higher composite average wellhead natural gas price ($139 million) and increased natural gas deliveries ($124 million). The composite average wellhead price for natural gas increased 11% to $6.10 per Mcf for the first six months of 2006 from $5.51 per Mcf for the same period in 2005.

Natural gas deliveries increased 126 MMcfd, or 11%, to 1,298 MMcfd for the first six months of 2006 from 1,172 MMcfd for the same period in 2005. The increase was due to higher production in the United States (69 MMcfd) and Trinidad (65 MMcfd), partially offset by decreased production in the United Kingdom (4 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (65 MMcfd) and the Rocky Mountain area (19 MMcfd), partially offset by decreased production in offshore Gulf of Mexico (21 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 (80 MMcfd) and increased contractual demand (36 MMcfd), partially offset by a decrease in volume 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 six months of 2006 increased $48 million, or 19%, to $306 million from $258 million for the same period in 2005. The increase was due to a higher composite average wellhead crude oil and condensate price ($67 million), partially offset by decreased wellhead crude oil and condensate sales ($19 million). The composite average wellhead crude oil and condensate price for the first six months of 2006 was $63.21 per barrel compared to $49.41 per barrel for the same period in 2005.

Natural gas liquids revenues for the first six months of 2006 increased $20 million, or 47%, to $63 million from $43 million for the same period in 2005. The increase was due to increases in the composite average price ($16 million) and deliveries ($4 million).

During the first six months of 2006, EOG recognized a gain on mark-to-market financial commodity derivative contracts of $198 million and the net cash inflow related to settled natural gas financial collar and price swap contracts was $94 million. During the first six months of 2005, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $1 million and the net cash inflow related to settled natural gas financial collar contracts was $10 million.

Operating and Other Expenses. For the first six months of 2006, operating expenses of $920 million were $163 million higher than the $757 million incurred in the same period in 2005. The following table presents the costs per Mcfe for the six-month periods ended June 30:

			Six Months Ended
			June 30,
			2006		2005

Lease and Well		$	0.64	$	0.52
Transportation Costs			0.20		0.15
DD&A			1.36		1.24
G&A			0.27		0.23
Taxes Other Than Income			0.37		0.32
Interest Expense, Net			0.09		0.11
	Total Per-Unit Costs⁽¹⁾	$	2.93	$	2.57

(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 six months ended June 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 $175 million for the first six months of 2006 were $42 million higher than the same prior year primarily due to higher operating and maintenance expenses in the United States ($17 million), Canada ($11 million) and Trinidad ($2 million); higher lease and well administrative expenses, including stock-based compensation expenses, in the United States ($5 million) and Canada ($2 million); and changes in the Canadian exchange rate ($4 million).

Transportation costs of $54 million for the first six months of 2006 increased $17 million from $37 million for the same prior year period primarily due to increased production in the Fort Worth Basin Barnett Shale Play.

DD&A expenses of $371 million for the first six months of 2006 increased $58 million from the same prior year period primarily due to increased DD&A rates in the United States ($24 million), Canada ($6 million) and the United Kingdom ($5 million); increased production in the United States ($16 million); and changes in the Canadian exchange rate ($6 million).

G&A expenses of $75 million for the first six months of 2006 were $16 million higher than the same prior year period primarily due to higher employee-related expenses ($11 million) and higher insurance costs ($2 million). The increase in employee-related costs primarily reflects higher stock-based compensation expense ($6 million).

Taxes other than income of $101 million for the first six months of 2006 were $21 million higher than the same prior year period. Severance/production taxes increased due primarily to increased wellhead revenues in the United States ($11 million) and Trinidad ($7 million), partially offset by an increase in credits taken for a Texas high cost gas severance tax exemption ($7 million). Ad valorem/property taxes increased primarily due to higher property valuations in the United States ($7 million).

Interest expense, net was $26 million for the first six months of 2006, down $3 million compared to the same prior year period primarily due to higher capitalized interest ($2 million) and a slightly lower average debt balance ($1 million).

Exploration costs of $75 million for the first six months of 2006 increased $12 million from $63 million for the same prior year period primarily due to higher employee-related costs, including stock-based compensation expenses.

Impairments of $45 million for the first six months of 2006 were $9 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 ($7 million) and increased amortization of unproved leases in Canada ($2 million). EOG recorded impairments of $20 million and $13 million for the six-month periods ended June 30, 2006 and 2005, respectively, under SFAS No. 144 for properties in the United States.

Other income, net was $36 million for the first six months of 2006 compared to $12 million for the same prior year period. The increase of $24 million was primarily due to higher interest income ($13 million), higher gains on sales of properties ($4 million), decreased net foreign currency transaction losses ($3 million), and increased equity income from investments in Nitrogen (2000) Unlimited and Caribbean Nitrogen Company Limited ($3 million).

Income tax provision of $336 million for the first six months of 2006 increased $90 million compared to the same prior year period due primarily to a higher tax provision resulting from increased pretax income ($138 million), partially offset by a decrease in foreign income taxes ($48 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 six months of 2006 decreased to 31% 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 six months ended June 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 six months of 2006, EOG's cash balance increased $115 million to $759 million from $644 million at December 31, 2005.

Net cash provided by operating activities of $1,376 million for the first six months of 2006 increased $391 million compared to the same period in 2005 primarily reflecting an increase in wellhead revenues ($331 million), favorable changes in working capital and other liabilities ($102 million) and a change in the net cash flows from settlement of financial commodity derivative contracts ($84 million), partially offset by an increase in cash operating expenses ($108 million).

Net cash used in investing activities of $1,180 million for the first six months of 2006 increased by $413 million compared to the same period in 2005 due primarily to increased additions to oil and gas properties ($428 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 ($30 million).

Net cash used in financing activities was $88 million for the first six months of 2006 compared to net cash provided by financing activities of $44 million for the same period in 2005. Financing activities in 2006 included repayment of long-term debt ($103 million), cash dividend payments ($28 million), excess tax benefits from stock-based compensation expenses ($21 million), proceeds from sales of treasury stock attributable to employee stock option exercises and employee stock purchase plan ($11 million) and long-term debt borrowings ($10 million).

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

				Six Months Ended
				June 30,
				2006		2005

United States			$	1,027	$	661
Canada				153		114
		United States and Canada		1,180		775
Trinidad				70		23
United Kingdom				15		27
	Exploration and Development Expenditures			1,265		825
Asset Retirement Costs				4		3
	Total Exploration and Development Expenditures		$	1,269	$	828

Total exploration and development expenditures of $1,269 million for the first six months of 2006 were $441 million higher than the same period in 2005. The 2006 exploration and development expenditures of $1,265 included $920 million in development, $330 million in exploration, $9 million in capitalized interest and $6 million in property acquisitions. The 2005 exploration and development expenditures of $825 included $544 million in development, $262 million in exploration, $12 million in property acquisitions and $7 million in capitalized interest.

Higher development expenditures for the first six months of 2006 of $376 million were due primarily to increased development drilling expenditures in the United States ($300 million) and Canada ($23 million), increased expenditures related to infrastructure facilities in the United States ($32 million) and increased recompletions in the United States ($20 million).

Higher exploration expenditures for the first six months of 2006 of $68 million were primarily due to increased exploratory drilling expenditures, including dry hole costs, in Trinidad ($39 million) and the United States ($12 million); increased expenditures for leasehold acquisitions in the United States ($8 million) and Canada ($4 million); and higher exploration administrative expenses, including stock-based compensation expense, in the United States ($5 million).

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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 collar and price swap contracts at July 26, 2006 with prices expressed in dollars per million British thermal units ($/MMBtu) and notional volumes in million British thermal units per day (MMBtud). The total fair value of the natural gas financial collar and price swap contracts at June 30, 2006 was a positive $116 million.

Natural Gas Financial Contracts
	Collar Contracts					Price Swap Contracts
		Floor Price		Ceiling Price
			Weighted		Weighted		Weighted
			Average	Ceiling	Average		Average
	Volume	Floor Range	Price	Range	Price	Volume	Price
	(MMBtud)	($/MMBtu)	($/MMBtu)	($/MMBtu)	($/MMBtu)	(MMBtud)	($/MMBtu)
2006
July (closed)	50,000	$9.75 - 10.00	$9.87	$12.35 - 12.85	$12.50	315,000	$8.77
August	50,000	9.75 - 10.00	9.87	12.50 - 13.00	12.67	340,000	8.67
September	-	-	-	-	-	315,000	8.40
October	-	-	-	-	-	280,000	8.25
November	-	-	-	-	-	75,000	9.03
December	-	-	-	-	-	75,000	10.31

2007
January	-	-	-	-	-	50,000	$11.42
February	-	-	-	-	-	50,000	11.45
March	-	-	-	-	-	50,000	11.23
April	-	-	-	-	-	50,000	9.27
May	-	-	-	-	-	50,000	9.07
June	-	-	-	-	-	50,000	9.17
July	-	-	-	-	-	50,000	9.28
August	-	-	-	-	-	50,000	9.36
September	-	-	-	-	-	50,000	9.44
October	-	-	-	-	-	50,000	9.58
November	-	-	-	-	-	50,000	10.28
December	-	-	-	-	-	50,000	10.94

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Subsequent to June 30, 2006, EOG entered into crude oil financial price swap contracts. Presented below is a comprehensive summary of EOG's 2007 crude oil price swap contracts at July 26, 2006 with prices expressed in dollars per barrels ($/Bbl) and notional volumes in barrels per day (Bbld).

Crude Oil Financial Price Swap Contracts
		Weighted
	Volume	Average Price
	(Bbld)	($/Bbl)
2007
January	3,000	$77.79
February	3,000	77.88
March	3,000	77.89
April	3,000	77.84
May	3,000	77.75
June	3,000	77.63
July	3,000	77.51
August	3,000	77.39
September	3,000	77.26
October	3,000	77.14
November	3,000	76.98
December	3,000	76.80

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 the 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⁾

April 1, 2006 - April 30, 2006	26,813	$	73.61	-	6,386,200
May 1, 2006 - May 31, 2006	120,078		74.52	-	6,386,200
June 1, 2006 - June 30, 2006	-		-	-	6,386,200
Total	146,891		74.35	-

(1) Comprises 146,891 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The Annual Meeting of Shareholders of EOG Resources, Inc. was held on May 2, 2006, in Houston, Texas, for the purpose of electing a board of directors and ratifying the appointment of auditors. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934, and there was no solicitation in opposition to management's solicitations.

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

	Shares	Shares
Nominee	For	Withheld

George A. Alcorn	218,787,977	2,841,155
Charles R. Crisp	218,856,770	2,772,362
Mark G. Papa	212,731,563	8,897,569
Edmund P. Segner, III	213,392,199	8,236,933
William D. Stevens	192,056,628	29,572,504
H. Leighton Steward	218,828,103	2,801,030
Donald F. Textor	213,243,861	8,385,271
Frank G. Wisner	218,830,987	2,798,145

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(b) The ratification of the appointment of Deloitte & Touche LLP, independent registered public accountants, as EOG's independent auditors for the year ending December 31, 2006 was ratified by the following vote: 220,098,921 shares for; 343,868 shares against; and 1,186,343 shares abstaining.

ITEM 6. EXHIBITS

*10.1 -	First Amendment, dated June 21, 2006, to Revolving Credit Agreement, dated June 28, 2005, among EOG Resources, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.

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

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

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

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

*Exhibits filed herewith

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		EOG RESOURCES, INC.
		(Registrant)


Date: August 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

*10.1 -	First Amendment, dated June 21, 2006, to Revolving Credit Agreement, dated June 28, 2005, among EOG Resources, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.

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

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

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

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

*Exhibits filed herewith

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