EOG 10-Q Quarterly Report March 31, 2012

EOG RESOURCES INC

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10-Q 1 eog1qtr10-q.htm EOG FORM 10-Q eog1qtr10-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 March 31, 2012

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	269,594,283 (as of May 1, 2012)

EOG RESOURCES, INC.

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements (Unaudited)

		Consolidated Statements of Income and Comprehensive Income - Three Months Ended March 31, 2012 and 2011	3

		Consolidated Balance Sheets - March 31, 2012 and December 31, 2011	4

		Consolidated Statements of Cash Flows - Three Months Ended March 31, 2012 and 2011	5

		Notes to Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	18

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	30

	ITEM 4.	Controls and Procedures	30

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	31

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31

	ITEM 4.	Mine Safety Disclosures	31

	ITEM 5.	Other Information	31

	ITEM 6.	Exhibits	33

SIGNATURES			34

EXHIBIT INDEX			35

- 2 -

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In Thousands, Except Per Share Data)

(Unaudited)

	Three Months Ended
	March 31,
	2012			2011
Net Operating Revenues
Crude Oil and Condensate	$	1,310,335		$	757,362
Natural Gas Liquids		198,310			148,727
Natural Gas		367,284			583,919
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		134,208			(66,746	)
Gathering, Processing and Marketing		718,157			395,583
Gains on Asset Dispositions, Net		67,468			71,742
Other, Net		10,889			6,519
Total		2,806,651			1,897,106
Operating Expenses
Lease and Well		261,495			215,089
Transportation Costs		131,842			97,633
Gathering and Processing Costs		25,592			19,196
Exploration Costs		42,807			50,909
Dry Hole Costs		-			22,951
Impairments		133,147			89,328
Marketing Costs		705,468			385,409
Depreciation, Depletion and Amortization		748,743			568,226
General and Administrative		76,269			70,037
Taxes Other Than Income		121,516			105,877
Total		2,246,879			1,624,655
Operating Income		559,772			272,451
Other Income, Net		10,631			3,604
Income Before Interest Expense and Income Taxes		570,403			276,055
Interest Expense, Net		50,269			50,333
Income Before Income Taxes		520,134			225,722
Income Tax Provision		196,125			91,749
Net Income	$	324,009		$	133,973
Net Income Per Share
Basic	$	1.22		$	0.52
Diluted	$	1.20		$	0.52
Dividends Declared per Common Share	$	0.17		$	0.16
Average Number of Common Shares
Basic		266,674			255,200
Diluted		270,242			258,819

Comprehensive Income
Net Income	$	324,009		$	133,973
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		26,525			43,842
Foreign Currency Swap		2,061			659
Income Tax Related to Foreign Currency Swap		(527	)		(164	)
Interest Rate Swap		(595	)		1,604
Income Tax Related to Interest Rate Swap		214			(578	)
Other		27			30
Other Comprehensive Income		27,705			45,393
Comprehensive Income	$	351,714		$	179,366

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

- 3 -

EOG RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Data)

(Unaudited)

	March 31,			December 31,
	2012			2011
ASSETS
Current Assets
Cash and Cash Equivalents	$	294,064		$	615,726
Accounts Receivable, Net		1,543,491			1,451,227
Inventories		561,512			590,594
Assets from Price Risk Management Activities		451,399			450,730
Income Taxes Receivable		24,593			26,609
Other		166,974			119,052
Total		3,042,033			3,253,938

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		35,092,346			33,664,435
Other Property, Plant and Equipment		2,277,035			2,149,989
Total Property, Plant and Equipment		37,369,381			35,814,424
Less: Accumulated Depreciation, Depletion and Amortization		(15,235,540	)		(14,525,600	)
Total Property, Plant and Equipment, Net		22,133,841			21,288,824
Other Assets		379,662			296,035
Total Assets	$	25,555,536		$	24,838,797


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,289,903		$	2,033,615
Accrued Taxes Payable		123,391			147,105
Dividends Payable		45,333			42,578
Liabilities from Price Risk Management Activities		25,787			-
Deferred Income Taxes		122,833			135,989
Other		165,100			163,032
Total		2,772,347			2,522,319

Long-Term Debt		5,010,523			5,009,166
Other Liabilities		790,416			799,189
Deferred Income Taxes		3,990,407			3,867,219
Commitments and Contingencies (Note 8)

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 269,967,577 Shares Issued at March 31, 2012 and 269,323,084 Shares Issued at December 31, 2011		202,700			202,693
Additional Paid in Capital		2,328,435			2,272,052
Accumulated Other Comprehensive Income		429,451			401,746
Retained Earnings		10,067,541			9,789,345
Common Stock Held in Treasury, 386,828 Shares at March 31, 2012 and 303,633 Shares at December 31, 2011		(36,284	)		(24,932	)
Total Stockholders' Equity		12,991,843			12,640,904
Total Liabilities and Stockholders' Equity	$	25,555,536		$	24,838,797

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

- 4 -

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2012			2011
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	324,009		$	133,973
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		748,743			568,226
Impairments		133,147			89,328
Stock-Based Compensation Expenses		28,338			27,430
Deferred Income Taxes		110,148			31,290
Gains on Asset Dispositions, Net		(67,468	)		(71,742	)
Other, Net		446			2,523
Dry Hole Costs		-			22,951
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		(134,208	)		66,746
Realized Gains		133,601			24,937
Excess Tax Benefits from Stock-Based Compensation		(16,651	)		-
Other, Net		3,352			6,219
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(89,948	)		(113,855	)
Inventories		10,208			(67,733	)
Accounts Payable		236,625			165,497
Accrued Taxes Payable		(5,163	)		79,748
Other Assets		(108,840	)		(18,656	)
Other Liabilities		(5,059	)		8,621
Changes in Components of Working Capital Associated with Investing and Financing Activities		(223,675	)		1,985
Net Cash Provided by Operating Activities		1,077,605			957,488

Investing Cash Flows
Additions to Oil and Gas Properties		(1,878,813	)		(1,527,854	)
Additions to Other Property, Plant and Equipment		(170,704	)		(159,794	)
Proceeds from Sales of Assets		450,110			260,107
Changes in Components of Working Capital Associated with Investing Activities		224,087			(206	)
Net Cash Used in Investing Activities		(1,375,320	)		(1,427,747	)

Financing Cash Flows
Common Stock Sold		-			1,388,211
Dividends Paid		(43,250	)		(39,003	)
Excess Tax Benefits from Stock-Based Compensation		16,651			-
Treasury Stock Purchased		(20,072	)		(14,981	)
Proceeds from Stock Options Exercised		20,198			17,363
Other, Net		(412	)		(1,779	)
Net Cash (Used in) Provided by Financing Activities		(26,885	)		1,349,811

Effect of Exchange Rate Changes on Cash		2,938			(120	)

(Decrease) Increase in Cash and Cash Equivalents		(321,662	)		879,432
Cash and Cash Equivalents at Beginning of Period		615,726			788,853
Cash and Cash Equivalents at End of Period	$	294,064		$	1,668,285

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

- 5 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	Summary of Significant Accounting Policies

General. The consolidated financial statements of EOG Resources, Inc., together with its subsidiaries (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, 2011, filed on February 24, 2012 (EOG's 2011 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, 2012 are not necessarily indicative of the results to be expected for the full year.

Recently Issued Accounting Standards. In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, "Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs". ASU 2011-04 amends the Fair Value Measurement Topic of the Accounting Standards Codification (ASC) to clarify the FASB's intent about the application of existing fair value measurement requirements and change certain principles or requirements for measuring fair value or disclosing information about fair value measurements. ASU 2011-04 became effective for interim and annual fiscal periods beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material impact on EOG's financial statements.

In June 2011, the FASB issued ASU 2011-05 "Comprehensive Income (Topic 220): Presentation of Comprehensive Income." ASU 2011-05 is intended to increase the prominence of comprehensive income in the financial statements by requiring that an entity that reports items of comprehensive income do so in either one continuous or two consecutive financial statements. ASU 2011-05 also requires separate presentation on the face of the financial statements for items reclassified from other comprehensive income into net income. Subsequently, in December 2011, the FASB deferred the effective date of the provisions of ASU 2011-05 relating to the presentation of reclassification adjustments out of accumulated other comprehensive income. The provisions of ASU 2011-05 not deferred by the FASB became effective for interim and annual fiscal periods beginning after December 15, 2011. Retroactive application is required. The adoption of ASU 2011-05 did not have a material impact on EOG's financial statements.

- 6 -

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 2011 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included in the Consolidated Statements of Income and Comprehensive Income based upon job functions of the employees receiving the grants as follows (in millions):

	Three Months Ended
	March 31,
	2012		2011

Lease and Well	$	8.5	$	7.7
Gathering and Processing Costs		0.2		0.2
Exploration Costs		6.6		6.1
General and Administrative		13.0		13.4
Total	$	28.3	$	27.4

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, 2012, approximately 4.9 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 Plan from either previously authorized unissued shares or treasury shares to the extent treasury shares are available.

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 $10.9 million and $9.4 million during the three months ended March 31, 2012 and 2011, 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, 2012 and 2011 are as follows:

	Stock Options/SARs						ESPP
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2012			2011			2012			2011

Weighted Average Fair Value of Grants	$	37.97		$	34.20		$	28.24		$	21.55
Expected Volatility		41.11	%		36.77	%		46.42	%		30.26	%
Risk-Free Interest Rate		0.49	%		1.18	%		0.06	%		0.18	%
Dividend Yield		0.6	%		0.6	%		0.6	%		0.6	%
Expected Life	5.6 yrs.			5.5 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.

- 7 -

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, 2012 and 2011 (stock options and SARs in thousands):

	Three Months Ended					Three Months Ended
	March 31, 2012					March 31, 2011
				Weighted					Weighted
	Number of			Average		Number of			Average
	Stock			Grant		Stock			Grant
	Options/SARs			Price		Options/SARs			Price

Outstanding at January 1		8,374		$	70.01		8,445		$	64.49
Granted		20			107.99		16			101.30
Exercised (1)		(656	)		63.99		(857	)		50.15
Forfeited		(36	)		87.99		(49	)		86.73
Outstanding at March 31 (2)		7,702		$	70.54		7,555		$	66.05

Vested or Expected to Vest (3)		7,456		$	69.98		7,323		$	65.36

Exercisable at March 31 (4)		4,594		$	59.20		4,601		$	52.12

(1)

The total intrinsic value of stock options/SARs exercised for the three months ended March 31, 2012 and 2011 was $32.4 million and $51.1 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, 2012 and 2011 was $313.3 million and $396.8 million, respectively. At March 31, 2012 and 2011, the weighted average remaining contractual life was 3.5 years and 3.8 years, respectively.

(3)	The total intrinsic value of stock options/SARs vested or expected to vest at March 31, 2012 and 2011 was $307.5 million and $389.6 million, respectively. At March 31, 2012 and 2011, the weighted average remaining contractual life was 3.5 years and 3.7 years, respectively.

(4)	The total intrinsic value of stock options/SARs exercisable at March 31, 2012 and 2011 was $239.1 million and $305.8 million, respectively. At March 31, 2012 and 2011, the weighted average remaining contractual life was 2.2 years and 2.6 years, respectively.

At March 31, 2012, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $79.8 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 $17.4 million and $18.0 million for the three months ended March 31, 2012 and 2011, respectively.

- 8 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth the restricted stock and restricted stock unit transactions for the three-month periods ended March 31, 2012 and 2011 (shares and units in thousands):

	Three Months Ended					Three Months Ended
	March 31, 2012					March 31, 2011
				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		4,240		$	82.93		4,009		$	79.13
Granted		271			112.53		266			105.65
Released (1)		(466	)		70.13		(182	)		67.27
Forfeited		(36	)		88.18		(48	)		78.30
Outstanding at March 31 (2)		4,009		$	86.36		4,045		$	81.42

(1)

The total intrinsic value of restricted stock and restricted stock units released for the three months ended March 31, 2012 and 2011 was $53.1 million and $19.3 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 March 31, 2012 and 2011 was $445.4 million and $479.4 million, respectively.

At March 31, 2012, unrecognized compensation expense related to restricted stock and restricted stock units totaled $142.5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.6 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, 2012 and 2011 (in thousands, except per share data):

	Three Months Ended
	March 31,
	2012		2011

Numerator for Basic and Diluted Earnings Per Share -
Net Income	$	324,009	$	133,973

Denominator for Basic Earnings Per Share -
Weighted Average Shares		266,674		255,200
Potential Dilutive Common Shares -
Stock Options/SARs		1,800		1,937
Restricted Stock and Restricted Stock Units		1,768		1,682
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares		270,242		258,819

Net Income Per Share
Basic	$	1.22	$	0.52
Diluted	$	1.20	$	0.52

- 9 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 0.1 million and 0.2 million shares for the three months ended March 31, 2012 and 2011, respectively.

4. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the three-month periods ended March 31, 2012 and 2011 (in thousands):

	Three Months Ended
	March 31,
	2012		2011

Interest (1)	$	33,504	$	19,912
Income Taxes, Net of Refunds Received	$	83,955	$	9,820

(1)	Net of capitalized interest of $12 million and $16 million for the three months ended March 31, 2012 and 2011, respectively.

EOG's accrued capital expenditures at March 31, 2012 and 2011 were $880 million and $779 million, respectively.

5.	Segment Information

Selected financial information by reportable segment is presented below for the three-month periods ended March 31, 2012 and 2011 (in thousands):

	Three Months Ended
	March 31,
	2012			2011
Net Operating Revenues
United States	$	2,591,341		$	1,627,598
Canada		88,070			115,963
Trinidad		121,070			145,888
Other International (1)		6,170			7,657
Total	$	2,806,651		$	1,897,106

Operating Income (Loss)
United States	$	530,951		$	209,886
Canada		(38,584	)		(19,436	)
Trinidad		77,213			91,200
Other International (1)		(9,808	)		(9,199	)
Total		559,772			272,451

Reconciling Items
Other Income, Net		10,631			3,604
Interest Expense, Net		50,269			50,333
Income Before Income Taxes	$	520,134		$	225,722

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

- 10 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Total assets by reportable segment are presented below at March 31, 2012 and December 31, 2011 (in thousands):

	At		At
	March 31,		December 31,
	2012		2011
Total Assets
United States	$	22,112,317	$	21,313,158
Canada		2,141,217		2,131,949
Trinidad		1,001,172		1,085,664
Other International (1)		300,830		308,026
Total	$	25,555,536	$	24,838,797

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

6.	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, 2012 and 2011 (in thousands):

	Three Months Ended
	March 31,
	2012			2011

Carrying Amount at Beginning of Period	$	587,084		$	498,288
Liabilities Incurred		10,873			5,959
Liabilities Settled (1)		(25,347	)		(14,078	)
Accretion		7,751			6,166
Revisions		5			748
Foreign Currency Translations		3,078			2,158
Carrying Amount at End of Period	$	583,444		$	499,241

Current Portion	$	42,457		$	33,315
Noncurrent Portion	$	540,987		$	465,926

(1) Includes settlements related to asset sales.

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.

- 11 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

7.	Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the three-month period ended March 31, 2012 are presented below (in thousands):

	Three Months Ended
	March 31, 2012

Balance at December 31, 2011	$	61,111
Additions Pending the Determination of Proved Reserves		51,164
Reclassifications to Proved Properties		(116	)
Charged to Dry Hole Costs		-
Foreign Currency Translations		1,074
Balance at March 31, 2012	$	113,233

The following table provides an aging of capitalized exploratory well costs at March 31, 2012 (in thousands, except well count):

	At
	March 31,
	2012

Capitalized exploratory well costs that have been capitalized for a period less than one year	$	68,173
Capitalized exploratory well costs that have been capitalized for a period greater than one year		45,060	(1)
Total	$	113,233
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.) ($20 million), a project in the Sichuan Basin, Sichuan Province, China ($10 million), an East Irish Sea project in the U.K. ($9 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 submitted a revised field development plan to the U.K. Department of Energy and Climate Change (DECC) during the second quarter of 2011 and anticipates receiving approval of this plan during the first half of 2012. The evaluation of the Sichuan Basin project is expected to be completed by the end of 2012. In the East Irish Sea project, EOG received DECC regulatory approval of its field development plan in March 2012. Fabrication of facilities and pipelines is progressing. EOG expects to begin facility and pipeline installation in the second half of 2012. The drilling of development wells is expected to commence at the beginning of 2013, with initial production expected in the second half of 2013. In the B.C. shale project, EOG drilled three wells during the first quarter of 2012 and expects to drill four additional wells by the end of the first half of 2012 to retain land and further evaluate the project. The related well completion activities are not expected to commence until 2013 or later.

8.	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, 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.

- 12 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

9.	Pension and Postretirement Benefits

EOG has defined contribution pension plans in place for most of its employees in the United States, Canada, Trinidad and the United Kingdom, and defined benefit pension plans covering certain employees of its Canadian and Trinidadian subsidiaries. For the three months ended March 31, 2012 and 2011, EOG's total costs recognized for these pension plans were $10.9 million and $7.7 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.

10. Long-Term Debt and Common Stock

Long-Term Debt. During the three months ended March 31, 2012 and 2011, EOG utilized commercial paper, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding borrowings from commercial paper issuances at March 31, 2012. The average of the borrowings outstanding under the commercial paper program was $59 million during the three months ended March 31, 2012. The weighted average interest rate for commercial paper borrowings for the three months ended March 31, 2012 was 0.38%.

EOG currently has a $2.0 billion unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The Agreement matures on October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the Banks holding greater than 50% of the commitments then outstanding under the Agreement. At March 31, 2012, 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 (LIBOR) plus an applicable margin (Eurodollar rate), or the base rate (as defined in the Agreement) plus an applicable margin. At March 31, 2012, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.12% and 3.25%, respectively.

Common Stock. On February 16, 2012, EOG's Board of Directors increased the quarterly cash dividend on the Common Stock from the previous $0.16 per share to $0.17 per share, effective with the dividend paid on April 30, 2012 to stockholders of record as of April 16, 2012.

- 13 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

11.	Fair Value Measurements

As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2011 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, 2012 and December 31, 2011 (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, 2012
Financial Assets:
Natural Gas Derivative Contracts	$	-	$	80	$	-	$	80
Natural Gas Options/Swaptions		-		432		-		432

Financial Liabilities:
Crude Oil Derivative Contracts	$	-	$	4	$	-	$	4
Crude Oil Options/Swaptions		-		22		-		22
Foreign Currency Rate Swap		-		54		-		54
Interest Rate Swap		-		4		-		4

At December 31, 2011
Financial Assets:
Crude Oil and Natural Gas Derivative Contracts	$	-	$	110	$	-	$	110
Crude Oil and Natural Gas Options/Swaptions		-		376		-		376

Financial Liabilities:
Foreign Currency Rate Swap	$	-	$	52	$	-	$	52
Interest Rate Swap		-		3		-		3

The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) and the interest rate swap 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.

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 property, plant and equipment. 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 6.

- 14 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Proved oil and gas properties and other property, plant and equipment with a carrying amount of $120 million were written down to their fair value of $45 million, resulting in a pretax impairment charge of $75 million for the three months ended March 31, 2012. Included in the $75 million pretax impairment charge is a $58 million impairment of proved oil and gas properties and other property, plant and equipment, for which EOG utilized an accepted offer from a third-party as the basis for determining fair value. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

Fair Value of Debt. At both March 31, 2012 and December 31, 2011, EOG had outstanding $5,040 million aggregate principal amount of debt, which had estimated fair values of approximately $5,644 million and $5,657 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at the end of each respective period.

12.	Risk Management Activities

Commodity Price Risk . As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2011 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, option 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. These physical commodity contracts qualify for the normal purchases and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at March 31, 2012, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

Crude Oil Derivative Contracts
			Weighted
	Volume		Average Price
	(Bbld)		($/Bbl)
2012 (1)
January 1, 2012 through February 29, 2012 (closed)		34,000	$	104.95
March 2012 (closed)		52,000		105.80
April 1, 2012 through June 30, 2012		52,000		105.80
July 1, 2012 through August 31, 2012		35,000		105.56
September 1, 2012 through December 31, 2012		17,000		103.59

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period. Options covering a notional volume of 17,000 Bbld are exercisable on June 29, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 17,000 Bbld at an average price of $106.31 per barrel for the period July 1, 2012 through December 31, 2012. Options covering a notional volume of 18,000 Bbld are exercisable on August 31, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 18,000 Bbld at an average price of $107.42 per barrel for the period September 1, 2012 through February 28, 2013.

- 15 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at March 31, 2012, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Derivative Contracts
	Volume (MMBtud)		Weighted Average Price ($/MMBtu)
2012 (1)
January 2012 through April 30, 2012 (closed)		525,000	$	5.44
May 1, 2012 through December 31, 2012		525,000	$	5.44

2013 (2)
January 1, 2013 through December 31, 2013		150,000	$	4.79

2014 (2)
January 1, 2014 through December 31, 2014		150,000	$	4.79

(1)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from May 1, 2012 through December 31, 2012.

(2)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2013 and 2014.

Foreign Currency Exchange Rate Derivative. EOG is party to a foreign currency aggregate swap 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 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 resulted in an increase in Other Comprehensive Income (OCI) of $1.5 million and $0.5 million for the three months ended March 31, 2012 and 2011, respectively.

Interest Rate Derivative. EOG is a party to an interest rate swap with a counterparty bank. The interest rate swap was entered into in order to mitigate EOG's exposure to volatility in interest rates related to EOG's $350 million principal amount of Floating Rate Senior Notes due 2014. The interest rate swap has a notional amount of $350 million. EOG accounts for the interest rate swap using the hedge accounting method. Changes in the fair value of the interest rate swap do not impact Net Income. The after-tax impact from the interest rate swap resulted in a decrease in OCI of $0.4 million and an increase in OCI of $1.0 million for the three months ended March 31, 2012 and 2011, respectively.

- 16 -

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)

(Unaudited)

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding derivative financial instruments at March 31, 2012 and December 31, 2011. Certain amounts may be presented on a net basis on 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	2012		2011

Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities	$	441	$	451
Current portion	Assets from Price Risk Management Activities	$	441	$	451
Noncurrent portion	Other Assets	$	71	$	35

Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities	$	26	$	-

Foreign currency swap - Noncurrent portion	Other Liabilities	$	54	$	52

Interest rate swap - Noncurrent portion	Other Liabilities	$	4	$	3

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 11). 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 (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 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 11 for the aggregate fair value of all derivative instruments that are in a net liability position at March 31, 2012 and December 31, 2011. EOG had no collateral posted at both March 31, 2012 and December 31, 2011 and held collateral of $78 million and $67 million at March 31, 2012 and December 31, 2011, respectively.

13. Divestitures

During the first quarter of 2012, EOG received proceeds of approximately $450 million from the sales of producing properties and acreage, primarily in the Upper Gulf Coast area, the Rocky Mountain area and the Permian Basin.

- 17 -

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 have 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 and completion expertise gained from its natural gas resource plays to unconventional crude oil and liquids-rich reservoirs. In 2012, EOG continues to focus its efforts on developing its existing North American crude oil and condensate and liquids-rich acreage. In addition, EOG continues to evaluate certain potential liquids-rich exploration and development prospects. For the first quarter of 2012, crude oil and condensate and natural gas liquids production accounted for approximately 43% of total company production as compared to 32% for the comparable period in 2011. In North America, crude oil and condensate and natural gas liquids production accounted for approximately 49% of total North American production during the first quarter of 2012 as compared to 37% for the comparable period in 2011. This liquids growth primarily reflects increased production from the Eagle Ford Shale near San Antonio, Texas, and the Fort Worth Basin Barnett Shale area. Based on current trends, EOG expects its 2012 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 2011. EOG delivers its crude oil to various markets in the United States, including sales points on the Gulf Coast. Most recently, with increases in crude oil production from the Eagle Ford Shale, EOG has increased sales to the Gulf Coast and is receiving pricing for those sales based on the Light Louisiana Sweet price. In order to access more diverse markets for its crude-by-rail shipments, EOG completed the construction of a crude oil unloading facility in St. James, Louisiana, where sales are based upon the Light Louisiana Sweet crude oil index. This facility, which received the first unit train of EOG crude oil in April 2012, has a capacity of approximately 100 thousand barrels per day (MBbld) and is able to accommodate multiple trains at a single time.

As previously reported, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), holds a 30% interest in both the planned liquefied natural gas 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) which is intended to link Western Canada's natural gas producing regions to the Kitimat LNG Terminal. An affiliate of Apache Corporation is the operator of both PTP and the Kitimat LNG Terminal. The front-end engineering and design study is expected to be delivered in the second half of 2012, and EOG expects to make a final investment decision at the beginning of 2013.

EOG's major producing areas in the United States and Canada are in Louisiana, New Mexico, North Dakota, Pennsylvania, Texas, Utah, Wyoming and western Canada.

- 18 -

International. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium Block, Modified U(a) Block and Modified U(b) Block, as well as the Pelican Field, have been developed and are producing natural gas and crude oil and condensate. In Block 4(a), production from the six wells in the Toucan Field and one in the EMZ Area began in February 2012 to supply natural gas under a contract with the National Gas Company of Trinidad and Tobago.

In the United Kingdom, EOG continues to make progress in field development for its East Irish Sea Conwy/Corfe crude oil discovery and its Central North Sea Columbus natural gas discovery. The field development plan for the Conwy/Corfe project was approved by the U.K. Department of Energy and Climate Change in March 2012. Fabrication of facilities and pipelines is progressing. EOG expects to begin facility and pipeline installation in the second half of 2012. The drilling of development wells is expected to commence at the beginning of 2013, with initial production expected in the second half of 2013.

During the first quarter of 2012, EOG drilled a monitoring well targeting the Vaca Muerta oil shale in the Aguada del Chivato Block in the Neuquén Basin in Neuquén Province, Argentina. In addition, EOG drilled a horizontal well in this formation that it plans to complete in the second quarter of 2012. EOG is also participating in the drilling of a well in the Bajo de Toro Block, also targeting the Vaca Muerta oil shale. This well is expected to be completed in the second quarter of 2012.

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 where indigenous 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 28% at both March 31, 2012 and December 31, 2011. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

EOG's total anticipated 2012 capital expenditures are estimated to range from $7.4 billion to $7.6 billion, excluding acquisitions. The majority of 2012 expenditures will be focused on United States and Canada crude oil and liquids-rich gas drilling activity and, to a much 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 2012. EOG's business plan includes selling certain non-core assets in 2012 to partially cover the anticipated shortfall. In the first quarter of 2012, proceeds of approximately $450 million were received from the sale of producing properties and acreage, primarily in the Upper Gulf Coast area, the Rocky Mountain area and the Permian Basin. 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 facility 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.

- 19 -

Results of Operations

The following review of operations for the three months ended March 31, 2012 and 2011 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 2012, net operating revenues increased $910 million, or 48%, to $2,807 million from $1,897 million for the same period of 2011. 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 2012 increased $386 million, or 26%, to $1,876 million from $1,490 million for the same period of 2011. During the first quarter of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $134 million compared to net losses of $67 million for the same period of 2011. 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 2012 increased $322 million, or 82%, to $718 million from $396 million for the same period of 2011. Gains on asset dispositions, net, of $67 million for the first quarter of 2012 primarily consist of gains on asset dispositions in the Rocky Mountain area and Texas.

- 20 -

Wellhead volume and price statistics for the three-month periods ended March 31, 2012 and 2011 were as follows:

	Three Months Ended
	March 31,
	2012		2011

Crude Oil and Condensate Volumes (MBbld) (1)
United States		131.0		81.4
Canada		7.5		8.5
Trinidad		2.2		4.4
Other International (2)		0.1		0.1
Total		140.8		94.4

Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States	$	101.81	$	88.00
Canada		89.39		84.24
Trinidad		99.25		86.84
Other International (2)		107.15		85.57
Composite		101.12		87.61

Natural Gas Liquids Volumes (MBbld) (1)
United States		50.3		34.5
Canada		0.8		0.9
Total		51.1		35.4

Average Natural Gas Liquids Prices ($/Bbl) (3)
United States	$	42.49	$	46.63
Canada		50.88		47.11
Composite		42.62		46.65

Natural Gas Volumes (MMcfd) (1)
United States		1,062		1,134
Canada		105		143
Trinidad		369		385
Other International (2)		11		14
Total		1,547		1,676

Average Natural Gas Prices ($/Mcf) (3)
United States	$	2.46	$	4.10
Canada		2.45		3.67
Trinidad		2.98		3.20
Other International (2)		5.79		5.63
Composite		2.61		3.87

Crude Oil Equivalent Volumes (MBoed) (4)
United States		358.5		304.9
Canada		25.7		33.2
Trinidad		63.8		68.6
Other International (2)		1.8		2.4
Total		449.8		409.1

Total MMBoe (4)		40.9		36.8

(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.

- 21 -

Wellhead crude oil and condensate revenues for the first quarter of 2012 increased $553 million, or 73%, to $1,310 million from $757 million for the same period of 2011, due to an increase of 46 MBbld, or 49%, in wellhead crude oil and condensate deliveries ($378 million) and a higher composite average wellhead crude oil and condensate price ($175 million). The increase in deliveries primarily reflects increased production in the Eagle Ford Shale. EOG's composite average wellhead crude oil and condensate price for the first quarter of 2012 increased 15% to $101.12 per barrel compared to $87.61 per barrel for the same period of 2011.

Natural gas liquids revenues for the first quarter of 2012 increased $49 million, or 33%, to $198 million from $149 million for the same period of 2011, due to an increase of 16 MBbld, or 44%, in natural gas liquids deliveries ($68 million), partially offset by a lower composite average price ($19 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area and the Eagle Ford Shale. EOG's composite average natural gas liquids price for the first quarter of 2012 decreased 9% to $42.62 per barrel compared to $46.65 per barrel for the same period of 2011.

Wellhead natural gas revenues for the first quarter of 2012 decreased $217 million, or 37%, to $367 million from $584 million for the same period of 2011. The decrease was due to a lower composite average wellhead natural gas price ($178 million) and a decrease in natural gas deliveries ($39 million). EOG's composite average wellhead natural gas price for the first quarter of 2012 decreased 33% to $2.61 per Mcf compared to $3.87 per Mcf for the same period of 2011.

Natural gas deliveries for the first quarter of 2012 decreased 129 MMcfd, or 8%, to 1,547 MMcfd from 1,676 MMcfd for the same period of 2011. The decrease was primarily due to lower production in the United States (72 MMcfd), Canada (38 MMcfd) and Trinidad (16 MMcfd). The decrease in the United States was primarily attributable to asset sales that occurred subsequent to the first quarter of 2011 and decreased production in the Rocky Mountain area and Kansas, partially offset by increased production in Pennsylvania and Louisiana. The decrease in Canada was primarily due to decreased production in Alberta and the Horn River Basin area. The decrease in Trinidad was primarily attributable to a decrease in contractual deliveries.

During the first quarter of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $134 million compared to net losses of $67 million for the same period of 2011. During the first quarter of 2012, the net cash inflow related to settled crude oil and natural gas derivative contracts was $134 million compared to $25 million for the same period of 2011.

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, 2012 and 2011, 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 2012, 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 2012 totaled $13 million compared to $10 million for the same period of 2011, primarily as a result of increased crude oil marketing activities.

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Operating and Other Expenses. For the first quarter of 2012, operating expenses of $2,247 million were $622 million higher than the $1,625 million incurred during the first quarter of 2011. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended March 31, 2012 and 2011:

	Three Months Ended
	March 31,
	2012		2011

Lease and Well	$	6.37	$	5.82
Transportation Costs		3.21		2.64
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties		17.32		14.57
Other Property, Plant and Equipment		0.90		0.83
General and Administrative (G&A)		1.86		1.89
Interest Expense, Net		1.22		1.36
Total (1)	$	30.88	$	27.11

(1)	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 G&A for the three months ended March 31, 2012 compared to the same period of 2011 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 costs 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 and maintenance 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 and maintenance costs for wells producing crude oil are higher than operating and maintenance costs for wells producing natural gas.

Lease and well expenses of $261 million for the first quarter of 2012 increased $46 million from $215 million for the same prior year period primarily due to higher operating and maintenance costs in the United States ($40 million) and Canada ($3 million) and increased lease and well administrative expenses in the United States ($6 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 $132 million for the first quarter of 2012 increased $34 million from $98 million for the same prior year period primarily due to increased transportation costs in the Eagle Ford Shale.

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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.

DD&A expenses for the first quarter of 2012 increased $181 million to $749 million from $568 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first quarter of 2012 were $174 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 ($79 million), partially offset by a decrease in production in Canada ($15 million). DD&A rates increased due primarily to a proportional increase in production from higher-cost properties in the United States ($109 million) and Canada ($8 million), partially offset by a decrease in rates in Trinidad ($5 million).

DD&A expenses associated with other property, plant and equipment were $7 million higher than the same prior year period primarily due to oil and gas gathering assets placed in service in the Eagle Ford Shale.

G&A expenses of $76 million for the first quarter of 2012 increased $6 million from the same prior year period primarily due to higher employee-related costs.

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 $7 million to $26 million for the first quarter of 2012 compared to $19 million for the same prior year period. The increase primarily reflects increased activities in the Eagle Ford Shale.

Exploration costs of $43 million for the first quarter of 2012 decreased $8 million from $51 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States ($10 million) and decreased delay rentals in the United States ($2 million), partially offset by increased geological and geophysical expenditures in Canada ($3 million) and increased exploration administrative expenses in the United States ($2 million).

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties and other property, plant and equipment. 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 using the Income Approach as described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification. For certain natural gas assets held for sale, EOG utilized accepted bids as the basis for determining fair value.

Impairments of $133 million for the first quarter of 2012 were $44 million higher than impairments for the same prior year period primarily due to higher impairments of proved oil and gas properties and other assets in the United States. EOG recorded impairments of proved properties and other assets of $94 million and $48 million for the first quarter of 2012 and 2011, 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 2012 increased $16 million to $122 million (6.5% of wellhead revenues) compared to $106 million (7.1% 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 ($21 million) and increased ad valorem/property taxes in the United States ($3 million), partially offset by decreased severance/production taxes in Canada ($4 million) and Trinidad ($4 million) and increased credits available to EOG in 2012 for Texas high-cost gas severance tax rate reductions ($3 million).

Other income, net was $11 million for the first quarter of 2012 compared to $4 million for the same prior year period. The increase of $7 million was primarily due to higher interest income.

Income tax provision of $196 million for the first quarter of 2012 increased $104 million from $92 million in 2011 due primarily to greater pretax income. The net effective tax rate for the first quarter of 2012 decreased to 38% from 41% in the prior year period. The net effective tax rate for the first quarter of 2012 exceeded the United States statutory tax rate (35%) due mostly to foreign earnings in Trinidad (55% statutory tax rate) combined with losses in Canada (26% statutory tax rate).

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the three months ended March 31, 2012 were funds generated from operations, 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 2012, EOG's cash balance decreased $322 million to $294 million from $616 million at December 31, 2011.

Net cash provided by operating activities of $1,078 million for the first three months of 2012 increased $120 million compared to the same period of 2011 primarily reflecting an increase in wellhead revenues ($386 million) and a favorable change in the net cash flow from the settlement of financial commodity derivative contracts ($109 million), partially offset by unfavorable changes in working capital and other assets and liabilities ($140 million), an increase in cash operating expenses ($98 million), an increase in cash paid for income taxes ($74 million) and an increase in net cash paid for interest expense ($14 million).

Net cash used in investing activities of $1,375 million for the first three months of 2012 decreased by $52 million compared to the same period of 2011 due primarily to favorable changes in working capital associated with investing activities ($224 million) and an increase in proceeds from sales of assets ($190 million), partially offset by an increase in additions to oil and gas properties ($351 million) and an increase in additions to other property, plant and equipment ($11 million).

Net cash used in financing activities of $27 million for the first three months of 2012 included cash dividend payments ($43 million) and the purchase of treasury stock in connection with stock compensation plans ($20 million). Cash provided by financing activities for the first three months of 2012 included proceeds from stock options exercised ($20 million) and excess tax benefits from stock-based compensation ($17 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).

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Total Expenditures. For the year 2012, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $7.4 billion to $7.6 billion, excluding acquisitions. The table below sets out components of total expenditures for the three-month periods ended March 31, 2012 and 2011 (in millions):

	Three Months Ended
	March 31,
	2012		2011

Expenditure Category
Capital
Drilling and Facilities	$	1,717	$	1,408
Leasehold Acquisitions		150		78
Property Acquisitions		-		1
Capitalized Interest		12		16
Subtotal		1,879		1,503
Exploration Costs		43		51
Dry Hole Costs		-		23
Exploration and Development Expenditures		1,922		1,577
Asset Retirement Costs		12		8
Total Exploration and Development Expenditures		1,934		1,585
Other Property, Plant and Equipment		171		160
Total Expenditures	$	2,105	$	1,745

Exploration and development expenditures of $1,922 million for the first three months of 2012 were $345 million higher than the same period of 2011 due primarily to increased drilling and facilities expenditures in the United States ($354 million) and the United Kingdom ($23 million); and increased leasehold acquisition expenditures in the United States ($56 million) and Canada ($15 million); partially offset by decreased drilling and facilities expenditures in Canada ($54 million), Trinidad ($22 million) and China ($6 million); decreased dry hole costs in the United States ($23 million); and decreased exploration geological and geophysical expenditures in the United States ($10 million). The exploration and development expenditures for the first three months of 2012 of $1,922 million consist of $1,648 million in development, $262 million in exploration and $12 million in capitalized interest. The exploration and development expenditures for the first three months of 2011 of $1,577 million consist of $1,406 million in development, $154 million in exploration, $16 million in capitalized interest and $1 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 its operations, 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, 2011, filed on February 24, 2012, 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, option 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 (Losses) on Mark-to-Market Commodity Derivative Contracts in the Consolidated Statements of Income and Comprehensive 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.

Commodity Derivative Contracts. The total fair value of EOG's crude oil and natural gas derivative contracts was reflected on the Consolidated Balance Sheets at March 31, 2012 as a liability of $26 million and an asset of $512 million, respectively. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at May 8, 2012, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

Crude Oil Derivative Contracts
			Weighted
	Volume		Average Price
	(Bbld)		($/Bbl)
2012 (1)
January 1, 2012 through February 29, 2012 (closed)		34,000	$	104.95
March 1, 2012 through April 30, 2012 (closed)		52,000		105.80
May 1, 2012 through June 30, 2012		52,000		105.80
July 1, 2012 through August 31, 2012		50,000		106.90
September 1, 2012 through December 31, 2012		32,000		106.61

(1)

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Presented below is a comprehensive summary of EOG's natural gas derivative contracts at May 8, 2012, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Derivative Contracts
	Volume (MMBtud)		Weighted Average Price ($/MMBtu)
2012 (1)
January 1, 2012 through May 31, 2012 (closed)		525,000	$	5.44
June 1, 2012 through December 31, 2012		525,000	$	5.44

2013 (2)
January 1, 2013 through December 31, 2013		150,000	$	4.79

2014 (2)
January 1, 2014 through December 31, 2014		150,000	$	4.79

(1)

(2)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative 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 derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2013 and 2014.

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, generate income or cash flows or pay dividends 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 and condensate, natural gas liquids, 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, advanced completion technologies and hydraulic fracturing;

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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 and capital expenditure requirements 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, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

·	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;

·	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, and to otherwise satisfy its capital expenditure requirements;

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

·	the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;

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

·	the other factors described under Item 1A, "Risk Factors," on pages 15 through 23 of EOG's Annual Report on Form 10-K for the year ended December 31, 2011.

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 42 through 47 of EOG's Annual Report on Form 10-K for the year ended December 31, 2011, filed on February 24, 2012 (EOG's 2011 Annual Report); and (ii) Note 11, "Risk Management Activities," to EOG's Consolidated Financial Statements on pages F-25 through F-28 of EOG's 2011 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 12 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 in the reports EOG 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 8 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, 2012 – January 31, 2012		8,725	$	104.02		-		6,386,200
February 1, 2012 – February 29, 2012		75,198		116.90		-		6,386,200
March 1, 2012 – March 31, 2012		92,887		112.40		-		6,386,200
Total		176,810		113.90		-

(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 million shares of EOG's common stock. During the first quarter of 2012, EOG did not repurchase any shares under the Board-authorized repurchase program.

ITEM 4. MINE SAFETY DISCLOSURES

The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this report.

ITEM 5. OTHER INFORMATION

Appointment of General Counsel. On May 3, 2012, EOG Resources, Inc. (EOG) announced the appointment of Michael P. Donaldson as Vice President, General Counsel and Corporate Secretary of EOG, effective May 3, 2012. Mr. Donaldson previously served as Deputy General Counsel and Corporate Secretary of EOG and succeeds Frederick J. "Rick" Plaeger, II (formerly Senior Vice President and General Counsel of EOG), who has advised EOG of his intention to transition towards retirement beginning May 3, 2012. Mr. Plaeger will continue with EOG in the role of Vice President, Government Relations, but will no longer be an executive officer of EOG.

EOG entered into an agreement with Mr. Plaeger to terminate his change of control agreement with EOG, effective May 3, 2012. EOG also entered into a change of control agreement with Mr. Donaldson, effective May 3, 2012, with terms substantially similar to EOG's other change of control agreements currently in effect.

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2012 Annual Meeting of Stockholders. The 2012 annual meeting of stockholders (Annual Meeting) of EOG was held on May 2, 2012 in Houston, Texas, for the following purposes: (i) to elect seven directors to hold office until EOG's 2013 annual meeting of stockholders and until their respective successors are duly elected and qualified; (ii) to ratify the appointment by the Audit Committee of EOG's Board of Directors (Board) of Deloitte & Touche LLP, independent registered public accounting firm, as EOG's auditors for the year ending December 31, 2012; (iii) to hold a non-binding advisory vote on the compensation of EOG's named executive officers; and (iv) to consider two stockholder proposals, if properly presented at the Annual Meeting. At the close of business on March 9, 2012, the record date for the Annual Meeting, there were 269,355,685 shares of EOG common stock issued, outstanding and entitled to vote.

Proxies for the Annual Meeting were solicited by the Board pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended, and there was no solicitation in opposition to the Board's nominees for director.

Each of the seven nominees for director was duly elected by EOG's stockholders, with votes as follows:

Nominee	Shares For	Shares Against	Shares Abstaining	Broker Non-Votes

George A. Alcorn	211,635,801	18,138,057	90,880	10,871,522
Charles R. Crisp	211,548,107	18,237,600	79,031	10,871,522
James C. Day	212,390,132	17,393,552	81,054	10,871,522
Mark G. Papa	224,937,813	4,800,092	126,833	10,871,522
H. Leighton Steward	212,285,054	17,496,166	83,518	10,871,522
Donald F. Textor	211,730,400	18,053,546	80,792	10,871,522
Frank G. Wisner	211,637,530	18,146,204	81,004	10,871,522

The appointment of Deloitte & Touche LLP, independent registered public accounting firm, as EOG's auditors for the year ending December 31, 2012, was ratified by EOG's stockholders by the following vote: 239,733,678 shares for; 865,110 shares against; and 137,472 shares abstaining. There were no broker non-votes submitted with respect to this proposal.

With respect to the non-binding advisory vote on the compensation of EOG's named executive officers as disclosed in EOG's 2012 proxy statement, the compensation of EOG's named executive officers was approved by EOG's stockholders by the following vote:

Shares For	Shares Against	Shares Abstaining	Broker Non-Votes

192,637,401	31,030,723	6,196,614	10,871,522

The two stockholder proposals, which were each properly presented at the Annual Meeting, received the following votes:

Proposal	Shares For	Shares Against	Shares Abstaining	Broker Non-Votes

Stockholder Proposal Concerning Accelerated Vesting of Executive Officer Stock Awards Upon a Change of Control	97,593,515	132,149,741	121,482	10,871,522

Stockholder Proposal Concerning Stock Retention Requirements for Executive Officers	52,996,832	176,272,573	595,333	10,871,522

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ITEM 6. EXHIBITS

Exhibit No. Description

10.1	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Adoption Agreement, originally dated as of December 16, 2008 (and as amended through February 24, 2012 (including an amendment to Item 7 thereof, effective January 1, 2012, with respect to the deferral of restricted stock units)) (formerly known as the EOG Resources, Inc. 1996 Deferral Plan) (incorporated by reference to Exhibit 10.2(b) to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2011) (originally filed as Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).

10.2	-	Agreement, dated as of February 21, 2012, by and between EOG and Mark G. Papa (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K, filed February 27, 2012).

10.3	-	Agreement, dated as of February 21, 2012, by and between EOG and William R. Thomas (incorporated by reference to Exhibit 10.2 to EOG's Current Report on Form 8-K, filed February 27, 2012).

10.4	-	Agreement, dated as of February 21, 2012, by and between EOG and Gary L. Thomas (incorporated by reference to Exhibit 10.3 to EOG's Current Report on Form 8-K, filed February 27, 2012).

10.5	-	Agreement, dated as of February 21, 2012, by and between EOG and Frederick J. Plaeger, II (incorporated by reference to Exhibit 10.4 to EOG's Current Report on Form 8-K, filed February 27, 2012).

* 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.

* 95	-	Mine Safety Disclosure Exhibit.

* **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 and Comprehensive Income - Three Months Ended March 31, 2012 and 2011, (ii) the Consolidated Balance Sheets - March 31, 2012 and December 31, 2011, (iii) the Consolidated Statements of Cash Flows - Three Months Ended March 31, 2012 and 2011 and (iv) Notes to Consolidated Financial Statements.

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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 8, 2012	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	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Adoption Agreement, originally dated as of December 16, 2008 (and as amended through February 24, 2012 (including an amendment to Item 7 thereof, effective January 1, 2012, with respect to the deferral of restricted stock units)) (formerly known as the EOG Resources, Inc. 1996 Deferral Plan) (incorporated by reference to Exhibit 10.2(b) to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2011) (originally filed as Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).

10.2	-	Agreement, dated as of February 21, 2012, by and between EOG and Mark G. Papa (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K, filed February 27, 2012).

10.3	-	Agreement, dated as of February 21, 2012, by and between EOG and William R. Thomas (incorporated by reference to Exhibit 10.2 to EOG's Current Report on Form 8-K, filed February 27, 2012).

10.4	-	Agreement, dated as of February 21, 2012, by and between EOG and Gary L. Thomas (incorporated by reference to Exhibit 10.3 to EOG's Current Report on Form 8-K, filed February 27, 2012).

10.5	-	Agreement, dated as of February 21, 2012, by and between EOG and Frederick J. Plaeger, II (incorporated by reference to Exhibit 10.4 to EOG's Current Report on Form 8-K, filed February 27, 2012).

* 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.

* 95	-	Mine Safety Disclosure Exhibit.

* **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

- 35 -

TABLE OF CONTENTS

Part I. Financial Informationprint Item 3. Quantitative and Qualitative Disclosures About Market Riskprint Item 4. Controls and Proceduresprint Part II. Other Informationprint Item 1. Legal Proceedingsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 4. Mine Safety Disclosuresprint Item 5. Other Informationprint Item 6. Exhibitsprint

Customer name	Ticker
Adams Resources & Energy, Inc.	AE
Apache Corporation	APA
EQT Corporation	EQT
ManpowerGroup Inc.	MAN
Valero Energy Corporation	VLO

Supplier name	Ticker
Honeywell International Inc.	HON
Raytheon Technologies Corporation	RTX
American Water Works Company, Inc.	AWK
Ecopetrol S.A.	EC
Dover Corporation	DOV
Xylem Inc.	XYL
Broadridge Financial Solutions, Inc.	BR
Markel Corporation	MKL
Halliburton Company	HAL

EOG 10-Q Quarter ended March 31, 2012