Edgar Filing: EOG RESOURCES INC

eog2qtr10-q.htm

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, 2010

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

Commission File Number: 1-9743

EOG RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware		47-0684736
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002

(Address of principal executive offices) (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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

Title of each class	Number of shares
Common Stock, par value $0.01 per share	253,468,390 (as of August 2, 2010)

EOG RESOURCES, INC.

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements (Unaudited)

		Consolidated Statements of Income - Three Months Ended June 30, 2010 and 2009 and Six Months Ended June 30, 2010 and 2009	3

		Consolidated Balance Sheets - June 30, 2010 and December 31, 2009	4

		Consolidated Statements of Cash Flows - Six Months Ended June 30, 2010 and 2009	5

		Notes to Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	39

	ITEM 4.	Controls and Procedures	39

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	40

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40

	ITEM 6.	Exhibits	41

SIGNATURES			42

EXHIBIT INDEX			43

-2-

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands, Except Per Share Data)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010		2009


Net Operating Revenues
Natural Gas	$	553,354		$	460,044		$	1,230,336	$	1,027,622
Crude Oil, Condensate and Natural Gas Liquids		560,049			287,134			1,069,238		487,462
Gains on Mark-to-Market Commodity Derivative Contracts		37,015			33,570			44,818		384,953
Gathering, Processing and Marketing		195,876			77,284			367,819		115,126
Other, Net		11,674			3,007			16,450		4,085
Total		1,357,968			861,039			2,728,661		2,019,248

Operating Expenses
Lease and Well		160,734			134,599			326,726		280,105
Transportation Costs		94,345			66,011			183,056		134,873
Gathering and Processing Costs		13,220			13,521			28,881		31,234
Exploration Costs		50,131			34,307			101,328		83,930
Dry Hole Costs		19,318			33,643			42,395		36,637
Impairments		80,362			47,046			149,957		112,517
Marketing Costs		191,213			74,050			359,977		106,003
Depreciation, Depletion and Amortization		465,343			375,592			897,249		764,921
General and Administrative		64,737			58,760			125,160		116,706
Taxes Other Than Income		78,064			23,492			153,529		70,892
Total		1,217,467			861,021			2,368,258		1,737,818

Operating Income		140,501			18			360,403		281,430
Other Income (Expense), Net		(545	)		1,237			2,138		2,976
Income Before Interest Expense and Income Taxes		139,956			1,255			362,541		284,406
Interest Expense, Net		29,897			24,811			55,325		43,187
Income (Loss) Before Income Taxes		110,059			(23,556	)		307,216		241,219
Income Tax Provision (Benefit)		50,187			(6,850	)		129,329		99,215
Net Income (Loss)	$	59,872		$	(16,706	)	$	177,887	$	142,004

Net Income (Loss) Per Share
Basic	$	0.24		$	(0.07	)	$	0.71	$	0.57
Diluted	$	0.24		$	(0.07	)	$	0.70	$	0.57

Dividends Declared per Common Share	$	0.155		$	0.145		$	0.310	$	0.290

Average Number of Common Shares
Basic		250,825			248,207			250,596		248,095
Diluted		254,503			248,207			254,206		250,499

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,
	2010			2009
ASSETS
Current Assets
Cash and Cash Equivalents	$	650,114		$	685,751
Accounts Receivable, Net		810,145			771,417
Inventories		306,563			261,723
Assets from Price Risk Management Activities		18,671			20,915
Income Taxes Receivable		30,684			37,009
Deferred Income Taxes		1,169			-
Other		98,797			62,726
Total		1,916,143			1,839,541

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		26,647,238			24,614,311
Other Property, Plant and Equipment		1,490,111			1,350,132
Total Property, Plant and Equipment		28,137,349			25,964,443
Less: Accumulated Depreciation, Depletion and Amortization		(10,713,031	)		(9,825,218	)
Total Property, Plant and Equipment, Net		17,424,318			16,139,225
Other Assets		125,222			139,901
Total Assets	$	19,465,683		$	18,118,667


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	1,255,657		$	979,139
Accrued Taxes Payable		90,051			92,858
Dividends Payable		38,853			36,286
Liabilities from Price Risk Management Activities		42,207			27,218
Deferred Income Taxes		9,889			35,414
Current Portion of Long-Term Debt		-			37,000
Other		121,480			137,645
Total		1,558,137			1,345,560

Long-Term Debt		3,734,067			2,760,000
Other Liabilities		618,743			632,652
Deferred Income Taxes		3,423,717			3,382,413
Commitments and Contingencies (Note 9)

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 253,517,235 Shares Issued at June 30, 2010 and 252,627,177 Shares Issued at December 31, 2009		202,535			202,526
Additional Paid in Capital		656,529			596,702
Accumulated Other Comprehensive Income		314,631			339,720
Retained Earnings		8,966,181			8,866,747
Common Stock Held in Treasury, 122,265 Shares at June 30, 2010 and 118,525 Shares at December 31, 2009		(8,857	)		(7,653	)
Total Stockholders' Equity		10,131,019			9,998,042
Total Liabilities and Stockholders' Equity	$	19,465,683		$	18,118,667

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,
	2010			2009
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	177,887		$	142,004
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		897,249			764,921
Impairments		149,957			112,517
Stock-Based Compensation Expenses		44,953			48,479
Deferred Income Taxes		24,493			62,161
Other, Net		(8,884	)		1,689
Dry Hole Costs		42,395			36,637
Mark-to-Market Commodity Derivative Contracts
Total Gains		(44,818	)		(384,953	)
Realized Gains		38,827			655,740
Excess Tax Benefits from Stock-Based Compensation		-			(21,874	)
Other, Net		8,454			6,865
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(39,275	)		149,021
Inventories		(67,363	)		(22,151	)
Accounts Payable		254,878			(414,823	)
Accrued Taxes Payable		(6,011	)		4,131
Other Assets		(24,499	)		(7,487	)
Other Liabilities		(10,930	)		(24,842	)
Changes in Components of Working Capital Associated with Investing and Financing Activities		(135,973	)		169,183
Net Cash Provided by Operating Activities		1,301,340			1,277,218

Investing Cash Flows
Additions to Oil and Gas Properties		(2,288,270	)		(1,433,591	)
Additions to Other Property, Plant and Equipment		(115,661	)		(151,845	)
Proceeds from Sales of Assets		41,939			828
Changes in Components of Working Capital Associated with Investing Activities		135,693			(169,101	)
Other, Net		(4,157	)		1,384
Net Cash Used in Investing Activities		(2,230,456	)		(1,752,325	)

Financing Cash Flows
Long-Term Debt Borrowings		991,395			900,000
Long-Term Debt Repayments		(37,000	)		-
Dividends Paid		(75,179	)		(69,516	)
Excess Tax Benefits from Stock-Based Compensation		-			21,874
Treasury Stock Purchased		(7,307	)		(6,125	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		21,023			8,026
Debt Issuance Costs		(1,194	)		(8,741	)
Other, Net		280			(82	)
Net Cash Provided by Financing Activities		892,018			845,436

Effect of Exchange Rate Changes on Cash		1,461			5,324

(Decrease) Increase in Cash and Cash Equivalents		(35,637	)		375,653
Cash and Cash Equivalents at Beginning of Period		685,751			331,311
Cash and Cash Equivalents at End of Period	$	650,114		$	706,964

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., together with its subsidiaries (collectively, EOG), included herein have been prepared by management without audit pursuant to the rules and regulations of the United States 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 presented. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures included either on the face of the financial statements or in these notes are sufficient to make the interim information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in EOG's Annual Report on Form 10-K for the year ended December 31, 2009, filed on February 25, 2010 (EOG's 2009 Annual Report).

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three and six months ended June 30, 2010 are not necessarily indicative of the results to be expected for the full year.

EOG has determined that there are no subsequent events which require recognition or disclosure in these consolidated financial statements except as disclosed herein.

Recently Issued Accounting Standards and Developments. In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-06, "Improving Disclosures About Fair Value Measurements" (ASU 2010-06), which amends the Fair Value Measurements and Disclosures Topic of the Accounting Standards Codification (ASC) (ASC Topic 820). Among other provisions, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. This amendment requires new disclosures on the value of, and the reason for, transfers in and out of Levels 1 and 2 of the fair value hierarchy and additional disclosures about purchases, sales, issuances and settlements within Level 3 fair value measurements. ASU 2010-06 also clarifies existing disclosure requirements on levels of disaggregation and about inputs and valuation techniques. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 19, 2009, except for the requirement to provide additional disclosures regarding Level 3 measurements which will be effective for interim and annual reporting periods beginning after December 15, 2010. See Note 12.

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2. Stock-Based Compensation

As more fully discussed in Note 6 to the Consolidated Financial Statements included in EOG's 2009 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included in the Consolidated Statements of Income based upon job functions of the employees receiving the grants as follows (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009

Lease and Well	$	6.0	$	5.4	$	12.3	$	11.4
Gathering and Processing Costs		0.3		-		0.3		-
Exploration Costs		5.3		4.9		10.8		10.1
General and Administrative		10.9		11.8		21.6		27.0
Total	$	22.5	$	22.1	$	45.0	$	48.5

The EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, as amended (2008 Plan), provides for grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units and other stock-based awards, up to an aggregate maximum of 12.9 million shares of common stock, plus shares underlying forfeited or cancelled grants under the prior stock plans. At the 2010 Annual Meeting of Stockholders in April 2010 (2010 Annual Meeting), an amendment to the 2008 Plan was approved, pursuant to which the number of shares of common stock available for future grant under the 2008 Plan was increased by an additional 6.9 million shares, to 12.9 million shares. In addition, pursuant to the amendment, the maximum aggregate number of shares of common stock that may be granted under the 2008 Plan (i) as restricted stock, restricted stock units, performance stock, performance units or other stock-based awards ("full value" awards) has been increased by an additional 2.4 million shares, (ii) as incentive stock options has been increased by an additional 1.0 million shares and (iii) as non-qualified stock options or SARs has been increased by an additional 6.9 million shares. The amendment also (i) effected certain changes to the provisions of the 2008 Plan regarding accelerated vesting of awards upon a change in control of EOG and (ii) permits a "qualified institutional investor" (as defined in the amendment) to generally acquire beneficial ownership of up to 15 percent of EOG's common stock then-outstanding without the acquisition being considered a change in control of EOG under the terms of the 2008 Plan. At June 30, 2010, approximately 8.8 million common shares remained available for grant under the 2008 Plan. Effective with the adoption of the 2008 Plan, EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares.

Stock Options and Stock Appreciation Rights and Employee Stock Purchase Plan. The fair value of all Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model. Certain of EOG's stock options granted in 2005 contain a feature that limits the potential gain that can be realized by requiring vested options to be exercised if the market price of EOG's common stock reaches 200% of the grant price for five consecutive trading days (Capped Option). EOG may or may not issue Capped Options in the future. The fair value of each Capped Option grant was estimated using a Monte Carlo simulation. Effective May 2005, the fair value of stock option grants not containing the Capped Option feature and SAR grants was estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $9.3 million and $10.4 million during the three months ended June 30, 2010 and 2009, respectively, and $17.8 million and $19.1 million during the six months ended June 30, 2010 and 2009, respectively.

At the 2010 Annual Meeting, an amendment to the ESPP was approved to increase the shares available for grant by 1,000,000 shares. The ESPP was originally approved by EOG's stockholders in 2001, and would have expired on July 1, 2011. The amendment also extended the term of the ESPP to December 31, 2019, unless terminated earlier by its terms or by EOG. EOG had previously suspended the ESPP, effective for the July 1, 2009 - December 31, 2009 offering period, due to an insufficient number of shares then remaining available under the ESPP. Subject to

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

stockholder approval at the 2010 Annual Meeting of the above-referenced amendment to the ESPP to increase the shares available under the ESPP, EOG resumed the ESPP for the January 1, 2010 to June 30, 2010 offering period.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the six-month periods ended June 30, 2010 and 2009 are as follows:

	Stock Options/SARs						ESPP
	Six Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009

Weighted Average Fair Value of Grants	$	33.38		$	26.59		$	24.66		$	25.78
Expected Volatility		38.05	%		51.74	%		34.78	%		78.89	%
Risk-Free Interest Rate		1.21	%		1.09	%		0.15	%		0.25	%
Dividend Yield		0.6	%		0.9	%		0.7	%		1.0	%
Expected Life	5.0 yrs			4.8 yrs			0.5 yrs			0.5 yrs

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

The following table sets forth stock option and SAR transactions for the six-month periods ended June 30, 2010 and 2009 (stock options and SARs in thousands):

	Six Months Ended					Six Months Ended
	June 30, 2010					June 30, 2009
				Weighted					Weighted
	Number of			Average		Number of			Average
	Stock			Grant		Stock			Grant
	Options/SARs			Price		Options/SARs			Price

Outstanding at January 1		8,335		$	57.08		7,802		$	52.56
Granted		91			103.36		66			70.34
Exercised (1)		(724	)		40.72		(191	)		30.64
Forfeited		(56	)		79.22		(59	)		71.72
Outstanding at June 30 (2)		7,646		$	59.02		7,618		$	53.11

Vested or Expected to Vest (3)		7,414		$	58.32		7,391		$	52.38

Exercisable at June 30 (4)		4,750		$	45.71		4,660		$	38.60

(1)

The total intrinsic value of stock options/SARs exercised for the six months ended June 30, 2010 and 2009 was $45 million and $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 stock options/SARs.

(2)

The total intrinsic value of stock options/SARs outstanding at June 30, 2010 and 2009 was $303 million and $146 million, respectively. At June 30, 2010 and 2009, the weighted average remaining contractual life was 3.8 years and 4.1 years, respectively.

(3)

The total intrinsic value of stock options/SARs vested or expected to vest at June 30, 2010 and 2009 was $299 million and $146 million, respectively. At June 30, 2010 and 2009, the weighted average remaining contractual life was 3.8 years and 4.1 years, respectively.

(4)

The total intrinsic value of stock options/SARs exercisable at June 30, 2010 and 2009 was $251 million and $140 million, respectively. At June 30, 2010 and 2009, the weighted average remaining contractual life was 2.9 years and 3.5 years, respectively.

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

At June 30, 2010, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $64.4 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.3 years.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $13.2 million and $11.7 million for the three months ended June 30, 2010 and 2009, respectively, and $27.2 million and $29.4 million for the six months ended June 30, 2010 and 2009, respectively.

The following table sets forth the restricted stock and restricted stock units transactions for the six-month periods ended June 30, 2010 and 2009 (shares and units in thousands):

	Six Months Ended					Six Months Ended
	June 30, 2010					June 30, 2009
				Weighted					Weighted
	Number of			Average		Number of			Average
	Shares and			Grant Date		Shares and			Grant Date
	Units			Fair Value		Units			Fair Value

Outstanding at January 1		3,636		$	73.69		3,048		$	70.24
Granted		251			95.95		686			49.30
Released (1)		(206	)		49.46		(335	)		25.61
Forfeited		(44	)		76.23		(22	)		79.53
Outstanding at June 30 (2)		3,637		$	76.57		3,377		$	70.35

(1)

The total intrinsic value of restricted stock and restricted stock units released for the six months ended June 30, 2010 and 2009 was $20 million and $19 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.

(2)

The total intrinsic value of restricted stock and restricted stock units outstanding at June 30, 2010 and 2009 was $358 million and $229 million, respectively.

At June 30, 2010, unrecognized compensation expense related to restricted stock and restricted stock units totaled $131.3 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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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. Earnings (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the three-month and six-month periods ended June 30, 2010 and 2009 (in thousands, except per share data). For the three-month period ended June 30, 2009, the same number of shares was used in the calculation of both basic and diluted earnings per share as a result of the net loss realized during the period.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010		2009			2010		2009
Numerator for Basic and Diluted Earnings Per Share -
Net Income (Loss)	$	59,872	$	(16,706	)	$	177,887	$	142,004

Denominator for Basic Earnings Per Share -
Weighted Average Shares		250,825		248,207			250,596		248,095
Potential Dilutive Common Shares -
Stock Options/SARs		2,181		-			2,139		1,462
Restricted Stock and Restricted Stock Units		1,497		-			1,471		942
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares		254,503		248,207			254,206		250,499

Net Income (Loss) Per Share
Basic	$	0.24	$	(0.07	)	$	0.71	$	0.57
Diluted	$	0.24	$	(0.07	)	$	0.70	$	0.57

The diluted earnings per share calculation excludes stock options, SARs, restricted stock and restricted stock units that were anti-dilutive. The excluded stock options and SARs totaled 0.1 million and 7.7 million for the three months ended June 30, 2010 and 2009, respectively, and 0.1 million and 3.2 million for the six months ended June 30, 2010 and 2009, respectively. For the quarter ended June 30, 2009, excluded restricted stock and restricted stock units totaled 3.4 million.

4. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the six-month periods ended June 30, 2010 and 2009 (in thousands):

	Six Months Ended
	June 30,
	2010		2009

Interest (1)	$	60,918	$	44,270
Income Taxes	$	129,850	$	26,162

(1)	Net of capitalized interest of $37 million and $25 million for the six months ended June 30, 2010 and 2009, respectively.

Non-cash investing activities for the six months ended June 30, 2010 included non-cash additions of $3 million to EOG's oil and gas properties in connection with contingent consideration related to EOG's acquisition of certain unproved properties (see Note 14).

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

5. Comprehensive Income (Loss)

The following table presents the components of EOG's comprehensive income (loss) for the three-month and six-month periods ended June 30, 2010 and 2009 (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Comprehensive Income (Loss)
Net Income (Loss)	$	59,872		$	(16,706	)	$	177,887		$	142,004
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		(91,256	)		150,251			(29,088	)		98,963
Foreign Currency Swap Transaction		842			2,572			5,390			4,966
Income Tax Related to Foreign Currency Swap Transaction		(215	)		(649	)		(1,443	)		(1,258	)
Defined Benefit Pension and Postretirement Plans		40			36			80			70
Income Tax Related to Defined Benefit Pension and Postretirement Plans		(14	)		(13	)		(28	)		(25	)
Total	$	(30,731	)	$	135,491		$	152,798		$	244,720

6. Segment Information

Selected financial information by reportable segment is presented below for the three-month and six-month periods ended June 30, 2010 and 2009 (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009

Net Operating Revenues
United States	$	1,123,161		$	719,714		$	2,243,862		$	1,722,618
Canada		113,560			86,142			253,599			191,044
Trinidad		114,782			50,150			217,996			91,412
Other International (1)		6,465			5,033			13,204			14,174
Total	$	1,357,968		$	861,039		$	2,728,661		$	2,019,248

Operating Income (Loss)
United States	$	118,453		$	(6,088	)	$	309,323		$	255,630
Canada		(42,778	)		(10,787	)		(55,220	)		(8,398	)
Trinidad		74,942			29,772			146,969			51,270
Other International (1)		(10,116	)		(12,879	)		(40,669	)		(17,072	)
Total		140,501			18			360,403			281,430

Reconciling Items
Other Income (Expense), Net		(545	)		1,237			2,138			2,976
Interest Expense, Net		29,897			24,811			55,325			43,187
Income (Loss) Before Income Taxes	$	110,059		$	(23,556	)	$	307,216		$	241,219

(1) Other International includes EOG's United Kingdom and China operations.

-11-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Total assets by reportable segment are presented below at June 30, 2010 and December 31, 2009 (in thousands):

	At		At
	June 30,		December 31,
	2010		2009
Total Assets
United States	$	15,464,619	$	14,108,129
Canada		2,847,613		2,888,949
Trinidad		837,446		813,901
Other International (1)		316,005		307,688
Total	$	19,465,683	$	18,118,667

(1) Other International includes EOG's United Kingdom and China operations.

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 property, plant and equipment for the six-month periods ended June 30, 2010 and 2009 (in thousands):

	Six Months Ended
	June 30,
	2010			2009

Carrying Amount at Beginning of Period	$	456,484		$	368,159
Liabilities Incurred		10,601			15,415
Liabilities Settled		(8,168	)		(10,502	)
Accretion		12,086			10,690
Revisions (1)		46			(94	)
Foreign Currency Translations		(902	)		3,806
Carrying Amount at End of Period	$	470,147		$	387,474

Current Portion	$	29,473		$	19,834
Noncurrent Portion	$	440,674		$	367,640

(1) Revisions to asset retirement obligations primarily reflect changes in abandonment cost estimates.

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

-12-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

8. Suspended Well Costs

EOG's net changes in suspended well costs for the six-month period ended June 30, 2010 are presented below (in thousands):

	Six Months
	Ended
	June 30,
	2010

Balance at December 31, 2009	$	118,459
Additions Pending the Determination of Proved Reserves		81,575
Reclassifications to Proved Properties		(25,971	)
Charged to Dry Hole Costs		(5,379	)
Foreign Currency Translations		(3,254	)
Balance at June 30, 2010	$	165,430

The following table provides an aging of suspended well costs at June 30, 2010 (in thousands, except well count):

	At
	June 30,
	2010

Capitalized exploratory well costs that have been capitalized for a period less than one year	$	91,530
Capitalized exploratory well costs that have been capitalized for a period greater than one year		73,900	(1)
Total	$	165,430
Number of exploratory wells that have been capitalized for a period greater than one year		5

(1)

Consists of costs related to three shale projects in British Columbia, Canada (B.C.) ($45 million), an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($20 million) and an East Irish Sea project in the U.K. ($9 million). In the B.C. shale projects, EOG is currently evaluating additional well data and infrastructure alternatives for delivery of product and expects to complete its evaluations by the end of 2010. In the Central North Sea project, EOG is currently evaluating an export route and negotiating commercial terms for transport of production from the project. The operator expects to submit a revised field development plan to the U.K. Department of Energy and Climate Change during the fourth quarter of 2010 and anticipates approval in early 2011. In the East Irish Sea project, EOG is currently preparing a field development plan that it anticipates submitting to the U.K. Department of Energy and Climate Change during the third quarter of 2010.

9. Commitments and Contingencies

There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes. While the ultimate outcome and impact on EOG cannot be predicted with certainty, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow. EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

10. Pension Benefits

EOG has a non-contributory defined contribution pension plan and a matched defined contribution savings plan in place for most of its employees in the United States. For the six months ended June 30, 2010 and 2009, EOG's total costs recognized for these pension plans were $11.0 million and $10.4 million, respectively.

In addition, as more fully discussed in Note 6 to Consolidated Financial Statements included in EOG's 2009 Annual Report, EOG's Canadian, Trinidadian and United Kingdom subsidiaries maintain various pension and savings plans for most of their respective employees. For the six months ended June 30, 2010 and 2009, combined contributions to these plans were $1.4 million and $1.2 million, respectively.

11. Long-Term Debt

Long-Term Debt. EOG utilizes commercial paper and short-term borrowings from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding borrowings from commercial paper issuances or uncommitted credit facilities at June 30, 2010. The weighted average interest rates for commercial paper and uncommitted credit facility borrowings for the six months ended June 30, 2010 were 0.32% and 0.70%, respectively.

On May 20, 2010, EOG completed its public offering of $500 million aggregate principal amount of 2.95% Senior Notes due 2015 and $500 million aggregate principal amount of 4.40% Senior Notes due 2020 (together, Notes). Interest on the Notes is payable semi-annually in arrears on June 1 and December 1 of each year beginning December 1, 2010. Net proceeds from the offering of approximately $990 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings.

EOG currently has a $1.0 billion unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The Agreement matures on June 28, 2012. At June 30, 2010, there were no borrowings or letters of credit outstanding under the Agreement. Advances under the Agreement accrue interest based, at EOG's option, on either the London InterBank Offering Rate plus an applicable margin (Eurodollar rate) or the base rate of the Agreement's administrative agent. At June 30, 2010, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 0.54% and 3.25%, respectively.

On May 12, 2010, EOG Resources Trinidad Limited, a wholly owned foreign subsidiary of EOG, repaid at maturity the remaining $37 million outstanding balance of, and cancelled, its $75 million Revolving Credit Agreement.

Fair Value of Debt. At June 30, 2010 and December 31, 2009, EOG had outstanding $3,760 million and $2,797 million, respectively, aggregate principal amount of debt, which had estimated fair values of approximately $4,154 million and $3,056 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such quotes were not available, upon interest rates available to EOG at the end of each respective period.

-14-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

12. Fair Value Measurements

Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the accompanying Consolidated Balance Sheets. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2009 Annual Report, EOG adopted the provisions of the Fair Value Measurements and Disclosures Topic of the ASC for its financial and nonfinancial assets and liabilities. The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at June 30, 2010 and December 31, 2009 (in millions):

	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)
					Significant Unobservable Inputs (Level 3)


							Total
At June 30, 2010
Financial Assets:
Crude Oil Price Swaps	$	-	$	32	$	-	$	32

Financial Liabilities:
Natural Gas Basis Swaps	$	-	$	42	$	-	$	42
Foreign Currency Rate Swap		-		42		-		42
Contingent Consideration		-		-		19		19

At December 31, 2009
Financial Assets:
Natural Gas Collars, Price Swaps and Basis Swaps	$	-	$	21	$	-	$	21

Financial Liabilities:
Natural Gas Collars, Price Swaps and Basis Swaps	$	-	$	37	$	-	$	37
Foreign Currency Rate Swap		-		49		-		49
Contingent Consideration		-		-		35		35

The estimated fair value of crude oil financial price swap and natural gas financial collar, price swap and basis swap contracts was based upon forward commodity price curves based on quoted market prices. The estimated fair value of the foreign currency rate swap was based upon forward currency rates.

-15-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

In connection with the acquisition of certain unproved acreage in Nacogdoches County, Texas, during the fourth quarter of 2009 and the first quarter of 2010, EOG could be required to make an additional one-time supplemental cash payment to the sellers contingent upon future natural gas prices over a five-year period (see Note 14). The fair value of the contingent consideration was estimated using present value techniques based upon an assessment of the probability that EOG would be required to make such future payment. Level 3 inputs used in such assessment include EOG's internal estimates of future natural gas prices and an appropriate risk-adjusted discount rate.

The following table presents the reconciliation of the beginning and ending fair value of EOG's contingent consideration liability measured using significant unobservable inputs (Level 3) during the six-month period ended June 30, 2010 (in millions):

	Six Months Ended
	June 30, 2010

Fair Value at Beginning of Period	$	35
Additions (see Note 14)		3
Change in Fair Value Included in Earnings (1)		(19	)
Fair Value at End of Period	$	19

(1) Reflected as a reduction of depreciation, depletion and amortization.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 7.

Proved oil and gas properties with a carrying amount of $122 million were written down to their fair value of $91 million, resulting in a pretax impairment charge of $31 million for the six months ended June 30, 2010. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future natural gas and crude oil prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

13. Risk Management Activities

Commodity Price Risk. As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2009 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, price swap and basis swap contracts, as a means to manage this price risk. In addition to financial transactions, from time to time, 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. EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $37 million and $34 million for the three months ended June 30, 2010 and 2009, respectively, and $45 million and $385 million for the six months ended June 30, 2010 and 2009, respectively.

-16-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Natural Gas Financial Collar Contracts. At June 30, 2010, EOG had no outstanding natural gas financial collar contracts. Presented below is summary information regarding EOG's 2010 natural gas financial collar contracts which were outstanding during the first six months of 2010. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/MMBtu).

Natural Gas Financial Collar Contracts
			Floor Price				Ceiling Price
					Weighted Average Price ($/MMBtu)				Weighted Average Price ($/MMBtu)

	Volume (MMBtud)		Floor Range ($/MMBtu)				Ceiling Range ($/MMBtu)
	Volume (MMBtud)		Floor Range ($/MMBtu)				Ceiling Range ($/MMBtu)
2010
January (closed)		40,000	$	11.44 - 11.47	$	11.45	$	13.79 - 13.90	$	13.85
February (closed)		40,000		11.38 - 11.41		11.40		13.75 - 13.85		13.80
March (closed)		40,000		11.13 - 11.15		11.14		13.50 - 13.60		13.55
April (closed)		40,000		9.40 - 9.45		9.42		11.55 - 11.65		11.60
May (closed)		40,000		9.24 - 9.29		9.26		11.41 - 11.55		11.48
June (closed)		40,000		9.31 - 9.36		9.34		11.49 - 11.60		11.55

Natural Gas Financial Price Swap Contracts. At June 30, 2010, EOG had no outstanding natural gas financial price swap contracts. Presented below is summary information regarding EOG's 2010 natural gas financial price swap contracts which were outstanding during the first six months of 2010.

Natural Gas Financial Price Swap Contracts
			Weighted Average Price ($/MMBtu)
	Volume (MMBtud)
	Volume (MMBtud)
2010
January (closed)		20,000	$	11.20
February (closed)		20,000		11.15
March (closed)		20,000		10.89
April (closed)		20,000		9.29
May (closed)		20,000		9.13
June (closed)		20,000		9.21

Subsequent to June 30, 2010, EOG has entered into additional natural gas financial price swap contracts for the years 2011 and 2012. For information on such contracts, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commodity Derivative Transactions.

-17-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Crude Oil Financial Price Swap Contracts. Presented below is a comprehensive summary of EOG's crude oil financial price swap contracts at June 30, 2010, with notional volumes expressed in barrels per day (Bbld) and prices in dollars per barrel ($/Bbl). The average price of EOG's crude oil financial price swap contracts outstanding is $91.50 per barrel for the period from September 1, 2010 to December 31, 2010 and $93.18 per barrel for the year 2011.

Crude Oil Financial Price Swap Contracts
			Weighted Average Price ($/Bbl)
	Volume (Bbld)
	Volume (Bbld)
2010
September		2,000	$	91.50
October		2,000		91.50
November		2,000		91.50
December		2,000		91.50

2011
January		6,000	$	93.18
February		6,000		93.18
March		6,000		93.18
April		6,000		93.18
May		6,000		93.18
June		6,000		93.18
July		6,000		93.18
August		6,000		93.18
September		6,000		93.18
October		6,000		93.18
November		6,000		93.18
December		6,000		93.18

-18-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Natural Gas Financial Basis Swap Contracts. Prices received by EOG for its natural gas production generally vary from New York Mercantile Exchange (NYMEX) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas financial basis swap contracts in order to fix the differential between prices in the Rocky Mountain area and NYMEX Henry Hub prices. Presented below is a comprehensive summary of EOG's natural gas financial basis swap contracts at June 30, 2010. The weighted average price differential represents the amount of reduction to NYMEX gas prices per MMBtu for the notional volumes covered by the basis swap contracts.

Natural Gas Financial Basis Swap Contracts
			Weighted Average Price Differential ($/MMBtu)

	Volume (MMBtud)
	Volume (MMBtud)
2010
First Quarter (closed)		65,000	$	(1.72	)
Second Quarter (closed)		65,000		(2.56	)
Third Quarter (1)		65,000		(3.17	)
Fourth Quarter		65,000		(3.73	)

2011
First Quarter		65,000	$	(1.89	)

(1) Includes closed contracts for July 2010.

Foreign Currency Exchange Rate Risk. As more fully described in Note 2 to the Consolidated Financial Statements included in EOG's 2009 Annual Report, EOG is party to a foreign currency swap transaction with multiple banks to eliminate any exchange rate impacts that may result from the $150 million aggregate principal amount of notes issued by one of EOG's Canadian subsidiaries. EOG accounts for the foreign currency swap transaction using the hedge accounting method. Changes in the fair value of the foreign currency swap do not impact Net Income (Loss). The after-tax net impact from the foreign currency swap transaction was an increase in Other Comprehensive Income of $1 million and $2 million for the three months ended June 30, 2010 and 2009, respectively, and $4 million for both the six months ended June 30, 2010 and 2009 (see Note 5).

-19-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth the amount, on a gross basis, and classification of EOG's outstanding derivative financial instruments at June 30, 2010 and December 31, 2009. Certain amounts may be presented on a net basis in the consolidated financial statements when such amounts are with the same counterparty and subject to master netting arrangements between EOG and the counterparties to the transactions (in millions):

		Fair Value at
		June 30,		December 31,
Description	Location on Balance Sheet	2010		2009

Asset Derivatives
Crude Oil Price Swaps and Natural Gas Collars and Price Swaps -
Current Portion	Assets from Price Risk Management Activities	$	19	$	50
	Assets from Price Risk Management Activities	$	19	$	50
Noncurrent Portion	Other Assets	$	13	$	-

Liability Derivatives
Natural Gas Basis Swaps -
Current Portion	Liabilities from Price Risk Management Activities	$	42	$	57
	Liabilities from Price Risk Management Activities	$	42	$	57
Noncurrent Portion	Other Liabilities	$	-	$	9

Foreign Currency Rate Swap - Noncurrent Portion	Other Liabilities	$	42	$	49

Credit Risk. Notional contract amounts are used to express the magnitude of commodity price and foreign currency swap agreements. The amounts potentially subject to credit risk, in the event of nonperformance by the other parties, are equal to the fair value of such contracts (see Note 12). EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk.

All of EOG's outstanding derivative instruments are covered by International Swap Dealers Association, Inc. Master Agreements (ISDAs) with counterparties. The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit rating. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit rating to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDAs to be settled immediately. See Note 12 for the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position at June 30, 2010 and December 31, 2009. EOG had no collateral posted at June 30, 2010 and December 31, 2009.

-20-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)

(Unaudited)

14. Acquisitions

During the second quarter of 2010, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOG Canada), agreed to acquire the shares of Galveston LNG Inc., a Calgary-based corporation which, through its wholly-owned subsidiary, Kitimat LNG Inc., owns 49 percent of the planned liquefied natural gas (LNG) export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia. Preliminary construction costs, currently estimated to be approximately $3 billion (Canadian), will be revised at the conclusion of front-end engineering and design. In addition, Galveston LNG Inc. also owns a 24.5 percent interest in the proposed Pacific Trail Pipelines, an estimated $1 billion (Canadian) project, originating at Summit Lake, British Columbia. The pipeline is intended to link Western Canada’s natural gas producing regions to the Kitimat LNG terminal. An affiliate of Apache Corporation owns 51 percent of the planned Kitimat LNG terminal and 25.5 percent interest in the proposed Pacific Trail Pipelines and will be the operator of the Kitimat LNG terminal. Under the terms of the agreement, EOG Canada's offer to purchase the shares of Galveston LNG Inc. is conditioned upon the achievement of certain commercial and regulatory milestones.

As more fully described in Note 17 to the Consolidated Financial Statements included in EOG's 2009 Annual Report, in the fourth quarter of 2009, EOG entered into an agreement to acquire unproved acreage in Nacogdoches County, Texas, within the Haynesville and Bossier Shale formations (Haynesville Assets). The acquisition agreement provides for an additional one-time supplemental cash payment to the sellers of the Haynesville Assets that is contingent on the satisfaction of certain conditions (within a five-year period beginning on the principal closing date) set forth in the acquisition agreement with respect to future natural gas prices. EOG estimated the fair value of the contingent consideration as of the acquisition dates in accordance with the provisions of the Business Combinations Topic of the ASC and has included such amount in Other Liabilities on the Consolidated Balance Sheets. In accordance with the acquisition agreement, EOG acquired additional Haynesville Assets at a final closing which occurred in the first quarter of 2010. The total consideration recorded in 2010 for the acquisition of the Haynesville Assets was $18 million, including the contingent consideration. The estimated fair value of the contingent consideration, including $3 million of contingent consideration related to the 2010 acquisition, was $19 million at June 30, 2010 (see Note 12).

-21-

PART I. FINANCIAL INFORMATION

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EOG RESOURCES, INC.

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, 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, Trinidad, the United Kingdom and China. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment capital by controlling operating and capital costs. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet. EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. Maintaining the lowest possible operating cost structure that is consistent with safe operations is also an important goal in the implementation of EOG's strategy.

United States and Canada. EOG's efforts to identify plays with large reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's future natural gas and crude oil production. Production in the United States and Canada accounted for approximately 82% of total company production in the first six months of 2010 as compared to 86% in the first six months of 2009. EOG has placed an emphasis on applying its horizontal drilling expertise gained in natural gas resources plays to unconventional oil reservoirs. In 2010, EOG is focusing its efforts on developing its existing North American crude oil and condensate and natural gas liquids acreage and capturing additional North American horizontal oil plays. During the first six months of 2010, the North Dakota Bakken and Fort Worth Basin Barnett Shale areas produced an increasing amount of crude oil and condensate and natural gas liquids as compared to the comparable period in 2009. EOG holds approximately 505,000 net acres in the mature oil window of the Eagle Ford Shale Play in South Texas where it has drilled and completed approximately 30 wells. EOG expects significant crude oil production from this area beginning in 2011. For the first six months of 2010, crude oil and condensate and natural gas liquids production accounted for approximately 26% of total company production as compared to 21% for the comparable period in 2009. Based on current trends, EOG expects its 2010 crude oil and condensate and natural gas liquids production to continue to increase both in total and as a percentage of total company production as compared to 2009. EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

During the second quarter of 2010, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOG Canada), agreed to acquire the shares of Galveston LNG Inc., a Calgary-based corporation which, through its wholly-owned subsidiary, Kitimat LNG Inc., owns 49 percent of the planned liquefied natural gas (LNG) export terminal to be located at Bish Cove, near the Port of Kitimat, about 405 miles north of Vancouver, British Columbia. Planned capacity of the proposed Kitimat LNG terminal is about 700 million cubic feet of natural gas per day or five million metric tons of LNG per year. Preliminary construction costs, currently estimated to be approximately $3 billion (Canadian), will be revised at the conclusion of front-end engineering and design. In addition, Galveston LNG Inc. also owns a 24.5 percent interest in the proposed Pacific Trail Pipelines, an estimated $1 billion (Canadian), 300-mile project, originating at Summit Lake, British Columbia. The pipeline is intended to link western Canada's natural gas producing regions to the Kitimat LNG terminal. An affiliate of Apache Corporation owns 51 percent of the planned Kitimat LNG terminal and 25.5 percent interest in the proposed Pacific Trail Pipelines and will be the operator of the Kitimat LNG terminal. Under the terms of the agreement, EOG Canada's offer to purchase the shares of Galveston LNG Inc. is conditioned upon the achievement of certain commercial and regulatory milestones.

EOG has decided to market its Canadian shallow natural gas assets in 2010. EOG began marketing these assets in July 2010 with the anticipation of receiving bids in September 2010. If an acceptable bid is received, EOG expects to close the transaction during the fourth quarter of 2010.

-22-

International. In the United Kingdom, EOG plans to submit a field development plan to the United Kingdom Department of Energy and Climate Change in the third quarter of 2010 for its 2009 East Irish Sea oil discovery designated as the Conwy field. EOG has a 100% working interest in this field.

During the second quarter of 2010, EOG completed its second horizontal well in the Sichuan Basin, Sichuan Province, The People's Republic of China. During the third quarter of 2010, EOG plans to complete one additional horizontal well that was drilled during the fourth quarter of 2009. In July 2010, EOG finished drilling a third horizontal well and began drilling a fourth horizontal well. EOG expects to complete its evaluation of the economic viability of this project by the end of 2010.

EOG continues to evaluate other select natural gas and crude oil opportunities outside the United States and Canada primarily by pursuing opportunities in countries where indigenous natural gas and crude oil reserves have been identified.

Capital Structure. One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 27% at June 30, 2010 compared to 22% at December 31, 2009. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity. On May 20, 2010, EOG completed its public offering of $500 million aggregate principal amount of 2.95% Senior Notes due 2015 and $500 million aggregate principal amount of 4.40% Senior Notes due 2020 (together, Notes). Interest on the Notes is payable semi-annually in arrears on June 1 and December 1 of each year, beginning December 1, 2010. Net proceeds from the offering of approximately $990 million were used for general corporate purposes, including the repayment of outstanding commercial paper borrowings. During the first six months of 2010, EOG funded $2.5 billion in exploration and development and other property, plant and equipment expenditures, paid $75 million in dividends to common stockholders and repaid $37 million of long-term debt, primarily by utilizing cash provided from its operating activities, cash on hand, proceeds from the offering of the Notes and proceeds from commercial paper borrowings.

For 2010, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $5.6 billion, excluding acquisitions. United States and Canada crude oil drilling activity and, to a lesser extent, natural gas drilling activity will be the key components of these expenditures. EOG intends to manage the 2010 capital budget while maintaining a strong balance sheet, by successfully marketing its Canadian shallow natural gas assets (as discussed above) and certain other North American assets (both producing and non-producing), including certain of its horizontal shale gas acreage and its rich natural gas and crude oil acreage. If acceptable bids are received, EOG expects to close these transactions during the fourth quarter of 2010. Moreover, 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.

Results of Operations

The following review of operations for the three and six months ended June 30, 2010 and 2009 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Three Months Ended June 30, 2010 vs. Three Months Ended June 30, 2009

Net Operating Revenues. During the second quarter of 2010, net operating revenues increased $497 million, or 58%, to $1,358 million from $861 million for the same period of 2009. Total wellhead revenues for the second quarter of 2010, which are revenues generated from sales of EOG's production of natural gas, crude oil and condensate and natural gas liquids, increased $366 million, or 49%, to $1,113 million from $747 million for the same period of 2009. During the second quarter of 2010, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $37 million compared to net gains of $34 million for the same period of 2009. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party natural gas, crude oil and condensate and natural gas liquids as well as gathering fees associated with gathering third-party natural gas, for the second quarter of 2010 increased $119 million, or 153%, to $196 million from $77 million for the same period of 2009.

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Wellhead volume and price statistics for the three-month periods ended June 30, 2010 and 2009 were as follows:

	Three Months Ended
	June 30,
	2010		2009
Natural Gas Volumes (MMcfd) (1)
United States		1,069		1,139
Canada		204		225
Trinidad		341		266
Other International (2)		15		15
Total		1,629		1,645

Average Natural Gas Prices ($/Mcf) (3)
United States	$	4.12	$	3.37
Canada		3.60		3.40
Trinidad		2.58		1.51
Other International (2)		4.27		3.55
Composite		3.73		3.07

Crude Oil and Condensate Volumes (MBbld) (1)
United States		57.6		42.9
Canada		6.6		2.9
Trinidad		5.4		3.0
Other International (2)		0.1		0.1
Total		69.7		48.9

Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States	$	73.18	$	52.82
Canada		71.63		52.52
Trinidad		68.90		47.50
Other International (2)		73.21		46.75
Composite		72.69		52.47

Natural Gas Liquids Volumes (MBbld) (1)
United States		27.5		22.1
Canada		0.9		1.0
Total		28.4		23.1

Average Natural Gas Liquids Prices ($/Bbl) (3)
United States	$	40.31	$	25.60
Canada		42.55		25.60
Composite		40.38		25.60

Natural Gas Equivalent Volumes (MMcfed) (4)
United States		1,579		1,529
Canada		249		249
Trinidad		373		284
Other International (2)		16		15
Total		2,217		2,077

Total Bcfe (4)		201.8		189.0

(1)	Million cubic feet per day or thousand barrels per day, as applicable.

(2)	Other International includes EOG's United Kingdom and China operations.

(3)	Dollars per thousand cubic feet or per barrel, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 13 to the Consolidated Financial Statements).

(4)

Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil and condensate and natural gas liquids. Natural gas equivalents are determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil and condensate or natural gas liquids. Bcfe is calculated by multiplying the MMcfed amount by the number of days in the period and then dividing that amount by one thousand.

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Wellhead natural gas revenues for the second quarter of 2010 increased $93 million, or 20%, to $553 million from $460 million for the same period of 2009. The increase was due to a higher composite average wellhead natural gas price ($98 million), partially offset by decreased natural gas deliveries ($5 million). EOG's composite average wellhead natural gas price increased 21% to $3.73 per thousand cubic feet (Mcf) for the second quarter of 2010 from $3.07 per Mcf for the same period of 2009.

Natural gas deliveries for the second quarter of 2010 decreased 16 MMcfd, or 1%, to 1,629 MMcfd from 1,645 MMcfd for the same period of 2009, reflecting EOG's increased emphasis on crude oil and liquids rich projects. The decrease was primarily due to lower production in the United States (70 MMcfd) and Canada (21 MMcfd), partially offset by higher production in Trinidad (75 MMcfd). The decrease in the United States was primarily attributable to decreased production from Texas (64 MMcfd), the Rocky Mountain area (20 MMcfd), New Mexico (9 MMcfd) and Kansas (7 MMcfd), partially offset by increased production from Louisiana (23 MMcfd), Pennsylvania (11 MMcfd) and Mississippi (6 MMcfd). The increase in Trinidad was primarily attributable to deliveries under a take-or-pay contract, which began January 1, 2010 (71 MMcfd).

Wellhead crude oil and condensate revenues for the second quarter of 2010 increased $223 million, or 95%, to $456 million from $233 million for the same period of 2009 due to a higher composite average wellhead crude oil and condensate price ($127 million) and an increase of 21 MBbld, or 43%, in wellhead crude oil and condensate deliveries ($96 million). The increase in deliveries primarily reflects increased production in North Dakota (12 MBbld), Texas (5 MBbld) and Canada (4 MBbld). The composite average wellhead crude oil and condensate price for the second quarter of 2010 increased 39% to $72.69 per barrel compared to $52.47 per barrel for the same period of 2009.

Natural gas liquids revenues for the second quarter of 2010 increased $50 million, or 94%, to $104 million from $54 million for the same period of 2009 due to a higher composite average price ($38 million) and an increase of 5 MBbld, or 23%, in natural gas liquids deliveries ($12 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area. The composite average natural gas liquids price for the second quarter of 2010 increased 58% to $40.38 per barrel compared to $25.60 per barrel for the same period of 2009.

During the second quarter of 2010, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $37 million compared to net gains of $34 million for the same period of 2009. During the second quarter of 2010, the net cash inflow related to settled natural gas financial collar, price swap and basis swap contracts was $16 million compared to the net cash inflow of $345 million for the same period of 2009.

Gathering, processing and marketing revenues represent sales of third-party natural gas, crude oil and condensate and natural gas liquids as well as gathering fees associated with gathering third-party natural gas. During the three months and six months ended June 30, 2010 and 2009, such revenues were primarily related to sales of third-party crude oil and natural gas. Sales of third-party natural gas are utilized in order to balance firm transportation capacity with production in certain areas. Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs.

During the second quarter of 2010, gathering, processing and marketing revenues and marketing costs increased primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs for the second quarter of 2010 increased to $5 million from $3 million for the same period of 2009 due primarily to increased margin from crude oil marketing activities, partially offset by decreased margin from natural gas marketing activities.

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Operating and Other Expenses. For the second quarter of 2010, operating expenses of $1,217 million were $356 million higher than the $861 million incurred in the second quarter of 2009. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the three-month periods ended June 30, 2010 and 2009:

	Three Months Ended
	June 30,
	2010		2009

Lease and Well	$	0.80	$	0.71
Transportation Costs		0.47		0.35
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties (1)		2.18		1.86
Other Property, Plant and Equipment		0.14		0.12
General and Administrative (G&A)		0.32		0.31
Interest Expense, Net		0.15		0.13
Total (2)	$	4.06	$	3.48

(1)

The 2010 amount excludes the change in the estimated fair value of the contingent consideration liability of $2 million, or $0.01 per Mcfe (see Note 12 and Note 14 to the Consolidated Financial Statements).

(2)

Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A and interest expense, net for the three months ended June 30, 2010 compared to the same period of 2009 are set forth below.

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 natural gas and crude oil 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 operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates 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. In general, operating costs for wells producing crude oil and condensate are higher than operating costs for wells producing natural gas.

Lease and well expenses of $161 million for the second quarter of 2010 increased $26 million from $135 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($13 million) and Canada ($3 million), higher lease and well administrative expenses ($4 million) and changes in the Canadian exchange rate ($4 million).

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees, fuel costs, transportation fees and costs associated with EOG's crude-by-rail operations.

Transportation costs of $94 million for the second quarter of 2010 increased $28 million from $66 million for the same prior year period primarily due to increased transportation costs in the Rocky Mountain area ($15 million), the Fort Worth Basin Barnett Shale area ($9 million) and the Upper Gulf Coast area ($5 million), primarily reflecting increased costs associated with marketing arrangements to transport production to downstream markets. The increased transportation costs in the Rocky Mountain area include costs associated with EOG’s crude-by-rail operations.

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DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells, reserve revisions (upward or downward) primarily related to well performance and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from year to year. DD&A of the cost of other property, plant and equipment is calculated using the straight-line depreciation method over the useful lives of the assets. Other property, plant and equipment consist of gathering and processing assets, compressors, crude-by-rail assets, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

DD&A expenses for the second quarter of 2010 increased $89 million to $465 million from $376 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2010 were $84 million higher than the same prior year period primarily due to higher unit rates in Canada ($32 million), the United States ($26 million) and Trinidad ($4 million); unfavorable changes in the Canadian exchange rate ($10 million) and as a result of increased production in the United States ($9 million) and in Trinidad ($3 million).

DD&A expenses associated with other property, plant and equipment for the second quarter of 2010 were $5 million higher than the same prior year period primarily due to gathering and processing assets placed in service in the Rocky Mountain area ($3 million) and the Fort Worth Basin Barnett Shale area ($2 million).

Interest expense, net of $30 million for the second quarter of 2010 increased $5 million compared to the same prior year period primarily due to a higher average debt balance ($11 million), partially offset by higher capitalized interest ($6 million).

Exploration costs of $50 million for the second quarter of 2010 increased $16 million from $34 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States.

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties. Unproved properties with individually significant acquisition costs are amortized over the lease term and analyzed on a property-by-property basis for any impairment in value. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

Impairments of $80 million for the second quarter of 2010 increased $33 million from $47 million for the same prior year period primarily due to increased amortization of unproved property costs in the United States ($14 million) and increased impairments of proved properties in the United States ($11 million) and Canada ($9 million). EOG recorded impairments of proved properties of $20 million and zero for the second quarter of 2010 and 2009, respectively.

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on wellhead revenues and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

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Taxes other than income for the second quarter of 2010 increased $55 million to $78 million (7.0% of wellhead revenues) from $23 million (3.1% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to a decrease in credits taken in 2010 for Texas high cost gas severance tax rate reductions as a result of fewer wells qualifying for such credit ($20 million), an increase in severance/production taxes as a result of increased wellhead revenues in the United States ($15 million) and Trinidad ($7 million) and higher ad valorem/property taxes in the United States ($10 million). The increase in taxes other than income as a percentage of wellhead revenues primarily reflects an increase in non-revenue based taxes and fewer wells qualifying for Texas high cost gas severance tax rate reductions in 2010.

EOG recognized an income tax provision of $50 million for the second quarter of 2010 compared to an income tax benefit of $7 million for the comparable prior year period. The increase of $57 million is primarily due to increased pretax income. The net effective tax rate for the second quarter of 2010 increased to 46% from 29% for the same prior year period primarily as a result of higher foreign and state taxes.

Six Months Ended June 30, 2010 vs. Six Months Ended June 30, 2009

Net Operating Revenues. During the first six months of 2010, net operating revenues increased $710 million, or 35%, to $2,729 million from $2,019 million for the same period of 2009. Total wellhead revenues for the first six months of 2010 increased $785 million, or 52%, to $2,300 million from $1,515 million for the same period of 2009. During the first six months of 2010, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $45 million compared to net gains of $385 million for the same period of 2009. Gathering, processing and marketing revenues for the first six months of 2010 increased $253 million, or 219%, to $368 million from $115 million for the same period of 2009.

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Wellhead volume and price statistics for the six-month periods ended June 30, 2010 and 2009 were as follows:

	Six Months Ended
	June 30,
	2010		2009
Natural Gas Volumes (MMcfd)
United States		1,055		1,167
Canada		208		227
Trinidad		346		264
Other International		16		15
Total		1,625		1,673

Average Natural Gas Prices ($/Mcf) (1)
United States	$	4.67	$	3.72
Canada		4.42		3.92
Trinidad		2.54		1.42
Other International		4.27		4.84
Composite		4.18		3.39

Crude Oil and Condensate Volumes (MBbld)
United States		55.9		43.8
Canada		6.2		3.1
Trinidad		4.6		3.0
Other International		0.1		0.1
Total		66.8		50.0

Average Crude Oil and Condensate Prices ($/Bbl) (1)
United States	$	73.23	$	42.85
Canada		72.39		44.53
Trinidad		67.89		40.49
Other International		72.18		46.73
Composite		72.77		42.82

Natural Gas Liquids Volumes (MBbld)
United States		25.6		21.9
Canada		0.9		1.1
Total		26.5		23.0

Average Natural Gas Liquids Prices ($/Bbl) (1)
United States	$	43.23	$	23.88
Canada		44.09		25.56
Composite		43.25		23.96

Natural Gas Equivalent Volumes (MMcfed)
United States		1,545		1,561
Canada		250		252
Trinidad		374		282
Other International		16		16
Total		2,185		2,111

Total Bcfe		395.4		382.1

(1)

Excludes the impact of financial commodity derivative instruments (see Note 13 to the Consolidated Financial Statements).

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Wellhead natural gas revenues for the first six months of 2010 increased $202 million, or 20%, to $1,230 million from $1,028 million for the same period of 2009. The increase was due to a higher composite average wellhead natural gas price ($232 million), partially offset by decreased natural gas deliveries ($30 million). EOG's composite average wellhead natural gas price increased 23% to $4.18 per Mcf for the first six months of 2010 from $3.39 per Mcf for the same period of 2009.

Natural gas deliveries for the first six months of 2010 decreased 48 MMcfd, or 3%, to 1,625 MMcfd from 1,673 MMcfd for the same period of 2009, reflecting EOG's increased emphasis on crude oil and liquids rich projects. The decrease was due to lower production in the United States (112 MMcfd) and Canada (19 MMcfd), partially offset by increased production in Trinidad (82 MMcfd). The decrease in the United States was primarily attributable to decreased production in Texas (101 MMcfd), the Rocky Mountain area (25 MMcfd), New Mexico (9 MMcfd) and Kansas (7 MMcfd), partially offset by increased production from Louisiana (27 MMcfd), Pennsylvania (9 MMcfd) and Mississippi (2 MMcfd). The increase in Trinidad was primarily attributable to deliveries under a take-or-pay contract, which began January 1, 2010 (71 MMcfd).

Wellhead crude oil and condensate revenues for the first six months of 2010 increased $474 million, or 122%, to $862 million from $388 million for the same period of 2009 due to a higher composite average wellhead crude oil and condensate price ($355 million) and an increase of 17 MBbld, or 34%, in wellhead crude oil and condensate deliveries ($119 million). The increase in deliveries primarily reflects increased production in North Dakota (11 MBbld) and Texas (3 MBbld). The composite average wellhead crude oil and condensate price for the first six months of 2010 increased 70% to $72.77 per barrel compared to $42.82 per barrel for the same period of 2009.

Natural gas liquids revenues for the first six months of 2010 increased $107 million, or 108%, to $207 million from $100 million for the same period of 2009 due to a higher composite average price ($92 million) and an increase of 4 MBbld, or 15%, in natural gas liquids deliveries ($15 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area. The composite average natural gas liquids price for the first six months of 2010 increased 81% to $43.25 per barrel compared to $23.96 per barrel for the same period of 2009.

During the first six months of 2010, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $45 million compared to net gains of $385 million for the same period of 2009. During the first six months of 2010, the net cash inflow related to settled natural gas financial collar, price swap and basis swap contracts was $39 million compared to the net cash inflow of $656 million for the same period of 2009.

Operating and Other Expenses. For the first six months of 2010, operating expenses of $2,368 million were $630 million higher than the $1,738 million incurred in the same period of 2009. The following table presents the costs per Mcfe for the six-month periods ended June 30, 2010 and 2009:

	Six Months Ended
	June 30,
	2010		2009

Lease and Well	$	0.83	$	0.73
Transportation Costs		0.46		0.35
DD&A -
Oil and Gas Properties (1)		2.18		1.88
Other Property, Plant and Equipment		0.14		0.12
G&A		0.32		0.31
Interest Expense, Net		0.14		0.11
Total (2)	$	4.07	$	3.50

(1)

The 2010 amount excludes the change in the estimated fair value of the contingent consideration liability of $19 million, or $0.05 per Mcfe (see Note 12 and Note 14 to the Consolidated Financial Statements).

(2)

Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

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The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A and interest expense, net for the six months ended June 30, 2010 compared to the same period of 2009 are set forth below.

Lease and well expenses of $327 million for the first six months of 2010 increased $47 million from $280 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($17 million) and Canada ($5 million), changes in the Canadian exchange rate ($10 million), higher lease and well administrative expenses ($8 million) and increased expenditures for workovers in Canada ($3 million) and the United States ($2 million).

Transportation costs of $183 million for the first six months of 2010 increased $48 million from $135 million for the same prior year period primarily due to increased transportation costs in the Rocky Mountain area ($28 million), the Fort Worth Basin Barnett Shale area ($15 million) and the Upper Gulf Coast area ($6 million), primarily reflecting increased costs associated with marketing arrangements to transport production to downstream markets. The increased transportation costs in the Rocky Mountain area include costs associated with EOG’s crude-by-rail operations.

DD&A expenses for the first six months of 2010 increased $132 million to $897 million from $765 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first six months of 2010 were $122 million higher than the same prior year period primarily due to higher unit rates in Canada ($57 million), the United States ($53 million) and Trinidad ($7 million); unfavorable changes in the Canadian exchange rate ($24 million) and as a result of increased production in Trinidad ($6 million), partially offset by a change in the fair value of the contingent consideration liability ($19 million) and decreased production in the United States ($9 million).

DD&A expenses associated with other property, plant and equipment for the first six months of 2010 were $10 million higher than the same prior year period primarily due to gathering and processing assets placed in service in the Fort Worth Basin Barnett Shale area ($6 million) and Rocky Mountain area ($5 million).

Interest expense, net of $55 million for the first six months of 2010 increased $12 million compared to the same prior year period primarily due to a higher average debt balance ($24 million), partially offset by higher capitalized interest ($12 million).

Exploration costs of $101 million for the first six months of 2010 increased $17 million from $84 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States.

Impairments of $150 million for the first six months of 2010 increased $37 million from $113 million for the same prior year period primarily due to increased amortization of unproved property costs in the United States ($31 million) and increased impairments of proved properties in Canada ($10 million), partially offset by decreased impairments of proved properties in the United States ($3 million). EOG recorded impairments of proved properties of $31 million and $23 million for the six months ended June 30, 2010 and 2009, respectively.

Taxes other than income for the first six months of 2010 increased $83 million to $154 million (6.7% of wellhead revenues) from $71 million (4.7% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes primarily as a result of increased wellhead revenues in the United States ($28 million), Trinidad ($13 million) and Canada ($3 million); a decrease in credits taken in 2010 for Texas high cost gas severance tax rate reductions as a result of fewer wells qualifying for the credit ($28 million) and higher ad valorem/property taxes in the United States ($9 million).

Income tax provision of $129 million for the first six months of 2010 increased $30 million compared to the same prior year period due primarily to increased pretax income. The net effective tax rate for the first six months of 2010 increased to 42% from 41% for the same prior year period.

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Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2010 were funds generated from operations, net proceeds from the issuance of the Notes, proceeds from the sale of oil and gas properties and proceeds from stock options exercised and employee stock purchase plan activity. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; dividend payments to stockholders; and repayment of long-term debt. During the first six months of 2010, EOG's cash balance decreased $36 million to $650 million from $686 million at December 31, 2009.

Net cash provided by operating activities of $1,301 million for the first six months of 2010 increased $24 million compared to the same period of 2009 primarily reflecting an increase in wellhead revenues ($785 million) and favorable changes in working capital and other assets and liabilities ($107 million), partially offset by an unfavorable change in net cash flow from the settlement of financial commodity derivative contracts ($617 million), an increase in cash operating expenses ($204 million), an increase in net cash paid for income taxes ($104 million), and an increase in cash paid for interest expense ($17 million).

Net cash used in investing activities of $2,230 million for the first six months of 2010 increased by $478 million compared to the same period of 2009 due primarily to an increase in additions to oil and gas properties ($855 million), partially offset by favorable changes in working capital associated with investing activities ($305 million), an increase in proceeds from sales of assets ($41 million) and a decrease in additions to other property, plant and equipment ($36 million).

Net cash provided by financing activities of $892 million for the first six months of 2010 included the issuance of the Notes ($991 million) and proceeds from stock options exercised and employee stock purchase plan activity ($21 million). Cash used in financing activities for the first six months of 2010 included cash dividend payments ($75 million), the repayment of long-term debt ($37 million) and the purchase of treasury stock ($7 million). Net cash provided by financing activities of $845 million for the first six months of 2009 included a long-term debt borrowing ($900 million), excess tax benefits from stock-based compensation ($22 million) and proceeds from stock options exercised and employee stock purchase plan activity ($8 million). Cash used in financing activities for the first six months of 2009 included cash dividend payments ($70 million), debt issuance costs ($9 million) and the purchase of treasury stock ($6 million).

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Total Expenditures. For 2010, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $5.6 billion, excluding acquisitions. The table below sets out components of total expenditures for the six-month periods ended June 30, 2010 and 2009 (in millions):

	Six Months Ended
	June 30,
	2010		2009
Expenditure Category
Capital
Drilling and Facilities	$	1,934	$	1,233
Leasehold Acquisitions		257		131
Property Acquisitions (1)		21		7
Capitalized Interest		37		25
Subtotal		2,249		1,396
Exploration Costs		101		84
Dry Hole Costs		42		37
Exploration and Development Expenditures		2,392		1,517
Asset Retirement Costs		13		15
Total Exploration and Development Expenditures		2,405		1,532
Other Property, Plant and Equipment		116		152
Total Expenditures	$	2,521	$	1,684

(1)

In 2010, property acquisitions included contingent consideration, with an estimated fair value of $3 million, related to the acquisition of the Haynesville Assets (see Note 14 to the Consolidated Financial Statements).

Exploration and development expenditures of $2,392 million for the first six months of 2010 were $875 million higher than the same period of 2009 due primarily to increased drilling and facilities expenditures in the United States ($560 million), Canada ($56 million), Trinidad ($41 million) and China ($24 million); increased leasehold acquisition expenditures in the United States ($120 million); changes in the foreign currency exchange rate in Canada ($28 million); increased dry hole costs in the United Kingdom ($16 million) and Trinidad ($5 million); increased property acquisition expenditures in the United States ($14 million); increased geological and geophysical expenditures in the United States ($13 million); and increased capitalized interest in the United States ($12 million); partially offset by decreased dry hole costs in the United States ($13 million). The exploration and development expenditures for the first six months of 2010 of $2,392 million include $1,743 million in development, $591 million in exploration, $37 million in capitalized interest and $21 million in property acquisitions. The exploration and development expenditures for the first six months of 2009 of $1,517 million include $1,111 million in development, $374 million in exploration, $25 million in capitalized interest and $7 million in property acquisitions.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development and other property, plant and equipment expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in the United States, Canada, Trinidad, the United Kingdom and China, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

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Commodity Derivative Transactions. As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2009, filed on February 25, 2010, 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, price swap and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income. The related cash flow impact is reflected as Cash Flows from Operating Activities. In addition to financial transactions, from time to time, 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.

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As of August 5, 2010, EOG had no outstanding natural gas financial collar contracts in place.

Financial Price Swap Contracts. The total fair value of EOG's crude oil financial price swap contracts at June 30, 2010 was a positive $32 million, which is reflected in the Consolidated Balance Sheets. Subsequent to June 30, 2010, EOG has entered into additional natural gas financial price swap contracts for 2011 and 2012. Presented below is a comprehensive summary of EOG's natural gas and crude oil financial price swap contracts at August 5, 2010, with notional volumes expressed in million British thermal units per day (MMBtud) and in barrels per day (Bbld) and prices expressed in dollars per million British thermal units ($/MMBtu) and in dollars per barrel ($/Bbl), as applicable. The average price of EOG's natural gas financial price swap contracts outstanding for the year 2011 is $5.44 per million British thermal units (MMBtu) and for the year 2012 is $5.44 per MMBtu. The average price of EOG's crude oil financial price swap contracts outstanding is $91.50 per barrel for the period from September 1, 2010 to December 31, 2010 and $93.18 per barrel for the year 2011.

Financial Price Swap Contracts
	Natural Gas				Crude Oil
	Volume (MMBtud)		Weighted Average Price ($/MMBtu)		Volume (Bbld)		Weighted Average Price ($/Bbl)
2010
September		-	$	-		2,000	$	91.50
October		-		-		2,000		91.50
November		-		-		2,000		91.50
December		-		-		2,000		91.50

2011 (1)
January		150,000	$	5.44		6,000	$	93.18
February		150,000		5.44		6,000		93.18
March		150,000		5.44		6,000		93.18
April		150,000		5.44		6,000		93.18
May		150,000		5.44		6,000		93.18
June		150,000		5.44		6,000		93.18
July		150,000		5.44		6,000		93.18
August		150,000		5.44		6,000		93.18
September		150,000		5.44		6,000		93.18
October		150,000		5.44		6,000		93.18
November		150,000		5.44		6,000		93.18
December		150,000		5.44		6,000		93.18

2012
January		100,000	$	5.44		-	$	-
February		100,000		5.44		-		-
March		100,000		5.44		-		-
April		100,000		5.44		-		-
May		100,000		5.44		-		-
June		100,000		5.44		-		-
July		100,000		5.44		-		-
August		100,000		5.44		-		-
September		100,000		5.44		-		-
October		100,000		5.44		-		-
November		100,000		5.44		-		-
December		100,000		5.44		-		-

(1)

Subsequent to June 30, 2010, EOG entered into swaption contracts which give a counterparty the option of entering into a price swap at a future date. Such option is exercisable on December 22, 2010. If counterparty exercises this option, the notional volume of EOG's existing natural gas financial price swap contracts will increase by 100,000 MMBtud at an average price of $5.48 for the full year 2011.

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Financial Basis Swap Contracts. Prices received by EOG for its natural gas production generally vary from New York Mercantile Exchange (NYMEX) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas financial basis swap contracts in order to fix the differential between prices in the Rocky Mountain area and NYMEX Henry Hub prices. The total fair value of EOG's natural gas financial basis swap contracts at June 30, 2010 was a negative $42 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial basis swap contracts at August 5, 2010. The notional volumes are expressed in million British thermal units per day (MMBtud) and price differentials are expressed in dollars per million British thermal units ($/MMBtu). The weighted average price differential represents the amount of reduction to NYMEX gas prices per MMBtu for the notional volumes covered by the basis swap contracts.

Natural Gas Financial Basis Swap Contracts
	Volume		Weighted Average Price Differential
	(MMBtud)		($/MMBtu)
2010
First Quarter (closed)		65,000	$	(1.72	)
Second Quarter (closed)		65,000		(2.56	)
Third Quarter (1)		65,000		(3.17	)
Fourth Quarter		65,000		(3.73	)

2011
First Quarter		65,000	$	(1.89	)

(1) Includes closed contracts for the months of July and August 2010.

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Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production or generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known and unknown risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

·	the timing and extent of changes in prices for natural gas, crude oil and related commodities;

·	changes in demand for natural gas, crude oil and related commodities, including ammonia and methanol;

·	the extent to which EOG is successful in its efforts to discover and market reserves and to acquire natural gas and crude oil properties;

·	the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling and advanced completion technologies;

the extent to which EOG is successful in its efforts to economically develop its acreage in, and to produce reserves and achieve anticipated production levels from, its existing and future natural gas and crude oil exploration and development projects, given the risks and uncertainties inherent in drilling, completing and operating natural gas and crude oil wells and the potential for interruptions of production, whether involuntary or intentional as a result of market or other conditions;

·	the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

·	the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights of way;

·	changes in government policies, laws and regulations, including environmental and tax laws and regulations;

·	competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

·	EOG's ability to obtain access to surface locations for drilling and production facilities;

·	the extent to which EOG's third-party-operated natural gas and crude oil properties are operated successfully and economically;

·	EOG's ability to effectively integrate acquired natural gas and crude oil properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

·	weather, including its impact on natural gas and crude oil demand, and weather-related delays in drilling and in the installation and operation of production, gathering, processing, compression and transportation facilities;

·	the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

·	EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all;

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

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·	the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;

·	political developments around the world, including in the areas in which EOG operates;

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

·	the timing and impact of liquefied natural gas imports;

·	the use of competing energy sources and the development of alternative energy sources;

·	the extent to which EOG incurs uninsured losses and liabilities;

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

·	the other factors described under Item 1A, "Risk Factors," on pages 14 through 19 of EOG's Annual Report on Form 10-K for the year ended December 31, 2009.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances 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 (i) the "Derivative Transactions," "Financing," "Foreign Currency Exchange Rate Risk" and "Outlook" sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity," on pages 37 through 41 of EOG's Annual Report on Form 10-K for the year ended December 31, 2009, filed on February 25, 2010 (EOG's 2009 Annual Report); and (ii) Note 11, "Risk Management Activities," on pages F-25 through F-28, to EOG's Consolidated Financial Statements included in EOG's 2009 Annual Report. There have been no material changes in this information. For additional information regarding EOG's financial commodity derivative contracts and physical commodity contracts, see (i) Note 13 to Consolidated Financial Statements in this Quarterly Report on Form 10-Q; (ii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Net Operating Revenues" in this Quarterly Report on Form 10-Q; and (iii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions" in this Quarterly Report on Form 10-Q.

ITEM 4. CONTROLS AND PROCEDURES

EOG RESOURCES, INC.

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this Quarterly Report on Form 10-Q (Evaluation Date). Based on this evaluation, EOG's principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date in ensuring that information that is required to be disclosed by EOG in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to EOG's management as appropriate to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting. There were no changes in EOG's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act) that occurred during the quarterly period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

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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.

On July 12, 2010, EOG Resources, Inc. (EOG) entered into a Consent Order and Agreement (COA) with the Pennsylvania Department of Environmental Protection (PADEP) to fully resolve alleged violations of the State of Pennsylvania’s Oil and Gas Act, Clean Streams Law, Air Act and Solid Waste Management Act. The alleged violations arose out of a well control incident on June 3, 2010 at the EOG-operated Punxsutawney Hunt Club #36H natural gas well in Clearfield County, Pennsylvania. As part of the COA, EOG has paid a civil penalty, including response costs incurred by the PADEP, of $353,419, and is in the process of implementing additional operating practices.

EOG had suspended operations in Pennsylvania following the incident pending an investigation by PADEP and an independent industry expert hired by EOG. PADEP authorized EOG to resume normal drilling operations on June 14, 2010 and to resume hydraulic fracturing operations on June 25, 2010. With the COA, EOG was authorized to resume all PADEP-permitted operations in Pennsylvania immediately.

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

The following table sets forth, for the periods indicated, EOG's share repurchase activity:

					Total Number of
	Total				Shares Purchased as		Maximum Number
	Number of		Average		Part of Publicly		of Shares that May Yet
	Shares		Price Paid		Announced Plans or		Be Purchased Under
Period	Purchased (1)		Per Share		Programs		The Plans or Programs (2)

April 1, 2010 - April 30, 2010		10,707	$	106.32		-		6,386,200
May 1, 2010 - May 31, 2010		3,335		108.47		-		6,386,200
June 1, 2010 - June 30, 2010		4,336		105.97		-		6,386,200
Total		18,378	$	106.63		-

(1)

Represents shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock or restricted stock unit grants or (ii) in payment of the exercise price of employee stock options. These shares do not count against the 10 million aggregate share authorization by EOG's Board of Directors (Board) discussed below.

(2)	In September 2001, the Board authorized the repurchase of up to 10 million shares of EOG's common stock. EOG did not repurchase any shares under the Board-authorized repurchase program during the second quarter of 2010.

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ITEM 6. EXHIBITS

Exhibit No. Description

4.1	-	Officers' Certificate Establishing 2.95% Senior Notes due 2015 and 4.40% Senior Notes due 2020, dated May 20, 2010 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed May 26, 2010).

4.2	-	Form of Global Note with respect to the 2.95% Senior Notes due 2015 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed May 26, 2010).

4.3	-	Form of Global Note with respect to the 4.40% Senior Notes due 2020 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed May 26, 2010).

10.1	-	Second Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as of January 1, 2010 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).

10.2	-	EOG Resources, Inc. Amended and Restated Executive Officer Annual Bonus Plan (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).

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

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

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

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

* **101.INS	-	XBRL Instance Document.

* **101.SCH	-	XBRL Schema Document.

* **101.CAL	-	XBRL Calculation Linkbase Document.

* **101.DEF	-	XBRL Definition Linkbase Document.

* **101.LAB	-	XBRL Label Linkbase Document.

* **101.PRE	-	XBRL Presentation Linkbase Document.

* Exhibits filed herewith

** Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income - Three Months Ended June 30, 2010 and 2009 and Six Months Ended June 30, 2010 and 2009, (ii) the Consolidated Balance Sheets - June 30, 2010 and December 31, 2009, (iii) the Consolidated Statements of Cash Flows - Six Months Ended June 30, 2010 and 2009 and (iv) Notes to Consolidated Financial Statements. Users of this data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

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SIGNATURES

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

		EOG RESOURCES, INC.
		(Registrant)



Date: August 5, 2010	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial and Accounting Officer and Duly Authorized Officer)

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EXHIBIT INDEX

Exhibit No. Description

4.1	-	Officers' Certificate Establishing 2.95% Senior Notes due 2015 and 4.40% Senior Notes due 2020, dated May 20, 2010 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed May 26, 2010).

4.2	-	Form of Global Note with respect to the 2.95% Senior Notes due 2015 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed May 26, 2010).

4.3	-	Form of Global Note with respect to the 4.40% Senior Notes due 2020 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed May 26, 2010).

10.1	-	Second Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as of January 1, 2010 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).

10.2	-	EOG Resources, Inc. Amended and Restated Executive Officer Annual Bonus Plan (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).

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

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

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

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

* **101.INS	-	XBRL Instance Document.

* **101.SCH	-	XBRL Schema Document.

* **101.CAL	-	XBRL Calculation Linkbase Document.

* **101.DEF	-	XBRL Definition Linkbase Document.

* **101.LAB	-	XBRL Label Linkbase Document.

* **101.PRE	-	XBRL Presentation Linkbase Document.

* Exhibits filed herewith

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