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
		March 31,
		2011				2010
Net Operating Revenues
Crude Oil and Condensate		$	757,362			$	406,163
Natural Gas Liquids			148,727				103,026
Natural Gas			583,919				676,982
(Losses) Gains on Mark-to-Market Commodity Derivative Contracts			(66,746	)			7,803
Gathering, Processing and Marketing			395,583				171,943
Gains (Losses) on Property Dispositions, Net			71,742				(676	)
Other, Net			6,519				5,452
Total			1,897,106				1,370,693
Operating Expenses
Lease and Well			215,089				165,992
Transportation Costs			97,633				88,711
Gathering and Processing Costs			19,196				15,661
Exploration Costs			50,909				51,197
Dry Hole Costs			22,951				23,077
Impairments			89,328				69,595
Marketing Costs			385,409				168,764
Depreciation, Depletion and Amortization			568,226				431,906
General and Administrative			70,037				60,423
Taxes Other Than Income			105,877				75,465
Total			1,624,655				1,150,791
Operating Income			272,451				219,902
Other Income, Net			3,604				2,683
Income Before Interest Expense and Income Taxes			276,055				222,585
Interest Expense, Net			50,333				25,428
Income Before Income Taxes			225,722				197,157
Income Tax Provision			91,749				79,142
Net Income		$	133,973			$	118,015
Net Income Per Share
Basic		$	0.52			$	0.47
Diluted		$	0.52			$	0.46
Dividends Declared per Common Share		$	0.160			$	0.155
Average Number of Common Shares
Basic			255,200				250,370
Diluted			258,819				253,869

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)

 

		March 31,				December 31,
		2011				2010
ASSETS
Current Assets
Cash and Cash Equivalents		$	1,668,285			$	788,853
Accounts Receivable, Net			1,228,549				1,113,279
Inventories			481,826				415,792
Assets from Price Risk Management Activities			45,498				48,153
Income Taxes Receivable			30,546				54,916
Deferred Income Taxes			28,072				9,260
Other			114,827				97,193
Total			3,597,603				2,527,446
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)			30,526,397				29,263,809
Other Property, Plant and Equipment			1,863,061				1,733,073
Total Property, Plant and Equipment			32,389,458				30,996,882
Less:  Accumulated Depreciation, Depletion and Amortization			(12,748,006	)			(12,315,982	)
Total Property, Plant and Equipment, Net			19,641,452				18,680,900
Other Assets			306,467				415,887
Total Assets		$	23,545,522			$	21,624,233
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable		$	1,838,959			$	1,664,944
Accrued Taxes Payable			136,897				82,168
Dividends Payable			40,247				38,962
Liabilities from Price Risk Management Activities			105,231				28,339
Deferred Income Taxes			7,944				41,703
Current Portion of Long-Term Debt			220,000				220,000
Other			150,913				143,983
Total			2,500,191				2,220,099
Long-Term Debt			5,004,725				5,003,341
Other Liabilities			680,754				667,455
Deferred Income Taxes			3,571,473				3,501,706
Commitments and Contingencies (Note 9)
Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 268,540,507 Shares Issued at March 31, 2011 and 254,223,521 Shares Issued at December 31, 2010			202,685				202,542
Additional Paid in Capital			2,148,476				729,992
Accumulated Other Comprehensive Income			485,464				440,071
Retained Earnings			8,963,475				8,870,179
Common Stock Held in Treasury, 121,135 Shares at March 31, 2011 and 146,186 Shares at December 31, 2010			(11,721	)			(11,152	)
Total Stockholders' Equity			11,788,379				10,231,632
Total Liabilities and Stockholders' Equity		$	23,545,522			$	21,624,233

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)

		Three Months Ended
		March 31,
		2011				2010
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income		$	133,973			$	118,015
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization			568,226				431,906
Impairments			89,328				69,595
Stock-Based Compensation Expenses			27,430				22,494
Deferred Income Taxes			31,290				36,695
(Gains) Losses on Property Dispositions, Net			(71,742	)			676
Other, Net			2,523				(953	)
Dry Hole Costs			22,951				23,077
Mark-to-Market Commodity Derivative Contracts
Total Losses (Gains)			66,746				(7,803	)
Realized Gains			24,937				22,960
Other, Net			6,219				2,505
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable			(113,855	)			(95,770	)
Inventories			(67,733	)			(53,312	)
Accounts Payable			165,497				147,632
Accrued Taxes Payable			79,748				(3,790	)
Other Assets			(18,656	)			(13,494	)
Other Liabilities			8,621				(5,554	)
Changes in Components of Working Capital Associated with Investing and Financing Activities			1,985				(74,592	)
Net Cash Provided by Operating Activities			957,488				620,287
Investing Cash Flows
Additions to Oil and Gas Properties			(1,527,854	)			(1,063,390	)
Additions to Other Property, Plant and Equipment			(159,794	)			(61,483	)
Proceeds from Sales of Assets			260,107				3,766
Changes in Components of Working Capital Associated with Investing Activities			(206	)			74,322
Other, Net			-				7,107
Net Cash Used in Investing Activities			(1,427,747	)			(1,039,678	)
Financing Cash Flows
Common Stock Sold			1,388,211				-
Dividends Paid			(39,003	)			(36,289	)
Treasury Stock Purchased			(14,981	)			(5,347	)
Proceeds from Stock Options Exercised			17,363				5,277
Other, Net			(1,779	)			270
Net Cash Provided by (Used in) Financing Activities			1,349,811				(36,089	)
Effect of Exchange Rate Changes on Cash			(120	)			(187	)
Increase (Decrease) in Cash and Cash Equivalents			879,432				(455,667	)
Cash and Cash Equivalents at Beginning of Period			788,853				685,751
Cash and Cash Equivalents at End of Period		$	1,668,285			$	230,084

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 (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, 2010, filed on February 24, 2011 (EOG's 2010 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 months ended March 31, 2011 are not necessarily indicative of the results to be expected for the full year.

2.	Stock-Based Compensation

As more fully discussed in Note 6 to the Consolidated Financial Statements included in EOG's 2010 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
		March 31,
		2011				2010
Lease and Well		$	7.7			$	6.3
Gathering and Processing Costs			0.2				-
Exploration Costs			6.1				5.5
General and Administrative			13.4				10.7
Total		$	27.4			$	22.5

 

 

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.  At March 31, 2011, approximately 6.8 million common shares remained available for grant under the 2008 Plan.  EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares.

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Stock Options and Stock-Settled 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.  The fair value of stock option and SAR grants is estimated using the Hull-White II binomial option pricing model.  Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $9.4 million and $8.5 million during the three months ended March 31, 2011 and 2010, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the three-month periods ended March 31, 2011 and 2010 are as follows:

		Stock Options/SARs								ESPP
		Three Months Ended								Three Months Ended
		March 31,								March 31,
		2011				2010				2011				2010
Weighted Average Fair Value of Grants		$	34.20			$	27.91			$	21.55			$	24.66
Expected Volatility			36.77	%			38.22	%			30.26	%			34.78	%
Risk-Free Interest Rate			1.18	%			1.01	%			0.18	%			0.15	%
Dividend Yield			0.6	%			0.7	%			0.6	%			0.7	%
Expected Life		5.5 yrs.				4.2 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 common 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.

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth stock option and SAR transactions for the three-month periods ended March 31, 2011 and 2010 (stock options and SARs in thousands):

		Three Months Ended								Three Months Ended
		March 31, 2011								March 31, 2010
						Weighted								Weighted
		Number of				Average				Number of				Average
		Stock				Grant				Stock				Grant
		Options/SARs				Price				Options/SARs				Price
Outstanding at January 1			8,445			$	64.49				8,335			$	57.08
Granted			16				101.30				30				97.68
Exercised (1)			(857	)			50.15				(266	)			30.32
Forfeited			(49	)			86.73				(19	)			77.05
Outstanding at March 31 (2)			7,555			$	66.05				8,080			$	58.07
Vested or Expected to Vest (3)			7,323			$	65.36				7,845			$	57.38
Exercisable at March 31 (4)			4,601			$	52.12				5,155			$	45.36

(1)

The total intrinsic value of stock options/SARs exercised for the three months ended March 31, 2011 and 2010 was $51.1 million and $17.6 million, respectively.  The intrinsic value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the stock options/SARs.

(2)	The total intrinsic value of stock options/SARs outstanding at March 31, 2011 and 2010 was $396.8 million and $283.5 million, respectively.  At March 31, 2011 and 2010, the weighted average remaining contractual life was 3.8 years and 3.9 years, respectively.

(3)	The total intrinsic value of stock options/SARs vested or expected to vest at March 31, 2011 and 2010 was $389.6 million and $280.6 million, respectively.  At March 31, 2011 and 2010, the weighted average remaining contractual life was 3.7 years and 3.9 years, respectively.

(4)	The total intrinsic value of stock options/SARs exercisable at March 31, 2011 and 2010 was $305.8 million and $245.9 million, respectively.  At March 31, 2011 and 2010, the weighted average remaining contractual life was 2.6 years and 3.1 years, respectively.

At March 31, 2011, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $79.0 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.6 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 $18.0 million and $14.0 million for the three months ended March 31, 2011 and 2010, respectively.

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth the restricted stock and restricted stock units transactions for the three-month periods ended March 31, 2011 and 2010 (shares and units in thousands):

		Three Months Ended								Three Months Ended
		March 31, 2011								March 31, 2010
						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			4,009			$	79.13				3,636			$	73.69
Granted			266				105.65				222				94.69
Released (1)			(182	)			67.27				(176	)			47.38
Forfeited			(48	)			78.30				(10	)			72.15
Outstanding at March 31 (2)			4,045			$	81.42				3,672			$	76.23

(1)

The total intrinsic value of restricted stock and restricted stock units released for the three months ended March 31, 2011 and 2010 was $19.3 million and $17.2 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 aggregate intrinsic value of restricted stock and restricted stock units outstanding at March 31, 2011 and 2010 was $479.4 million and $341.3 million, respectively.

At March 31, 2011, unrecognized compensation expense related to restricted stock and restricted stock units totaled $152.1 million.  Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.7 years.

3.	Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the three-month periods ended March 31, 2011 and 2010 (in thousands, except per share data):

		Three Months Ended
		March 31,
		2011				2010
Numerator for Basic and Diluted Earnings Per Share -
Net Income		$	133,973			$	118,015
Denominator for Basic Earnings Per Share -
Weighted Average Shares			255,200				250,370
Potential Dilutive Common Shares -
Stock Options/SARs			1,937				2,100
Restricted Stock and Restricted Stock Units			1,682				1,399
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares			258,819				253,869
Net Income Per Share
Basic		$	0.52			$	0.47
Diluted		$	0.52			$	0.46

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive.  The excluded stock options and SARs totaled 0.2 million shares for each of the three months ended March 31, 2011 and 2010.

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

4.      Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the three-month periods ended March 31, 2011 and 2010 (in thousands):

		Three Months Ended
		March 31,
		2011				2010
Interest (1)		$	19,912			$	4,842
Income Taxes, Net of Refunds Received		$	9,820			$	48,369

(1)	Net of capitalized interest of $16 million and $18 million for the three months ended March 31, 2011 and 2010, respectively.

EOG's accrued capital expenditures at March 31, 2011 and 2010 were $779 million and $451 million, respectively.

5.      Comprehensive Income

The following table presents the components of EOG's comprehensive income for the three-month periods ended March 31, 2011 and 2010 (in thousands):

		Three Months Ended
		March 31,
		2011				2010
Comprehensive Income
Net Income		$	133,973			$	118,015
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments			43,842				62,168
Foreign Currency Swap Transaction			659				4,548
Income Tax Related to Foreign Currency Swap Transaction			(164	)			(1,228	)
Interest Rate Swap Transaction			1,604				-
Income Tax Related to Interest Rate Swap Transaction			(578	)			-
Other			30				26
Total		$	179,366			$	183,529

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

6.	Segment Information

Selected financial information by reportable segment is presented below for the three-month periods ended March 31, 2011 and 2010 (in thousands):

		Three Months Ended
		March 31,
		2011				2010
Net Operating Revenues
United States		$	1,627,598			$	1,120,701
Canada			115,963				140,039
Trinidad			145,888				103,214
Other International (1)			7,657				6,739
Total		$	1,897,106			$	1,370,693
Operating Income (Loss)
United States		$	209,886			$	190,870
Canada			(19,436	)			(12,442	)
Trinidad			91,200				72,027
Other International (1)			(9,199	)			(30,553	)
Total			272,451				219,902
Reconciling Items
Other Income, Net			3,604				2,683
Interest Expense, Net			50,333				25,428
Income Before Income Taxes		$	225,722			$	197,157

 

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

Total assets by reportable segment are presented below at March 31, 2011 and December 31, 2010 (in thousands):

		At				At
		March 31,				December 31,
		2011				2010
Total Assets
United States		$	19,589,528			$	17,762,533
Canada			2,689,299				2,598,412
Trinidad			1,048,611				954,391
Other International (1)			218,084				308,897
Total		$	23,545,522			$	21,624,233

 

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

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 three-month periods ended March 31, 2011 and 2010 (in thousands):

		Three Months Ended
		March 31,
		2011				2010
Carrying Amount at Beginning of Period		$	498,288			$	456,484
Liabilities Incurred			5,959				5,376
Liabilities Settled			(14,078	)			(2,542	)
Accretion			6,166				5,322
Revisions			748				177
Foreign Currency Translations			2,158				3,133
Carrying Amount at End of Period		$	499,241			$	467,950
Current Portion		$	33,315			$	30,938
Noncurrent Portion		$	465,926			$	437,012

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.

8.	Suspended Well Costs

EOG's net changes in capitalized exploratory well costs for the three-month period ended March 31, 2011 are presented below (in thousands):

		Three Months Ended
		March 31, 2011
Balance at December 31, 2010		$	99,801
Additions Pending the Determination of Proved Reserves			14,694
Reclassifications to Proved Properties			(19,966	)
Charged to Dry Hole Costs			(19,509	)
Foreign Currency Translations			1,151
Balance at March 31, 2011		$	76,171

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table provides an aging of capitalized exploratory well costs at March 31, 2011 (in thousands, except well count):

		At
		March 31,
		2011
Capitalized exploratory well costs that have been capitalized for a period less than one year		$	19,096
Capitalized exploratory well costs that have been capitalized for a period greater than one year			57,075	(1)
Total		$	76,171
Number of exploratory wells that have been capitalized for a period greater than one year			4

(1)

Consists of costs related to an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($22 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($20 million), and a shale project in British Columbia, Canada (B.C.) ($6 million).  In the Central North Sea project, the operator and partners are currently negotiating processing and transportation terms with export infrastructure owners.  The operator expects to submit a revised field development plan to the U.K. Department of Energy and Climate Change (DECC) during the third quarter of 2011 and anticipates receiving approval of this plan during the first quarter of 2012.  In the East Irish Sea project, EOG submitted its field development plan to the DECC during the first quarter of 2011 with regulatory approval expected by the end of 2011.  The evaluation of the Sichuan Basin project is expected to be completed during the first half of 2011.  In the B.C. shale project, EOG drilled two additional wells in the first quarter of 2011 to further evaluate the project.  The related well completion activities are expected to commence in 2013.

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.

10.	Pension and Postretirement 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, Canada, Trinidad and the United Kingdom, in addition to defined benefit pension plans covering certain employees of its Canadian and Trinidadian subsidiaries.  For each of the three months ended March 31, 2011 and 2010, EOG's total costs recognized for these pension plans were $7.7 million and $6.4 million, respectively.  EOG also has postretirement medical and dental plans in place for eligible employees in the United States and Trinidad, the costs of which are not material.

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

11.      Long-Term Debt and Common Stock

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 March 31, 2011.  The average borrowings outstanding under the commercial paper program was $6 million during the three months ended March 31, 2011.  The weighted average interest rate for commercial paper borrowings for the three months ended March 31, 2011 was 0.32%.

EOG currently has two $1.0 billion unsecured Revolving Credit Agreements with domestic and foreign lenders.  At March 31, 2011, there were no borrowings or letters of credit outstanding under either of these agreements.  The first $1.0 billion unsecured Revolving Credit Agreement (2005 Agreement) matures on June 28, 2012.  Advances under the 2005 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 (as defined in the 2005 Agreement).  At March 31, 2011, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2005 Agreement, would have been 0.43% and 3.25%, respectively.

The second $1.0 billion unsecured Revolving Credit Agreement (2010 Agreement) matures on September 10, 2013 (subject to EOG's option to extend, on up to two occasions, the term for successive one-year periods).  Advances under the 2010 Agreement accrue interest based, at EOG's option, on either the Eurodollar rate or the base rate (as defined in the 2010 Agreement) plus an applicable margin.  At March 31, 2011, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2010 Agreement, would have been 1.82% and 3.83%, respectively.

Fair Value of Debt.   At both March 31, 2011 and December 31, 2010, EOG had outstanding $5,260 million aggregate principal amount of debt, which had estimated fair values of approximately $5,520 million and $5,602 million, respectively.  The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, upon interest rates available to EOG at the end of each respective period.

Common Stock.   On March 7, 2011, EOG completed the sale of 13,570,000 shares of EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share.  Net proceeds from the sale of the Common Stock were approximately $1.39 billion after deducting the underwriting discount and offering expenses.  Proceeds from the sale will be used for general corporate purposes, including funding future capital expenditures.

On February 17, 2011, the EOG Board of Directors increased the quarterly cash dividend on the Common Stock from the previous $0.155 per share to $0.16 per share effective with the dividend paid on April 29, 2011 to stockholders of record as of April 15, 2011.

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

12.	Fair Value Measurements

As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets.  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 March 31, 2011 and December 31, 2010 (in millions):

		Fair Value Measurements Using:
		Quoted				Significant
		Prices in				Other				Significant
		Active				Observable				Unobservable
		Markets				Inputs				Inputs
		(Level 1)				(Level 2)				(Level 3)				Total
At March 31, 2011
Financial Assets:
Natural Gas Price Swaps		$	-			$	50			$	-			$	50
Natural Gas Swaptions			-				3				-				3
Interest Rate Swaps			-				2				-				2
Financial Liabilities:
Crude Oil Price Swaps		$	-			$	98			$	-			$	98
Foreign Currency Rate Swap			-				59				-				59
At December 31, 2010
Financial Assets:
Natural Gas Price Swaps		$	-			$	62			$	-			$	62
Natural Gas Swaptions			-				6				-				6
Interest Rate Swaps			-				2				-				2
Financial Liabilities:
Crude Oil Price Swaps and Natural Gas Basis Swaps		$	-			$	29			$	-			$	29
Foreign Currency Rate Swap			-				55				-				55

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

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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.

Based on an accepted offer from a third-party buyer, proved oil and gas properties and other property, plant and equipment with a carrying amount of $115 million were written down to their fair value of $67 million, resulting in a pretax impairment charge of $47 million for the three months ended March 31, 2011.

13.	Risk Management Activities

Commodity Price Risk .   As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2010 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 crude oil and natural gas.  EOG utilizes financial commodity derivative instruments, primarily price swap, collar and basis swap contracts, as a means to manage this price risk.  In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions.  The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.  EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $67 million and net gains on the mark-to-market of financial commodity derivative contracts of $8 million for the three months ended March 31, 2011 and 2010, respectively.

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Financial Price Swap Contracts.   Presented below is a comprehensive summary of EOG's crude oil and natural gas financial price swap contracts at March 31, 2011, with notional volumes expressed in barrels per day (Bbld) and in million British thermal units per day (MMBtud) and prices expressed in dollars per barrel ($/Bbl) and in dollars per million British thermal units ($/MMBtu), as applicable.

Financial Price Swap Contracts
		Crude Oil								Natural Gas
		Volume (Bbld)				Weighted Average Price ($/Bbl)				Volume (MMBtud)				Weighted Average Price ($/MMBtu)
2011 (1)
January 2011 (closed)			17,000			$	90.44				275,000			$	5.19
February 2011 (closed)			18,000				90.69				425,000				5.09
March 2011 (closed)			20,000				91.82				425,000				5.09
April 2011 (2)			24,000				93.61				475,000				5.03
May 1, 2011 through December 31, 2011			24,000				93.61				550,000				4.96
2012 (3)
January 1, 2012 through December 31, 2012			2,000			$	100.50				325,000			$	5.54

(1)

EOG has entered into natural gas financial price swap contracts which give counterparties the option of entering into price swap contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas financial price swap contracts will increase by 400,000 MMBtud at an average price of $4.78 per million British thermal units (MMBtu) for the period from May 1, 2011 through December 31, 2011.

(2)	The crude oil contracts for April 2011 close on April 30, 2011.  The natural gas contracts for April 2011 are closed.

(3)

EOG has entered into natural gas financial price swap contracts which give counterparties the option of entering into price swap contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas financial price swap contracts will increase by 225,000 MMBtud at an average price of $5.58 per MMBtu for each month of 2012.

Subsequent to March 31, 2011, EOG entered into additional crude oil and 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.

Foreign Currency Exchange Rate Risk.   As more fully described in Note 2 to the Consolidated Financial Statements included in EOG's 2010 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 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.  The after-tax net impact from the foreign currency swap transaction was an increase in Other Comprehensive Income (OCI) of $0.5 million and $3.3 million for the three months ended March 31, 2011 and 2010, respectively.

Interest Rate Derivatives.   As more fully discussed in Note 2 to the Consolidated Financial Statements included in EOG's 2010 Annual Report, EOG is a party to an interest rate swap transaction to mitigate its exposure to volatility in interest rates related to EOG's $350 million principal amount of Floating Rate Senior Notes due 2014 issued on November 23, 2010.  The interest rate swap has a notional amount of $350 million and a fair value at March 31, 2011 of $2 million.  EOG accounts for the interest rate swap transaction using the hedge accounting method.  The after-tax impact from the interest rate swap transaction was an increase in OCI of $1 million for the three months ended March 31, 2011.

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding financial derivative instruments at March 31, 2011 and December 31, 2010.  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 a master netting arrangement (in millions):

			Fair Value at
			March 31,				December 31,
Description	Location on Balance Sheet		2011				2010
Asset Derivatives
Natural gas price swaps -
Current portion	Assets from Price Risk Management Activities		$	46			$	51
Noncurrent portion	Other Assets		$	17			$	18
Liability Derivatives
Crude oil price swaps and natural gas price and basis swaps -
Current Portion	Liabilities from Price Risk Management Activities		$	105			$	30
Noncurrent Portion	Other Liabilities		$	3			$	-
Foreign currency and interest rate swap -  Noncurrent portion	Other Liabilities		$	57			$	53

Credit Risk.   Notional contract amounts are used to express the magnitude of commodity price, foreign currency and interest rate swap agreements.  The amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 12).  EOG evaluates its exposure to significant counterparties on an ongoing basis, including exposure 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 Master Agreements (ISDA) 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 ratings.  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 March 31, 2011 and December 31, 2010.  EOG had no collateral posted at either March 31, 2011 or December 31, 2010.

 

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EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)

(Unaudited)

14.  Acquisitions and Divestitures

First quarter 2011 transactions related to the planned liquefied natural gas (LNG) export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia (Kitimat LNG Terminal) and the proposed Pacific Trail Pipelines (PTP) originating at Summit Lake, British Columbia intending to link Western Canada's natural gas producing regions to the Kitimat LNG Terminal were as follows:

·

In March 2011, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), purchased an additional 24.5% interest in PTP for $25.2 million.  A portion of the purchase price ($15.3 million) was paid at closing with the remaining amount to be paid contingent on the decision to proceed with the construction of the Kitimat LNG Terminal.  Subsequent to closing, EOGRC's ownership interest was 49%.  An affiliate of Apache Corporation (Apache) purchased the remaining 25.5% interest in PTP, increasing its ownership interest to 51% of the proposed project.

·

In March 2011, EOGRC and Apache, through a series of transactions, sold a portion of their interests in the Kitimat LNG Terminal and PTP to an affiliate of Encana Corporation (Encana).  Subsequent to these transactions, ownership interests in both the Kitimat LNG Terminal and PTP are:  Apache (operator) 40%, EOGRC 30% and Encana 30%.  All future costs of the project will be paid by each party in proportion to its respective ownership percentage.

During the first quarter of 2011, EOG received proceeds of approximately $260 million from the sale of producing properties and acreage, primarily in the Rocky Mountain area and Texas, and the sale of a portion of its interest in the Kitimat LNG Terminal and PTP.

 

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PART I.  FINANCIAL INFORMATION

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EOG RESOURCES, INC.

 

Overview

 

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude 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 of capital by controlling operating and capital costs and maximizing reserve recoveries.  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 prudent and 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 crude oil and natural gas production.  EOG has placed an emphasis on applying its horizontal drilling expertise gained from its natural gas resources plays to unconventional crude oil reservoirs.  In 2011, EOG expects to focus its efforts on developing its existing North American crude oil and condensate and natural gas liquids acreage and capturing additional North American horizontal crude oil plays.  For the first quarter of 2011, crude oil and condensate and natural gas liquids production accounted for approximately 32% of total company production as compared to 25% for the comparable period in 2010.  First quarter 2011 North American liquids production accounted for approximately 37% of total North American production as compared to 29% in 2010.  This liquids growth reflects production from the Eagle Ford Shale Play near San Antonio, Texas, and increasing amounts of crude oil and condensate and natural gas liquids production in the North Dakota Bakken and Fort Worth Basin Barnett Shale areas.  Based on current trends, EOG expects its 2011 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 2010.  In addition, EOG continues to evaluate certain potential liquids-rich exploration and development prospects.   EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

First quarter 2011 transactions related to the planned liquefied natural gas (LNG) export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia (Kitimat LNG Terminal) and the proposed Pacific Trail Pipelines (PTP) originating at Summit Lake, British Columbia intending to link Western Canada's natural gas producing regions to the Kitimat LNG Terminal were as follows:

·

In March 2011, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), purchased an additional 24.5% interest in PTP for $25.2 million.  A portion of the purchase price ($15.3 million) was paid at closing with the remaining amount to be paid contingent on the decision to proceed with the construction of the Kitimat LNG Terminal.  Subsequent to closing, EOGRC's ownership interest was 49%.  An affiliate of Apache Corporation (Apache) purchased the remaining 25.5% interest in PTP, increasing its ownership interest to 51% of the proposed project.

·	EOGRC and Apache awarded the front-end engineering and design (FEED) contract to a global engineering company.

·

In March 2011, EOGRC and Apache, through a series of transactions, sold a portion of their interests in the Kitimat LNG Terminal and PTP to an affiliate of Encana Corporation (Encana).  Subsequent to these transactions, ownership interests in both the Kitimat LNG Terminal and PTP are:  Apache (operator) 40%, EOGRC 30% and Encana 30%.  All future costs of the project will be paid by each party in proportion to its respective ownership percentage.

 

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International.    In Trinidad, EOG continued to deliver natural gas under existing supply contracts.  Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block and Modified U(b) Block, as well as the Pelican Field, have been developed and are producing crude oil and condensate and natural gas.  EOG expects to drill and complete several development wells in the Toucan Field on Block 4(a) with first production expected in 2012.  In the United Kingdom, EOG continues to make progress in field development plans for its East Irish Sea Conwy/Corfe crude oil discovery and its Central North Sea Columbus natural gas discovery.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States and Canada primarily by pursuing exploitation opportunities in countries with large shale plays where crude oil and natural gas 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 31% at March 31, 2011 and 34% at December 31, 2010.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On March 7, 2011, EOG completed the sale of 13,570,000 shares of EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share.  Net proceeds from the sale of the Common Stock were approximately $1.39 billion after deducting the underwriting discount and offering expenses.  Proceeds from the sale will be used for general corporate purposes, including funding future capital expenditures.  During the first quarter of 2011, EOG funded $1.7 billion in exploration and development and other property, plant and equipment expenditures and paid $39 million in dividends to common stockholders, primarily by utilizing cash on hand, cash provided from its operating activities, proceeds from the Common Stock sold and proceeds from asset sales.

The total anticipated 2011 capital expenditures are estimated to range from $6.4 billion to $6.6 billion, excluding acquisitions.  The majority of 2011 expenditures will be focused on United States and Canada crude oil drilling activity and, to a lesser extent, natural gas drilling activity in the Haynesville, Marcellus and British Columbia Horn River Basin plays to hold acreage.  EOG expects capital expenditures to be greater than cash flow from operating activities for 2011.  Along with the sale of Common Stock discussed above, EOG's business plan includes selling certain non-core natural gas assets in 2011 to cover the anticipated shortfall.  In the first quarter of 2011, proceeds of approximately $260 million were received from the sale of producing properties and acreage, primarily in the Rocky Mountain area and Texas, and the sale of a portion of EOG's interest in the Kitimat LNG Terminal and PTP.  Subsequent to March 31, 2011, EOG received additional proceeds of $387 million in connection with the sale of natural gas assets, primarily in Texas.  EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its revolving credit facilities and equity and debt offerings.  When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer 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 months ended March 31, 2011 and 2010 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Net Operating Revenues.   During the first quarter of 2011, net operating revenues increased $526 million, or 38%, to $1,897 million from $1,371 million for the same period of 2010.  Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, natural gas liquids and natural gas, for the first quarter of 2011 increased $304 million, or 26%, to $1,490 million from $1,186 million for the same period of 2010.  During the first quarter of 2011, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $67 million compared to net gains of $8 million for the same period of 2010.  Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas, for the first quarter of 2011 increased $224 million, or 130%, to $396 million from $172 million for the same period of 2010.  Gains on property dispositions, net, of $72 million for the first quarter of 2011 primarily consist of gains on property dispositions in the Rocky Mountain area and Texas.

 

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Wellhead volume and price statistics for the three-month periods ended March 31, 2011 and 2010 were as follows:

		Three Months Ended
		March 31,
		2011				2010
Crude Oil and Condensate Volumes (MBbld) (1)
United States			81.4				54.1
Canada			8.5				5.8
Trinidad			4.4				3.8
Other International (2)			0.1				0.1
Total			94.4				63.8
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States		$	88.00			$	73.29
Canada			84.24				73.27
Trinidad			86.84				66.45
Other International (2)			85.57				71.37
Composite			87.61				72.87
Natural Gas Liquids Volumes (MBbld) (1)
United States			34.5				23.7
Canada			0.9				0.9
Total			35.4				24.6
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States		$	46.63			$	46.64
Canada			47.11				45.78
Composite			46.65				46.61
Natural Gas Volumes (MMcfd) (1)
United States			1,134				1,043
Canada			143				211
Trinidad			385				351
Other International (2)			14				16
Total			1,676				1,621
Average Natural Gas Prices ($/Mcf) (3)
United States		$	4.10			$	5.24
Canada			3.67				5.22
Trinidad			3.20				2.51
Other International (2)			5.63				4.28
Composite			3.87				4.64
Crude Oil Equivalent Volumes (MBoed) (4)
United States			304.9				251.6
Canada			33.2				41.8
Trinidad			68.6				62.3
Other International (2)			2.4				2.8
Total			409.1				358.5
Total MMBoe (4)			36.8				32.3

(1)	Thousand barrels per day or million cubic feet per day, as applicable.

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

(3)	Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments.

(4)

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

 

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Wellhead crude oil and condensate revenues for the first quarter of 2011 increased $351 million, or 86%, to $757 million from $406 million for the same period of 2010, due to an increase of 31 MBbld, or 48%, in wellhead crude oil and condensate deliveries ($224 million) and a higher composite average wellhead crude oil and condensate price ($127 million).  The increase in deliveries primarily reflects increased production in Texas (19 MBbld), Colorado (4 MBbld) and North Dakota (3 MBbld).  Production increases in Texas were the result of increased production from the Fort Worth Basin Barnett Combo and Eagle Ford plays.  Production increases in North Dakota resulted from increased deliveries from the Bakken and Three Forks plays.  EOG's composite average wellhead crude oil and condensate price for first quarter of 2011 increased 20% to $87.61 per barrel compared to $72.87 per barrel for the same period of 2010.

Natural gas liquids revenues for the first quarter of 2011 increased $46 million, or 44%, to $149 million from $103 million for the same period of 2010, due to an increase of 11 MBbld, or 44%, in natural gas liquids deliveries.  The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area.  EOG’s composite average natural gas liquids price for the first quarter of 2011 was $46.65 per barrel compared to $46.61 per barrel for the same period of 2010.

Wellhead natural gas revenues for the first quarter of 2011 decreased $93 million, or 14%, to $584 million from $677 million for the same period of 2010.  The decrease was due to a lower composite average wellhead natural gas price ($116 million), partially offset by an increase in natural gas deliveries ($23 million).  EOG's composite average wellhead natural gas price for the first quarter of 2011 decreased 17% to $3.87 per Mcf compared to $4.64 per Mcf for the same period of 2010.

Natural gas deliveries for the first quarter of 2011 increased 55 MMcfd, or 3%, to 1,676 MMcfd from 1,621 MMcfd for the same period of 2010.  The increase was primarily due to higher production in the United States (91 MMcfd) and Trinidad (34 MMcfd), partially offset by decreased production in Canada (68 MMcfd).  The increase in the United States was primarily attributable to increased production in Texas (125 MMcfd) and Pennsylvania (15 MMcfd), partially offset by decreased production in the Rocky Mountain area (26 MMcfd), Mississippi (10 MMcfd), offshore Gulf of Mexico (5 MMcfd), Oklahoma (3 MMcfd), New Mexico (3 MMcfd) and Kansas (3 MMcfd).  The increase in Trinidad was primarily attributable to an increase in contractual deliveries.  The decreased production in Canada primarily reflects sales of certain shallow natural gas properties in the fourth quarter of 2010, partially offset by increased production from the Horn River Basin area.

During the first quarter of 2011, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $67 million compared to net gains of $8 million for the same period of 2010.  During the first quarter of 2011, the net cash inflow related to settled crude oil and natural gas financial price swap contracts and natural gas basis swap contracts was $25 million compared to the net cash inflow related to settled natural gas financial collar, price swap and basis swap contracts of $23 million for the same period of 2010.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas.  For the three months ended March 31, 2011 and 2010, gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas.  The purchase and sale of third-party crude oil and natural gas are utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities.  Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs.

During the first quarter of 2011, 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 first quarter of 2011 totaled $10 million compared to $3 million for the same period of 2010, primarily as a result of higher natural gas marketing margins.

 

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Operating and Other Expenses.   For the first quarter of 2011, operating expenses of $1,625 million were $474 million higher than the $1,151 million incurred during the first quarter of 2010.  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended March 31, 2011 and 2010:

		Three Months Ended
		March 31,
		2011				2010
Lease and Well		$	5.82			$	5.17
Transportation Costs			2.64				2.76
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties (1)			14.57				13.12
Other Property, Plant and Equipment			0.83				0.85
General and Administrative (G&A)			1.89				1.88
Interest Expense, Net			1.36				0.79
Total (2)		$	27.11			$	24.57

(1)	The 2011 and 2010 amounts exclude the change in the estimated fair value of a contingent consideration liability relating to the acquisition of certain unproved acreage of $1 million, or $0.02 per Boe, and $17 million, or $0.52 per Boe, respectively.

(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, G&A, and interest expense, net for the three months ended March 31, 2011 compared to the same period of 2010 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 crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses.  Operating and maintenance expenses include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power.  Workovers are 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 are higher than operating costs for wells producing natural gas.

Lease and well expenses of $215 million for the first quarter of 2011 increased $49 million from $166 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($41 million), increased lease and well administrative expenses in the United States ($8 million), increased workover expenditures in the United States ($3 million) and unfavorable changes in the Canadian exchange rate ($2 million), partially offset by lower operating and maintenance expenses in Canada ($7 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 crude-by-rail operations.

Transportation costs of $98 million for the first quarter of 2011 increased $9 million from $89 million for the same prior year period primarily due to increased transportation costs in the Upper Gulf Coast area ($7 million) and the Fort Worth Basin Barnett Shale area ($3 million) as a result of increased costs associated with marketing arrangements to transport production to downstream markets.

 

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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 first quarter of 2011 increased $136 million to $568 million from $432 million for the same prior year period.  DD&A expenses associated with oil and gas properties for the first quarter of 2011 were $133 million higher than the same prior year period primarily due to higher unit rates described below and as a result of increased production in the United States ($67 million) and Trinidad ($2 million) and unfavorable changes in the Canadian exchange rate ($4 million), partially offset by a decrease in production in Canada ($17 million).  DD&A rates increased due primarily to a proportional increase in production from higher-cost properties in the United States ($58 million).

DD&A expenses associated with other property, plant and equipment were $3 million higher than the same prior year period primarily due to gathering and processing assets placed in service in the Rocky Mountain area.

G&A expenses of $70 million for the first quarter of 2011 increased $10 million from the same prior year period primarily due to higher employee-related costs.

Interest expense, net of $50 million for the first quarter of 2011 increased $25 million as compared to the same prior year period primarily due to a higher average debt balance ($22 million) and lower capitalized interest ($3 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG’s gathering and processing assets.

Gathering and processing costs increased $3 million to $19 million for the first quarter of 2011 compared to $16 million for the same prior year period.  The increase reflects increased activities in the Fort Worth Basin Barnett Shale area ($3 million) and Canada ($2 million), partially offset by decreased activities in the Rocky Mountain area ($1 million).

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 generally calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.  For certain natural gas assets held for sale, EOG utilized accepted bids as the basis for determining fair value.

Impairments of $89 million for the first quarter of 2011 were $20 million higher than impairments for the same prior year period primarily due to increased impairments of proved properties in the United States ($38 million), partially offset by decreased amortization of unproved property costs in the United States ($17 million).  EOG recorded impairments of proved properties of $48 million and $11 million for the first quarter of 2011 and 2010, respectively.

 

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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.

Taxes other than income for the first quarter of 2011 increased $31 million to $106 million (7.1% of wellhead revenues) compared to $75 million (6.4% of wellhead revenues) for the same prior year period.  The increase in taxes other than income was primarily due to increased severance/production taxes as a result of increased wellhead revenues in the United States ($20 million) and Trinidad ($3 million), increased severance/production taxes as a result of increased crude oil production in Canada ($3 million) and a decrease in credits available to EOG in 2011 for Texas high-cost gas severance tax rate reductions as a result of fewer wells qualifying for such credit ($3 million).

Income tax provision of $92 million for the first quarter of 2011 increased $13 million compared to the same prior year period primarily due to higher pretax income.  The net effective tax rate for the first quarter of 2011 increased to 41% from 40% for the first quarter of 2010.

Capital Resources and Liquidity

Cash Flow.   The primary sources of cash for EOG during the three months ended March 31, 2011 were funds generated from operations, net proceeds from the sale of Common Stock previously discussed, proceeds from asset sales and proceeds from stock options exercised. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; and dividend payments to stockholders.  During the first three months of 2011, EOG's cash balance increased $879 million to $1,668 million from $789 million at December 31, 2010.

Net cash provided by operating activities of $957 million for the first three months of 2011 increased $337 million compared to the same period of 2010 primarily reflecting an increase in wellhead revenues ($304 million), favorable changes in working capital and other assets and liabilities ($60 million) and a decrease in cash paid for income taxes ($39 million), partially offset by an increase in cash operating expenses ($93 million) and an increase in net cash paid for interest expense ($15 million).

Net cash used in investing activities of $1,428 million for the first three months of 2011 increased by $388 million compared to the same period of 2010 due primarily to an increase in additions to oil and gas properties ($464 million); an increase in additions to other property, plant and equipment ($98 million); and unfavorable changes in working capital associated with investing activities ($75 million); partially offset by an increase in proceeds from sales of assets ($256 million).

Net cash provided by financing activities of $1,350 million for the first three months of 2011 included net proceeds from the sale of Common Stock ($1,388 million) and proceeds from stock options exercised ($17 million).  Cash used in financing activities for the first three months of 2011 included cash dividend payments ($39 million) and the purchase of treasury stock in connection with stock compensation plans ($15 million).  Net cash used in financing activities of $36 million for the first three months of 2010 included cash dividend payments ($36 million) and the purchase of treasury stock in connection with stock compensation plans ($5 million).  Cash provided by financing activities for the first three months of 2010 included proceeds from stock options exercised ($5 million).

 

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Total Expenditures.   For 2011, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $6.4 billion to $6.6 billion, excluding acquisitions.  The table below sets out components of total expenditures for the three-month periods ended March 31, 2011 and 2010 (in millions):

		Three Months Ended
		March 31,
		2011				2010
Expenditure Category
Capital
Drilling and Facilities		$	1,408			$	868
Leasehold Acquisitions			78				141
Property Acquisitions			1				17
Capitalized Interest			16				18
Subtotal			1,503				1,044
Exploration Costs			51				51
Dry Hole Costs			23				23
Exploration and Development Expenditures			1,577				1,118
Asset Retirement Costs			8				6
Total Exploration and Development Expenditures			1,585				1,124
Other Property, Plant and Equipment			160				61
Total Expenditures		$	1,745			$	1,185

Exploration and development expenditures of $1,577 million for the first three months of 2011 were $459 million higher than the same period of 2010 due primarily to increased drilling and facilities expenditures in the United States ($524 million), partially offset by decreased leasehold acquisition expenditures in the United States ($54 million) and decreased property acquisitions in the United States ($16 million).  The exploration and development expenditures for the first three months of 2011 of $1,577 million include $1,406 million in development, $154 million in exploration, $16 million in capitalized interest and $1 million in property acquisitions.  The exploration and development expenditures for the first three months of 2010 of $1,118 million include $797 million in development, $286 million in exploration, $18 million in capitalized interest and $17 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 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.

Commodity Derivative Transactions.   As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2010 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 crude oil and natural gas.  EOG utilizes financial commodity derivative instruments, primarily price swap, collar 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 (Losses) Gains on Mark-to-Market Commodity Derivative Contracts in the Consolidated Statements of Income.  The related cash flow impact is reflected as Cash Flows from Operating Activities.  In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions.  The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

 

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Financial Price Swap Contracts.   The total fair value of EOG's crude oil and natural gas financial price swap contracts was reflected on the Consolidated Balance Sheets at March 31, 2011 as a liability of $98 million and an asset of $53 million, respectively.  Presented below is a comprehensive summary of EOG's crude oil and natural gas financial price swap contracts at May 5, 2011, with notional volumes expressed in barrels per day (Bbld) and in million British thermal units per day (MMBtud) and prices expressed in dollars per barrel ($/Bbl) and in dollars per million British thermal units ($/MMBtu), as applicable.

Financial Price Swap Contracts
		Crude Oil								Natural Gas
		Volume (Bbld)				Weighted Average Price ($/Bbl)				Volume (MMBtud)				Weighted Average Price ($/MMBtu)
2011 (1)
January 2011 (closed)			17,000			$	90.44				275,000			$	5.19
February 2011 (closed)			18,000				90.69				425,000				5.09
March 2011 (closed)			20,000				91.82				425,000				5.09
April 2011 (closed)			24,000				93.61				475,000				5.03
May 2011 (2)			24,000				93.61				650,000				4.90
June 1, 2011 through December 31, 2011			30,000				97.02				650,000				4.90
2012 (3)
January 1, 2012 through December 31, 2012			9,000			$	107.12				525,000			$	5.44

(1)

EOG has entered into natural gas financial price swap contracts which give counterparties the option of entering into price swap contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas financial price swap contracts will increase by 500,000 MMBtud at an average price of $4.73 per million British thermal units (MMBtu) for the period from June 1, 2011 through December 31, 2011.

(2)	The crude oil contracts for May 2011 will close on May 31, 2011.  The natural gas contracts for May 2011 are closed.

(3)

EOG has entered into natural gas financial price swap contracts which give counterparties the option of entering into price swap contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas financial price swap contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for each month of 2012.

 

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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, and demand for, crude oil, natural gas and related commodities;

·	the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

·	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 crude oil and natural gas exploration and development projects, given the risks and uncertainties inherent in drilling, completing and operating crude oil and natural gas wells and the potential for interruptions of development and production, whether involuntary or intentional as a result of market or other conditions;

·	the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;

·	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;

·

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal and hydraulic fracturing and laws and regulations imposing conditions and restrictions on drilling and completion operations;

·	EOG's ability to effectively integrate acquired crude oil and natural gas 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;

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

·	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;

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

·	weather, including its impact on crude oil and natural gas 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;

 

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

·	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 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 20 of EOG's Annual Report on Form 10-K for the year ended December 31, 2010.

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 41 through 45 of EOG's Annual Report on Form 10-K for the year ended December 31, 2010, filed on February 24, 2011 (EOG's 2010 Annual Report); and (ii) Note 11, "Risk Management Activities," to EOG's Consolidated Financial Statements on pages F-26 through F-29 of EOG's 2010 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.

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

The following table sets forth, for the periods indicated, EOG Resources, Inc.'s (EOG) 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)
January 1, 2011 – January 31, 2011			8,898			$	100.48				-				6,386,200
February 1, 2011 – February 28, 2011			11,546				109.28				-				6,386,200
March 1, 2011 – March 31, 2011			137,925				113.49				-				6,386,200
Total			158,369				112.45				-

(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 of EOG's Board of Directors (Board) discussed below.

(2)	In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock.  During the first quarter of 2011, EOG did not repurchase any shares under the Board-authorized repurchase program.

 

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ITEM 6.    EXHIBITS

Exhibit No.                                     Description

*      10.1	-	Executive Employment Agreement between EOG and William R. Thomas, effective as of February 1, 2011.
*      10.2	-	Change of Control Agreement between EOG and William R. Thomas, effective as of January 12, 2011.
*      10.3	-	Form of Stock Option Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (effective for grants made beginning February 23, 2011).
*      10.4	-	Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (effective for grants made beginning February 23, 2011).
*      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.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 March 31, 2011 and 2010, (ii) the Consolidated Balance Sheets - March 31, 2011 and December 31, 2010, (iii) the Consolidated Statements of Cash Flows - Three Months Ended March 31, 2011 and 2010 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: May 5, 2011	By:	/s/ TIMOTHY K. DRIGGERS                                                          Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

 

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EXHIBIT INDEX

Exhibit No.                                     Description

*      10.1	-	Executive Employment Agreement between EOG and William R. Thomas, effective as of February 1, 2011.
*      10.2	-	Change of Control Agreement between EOG and William R. Thomas, effective as of January 12, 2011.
*      10.3	-	Form of Stock Option Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (effective for grants made beginning February 23, 2011).
*      10.4	-	Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (effective for grants made beginning February 23, 2011).
*      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.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 March 31, 2011 and 2010, (ii) the Consolidated Balance Sheets - March 31, 2011 and December 31, 2010, (iii) the Consolidated Statements of Cash Flows - Three Months Ended March 31, 2011 and 2010 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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